Handout Well Intervention Pressure Control [PDF]

Zitiervorschau

Table of Content Part 1

Completion Operations

Page 5 - 77

Part 2

Completion Equipment

Page 78 - 111

Part 3

Coiled Tubing

Page 112 - 144

Part 4

Snubbing

Page 145 - 176

Part 5

Wireline

Page 177 - 208

Page |1

Part 1 Completion Operations

Page |2

1.0

Forward ........................................................................................................................... 5

2.0

Completion operations ..................................................................................................... 5

3.0

WA01.01 Negative Impact & Effects of a Well Control Incident ......................................... 5

4.0

WA01.02 Well Integrity Requirements .............................................................................. 7

5.0

WA02.01 Training and Competency ................................................................................. 10

6.0

WA03.01 Roles and Responsibilities ................................................................................ 11

7.0

WA03.02 Pre- Job Meeting .............................................................................................. 11

8.0

WA03.03 Importance of Pre-Job Planning ........................................................................ 13

9.0

WA04.01 Handovers ........................................................................................................ 13

10.0

WB01/02/03 Hydrostatic Pressure................................................................................... 14

11.0

WB02.01 Formation Pressure .......................................................................................... 14

12.0

WB03.01 Formation Fracture Pressure............................................................................. 15

13.0

WB01.01/02/03 Hydrostatic Calculations......................................................................... 16

14.0

Fluid Pressure.................................................................................................................. 17

15.0

WC01.01 Well Barrier Envelope Philosophy ..................................................................... 25

16.0

WC02.03 Well Barrier Management................................................................................. 27

17.0

WC02.04 Well Barrier Element Testing............................................................................. 28

18.0

WC02.05 Barrier Test Documentation .............................................................................. 29

19.0

WC02.06 Corrective Action Due to Barrier Test failure ..................................................... 29

20.0

WC02.07 Barriers ............................................................................................................ 29

21.0

WC02.09 Principle of Barrier Classification ....................................................................... 34

22.0

WD01.01 Principles of Risk Management ......................................................................... 37

23.0

WD01.02 Management of Change ................................................................................... 38

24.0

WD02.01 Emergency Drills............................................................................................... 40

25.0

WG01.01 Circulating System ............................................................................................ 42

26.0

WP01.01 Inflow Testing ................................................................................................... 42

27.0

WP01.02 Importance of the Inflow Test ........................................................................... 43

28.0

WP01.03 Interpreting Inflow Test Results ........................................................................ 43

29.0

WP01.05 Inflow Test Procedures ..................................................................................... 44

30.0

WH01.01 Integrity Testing ............................................................................................... 45

31.0

WH01.02 Integrity Testing Procedures ............................................................................. 45

32.0

WI01.01 Boyle’s Law ....................................................................................................... 48

33.0

WI01.02 Circulation of Influx ........................................................................................... 48

34.0

WI01.03 Basic Gas Law .................................................................................................... 49

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35.0

WI01.04 Influx Migration ................................................................................................. 49

36.0

WJ01.01 Shut In Procedure .............................................................................................. 50

37.0

WJ02.01 Shut In Procedure - Tree .................................................................................... 51

38.0

WJ02.02 Shut In Procedure - Well .................................................................................... 51

39.0

WJ02.03 Shut In Pressures Procedures ............................................................................. 52

40.0

WJ02.05 Valve Opening Precautions _ Procedures ........................................................... 52

41.0

WJ04.01 Shut In Pressures ............................................................................................... 53

42.0

WJ04.02 Differences Between SITHP and SICP ................................................................. 53

43.0

WJ05.01 Limitations of Pressure Gauges .......................................................................... 54

44.0

WJ06.01 Gas Migration.................................................................................................... 56

45.0

WJ06.02 Monitoring Pressures at Shut-in ........................................................................ 56

46.0

WJ06.03 Pressure Trends ................................................................................................. 56

47.0

WK02.01 Production Well Kill Procedures ........................................................................ 57

48.0

WK02.02 Well Kill Methods Pros & Cons .......................................................................... 57

49.0

WK02.03 Well Kill Method Appropriate Selection ............................................................ 58

50.0

WK03.01 Reverse Circulation ........................................................................................... 58

51.0

WK04.01-12 .................................................................................................................... 67

52.0

WK05.01 Bullheading ...................................................................................................... 67

53.0

WK06.04 Lubricate and Bleed .......................................................................................... 72

54.0

WK06.05 Lubricate and Bleed Procedure ......................................................................... 72

55.0

WK06.06 Lubricate & Bleed Summary .............................................................................. 74

56.0

WN05.01 Hydrates .......................................................................................................... 75

57.0

WN05.02 Hydrate Prevention Removal ............................................................................ 75

58.0

WN10.01/02/03 Blockages .............................................................................................. 77

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1.0

Forward

Well pressure control is the most critical consideration in the planning and performing of any well servicing operation. The awareness of well pressure control in the prevention of injury to personnel, harm to the environment and potential loss of facilities must be fully appreciated by planning engineers and well site personnel. This appreciation must include personnel in having a sound knowledge of legislative requirements, completion equipment, pressure control equipment and operating practices and procedures. ‘Well Intervention’ and ‘Work-over’ are commonly used terms to describe servicing operations on oil and gas wells and which have, in the past, had many different interpretations. However, in general, ‘Work-over’ describes well service operations on dead wells in which the formation pressure is primarily controlled with hydrostatic pressure. Work- over operations are carried out by a drilling rig, work-over rig or Hydraulic Work-over Unit (HWO) where the Xmas tree is removed from the wellhead and replaced by blow out preventer (BOP) equipment. ‘Well Intervention’ is a term used to describe ‘through-tree’ live well operations during which the well pressure is contained with pressure control equipment. Well Interventions are conducted by Wireline, coiled tubing or snubbing methods. Snubbing operations today are now usually conducted with HWO units. This course is designed to provide essential knowledge to delegates participating in Well Intervention Pressure Control. Well intervention pressure control equipment used by Wireline, coil tubing and snubbing units is so termed, as it must control well pressure during live well intervention operations. It significantly differs from BOP systems used on dead well work-overs. As most well servicing is now conducted by live well intervention methods these are fully addressed as part of the course. The term Well Control specifically applicable to drilling or work-over operations using hydrostatic pressure is not addressed in this manual. To have an understanding of well operations conducted by live well intervention methods and the associated pressure control equipment, it is first necessary to have, or obtain, a basic knowledge of completion designs, completion equipment, practices, well service methods and their applications. An overview of these is given in the early sections of the reference book.

2.0

Completion operations

3.0

WA01.01 Negative Impact & Effects of a Well Control Incident

Well control is the management of the dangerous effects caused by the unexpected release of formation fluid, such as natural gas and/or crude oil, upon surface equipment and escaping into the atmosphere. Technically, oil well control involves preventing the formation fluid, usually referred to as kick, from entering into the wellbore during drilling. Formation fluid can enter the wellbore if the pressure exerted by the column of drilling fluid is not great enough to overcome the pressure exerted by the fluids in the formation being drilled. Well control also Page |5

includes monitoring a well for signs of impending influx of formation fluid into the wellbore during drilling and procedures, to stop the well from flowing when it happens by taking proper remedial actions. Failure to manage and control these pressure effects can cause serious equipment damage and injury, or loss of life. Improperly managed well control situations can cause kicks or influxes,which are uncontrolled and explosive expulsions of formation fluid from the well, potentially resulting in a fire, injury/death, environmental problems and loss of the asset. Blowouts are easily the most dangerous and destructive potential disasters in the world of oil drilling. Not only can they lead to serious injury and even death, but also they can also cause massive, debilitating production shutdowns and can have a negative effect on future production from the lost well. Blowouts can also cause severe ecological damage. As with any potential disaster, prevention is the first step in avoiding an otherwise costly and dangerous situation. These preventative measures are called, collectively, Well Control. "Blowout Prevention is simply the training and understanding of how to prevent this from happening." Blowout prevention is a very broad term that can encompass anything from the precautionary methods used on rigs to prevent "kicks" -- the unexpected and undesired flow of formation fluids into a well -- from developing, to the use of sophisticated devices called Blowout Preventers (or BOPs) designed to close off a well in the face of a looming blowout. The first stage of blowout prevention/Intervention operations is preparedness. Most countries and corporations require certification in well control/intervention practices from all drilling/Intervention employees, a policy that underscores the potential danger of a blowout or an unplanned event. To prevent kicks, drilling operators must use "drilling mud," otherwise known as drilling fluid, a viscous mud-like substance that comes in varying densities, to balance the tremendous upward pressure of the formation fluids surging up the well. The downward pressure of the drilling fluid is called bottom hole pressure. Drilling fluid engineers must be vigilant and careful to ensure that the pressures reach equilibrium, a tedious but vitally important task. "The working fluid in a well is considered the primary barrier against blowouts or unplanned events, "Theoretically, if the formation pressure is greater than the bottom-hole pressure, formation fluids could enter a well and, if uncontrolled, develop into a disaster." Macondo 2011 SINTEF investigation Important Underlying causes of the incident:

Page |6



Ineffective leadership



Compartmentalisation of information and deficient communication



Failure to provide timely procedures



Poor training and supervision of employees



Ineffective management and oversight of contractors



Inadequate use of technology/instrumentation



Failure to appropriately analyse and appreciate risk



Focus on time and costs rather than control of major accident risks



4.0

WA01.02 Well Integrity Requirements

Well Integrity is defined as the application of technical, operational and organizational solutions to reduce risk of uncontrolled release of formation fluids throughout the life cycle of a well. There are various facets to well integrity, including accountability and responsibility, well operating processes, well service processes, tubing/annulus integrity, tree/wellhead integrity and testing of safety systems. Well Barriers are the corner stone of managing Well Integrity. The primary purpose of well integrity management is to maintain full control of fluids at all times to prevent the loss of containment to the exterior of the wellbore, the environment and the formations penetrated by the wellbore. This is achieved by employing and maintaining one or more barrier envelope.

4.1

WA – Well Control Training & Assessment

This is what we want to avoid! Why is Well Integrity Important?

It can help to prevent incidents like this.

Page |7

4.2

Page |8

Integrity Drivers & Implementation 

Safety



Statutory regulations



Internal Policy & Standards



Production



Reputation



Technical & Performance Standards



Procedures



Industry Standards



Vendors Procedures.

4.3

Knowledge, Training & Competency

This can be defined as the ability to undertake responsibilities and perform activities to a recognised standard on a regular basis. It is a combination of skills, experience and knowledge. The inadequate management of competence has not only contributed to disasters such as Esso Longford and BP Texas City, but also to fatalities, personal injuries. Training is an important component of establishing competency but is not sufficient on its own. Consolidation of knowledge and skills through practice is a key part of developing competency. Training and competence assessment methods should be appropriate to the hazard profile of the tasks being undertaken. Training should be validated (“Did it deliver what it was supposed to”) and recorded.

The purpose of training is for personnel to be able to carry out defined tasks without supervision. Because you are part of a team other people rely on you to be able to identify risks and deal with them

Training is always ongoing

4.4

Well Integrity Minimum Standards

Accountable Person

Wells Technical Authority

Well Operating Procedures

Well Handover Process & Operate Wells

Well Intervention Procedures

Field Specific Procedures

Tubing / Casing Integrity Management

Field Specific Procedures

Xmas Tree Maintenance & Testing Policy

Field Specific Procedures & Planned maintenance routines (PMR’s)

DHSV / ASV Integrity Management

Field Specific Procedures & Planned maintenance routines (PMR’s

Knowledge Management

Drilling & Well Operations Policy

Page |9

4.5

Root Causes of Well Control Incidents

There will always be potential oil well control problems, as long as there are drilling operations anywhere in the some are actually unavoidable. Since we know the consequences of failed well control are severe, efforts should be made to prevent some human errors which are the root causes of these incidents. These causes include:

4.6



Lack of knowledge and skills of personnel



Improper work practices



Lack of understanding of well control training



Lack of application of policies, procedures, and standards



Inadequate risk management

Building Well Control Culture

Good well control culture requires personnel involved in well control to develop a core value for it by doing the proper thing at the proper time. A good well control culture will definitely minimize well control incidents. Building well-control culture would involve developing competent personnel that are able to recognize well-control problems and know what to do to mitigate against them. This is usually done through quality-assurance programs and training.

5.0

WA02.01 Training and Competency

It is each and every employee’s responsibility to ensure that they have satisfied themselves with the requirements of the Work Programme and the status of all equipment etc. prior to commencing operations. If any other issues have not been addressed and confirmed, then the operation must cease until an agreeable solution has be identified and actioned. Ensure that the crew are aware of any pre operational Safety and Environmental Risk Assessments that are to be completed prior to operations commencing. Liase with the Production Control Room and any relevant Supervisors with regard to the bleed down and venting of equipment. P a g e | 10

Liase with the platform supervisor, deck foreman and crane drivers with regard to operations being undertaken, so they are aware of the restrictions on crane movement within the vicinity of the intervention equipment. Check that all pressure control equipment, power packs, wire, slings and lifting equipment have current valid certification. Check Well File and Work Programme with regard to any hazardous well conditions, problems, etc. that have already been logged in the past.

6.0

WA03.01 Roles and Responsibilities

A well is initially drilled and completed under the control of the drilling and completions department operating under the request of the asset. Once the well is completed, control is transferred to the asset's production team, who will operate the well as appropriate for their purposes. Should any issues of well integrity or any requirement for well work arise; the asset will refer the issue to the well services. During interventions, control of affected well is handed over from production to the well services crew at the well site, a practical action involving transferring control lines from the production control panel to the well services control panel.

7.0



During a handover it is the responsibility of the signatory to ensure the full status ofthe well/equipment are as per the hand over report. (WSS)



During an intervention operation it is the responsibility of the equipment operator to maintain well control



In the event of an emergency it is the nominated person responsibility to shut the well in



(Control Panel)



Production is responsible for the well until it is handed over to Well Services

WA03.02 Pre- Job Meeting

A pre-operational meeting must be held with all parties who may be involved in or be affected by the well intervention programme. The following agenda Guidance must be adhered to as a minimum and made clear to all members of the work party. This process must be repeated for each well intervention programme. Additionally, regular pre shift meetings must be held and recorded as well as further toolbox talks to be held during the shift at every operational phase change, to ensure that all members of the well intervention team are kept fully informed of every aspect of the operation.

P a g e | 11

These toolbox talks shall involve all members of the intervention team and client representatives as required. Any non-routine issues MUST be reported to the client representative onboard and to the onshore support team as required.

Pre Operations Meeting Guidelines This meeting shall have representation from the following departments / service lines. 

Company crew – All disciplines and grades.



Other service company representatives.



Operating Company Representative.



Production Department Representative



Drilling Department Representative



Facilities Department Representative

If any given department is not represented at this meeting, they must be made aware of the operational requirements of the intervention team immediately after the meeting, these requirements should include, but not be limited to, the following:

P a g e | 12



Planned Well Operation Programme to be reviewed step by step and all parties agree on roles and responsibilities within the intervention team.



Review of any onshore Risk Assessment details and findings.



Review of well history. (To be reviewed in line with planned operation).



Current status of Well and Christmas tree.



Any safety issues e.g. H2s presence etc.



Working rules i.e. two people must be present at the worksite during Wireline operations in the well bore.



All pre operational equipment checklists must be completed and equipment confirmed as fit for purpose.



Any defects must be recorded in compliance with QA procedures. Thus adopting aprevention attitude to operational equipment and potential operational issues.



All personnel to be aware of the procedure that MUST be followed in the event that there is a significant change to the agreed Programme. It must be made clear to all that the operation must STOP until agreement on the way ahead is reached by all. Any significant changes to the Programme must be communicated back to the company onshore support team.



It must also be made clear that no other work can be carried out on the well orsurrounding area without the knowledge and consent of the senior company representative.



If in doubt:

Stop – Check– Validate Stop - the operation if there is any doubt or concern about the operation no matter how small it may initially appear, seek the advice of other qualified personnel or client, personnel and onshore support, if required, before considering the continuation of the operation. Check - that what is being done is in accordance with all company and client policies, procedures and written work instructions and ensure that all relevant aspects of the pre job safety briefing have been considered. Validate - all aspects of the operation including equipment and pre operational checks and crew competence. If in doubt, ask for validation for any issue or situation. Do not continue with any operation unless you are completely satisfied that all aspects of the operation and personnel have been validated and confirmed. When required, verification should be confirmed by counter signature.

8.0

WA03.03 Importance of Pre-Job Planning

All operations must be carried out with due regard to the operating Companies Permit to Work System and working procedures, so familiarise yourself with it in plenty of time. It is the Senior Representative’s responsibility to ensure that any safety or operational condition on the permit is adhered to and to ensure that all pre-job meetings and assessments are completed as per Safety Procedures If, however, a Contractual Interface Agreement exists, where the operator’s format of Preoperations Meeting (Toolbox Talk) must be employed, then this meeting format will be adopted. If no interface agreement exists, then the company format as laid out in the referenced relevant Safety Procedures and this Work Instruction will be us.

9.0

WA04.01 Handovers

The handover from the “outgoing” to “incoming” crew shall be carried in a formal and consistent manner and include all safety critical and relevant details to assure operating integrity and the safe, continuous and effective operation of the intervention procedures Analysis of accidents has repeatedly cited lack of effective communication as a major contributory factor and particularly where breaks in work continuity occur, as can be the case where a crew change takes place. P a g e | 13

Handover notes that are not supported by clear and concise “verbal” communication often leads to misunderstanding as to the “true status” being conveyed. Misinterpretation of the handover documents may result, because each individual’s information needs are different. Ultimately these may impact upon asset performance through missed opportunities and unplanned deferments. To address the above all Safety Critical aspects personnel shall conduct a formal hand-over with both written and verbal actions. Where required the handover will be supplemented by Checklists and Handover Sheets with the current well status.

10.0

WB01/02/03 Hydrostatic Pressure

Hydrostatic pressure is the pressure exerted by a vertical column of fluid As API units are used Hydrostatic Pressure (HP) is measure in pounds per square inch (psi) Mud Weight is measured in pounds per gallon (ppg) True Vertical Depth (TVD) is measured in feet (ft) HP = MW x 0.052 x TVD

11.0

WB02.01 Formation Pressure

Formation pressure is the pressure of the fluid within the pore spaces of the formation rock. This pressure can be affected by the weight of the overburden (rock layers) above the formation, which exerts pressure on both the grains and pore fluids. Grains are solid or rock material, and pores are spaces between grains. If pore fluids are free to move, or escape, the grains lose some of their support and move closer together. This process is called consolidation. Depending on the magnitude of the pore pressure, it can be described as being normal, abnormal or subnormal. Normal Pore Pressure or formation pressure is equal to the hydrostatic pressure of formation fluid extending from the surface to the surface formation being considered. In other words, if the formation was opened up and allowed to fill a column whose length is equal to the depth of the formation, then the pressure at the bottom of the column will be equal to the formation pressure and the pressure at surface is equal to zero. Normal pore pressure is not a constant. Its magnitude varies with the concentration of dissolved salts, type of fluid, gases present and temperature gradient. When a normally pressured formation is raised toward the surface while prevented from losing pore fluid in the process, it will change from normal pressure (at a greater depth) to abnormal pressure (at a shallower depth). When this happens, and then one drill into the formation, mud weights of up to 20 ppg (2397 kg/m ³) may be required for control. This process accounts for many of the shallow, abnormally pressured zones in the world. In areas where faulting is present, salt layers or domes are predicted, or excessive geothermal gradients are known, drilling operations may encounter abnormal pressure. Abnormal Pore Pressure is defined as any pore pressure that is greater than the hydrostatic pressure of the formation fluid occupying the pore space. It is sometimes called overpressure or geopressure. An abnormally P a g e | 14

pressured formation + .465psi/ft can often be predicted using well history, surface geology, downhole logs or geophysical surveys. Subnormal Pore Pressure is defined as any formation pressure that is less than the corresponding fluid hydrostatic pressure at a given depth. Subnormal pressured formations have pressure gradients lower than fresh water or less than 0.433 psi/ft (0.0979 bar/m). Naturally occurring subnormal pressure can be developed when the overburden has been stripped away, leaving the formation exposed at the surface. Depletion of original pore fluids through evaporation, capillary action and dilution produces hydrostatic gradients below 0.433 psi/ft (0.0979 bar/m). Subnormal pressures may also be induced through depletion of formation fluids. If Formation Pressure < Hydrostatic pressure then it is under pressured. If Formation Pressure > Hydrostatic pressure then it is over pressured.

12.0

WB03.01 Formation Fracture Pressure

The amount of pressure a formation can withstand before it splits is termed the fracture pressure. The pressure of fluid in a well must exceed formation pressure before the fluid can enter a formation and cause a fracture. Fracture pressure is expressed in psi, as a gradient in psi/ft, or as a fluid weight equivalent in ppg. In order to plan a conventional rig well intervention, it is necessary to have some knowledge of the fracture pressures of the formation to be encountered. If wellbore pressures were to equal or exceed this fracture pressure, the formation would break down as the fracture was initiated, followed by loss of work-over fluid, loss of hydrostatic pressure, loss of primary well control and irreparable damage to the formation. Most operating companies have strict policies and procedures to ensure the fracture pressure is never exceeded (unless the formation was to be deliberately fractured for reservoir productivity improvement through sand fracking operations, etc.). Unless the service is to conduct remedial operations on or in the casing across the formation, it is preferred to isolate the formation from the kill fluid by installing a barrier or plug. Fracture pressures are related to the weight of the formation matrix (rock) and the fluids (water/oil) occupying the pore space within the matrix, above the zone of interest. These two factors combine to produce what is known as the overburden pressure. Assuming the average density of a thick sedimentary sequence to be the equivalent of 19.2ppg then the overburden gradient is given by:

0.052 x 19.2 = 1.0psi/ft

Since the degree of compaction of sediments is known to vary with depth, the gradient is not constant. Onshore, since the sediments tend to be more compacted, the overburden gradient can be taken as being close to 1.0psi/ft. Offshore, however the overburden gradients at shallow depths will be much less than 1.0psi/ft due to the effect of the depth of seawater and large thickness of unconsolidated sediment.

P a g e | 15

Barrier Classification This section describes the classification of each common barrier grouping definitions used. Note: these may not be generic to the industry world-wide.

13.0

WB01.01/02/03 Hydrostatic Calculations

Hydrostatic Pressure is the pressure exerted by a column of fluid due to gravity

13.1

WB – Introduction to Well Control

Fresh water is used as a universal standard since it may be obtained relatively easily in any part of the world. In the oilfield it is common practice to use the density of fresh water as the standard and compare all other liquid densities to this standard.

13.2

o

Fresh water has a density of 8.33 ppg

o

The gradient of fresh water is 0.433 psi/ft.

o

The Specific Gravity is 1

o

The constant 0.052 is used to convert ppg to psi.

Fundamentals of Fluid and Pressure

Understanding pressures and pressure relationships is important in understanding well control. Pressure is defined as the force per unit area exerted by a fluid i.e:

Pressure = Force ÷ Area Therefore, the formula can be changed to calculate the force from a given pressure and a unit area:

Force = Pressure x Area Pressure is usually expressed as the pounds of force that is applied against a one square inch area, i.e. pounds per square inch (psi). Therefore, when a gas is placed in a pressure tight container, it exerts a pressure on all sides of the container. If the gas pressure is 100psi, it exerts a force of 100lbs on each square inch of the container area. Similarly, if a liquid is placed in a can, it exerts a pressure on the sides and bottom of the container due to the weight of the liquid, which is also expressed as psi. In well control, both of these effects are of the utmost importance. Pressure can be expressed as absolute or as gauge pressure. Absolute pressure includes atmospheric pressure that is also applied due to the weight of the atmosphere and is 14.7psi Some gauges, especially BHP gauges, are calibrated in absolute terms, but regular gauges showing psig indicate they have been calibrated at atmospheric pressure and the 14.7psi is excluded. Although this is a relatively small amount and can be ignored in most instances, it is important when gathering data for reservoir analysis.

Hydrostatic Pressure is calculated with the following P a g e | 16

HP = 0.052 x MW x TVD As MW increases HP increases AS TVD increases HP increases 14.0

Fluid Pressure

A fluid is any substance that is not solid and can flow. Liquids like water and oil are fluids. Gas is also a fluid. Under certain conditions, salt, steel and rock can become fluid and in fact almost any solid can become fluid under extreme pressure and temperature. Well control involves fluids such as gas, oil, water and completion fluids, brines and mud. Fluids exert pressure that is caused by the density, or weight of the fluid. This is normally expressed in pounds per gallon (ppg) or pounds per cubic foot (lbs/ft3). Other abbreviations for these are lbs/gal and lbs/cu.ft3.

As the pressure developed by a fluid is relative to the true vertical depth, it is often expressed as psi per foot (psi/ft). This is termed the fluid’s pressure gradient. The pressure gradient for a fluid is relative to the fluid’s weight or density. The higher the density, the greater the pressure gradient. To understand this relationship, it is helpful to visualise a cubic foot of fluid

P a g e | 17

14.1

Derivation of the Constant

A cubic foot contains = 7.48 US gallons. If the cube was filled with a fluid weighing 1ppg, the cube would weigh 7.48lbs The pressure exerted on the bottom of the cube is; 1ft2 = 12” x 12” area = 144 sq inch Therefore the pressure per squared inches is; 7.48 US Gallons ÷ 144 sq. inches = 0.052 psi

This relationship between a fluid density in ppg and gradient pressure in psi/ft is always the same therefore, 0.052 is a constant. A cubic foot of fresh water weighs 62.4 lbs therefore the weight per gallon is; 62.4 ÷ 7.48 = 8.33 ppg.

Therefore the gradient of fresh water is; 8.33 ppg x 0.052 = 0.433 psi/ft

Example The pressure gradient of 10 ppg fluid = 10 ppg x 0.052 = 0.52 psi/ft Example Find the weight of a fluid, which has a gradient of 0.465psi/ft

0.465 psi/ft x 0.052 = 8.94 ppg This constant is probably the most useful constant used in calculations.

14.2

Hydrostatic Pressure

Hydrostatic pressure (HP) is the pressure developed by a fluid at a given true vertical depth in a well irrespective of the measured depth. ‘Hydro’ means water, or fluids, which exert pressure and ‘static’ means motionless. So hydrostatic pressure is the pressure created by a stationary column of fluid. The hydrostatic pressure of any fluid can be calculated at any true vertical depth (TVD) provided the pressure gradient of the fluid is known. The previous calculations have dealt with fluid pressure with a gradient of one foot depth but it is now simple to determine the pressure exerted by a fluid at any true vertical depth by multiplying that pressure P a g e | 18

gradient by the true vertical height of the column in feet. The true vertical height of the column is the important factor in the equation, as its volume or shape is irrelevant. The equation is: HP = PG x TVD where:

HP = Hydrostatic pressure PG = Pressure gradient TVD = True Vertical Depth Example What is the hydrostatic pressure exerted by a 1000 ft TVD column of fresh water?

HP = 0.433 psi/ft x 1000 ft = 433 psi

Example What is the hydrostatic pressure of a 500ft TVD column of fresh water? HP = 0.433 psi/ft x 500ft = 216.5psi

Example What is the hydrostatic pressure of a 6,750 ft MD well, filled with a fluid 0.478 psi/ft pressure gradient and a TVD of 6,130ft ? HP = 0.478psi/ft x 6,130ft = 2,930psi

Example

A 12,764ft TVD well is filled with a 15ppg fluid, what is the BHP. HP = 15ppg x 0.052 x 12,764ft = 9,956psi

Equipped with this knowledge, it is now easy to calculate the hydrostatic pressure with two of more fluids P a g e | 19

in a well provided the depths (TVD) of the fluid interfaces are known. Using the same formula, the HP for each fluid section is calculated in the same way and the sum of the individual calculations gives the HP at the bottom of the hole or well.

Example A 10,500ft TVD well has two fluids in the well, a 15 ppg fluid from TD to 7,125 ft and 8.33ppg fluid to surface, what is the HP at the bottom of the well?

HP of 15ppg fluid

HP of 8.33ppg fluid

Total HP

14.3

=

15ppg x 0.052 x (10,500 - 7,125)ft

=

15ppg x 0.052 x 3,375ft

=

2,633psi

=

8.33ppg x 0.052 x 7,125ft

=

3,086psi

=

2,633psi + 3,086psi

=

5,719psi

Specific Gravity

Many fluids in the oilfield are also expressed in Specific Gravity (SG) as well as weight in ppg. It is also necessary to be able to convert SG to pressure gradient in order to calculate hydrostatic pressures. SG is the ratio of the weight of a fluid (liquid) to the weight of fresh water. Fresh water weighs 8.33 ppg and salt water is nominally valued at 10 ppg. Therefore, the SG of salt water is:

The SG of fresh water is 1.0. As the gradient of fresh water is known to be 0.433psi/ft, to obtain the gradient of a fluid, it is simply necessary to multiply its SG by 0.433psi/ft.

Example What is the hydrostatic pressure (HP) exerted by a true vertical 5,000ft column of brine with a SG of 1.17. HP of Brine = 1.17 x 0.433 psi/ft x 5,000ft = 2,533psi

P a g e | 20

14.4

API Gravity

API gravity is another value used to express relative weight of fluids, and was introduced by the American Petroleum Institute to standardise the weight of oilfield fluids at a base temperature of 60° F. Water in this case was also used as the standard and assigned the value of 10API gravity. To convert from API gravity to specific gravity, the following formula is used.

API of Fresh Water = 10˚ Formula = 141.5 ÷ 131.5 + AP Example What is SG of 76 API? SG of 76 API = 141.5 ÷ (131.5 + 76) = 141.5 ÷ 207.5 = .68192 SG

14.5

Bottom Hole Pressure

Bottom-hole pressure is used to represent the sum of all the pressures being exerted at the bottom of the hole. Pressure is imposed on the walls of the hole. The hydrostatic fluid column accounts for most of the pressure.

Gas Correction Tables Well Depth 3,000 3,500 4,000 4,500 5,000 5,500 6,000 6,500 7,000 7,500 8,000 8,500 9,000 9,500 P a g e | 21

0.6 1.064 1.075 1.087 1.098 1.110 1.121 1.133 1.145 1.157 1.169 1.181 1.193 1.206 1.218

Correction Factors 0.7 0.8 1.075 1.087 1.089 1.102 1.102 1.117 1.115 1.133 1.129 1.149 1.143 1.165 1.157 1.181 1.171 1.197 1.185 1.214 1.204 1.232 1.214 1.248 1.239 1.266 1.244 1.282 1.259 1.302

0.9 1.098 1.115 1.133 1.151 1.169 1.187 1.206 1.224 1.244 1.264 1.282 1.304 1.324 1.345

10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 14,000 14,500 15,000

1.232 1.244 1.257 1.270 1.282 1.297 1.311 1.324 1.338 1.352 1.366

1.275 1.289 1.306 1.322 1.338 1.354 1.371 1.388 1.405 1.422 1.438

1.320 1.338 1.357 1.376 1.395 1.415 1.434 1.455 1.475 1.495 1.515

1.366 1.388 1.410 1.433 1.455 1.477 1.500 1.523 1.548 1.573 1.596

Gas Correction Factors

GAS CORRECTION FACTORS

8.0

Most well servicing operations entails working with live wells whether using a through- tubing method or rig intervention. Even with a rig operation, the well must be prepared by being killed prior to the intervention. This involves dealing with gas in the well. Production wells with gas in the fluids will exert a static surface pressure equal to the formation pressure less the hydrostatic pressure in the production bore. The gas entrained in the production fluids will segregate from the liquids. In a static situation, the closed in tubing head pressure (CITHP) and hydrostatic pressure will balance the formation pressure. As discussed earlier, gas is also a fluid and exerts a hydrostatic pressure. Being compressible pressure affects the density of the gas. A set of correction factors are used which are used to calculate hydrostatic pressures at varying TVDs with a range of gas gravities. The correction factor, according to the TVD of the gas column and the gas gravity, is multiplied by the CITHP:

HP = Correction factor x CITHP Example What is the HP of a 5,000ft TVD column of 0.7 SG gas with a closed in tubing head pressure of 1,650psi?

HP of gas = 1.129 x 1,650psi = 1863 psi

P a g e | 22

Therefore, when we calculate the bottom-hole pressure from the above, we must add the pressure together to calculate the BHP;

Surface pressure

= 1650 psi

Gas Tubing Hydrostatic = BHP – SP = 1863 – 1650 = 213 psi (.0426 psi/ft) BHP

= 1863 (1650 + 213) (FG .3726 psi/ft)

Conversely when we need to determine the BHP and the maximum Surface pressure we need to minus the pressures from the bottom up using the formation gradient (FG) = BHP;

BHP Tubing gas gradient

= FG x TVD = 1863 psi = .0426 psi/ft x 5000 = 213 psi/ft Surface pressure = 1863 psi (BHP) – 213 (gas in tubing) = 1650 psi

Using the calculations already given in earlier sections and the gas correction factors, hydrostatic pressures in relatively complicated systems can now be determined.

DIFFERENTIAL PRESSURES

8.1

What is the differential pressure between the annulus and tubing at a circulation device installed at a depth of 8,200ft TVD in the tubing string? The following are the well conditions: The tubing/casing annulus is filled with 10.29ppg brine. The well is shut in at surface with a CITHP of 600psi There is a gas cap of 0.6SG gas from 4,000ft There is 32 API oil from 4,000 ft to 12,000 ft To help in the calculation, it is sometimes better to make a sketch.

P a g e | 23

Example HP of brine in annulus at circulation device: = 10.29ppg x 0.052 x 8,200ft = 4,387psi

HP of gas cap = 1.087 (from table) x 600 psi = 652psi HP of oil column: Oil SG

= 141.5 ÷ 131.5 + 32 = 0.865 SG

HP of Oil Column = 0.865 SG x 0.433psi/ft x (8,200 - 4,000)ft = 1,573psi

Total HP in tubing

= HP of gas + HP of oil =

= 652 psi + 1,573 psi

= 2,225 psi

DIFFERENTIAL PRESSURE ACROSS CIRCULATION DEVICE

8.2

= HP of annulus - HP of tubing = 4,387psi - 2,225psi = 2,162psi form annulus to tubing

If the circulation device were to be opened, then the opening tool-string would be exposed to 2,162psi differential pressure. If using wireline, this pressure differential will need to be equalised before opening the device.

P a g e | 24

15.0

WC01.01 Well Barrier Envelope Philosophy

Well Barriers are the corner stone of managing Well Integrity. The primary purpose of well integrity management is to maintain full control of fluids at all times to prevent the loss of containment to the exterior of the wellbore, the environment and the formations penetrated by the wellbore. The barrier system for the well is called the ‘well barrier envelope’. This system includes both active barrier elements (like DHSV and master valves) and passive barrier elements (like casing, tubing and production packer). 

Barriers are not 'stand-alone' items, they are part of a group of components which form a barrier envelope i.e. they form part of a barrier system.



The wireline stuffing box is only a component (element) of the stuffing box- lubricator-BOP envelope which contains well fluids.



In the following drawing the envelope of barrier elements that prevents flow out of the well via the tubing string when the tree is closed is as follows:- If any one of the elements in this envelope fails, there are various secondary elements which should prevent the escape of wellbore fluids from the well. For example, if there is a leak at the packer into the annulus, the overbalanced completion fluid will initially stop the wellbore fluids from reaching the production casing. After a while, this may change as the completion fluid escapes from the annulus and the wellbore fluids will then be prevented from leaving the well by the production casing, side outlet valves and the tubing hanger seals.

For all live well work, we rely on barriers. These may be downhole barriers (mechanical plugs, columns of fluid, etc.) or they may be surface barriers. Barriers are divided into primary, secondary and tertiary barriers, or barrier elements. During intervention work, there will be one primary barrier such as the stuffing box on a slick- line job. This primary barrier may not be the same for the whole job. In the slick-line example, the stuffing box is only the primary barrier when the wire is in the hole. When the wire is out of the hole, and the lubricator laid down, the Xmas tree (swab valve) is the primary barrier. The backup safety devices are the secondary barriers (the BOP's in slick-line work) and the tertiary barriers are those which are only used in the event of an emergency (the cutter valves). There may be multiple barriers such as when two or more plugs are placed in a well or when two valves in the same line are closed. For a truly safe operation, double barriers should always be used. Barriers alone will not contain well pressure. In the example of the slick-line rig up, the stuffing box (the primary barrier) will not contain the wellbore fluids and pressure without the lubricator when it is attached to and all the other components connected to the tree.

P a g e | 25

DHSVPressure Envelope

SCSSSV Tubing Packer Casing below the Packer

Barrier Elements

P a g e | 26

In this way we can consider a barrier envelope. The envelope is made up of the barrier elements containing the pressure or fluids. In the example of the slickline rig up, the envelope is the tree X-over, the BOP, the lubricator sections and the stuffing box. The DHSV forms part of the pressure containing tubing string in the same way as any other non-well control completion component. If any one of the elements in this envelope fails, there are various secondary elements to prevent the escape of wellbore fluids from the well. For example, if the packer leaks into the annulus, an overbalanced completion fluid will initially stop the wellbore fluids from reaching the production casing. After a while, this may change as the completion fluid escapes from the annulus and the wellbore fluids will then be prevented from leaving the well by the production casing, annulus valves and the tubing hanger seals. The purpose of developing a well is to safely and economically produce oil or gas and, as such, the completion is one of the key elements in the safety of the well. The well should be designed to ensure that, in general, there are two reliable and independent barriers between the reservoir and the environment at all times. A barrier is any device, fluid or substance that prevents the flow of well bore fluids and it does this by blocking off the flow path. It is good practice to ensure that at least two tested barriers are available at all times and it should be borne in mind that a well which cannot sustain flow should have the same amount of barriers as a well that can flow.

16.0

WC02.03 Well Barrier Management

The primary well barrier elements are SCSSV, production packer & completion string. Secondary barrier elements include Christmas tree, tubing hanger, wellhead, casing and cement. Well barrier elements include deep-set plugs under the production packer and plugs in the hanger assembly for the completion string

P a g e | 27

17.0

WC02.04 Well Barrier Element Testing Element Type

Function

Failure mode Leak off into the formation

Fluid Column

Exerts a hydrostatic pressure on the formation that prevents the flow of pressure or gas

Formation Strength

Wellhead

Casing

Deep Set Plug

Production Packer

P a g e | 28

Provides a mechanical seal in the annulus where the formation is not isolated by cement or tubulars. Provides a continuous permanent & impermeable hydraulic seal above the reservoir. Impermeable formation located above the reservoir sealing either cement/annulus isolation or directly to the casing/liner. Provides mechanical support for suspending the casing and tubing hanger. Provides a mechanical

Leak off into the formation Not sufficient formation strength to with stand annulus pressure Not sufficient formation strength to achieve a hydraulic seal

Leaking seal or valves Mechanical over load

interface for connecting a riser, BOP or xmas tree

Contains completion fluids within its bore so that it does not leak out into any other annuli or exposed formations Provides a positive sealing device in the tubing to prevent flow from the formation side. Provides a mechanical seal between the completion tubing and the casing liner. Establishes the “A” annulus above thus preventing communication from the formation into the annulus.

Leak at any connections Leaks caused by corrosion or erosion Parted connections Leak across v packing either externally or internally

Leaks across either the internal or external seals

18.0

WC02.05 Barrier Test Documentation

All pressure tests must continue until a straight line has been held for 10-minutes to the specified pressure on a certified chart recorder or equivalent. This chart must be signed by a company representative to witness the completion of a satisfactory pressure test and must contain the following information:

Sequence that pressure test was carried out against relevant section of chart.



Equipment identification numbers being pressure tested.



Client name



Field



Well No.



Date



Test Medium

The different mediums commonly used while pressure testing are as follows:

19.0



Water



Water/Glycol mix

WC02.06 Corrective Action Due to Barrier Test failure

Depending on the type of barrier that failed will depend on the course of action to be taken? Failed wireline retrievable DHSV would require changing out. Failed tubing retrievable DHSV would require locking out & set insert valve. Failed plug would either require pulling and resetting if leak-off was insignificant set another plug above. Annulus pressure would require monitoring or lubricating and bleeding

20.0

WC02.07 Barriers

All barriers that are not liquid are mechanical barriers. Just like a fluid barrier, a mechanical barrier must also satisfy many requirements in order to be approved. It must be defined, described, tested, approved and documented. P a g e | 29

We have several types of mechanical barriers and it is natural to undertake a grouping. We discern between permanent and temporary barriers. In addition, we separate between permanently installed and closable barriers. There are requirements for the testing of barriers. Since there are different types of equipment that go into the barriers, it is necessary to test in different ways. In some cases it is necessary to put extra pressure on one side. This is called a positive test. Other times it is necessary to bleed off pressure on one side to check if there is leak. This is called an “inflow test,” or a negative test. As an example, the well will be pressurized to test if the cement holds when the casing has been cemented. When the BOP is to be tested before rigging up, it is closed and exposed to pressure from different directions depending on how it is configured.

20.1

Barrier Types

There are two types of barrier, mechanical and fluid

P a g e | 30



Mechanical Plugs



Check Valve / BPV Valve



Pressure Cycle Plug



Pump Through Plug



Expendable Plug



Wireline Plug



Pump Open Plug



Bridge Plugs



Cement Plugs



Ice Plugs



Overbalanced Fluids

20.1.1 Tubing Hanger Plugs

The innermost hanger, the tubing hanger, usually has a profile for locating a Tubing Hanger Plug (THP) or Back Pressure Valve (BPV) or Two Way Check Valve (TWCV). These all perform the same function i.e. seal off the top of the well below the Xmas tree to allow the tree to be tested, repaired or removed. These well containment devices can be run into the tubing hanger with the well under pressure and used as mechanical barriers required before removing a Xmas tree. There are two basic types of tubing hanger plugs, wireline plug type and a type that is mechanically screwed into the hanger called Back Pressure Plugs (BPV).

20.1.2 Wireline Type Plugs The wireline plugs are run into the profile and locked in the tubing hanger. The various types of plug. Seal off the wellbore from below but still allow pumping through from above (BPVs), Seal off in both directions (Positive Plugs) and that will seal off in either but allow slow pumping through the valve from above (Tics). These plugs can be run and pulled with a wireline unit or by using a special lubricator which does the same job but is operated manually using rods whilst still containing the well pressure.

20.1.3 Threaded Plugs These plugs are screwed into a threaded section of the tubing hanger where they seal externally. They are run and pulled using a special lubricator (Polished Rod Lubricator) that contains the wellbore pressure whist the plug or valve is being run or pulled.

20.1.4 Blanking Plugs Blanking plugs are set in nipples to shut off the flow of fluids. A true blanking plug has no fluid bypass facility making running procedures slow. Bypass blanking plugs allow fluid bypass and may require one or two runs to set them. Before these plugs are pulled they should be equalised above and below.

P a g e | 31

20.1.5 Check Valves (Standing Valves) Standing valves or check valves (not to be confused with the check valves which form part of a coil tubing or snubbing Bottom Hole Assembly) are run and set in a nipple and are designed to hold pressure from above only. They are used for pressure testing the tubing above them and for setting packers. The valve can be recovered as soon as pressure testing or packer setting operations are complete. This type of valve is usually fitted with an equalising valve that will shear prior to pulling. Check valves will normally only require one wireline trip for running and retrieval since the wireline remains latched during packer setting or pressure testing operations.

20.1.6 Pump Through Plugs Pump through Plugs hold pressure from below and are used to isolate the well below their location in the wellbore. These plugs can be pumped through for well kill operations etc.

20.1.7 Pump Open Plugs Pump Open Plugs are positive plugs but can be pumped open by applying excess surface pressure. They serve as temporary tubing plugs that can be pumped open for production without having to be retrieved by wireline.

20.1.8 Expendable Plugs This is a plugging device run as an integral part of the tubing. It can be used to set a hydraulic set packer or to test the tubing string. When the plug is expended, the plugging material disintegrates leaving a full tubing I.D.

20.1.9 Pressure Cycle Plugs Pressure cycle plugs are similar to Pump Open Plugs but with this design the plug opens after pressure above the plug has been cycled a pre-set number of times (up to 20) and to a pre-set pressure. This cycling offers better protection against premature opening. These plugs can be run into a nipple on a lock mandrel or they can be pre-installed prior to running the completion.

P a g e | 32

20.1.10

Ice Plugs

This (non-routine) type of plug is classified as a mechanical plug and is set using the Freeze Method. An ice plug is made in the wellhead or other surface component. The process of making ice plugs involves chemicals like glycol, heat exchangers, dry ice, liquid nitrogen and static fresh water. The process is very slow and it may take up to 18 hours for an ice plug to form.

While testing a mechanical barrier (positive plug) in a well, it will mainly be exposed to differential pressure when one bleeds off pressure on the topside of the plug. There are many ways of performing a test and it is important to know where information about the correct procedure can be found. In many cases, it will be internal test procedures or the operator company’s procedures that apply. Often the applicable procedure will be put in as a part of the well program or referred to in the operational manual, API, NORSOK or the equipment suppliers’ recommendations. The procedures will be built on experience, manufacturer recommendations, and requirements from the authorities.

20.2

Hydrostatic Fluid

A fluid barrier is a liquid fluid column with a specific gravity that allows the hydrostatic pressure to be higher than the reservoir pressure at the bottom of the well. A fluid barrier is always the primary barrier and must be observable. A mechanical barrier is a tested and approved barrier that is not liquid A fluid barrier is a fluid column with enough specific gravity to create a hydrostatic pressure that is larger than the reservoir pressure at the bottom of the well in question is called an overbalance.

Overpressure on the reservoir is called overbalance or kill margin. The strength and friction in the reservoir decides how large this difference can be. It is assumed that there is fluid from the bottom all the way to the surface. It is also assumed that the fluid column is in direct contact with the reservoir fluid and pressure. In other words, there cannot be a plug placed in the well.

P a g e | 33

It is a requirement that the fluid barrier is observable. This can be done in several different ways, the most primitive way being to keep watch at the top of the well to see that the fluid is stable. A fluid barrier will always be a primary barrier. As a curiosity we can say that if we freeze water so that it becomes an ice plug this will be a mechanical barrier once it is tested and approved.

Barriers MUST be observed

Hydrostatic barriers are primary barriers if they are being monitored i.e. it is important to know the fluid is still present and the physical properties of the fluid to ensure an overbalance at the top of the perforations. Hydrostatic barriers exert a hydrostatic pressure sufficient to overbalance the formation pressure.

21.0

WC02.09 Principle of Barrier Classification

Barriers are classified as follows: Primary - The barrier that performs well pressure control function during normal operating conditions. Usually a closed barrier

Secondary - The barrier that performs well pressure control function in the event that the primary barrier fails. Usually a closable barrier.

Tertiary - The barrier that performs well pressure control function in the event that the primary and secondary barriers fail.

The Primary barrier for slickline is the stuffing box or for braided line, the grease head. The equivalent device for Coiled Tubing and Snubbing operations is the Stripper packer, Stripper rubber or Stripper rams. The Secondary barrier for Wireline is the wireline BOP, for Coiled Tubing the tubing rams (pipe rams) and for Snubbing the Safety rams (pipe rams)

P a g e | 34

The Tertiary barrier for all three services is a cutter valve, usually a shear seal (safety head) which is normally mounted immediately above the Xmas tree. This type of barrier would be used only in a real emergency situation.

Types of Mechanical Barriers:

CLOSED BARRIERS 

Stuffing boxes



Strippers



Grease Heads



Plugs

CLOSABLE BARRIERS 

BOP's



Shear Seal/BOP valves



Annular Preventers



Xmas Tree Gate Valves



Sub-Surface Safety Valves

In some areas, Sub-Surface Safety Valves are not classified as barriers since API specifications allow an acceptable leak rate for safety valves. Sub-Surface Safety Valves may however be classified as barriers if they are leak tight.

21.1

Principle of Primary and Secondary Well Barrier Envelopes

While testing a mechanical barrier (positive plug) in a well, it will mainly be exposed to differential pressure when one bleeds off pressure on the topside of the plug. There are many ways of performing a test and it is important to know where information about the correct procedure can be found. In many cases it will be internal test procedures or the operator company’s procedures that apply. Often the applicable procedure will be put in as a part of the well program or referred to in the operational manual, P a g e | 35

API, NORSOK or the equipment suppliers’ recommendations. The procedures will be built on experience, manufacturer recommendations, and requirements from the authorities.

21.2

Barrier Requirement

All wells should be secured with a minimum of two barriers that must be tested, whether the well is live or dead. So, what then do we understand by the word barrier? Any mechanical or fluid device that prevents the flow of pressure or fluids On a drawing of a cross section of a well, we can draw a line from the bottom of the well up to the surface and down again on the other side. We call this a barrier envelope. Such an envelope is composed of many barrier elements, and we must differentiate between the envelope and the elements. If we put a plug in the well, it is a barrier element that is part of a barrier envelope. The barriers are to be independent of each other. This means that we should be able to draw two separate lines outside each other on the well drawing. That which is active against the well pressure is the primary barrier. For example, in wireline the lubricator and stuffing box are the primary barrier. If this leaks, the secondary barrier activates, which will be the BOP closing around the wire. If the secondary barrier fails, the tertiary barrier is activated, which is some form of a cut-and-seal ram. IWCF defines everything that cuts and seals as a tertiary barrier. It can be a rigged up a manual shear ram, a hydraulic shear ram in the BOP, or a main valve in the Xmas tree if it is designed for cutting wire. In any case, the valves must be individually tested and approved before they are accepted as barriers.

P a g e | 36

22.0

WD01.01 Principles of Risk Management  Are generally a way to express such a risk is by combining the probability of an event with its consequences.  Barriers are introduced as a means of risk management, by reducing the probability or severity of an event.  Defined as measures designed/implemented to reduce the probability of triggering apredefined hazard and/or to reduce the consequence of a pre-defined hazardous event.

For example a well to kick, the primary barrier is the preventive barrier while the secondary barrier is the mitigating barrier.

22.1

22.2

WD01.01 Principles of Risk Management 

Create value – resources expended to mitigate risk should be less than the consequence of inaction, or the gain should exceed the pain



Be an integral part of organizational processes



Be part of decision making process



Explicitly address uncertainty and assumptions



Be a systematic and structured process



Be based on the best available information



Be flexible



Take human factors into account



Be transparent and inclusive



Be dynamic, iterative and responsive to change



Be capable of continual improvement and enhancement



Be continually or periodically re-assessed

Method

For the most part, these methods consist of the following elements, performed, more or less, in the following order. P a g e | 37

Identify, characterize threats Assess the vulnerability of critical assets to specific threats.

Determine the risk (i.e. the expected likelihood and consequences of specific types of attacks on specific assets) Identify ways to reduce those risks

Prioritize risk reduction measures based on a strategy

23.0

WD01.02 Management of Change

An Examiner will be responsible for verifying that the program execution follows the well design/plan in regard to critical well control issues and ensures compliance with the reporting as it relates to those requirements; ensuring all critical changes as they relate to well control issues are managed thru appropriate risk assessment and management of change (MOC) procedures To ensure that any deviations from approved procedures or processes used by the company are: 

Documented



Managed



Authorized

The impact of risks to people and the environment are assessed and mitigated prior to the deviations being implemented. Where there is a belief a change may introduce new hazards or increase risk, the procedure shall be implemented. This procedure shall apply to all activities carried out by employees of the company and by its Subcontractors. It shall apply to all health, safety and environmental risk it shall cover all activities including field operations, base operations and maintenance.

Shall apply across all activities including:



P a g e | 38

Situation or client changes to the work scope in the field, including formal variation orders.



Changes impacting testing activities wherever these are carried out.



Change which occurs as a result of events effecting routine operational, maintenance and/or workshop fabrication activities.

Major change requires the following:

23.1



All work affected by the change must be stopped



Complete the company documentation,



Offshore documentation must also be signed by the company man.



Risk Assessment done to take account of changes



Management approval must be obtained before the work can resume.

Responsibilities 

All Personnel



Supervisors



Managers



Personnel



Stay alert and assess the impact of change and its potential for creating or increasing risk or pass information about the change to a competent person who can make the assessment.



Act on the assessment and document and implement a revised work activity and risk assessment.

PS - Before resuming work, communicate the changes to all persons potentially affected by the changes.

23.2

Procedures

Minor Change - If a change is minor it shall be dealt with at the worksite using relevant company procedure and clearance to proceed will be based on a suitable assessment. Major Change - If a change is major it shall be dealt with using the company MOC form. This must be completed at the worksite and the content communicated to an appropriate manager. If the MOC relates to offshore or onshore field based work for clients, the MOC must be signed by the client. The risk assessment for the work shall be reviewed and approved. The manager must give his approval before work can resume

P a g e | 39

24.0

WD02.01 Emergency Drills

The following guidelines shall be followed for well control drills:

24.1



Well control drills shall be initiated by the contractor or the Drilling Supervisor and performed under the supervision of the Drilling Supervisor to ensure that the crews are adequately trained and prepared to implement well control procedures correctly.



Well control drills shall only be conducted when they do not complicate ongoing operations.



A kick should be simulated by manipulation of a primary kick indicator such as the tank level indicator or the flow line indicator.



The drills described in the above section include the full sequence of shutting in a well. The critical reaction time shall be measured up to the point when the well is closed in.



Trip drills shall only be conducted if the BHA is inside the casing shoe.



Out-of-hole drills may be conducted at any time when out of hole with no tools orwire line through the BOP stack

Abandonment Drill

Abandonment drills must include the following: Each drill must include summoning of industrial personnel and crew to muster stations with the general alarm, followed by drill announcements on the public address or other communication system, and ensuring that all on board are made aware of the order to abandon ship. Each should include the following:

24.2

o

Reporting to stations and preparing for the duties described in the muster list.

o

Check that all personnel and crew are suitably dressed.

o

Check that lifejackets or immersion suits are correctly donned.

o

Lower at least one lifeboat after any necessary preparation for launching.

o

Start and operate the lifeboat engine.

o

Operate the davits used for launching the life rafts

Fire Drills

Fire drills must, as far as practicable, be planned in such a way that due consideration is given to regular practice in the various emergencies that may occur depending on the type of unit. Each fire drill must include: P a g e | 40

24.3



Reporting to stations, and preparing for the duties described in the muster list for the particular fire emergency being simulated;



Start fire pumps and the use of two jets of water to determine that the system is in proper working order;



Check the fireman's outfits and other personal rescue equipment;



Check the relevant communication equipment;



Check the operation of watertight doors, fire doors, and fire dampers and main inlets and outlets of ventilation systems in the drill area;



Check the necessary arrangements for subsequent abandonment of the unit and simulated operation of remote controls for stopping ventilation and fuel supplies to machinery spaces.



The equipment used during drills must immediately be brought back to its fully operational condition, and any faults and defects discovered during the drills must be remedied as soon as possible.

Reporting

The Drill is to be documented in the daily report. Under remarks the following shall be recorded: 

Type of drill.



Time of drill.



Reaction time in seconds from the moment the kick is simulated until the well is closed in.

The designated crew member is a member of the drill crew who is present on the drill floor at the time of a BOP drill or well control situation. All drill crew members must be capable and able to react correctly to the drill or real well control situation. The total time taken for the drill. The time taken should be less than a pre-determined benchmark. If not, the drill shall be repeated.

The following shall be recorded on the DDR:

P a g e | 41



The reaction time from the moment the kick is simulated until the designated crew member is ready to start the closing procedure.



The total time it takes to complete the entire drill.



Time drill was held (to determine which crew performed the drill).

25.0

WG01.01 Circulating System

Pump pressure is produced by the pump to move the required volume of mud/fluids from the pump through the drill-string, the bit and up the annulus to the surface. All the pressure produced by the pump is expended in this process, overcoming friction losses between the mud and whatever it is in contact with. The pump should be capable of pumping the surface lines and a maximum anticipated SIWHP plus a margin for friction. Pumping Equipment contains the following items:



Pump o

Rating

o

Barrel/stroke

o

Relief valve setting



Surface Pump Lines



Choke Manifold



Isolation Valves



Pressure Gauge



Fluid Disposal System



Mixing Tanks



Reserve Tanks



Fluid



Chemicals o

Corrosion Inhibitor

o

Oxygen Scavenger

o

Biocide

Bottom Hole Pressure increases when the pump is running. Pump pressure, which is also referred to as system pressure loss, is the sum total of all the pressure losses from the well surface equipment, the drill pipe, the drill collar, the drill bit, and annular friction losses around the drill collar and drill pipe. It measures the system pressure loss at the start of the circulating system and measures the total friction pressure.

26.0

WP01.01 Inflow Testing

P a g e | 42

After setting a barrier in the well needs to be tested preferably in the direction of the flow by means of an “Inflow test” or negative test. They are generally carried out to verify that there is no communication with the formation through the casing, a liner lap or past a cement plug (bridge plug) and other pressure control devices set in the well, either during production or work-overs. Most of the applications are in connection with testing or squeezed off perforations and casing leaks, testing liner-laps, Xmas trees, DHSV, cement plugs and bridge plugs, wireline plugs or individual well barrier elements. An inflow test is performed by reducing the hydrostatic head above the item to be tested by circulating to a lighter fluid or by bleeding pressure above the barrier in question then monitoring for any pressure build up.

27.0

WP01.02 Importance of the Inflow Test

Barriers should be pressure tested in the direction of flow. Where the barrier cannot be pressurized from below the only way to verify the integrity of the seal is to do an inflow test by reducing pressure from above. Before the production completion is run, the well is displaced to a lighter fluid to encourage flow of formation fluids into the wellbore. if any problems with the connections or the casing line lap are present, this could pose a threat to the well and personnel working on it as formation fluids could by-pass any safety related equipment in the well. 28.0

WP01.03 Interpreting Inflow Test Results

The “Horner Plot” method should be used for interpreting inflow tests to confirm the integrity of liner laps for over pressured gas wells.

P a g e | 43

29.0

WP01.05 Inflow Test Procedures

Direction of flow – Confirmed - OK

Alternative 

Pressure Test



Lower than maximum load



Opposite direction to flow



Differential volume

Other - Physical Test

P a g e | 44



Slack off weight



Mud density check.

30.0

WH01.01 Integrity Testing

A mechanical barrier must always be tested from below by means of an inflow test before it can be accepted. The way this is done varies depending on which component is being tested and in which situation the need for testing arises. One thing in common for all the test methods is that a predefined pressure difference must be created in such a way that it can be read off and documented on a pressure recorder.

31.0

WH01.02 Integrity Testing Procedures

In some cases, we will pump fluid into the well and then increase the pressure on one side in order to observe a drop in pressure. In other cases we will bleed off pressure on one side and then observe a pressure increase. In all cases we act according to the described procedures and leak criteria.

31.1

Safety Valve Leak Testing  Leak tests are performed immediately after Sub-Surface Safety Valves are installed.  A typical leak test involves closing the production, kill and swab valves on the Xmas tree and bleeding off the control line pressure to the Sub Surface Safety Valve.  Tubing pressure is bled off slowly above the valve to zero for a tubing retrievable valve and in 100psi. (6.9bar) stages for a wireline retrievable valve.  For hydrostatic on body, the test pressure shall be determined by the rated working pressure of the equipment. Refer to API Spec. or manufacture’s procedure for details of testing.  During testing, check visible signs for leakage and for multiple bore component, eachbore shall be tested individually.

31.2

P a g e | 45

Tree and Wellheads 

Bi-directional valves shall have hydrostatic seat test pressure equal to the rated working pressure applied to each side of the gate with the other side open to atmosphere.



For uni-directional, valves shall have pressure applied in the direction indicated on thebody, except for check valve which will be tested on the down-stream side.



If function tests under full differential pressure are required, check for actual pressure maintained.

31.3

Mechanical Barriers

Must be tested, preferably from the direction of flow. If an inflow test cannot be carried out it can be tested from above by using positive pressure.  Tests on closed type barriers should be leak tight. The leakage rate on closable barriers such as Xmas tree valves etc. should be the API leakage criteria: 400cc/min or 900scf/hr with the exception of sub-surface safety valves used in well plugging (refer to note above in list of closable barriers).  Each operator should develop procedures for testing Xmas tree and sub-surface safety valves to meet this criterion.

31.4

Sliding Side door

A communication device such as a Sliding side door is tested when it has been moved to the closed position. Because the well bore is open to the formation the only feasible solution is to apply a small amount of pressure to the annulus to prove the backside of the SSD is holding pressure.

31.5

Formation Integrity Tests

To determine the fracture pressure of a formation, a leak-off test (LOT) or a formation integrity test (FIT) may be performed with a solids carrying fluid or mud. Where solids free workover fluids are used, a formation integrity test cannot be conducted and in these cases the formation is protected solely by a MAASP, which is set at a safe percentage of the original casing pressure rating.(i.e 80% of casing burst pressure) LOTs and FITs determine if the cement seal between the casing and the formation is adequate and the maximum pressure or fluid weight that the formation(s) can withstand without fracturing. As the leak-off test actually causes a fracture to determine the fracture gradient, it is rarely used in well servicing operations and the FIT is adopted. Whichever is to be performed, it must be ensured that the well is fully circulated to the correct weight workover fluid and the pump deliverability is sufficient.

31.6

Leak Off Tests

The test is performed by applying incremental pressures from the surface to the closed wellbore/casing system until it can be seen that fluid is being injected into the formation. Leak-off tests should normally be taken to this leak-off pressure unless it exceeds the pressure to which the casing was tested. A typical procedure is as follows: P a g e | 46



Before starting, gauges should be checked for accuracy. The upper pressure limit should be determined.



The casing should be pressure tested before well operations commence.



Circulate and condition the mud, check mud density in and out.



Close BOPs.



With the well closed in, the pump is used to pump a small volume at a time into thewell typically a 1/4 or 1/2bbl per min. Monitor the pressure build up and accurately record the volume of mud pumped. Plot pressure versus volume of mud pumped.



Stop the pump when any deviation from linearity is noticed between pump pressure and volume pumped.



Bleed off the pressure and establish the amounts of mud, if any lost to the formation.

Examples of leak-off test plot interpretation In non-consolidated or highly permeable formations fluid can be lost at very low pressures. In this case the pressure will fall once the pump has been stopped and a plot such as that shown will be obtained as shown typical plots for consolidated permeable and consolidated impermeable formations respectively.

Idealised Test Curves

P a g e | 47

31.7

Formation Integrity Tests

A FIT can be performed when it is not acceptable to fracture a formation. In a FIT, fluid is pumped into the shut in well until a predetermined pressure is reached that is determined to be below the pressure to break down the formation. This value used is usually obtained by accessing information from well’s completion report and nearby well data. The procedure is:

32.0



Before starting, gauges should be checked for accuracy.



The casing should be pressure tested before well operations commence.



Circulate and condition the mud, check mud density in and out.



Close BOPs.



With the well closed in, the pump is used to incrementally raise the pressure in the well to the test pressure and monitor the pressure to ensure that there is no leak off.

WI01.01 Boyle’s Law

Boyle's Law, a principle that describes the relationship between the pressure and volume of a gas. According to this law, the pressure exerted by a gas held at a constant temperature varies inversely with the volume of the gas. For example, if the volume is halved, the pressure is doubled; and if the volume is doubled, the pressure is halved. The reason for this effect is that a gas is made up of loosely spaced molecules moving at random. If a gas is compressed in a container, these molecules are pushed together; thus, the gas occupies less volume. The molecules, having less space in which to move, hit the walls of the container more frequently and thus exert an increased pressure

33.0

WI01.02 Circulation of Influx

As the influx is circulated up the well, the volume increases and the hydrostatic head above reduces, however as bottom hole pressure is kept constant by increasing the surface annulus pressure to compenstate for the hydrostatic loss

P a g e | 48

34.0

WI01.03 Basic Gas Law

Gas kicks that dissolve in mud can be difficult to detect, especially if the kick is relatively small. Since they are absorbed by the mud, little or no pit gain occurs. Also, no measurable increase in the flow rate of the mud being pumped out of the well occurs. Later, however, as the dissolved gas in the mud nears the surface, it begins evolving from the mud and rapidly expands. This rapid expansion suddenly increases the return flow rate and can create a large pit gain if the well is not rapidly shut in. Also, when a gas kick dissolves in the mud, and Crew members do detect it, they may believe that the well has taken a saltwater kick: the pit gain may be relatively small and the difference between the shut-in Drill pipe pressure and the shut-in casing pressure may be small. When dissolved gases come out of solution, however, they expand rapidly. As a result, the shut-in casing pressure rises quickly. Personnel should be aware of the problem and keep close surveillance on the casing pressure. Because gases can dissolve in mud, most operators and contractors prefer to consider all kicks as gas kicks and react appropriate.

35.0

WI01.04 Influx Migration The gas kick volume will increase when the kick is circulated up a vertical well because the reduction in hydrostatic pressure results in expanding of gas as per Boyle’s gas law

Boyle’s Law P1 x V1 = P2 x V2

The pressure trend for a gas influx in an open well will increase the bubble size but will reduce the pressure. If the bubble doubles the pressure will half.

35.1

Shut In Pressures in a Horizontal Well

In horizontal wells, kicks can come into the well and you will see pit gain but when the well is shut in you will not see any difference between shut in casing pressure and shut in drill pipe pressure. This situation happens because the kick in the horizontal section does not have the vertical height.

You will not see any drastic pit gain when the gas kick is still in the horizontal zone but the pit gain will significantly increase once it starts going into the deviated / vertical section of the well.

P a g e | 49

35.2

Behaviour of Influx Fluids

Gas in the horizontal section of a well is unlikely to migrate. The undulations (unevenness) of the horizontal section may allow gas pockets to become trapped during kill operations. Therefore higher flow rates at a later stage may move these pockets along the hole with the potential for the loss of hydrostatic pressure due to gas expansion, once the influx moves out of the horizontal section. As soon as gas is circulated out of the horizontal section, it will then affect bottom-hole pressure, but not necessarily the pit volume until it moves closer to surface. Gas migration may be rapid in the high angle sections of a hole due to the influx moving up the “High Side”. Wells that are deviated at or close to surface may encounter severe problems with gas migration. Brine fluid circulated up the annulus in high angle wells will tend to flow on the high side. Bottoms up may occur sooner than expected, due to the reduced flow path. During well control operations, as a gas influx, is circulated from the horizontal section, into the deviated section, it will cause the casing pressure to increase without any corresponding increase in pit level. Running into swabbed fluids in the horizontal section may cause the influx fluid to move into the deviated well section therefore reducing bottom hole pressure.

36.0

WJ01.01 Shut In Procedure

Normal opening and closing of the Xmas tree when running in or pulling out of the hole. Before running into the well, the rig up is tested according to the current procedures to a minimum of CITHP.

Running In Check that the lower master valve (Manual Master Valve - MMV) is open. Count the number of turns and report if the number deviates from the well records. Open the upper master valve (Hydraulic Master Valve - HMV). This is usually a “normally closed” or “fail safe close” type valve and must therefore be kept open with the help of hydraulic pressure. Well pressure can now be read off the gauge in the Xmas tree’s body and pressure in the lubricator can be equalised to well pressure. The swab valve, which is a manual valve, can now be opened. The revolutions are to be counted and reported so that they can be compared the next time the valve is closed. The xmas tree is now opened up and well intervention equipment is ready to be run into the well.

Pulling Out P a g e | 50

When the equipment is pulled out of the well after the task, the Xmas tree shall be shut in again. This takes place more or less in the opposite direction of what is described above:

37.0



Pull the equipment out of the hole and up into the lubricator in accordance to the current procedures. Close the swab valve carefully while counting the number of turns. If too few turns are registered, this means that there is an obstruction in the valve. Open the valve and attempt to pull farther out of the hole before trying to close the valve again.



When the swab valve is closed with the correct number of turns, it can be tested. The upper master valve (HMV) can now be closed. Check that it is completely closed with the help of the indicator. When the master valve is closed, it is to be tested. The most common way to do this is by opening the swab valve with a few rotations and then bleeding off the pressure into the drain.



When the master valve is tested, the swab valve is closed once more. At this point we can define ourselves as being out of hole; the lubricator can be opened and tools can be changed/replaced.

WJ02.01 Shut In Procedure - Tree

When equipment is run into the well it is no longer possible to close the Xmas tree in the usual way since there is now a wire-line or pipe through the valves. If the need arises to close and secure the well in this situation, one must resort to shutting in the rigged up BOP around the wireline or pipe. When activating the BOP, this will normally take place with the help of hydraulics, either by activating an accumulator, or by using the air-driven pumps. This is controlled form the BOP’s control panel or from the panel on the pump unit themselves. When the BOP is hydraulically closed, the manual stem should always be screwed in to secure that the BOP is and stays closed. If possible, the BOP is now tested in the current situation, and it cannot be disconnected or worked on before the testing is completed. Testing consists of bleeding off pressure on the upside of the BOP and inflow testing the valve. Leakage criteria and the length of the test can vary from operator to operator. Ensure that the applicable procedures are available before running into hole. In some cases it will not be enough to secure the well in the described manner. It may then be necessary to cut the wireline or pipe so that it is possible to shut in the Xmas tree and possibly the subsurface safety valve. In such instances it is often the case that you should pull out of hole enough that the pipe or wireline falls below the valve after cutting. Emergency procedures for this will vary from operator to operator, but they have common features. Make sure that you know the procedure and have it available before running in the hole.

38.0

WJ02.02 Shut In Procedure - Well

P a g e | 51

How to verify that the well has been shut in and explain the correct action. Once the well is shut-in, check the following:

39.0



That shut-in pressures are being monitored



That the pit gain is recorded



That the preventer is making the proper seal



Check the flow line for possible leaks



The choke manifold is lined up and check for leaks



Close if necessary the valve upstream of the active choke

WJ02.03 Shut In Pressures Procedures

When a well has been shut in after years of productivity, it will become necessary to monitor the SITHP for a period of time. It is not unusual to have small bubbles of gas in the well, which will require time to migrate to the surface, therefore it is imperative to monitor the gauge on the tree cap. When the pressure stops building it will be safe to proceed with the work over as per company procedures. Common causes of Increase shut-in tubing head pressure are:

40.0



Gas Migration



Thermal Expansion



Gas Build up

WJ02.05 Valve Opening Precautions _ Procedures

Most valves are constructed to be opened and closed under pressure, but not with pressure on only one side. This means that one usually can close a valve without significant problems, but that one must always ensure that there are no mechanical objects in the flow path of the valve that is to be closed.

It is standard practice to count the turns a manual valve has in order to verify whether it is entirely opened or closed. On hydraulic valves there is usually an indicator that shows whether the valve is fully opened or closed. If you want to open a valve, you have to ensure that the pressure is first equalized, so that no damage occurs to the valve or equipment downstream of the valve. On a manual valve there is danger for damage on the stem while on hydraulic valves there is greater danger for damage on the gate and seat. P a g e | 52

The damage that can be caused by pressure waves downstream of the valve are primarily related to The damage that can be caused by pressure waves downstream of the valve are primarily related to situations where there is for example well intervention equipment in the riser. A pressure shock will potentially damage the equipment in the riser or the tool-string rope socket. It may also have equipment damage and delays. Opening:

Differential surges of pressure possibly kinking the wire at the rope socket causing damage to the stem Closing: Closing the valves on the tool-string Possibility of cutting the wire Counting the turns on the swab valve

41.0

WJ04.01 Shut In Pressures

When the well has to be shut in after a period of flow or production, it is advisable to observe the well head pressure gauge to ensure that the wellhead pressures can be monitored. The procedure is quite simple:

42.0



Close the choke followed by the Flow wing valve.



Ensure that the tree cap pressure gauge is not isolated.



Pressure gauges must the correct diameter and pressure rating



Pressure gauges must also be in calibration and within the test certification.



Monitor wellhead pressure and note any build up in pressure. Gas percolation



When pressure stops building up wait a suitable length of time to ensure no further build up.

WJ04.02 Differences Between SITHP and SICP

The reasons for possible differences between the shut in drill pipe pressure and casing shut in pressure could be due to one of the following:

P a g e | 53



Blockages in the annulus



Inaccuracy of the pressure gauges



Well deviation



Well bore fluids



A kick has occurred

43.0

WJ05.01 Limitations of Pressure Gauges

Broken gauges lead to bad decisions, and bad decisions lead to process downtime or accidents. The frustrating part is that most of these expensive and potentially dangerous issues could be relatively easily prevented. When there are hundreds or even thousands of gauges in a large offshore facility, some gauges are going to be damaged or malfunction in a given year no matter the technical proficiency of the maintenance team. It's simply a matter of statistics. Many times, gauge failure can be attributed to misapplication, but all too often, extreme or stressful conditions may cause gauges to fail. Common reasons for gauge failure and recommended solutions to help avoid the headaches of frequent replacement and risks of inaccurate readings, which can lead to a catastrophic disaster.

43.1

Temperature

Extremely high or low temperatures can have a negative impact on gauges and other instrumentation. Gauges not designed for these extreme operating conditions can malfunction in a relatively short period of time. Some gauges are designed for extreme temperature conditions and will provide reliable information for the lifetime of the instrument. Gauges designed for use in extreme temperatures, are made from special corrosion-resistant alloys and can be equipped with cooling fins or a diaphragm seal to isolate the gauge from the hot or cold media.

43.2

Mechanical Vibration

Numerous studies have shown that vibration is the main cause of pressure gauge failure in manufacturing facilities. Vibration has a negative impact on gauge accuracy in two ways. First, it is difficult to accurately read a pointer on a dial when a gauge is vibrating. Second, incremental damage to the pointer mechanism from vibration can eventually move a pointer off zero, producing inaccurate readings. Different types of gauges are built to withstand various types and levels of vibrations, and it is critical to use an appropriate, quality gauge for every application. Installing a pressure gauge with low vibration resistance in a high-vibration area is a recipe for trouble. Not only will it have a dramatically shortened lifetime, the vibration might even crack the Bourdon tube and release process media. High quality liquid-filled gauges, which dampen vibrations and minimize stress on internal components, are ideal for high-vibration applications.

P a g e | 54

43.3

Over Pressure

Process media is normally transported through a piping system at relatively high pressure, and gauges appropriate for that pressure are installed for process monitoring. However, when workers switch pumps on or off, or open or close valves, a surge of media flows through the pipe and impacts the pressure gauge, causing a spike which can damage the gauge. The solution to overpressure problems is to use reliable gauges with tolerances several times higher than the standard flow pressure or to install overpressure protectors on gauges in areas where overpressure spikes tend to occur.

43.4

Pulsation

Pulsation can be defined as regularly occurring overpressure spikes. When media rapidly cycles through the gauge, the pressure spikes intermittently. The most common solution for pulsation involve installing a socket restrictor or a pressure snubber, which slows down the media by reducing the size of the intake orifice and minimizes pressure fluctuations.

43.5

Corrosion

Many process media are corrosive, and any gauges used in these process streams must have internal parts that are resistant to corrosion. Bourdon tubes can corrode and release dangerous process fluid if a gauge made of non-corrosion- resistant material is used or if a gauge made of an appropriate material is used beyond its lifetime. Another solution is to use a diaphragm seal made of a corrosion-resistant alloy.

43.6

Clogging

Clogging can be a serious problem for gauges, especially with process media that are subject to congealing or crystallization. Gauges that become clogged often "freeze up," creating a dangerous situation of indicating no pressure when in fact the system is under tremendous pressure. The best solution for most clogging problems is to use a diaphragm seal equipped with flushing ports to constantly flush the diaphragm surface.

P a g e | 55

44.0

WJ06.01 Gas Migration

It’s a principle that describes the relationship between the pressure and volume of a gas. According to this law, the pressure exerted by a gas held at a constant temperature varies inversely with the volume of the gas. For example, if the volume is halved, the pressure is doubled; and if the volume is doubled, the pressure is halved. The reason for this effect is that a gas is made up of loosely spaced molecules moving at random. If a gas is compressed in a container, these molecules are pushed together; thus, the gas occupies less volume. The molecules, having less space in which to move, hit the walls of the container more frequently and thus exert an increased pressure The gas kick is highly compressible, the space the gas occupies will depend on the pressure and temperature. Ignoring the temperature and other effects, reducing the pressure on the gas will allow it to expand occupying more space. If the pressure is increased then the volume will decrease. If the pressure is maintained then the volume will remain unchanged If gas is allowed to migrate in a wellbore that is closed in then there is no room for any expansion to take place. This means the gas will take its original pressure with it as it moves up the wellbore. When this happens it is seen as a pressure rise on both SICP and SIDPP. This causes the well to pressure up in all directions creating extra pressure at the shoe and on the bottom of the hole, whilst the gas bubble pressure remains unchanged. To reduce the pressure caused by gas migration a calculated amount of drilling fluid must be bled from the choke in order to allow the gas to expand, which will in turn reduce the pressure. This procedure will return SIDPP to its original value but SICP will have increased slightly above its original value. Gas in water based mud can migrate up the well bore. Migration will occur if the well is shut in or open. With the well open gas will expand as it migrates and displace mud from the well. The pressure from the gas will be reducing. If the well is shut in and the gas migrates, it cannot expand, no mud is being displaced from the well, to allow expansion. If the gas cannot expand then the pressure will not change.

45.0

WJ06.02 Monitoring Pressures at Shut-in

The importance of monitoring surface pressures immediately after shut-in When the well is shut-in, fluid form the well at surface is stopped but the formation fluid is still flowing into the well. While the surface pressures build up the formation fluid is still flowing into the well bore. Once the surface pressures have stabilized the flow of fluid from the formation to the wellbore ceases. 46.0

WJ06.03 Pressure Trends

After the well is shut-in and the shut-in pressures have stabilized the flow of formation fluid into the wellbore stops. The volume of gas in the wellbore remains constant. As the gas P a g e | 56

slowly moves up the wellbore due to differences in density between the wellbore fluids the volume of the gas remains constant. Using Boyles law if the volume remains unchanged then the pressure exerted by the gas also remains unchanged. As the gas migrates up the wellbore all the surrounding pressures increase. If the surrounding pressures exceed formation fracture pressure then fluid will be lost to the formation. 47.0

WK02.01 Production Well Kill Procedures The choice of well kill procedure will depend on a number of factors including tubing and casing integrity, ability to circulate the annulus, formation pressure and the method of well completion.

When it is required to kill a production well, the easiest, quickest, most certain method is by circulation. This requires establishing a communication path as close to the producing zone as possible. This might be by opening a SSD just above the packer (or punching a hole in the tubing, or pulling a dummy from a SPM) in a completion or by using a string of pipe that has been run to a suitable (deep) depth using Coiled Tubing or Snubbing. In this case, the method of killing the well is to circulate a kill weight fluid around the wellbore whilst maintaining a constant BHP sufficient to give a slight overbalance against the formation pressure. This is achieved by opening or closing a surface choke, and following a pre-calculated kill sheet which gives the required tubing surface pressure during the kill. The principles for working out the kill sheet are the same whether it is forward or reverse circulation. Various factors must be taken into account when preparing a kill graph.

48.0



Is the tubing the same ID/OD for the whole length?



Weight of fluid currently in tubing and annulus and weight of kill fluid?



Current shut in WHP and annulus pressure?



Contents of wellbore, oil or gas?

WK02.02 Well Kill Methods Pros & Cons

The different methods that are used to kill a well are as follows: 

Reverse circulation (annulus/tubing)



Forward circulation (tubing/annulus)



Bullheading (tubing/formation)



Lubricate and Bleed (Replace gas with fluid)

To kill a well using circulation, we can proceed in two ways: Normal circulation (“forward”) - Kill fluid circulates down the production tubing, through a circulation P a g e | 57

point over the packer and up the annulus. The circulation point can be a side pocket, sliding sleeve, or shoot holes in the production tubing to establish a circulation point. Reverse circulation - Kill fluid is circulated down through the annulus, through the circulation point over the packer and up the production tubing, this would be a planned operation.

The fluid that is used to kill the well is weighed up. This fluid must be heavy enough to give a small overbalance against the formation pressure. It is very important that the kill fluid does not damage the reservoir or reservoir fluid. If the kill fluid reacts with the reservoir rock or fluid, it can lead to plugging of the reservoir. Normally, the annulus is filled with packer fluid that is heavier than the hydrocarbons. It is therefore most practical to use reverse circulation. This means that the fluid that is in the annulus is displaced into the production tubing by the kill fluid. A production well with an open circulation point over the packer can be compared to a U-tube that is open at the bottom. When a well is to be killed with circulation, we can put a plug in the tail pipe, or the circulation can be completed without this plug. The purpose of the plug is, among other things, to prevent the kill fluid from coming into contact with the reservoir fluid. The principle for preparing a kill sheet is the same for both reverse and normal circulation. A kill sheet is a graph that shows how the wellhead pressure develops as the kill fluid is pumped in. A kill sheet is an important tool for securing that the bottom-hole pressure is always larger than the formation pressure.

49.0

WK02.03 Well Kill Method Appropriate Selection

The choice of well kill procedure will depend on a number of factors including tubing and casing integrity, ability to circulate the annulus, formation pressure and the method of well completion. Can we establish a circulating point, is the DHSV serviceable etc. etc.

50.0

WK03.01 Reverse Circulation

Directional down the annulus and up thru the tubing is generally the method used in a planned well kill. All wells can normally killed in this manner because there is less risk of formation damage, surface pressures remain lower and clean kill fluid fills both the annulus and tubing.

Advantages P a g e | 58



Hydrocarbons brought up through the Xmas Tree to the production facilities



Gas and oil will remain segregated throughout



Low circulation pressures on the annulus



Little or no damage to the formation by foreign fluids or contaminants from the tubing or annulus



Little risk of accidentally fracturing the formation

PS – Can only be done if there is a circulating point and there are no issues with the DHSV

Kill fluid is pumped down the tubing, through a circulating device (or out the end of a work string/coiled tubing) and up the annulus. If washing out fill or debris in the bottom of the well (rat hole), care must be taken to ensure that the work is done very slowly because:

Large quantities of solids in the annulus can add significant weight to the fluid in use, increasing the BHCP and can cause lost circulation. This assumes that the well has been killed and the packer has been pulled.



If there is a large quantity of solids in the annulus and the pump has to be shut down or fails, there is a chance of the solids settling out around tool-strings or BHA's causing them to become stuck. This assumes that the well has been killed and the packer has been pulled.

If the well is not plugged and circulation is taking place through a SSD or SPM, there is a risk of hydrocarbons entering the annulus. After running a completion, a light fluid (often diesel) is usually pumped down the annulus to provide a lighter column of fluid in the wellbore for under balanced perforating or for bringing the well in. This is followed down with the completion brine which, after careful calculation, is left in the annulus. The SSD or SPM is then closed, stopping the fluids in the well from U- tubing. When the sleeve is closed the annulus pressure can be bled off to check there is no communication. Forward circulation has several disadvantages over reverse circulation: 

It involves higher annulus circulation pressures



Disposal of formation fluids through the side outlet valves is difficult.



It is more difficult to pump the oil/gas ahead of the kill fluid.



The fluid in the wellbore may mix with fluid in the annulus making choke operation and disposal more difficult.



The empty pipe will have to be filled when running in the hole in order to stop it from collapsing.

As the pumps are run up to speed, the tubing pressure will rise as the well is killed with the kill fluid coming P a g e | 59

out of the bottom of the pipe and up the completion. The control of the operation is undertaken by adjusting the choke, which must be in the flow path from the completion or tree, so that the pumping pressure follows the predicted graph. Under normal circumstances, a forward circulation kill would probably only be undertaken with a Coiled Tubing or Snubbing string in the hole.

50.1

Reverse Circulation Kill Fluid Lighter than Annular Fluid

The following must be calculated and noted before the kill operation is started: 

Volume in the production tubing bbl/ft capacity



Volume in the annulus bbl/ft capacity



Total well volume.



The density of the kill fluid: Calculated from the reservoir pressure.



Wellhead pressure (read or calculated from the reservoir).



Calculate static annular pressure when communication is established between the annulus and production tubing.



Vertical well/well angle

Well Data: SSD depth Gas - Oil Contact depth Pressure @ SSD Well Head Pressure (WHP) Gas density Oil density Kill fluid density Brine density Production tubing capacity Annular capacity

10,000 7,000 5,400 3,500 0.100 0.400 0.540 0.620

ft MD/TVD ft MD/TVD psi psi psi/ft psi/ft psi/ft psi/ft

0.050 bbl/ft 0.070 bbl/ft

Calculations Volume in production tubing Volume in Annulus Full circulation volume P a g e | 60

= 0.050 bbl/ft x 10,000 ft 500 bbl = 0.070 bbl/ft x 10,000 ft = 700 bbl = 500 bbl + 700 bbl = 1,200 bbl

A) Initial condition before SSD opened Wellhead Pressure

= 3,500 psi

Pressure @ SSD tubing side

= = = =

HPgas + HPoil + WHP (0.1 x 7,000) + (0.4 x 3,000) +3,500 700 + 1,200 + 3,500 5,400 psi

Casing Head Pressure Pressure @ SSD annulus side

= = = =

0 psi HPBrine 0.62 x 10,000 ft 6,200 psi

Total volume pumped

= 0 bbl

The large differential pressure (800 psi) at the SSD causes a U-tube effect creating a void in the annulus. The pumps are started, SCRs at 30 & 40 spm are taken and the void is the annulus being filled.

B) WHP = 0 psi Wellhead Pressure

= 0 psi

Pressure @ SSD tubing side

= = = =

Volume of brine in tubing

= 0.050 bbl/ft x 6,730 ft = 336.5 bbl

Volume of brine in annulus

= 700 bbl – 336.5 bbl = 363.5 bbl

Casing Head Pressure Pressure @ SSD annulus side

= 0 psi = (0.62 x 5,193) + (0.54 x 4,037) = 5,400 psi

Total Volume pumped

= 282.6 bbls

P a g e | 61

HPgas + HPoil + HPBrine (0.1 x 270) + (0.4 x 3,000) + (0.62 x 6,730) 270 + 1,200 + 4,173 5,400 psi

C) Oil at Surface Wellhead Pressure

= 0 psi

Pressure @ SSD tubing side

= = = =

Volume of brine in tubing

= 0.050 bbl/ft x 7,938 ft = 396.9 bbl

Volume of brine in annulus

= 0.070 bbl/ft x 4330 = 303.1 bbl

Casing Head Pressure Pressure @ SSD annulus side

= = = =

Total volume pumped D) Brine at Surface

= 396.9 bbls

Wellhead Pressure

= 0 psi

Pressure @ SSD tubing side

= HPBrine = 0.62 x 10,000 = 6,200 psi

Volume of brine in tubing

= 500 bbl

Volume of brine in annulus

= 200 bbl

Casing Head Pressure Pressure @ SSD annulus side

= = = =

Total volume pumped

= 500 bbls

HPoil + HPBrine (0.4 x 2,062) + (0.62 x 7,938) 825 + 4,921 5,746 psi

0 psi HPBrine + HPKill Fluid (0.62 x 4,330) + (0.54 x 5,670) 5,746 psi

572 psi HPBrine + HPKill Fluid + CHP (0.62 x 2,857) + (0.54 x 7,143) + 572 6200 psi

E) Kill fluid at SSD Wellhead Pressure P a g e | 62

= 0 psi

Pressure @ SSD tubing side

= HPBrine = 0.62 x 10,000 = 6,200 psi

Volume of brine in tubing

= 500 bbl

Volume of kill fluid in annulus

= 700 bbl

Casing Head Pressure Pressure @ SSD annulus side

= = = =

Total volume pumped

= 700 bbls

800 psi HPKill Fluid + CHP (0.54 x 10,000) + 800 6200 psi

F) Kill Fluid at Surface Wellhead Pressure

= 0 psi

Pressure @ SSD tubing side

= HPKill Fluid = 0.54 x 10,000 = 5,400 psi

Volume of kill fluid in tubing

= 500 bbl

Volume of kill fluid in annulus

= 700 bbl

Casing Head Pressure Pressure @ SSD annulus side

= = = =

Total volume pumped

= 1,200 bbls

0 psi HPKill Fluid 0.54 x 10,000 5,400 psi

The annulus and tubing are full of clean kill fluid, the both surface pressure gauges read zero. The well is dead.

P a g e | 63

50.2

Reverse Circulation Kill Fluid heavier than Annular Fluid

Well Data: SSD depth Gas - Oil Contact depth Pressure @ SSD Well Head Pressure (WHP) Gas density Oil density Kill fluid density Brine density

10,000 4,000 5,100 2,320 0.140 0.370 0.540 0.510

Production tubing capacity Annular capacity

ft MD/TVD ft MD/TD psi psi psi/ft psi/ft psi/ft psi/ft

0.008 bbl/ft 0.030 bbl/ft

Calculations Volume in production tubing

= 0.008 bbl/ft x 10,000 ft 80 bbl = 0.030 bbl/ft x 10,000 ft = 300 bbl = 80 bbl + 300 bbl = 380 bbl

Volume in Annulus Full circulation volume

A) Initial condition before SSD opened Wellhead Pressure

= 2,320 psi

Pressure @ SSD tubing side P@SSDtbg

= = = =

HPgas + HPoil + WHP (0.14 x 4,000) + (0.37 x 6,000) +2,320 560 + 2,220 + 2,320 5,100 psi

Casing Head Pressure Pressure @ SSD annulus side P@SSDann

= = = =

0 psi HPBrine 0.51 x 10,000 ft 5,100 psi

Total volume pumped

= 0 bbl

Pressure across the SSD is balanced so no U-tubing when the SSD is opened. An overbalance of 200 psi is to be maintained at the SSD during circulation.

P a g e | 64

B) Gas out THP

= = = = =

P@SSD - HPoil - HPBrine 5,300 - HPoil - HPBrine 5,300 - (0.37 x 6,000) - (0.51 x 4,000) 5,300 - 2,220 - 2,040 1,040 psi

Volume of Gas

= 0.008 bbl/ft x 4,000 ft = 32 bbl

Height of Kill fluid in annulus

= 32 bbl ÷ 0.030 bbl/ft = 1067 ft

CHP

= P@SSDann - (0.54 x 1,067) - (0.51 x 8,933) = 5,300 psi – 576 – 4,556 = 168 psi

Total Volume pumped

= 32 bbls

C) Oil at Surface THP

= = = = =

Volume of oil & gas pumped

= 0.008 bbl/ft x 10,000 ft = 80 bbl

Height of Kill fluid in annulus

= 80 bbl ÷ 0.030 bbl/ft = 2667 ft

CHP

= P@SSDann - (0.54 x 2,667) - (0.51 x 7,333) = 5,300 psi - 1440 - 3,740 = 120 psi

Total Volume pumped

= 80 bbls

P a g e | 65

P@SSD - HPBrine 5,300 - HPBrine 5,300 - (0.51 x 10,000) 5,300 – 5,100 200 psi

D) CHP = 0 psi THP

= = = = =

P@SSD - HPBrine 5,300 - HPBrine 5,300 - (0.51 x 10,000) 5,300 – 5,100 200 psi

CHP

= P@SSDann - (0.54 x 6,667) - (0.51 x 3,333) = 5,300 psi - 3,600 – 1,700 = 0 psi

Volume of Kill fluid pumped

= 0.030 bbl/ft x 6,667 ft = 200 bbl

Total Volume pumped

= 200 bbls

E) Kill fluid at SSD THP

= = = = =

CHP

= P@SSDann - (0.54 x 10,000) = 5,300 psi – 5,400 = -100 psi

Pressure gauge will show 0 psi Total Volume pumped

P@SSD - HPBrine 5,300 - HPBrine 5,300 - (0.51 x 10,000) 5,300 – 5,100 200 psi

= 300 bbls

F) Kill Fluid at Surface THP

P a g e | 66

= = = =

P@SSD - HPkill fluid 5,300 - (0.54 x 10,000) 5,300 – 5,400 -100 psi

0 psi as pressure gauge does’t show negative pressure

CHP

= P@SSDann - (0.54 x 10000) = 5,300 psi – 5,400 = -100 psi

0 psi as pressure gauge does’t show negative pressure Total Volume pumped

= 380 bbls

The annulus and tubing are full of clean kill fluid, the both surface pressure gauges read zero. The well is dead.

51.0

WK04.01-12

See Workbook 52.0

WK05.01 Bullheading

Bullheading (or squeeze killing) involves pumping kill weight fluid down the tubing and forcing the wellbore fluids back into the formation through the perforations. This method is only possible if the well conditions are such that pumping back into the formation is possible. If the tubing or perforations are blocked then this method cannot be used. It is also used when the tubing has been landed in a packer and it is not possible to establish a circulation path around the tubing shoe (other than perforating) The pumping rate during bullheading must be high enough to stop any gas migrating back up through the kill fluid and to keep the fluid from free falling down the tubing and mixing with the wellbore fluids. Ideally a wall of fluid should be forced down the tubing, pushing everything in front of it. The pump pressure must not exceed formation fracture pressure. Fracturing the formation can cause severe losses that are very difficult to stop even with coarse LCM (lost circulation material). Pressure ratings of surface equipment must also be considered. Most producing wells have reduced formation pressures and a full column of kill fluid (seawater is the normal minimum) may give rise to excessive bottom hole pressures which may cause the fluids to be lost into the formation. In this case, solids such as sized salt particles or Calcium Carbonate etc. may be required to temporarily block off the perforations to enable them to support the full column of kill fluid. In low permeability wells where it is difficult to pump fluids into the formation, high surface pressure can result from low pump rates. Small ID tubing strings may also cause pressure problems because of high friction losses in the tubing. If the P a g e | 67

tubing is very large, pressure will probably not be a problem although it may be difficult to maintain the clear interface between the kill fluids and the wellbore fluids. This can cause the kill to take much longer with much more fluid lost to the formation. The main disadvantage of bull-heading is that everything that is in the wellbore, including scale, debris, sand, etc. is likely to be forced back into the formation. There is even the risk of plugging the perforations before the kill is achieved. Surface and downhole pressures will be the highest with bull-heading. If filtered kill fluids are to be pumped into a high permeability reservoir, then the bullhead kill may be the preferred option. A typical graph of the pumping pressure is illustrated, again assuming that the completion geometry does not alter, the well is not approaching horizontal, there is no gas migration and the wellbore fluids can be easily pumped back into the formation.

Bullhead Graph Example

Advantages

P a g e | 68



Tubing contents pumped into the formation.



Quick operation if time or speed is important, especially if there is a lack of well files or information regarding the well configuration to calculate a reverse kill.



Would depend on formation permeability and rated equipment pressure to carry outthe operation.

Disadvantages 

Scale or contaminants in the tubing are pumped against the formation – Pore or perforation plugging with scale or debris from the well is a common cause of near well bore damage



Low formation fracture pressures may be exceeded causing accidental fractures



Gas may slip up the tubing if the pump rate is not sufficient for larger tubing size

The following factors must be taken into consideration: Injection Pressure: The pressure necessary to push the formation fluid back into the formation.

Decided by an injection test. Remember to record the relationship between pump rate and injection pressure. Density, formation fluid: Decides the static surface pressure, refer to formation pressure and pressure developed. Density, kill fluid: Decides the pressure development during the process and change in the frictional pressure loss. Pump rate: Decides the frictional pressure loss and as well as the change in frictional pressure. Formation fluid: Deciding factor for the choice of pump rate. If it is a gas, the pump rate must be as high as possible at least greater than the migration speed of the gas in fluid. Use migration speed 1000 - 4000 ft/hour. Formation Strength: When choosing a pump rate we must avoid using an injection pressure that exceeds the formation strength in order to avoid fracturing. The strength of the cement behind the casing must also be considered.

P a g e | 69

2730 psi

0 psi

5246 psi 3192 psi

5366 psi 4670 psi

The pump pressure is increased until the kill fluid is pushed into the tubing and the well fluid is displaced back into the reservoir. Surface pressure will gradually sink as the hydrostatic pressure of the fluid column rises.

965 psi

0 psi

5246 psi

3192 psi

5366 psi 4670 psi

A production tubing volume is pumped and the well is killed. 965 psi is the pressure that we must have to overcome the reservoir friction and frictionally pressure loss in the tubing and surface equipment.

P a g e | 70

0 psi

0 psi

4695 psi

3192 psi

4815 psi 4670 psi

The pump stops and the surface pressure will go to 0 psi; the bottom hole pressure is at 4815 psi and has a kill margin of 174 psi. The well is killed.

Changes in friction can be difficult to evaluate directly, especially on gas wells, because a fluid gives completely different frictional pressures. Frictional pressure loss with well fluid can be measured and related to the production rate. Frictional pressure loss is measured as the pressure difference between reservoir pressure, measured downhole pressure, and surface pressure in production. Calculate the frictional pressure loss with kill fluid.

When you are going to begin volume calculations, you sum up the capacity multiplied by the length of each section. The pressure course during the process relates to the number of pump strokes or the pumped volume. In the process, the following happens:

P a g e | 71



Surface pressure is gradually reduced as the hydrostatic pressure from the kill fluid increases.



Friction in the system changes as the kill fluid replaces the well fluid. Normally, the friction increases.



Injection pressure stays the same as long as the pump rate is held constant, until thekill fluid meets the formation. Then the pressure will usually increase.



The course of the pressure is described by doing calculations for 5 - 10 points in the process and plotting the results in a pressure/volume or pressure/pump stroke diagram.



If we wait until the kill fluid meets the reservoir, we will see a strong increase the pressure on the pump.

When this happens, it is normal to stop pumping and end the operation. 53.0

WK06.04 Lubricate and Bleed

We use this method if it is not possible to use any of the other methods we have discussed. A condition for using this method is that we are dealing with a gas well, or that there is a lot of gas in the pipe that is to be killed. Examples of situations where we use this method include when we have a well control problem, such as a stuck wireline cable in the well, and where we cannot bullhead before the shut-in pressure of the well is reduced.

When we pump into the well, gas is compressed. Therefore, we see an increase in pressure at the top. In addition, the hydrostatic pressure in the well increases. These two conditions lead to a pressure increase in the well that must not exceed that which the well tolerates (refer to injection or fracturing). The amount that can be pumped in is therefore limited, so that the process must be repeated until all the gas is bled out and replaced with fluid. If we know the height of the gas and the formation pressure, we can calculate the necessary density to kill the well.

54.0

WK06.05 Lubricate and Bleed Procedure Lubricate and bleed (sometimes called a lubricated kill) is performed by:

P a g e | 72



Calculating the capacity of the tubing and pumping half that volume of kill fluid into the well.



Observing the well for 30-60 mins. The tubing head pressure will drop due to thehydrostatic head of the initial kill mud pumped. When the wellhead pressure is constant the next step is taken.



Pump around 10 barrels of kill fluid and ensure that the wellhead pressure does not exceed 200 psi above the observed tubing head pressure.



Bleed off gas from the tubing at a high rate immediately after pumping the batch ofkill fluid. The tubing head pressure should drop an amount equal to the hydrostatic head of the mud pumped. If the gas pressure is not bled off quickly enough, the additional pressure caused by the increased hydrostatic, may cause losses.



The gas migrates to surface through a non-viscous fluid in a straight well at up to perhaps 2000 ft/hr, time must be allowed for the fluid to fall through the gas before bleeding off. This is to avoid bleeding off the kill fluid that has already been pumped. Lubricate and bleed method can take a long time to perform.

54.1



With 27/8" tubing in the well and 9 ppg kill fluid (brine), a typical pressure reduction might be in the order of 80-85 psi/barrel pumped. In a 6500 ft. well, it might take 40 bbls to fill the tubing. The graph shows typical pumping pressure during a kill operation.



When the well is dead, it will contain a full column of fluid. Assuming that it is stationary and overbalanced, this fluid is the primary barrier.

Combining The Methods

Once in a while it can be advantageous or necessary to combine the methods we have just described. Examples of this can be when we bullhead tubing into a reservoir before opening the sliding sleeve and circulating, or when we lubricate and bleed the tubing before we continue bullheading.

54.2

Workover/Well Kill Fluids

Fluids used in completing or well services operations have many applications e.g. During perforating, cementing, fracturing, acidising, well killing, re-completing, milling, drilling, clean outs and fluid loss prevention. They may also have long term functions as packer or completion fluids. They must provide an overbalance and be clear dens brines.

P a g e | 73



Generally, the most economic fluid, which meets all of the criteria, is used and it should be solid free and non-damaging.



Clear brines are used as they are cheap, readily obtainable, easily transportable and easily filtered in normal weight ranges.



The disadvantage is that they have no bridging capability and are easily lost into the formation (unless the well is plugged). In this case, a LCM pill is usually placed against the formation to prevent or reduce the losses.



Clear brines are weighted by salts to achieve the desired densities.



Brines are available in weight ranges from 8.3 to 21.0lbs/gal.



The heavier brines can be very corrosive to metals and hazardous to personnel, hence require special handling. Personnel must use appropriate safety work-wear and be aware of the hazards.

54.3

Chemical Make up of Brines

Potassium Chloride

KCL

8.3 – 9.7 lbs/gal

Sodium Chloride

NaCL

8.3 – 10.0 lbs/gal

Calcium Chloride

CaCl

8.3 – 11.8 lbs/gal

Calcium Chloride/Calcium Bromide

CaCl/CaBr2

11.8 – 15.2 lbs/gal

Calcium Chloride/Calcium Bromide/Zinc Bromide

CaCL/CaBr2/ZnBr2

14.5 – 19.2 lbs/gal

Zn Br2

13.5 – 21 lbs/gal

Zinc Bromide 54.4

Filtration and Cleanliness

Brines are usually filtered to a predetermined level of cleanliness, selected to meet the demands, by a filtration unit or a centrifuge. The two main types of filtration units used are: 

De Filtration Press



Cartridge Units.

The former uses Diatomaceous Earth formed as a cake on the faces of plates pressed together through which the fluid is pumped.

NOTE - They are a function of temperature, therefore the higher temperature the lower the pressure density Typical kill fluids might include: 

Sea Water



Completion fluid



Drilling mud (oil or water based).



Fresh Water

It is very important that the kill fluid is compatible with the formation and the formation fluids. Incompatible fluids can cause swelling of clays and chalks, scale deposition and other problems that can permanently block the perforations or greatly reduce productivity.

55.0

WK06.06 Lubricate & Bleed Summary

This method is very rarely used and involves pumping a controlled amount of kill fluid to exceed the SITHP. Given sufficient time for the kill fluid to gravitate into the tubing bore before bleeding off pressure to below the original SITHP. P a g e | 74

This operation may be restricted by tubular burst pressures, formation permeability, frac pressure and the rating of the surface equipment being used.

56.0

WN05.01 Hydrates

Hydrates are a product that arises when gas molecules bind to water molecules. The chemical reaction happens quickly when it first begins. The product can be compared to ice and snow, but is not frozen water. The creation of hydrates can only occur if there is free water available for the gas to react with. By free water we mean that the molecules are not bound to other matter, for example glycol or methanol. The chemical reaction can only occur within a certain area of pressure and temperature for each type of gas. The lower the temperature and the higher the pressure, the greater the risk for hydrate formation. The gas’ molecular weight also has meaning here. A lighter gas will react more easily with water than a heavier gas. Pressure and temperature can seldom be regulated in a live well, so we must primarily concentrate on the free water to prevent the formation of hydrates. One must avoid supplying free water in connection to leakage testing and pressure balancing. Therefore we commonly use a 50/50 mixture of water and glycol. If there is a lot of water in the well to begin with, one can use pure glycol so that the water binds when the glycol is released into the well In other situations it may occur that large amounts of fluid are pumped into the well to prevent hydrates. The fluid can be brine or diesel.

If hydrates arise in the well, the flow line or the riser, we will attempt to remove them in the most effective way. The methods that are used can be different depending on where the hydrates are localized. It is therefore important to first try to find out where the problem is; afterwards you can decide which method to use to remove the hydrates.

57.0

WN05.02 Hydrate Prevention Removal

If the hydrates are down in the well, they will often be removed on their own by increasing temperature, especially if the well has been cooled down by diverse pumping operations. Some will also bleed down pressure over the hydrates, but this is very risky as the hydrate plug can loosen and shoot up the well. A safer alternative is, if possible, to pump methanol. At some places we also pump warm fluid in the annulus that raises the temperature a little. A flow line on the seabed will be extra vulnerable to hydrates and it is here we often circulate methanol in order to prevent the formation of hydrates, as well as to remove any existing hydrates. If there are problems with hydrate formation on surface intervention equipment, it can sometimes be seen on the outside of the equipment as frost. We can attempt to warm up this area with warm water or steam. If we have the possibility to heat, you can go ahead even if we haven’t registered a specific area with outer P a g e | 75

frost. If it is possible to pump in methanol or glycol, it is done. Methanol will loosen up the hydrates. Glycol will not unless it is warm, but it will prevent a worsening of the situation and prevent the formation of new hydrates if the hydrates are loosened up by heat. External Hydrate Indicators: 

Vents blocking during venting down



Wireline gear sticking downhole for no apparent reason



A tree valve sticking or being completely blocked



Icing up on the outside of a valve or pipe work



Stuffing boxes Icing up

Internal Hydrate Indicators: 

Prevents vital equipment from functioning properly



Unable to flow the well



Unable run or pull wire line tools



Unable to circulate a well dead

Minimise the Risk

Prior to pressure testing pure glycol or glycol mix the density of the fluid should be measured for water content as follows Acceptable specific gravity range: 

MEG: Mono Ethylene Glycol (9.3 ppg)



TEG: Tri Mono Ethylene Glycol (9.4 ppg)

Hydrate Prevention:

P a g e | 76



Chemical Injection Lines



Flow the well (if possible)to keep pipe work and subsurface components “warm”



Glycol (anti-freeze) can be added to pressure testing water to inhibit hydrate formation

58.0

WN10.01/02/03 Blockages

In all well intervention, there is a risk that we cannot get into the well because of blockages. Examples of this include: 

A collapsed production tubing or casing



Fish in the hole



Sediment deposits (“scale”)



Build-up of sand

There are differences in how this is registered in wireline, pressure pipe and coiled tubing operations. In wireline operations that relate to gravity and the weight of the work string, the loss of weight on a place where there, according to the well sketch, should be free passage, indicates that we have met a blockage. Pressure pipe will be the same as in wireline operations if you operate in “pipe heavy” mode, in other words that the pipe is heavier than buoyancy and friction. But if you are in “pipe light” mode, where the pipe must be pushed against the well pressure, the blockage will be registered as an increase in compressive force or negative weight. Coiled tubing will be similar to pressure pipe operations, but here it is also common that we pump at the same time as the pipe is run into the well. It can therefore sometimes be an increase in pump pressure that first warns the operator that the equipment has run into blockage. All the situations described above occur while running into a well, but it is possible that problems arise when pulling out equipment. This will then register as an increase in weight in all cases except where coiled tubing and pressure pipe are in “pipe light” mode, in which case it will be registered as a reduction in negative weight. While running in there might be an edge or shoulder in the completion that stops the equipment. It will often be necessary to pull out of hole in order to change the tool string. If this doesn’t work it will be natural to attempt to pass the obstruction with a smaller tool and possibly use a Lead Impression Block to make an impression of the blockage. In coiled tubing and pressure pipe we can attempt to push through with force, but we risk getting stuck. Another possibility is to try to wash out the blockage by circulating fluid through the string and taking the returns at the surface. In a pressure pipe we also have the possibility to rotate the string at the same time as we move it up and down. This can be the solution if the string is hanging on an edge. The consequences of blockage in the well will often be that the planned operation will not be able to be completed before the blockage is removed, allowing the equipment to be run to the planned depth. Based on the actual well depth, history and experience, an evaluation will be made to identify which type of blockage we are most likely facing. Afterwards, a plan will be made to solve the problem. PS Do not run tractors where a well has a history of sand. P a g e | 77

Part 2 Completion Equipment

P a g e | 78

59.0

Completion Design .......................................................................................................... 80

60.0

WEQA05.01 Flange Connections ...................................................................................... 84

61.0

WEQG01.01 Xmas Trees .................................................................................................. 86

62.0

WEQG01.02 Tubing Hangers ............................................................................................ 88

63.0

WEQG01.03 Sub Surface Safety Valves ............................................................................ 89

64.0

WEQG01.04 Landing Nipples ........................................................................................... 97

65.0

WEQG01.05 Packer/Tubing Connection ........................................................................... 98

66.0

WEQG01.06 Retrievable Packer Accessories .................................................................... 98

67.0

WEQG01.07 Side Pocket Mandrels................................................................................. 100

68.0

WEQG01.08 Sliding Side Door ........................................................................................ 102

69.0

WEQG01.09 Sliding Side Door ........................................................................................ 102

70.0

WEQG01.10 Packers ...................................................................................................... 103

71.0

WEQG01.11 Packer Setting Procedures .......................................................................... 104

72.0

WEQG01.12 Wireline Entry Guide (WEG) ....................................................................... 105

73.0

Tubing ........................................................................................................................... 106

74.0

WEQG03.01 How to Check Equipment ........................................................................... 110

75.0

WEQG03.03 Non-Shearables Across BOP ....................................................................... 110

76.0

WEQJ01.01 Monitoring Annuli Pressures ....................................................................... 110

77.0

WEQJ01.02 Abnormal Annulus Pressures ....................................................................... 111

P a g e | 79

59.0

Completion Design

Completion, in petroleum production, is the process of making a well ready for production (or injection). This principally involves preparing the bottom of the hole to the required specifications, running in the production tubing and its associated down hole tools as well as perforating and stimulating as required. Sometimes, the process of running in and cementing the casing is also included. The well design process begins with an understanding of the environment in which the well will be drilled. Interpretations of local geologic structure, geo-pressure and formation strengths are developed. These interpretations may be derived either from local drilling experience or from seismic data. It should be noted that uncertainties will exist in the interpretation of the data and ultimately in the description of the geologic environment. The quality of geologic predictions ( e.g., pore pressure, fracture gradient, bottom hole temperature and pressure, formation fluids, H2S, CO2, chloride concentration, etc. ) often relies on the amount of control within a given area. As such, these predictions are usually expected to be more reliable for development wells than for exploration wells. However, for drilling operations in established deep water fields, the pore pressure and fracture gradient often demonstrate variability due to production. With a description of the geologic environment in place, constraints are then introduced by the designer to address specific well requirements. These include the directional drilling objectives and the required well depth. Production or evaluation requirements dictate the hole size desired at total depth. Depending on the geographical location, some wells will require an additional surface casing string for the isolation of shallow water or gas flows. It is common for deepwater Gulf of Mexico wells to penetrate long sections of salt. In some locations, the salt will provide a higher fracture strength, which may reduce the number of casing strings required to reach the ultimate well objective. The presence of salt in other locations may present drilling challenges such as shear/rubble zones, inclusions, or abnormal pressures within.

59.1

Lower Completion

This refers to the portion of the well across the production or injection zone. The well designer has many tools and options available to design the lower completion according to the conditions of the reservoir. Typically, the lower completion is set across the productive zone using a liner hanger system, which anchors the lower completion to the production casing string. The broad categories of lower completion are listed below.

59.2

Barefoot Completion

This type is the most basic, but can be a good choice for hard rock, multi-laterals and underbalance drilling. It involves leaving the productive reservoir section without any tubulars. This effectively removes control of flow of fluids from the formation; it is not suitable for weaker formations, which might require sand control, or for formations requiring selective isolation of oil, gas and water intervals. However, advances in interventions such as coiled tubing and tractors means that barefoot wells can be successfully produced.

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59.3

Open Hole

The production casing is set above the zone of interest before drilling the zone. The zone is open to the well bore. In this case little expense is generated with perforations log interpretation is not critical. The well can be deepened easily and it is easily converted to screen and liner. However, excessive gas and water production is difficult to control, and may require frequent clean outs. Also the interval can be selectively stimulated.

59.4

Cased Hole Completion

This involves running casing or a liner down through the production zone, and cementing it in place. Connection between the well bore and the formation is made by perforating. Because perforation intervals can be precisely positioned, this type of completion affords good control of fluid flow, although it relies on the quality of the cement to prevent fluid flow behind the liner. As such it is the most common form of completion...

59.5

59.6

Types of Flow 

Pumping flow - the tubing and pump are run to a depth beneath the working fluid. The pump and rod string are installed concentrically within the tubing. A tubing anchor prevents tubing movement while pumping.



Tubing flow - A tubing string and a production packer are installed. The packer means that all the flow goes through the tubing. Within the tubing you can mount a combination of tools that will help to control fluid flow through the tubing.



Gas Lift Well - Gas is fed into valves installed in mandrels in the tubing strip. The hydrostatic head is lowered and the fluid is gas lifted to the surface.

Design

No matter what the design of the completion is, whether complicated or simple, the nature of a completion is either production or Injection. Most Production wells have some sort of artificial lift installed in their well life.

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

Rod pump



Gas Lift



Jet Pump (Venturi effect), Electric / Hydraulic Submersible Pump (ESP)



Screw pump

59.7



Plunger lift



Water Injection wells are crucial for the life and development of an oil field.



Water Injection

Completions

In the early 1900s, oil and gas wells were commonly completed with only a string of cemented casing. As deeper, multiple and higher pressure reservoirs were encountered, it was recognised that such completions imposed limitations on well servicing and well control and that downhole designs would need to be changed to meet increasing needs for zonal isolation, selectivity, re-entry and control. This objective was achieved through the development of downhole equipment. Today, conventional oil and gas wells are completed with a variety of downhole devices designed to meet the functional and production requirements of the well. In simple terms "completion" refers to the method chosen to finalize a newly drilled well and will include: 

A method of providing communication between the reservoir and the wellbore



Tubing and casing design



A method of lifting well fluids to surface

The installation of various components to allow efficient production, pressure testing, emergency containment of reservoir fluids, reservoir monitoring and placement of barriers, well maintenance and well kill procedures. 59.8

Functional Requirements of a Completion

Completion design involves the selection of components to perform specific functions dependent on the philosophy of the operating company and, in some cases; the choice of component is based on historic reasons and preference. Some basic functional requirements may include:

P a g e | 82



The provision of optimum flowing conditions



Protecting the casing from corrosive fluids.



Chemical injection.



Well Killing requirements



Routine Intervention Operations



Tubing movement



Internal erosion



Installation of barriers

59.9

Well Construction Principles



Generally, a well will consist of conductor, casing, tubing, wellhead and Christmas tree.



The conductor protects the casing from seabed to platform surface, and provides a stable support for the wellhead and Christmas tree.



Three or four strings of casing will be run inside the conductor, with diminishing I.D’s



Typically 30” conductor.



20” Surface casing



13 3/8” Intermediate casing



9 5/8” Production casing



7” Liner.

59.10 Completion Equipment Most wells include at least one string of tubing in the completion. Other items such as flow couplings, circulation devices, blast joints and packers are run as an integral part of the completion string or tailpipe.

59.11 Completion Equipment Sub-Assemblies Why needed: 

Pre-assembled modules ensure pressure integrity of equipment in workshop



Pre-assembled modules function tested in workshop



Addition of pup joints allows for easier shipping / handling to the well site



Modules can be made up and saved ready for the completion operations



More cost effective and safer than performing the operation at the well site

What checks are required?

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

Pressure/Temperature ratings



Tubular Details Pressure ratings/service



Internal/External & Drift dimensions



Pressure test charts:

60.0



Pressure high & Low pressures applied



Times each test was carried out



Test medium used



Sign off signatures



Physical dimensions of all sub-assemblies

WEQA05.01 Flange Connections

Flanges are API connections and can be one of two types: 

Type 6B for 2000, 3000 and 5000 psi. flanges



Type 6BX for 10000, 15000 and 20000 psi. flanges

There are one or two exceptions to this rule. Low-pressure flanges (2000 & 3000 psi.) have rounded ring grooves as opposed to flat-bottomed ring grooves. Type 6B flanges use either and R or RX ring gasket. The gaskets are interchangeable, the only difference being that the RX gasket is pressure energised. The flanges do not make face-to-face contact when made up. Type 6BX flanges use BX ring gaskets.

Note: The given size of the flange is the internal diameter of the flange. All new pressure containing equipment (risers, BOP's, etc.) is tested to manufacturers test pressure (usually 1.5 times its working pressure) before being put into to service for the first time. In any equipment rig up, the maximum pressure rating is governed by the lowest rated component. "6B' and '6BX' flanges may be used as integral, blind or weld neck flanges. Type '6B' may also be used as threaded flanges. Some type '6BX' blind flanges are also used as test flanges. Segmented flanges are used on dual, triple, and quadruple completion wells and are integral with the equipment.

Design Type '6B', '6BX', and segmented flanges are designed for use in the combinations of nominal size ranges and rated working pressure as shown in the table.

Type '6B' Flanges General API Type '6B' flanges are of the ring joint type and are not designed for make-up face-to-face. The connection make-up bolting force reacts on the metallic ring gasket. The Type '6B' flanges shall be of the through-bolted or studded design. Ring gaskets have a limited amount of positive interference that assures the gasket will be joined into sealing relationship in the flange grooves; these gaskets should not be reused. Ring-joint gaskets should meet the requirements of API Specification 16A and be of the material and hardness specified in API Specification 6A. API RP 53 chapter 20.2.4 7.11.5.8 P a g e | 84

All bolts and nuts used in connection with flanges, clamps, and hubs should be selected in accordance with provisions of API Specification 6A.

Flange Connections Type 6BX are of a ring joint type. These flange connections are designed for face to face make up. The dimensions shall conform to API 6A specifications Section 900.

Flange Connections Type 6B are of a ring joint type. These flange connections are not designed for face to face bolting source re-acts on the metallic ring gasket. The type 6B flange may be of the bolt through or studded design. The type 6B uses type R or RX gaskets. The dimensions shall conform to API 6A, specifications Section 900.

60.1

Flanges and Hub Incorrect Make Up Factors

Human Factors - Remains the number one cause of flange leakage, and with accredited training the candidate will become aware of all the key issues to consider prior to assembly and tightening of a bolted connection.

Uneven Bolt Stress - An incorrect tightening/assembly procedure or difficult access to fasteners can leave some bolts loose while others are over tightened and can crush the gasket. This can cause inservice leaks, especially in high temperature services when the heavily loaded bolts relax.

Dirty or Damaged Flange Faces - Dirt, scale, scratches, protrusions, weld spatter on gasket seating surfaces, and warped seating surfaces provide leakage paths or can cause uneven gasket compression that can result in flange leakage. P a g e | 85

Excessive Piping System Loads at Flange Locations - Excessive forces and bending moments can loosen the bolting or distort the flanges and lead to leaks. Common causes are inadequate piping flexibility, using cold spring to align flanges, and improper location of supports or restraints.

Incorrect Gasket Specification and Size - this can result in blow out and flange leakage during start up or commissioning.

Improper Flange Facing - Deeper serrations than specified will prevent the seating of double jacketed or spiral wound gaskets and provide a leakage path.

High Vibration Levels - Excessive vibration can loosen flange bolts and ultimately cause flange leakage.

Non-validated torque or tension values – challenge the source of all information supplied.

61.0

WEQG01.01 Xmas Trees

We can install the Xmas tree when the hanger system, casings and tubing are in place. We use it when we open and close the well for flow or well interventions. It is extremely important that this is done according to current procedures. The Xmas tree is composed of several valves installed together in a system that secures the well. The Xmas tree is composed of many different valves with different functions and uses. The main valves are:

P a g e | 86



Lower master valve is a manually operated gate valve. It is normally open, and should not be used to regulate the well stream etc. The valve can be shut in conjunction to maintenance of valves found higher up and in emergency situations.



Upper master valve is a hydraulically operated gate valve that is normally controlled from a control panel. The valve is also a part of the automatic security system and can be activated by an individual closing signal.



Swab valve is used in conjunction with well intervention and is manually operated.



Production wing valve (flow wing valve) is found as both a manually or hydraulically operated valve. In the North Sea the hydraulically operated valve is used, and these are then associated with the same security system as the upper master valve.



Kill wing valve is normally manual and is used to pump in or circulate out fluid in the well.

On Xmas trees located in the North Sea we normally find two automatic “fail safe close” valves. These can be pneumatically, electromagnetically or hydraulically operated, or a combination of these. We know them best as the hydraulic wing valve and the hydraulic master valve. The hydraulic wing valve is primarily used in conjunction to process-related considerations. The hydraulic master valve closes at different alarm levels and with loss of hydraulic control pressure.

61.1

Closing the Tree

Normal procedures when opening and closing the Xmas tree is as follows: 

Test rigged up equipment according to procedures or a minimum of CITHP



Ensure that the lower master valve is open.



Open the swab valve with the expected number of turns.



After counting the turns, report if there is a difference.



After this, the upper master valve is opened. This one is usually a “normally closed” or “fail safe close” type of valve and must therefore be kept open with the help of hydraulic pressure. The well pressure can now be read on the gauge in the Xmas.



Tree’s intersection and pressure in the lubricator can be set equal to the well pressure.



The swab valve, which is manual, can now be cranked up. The turns are counted and reported so that it can be compared to the next time the valve is to be closed.



The Xmas tree is now opened up and all is ready for running in well intervention equipment into the well to complete the planned operation, or parts of it.

When the equipment is pulled out of the well after a completed or unsuccessful mission, the Xmas tree is closed again. This takes place in the reverse order of that described. Run the equipment out of the hole and up the lubricator according to the current running procedure. Close the swab valve carefully while counting the number of turns. If too few turns are registered, it most often means that there is an obstruction in the valve. If the valve can be almost completely closed, but is missing about 3 to 5 turns, it could be an obstruction in the valve. Do not try to force the valve again, as you might cut the wire. Open the valve and try to pull it farther out of the hole before attempting to close the valve again.

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When the swab valve is closed with the correct number of turns, it can be tested, but this is not customarily done in all places. The upper master valve can now be closed. Check that it closes completely with the help of the indicator rod. When the master valve is closed, it is tested. The most common way of doing this is by opening with a few turns on the Swab Valve and thereafter bleeding off pressure on the Lubricator manifold. . When the master valve is tested, the swab valve is closed again. At this point, we can define ourselves as out of hole; the lubricator can be detached and replaced if necessary. If there shall be rigging up or down from the well NORSOK requires a subsurface safety valve. The X-mas tree has ports in the intersection for pressure discharging. Depending on the well fluid, we can calculate the actual pressure at the subsurface safety valve’s depth. The pressures balances before pulling the wireline subsurface safety valve. At high well pressures there may sometimes be problems with opening the valve and keeping it open, so that the

62.0

WEQG01.02 Tubing Hangers

Tubing hangers bear and lock the upper most part of the production tubing. It seals between the outside of the production tubing and the inside of the casing, and it also usually provides the ability to install a plug or check valve on the inside. The tubing hanger is a primary barrier. During installation, the tubing hanger’s inner part is landed in the tubing hanger’s outer part and is sealed with elastic packers or metal-to-metal seals. When the production tubing is landed, there is usually a significant weight on the hanger, as it is carrying the upper part of the production tubing. When the weight is hung off, the handling pipe can be screwed out and if it is necessary, it is possible to insert a check valve after which the blowout preventer is removed and the Xmas tree is installed. When the well is in production, large forces may expand upwards and the weight of the tubing is not enough to keep the tubing in place. Therefore, all tubing hangers also have anchoring bolts all the way around that are screwed in after the tubing is landed in the hanger.

Tubing hangers that do not allow the application to insert plugs or check valves into the tubing hanger’s internal profile, but in our part of the world we usually do have this possibility. We distinguish between three types of main plugs that can be inserted into the tubing hanger: The old-fashioned type with coarse, exterior left handed threads that is inserted or pulled out with a rod. A type with a locking mechanism that is pulled and inserted with a rod. The latter type is a landing nipple for plugs.

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PS - The tubing hanger is a completion component which is landed and locked inside the tubing head spool and provides the following functions:

63.0



Suspends the upper part of the completion



Provides a seal between the tubing and the annulus



Installation point for barrier protection (BPV)

WEQG01.03 Sub Surface Safety Valves

The modern sub-surface safety valve was developed from the earliest low technology versions produced in the 1930's. The initial demand was for a downhole valve that would permit flow during normal conditions, but would isolate formation pressure from the wellhead to prevent damage or destruction. This valve would be installed downhole in the production string for use in an emergency. The first safety valve to be developed was a Sub- Surface Controlled Safety Valve (SSCSV) and was a poppet type valve with a mushroom shaped valve/seat system. Compared with today's valves, this simple poppet type valve had several disadvantages; restricted flow area, tortuous flow paths, low differential pressure rating and calibration difficulties. Despite these limitations the valve operated successfully and other versions were developed with less tortuous flow paths such as the ball and flapper valve. From this beginning, the Surface Controlled Sub-Surface Safety Valve (SCSSV) was developed in the late 1950's. This moved the point of control from downhole to surface. This design provided large flow areas, remote control of opening and closing, and responsiveness to a wide variety of abnormal surface conditions (fire, line rupture, etc.). Initial demand for this valve was slow due to its higher cost and the problems associated with successfully installing the hydraulic control line; hence its usage was low until the late 1960's. The SCSSV is controlled by control line pressure supplied from a surface control system, which is ideally suited to manual or automatic operation; the latter pioneered the sophisticated emergency shut-down systems used today. The versatility of the valve allows it to be used in specialised applications as well as in conventional systems. SCSSVs are available with ball or flapper type closure mechanisms although modern designs utilize the flapper type. In addition to the type of closure mechanism, SCSSVs can be further subdivided into four main categories: 

Wireline or tubing retrievable



Non-equalizing or self-equalizing



Concentric or rod piston



Single control line or dual balanced line

A valve may have any combination of these features depending on well conditions and the completion design. P a g e | 89

WRSV Applications

TRSV Applications

General application: where intervention by platforms is unavailable

General application: where larger flow area is expected

High pressure gas wells

High volume oil and gas wells

Extreme hostile environments where well fluids or temperature tend to shorten the life of component materials

Subsea completions

High velocity wells with abrasive production Multiple zone completions where several flow

63.1

Types of Sub Surface Safety Valves

Fail-safe Sub-Surface Safety Valves are designed to hold pressure from below and can be pumped through from above when they are closed. They are installed for use in an emergency to protect personnel, property and the environment in the event of an uncontrolled well flow ( blow-out) caused by collision, equipment failure, human error, fire, leakage or sabotage. Whether safety valves are required in a particular operating area depends on the location of the wells, on company operating policy and/or government legislation. Safety valves are set below any depth where damage could occur to the valve from surface impact, explosion or cratering.

63.2

Surface Controlled Sub Surface Safety Valve Setting Depth

Operators may have different criteria concerning setting depth including: 

Set below platform piles or the probable crater depth in the event of a blowout



Positioned below hydrate formation depth (for self- equalizing)



Below the mud line

As determined by local regulations.

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63.2.1 SCSSSV Wireline Retrievable Surface Controlled Sub Surface Safety Valves are installed in regular wireline type safety valve landing nipples using a lock mandrel. 63.3

Pressure Differential Safety Valves

This type of direct-controlled safety valve is a 'normally open' valve that utilises a pressure- differential to provide the method of valve closure. Normally a spring holds a valve off-seat until the well flow reaches a predetermined rate. This rate can be related to the pressure differential generated across an orifice or flow bean. When this differential is reached or exceeded, a piston moves upwards against a pre-set spring force closing the valve. Valves of this type are sometimes termed 'storm chokes'. There are two closing mechanisms available with these valves, i.e.: 

Ball



Flapper

The valve is held open by a spring force that may be increased by adding spacers or changing the spring. The relationship between flow rate and differential may be adjusted by changing the bean size. The valve when closed will remain in this position until pressure is applied at surface to equalise across it when the spring will return to the open position.

NOTE – Pulling the valves should not be attempted unless pressures have been equalized and the valve is open. 63.4

Ambient Safety Valves

This type of direct-controlled safety valve is a fail-safe closed valve, which is pre-charged with a calibrated dome (chamber) pressure prior to running. Ambient controlled valves will open when the well pressure reaches the set point of the dome calibration. The valve will close when the flowing pressure of the well, at the point of installation, drops below the predetermined dome pressure. Ambient type safety valves are also generally referred to as a 'storm chokes'. This type of valve is not limited by a flow bean which gives it a large internal diameter and, hence, a large flow area making it suitable for high volume installations possibly producing abrasive fluids. Ambient type safety valves are run with an equalising assembly to allow equalisation across the valve should it close, and a lock mandrel to locate and lock the valve in the landing nipple.

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Note: Pressure differential and ambient controlled sub-surface safety valves close on predetermined conditions. They do not offer control until these conditions exist. In addition, valve settings may change if flow beans become cut. Surface controlled safety valves should be considered in such cases.

63.5

Injection Valve

Injection valves are normally closed valves installed in injection wells. They act like check valves allowing the passage of the injected fluid or gas but close when injection is ceased. The closure mechanism is usually, either, a ball or flapper that opens when the differential pressure from the injected medium equalises below the valve. As the injection rate is increased to the precalculated rate, the differential acts on a choke bean and overcomes a spring to move the mechanism to the fully open mode. If the injection rate is insufficient or fluctuating, the mechanism will be damaged and may possibly flow cut. The flapper-type valve is the most popular as its operation is less complicated and is less prone to damage if the injection rate is not high enough.

Note: An equalizing sub should be installed between the lock mandrel and the regulator to facilitate the equalization of pressure. 63.6

Surface Controlled Sub-Surface Safety Valve

The SCSSV is a downhole safety device that can shut in a well in an emergency or provide a barrier between the reservoir and the surface. As the name suggests, the valve can be controlled from the surface by hydraulic pressure transmitted from a control panel through a control line to the safety valve. The remote operation of this type of valve from the surface can also be integrated with pilots, emergency shut down (ESD) systems, and surface safety control manifolds. This flexibility of the surface controlled safety valve design is its greatest advantage.

In the simplest system an SCSSV is a normally closed valve held open by control line pressure supplied by a manifold at the surface, the pressure is maintained by hydraulic pumps controlled by a pressure pilot installed at some strategic point at the wellhead. Damage to the wellhead or flow lines cause a pressure monitor pilot to exhaust pneumatic pressure from a low-pressure line, which in turn causes a relay to block control pressure to a three- way hydraulic controller resulting in hydraulic pressure loss in the SCSSV control line. When this pressure is lost, the safety valve automatically closes, shutting off all flow from the tubing.

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There are two main categories of SCSSV: 

Wireline Retrievable



Tubing Retrievable

Statistics have proven that the TRSV valve is more reliable than the WRSV and that the flapper is more reliable than the ball mechanism, therefore the TRSV flapper valve is the most reliable of all. SCSSVs utilise a ball or flapper type closure mechanism. Both categories are supplied with or without internal equalising features. The equalising feature allows the pressure to equalise across the valve so it can be re-opened. Valves without this feature need to be equalised by applying pressure at surface. The equalising valve has more operating parts and is less reliable than non- equalising valve, however, with the latter, equalisation pressure is often difficult to provide and may be time consuming. 63.7

Wireline Retrievable SCSSV

Wireline retrievable sub-surface safety valves are located and locked, using standard wireline methods, in a dedicated safety valve landing nipple (SVLN). When the safety valve is set in the nipple, the packing seals against the nipple bore below the port. The packing section of the lock mandrel forms a seal above the port in the nipple. Control pressure, introduced through the control line, enters the valve through the port in the housing and allows pressure to be applied to open the valve. Because a wireline retrievable SCSSV seats in a landing nipple installed in the production string, it has a much smaller bore than a tubing retrievable SCSSV for the same size of tubing. Frequently, wireline retrievable safety valves have to be pulled prior to wireline operations being carried out below them, which have strong implications on well safety. Compared to a tubing retrievable SCSSV, the wireline retrievable SCSSV is easy to replace in the case of failure. Introducing a planned maintenance schedule in which valves are regularly pulled and serviced can prevent most failures. However, during wireline entry operations there is also a safety risk and care must be maintained at all times. The components that are required for the installation of a wireline retrievable SCSSV are:

P a g e | 93



Hydraulic control line



Control line protectors



Hydraulic control manifold



Wireline retrievable safety valve



Safety valve landing nipple



Locking mandrel



Wireline installation and retrieval tools for the locking mandrel.

63.7.1 Running in Hole SCSSV The valve is held open during RIH using a running tool and running prong. When the valve is run as part of the completion, a flow tube or straddle is installed across the valve to hold it open. The straddle is later retrieved using wireline methods. The control line pressure circuit between the safety valve landing nipple and the surface manifold is complete when the nipple seal bores are straddled by the elastomers on the valve body and the lock mandrel

63.8

Tubing Retrievable SCSSV

Tubing retrievable safety valves operate using the same principle as wireline SCSSVs except all the components are incorporated in one assembly, which is installed in the completion string. Some later models have rod pistons instead of concentric piston designs. They also have both equalising and non-equalising versions and versions that enable the insertion of a wireline valve inside the TRSV when the operating mechanism has failed. If the failure is due to a leaking control line then this contingency measure is ineffective. To enable the installation of the insert valve, the tubing retrievable valve needs to be 'locked open' or 'locked out'; the reduced internal bore may adversely affect production rates but the well can be safely shut in during an emergency. The components required for a TRSV safety system are: 

Hydraulic control line



Control line protectors



Hydraulic control manifold



Tubing retrievable safety valve for insert capability:



Wireline safety valve



Locking mandrel



Wireline installation and retrieval tools for the locking mandrel



Lock-out tool for the tubing retrievable valve.

63.8.1 Running in Hole TRSSSVs TRSSSVs are run held open using control line pressure or a hold open sleeve, or a straddle (protection sleeve)

63.9

P a g e | 94

Leak Off Tests (Inflow Tests)

Leak off tests are performed immediately after Sub-Surface Safety Valves are installed. A typical leak off test involves closing the production, kill and swab valves on the Xmas tree and bleeding off the control line pressure to the Sub Surface Safety Valve. Tubing pressure is bled off slowly above the valve to zero for a tubing retrievable valve and in 100 psi. (6.9 bar) stages for a wireline retrievable valve. The system is closed in again and tubing pressure monitored. If there is a rapid build-up, a major leak is indicated or improper functioning of the valve; in this case the valve should be cycled and the test repeated. After a specified shut-in period the tubing, head pressure should be below a maximum allowable pressure as specified by the operator's leak off criteria although there is an API standard. It is extremely important that pressure data be fully and accurately recorded. After initial installation, leak tests should be carried out periodically; this accomplishes three functions: 

To test the integrity of the seal in the safety valve.



To test that the lock mandrel in a wireline retrievable valve is still properly locked.



To cycle the valve to prevent 'freezing' in wells where they have been sitting in either fully open or fully closed position for extended periods of time.

Only authorised personnel should conduct all the above tests on all Sub-¬Surface Safety Valves.

63.10 Reliability Statistics on reliability indicate that Tubing Retrievable downhole safety valves are more reliable than wireline retrievable valves. Mean times to failures are approximately 6 years for wireline valves compared to 15 years for tubing retrievable valves. Tubing retrievable valves are also full bore giving higher flow rates.

63.11 Insert Valves Insert valves are small wireline retrievable valves which can be inserted through a "Locked Open" failed tubing retrievable valve to provide continued production, although restricted, with a means of shutting the well in, until a workover campaign is scheduled. Typical wireline runs include:

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

RIH to lock out the flapper valve



RIH with a communication tool and function the communication system to the open position. This provides control line pressure to the valve.



RIH and set the insert valve. The insert valve straddles the control line port to provide the hydraulic pressure integrity required to function the valve.

63.11.1

Annular Safety Valves

The sub-surface safety valves discussed so far, i.e. tubing retrievable and wireline retrievable, only provide control of the tubing. In these systems, no annular flow control exists. The purpose of an annular safety valve is to seal the annulus between the tubing and the casing immediately below the wellhead. This protects surface facilities and personnel in the event that wellhead integrity is compromised and prevents gas escaping from the annulus in the event of an emergency

The ASV is usually set just below the Sub Surface Safety Valve, as shallow as possible to limit the volume of annular gas that would escape in the event of a wellhead failure. They prevent flow from the annulus in gas lift completions.

Annulus safety valve systems are usually associated with completions where artificial lift or secondary recovery methods are employed e.g. gas venting from an electric submersible pump (ESP), hydraulic pump, or gas lift installations. Their application is to remove the potential hazard of a large gas escape in the event there is an incident where the tubing hanger seal is breached. They prevent flow from the annulus in gas lift installations. There are a number of designs on the market and the variety of modes of operation is too wide to be covered in this document, however the basic concepts are the same. With any annulus system, there must be a sealing device between the tubing and the casing through which the flow of gas can be closed off. This is generally a packer but may also be a casing polished bore nipple into which a packing mandrel will seal. In the sealing device there is a valve mechanism operated by hydraulic pressure similar to an SCSSV. The valve mechanism opens the communication path from the annulus below to the annulus above the valve and is fail-safe closed. The closure mechanism may be a sliding sleeve or flapper device. 63.11.2

Surface Control Manifolds

Surface control manifolds are designed to provide and control the hydraulic pressure required to hold an SCSSV open. Air powered hydraulic pumps maintain the hydraulic operating pressure for the safety valve. The hydraulic pressure is controlled through a three-way valve, controlled by remote pressure pilots and fire sensors. Pilot, sensor or manual activation removes the hydraulic pressure, closing the safety valve.

Note: Activation can occur from the operation of remote-control pressure sensing pilots, fusible plugs, plastic line, sand probes, level controllers or emergency shut down (ESD) systems.

P a g e | 96

Surface control manifolds usually come complete with a reservoir, pressure control regulators, relief valves, gauges, and a pump with manual override. Manifolds, in combination with the various pilot monitors, have many different applications, e.g. controlling multiple wells using individual control, multiple wells using individual pressures or any combination of these.

64.0

WEQG01.04 Landing Nipples

Landing nipples, also known as wireline or seating nipples are short sections of thick- walled tubulars machined internally to provide a locking profile and at least one packing bore. They are supplied in ranges to suit most tubing sizes and weights with API or premium connections and are available in two basic types: 

No-Go or Non-Selective



Selective

The landing nipple is designed to provide a profile at a specific point in the completion to locate, lock and seal subsurface flow controls. Their primary purpose is for receiving flow control devices. The flow control devices are locked into the nipple using lock mandrels with locking dogs in matching profiles. The flow control devices seal within the nipple bore using elastomeric seals, usually Chevron seals.

64.1

No-Go or Non-Selective

The non-selective nipple is a locating device and receives a locking device that uses a No-Go for location (positioning) purposes. This requires that the OD of the locking device is slightly larger than the No-Go diameter of the nipple. The No-Go diameter is usually a small shoulder located below the packing bore (bottom No-Go) but in some designs, the top of the packing bore itself is used as the No-Go. Only one No-Go landing nipple of a particular size should be used in a completion string. The No-Go restriction determines the largest size of equipment that can run through the device and provides a positive location for setting. They are widely used in high angle wells where wireline tool manipulation is difficult and weight indicator sensitivity is reduced. When the lock mandrel has located the no-go, it is in the correct position to allow the locking dogs to be jarred into the locked position.

64.1.1 Selective In the selective system, the locking devices are designed with the same key profile as the nipples and selection of the nipple is determined by the operation of the running tool and the setting procedure. The selective design is full bore and allows the installation of several nipples of the same size. In the selective system, the locking devices are designed with the same key profile as the nipples and selection of the nipple is determined the operation of the running tool and the setting procedure. The selective design is full bore and allows the installation of several nipples of the same size. Uses of landing nipples are to: P a g e | 97

65.0



Plug tubing from above, below or from both directions for pressure testing.



Leak detection.



Install safety valves, chokes and other flow control devices.



Install bottom-hole pressure and temperature gauges.

WEQG01.05 Packer/Tubing Connection

There are various methods for connecting the tubing to the production packer. The method chosen will be determined by a number of different factors. Stress analysis. – Is tubing movement a design feature. Type of packer chosen – Retrievable/Permanent. Probability of work over.

Functionality – Ease and frequency of work-over

66.0

WEQG01.06 Retrievable Packer Accessories

The function of a Polished Bore Receptacle (PBR) and Extra Long Tubing Seal Receptacle (ELTSR) 66.1

Travel Joints (Telescoping Joints/PBR/ELSTR)

A travel joint is used with a retrievable packer to compensate for tubing movement due to temperature and/or pressure changes during treating or production. An important aspect in a completion with a permanent packer is the tubing/packer seal. As the packer in effect becomes part of the casing after it is set, the tubing must connect to the packer in a manner so that it can be released. This connection whether it is a straight stab in, latched or otherwise, must have a seal to isolate the annulus from well fluids and pressures. This seal usually consists of a number of seal elements to cater for tubing movement. Seal elements are classified into two groups:

P a g e | 98



Premium



Non-premium

The premium group is used in severe or sour well conditions i.e. H2S, CO2 etc. and are normally 'V' typepacking stacks containing various packing materials resistant to the particular environment. The non-premium seals are for sweet service and can be either 'V' type packing stacks or moulded rubber elements. Locator Tubing Seal Assemblies tubing seal assemblies and Tubing Seal Extensions, are fitted with a series of external seals providing an effective seal between the tubing and packer bore. They also have a No-Go type locator for locating in the packer. Locator seal assemblies are normally spaced out so that they can accommodate both upward and downward tubing movement caused by changes in temperature and pressure.

66.1.1 Seal Bore Extensions

A seal bore extension is used to provide additional seal bore length when a longer seal assembly is run to accommodate greater tubing movement. The seal bore extension is run below the packer and has the same ID as the packer.

66.1.2 Anchor Tubing Assemblies Anchor tubing seal assemblies, are used where it is necessary to anchor the tubing to a permanent packer while retaining the option to unlatch when required. Anchor latches are normally used where well conditions require the tubing to be landed in tension or where insufficient weight is available to prevent seal movement.

66.1.3 Polished Bore Receptacles A PBR is simply a seal receptacle attached to the top of a permanent packer or liner hanger packer in which the seal assembly lands. The through bore can be made larger than the packer, to provide a larger flow area through the seal assembly.

66.1.4 Tubing Seal Receptacles A TSR is an inverted version of a PBR, a polished OD male member is attached to the top of the packer and the female (or overshot) is attached to the tubing. The seals are contained in the female member so that they are recovered when pulling the tubing.

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67.0

WEQG01.07 Side Pocket Mandrels

The Side Pocket Mandrel was originally designed for gas lift completions to provide a means of injecting gas from the casing-tubing annulus to the tubing via a gas lift valve. However, Side Pocket Mandrels can be used as circulating devices during well control activities. The Side Pocket mandrel is a special receptacle with a receiving chamber parallel to the flow chamber and connects to the tubing above and below and leaves the bore of the mandrel open for production or intervention. The parallel receiving chamber is offset from the string and is used to house a number of flow control devices such as:

67.1



Gas lift valves



Gauges



Dummy valves



Chemical injection valves



Circulation valves



Differential dump kill valves

Gas Lift Valves

There are many different designs of gas lift valves for various applications. They range from simple orifice valves to pressure operated bellows type valves. However, they all contain check valves to prevent tubing to annulus flow. These check valves may leak after a period of use and should never be relied on as barriers in a well control situation. They should be replaced with dummy valves and the tubing pressure tested to confirm integrity. 67.2

Dummy Valves

These are tubing/annulus isolation valves installed in place of the circulating valves when circulation is not required, for pressure testing the tubing from both sides during installation of the completion, or when well service operations are required. The equalisation valve is designed to equalise pressure between tubing and casing and/or to circulate fluid before pulling the valve from the SPM. The valve has two sets of packing that straddle and pack off the casing ports in the SPM. The tubing and annulus are isolated from each other until a pulling tool operates the equalising device. Pressures equalise through a port before the valve and latch is retrieved.

P a g e | 100

67.3

Chemical Injection Valves

Designed to control the flow of chemicals injected into the production fluid at the depth of the valve. A spring provides the force necessary to maintain the valve in the fail-safe closed position. Reverse flow check valves, which prevent backflow and circulation from the tubing to the casing, are included as an integral part of the valve assembly. Injection chemicals enter the valve from the annulus in an open injection system. (This requires the annulus to be full of the desired chemical. An alternative method is to run an injection line from surface to the SPM.) When the hydraulic pressure of the injected chemicals overcomes the pre-set tension in the valve spring plus the pressure in the tubing, the valve opens. Chemicals then flow through the crossover seat in the valve and into the tubing.

67.4

Circulating Valves

A circulating valve is recommended to be installed in any SPM whenever a circulating operation is to be carried out. The circulating valve is designed to enable circulation of fluid through the SPM without damaging the pocket. The valve allows fluid to be dispersed from both ends allowing circulation of fluid at a minimal pressure drop. Some valves permit circulation from the casing into the tubing only and others to circulate fluid from the tubing into the casing only. If a circulating valve is not used when circulating, the pocket will flow cut and a workover would be required to replace the SPM.

67.5

Differential Dump Valves

Differential dump/kill valves are designed to provide a means of communication between the casing annulus and the tubing when an appropriate differential pressure occurs. Below a pre- set differential pressure, the valve acts as a dummy valve since it uses a moveable piston to block off the circulating ports in the valve and the side pocket mandrel. The differential pressure necessary to open the valve will depend on the type and number of shear screws installed. The valve will only open when the casing annulus pressure is increased by the differential (the shear screw rating) above the tubing pressure. An increase in tubing pressure above the casing annulus pressure will not open the valve. After opening, the piston is locked in the up position and fluids can flow freely in either direction. The hydrostatic pressure from the column of annulus fluid will kill the well and remedial operations can be planned.

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68.0

WEQG01.08 Sliding Side Door

Sliding Side Doors (SSDs) or Sliding Sleeves were originally designed for zone selection purposes however, they are used as well control devices and can be installed in the tubing above the packer to provide a means of circulating or communicating between the tubing and the annulus when the sleeve is moved to the open position. SSDs are also used to:



Bring a well into production after drilling or workover by circulating the completion fluid out of the tubing and replacing it with a lighter under balanced fluid.



Kill a well prior to pulling the tubing in a workover operation.



Select / isolate zones

The application of SSDs as a circulation device means they must be positioned as close as possible to the packer, normally within 100 ft.

69.0

WEQG01.09 Sliding Side Door

Sliding Side Doors (SSDs) are available in versions that open by shifting an inner sleeve, either upwards or downwards by using the appropriate shifting tool. When there are more than one SSD in a well, the sleeves may be opened and closed with selective shifting tools without disturbance of sleeves higher up in the string. Note: Tubing and annulus pressures must be equalised before an SSD is opened to prevent wireline tools being blown up or down the tubing. When used as circulation devices they must be fully open during circulation activities. Some operators will not install a SSD above the packer because it will introduce additional potential leak paths and seal failure can lead to a workover although a pack-off can be installed as a temporary solution. The top sub of the SSD incorporates a nipple profile and the bottom sub has a polished bore to enable the installation of the pack-off, sometimes also termed a straddle or isolation sleeve. Operators who do not include SSD's as a circulation path may prefer to use a tubing punch when a circulation path is required.

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70.0

WEQG01.10 Packers

A packer is a device used to provide a seal between the tubing and the casing, as well as providing a sealed tubing/casing annulus. This seal is created in conjunction with the completion tubulars and isolates the annulus from the casing below the packer. It allows the flow of reservoir fluids from the producing formation to be contained within the tubing up to the surface and prevents the production casing from being exposed to well pressure and corrosion from well effluents or injection fluids.

Packers are usually set just above the top perforations and remain in the well during normal well production. Service packers such as those used in well testing and cement squeezing etc. are used temporarily and retrieved for re-use or milled. A packer consists of:



Case hardened slips to bite into the casing wall and hold the packer in position against pressure and tubing forces.



Packing elements that seal against the casing.

In general, packers are classified in two groups:

32.17



Retrievable



Permanent

RETRIEVABLE PACKERS

These are generally run into the wellbore on the production tubing string. As the name implies, retrievable packers can be recovered from the well after setting by pulling it with the completion string.

32.18

PERMANENT PACKERS

These are installed in the wellbore usually independent of the production tubing string. A permanent packer may be considered as an integral part of the casing.

P a g e | 103

The tubing can be released from the packer leaving the packer set in the well. Tubing can subsequently be run back and re-sealed in the packer. Permanent packers are not attached to the production tubing and can only be removed from the well by milling operations.

71.0

WEQG01.11 Packer Setting Procedures

Mechanical set packers are set by some form of tubing movement, usually a rotation or upward /downward motion. Others can be weight set- the tubing weight can be used to compress and expand the sealing element. By a simple up string pull the packer is released. It is used best in shallow low-pressure wells that are straight. It is not designed to withstand pressure differences unless a hydraulic hold down is incorporated.

P a g e | 104



Tension-set packers are set by pulling a tension on the tubing, slacking off releases the packer. Good for shallow wells with moderate pressure differences. The lower pressure helps to increase the setting force on the packer. Used in a stimulation well.



Rotation-set packer- Tubing rotation is used to set the packer to mechanically lock it in and a left hand turn engages and a right hand turn retrieves it.



Hydraulic-set packers use fluid pressure to drive the cone behind the slips. Once set they remain set by the use of either entrapped pressure or a mechanical lock. They are released by picking up the tubing. They are good for used in deviated/ crooked holes where tubing movement is restricted or unwanted. The tubing can be hung in neutral/ tension or compression.



Inflatable packers - use fluid pressure to inflate a long cylindrical tube of reinforced rubber to set the packer. Frequently used for open-hole testing in exploration wells and for cement assurance in production wells. Also used in wells where the packer must pass through a restriction and then set at a much larger diameter in casing or open holes. Many variations for specific applications are available including those capable of withstanding high pressure differentials.



Permanent packers- Run and set on an electric wireline, drill pipe or tubing. Opposed slips are positioned to lock it in compression. Once set this packer is resistant to motion for either direction. Wireline uses an electric current to detonate an explosive charge to set the packer. A release stud then frees the assembly form the packer. Tubing can be used by applying rotation or a pull or a combination of both. They are good in wells that have high pressure differentials or large tubing load variations and can be set precisely. They can be set at the deepest depth of the well.



Cement packers - In this case the tubing is cemented in place inside the casing or open hole

Packer Setting Precautions: 

Casing Cleaned and scraped



Appropriate sized gauge ring run



Junk basket run to ensure no debris in the well bore



CCL to be run



Packer set between casing collars

Packer Pulling/Unseating Precautions:

72.0



After unseating Let the completion Hang



Pull completion slowly to prevent swabbing



Shut well in – do a flow check



Have TIW/Cross-overs on location



Punch hole in the packer tail pipe to release trapped gas

WEQG01.12 Wireline Entry Guide (WEG)

A wireline re-entry guide is used for the safe re-entry of wireline tools from the casing or liner back into the tubing string. It is attached to the end of the production string or packer tailpipe assembly and has a chamfered lead in with a full inside diameter.

Wireline re-entry guides are generally available in two forms: 

Bell Guide



Mule-Shoe

The Bell Guide has a 45° lead in taper to guide wireline tools back into the tubing. This type of guide has a relatively large outside diameter, and is used in completions where the end of the tubing does not need to pass through any casing obstacles such as liner laps.

The Mule Shoe guide has the same function as the Bell Guide but features a 45° angle cut on one side of the guide. The primary purpose of this angle is to guide the tubing past any obstructions in the wellbore when the tubing is being run. If the tubing hangs up on the liner lap or on the top of the packer, rotation of the tubing should allow the mule shoe guide to kick back into the wellbore.

P a g e | 105

73.0

Tubing

Tubing refers to the pipe used to create a flow conduit inside the wellbore, between the reservoir and the wellhead. This flow conduit provides control of the produced fluid and facilitates wellbore servicing operations such as wireline and pumping activities. Typically, tubing is run inside a casing string or a liner but tubing can also be cemented in slim hole wells as the production tubing. One or more strings of tubing may be used in a completion and this decision is a function of the number of reservoirs to be produced, whether the fluids will be commingled or produced separately and whether the reservoirs will be produced concurrently or sequentially. The purpose of using tubing in a well is to convey the produced fluids from the producing zone to the surface, or in some cases to convey fluids from the surface to the producing zone. It should continue to do this effectively, safely and economically for the life of the well, so care must be taken in its selection, protection and installation. The tubing must retain the well fluids and keep them out of the annulus to protect the casing from corrosion and well pressure, which may be detrimental to future well operations such as work-overs.

Tubing connections play a vital part in the function of the tubing. There are two types of connection available; API and premium connections. API connections are tapered thread connections and rely on thread compound to seal whereas the premium thread has at least one metal-to-metal seal. Premium connections are generally used in high-pressure wells. Tubulars up to and including 41/2 ins. are classified as tubing, over 41/2 ins. are classified as casing. In large capacity wells, casing size tubulars are often installed as the production conduit.

P a g e | 106

Tubing selection is governed by several factors:



Anticipated well peak production rate



Depth of well



Casing sizes



Well product



Use of wire-line tools and equipment



Pressures/temperatures



Tubing/annulus differential pressures

Casing and tubing strings are the main parts of the well construction. All wells drilled for the purpose of oil or gas production (or injecting materials into underground formations) must be cased with material with sufficient strength and functionality.

Special connections are used to achieve gas-tight sealing reliability and 100% connection efficiency (joint efficiency is defined as a ratio of joint tensile strength to pipe body tensile strength) under more severe well conditions. Severe conditions include: 

High pressure (typically > 5,000 psi)



High temperature (typically > 250°F)



A sour environment



Gas production



High-pressure gas lift



A steam well



A large dogleg (horizontal well)

When premium tubulars are being run into the well it is normal in modern day wells due to the high temperatures and gas tight requirement that the joints be torqued.

P a g e | 107

The purpose of torqueing every joint is to be able to prove the make up by downloading a thread torque graph ensuring that all joints meets with the current Integrity requirements. To meet various completion designs, there is a wide range of tubing sizes, wall thickness (weights) and materials to provide resistance to tubing forces and differing well environments. The best tubing selection is the cheapest tubing which will withstand the external, internal and longitudinal forces it will be subjected to, and resist all corrosive fluids in the well product. Tubing in the main, is supplied in accordance with API specifications, which have a range of materials to resist most of the potential corrosive well conditions, but, where deeper high-pressure sour reservoirs are being developed, the API range is not suitable. To fill this gap in the market, steel suppliers provide propriety grades. These grades are usually high chrome steels up to 24% chrome designed for various high temperature and sour well conditions. For ease of identification, tubing is colour coded to API specification. Some specialist supplier's steels are not covered by the code and provide their own specific codes.

P a g e | 108

73.1

Blast Joints

Fluids entering the tubing from the perforations may display a jetting behaviour. This fluid jetting may abrade the tubing string at the point of entry, ultimately causing tubing failure. Blast joints are joints of pipe with a wall thickness greater than the tubing. These joints are installed opposite the casing perforations (non-gravel packed) where external cutting or abrasive action occurs caused by produced well fluids or sand. They are heavy-walled tubulars available usually in 10, 15, and 20 ft. lengths. They should be long enough to extend at least 8 ft. either side of a perforated interval for a safety margin Blast joints delay failure from erosion at the point of entry and are similar to flow couplings, which are discussed later. Blast joints are usually manufactured from a heat-treated alloy such as 415H. Tungsten carbide or “stellite” is sometimes used.

73.2

Perforated Joints

In wells where flowing velocities are high, a restriction in the tubing, such as a gauge hanger, can cause false pressure and temperature readings. Vibrations in the tool can cause extensive damage to delicate instruments. To provide an alternative flow path, a perforated joint is installed above the gauge hanger nipple and allows unrestricted flow around the gauge. The perforated joint is normally a tubing joint drilled with sufficient holes to provide a flow area greater than that in the tubing above.

73.3

Flow Couplings

Flow couplings, are heavy-walled tubulars installed above or below any completion component causing a restriction to flow which may cause flow turbulence such as wireline nipples, SSDs, SCSSV landing nipples etc. and combat internal erosion. They are manufactured from harder materials and have a thicker wall thickness than the tubulars they protect so that, if erosion is experienced, the flow coupling will still maintain pressure integrity over the projected life of the well. In higher velocity wells, such as high pressure gas wells or injection wells, a flow coupling may also be placed below restrictions. PS Flow Couplings and Blast joints serve the same purpose. Blast joints are fitted below the packer across the formation where flow couplings are fitted above the packer to smooth the flow. P a g e | 109

74.0

WEQG03.01 How to Check Equipment

Before work is performed, check the type of equipment needed with respect to the pressure, dimensions, temperature, and well fluids (water, gas, oil or much sand).

The first thing you must do before rigging / installation is to verify that equipment is labelled and has all certificates. When rigging begins, remove all protectors, and threads and seal surfaces are cleaned and checked. Flanges are checked and packing rings replaced.

Checks must include: 

Correct pressure class on all equipment.



Correct dimensions



Correct crossovers (flanges) on all equipment



Packing rings are of the right type and are approved for their intended use



Correct torque given from the manufacturer is used.

Before the well is completed, all valves are tested. The minimum requirements are set by API, but several companies may operate with more stringent requirements.

75.0

WEQG03.03 Non-Shearables Across BOP

A safety joint should be made available on the rig floor. In the event the well has to be shut-in and a nonshearable is across the BOP, then the safety joint is made up to the non-shearable and then lowered until the safety joint is across the BOPs. The safety joint consists of a DPSV joint of drill pipe and a crossover sub if required.

76.0

WEQJ01.01 Monitoring Annuli Pressures

Definition of an annulus The area between two concentric circles = “a ring shaped part, figure or space” The annular voids form the principal barriers between the produced fluids and the atmosphere. 

P a g e | 110

By monitoring the annulus pressures, we are able to assess the condition and integrity of the well tubulars.

77.0



Anomalous annulus pressures may give the first indication of down hole problems although it does not automatically mean there is a leak



Thermal expansion or ingress of formation fluid could also cause an increase in annulus pressure, regular sampling of annulus fluids may also be undertaken



Annulus temperatures should also be considered

WEQJ01.02 Abnormal Annulus Pressures

This could be the first sign of a leak or can be caused by thermal expansion to the tubing due to the high flowing temperatures. There are various ways for bring the pressures back to normal, which would be constant monitoring along with a procedure called lubricate and bleed.

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Part 3 Coiled Tubing

P a g e | 112

78.0

Coiled Tubing Operations .............................................................................................. 114

79.0

WCA01.01 Deployment System ..................................................................................... 118

80.0

WCA01.02 Check Valves ................................................................................................ 119

81.0

WCA01.03 Additional Well Control Devices ................................................................... 119

82.0

WCA01.04 Coiled Strippers ............................................................................................ 120

83.0

WCA01.05 Minimum Barrier Requirements ................................................................... 121

84.0

WCA02.01 Operating Principles of Coiled Tubing ........................................................... 122

85.0

WCA02.02 Shear/Seal BOP ............................................................................................ 126

86.0

WCA04.01 Ram Type BOPs ............................................................................................ 128

87.0

WCA04.03 Seal Defects.................................................................................................. 130

88.0

WCA04.04 Assess Seal Damabge .................................................................................... 130

89.0

WCA04.05 Non-Shearable Components ......................................................................... 130

90.0

WCD01.01 Check Specific Rig Up Requirements ............................................................. 131

91.0

WCD01.02 Equipment Compatibility Check .................................................................... 131

92.0

WCD01.03 Coiled Tubing Stripping Elements.................................................................. 131

93.0

WCD01.04 Defective Stripping Elements ........................................................................ 132

94.0

WCD01.05 Function & Position of Valves ....................................................................... 132

95.0

WCD01.06 Adjustable and Fixed Chokes ........................................................................ 133

96.0

WCD01.07 Double Barrier Protection When Changing Stripper Elements ....................... 135

97.0

WCE01.01/02/03 Test Requirements for Pressure Testing .............................................. 135

98.0

WCF01.01 Mechanical Barrier ........................................................................................ 137

99.0

WCF01.03 Barrier Operations ........................................................................................ 138

100.0 Contingency Procedures ................................................................................................ 138 101.0 WCG01.01 Power Pack Failures ..................................................................................... 140 102.0 WCG01.02 Pump Unit Failure ........................................................................................ 140 103.0 WCG01.03 Stripping Element Failure ............................................................................. 141 104.0 WCG01.04 Leak Between the Top of Tree & Stripper ...................................................... 141 105.0 WCG01.05 Surface Pin Hole Leak in CT ........................................................................... 142 106.0 WCG01.06 ..................................................................................................................... 143 107.0 WCG01.07 General Muster Alarm .................................................................................. 143 108.0 WCG01.08 Collapsed Tubing .......................................................................................... 143

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78.0

Coiled Tubing Operations

Coiled Tubing was first utilised in operation PLUTO, during World War 2 to provided allied troops with a secure fuel supply from England to France to support the invasion of Europe. However, modern coiled tubing dates back to the 1960’s, these days’ well service and workover operations account for more than 75% of coiled tubing use. The ability to perform remedial work was the key driver associated with the development of Coiled Tubing.

Coiled tubing has had to overcome three technical challenges:



A continuous conduit capable of being inserted into the well bore (CT string).



A means of running and retrieving the CT string into or out of the well bore while under pressure (injector head).



A devise capable of providing a dynamic seal around the tubing string (stripper/pack off devices).

The main Coil Tubing functions:

P a g e | 114



Work Over



Production and Completion Services



Logging / E-line Operations



Stimulation



Drilling



Testing

The main components of a coiled tubing unit are usually modular, lightweight skid mounted designs, for ease of lifting and positioning on the well sites. Truck mounted versions are also manufactured for land wells accessible by road. There are five basic skid units that make up a standard modular coiled tubing package, these are: 

Power Pack



Control Cabin



Coiled Tubing Reel



Injector Head with Goose Neck



Wellhead Pressure Control System

While the initial development of Coiled Tubing was spurred by the desire to work on live wellbores, speed and economy have emerged as key advantages for application of Coiled Tubing.

In addition, the relatively small footprint and short rig-up time make Coiled Tubing even more attractive for drilling and workover applications.

P a g e | 115

78.1

43.0

Surface Equipment

SURFACE EQUIPMENT

A Coiled Tubing unit is made up of 5 basic components: the power pack, the control cabin, the tubing reel, the injector head and the BOP's. In addition to the basic components a spare reel of tubing is often taken on the job, especially offshore, and for work being carried out on a semi- submersible, a special lifting frame is used to allow the unit to be attached to the compensator. For work on wells with no derrick, a hydraulic support frame can be used to support the weight of the injector and gooseneck instead of requiring a crane throughout the job.

78.2

Power Unit

This large, usually diesel driven, power pack drives many hydraulic pumps that control all the functions on the unit. It provides the primary power supply for the pressure control equipment with accumulators on the skid. There is usually a secondary power source for charging the BOP accumulators. This is often an air pump. The accumulators have an operating pressure of 3000 psi. and the recharge pump is usually set to kick in when the pressure falls to 2700 psi. (90%). All accumulators are pre-charged with Nitrogen.

78.3

Control Cabin

The cabin can usually be raised hydraulically so that the operator can see over the reel in front of him and watch the pipe spooling over the gooseneck. The Coiled Tubing operator will have the following controls in front of him:

P a g e | 116



Reel and spooler controls.



All BOP's.



The injector head.



Recording instruments.



Depth counter and weight indicator.

78.4

Tubing Reel

The Coiled Tubing reel normally stores the entire tubing string. Capacity ranges from typically 5000 ft. to 22000 ft. The weight of a reel increases dramatically with length, diameter and pipe weight. In the worst cases, with very small offshore platform cranes, the pipe has been spooled from the full reel on the supply boat to an empty reel on the platform deck. In certain circumstances, it is also possible to join two reels together with a connector to make a longer tubing string. The reel is supported on an axle and is rotated by a hydraulic motor driven chain drive. This drive system ensures that some tension is kept on the pipe between the gooseneck and the reel. This is done by adjusting the hydraulic pressure on the reel motor. The reel drive system is NOT used to run pipe into or pull out of the well.

To control the spooling process and ensure that the pipe is correctly coiled on to the reel, a winding mechanism (the level wind) is synchronized with the rotation of the reel by a chain drive. This level wind assembly is part of the spooling arm that also contains the depth counters, ovality checker, etc. The inner end of the tubing is connected to a high-pressure rotating joint on the inside of the drum and then to a 2 inch valve. This allows fluid to be pumped down the coil whilst running in or pulling out. Attached to the side of the reel, there is a ball launcher. This is required so that a ball can be dropped (pumped) down the pipe to operate any one of various downhole tools. The ball (plug) launcher can also be used for launching displacement plugs that would be pumped before and after a batch of cement. The first plug would bump against the coiled tubing end fitting and continued pumping would shear the central core out of the plug. There is usually a spray system fitted on the skid that allows the pipe to be sprayed with oil based corrosion inhibitor when pulling out of the hole.

78.5

Injector head

The injector pushes or pulls the pipe in or out of the well. It does this by using hydraulic motors that drive chains with attached contoured blocks to grip the pipe and so push it in or out of the well. There are different sizes of injector with the ability to pull up to 120000 lbs. for the larger pipe sizes. The chains/blocks are specific to each pipe diameter. There are usually two speeds (gears) which allow up to 125 ft./min. and up to 250 ft./min. The operator has precise control of the injection force and the injection speed. An over-large injection force can result in damage to or breaking of the coil if an obstruction is encountered in the well. The controls are always set to the minimum necessary to run or pull the pipe. The inside chain tensioners are hydraulic cylinders that push on to "skates" on the backs of the chains and force them against the pipe. The outside chain tensioners are hydraulic cylinders that keep the chains tight. The load cell for the weight indicator and a reservoir for lubricant for the pipe are mounted on the injector. The gooseneck is attached to the top of the injector to guide the pipe coming from the reel into the top of the injector.

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79.0

WCA01.01 Deployment System

During standard operations, the distance from the swab valve on the Xmas tree to the stripper determines the maximum length of BHA that can be used during a Coiled Tubing job. For certain kinds of work, particularly perforating, it is necessary to have a much longer BHA. Before the use of deployment systems, operators used the DHSV as the only barrier when running up to 1500m. of TCP guns. The deployment system looks like a multi-ram BOP and is located below the quad or combi in the stack. Individual sections of the BHA are run (often on wireline) and are then held in the deployment system. The deployment system seals around the outside of the BHA in much the same way as a BOP. The next section of BHA is run and attached to the previous section. In some cases this is done by the deployment system screwing the sections together and in others, the sections latch together. In this way, very long BHA's can be run until it is time to connect the coiled tubing to the top section. The injector is then attached and the BHA can be run in to the well in the normal way. To remove the BHA, the procedure is reversed.

Advantages

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

A productivity index double than predicted



Perforating string insertion and retrieval without killing the well Features



Gun-system length records for CT and CIRP deployments



Entire 2870-ft interval perforated underbalanced in one run



Case study: Record perforated interval underbalanced using coiled tubing Perforating



Special connectors between the gun sections provided sealed ballistic transfer.

80.0

WCA01.02 Check Valves

Check valves allow flow in one direct, the only time that check valves would not be used is in a dead well situation. The only type of operation that requires no check valves is reverse circulation. Note: If Reverse circulation is to be carried out the check, valves need to be removed.

80.1

Flapper Check Valve

Flapper type check valves are of full-bore design. This enables the transmission of launching balls to function other downhole tools. The flap in the valve does not lie flat against the inside of the valve body, and this aids the flap to close if circulation is reversed. The flap has an elastomeric seat to enhance the sealing capability.

Large Internal Diameter Balls and Darts can be dropped thru. Double flapper type

81.0

WCA01.03 Additional Well Control Devices E is special configuration when using a pump out check valve for operational reasons. Due to the check valve, being expendable by pumping down a dropped ball another check valve cannot be installed above it. For this reason, primary internal well control is only single check valve. If expended the secondary well control system is a wireline check valve installed in the landing nipple.

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82.0

WCA01.04 Coiled Strippers

The stripper, sometimes referred to as the pack-off or stuffing box, provides the primary operational seal between the pressurized wellbore fluids and the environment. This device is always attached to the bottom of the injector and may be a single or tandem device. It is the primary barrier when Coiled Tubing is in the hole and allows the pipe to be run in or out whilst maintaining a seal around the pipe. Also called the stuffing box or tubing stripper, there are three basic kinds.



Conventional



Side Door



Radial

The Radial stripper is not widely used unless with the very big pipe sizes (27/8 inch and 3V2 inch). The principle of all three is the same. Operator controlled hydraulic pressure acts on a piston that pushes directly or indirectly on the insert (packer or element) which makes the seal around the pipe. The life of a stripper insert is dependent on many things such as: Wellhead pressure 

Stripper pack off pressure



External condition of pipe



Lubrication

If the inserts wear then they can be replaced with or without pipe in the hole. In order to change the insert with pipe in the hole, it is necessary to close the slip and pipe rams (in the BOP's below the stripper) and bleed off pressure above the pipe rams. The conventional stripper can be the most difficult to change the insert in, because it must be removed/inserted through the top of the stripper which is attached to the bottom of the injector. Access here is limited.

The side door and the radial are designed to have the element replaced through the side of the stripper. The use of tandem strippers is quite common as it provides a back up to the primary barrier (top stripper) in the event of the packing being worn. Rather than having to stop and replace the insert in the first stripper, it can be depressurised and the second (lower) stripper can be energised with the job continued without a break however, this would mean that only one barrier is available.

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83.0

WCA01.05 Minimum Barrier Requirements

The minimum barrier requirements is two some configurations have a third barrier, shear seal located on the tree.

83.1

WCA01.05 Shear/Blind or Shear/Seal Ram

The shear/blind ram shall be capable of shearing the highest-grade of work-string, as well as sealing off the wellbore with lateral and face seals. The shear/seal ram shall be capable of shearing the highest grad of as follows as well as sealing off the Wellbore with lateral and face seals. The ram design needs to clear sheared work-string from the seal area as a part of the shearing and closing operation, to enable circulation rate through the work-string left in the well. The shear blades shall be designed to prevent small pipe or cable to be caught. On high pressure or gas, wells there should be an extra shear capability situated on the tree to facilitate a cut on the coil if stuck at the bottom of the well. To be able to shut the well in, in this situation tension would be pulled on the coil then shear the coil to allow it to pass through the tree.

Points of Potential Failure are:

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

Reel Drive Brake



Reel Drive System



Turbine Counter

Three factors that affect the coil tubing Integrity: 

The radius of the gooseneck



Traction



Continuous Cycling of the coil tubing

Three factors that affect the longevity of the coil tubing: 

The radius of the gooseneck



Amount of bending cycles



Footage run

Comparison between model predictions for the point at which first cracks will begin and the actual test data for the point of failure from the fatigue tests. The model predictions for actual failures are also shown. From the predicted crack initiation data:

84.0



For a 1.25 ins. OD pipe and 0.87 ins. wall thickness, the pipe life increases by nearly 300% when the pressure is decreased from 5,000 psi. to 3,000 psi.



Increasing the gooseneck radius from 50 ins. to 72 ins. for 1.25 ins. OD pipe and 0.87 ins. wall thickness, increases the pipe life by 54%



Increasing the wall thickness from 0.87 ins. to 0.109 ins. for 1.25 ins. OD pipe with 5,000 psi., increases the pipe life by 127%



Decreasing the pipe diameter from 1.5 ins. to 1.25 ins. for 5,000 psi. increases the pipe life by 171%.

WCA02.01 Operating Principles of Coiled Tubing

When we activate, the backup barrier, it is usually because the primary barrier has failed. The placement will therefore be just under the stripper, but there will usually be a quick coupling in between. The backup barrier is often just called a BOP and is usually a ram type.

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In special cases, it can also be an annular BOP, but this is not common. Annular BOP’s are discussed under the chapter “Primary barriers.” Coiled tubing BOP’s are usually a block type BOP. It is of course possible to use individual valves in the same way as in snubbing, but it is no longer common to do so. A block type BOP can be made for two, three or four sets of different types of rams. Common for all of these is that we arrange them so that there is a pipe ram at the bottom. This valve is our back up barrier. The quadruple BOP came first and was a big improvement in comparison to the single BOP’s, but it was built with the same set up as using four single BOP’s. Eventually, some combinations of these different rams were made so that it was possible to use triple and combi-BOP’s, but these rams belong under “Secondary barriers” and will be further discussed there. A pipe ram is a ram with a replaceable seal in the front. The seal can be exchanged for different sizes in order to fit the particular pipe diameter. When the backup barrier - the pipe ram - is activated, it is also common to activate the slip ram to keep the pipe fixed and prevent it from moving up or down. The slip ram is usually placed right over the pipe ram. It is most common to place the pipe ram at the bottom of the BOP, but it is possible to make changes to this when necessary. One possibility is to have the pipe ram and slip ram switch places. When the backup barrier is activated, it must be secured mechanically by screwing in the locking screw and then testing. The test is an inflow test where pressure is bled off topside and then observed for a pressure increase.

84.1

Mechanical Construction and Function

A single BOP is built up with two double-acting hydraulic cylinders that operate, i.e. slide in and out, the actual ram that is installed. There are normally double seals between the hydraulic system and well pressure. To see how far in the rams are, there will often be an indicator pin installed on the hydraulic piston. A mechanic device is always installed, which is the locking screw on the BOP that prevents the ram and piston from accidentally closing. While rigging up the BOP, it is connected to all hydraulic hoses and then function tested. Leak testing of the pipe ram will later be performed with coiled tubing run through the BOP. It is common that pressure is then pumped up through the coiled tubing.

COMBI (combination) A combi BOP is a dual BOP that does exactly the same as the quad but has only two rams. The upper ram is the blind/shear and the lower ram is the pipe/slip. There is a kill line connection between the two rams and there are equalizing valves across each ram. If it is required to cut the pipe, the combi is operated in the same way as the quad. In order to make the cutting of the pipe more certain, it is best to have the pipe in tension rather than compression.

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The advantages of a combi over a quad are: 

Shorter



Less ram operations in an emergency i.e. quicker operation



Does not require the pipe to be raised to close the blinds and so requires only a minimum number of operating steps in an emergency



Requires less hydraulic fluid to perform the same functions (some power packs do not have enough accumulator capacity to operate all functions of a quad with the engine stopped).

Disadvantages are: 

It offers less flexibility in operation.



Pipe end will be more heavily crimped on cutting and that can make kill pumping difficult.

Advantages of using a combi bop are:



It is compact when there is a height restriction.



It only has two rams therefore; it is easy to shut it down in an emergency.



Least amount of leak paths

Pipe-Slip Rams

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Triple Compi BOP

84.2

Triple BOP

Triple BOP's are sometimes used and may be called triple combi BOP's. They can be set up in various ways to suit the job in hand. They can be fitted with all standard ram configurations and can have hydraulic booster actuators fitted if required. They are often fitted with combination rams hence the name triple combi BOP. Ram configuration (top to bottom):

84.3



Blind /shear



Slips



Pipe



Quad BOP

It is used to control the well pressure and allow for safe operation at all times. Here you can see a quad BOP. It means that all the necessary functions are separated from each other. We also have triple and combi-BOPs where some functions are combined with each other.

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85.0

WCA02.02 Shear/Seal BOP

The shear/seal BOP is preferably arranged directly on the Xmas tree and should be able to cut everything that can be run into the well and maintain a seal against well pressure. The shear/seal can be operated even if power from the installation fails. The valve has an accumulator bank to operate the rams in an emergency. Everything that cuts and seals is a tertiary barrier.

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85.1

Accumulator Bottles

standard accumulator bottle has an 11 gallon capacity, it is pre-charged with nitrogen and holds, when precharged to 3000 psi, 1.7 gallons of N2 and 8.33 gallons of hydraulic oil. Accumulator bottles are connected in series with the hydraulic system of the Coil

Tubing Unit and are continuously charged by the system and kicks in if the supply fails or drops below 2700 psi from 3000 psi. The accumulators must store enough fluid and energy to be able to function to close – open – close – open all the BOP rams.

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86.0

WCA04.01 Ram Type BOPs

There are several different makes and types of ram type BOP. They are all basically of the same style and are single, double, triple or quadruple. Coiled Tubing BOP's are controlled from a panel in the control cabin. The hydraulic pressure required to operate them is between 1500 and 3000 psi. They are usually either 3" or 4" nominal bore, but are available in smaller sizes for very small tubing and bigger sizes for the largest coiled tubing. Single BOP's used as shear seals (or safety heads) tend to be large bore with bigger hydraulic ram assemblies to ensure they will cut anything required. Most BOP's are rated at 10000 psi. The stripper is the primary barrier when coil is in the hole. Pipe rams are secondary barriers and safety heads (where used) are tertiary barriers. If an annular BOP is used it is a secondary barrier. If a second (tandem) stripper is used, it is a secondary barrier or back up to the primary barrier. Only one barrier is classified as the primary barrier although there may be multiple secondary barriers and multiple tertiary barriers.

86.1

Quad BOP

The quad (quadruple) BOP is a solid block BOP with four rams. For normal Coiled Tubing work, these rams always have the following functions (from the top down) 

Blind Rams, seals the wellbore when the CT is out of the BOP



Shear Rams, used to cut the pipe (only)



Slip Rams, supports the CT weight hanging below



Pipe Rams, seal around the hanging pipe.

Pipe Cutting Procedure

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

Close the slip rams to hold



Close the pipe rams to seal



Close the shear rams (cutters) and cut the pipe



Pull the remaining pipe above the blinds



Close the blinds

If required pump through the kill connection and down the pipe. Modern designs of cutters do not completely crimp the pipe where it is cut which allows fluid to be pumped down the coil in hole.

86.2

Annular BOP

Annular BOPS are sometimes used in CT rig ups and would typically be run below the standard quad, combi or triple BOP. WHY? To seal round the BHA, especially during deployment operations. Can also be run below a single stripper packer as a backup in preference to a dual stripper. This would provide a barrier to change the stripper element while inhole but would not affect BHA length above swab valve.

86.3

Riser

In most cases, risers will be rigged up. All connections between the valve tree and BOP are flanged. There can be so-called quick couplings over the BOP: It is important that the riser has the correct diameter and service for the operation in question. It must withstand the pressure and all well fluids that can be produced.

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87.0

WCA04.03 Seal Defects

Generally, we can say that there are three reasons for replacing packer elements in BOP’s:

88.0



The first is if there are changes in the dimension of the pipe that is run from one run to the next. In that case, it will be necessary to change the elements for the dimension to be run first. It may also be the case that several pipe dimensions are used on the same run. There will then usually be several BOP’s set up so that all dimensions are covered. One method of doing this is by using an annular in addition to regular ram BOP’s.



The second reason for replacing seals is general wear and tear.



The third reason for replacing seals is damage to the rubber. This may occur if for example the BOP are closed around a tool or tool string with sharp edges. There may also be gas leakage that cuts tracks in the rubber, or gas bubbles that penetrate into the rubber.

WCA04.04 Assess Seal Damage

Usually, ram seals are used until at least 80% of the seal surface is left in comparison to new elements. If damage or defect that can cause leaks to occur, the packing elements must be replaced. If the BOP has been activated with a pipe through it, the BOP must be dismantled and the packer that was used must be replaced. It is important to equalize the pressure over and under the valves before a closed valve is opened. If not, it is highly likely that the sealing elements will be damaged.

89.0

WCA04.05 Non-Shearable Components

All equipment used in well operations must be pressure classified and certified. Only approved workshop can carry out pressure testing and certification. Shear rams must be designed to cut the string in question. Unless it is classified as a Safety Head then this BOP will only cut the tubing and not the BHA.

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90.0

WCD01.01 Check Specific Rig Up Requirements

First, you have to verify that all the equipment is marked and has all certificates in place prior to rigging up. When rigging up begins, all protectors are removed and threads and seal surfaces are cleaned and confirmed. Flanges are checked and ring gaskets are replaced. Before the well is opened, the system is function and pressure tested as described in the procedures. To save time, the procedure should be designed so that several sections of the system are tested simultaneously. The procedures for leakage testing vary somewhat depending on where you are working. In an IWCF context, the whole rig-up should be tested to the well’s highest expected shut-in pressure, while in a NORSOK context the requirements are that a low pressure leak test and high pressure leak test are to be utilized. Usually the tests are performed from as lower most point in the rig up. Otherwise, it is common to pump pressure in through the coiled tubing, as this will also be tested. Checklists should be used to ensure that nothing is forgotten or left out. If a part of the equipment does not work or there are leaks, it must be repaired before the job can be started.

91.0

WCD01.02 Equipment Compatibility Check

Before a job is performed, check the type of equipment that is needed with respect to pressure, dimensions and service rating. Logistics and area with sufficient space for the equipment are also important This is information that the operating company shall provide to the service company in order to fulfil the equipment requirement. A list with specifications for necessary equipment can be set up. Ensure that all equipment that is available complete with all the necessary requirements.

92.0

WCD01.03 Coiled Tubing Stripping Elements

During CT operations the primary barrier is provided by the energised seals of the strippers. How the seals are energised varies from stripper to stripper.

92.1

Conventional Stripper

The picture here shows a conventional stripper. The packer elements and liners must be changed from the top. This makes the operation difficult since the injector is mounted on top of the stripper. For both side door strippers and radial strippers, the elements are changed on the side of the stripper. On a conventional stripper, hydraulics are applied from the underside of the piston, forcing the piston upwards. The piston then pushes on the liner, which compresses the packer against the upper liner. P a g e | 131

When the packer is compressed, the hydraulic pressure can be reduced; this is because the well pressure works on the same side.

92.2

Radial Stripper

A radial stripper operates hydraulically and has a radial movement. The packer elements can also be changed with coiled tubing in the well on this stripper. This stripper is shorter than a side door stripper and uses less vertical height. Radial strippers are not well assisted in closing, in other words it is only hydraulic pressure from the pump that compresses the packer.

92.3

Side Door Stripper

Hydraulics are used to move the piston downwards to close the packer, which seals around the coiled tubing. This is the opposite of the conventional as well pressure does not assist the stripper to close A “Tubing Lubrication port” can be used to lubricate the coiled tubing, so that the friction through the packer element is reduced.

92.3.1 Changing Packers on a Side Door Stripper

93.0



Hydraulics are used to move the piston that acts on the stripping elements. Hydraulic fluid holding the packer elements in place is bled off and the piston is pumped back.



When the packer system is pumped to the “completely open” position, we pump the retracting piston to the open position. When the piston is in the open position, the side door can be opened and the packer replaced. When the new packer is in place, the operation just described can be

WCD01.04 Defective Stripping Elements

If the equipment is damaged, we must consider the impact this has or can have. If the damage is insignificant, work may continue, but if the damage is significant, the operation should be halted until parts or the entire module is replaced. When the BOP is activated, there will always be some risk of causing damage, not only to the elements but also to the rams and other parts of the BOP. It is important to inspect the parts for damage and assess the extent of damage and its consequences.

94.0

WCD01.05 Function & Position of Valves

The equipment we have looked at so far is exterior pressure control equipment. In addition to this, we also have internal equipment. With this, we are first and foremost thinking about the check valves that are installed as a part of the bottom-hole assembly. There are five different kinds that are used, namely the flapper type, ball type and dome type. Usually, two valves are used in tandem. The most common type used today is the flapper type. P a g e | 132

There are different types of these, but the principle behind them is widely the same, and the advantage is that it is possible to pump a ball or darts through the valves. The ball is used to activate equipment, for example releasing the string if it is stuck.

94.1

95.0

BOSS Release Joint



Always Locate directly below Check Valves



Pumping a 7/8” diameter ball for 2- 7/8” OD Motor-head Assembly.

WCD01.06 Adjustable and Fixed Chokes

During circulation operations or during well killing, there is often a requirement to use a choke in order to maintain correct pressure control of the well. By correct use of a choke, the wellhead pressure can be adjusted so that bottom hole pressure can be held constant. By altering the size of the choke (i.e. the size of the hole through which the fluid flows), the rate the fluid leaves the well can be controlled. Most chokes are of a right-angled design and are usually installed on the flow wing of the Xmas tree in a producing well so that the well flow can be controlled. The choke size is normally given in multiples of V64" (e.g. 128/64 inch). There are several different types of choke made and it is important that well servicing personnel understand the differences between them. The different types of choke can be broken down into two main kinds:

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

Fixed chokes



Adjustable choke.

95.1

Fixed Chokes

In a fixed choke, the orifice through which the fluid flows (the choke bean) must be removed manually and replaced with one of a different size in order to alter the choke size. This can only be done with no flow through the choke and the pressure bled off. Fixed chokes are often installed on established wells where the flow requirements to the production plant are well known.

95.2

Adjustable Chokes

In an adjustable choke, the size of the orifice through which the fluid flows can be adjusted when the choke is in service. The most common type of adjustable choke uses a tapered needle and seat.

NOTE: If a f lowing well has to be shut in with or without tools in the bore it is a good procedure to close the adjustable choke.

95.2.1 WCD01.06 Adjustable and Fixed Chokes

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The choke manifold shall, both for snubbing and coiled tubing as a minimum include two chokes, manual or remote controlled. In the case of manually operated chokes, the circulating pressure and the choke manifold pressure should be displayed on or close to the manifold. All pressure indicators gauges should be through hydraulic pressure de-boosters with remote output. The manifold should also be fitted with a connection facility for an optional pressure gauge with low increment readings. Lines and hoses between the BOP stack and the choke manifold system shall, together with their connections and valves on the high-pressure side of the choke manifold, as a minimum have the same working pressure rating as the BOP stack. All valves should be gate valves

96.0

WCD01.07 Double Barrier Protection When Changing Stripper Elements

It is important when considering changing a stripping element with coil in the hole to ensure a twobarrier facility. This is achieved by rigging up two stripping elements. The top stripping packer would be the primary while lower packer would be redundant. When necessary the lower stripping packer and the coil BOP would be shut in the event of the top stripping ram leak. 1. Stop injecting & pumping 2. Engage injector brake 3. Close the lower stripping BOP if fitted. 4. Close pipe rams and bleed off above 5. Replace packer and test 6. Equalize pressure across pipe rams 7. Open pipe rams 8. Release injector brake

97.0

WCE01.01/02/03 Test Requirements for Pressure Testing

All equipment used for operations on wells must be pressure classified and certified. Pressure testing and certification takes place at an approved workshop. It is still necessary to test the device each time it is used. This is usually considered as leak testing, even though it is often called pressure testing.

P a g e | 135

97.1

97.2

Coiled Tubing Stripper Test



Pressure Test the Stripper from Below



Pump water through the coil from the cabin until returns are seen from the top of the stripper.



Energise the stripper



Apply Test Pressure in 500 PSI Increments



Monitor Pressure in the control cabin.

Quad Ram Test



Should be performed immediately after the stripper test



With Pressure Still Applied to the stripper



Close the Pipe Rams.



Bleed off trapped Pressure above the Pipe rams thru the Kill circulation/Port



Monitor the pressures in the control cabin.

Testing of the BOP in a pressure control situation is called an inflow test. It will be done approximately as follows:

97.3





P a g e | 136



Shut-in the BOP.



Screw the stems in for mechanical protection.



Bleed off pressure above the BOP.



Stop the bleeding and check if the pressure above the BOP rises



If the pressure does not rise, the test is ok.

Check Valve Pressure Test



Pressure up through the coil and slowly bleed pressure.



Bleed of pressure from the coil back to 1000 \psi and measure the leak off rate in the control cabin.



When pressure testing the shear seal rams they are generally tested from below by pumping through the kill wing.

98.0

WCF01.01 Mechanical Barrier

Internationally it is still common to separate the barriers on surface equipment into three groups: 

Primary barriers.



Secondary barriers.



Tertiary barriers.

On surface equipment for coiled tubing operations we can briefly say that the stripper is the primary barrier, pipe ram BOP is the secondary barrier, and everything that cuts is the tertiary barrier. When we activate, the backup barrier, it is usually because the primary barrier has failed. The placement will therefore be below the stripper, but there will usually be a quick union in between. The backup barrier is often just called a BOP and is usually a ram type. In special cases it can also be an annular BOP, but this is not common. Annular BOP’s are discussed under the chapter “Primary barriers.” Coiled tubing BOP’s are usually a block type BOP. It is of course possible to use individual rams in the same way as in snubbing, but it is no longer common to do so. A block type BOP can be made for two, three or four sets of different types of rams. Common for all of these is that we arrange them so that there is a pipe ram at the bottom. This valve is our back up barrier. The quad BOP came first and was a big improvement in comparison to the single BOP’s, but it was built with the same set up as using four single BOP’s. Eventually, some combinations of these different rams were made so that it was possible to use triple and combi-BOP’s, but these rams belong under “Secondary barriers” and will be further discussed there. A pipe ram is a ram with a replaceable seal in the front. The seal can be exchanged for different sizes in order to fit the particular pipe diameter. When the backup barrier - the pipe ram - is activated, it is also common to activate the slip ram to keep the pipe fixed and prevent it from moving up or down. The slip ram is usually placed right over the pipe ram. It is most common to place the pipe ram at the bottom of the BOP, but it is possible to make changes to this when necessary. One possibility is to have the pipe ram and slip ram switch places. When the backup barrier is activated, it must be secured mechanically by screwing in the locking screw and then testing. The test is an inflow test where pressure is bled off topside and then observed for a pressure increase.

98.1

Mechanical Construction and Function

A single BOP is built up with two double-acting hydraulic cylinders that operate, i.e. slide in and out, the actual ram that is installed. There are normally double seals between the hydraulic system and well pressure. To see how far in the rams are, there will often be an indicator pin installed on the hydraulic piston.

P a g e | 137

A mechanical safety is always installed, which is the locking screw on the BOP that prevents the ram from accidentally opening after the BOP is shut-in. Ram Quad Ram Configuration:

99.0



Blind Ram



Shear Ram



Kill Port



Slip Ram



Pipe Ram

WCF01.03 Barrier Operations

It is still common to separate the barriers on surface equipment into three groups: by classifying them as Primary, secondary and tertiary barriers. On surface equipment for coiled tubing operations, we can say that the stripper is the primary barrier, pipe rams are the secondary barrier, and everything that cuts is the tertiary barrier.

100.0 Contingency Procedures All tubing that is run into the hole as work strings are exposed to large amounts of stress and wear of different kinds. This applies to drilling, coiled tubing and snubbing. The result can be holes in the tubing, deformation, and breakage. Holes in the pipe usually result from wear as a result of turbulent flows combined with particles or gas in the fluid current, or as a result of acid that has stood still and been given the chance to erode the metal on a limited area. This is called “pin hole” and is most common in coiled tubing. A “pin hole” is not easy to discover, but if it is discovered the operation must be stopped and the pipe pulled out of hole in order to repair or replace the pipe. If we are in the middle of a pump operation we must evaluate whether pumping can or must be completed. When pumping acid, the acid must be pumped out before we can pull out. If the hole that is discovered is relatively close to the stripper and there is room to run the tubing farther down so that the hole comes into the well, it is recommended that this be done if we are pumping acid or other dangerous substances. Wear from fluid flow becomes larger the smaller the pipe that we use becomes, and the larger the rate we are pumping or producing at. Prolonged pumping will also increase the risk for holes. Once a leak occurs at surface, there is basically three options:

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

Run the leak back into the well



Pull the tubing out of the well



Stop operations and repair the coiled tubing

But, the action to take depends on other factors such as: 

The position of the leak?



How severe is the leak?



Is it getting worse?



Is a corrosive/toxic fluid being pumped?



Will stopping the pump collapse the tubing?

So, there are several possible actions to every complication.

When a complication develops, the main objectives are: 

To protect the crew



To control the well



To protect the equipment

This typically means that the well must be shut back in and in many cases, the well killed. Problems developing during a coiled tubing operation can be categorized:

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

Pumps



Lines/manifolds



Coiled tubing at surface



Coiled tubing in the well



Injector



Reel



BOP/wellhead and riser equipment



Power packs



Controls

101.0 WCG01.01 Power Pack Failures Actions to be performed:  Apply reel brake. Secure with chains.  Close the slip and pipe rams. Lock rams manually.  Monitor differential pressure and pump slowly if required.  Operation is now temporarily controlled enabling options to be considered for further action.

102.0 WCG01.02 Pump Unit Failure Actions to be performed:

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

Change over to backup pump system, if available.



If no backup pump available, close the inlet valve on the reel.



Pull CT out of hole (if major repair required), monitoring the CT-tubing annulus pressure.



Consider cutting pipe with shear ram rather than risk collapsed pipe and hydrocarbon lea



Operation is now temporarily controlled enabling options to be considered for further action

103.0 WCG01.03 Stripping Element Failure The Stripper/packer should be energized sufficiently with hydraulic pressure, so that it will contain any well bore fluids, but not restrict the running of the coiled tubing. Should the element start leaking and it cannot be energized to stem the leak, the following should be implemented:



Stop the Coiled tubing



Close the pipe rams



Energize the back-up stripper if fitted



Inform the company representative



Bleed down the pressure



Inflow test.



Change the stripping Elements

104.0 WCG01.04 Leak Between the Top of Tree & Stripper While the coiled tubing is in the well under pressure and a leak occurs between the tree and the Stripper. Actions to take

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

Stop the coiled tubing



Inform the company representative



Depending on the severity of the leak, a decision should be taken as to close the shear seal.

105.0 WCG01.05 Surface Pin Hole Leak in CT The correct action to take will in part depend on the fluid medium in the coiled tubing water or corrosive fluid such as acid.

105.1 Pin Hole Water Leak Actions to take The tubing develops a leak at the surface. In this situation, the procedure is quite simple: 

Stop the coiled tubing



Inform the company representative



Wait for the pressure in the tubing to bleed down



If the pressure drops and the check valves are holding



POOH spooling the pinhole onto the reel

105.2 Pin Hole Corrosive Fluid Leak Actions to take The tubing develops a leak at the surface. In this situation, the procedure is quite simple:

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

Stop the coiled tubing



Inform the company representative



Run the leak back into the pressure control below the stripper



Do a risk assessment to plan the way forward

106.0 WCG01.06 The correct action to take if there is a leak in the tubing below the coil.

107.0 WCG01.07 General Muster Alarm The Well Service Supervisor and individuals listed on the Exception list shall remain at the unit to ensure the well is secure during the emergency. All other personnel shall report according to muster plan.

The Control Room shall be updated with well status and how many people are at the location. Listen to PA announcements and act accordingly. 

Stop the Coil tubing



Stop pumping fluids



Close the tubing rams



Close the slip rams



Await further instructions



A decision should be made to close the shear/seal on top of the wellhead

If evacuating: Close shear seal BOP and allow pipe to drop. Close Tree and DHSV. Close manual locks on shear seal if safe to do so.

108.0 WCG01.08 Collapsed Tubing The tubing collapses downhole. Depending on the position of the collapsed tubing the fluid in the coil and if the pump pressure has gone up or down the procedure may change.

108.1 Tubing Ruptures The tubing ruptures as it comes over the gooseneck and separates. Initially this can be a potentially hazardous, and serious situation. The seriousness is dependent on the tubing's internal pressure, the wellhead pressure, and the type of medium within the tubing:

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

Stop the coiled tubing.



Inform the company representative.



Let the pressure in the tubing bleed down



If the pressure drops and the check valves are holding.



Pull rupture to deck level and splice tubing.



If it appears that, the check valves are not holding.



The shear seal should be closed and the well secured.



Prepare to fish coiled tubing.

108.2 Tubing Collapsed

Stop the coil tubing if it has not already stopped due to weight restriction (tubing may not pass stripper) 

Try and keep tubing full if possible.



Inform company man



Establish where collapse has occurred if possible.



There will be a need to consider killing the well.



Once well is dead try and pull coil through stripper, if tubing will not pass stripper.



At this point, it maybe decided to close shear seal on top of wellhead and fish coil.



It may be necessary to take stripper rubbers and brass out of stripper to allow tubing to pass.

Shutting in and testing of the BOP will primarily be used if there is a leak in the equipment above that BOP or when fishing coiled tubing or wireline. Generally if an alarm or emergency situations, arise, we will first and foremost prioritize pulling out of the hole and optionally preparing for cutting the coiled tubing so that the Xmas tree, and if necessary the subsurface safety valve, can be closed safely.

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Part 4 Snubbing

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Table of Contents 109.0 Snubbing Equipment ..................................................................................................... 147 110.0 WSA 02.01 Snubbing Blow Out Preventers ..................................................................... 150 111.0 WSA 02.02 Worn Elastomers/Temporary Suspension .................................................... 153 112.0 WSA02.03 Blind Shear (Safety Head) ............................................................................. 155 113.0 WSA 02.04 PCE Equipment Rig UP ................................................................................. 155 114.0 WSA 04.02 BOP Pressure Rating & Installation ............................................................... 156 115.0 WSA 04.03 Ram Equipment Change ............................................................................... 157 116.0 WSA04.04L BOP Element Change................................................................................... 157 117.0 WSA 04.05 Assess Damage to PCE.................................................................................. 160 118.0 WSA 04.06 Non Shearables ............................................................................................ 160 119.0 WSA 05.02 Installation and Operation of Sealing Elements ............................................ 161 120.0 WSA 05.03 Defects During Element Change that could Effect Function ........................... 161 121.0 WSA 05.04 Double Barrier Philosophy ........................................................................... 162 122.0 WSA 06.01 Function, Positioning and use of Valves/Plugs .............................................. 162 123.0 WSA 06.03 Alternative Well Control Devices .................................................................. 165 124.0 WSA 06.04 Fixed and Adjustable Chokes........................................................................ 165 125.0 WSD 01.01 Rig-Up Preparation and Checks .................................................................... 168 126.0 WSD 01.02 Adaptor, Connector and Flange Compatibility .............................................. 168 127.0 WSE 01.01 Requirements for Pressure Testing ............................................................... 169 128.0 WSE 01.02 Correct Test Procedures ............................................................................... 169 129.0 WSE 01.03 Pressure Test with Tubulars in Place ............................................................. 170 130.0 WSF 01.01 Mechanical Barriers...................................................................................... 170 131.0 WSF 01.03 Principle of Grouping Barriers ....................................................................... 170 132.0 WSG 01.01 Power Unit or Hydraulic Failure ................................................................... 171 133.0 WSG 01.02 Slip Bowl failure........................................................................................... 171 134.0 WSG01.03 Annular Element Failure ............................................................................... 172 135.0 WSG 01.04 Uncontrollable External Leak in BOP Stack ................................................... 172 136.0 WSG 01.05 Leak in Workstring ....................................................................................... 172 137.0 WSG 01.06 Stripping BOP Failure ................................................................................... 172 138.0 WSG 01.07 Consequences of String Washout ................................................................. 173 139.0 WSH 01.01 Well Shut-In With or Without Tubing in the Hole ......................................... 173 140.0 WSI 01.01 Calculate Pipe Forces .................................................................................... 174

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109.0 Snubbing Equipment 109.1

Hydraulic Jack

The jack is an assembly of hydraulic cylinders and slip bowls that enable pipe to be moved in or out of the well. The workbasket is located at the top of the assembly. The power tong arm, tongs, gin pole and counterbalance winch are attached to the workbasket. The travelling head that carries slip bowls and the rotary is located on the top cylinders. The hydraulic circuits can be set up to provide different speeds and power levels for the travelling head. The hydraulic fluid can be directed into all 4 cylinders or into only. On some units, it is possible to select which two opposing legs whereas on others, there is no choice. This is called 4-leg and 2-leg operation. It is also possible to select whether the hydraulic fluid being returned from the un-pressurised side of the cylinders is directed back to the tank or added to the fluid going to do the work in the pressurised side. This is called regeneration and is equivalent to high and low gearing. There are 4 operating modes:-



2 leg high (with regeneration) Fastest but lowest power



2 leg low



4 leg high (with regeneration)



4 leg low Slowest with highest power

It is normal to start the job in 2 legs high and, as the pipe weight increases, change into the other modes as required. It is a very simple job of turning a valve or two in the one mode to The stroke of a jack depends on the make, but most in the North Sea have a 10 ft. working stroke. 109.2

Tubing Guides

The higher the well pressure, the greater the force pushing up on the pipe being snubbed into or out of the well. Since the pipe coming up through the window and the jack is only restrained at a distance from the stripper bowl, there is a problem with potential buckling of the pipe out of the side of the window or jack. For this reason, in higher-pressure wells, guide tubes are placed in the window and in the jack. These restrain the pipe and stop it being buckled out of the side. The guide tubes can be easily inserted or removed and the one through the jack is in two pieces. One piece is sitting in the jack, hanging from a level with the top of the legs, and the other (inner) piece is hanging from the travelling head and sliding up and down inside the lower section.

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109.3

Access Window (Work Window)

The window is a large heavily constructed item consisting of two plates with solid steel legs spacing them apart. There are usually 4 legs and a window is always rated to the full load capacity of the unit. Traditionally 4 ft., 6 ft., 10 ft. or occasionally 15 ft. long, the window are used to enable large OD items of BHA, completions, etc. to be run or pulled without having to pass them through the slightly restricted ID of the slip bowls. With a hole through the top and bottom plates of usually 111/16 inch or 135/8 inch, they are bolted directly to the top of the stripper rubber and the jack is bolted to the top of the window. If rigged up on a Xmas tree and using a small diameter washout string, a window may not be required. For many jobs, such as running completions they are a much safer option than working a large OD component down through the slip bowls, having first split them open. Some windows are equipped with a beam at the top to enable a torque turn equipped back up tong to be hung in the window for making up the completion assemblies 109.4

Slips

The slips are attached to the travelling head and consist of one bowl for pipe heavy and one bowl for pipe light. Almost always hydraulically operated, the two bowls are the same with the pipe light bowl facing down. Similarly, the stationary slips are attached near the bottom of the jack, but do not move. In high-pressure wells, it is normal to use an extra set of stationary snubbers for safety. The slips are always used in pairs, they cannot be mixed: 

Pipe Heavy = Stationary and traveling heavies



Pipe Light = Stationary and travelling snubbers

109.5

Slip Operating Sequence

109.6

Rotary Table

The rotary table is attached to the travelling head making it possible to rotate the pipe while moving in or out of the well. Most rotary capacities are about 6000 ft-lb. maximum. This is usually more than a work string tool joint can safely take. Because the rotary is on top of the head, it can be a maximum of 10 to 12 ft. above the top of the cylinders at full stroke. Therefore, current rotary capacities are about the maximum that the design can achieve. Much higher capacity rotary's' are now installed in the windows of the latest North Sea short stroke units. This however greatly reduces the capacity to rotate whilst running in/pulling out

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109.7

Workbasket

The workbasket is attached to the top of the jack and provides the workstation for the crew to operate the controls for all the snubbing unit functions. A standpipe is attached up the outside of the unit and terminates at this level. A circulating hose and swivel with a connection to the pipe being run is attached to the standpipe. By attaching the circulating hose to a joint of pipe either in the hole or about to be run in the hole, it is possible to circulate whilst pulling up a joint of pipe or running it. There are two weight indicators at the operators console, one for heavy pipe and one for light pipe. These weight indicators read the hydraulic pressure in the jack circuits and so do not show any readings when the weight of the pipe is in the stationary slips. 109.8

Counterbalance

The winches for raising and lowering pipe are called counterbalance winches because they are hydraulically balanced to hold the weight of any particular object being lifted. With an individual load rating of between 1500 lbs. and 2000 lbs. usually, they are controlled from the BOP console by means of a separate hydraulic valve. Through this system, the force applied to each hydraulic winch is controlled so that when it is enough to just lift the joint of pipe, the remaining hydraulic fluid diverting back to tank. A good operator can set the valve such that the joint of pipe will be stationary, with the pin end in his hand, but he is able to raise or lower it by as much as he wants just by pulling up or pushing down on the joint with his hand.

109.9

Powerpack

Most power packs are powered by diesel engines driving multiple hydraulic pumps. All functions of the unit are supplied from the one power pack. The primary power for the BOP control panel is from this main power pack. The surface equipment can be shut in in the event of a power pack failure by using suitably sized accumulators, to close – open – close all the BOPs in the rig up.

109.10

Power Tongs

Tongs are normal hung from the tong arm attached to the side of the workbasket. If small tubing is being run through an existing completion, the tongs will be powered from the main power pack. Some units have the ability to hang tongs in the window for making up completion assemblies. 109.11 Other Equipment All snubbing units have the facility for using hand operated slips on the base plate of the window. These are used when it is necessary to 'hang' the pipe below the slip bowls so that both bowls can be opened or the pipe broken out or made up in the window e.g. when making up large OD items of BHA, completion assemblies, changing stripper rubbers, etc. P a g e | 149

On some units, it is common practice to rig up a hanger flange in the stack just below the stripper bowl or sometimes the annular and is used for exactly the same purpose as the hand slip bowl. It is much slower in use as it requires each of the dogs to be screwed in by hand. It can be very useful when shutting down for the night on a 12 hr/day operation if there is a worry about the pipe moving through the slip bowls when the unit is unattended. Care must always be taken with a small hanger flange to ensure that the forces acting on the pipe can be held by the dogs. In a small hanger flange, there might only be 4 or 6 dogs. Because of the nature of the pipe upsets and the BOP's, it is not normal practice for a snubbing unit to hang the pipe in the BOP's. Also, a large proportion of a job can be spent with either negative weight or limited positive weight in the string.

110.0 WSA 02.01 Snubbing Blow Out Preventers 110.1 Stripper Bowl

The stripper rubber is located in the stripper bowl and is used as a pack-off during stripping operations with most pipe, except collared pipe and is used to avoid ram-to-ram stripping. The stripper bowl is located below the access window and is used for the following:

Primary well control with low wellhead pressure work (the primary barrier)



Pipe cleaning when pulling out



Prevents debris from dropping into the wellbore during tripping

Stripper bowls are available with single and dual elements. Dual element bowls are rare. They are rated to an absolute maximum of 3000 psi. in practice the stripper rubber cannot be relied on as the primary well containment device at pressures above 2500 psi. The use of the stripper bowl allows for the continuous handling of pipe with a tapered upset or no upset. It is normal to have to change the stripper rubber(s) during a job. Wear on the rubbers is affected by 

Wellhead pressure



Lubrication at the rubber



External pipe roughness

It is normal practice when using stripping rams also to use a stripper bowl to provide

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

Barrier for egress of hydrocarbons



Primary barrier for HWO (2500 psi or less )



Pipe wiper



Debris barrier

110.2 Annular BOP

The annular (bag) is also a stripping device and is capable of sealing around any shape and size of pipe. If deploying a long BHA's with varying diameters, it may not be possible to operate the stripper rubber or stripper rams due to the lack of distance between the wellhead and the strippers. In this situation, use of an annular BOP may be required. The annular BOP is identical to a standard BOP used in drilling operations although normally of a smaller size. A typical BOP would be a Shaffer or Cameron 11" 10M or 71/i6 inch 10M. The pressure rating is specified according to the wellhead pressure. The annular BOP is used when normal ram-type BOP's cannot seal around a large diameter, such as a side pocket mandrel, blast joint etc. slip joint. The Annular is a secondary barrier. There are many different makes and types and it should be noted that not all will close and seal on open hole. When stripping a BHA through an annular BOP it is necessary to have a BHA schematic and to monitor the operating pressure. During snubbing operations, it is normal practice to have a 1 gal accumulator in the closing line hydraulic circuit to allow tool joints to be stripped through the annular, maintaining a steady hydraulic pressure on the closing line and preventing it from over- pressurizing.

110.3 Stripping Rams Stripping rams allow for controlled movement of tubulars in wells with surface pressure. By means of alternately opening and closing the two stripping rams, tool joints can be stripped in and out of the hole while maintaining full control of the annulus.

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Stripping BOP's are standard ram-type BOP's as used in drilling operations with special elements to enable them to seal on moving pipe. A typical BOP stack for snubbing operations might be anything from 2.9/16" 20000 psi. to 13.5/8" 5000 psi. As with all ram type BOP's, they are designed to hold pressure from below only and the pressure across the inner seals must be equalized before attempting to open them. A ram type BOP may be dressed as a stripping BOP or as a pipe ram (safety ram). They can also be dressed with variable rams, slip rams, blind rams or shear rams for continuous stripping.

110.4 Stripping Ram Seals These BOPS is the primary well control barriers when wellhead pressure is above 2500 to 3000 psi. The pressure rating and size are determined by the wellhead pressure and work to be undertaken. They are always used in pairs to enable a tool joint to be "worked" through while still retaining a seal around the pipe. It is normal practice to have to change stripping ram inner seals with their inserts during the course of a job. The life of the inserts is affected by:

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

Pipe external condition



Well pressure



Speed of running of the pipe

110.5 Safety Ram These are normal drilling type rams that can be dressed as slip rams or variable bore rams. It is necessary to have one BOP in the stack dressed for each size of pipe in use. For jobs involving tapered strings of pipe, pulling very long fish, etc., two or more safeties will be required. Often called the safety BOP's(safeties), they are normally only used when changing elements in the stripping rams, annular or stripper bowl, or when the pipe is stationary for a period of time. The safeties are normally placed in the stack immediately below the stripping rams. Safeties are secondary barriers and shears are tertiary barriers. The purpose of the safety ram is to maintain well control in the event of failure of or maintenance to the primary closing device. Safety rams are not designed for stripping through.

111.0 WSA 02.02 Worn Elastomers/Temporary Suspension During snubbing operations, the elastomers on the primary barriers, stripper bowl, annular and or stripper rams will get worn and will need to be replaced regularly. The well is secured with the safety rams providing barrier protection and pressure bleed down above and then the barriers are inflow tested prior to changing out the elastomers. 111.1 Blind Shear Ram The blind/shear rams are designed to shear the work string and maintain a seal. Blind/shear rams are not designed to cut the bottom hole assembly. Where separate blind and shear rams are used, the choice of where to place them is often dictated by well conditions or operator preference. For many snubbing jobs, the shear is placed below the blind since the pipe may well be trying to push out of the well bore at the time it is required to be cut. Conventional shear rams may not always cut the work-string completely (for example if it is required to cut a BHA with a fish inside) and it may be necessary to RIH one or two joints before operating normal shear rams. 111.2 Annular Seal Change

In the case of a leaking annular, it would be necessary to pull back out of the hole, close the blind rams and rig the jack off the well before being able to open the bonnet of the annular. The annular should always start a new job with a fresh rubber and it is indeed a rare occurrence to have to change it during a job. If an annular rubber had to be changed during a job, it would be normal practice to come out of the hole, if possible, rather than open the annular with pipe in the hole.

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This is a routine operation but opens up the topmost containment device.



Close the annular and lower stripping ram and check they are holding



Unscrew the retaining nut and pull out the rubber(s) with a tool joint



Hang off the pipe and close the safety ram



Bleed off below the annular through the bleed-off line



Break the joint in the window



Install the new rubber by placing it on the box and screwing in the pin



Make up the joint and take the weight of the string



Open the safety ram and run in to seat the rubber



Tighten the retaining nut



Open the BOP's and RIH

111.4 Stripping Ram Insert Change This can be considered as being in one of two categories: 

BOP elements changed out as normal routine due to wear



Leaks around elements occurring unexpectedly

In the case of routine replacement due to wear (the stripping rams are susceptible to this), the inner seals can be changed by closing the safety rams, bleeding off above them and opening the stripping ram bonnets to change the inner seals. It would be normal practice to change the seals in both sets of stripping BOP's at the same time. In the case of unexpected leaks, all the BOP's above the safeties can be repaired by closing the safeties, checking they are holding and then working on the stack. If possible, it is good practice to have two barriers by closing two BOPS' below the one that must be worked on.

111.5 Temporary Shutdown On some jobs, only 12-hour operations are planned and the routine at night is usually as follows:

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

Install closed stabbing valve having filled tubing



Close safety rams and manually lock



Tighten dogs on hanger flange

112.0 WSA02.03 Blind Shear (Safety Head) The safety head will cut the work-string /BHA and maintain a seal. It is a tertiary barrier. The shear/seal is flanged as close to the xmas tree as possible to ensure that the work-string falls below the tree after it has been cut. Shear/Seal BOP's (Safety heads) are used on jobs where it is necessary to cut more than just the work string. Most shear/blind or shear rams will only cut the work-string and not BHA, fish, wire, etc. Shear Seal BOP's have extra-large hydraulic cylinders and pistons to give a greater force to the cutting action. Like a shear/blind, they will seal off the hole after cutting. They are usually standard BOP's with different bonnet assemblies to give greater hydraulic force.

113.0 WSA 02.04 PCE Equipment Rig UP

Applications of a snubbing Unit 

Sand washing



Well unloading



Fishing



Washing perforations or Acidising



Cementing



Running and pulling tubing strings/re-completing



Drilling or milling

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Snubbing units are very portable, can perform just about any activity, and can rig up/down in a fraction of the time it takes a conventional rig or workover unit. Most work over units work on dead - no pressure wells. Snubbing units can perform operations on both “dead” and “live” wells.

113.1 Snubbing Is performed on a live well and uses B.O.P. and other mechanical devices as its means of well control. 

Annular BOP



Upper/Lower Stripping BOP



Pipe BOP/Safety



Shear/Seal BOP



Safety Head

113.2 Hydraulic Workover Is performed on a live well and uses B.O.P. and other mechanical devices as its means of well control. 

Annular BOP



Upper/Lower Stripping BOP



Pipe BOP/Safety



Shear/Seal BOP



Safety Head

114.0 WSA 04.02 BOP Pressure Rating & Installation A ram type BOP is constructed so that if it is closed and sealing, it is possible to bleed off pressure above it, well pressure will act on an area of the ram and assist the closing force. This will be the case for all pipe rams, pipe/slip rams, blind rams and shear/blind and shear/seal rams as described under “Secondary barriers”.

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115.0 WSA 04.03 Ram Equipment Change As snubbing operations are conducted with tubulars that are screwed together, therefore it is possible to have more than one external diameters of work string. In theory, you can do this as often as you like, as long as you have the correct equipment on the rig up. If you are going to run a tapered string then it is good practice to have more than one safety BOP in the rig up, at least one for each size diameter pipe that is to be run in the hole, as a back up to the primary barrier. In practice, this is quite labor intensive because it requires changing the ram on the stripper ram BOP’s for each new diameter. Therefore, it is only under special circumstances that this is done. An example can be using small ID tubulars at the bottom of the work string to get through a restriction in the well. We call this running a tapered string.

116.0 WSA04.04L BOP Element Change

116.1 Seals and Sealing Elements The stripper element is composed of a rubber mixture that can have many different reinforcements embedded into it. The most common is a reinforcement ring of brass on top to prevent the element from being pushed out of the house. It can also have a reinforcement downwards in the sleeve in order to balance wear on the equipment. A stripper bowl is not equipped with any form of hydraulic connection or a closing piston. It is the P a g e | 157

well pressure that pushes the packers together around the pipe and seals. The stripper bowl is therefore considered to be closed by well assistance, and it is the only one that is solely closed by well pressure. The stripper bowl on a snubbing rig always sits on top of the pressure control equipment. A stripper bowl consists of a housing and a mounted seal packer- the actual stripper element. The stripper element is not split and it is pushed into the house with a large amount of force with the help of the snubbing jack. Afterwards, the top flange is mounted on the housing. A requirement for being able to use the stripper is that there is no pressure higher than 3000 psi (210 bar). Another requirement for being able to use the stripper is that the snubbing string does not have 90-degree shoulders on joints. Time wise, it is an advantage to use the stripper bowl instead of stripping with the stripper ram BOP’s. Therefore, it pays off to make this possible. One can often reduce the pressure in the well by pumping in a heavy fluid on the top, and you can choose a work string with regular, bevelled edges on the joints.

116.2 Annular BOP An annular BOP can be used to strip in shorter lengths with varying outside diameters where a stripper cannot be used. Or, it can be installed as an extra safety precaution if this is desirable, in which case it will be defined as a secondary barrier. An annular BOP is not applied to common stripping, as it is expensive and complicated. As mentioned, the annular BOP is primarily used to strip in the bottomhole assembly and any components with a dimension than differs from that of the snubbing string it is used with.

There are several brands of annular BOP’s. In principle, the same equipment is used in both drilling, coiled tubing and snubbing, but the dimensions will vary. The smaller dimensions will generally be able to shut-in on open hole - in other words, where there is no pipe through the valve- but it will usually not withstand very high pressures. Larger dimensions cannot close on open hole.

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Annular BOP’s are also commonly called annular preventers.

116.3 Stripper Ram BOP If the pressure is higher than 3000 psi, or there are other reasons why we cannot use a stripper bowl to seal tightly around the work string, we use a stripper ram BOP. A stripper ram BOP is in principle a conventional BOP as described in the section “Mechanical construction and function”, but it is used here as a seal around a pipe which is in motion. Naturally, this causes great wear on seals, as well as a greater probability that a leak will eventually occur. To compensate for this there is usually a separate, renewable wear element that seals around the work string. To replace the worn items the well must be isolated with a regular safety BOP that is located below. It is inflow tested and the string is secured against movement before the stripper ram is open to replace the element. When stripping with a stripper ram we must use two BOP’s that alternate sealing tightly around the pipe. The point of this is that we cannot strip the tool joints through the BOP; but instead have to bleed them through equalizing loop. We call this stripping ram to ram. Ram to ram stripping requires that we have the ability to quickly allow pressure in between the BOP’s to equalize pressure, and to bleed off the same pressure afterwards.

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The following is how this is performed when running into the well:



The tool joint is run down to the lower stripper.



The upper stripper is closed.



Pressure is released and equalizes over the lower stripper.



The lower stripper is opened.



The tool joint is run through the lower stripper.



The lower stripper is closed.



The pressure is bled off between the upper and lower stripper.



The upper stripper is opened.

In order for the stripping operation to go quickly and efficiently, it is controlled from the work basket. This assumes that there are hydraulically operated valves for the pressure equalization loop and bleed off line. There will also be installed choke valves with fixed sized orifices, as well as manual valves as “back up” to the hydraulic ones. A stripper ram BOP is, like other ram type BOP’s, well pressure assisted.

117.0 WSA 04.05 Assess Damage to PCE

When the BOP’s are activated, there will always be some risk of causing damage, not only the elements but also the control systems and other parts of the BOP. It is important to inspect the parts for damage and assess the extent of damage and its consequences. 

Slack or oversized



Cuts, wounds or cracked rubber



Flattened or worn surfaces

118.0 WSA 04.06 Non Shearables

When running non-shearable items, there shall be minimum one pipe ram or annular preventer able to seal the actual size of the non-shearable item. Other activities should be coordinated in order to minimize the overall risk level on the installation while running non- shearable items through the BOP.

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119.0 WSA 05.02 Installation and Operation of Sealing Elements We will now look at a single BOP and show how it is constructed. A single BOP is built up with two double-acting hydraulic cylinders, which operate, i.e. slide out and in, the respective ram that is mounted. There are usually double seals between the hydraulic system and the well pressure. Between these there is a weep hole to the atmosphere, so that if one of the seals fails this can be observed. We can see which seal is leaking by the fluid type. To see how far in the rams are, there will often be an indicator rod mounted on the hydraulic piston. There is always a mechanical protection mounted, the locking stem on the BOP. These are screwed in by hand or hydraulically operated and prevents the ram and piston from being moved towards the open position after the BOP is closed. If mud is seen coming from the weep hole it means that the primary ram piston shaft seal is leaking. If hydraulic fluid is leaking from the hole, it means that the hydraulic chamber seals are leaking. The procedure for this is to shut down the operation replace the seals and retest.

120.0 WSA 05.03 Defects during Element Change that could Effect Function When the BOP’s are activated, there will always be some risk of causing damage, not only the elements but also the control systems and other parts of the BOP. It is important to inspect the parts for damage and assess the extent of damage and its consequences. 

Cracked or damaged seal elements



Explosive decompression



Temperatures



Deformed Seals



Suitable for service

There are three reasons why BOP ram elements in BOP’s are replaced. The first is if there is a change in the dimension of the pipe being run from one “round” to the next. The second reason for changing is general wear. It is common to say that one can use the elements until there is 80% of the rubber remaining in comparison to a new element. If the wear is greater, the elements are replaced. The third reason for replacing the elements is damage to the rubber. This can occur if, for example, the BOP is closed around a tool or tool string with sharp edges. It may also be the result of a gas leak, which cuts tracks in the rubber, or gas bubbles penetrating into the rubber.

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121.0 WSA 05.04 Double Barrier Philosophy The philosophy of maintaining a double barrier when changing the annular element during intervention In the case of a leaking annular, it would be necessary to pull out of the hole, close the blind rams and rig the jack off the well before being able to open the bonnet of the annular. The annular should always start a new job with a fresh rubber and it is indeed a rare occurrence to have to change it during a job. Close both the safety BOPs and inflow test remove the annular flange, change the element.

122.0 WSA 06.01 Function, Positioning and use of Valves/Plugs There are two main types of downhole barriers that are commonly used:

Back Pressure Valves



Pump down plug and landing nipple

122.1 Back Pressure Valves

Since the pipe is open at all times to surface, two check valves or backpressure valves (BPV's) are always placed at the bottom of the string, above the BHA. They allow fluid to be pumped down the string but stop flow up the pipe when pumping is stopped. Both ball and seat check valves and flapper valves are used. Flapper type check valves have the advantage of allowing balls to be pumped through them for operating tools in the BHA. Since the flow, area through these valves is fairly small, if there is any scale in the tubing it is quite easy for debris to plug them off. Two operations should be performed to minimise the risk of this happening. 

Tubing is to be inspected and rattled immediately prior to going out.



When filling up the string, pump one or two barrels through the valves every 10 or 20 joints to prevent the collapse of the pipe.

This is to ensure they are still open and to clear out any build¬-up of debris. The check valves are the primary internal barriers. In jobs, involving large amounts of pumping it is not uncommon for both backpressure valves (BPV's) to be washed out. A small wireline type-landing nipple is always placed above the BPV's so that in the event of a leakage through the BPV's, a plug can be seated in the nipple prior to pulling out with the pipe. It is normal to pump the pipe full of water prior to pumping the plug so as to minimise pollution from hydrocarbons or corrosive brines.

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122.2 Pump Down Plug and Nipple

A very wide variety of BHA devices can be used as a means of internal primary well control including: 

Pump out plugs or pump out BPV's



Sliding Side Doors or Sliding Sleeves coupled with positive plugs. This is mostly to allow reverse circulation.

122.3 Gray Valves

This wide variety of devices can allow tools to be operated in the BHA by dropping balls (including release joints) and allows the string to be run-in in the normal manner with twin BPV's, later converted to reverse circulate. After reversing, it is necessary to re-install a device to allow the string to be pulled out with full internal well control. As well as these items on the bottom of the string, full opening safety valves (TIW valves), inside BOP's or stabbing valves must always be available encase.

122.4 Snubbing Back Pressure Valves (BPVs)

The BPV's are primary internal barriers and prevent hydrocarbons from entering the work-string and to maintain pressure control. There are usually two in series. Which are flappers to enable balls and darts to be pumped through them. Check valves are located at the top of the bottom-hole assembly. It is common to use two check valves in sequence, but this is considered to be one barrier element, as we have no control over them individually. The BHA depends on what kind of operation is to be done, and can have for example circulation equipment, motors and bits. There are several types of check valves that can be used to establish a barrier. The dome type is no longer commonly used, not because it works particularly badly but because today there are better options. The ball valve is less susceptible to wear and plugging and is therefore still commonly used if you only take into account the need to establish a barrier. The flapper type of valve is not better than a ball valve when it comes to sealing, but it has the large advantage that it is possible to pump balls and darts through it. These are used to operate equipment located below the valves in the bottom-hole assembly.

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122.5 Nipple Profile

A nipple profile is installed in the BHA above the BPV's and is a secondary internal barrier after a plug has been set to maintain pressure control if the BPV's fail. As well as these items on the bottom of the string, full opening safety valves (TIW valves), inside BOP's or stabbing valves must always be available in the workbasket. These can be used in the event of a tubing/BHA break or leak in the tubing string to immediately close off any flow from the well.

122.6 Stabbing Valve The stabbing valve is normally a plug valve with a tubing thread connection below and a 2" Weco threaded connection for pumping above.

Advantages: 

Light



Easy to stab onto flowing pipe



Inbuilt pumping connection Disadvantages:



Small through bore



Wireline cannot be used through it

122.7 Full Opening Safety Valve The full opening safety valve is much bigger than a stabbing valve

Advantages: 

Larger bore



Easy to stab onto flowing pipe



Allows wireline to be rigged up on top of valve

Disadvantages: 

Heavy



Requires additional X-over for top connection for pumping

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122.8 Inside BOP The inside BOP was originally designed for stripping operations on a rig floor and has pipe connections at both ends.

Advantages: 

Can be RIH

Disadvantages: 

Heavy



Very difficult to stab onto flowing pipe

122.9 Back Pressure Valves

123.0 WSA 06.03 Alternative Well Control Devices The need for and use of alternative and additional internal well control devices in snubbing operations

E is special configuration when using a pump out check valve for operational reasons. Due to the check valve, being expendable by pumping down a dropped ball another check valve cannot be installed above it. For this reason, primary internal well control is only single check valve. If expended the secondary well control system is a wireline check valve installed in the landing nipple.

124.0 WSA 06.04 Fixed and Adjustable Chokes The principles of adjustable and fixed chokes, when they should be used and their function. Level of Importance L3.3/L4.5 P a g e | 165

Generally, the intention is to circulate fluid in the well when performing snubbing operations. Therefore, a temporary system of pipes must be rigged up on the surface. This system must be dimensioned for the amount of fluid to be circulated and the pressures that they will be exposed to, and also be made of the correct type of steel. For the system to work as intended, both shut-in valves and choke valves must be rigged up in connection to the pipes. After the choke valves, the liquid flow must be able to be directed to either the burners or the test separator on board. To ensure safety, lines must also be rigged up to the BOP so that it can be circulated and killed after any cutting of the snubbing string.

The choke can be of different types, but the traditional type is an adjustable “cone and seat” valve. This kind of valve becomes worn out, and it is therefore often necessary to replace the worn parts during an operation. This can be arranged by using two valves that are rigged on two parallel lines so that we can switch between them. Fixed size chokes are used for bleeding pressure; adjustable chokes are used to control pressure or flow. The requirements for pumping and circulating facilities are different for each job, but all operations require some form of pump to conduct the following type of operation:



A complete mixing and killing facility on an offshore satellite.



A hook up on an offshore platform direct to existing facilities.



A remote land job requiring basic pressure testing and pumping facilities only.



On the choke, kill and bleed off lines the main pressure control is via hydraulically operated valves controlled from the workbasket, with a manual valve as a backup to each. The manual valve must be on the inboard side of the hydraulic valve and remains unused in the open position throughout the job. It is only required when work needs to be done on the hydraulic valve.



The kill line is connected to the kill wing of the tree.



On some dead well operations, trip tank and fill-up line connections are made up to the top of the stack below the window for use while tripping.



For all snubbing jobs, a fluid pump (usually a cement or frac pump) is required.



Pressure testing,



Filling the pipe.



Displacing the pipe before pulling out to remove hydrocarbons and brines (which can be dangerous for the crew).



Through tubing pumping operations.



Well kill

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124.1 Operations Snubbing is performed on live wells and uses BOP's and other mechanical devices for well control. In this respect, the principles are exactly the same as with Coiled Tubing. A typical scenario might be as follows: The unit is rigged up on a large offshore platform beside a derrick doing a normal workover. It is required to wash out scale in the perforations and rat hole. The SIWHP prior to the well scaling up was 2850 psi. The unit has been rigged up on top of the Xmas tree with, (from bottom to top) 1 blind/shear ram, 1 pipe ram, 2 stripping rams, 1 annular BOP and a single element stripper bowl. The riser between the Xmas tree and the BOP's is long enough to accommodate the BHA comprising a mill/under reamer/mud motors and BPV's. The choke and kill lines are connected to the rig circulating system and cement pump via a choke manifold. Whilst running in with the clean out string, the wellhead pressure is low enough to use the stripper bowl. The two BPV's in the work-string prevent flow back up through the tubing. Once below the tailpipe, the rig cement pump is used for circulation, under reaming down with returns taken to a degasser and separator before returning to the pits. Well control is initially achieved by use of the annular and stripper bowl with the stripping BOP's and stripper rubber being used when the rat-hole is reached. Having finished washing out, it is discovered that the BPV's are both leaking so the pump down plug is dropped and seated. With full wellhead pressure restored, the pipe is pulled using the stripping rams for well control. The BOP's are controlled from the workbasket, a set on the BOP skid and a third remote panel has also been set up beside the rig remote panel due to the concurrent nature of the work. Due to the comparative complexity of the equipment and the requirement for an in-depth knowledge of the operation of the equipment on a live well, it is normal practise to have a snubbing supervisor (the equivalent of a tool pusher) on each snubbing crew. It is his responsibility to ensure the safe and correct procedures are followed at all times and particularly when using stripping BOP is, crossing the balance point, etc. After the unit is rigged up on the well, all features are function tested. The stack is then pressure tested including all connections, lines, valves and manifolds. To test the rams it is necessary to pick up one or more joints of pipe and run them into the stack so that the BOP's etc. can be tested. These joints will have the check valves (BPV's) on the bottom, which also tests the BPV's, and must be restrained from being pumped back out of the well as there will be considerable force generated beneath the closed check valves.

124.2 Opening the Well Introducing the tool string into the wellhead is one of the most delicate phases of a snubbing operation. It is at this time that the string is at its lightest and upward forces are trying to eject or buckle the pipe. P a g e | 167

Great care must be taken to ensure that the inverted, or snubbing, slips have taken a proper "bite" on the pipe, with the use of a clamp or dog collar below the slips is often required. When introducing the pipe into the well, the stripper rubber is first inserted and secured. The BHA is then made up onto the first joint and pushed through the rubber. The ram(s) can then be closed and the well opened up after equalising across the closed tree valves.

It is normal practise to use one stripping BOP or the annular to centralise the BHA and stop it hanging up in the stack and tree.

125.0 WSD 01.01 Rig-Up Preparation and Checks The first thing you must do before rigging is to verify that the equipment is labelled and that all certificates are in order. When rigging begins, all protectors are removed, and threads and sealing surfaces are cleaned and checked. Flanges are inspected and sealing rings are replaced. Before the well is opened, perform system function and leak test as described in the procedures. To save time, the procedures should be designed so that we can test several parts of the system simultaneously. The procedures for leak testing will vary depending on where you work. In an IWCF context, one can say that the whole rig up should be tested at the well’s highest estimated shut-in pressure Usually, the tests are performed from as low a point in the rig up as possible. Otherwise, it is common to install a bottom-hole assembly and at least one pipe, since the check valves are also tested. Checklists are to be used to ensure that nothing is forgotten or left out. If any part of the equipment does not work or there are leaks, this must be repaired before the job can be started. Testing is carried out after the first joint is hanging in the slips we should test from the lower most point in the stack and both the stationary and travelling slips must be engaged.

126.0 WSD 01.02 Adaptor, Connector and Flange Compatibility Before a job is performed, check the type of equipment needed with respect to pressure, dimensions and well fluids. This is the information the operator should provide with in connection with the ordering of the job if the conditions are not known for the service company. The job is then planned with regard to what is to be done and what surface and downhole equipment shall be used. Finally, a list of specifications for the necessary equipment can be set up.

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127.0 WSE 01.01 Requirements for Pressure Testing All equipment used for operations on wells shall be pressure rated and certified. Pressure testing and certification takes place at an approved workshop. It is still necessary to test the device each time it is used. This is then usually considered to be leak testing, even though it is often called pressure testing. A low-pressure test and a high-pressure test are used in accordance with the API procedures

128.0 WSE 01.02 Correct Test Procedures Testing procedures for snubbing operations will vary from place to place and from company to company. If you work on the Norwegian continental shelf, the NORSOK standard is followed. Make sure that you have access to the relevant procedures and that you follow them. Generally speaking, you can say that if a shear/ seal is rigged up it must be tested from kill wing valve on the Xmas tree or on the lowest possible level in the rig-up. From this point, we can also test the shear/blind. We also test the stripper, stripper ram and the safety BOP, and take a “body test” on the rig up. The check valves in the bottom-hole assembly are simultaneously tested. Whatever details are given in the procedure must be adapted to the equipment that is rigged up.

1.

The Xmas tree valves should be tested for operation and leaks before the operations commence.

2.

Pressure test all items possible before rigging up.

3.

Install the BHA on pipe into the Xmas tree with the two valves (usually the master valves) closed.

4.

Close the pipe rams in sequence and apply test pressure through the tree wing valve, or other suitable port, testing the BHA check valves and each ram in turn. Use the snubbers to hold the pipe in the BOPs.

5.

Test annular or stripping BOPs in the same manner.

6.

When all pressure testing and function testing has been completed with the stripper or lower stripper ram closed, equalise the pressure in the BOP stack with the well pressure below the tree.

7.

Slowly open the tree valves and observe for any leaks.

8.

Begin snubbing pipe monitoring the strippers

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129.0 WSE 01.03 Pressure Test with Tubulars in Place Testing of the BOP in a pressure control situation is called an inflow test. It will be carried approximately as follows: 

Close the BOP.



Screw pins in / activate hydraulic-mechanical locking for mechanical protection.



Bleed off pressure above the BOP.



Inflow test and monitor for pressure build up



If the pressure does not rise, the test is acceptable.

The described closure and testing of the BOP will primarily be used if there is a leak in the equipment above the BOP and when fishing pipe, coiled tubing or cable.

130.0 WSF 01.01 Mechanical Barriers We will now take a closer look at the secondary barriers when running snubbing. In an IWCF context, it is customary to regard all things that cut as tertiary barriers. This means that both shear/blind and shear/seal valves come under this category. In a typical rig up, we usually find a configuration with a shear/blind or a shear and a blind below the safety BOP. This is the secondary barrier that will cut the pipe and seal the well. In order to seal around the string, we must have a pipe ram below these. When running pipe without normal joint upsets we also use a slip ram this way, you can, after cutting, circulate down the severed string and take the returns under the pipe ram. Here we can see the similarities with a triple or quad coil BOP. This kind of layout also provides an additional back- up barrier element. If we do not have a shear/blind ram, but rather use a separate shear and blind, it is more complex action to activate cutting, as it involves two separate sets of rams to function, respectively, the cutting then sealing. After cutting the pipe, it is pulled up before closing the blind ram.

131.0 WSF 01.03 Principle of Grouping Barriers If a well is killed with a heavy fluid, it will be a primary barrier if it is being observed. In such a situation, there will have to be a close able, mechanical secondary barrier available. We must also distinguish between barrier elements and barrier envelopes. This means that many adjoining elements become an envelope. Internationally (IWCF), it is still customary to divide the barriers into three groups: primary, secondary and tertiary barriers. On surface equipment for snubbing operations we can say that the stripper, stripper P a g e | 170

ram and annular are primary barriers, safety BOP’s are secondary, and everything that cuts and seals are tertiary.

132.0 WSG 01.01 Power Unit or Hydraulic Failure The correct action to take when there is a power unit or hydraulic circuit failure while down hole or tripping Level of Importance L3.10/L4.10 Conduct maintenance procedures and ensure the engine is fully serviced with oil and fuel. Immediately set the Heavy slips on the pipe in the hole or the snubbing stationary if in the pipe light mode then close the safety rams on the tubing. 132.1 Burst Hose 

Conduct proper checks on all hose connections, valves and pumps.



Function test all hydraulic moving parts



Ensure that there is sufficient oil in the reservoir.



Replace hose or fitting,



Function test continue

133.0 WSG 01.02 Slip Bowl failure The correct action to take when there is a slip bowl failure When the seal in the slip fails, then: 1. Ensure when running pipe that the correct pressures are maintained for opening and closing the slips. 2. Ensure that slip inserts are free from grease, pipe dope and scale when running or pulling pipe. 3. Close the back-up slip, secure with a clamp prior to changing the worn slip insert.

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134.0 WSG01.03 Annular Element Failure In the case of a leaking annular, it would be necessary to pull back out of the hole, close the blind rams and rig the jack off the well before being able to open the bonnet of the annular. The annular should always start a new job with a fresh rubber and it is indeed a rare occurrence to have to change it during a job. If an annular rubber had to be changed during a job, it would be normal practice to come out of the hole, if at all possible, rather than open the annular with pipe in the hole.

135.0 WSG 01.04 Uncontrollable External Leak in BOP Stack Cut the pipe with the safety Head, confirm by closing the swab valve while counting the turns, close the master valve.

136.0 WSG 01.05 Leak in Workstring Sometimes you can incur pin hole leaks when running old tubing into a well which can be a problem. These are generally detected visually when joints are passing thru the stripping rubber as well as egressing fluids from the pipe. Surface leaks are generally cured by backing out the offending joint and installing the TIW valve to stop the leak. If this is not successful: 

Rig up TIW valve and drop plug and seat.



Confirm tubing leak.



Slug pipe with heavy fluid pull wet pipe.

If not successful: 

Multi wire line set bridge plugs could be installed above the hole.



Depending on hole size the well may have to be killed as a last resort

137.0 WSG 01.06 Stripping BOP Failure The correct action to take when there is a leak in the stripper BOP ram Ensure that the correct pump pressure is maintained for the rams being used. Ensure the equalizing and bleed off valves are functioning properly (BOP will not open if there is the presence of trapped pressure between the rams) 

Close the safety rams on the pipe and manually lock.



Bleed off pressure

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

Open rams and change out worn stripping inserts



Ensure rams are greased properly with the correct lubricant.

137.1 BPV Failure



Ensure that all valves are maintained.



Check springs, ball and seat are not worn or corroded.



Ensure that tool Joints are made up to the correct torque value.



Pipe dope or scale falling on top of the BPV.



When fluid is seen coming from the open pipe install the TIW valve and close it.



Insert pump down plug into the TIW



Attach circulating head, pen TIW.



Pump plug into the landing nipple.



Inflow test



Pull wet pipe

138.0 WSG 01.07 Consequences of String Washout If goes undetected can cause the pipe to part. Well may have to be killed before fishing to retrieve.

139.0 WSH 01.01 Well Shut-In With or Without Tubing in the Hole In other more general alarm and emergency situations, we will first and foremost give priority to pulling out of the hole and if necessary preparing for cutting the snubbing string so that the X-mas tree and subsurface safety valve can be closed.

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140.0 WSI 01.01 Calculate Pipe Forces To prevent pipe from buckling, snub force calculations should be performed. Snubbing force is calculated by taking wellbore pressure and applying it against the cross sectional area of the largest tool or pipe that the. BOP may be closed around. Generally, most people calculate this snub force using the OD of the pipe Also, the friction must be added when moving pipe through this BOP. Estimated Force lbs = (Tubing OD2 X *0.7854 X Surface Pressure psi) + Friction through BOP lbs Assume in this snubbing example that there is 8,500 psi of surface pressure and 1,000 psi of friction necessary to move 2 7/8” pipe through the BOPs. The formula would be: Force = (2.875 x 0.7854 x 8,500psi) + 1,000 psi (8.266 0.7854 x 8,500) + 1,000 55,182.99 + 1,000 = 56,183 lb

Snubbing Unit required = 120 K

Unit

120K

Hydraulic Snubbing/Work-Over Units Capabilities Rotating Stroke Lifting Snubbing Bore Size Head Length Capacity Capacity (in) Torque (ft) (Lbs) (Lbs) (ft-Lbs) 10 – 40 4 1/16” 120,000 60,000 2,000 Long Stroke

Work Window (ft) 6 – 10

150K

7 1/16”

10

150,000

75,000

3,500

6 – 10

225K

11”

10

225,000

113,000

4,000

6 – 10

340K

Up to 14”

10

340,000

175,000

20,000

6 – 10

460K

Up to 14”

10

460,000

230,000

20,000

6 – 10

600K

Up to 14”

10

600,000

300,000

20,000

6 – 10

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Please calculate the estimated snubbing force required on this well. 

Casing 5 ½” OD; 4.995” ID



Tubing 2 3/8” OD; 4.7 lbs/ft



Well Pressure 5,000 psi



BOP Frictional Force = 3,000 lbs

Estimated Force lbs = (2.375² x 0.7854 x 5,000) + 3,000 lbs

(5.64 x 0.7854 x 5,000) + 3,000 22,148 + 3,000 = 25,148 lbs force

Needs to be overcome in order to move pipe in the well.

140.1 Balance Point The Balance between Pipe Heavy/Pipe Light has to be calculated so that the changeover between using Slips and Heavies, and Snubbers can be made safely. The depth of the Balance Point is effected by: 

Wellhead Pressure



Fluid Contents of Pipe



Pipe Weight/foot

The largest Snubbing Force acting on the Pipe String is when the first joint is going in the Hole. 140.2 Calculation of Balance Point When the forces acting upwards and the forces acting downwards are equal, the balance point will have been reached. The following calculation can be used as an approximation for calculating the depth of the balance point. It does not consider friction forces etc.

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Known data 

Well head pressure 500psi



Tubing OD 2.375ins



Tubing Wt. 4.7lbs/ft.



Tubing contents 0.375 lbs/ft.



Pipe joint 31ft

To calculate balance point

Calculate the sum of the forces acting upwards = Area of the tubing x well head pressure x 500 = 2.375 x 2.375 x .7854 = 4.43 sq. ins x 500 = 2215psi snub force Calculate the sum of the forces acting downward = weight of pipe + weight of the contents of the pipe =

4.7lbs/ft.+ 0.375lbs/ft. = 5.075 lbs/ft. Length of pipe (ft.) to reach balance point = snub force 0 ÷ pipe weight U = 2215 -5.075 = 436 ft. = 436 feet ÷ 31feet (length of joint) = 14 joints

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Part 5 Wireline

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Table of Contents

141.0 Wireline ........................................................................................................................ 180 142.0 Wireline Operations ...................................................................................................... 185 143.0 WWA01.01 Surface Equipment ...................................................................................... 185 144.0 WWA01.02 Slickline Rig-Up Configuration ..................................................................... 186 145.0 WWA01.02 Braided Rig-Up Configuration ...................................................................... 188 146.0 WWA01.03 BOP Positioning .......................................................................................... 188 147.0 WWA01.06 Grease Control Head ................................................................................... 189 148.0 WWA01.07 Stuffing Box ................................................................................................ 190 149.0 WWA01.08 Ball Check Valve .......................................................................................... 191 150.0 Test Sub ........................................................................................................................ 191 151.0 Insitu Test Sub ............................................................................................................... 191 152.0 Chemical Injection Sub .................................................................................................. 192 153.0 Quick Unions ................................................................................................................. 192 154.0 Lubricators .................................................................................................................... 192 155.0 WWA02.01 Principles of Operation Slickline BOP ........................................................... 193 156.0 WWA02.02 The Principles of Pressure/Inflow Testing Slickline BOP ............................... 195 157.0 WWA02.03 Operating Principles of Braided Line BOP .................................................... 195 158.0 WWA02.04 Principles of Pressure Braided Line BOP....................................................... 196 159.0 WWA02.05 Braided Line Barriers ................................................................................... 196 160.0 WWA02.08 Shear/Seal BOP ........................................................................................... 197 161.0 WWA07.01 Changing a Seal in the BOP .......................................................................... 197 162.0 WWA07.03 Sealing Elements ......................................................................................... 198 163.0 WWA07.04 Sealing Elements Inspection ........................................................................ 198 164.0 WWA07.05 Assess Equipment/Seal Damage .................................................................. 198 165.0 WWA07.06 Explosive Decompression ............................................................................ 198 166.0 WWD01.01 Rig Up Checks Prior to Installation ............................................................... 199 167.0 WWD01.02 Equipment Check ........................................................................................ 200 168.0 WWD01.03 Critical Isolation Requirements ................................................................... 200 169.0 WWE01.01 Testing Requirements .................................................................................. 201 170.0 WWE01.02 Certification and Compatibility .................................................................... 202 171.0 WWE01.03 Test Procedures ........................................................................................... 202 172.0 WWG01.01 Leak at the Stuffing Box .............................................................................. 204 P a g e | 178

173.0 WWG01.02 Leak in Surface Equipment Above BOP ........................................................ 205 174.0 WWG01.03 Maintaining a Grease Seal ........................................................................... 205 175.0 WWG01.04 Cable Rupture ............................................................................................. 206 176.0 WWG01.05 Hydraulic Master Valve Control Line Leak .................................................... 207 177.0 WWG01.06 DHSV Control Line Leak ............................................................................... 207 178.0 WWG01.07 BOP Hydraulic Control Panel Malfunction ................................................... 207 179.0 WWG01.08 Wire Pulled Out of Rope Socket .................................................................. 207 180.0 WWK01.01 Drift Runs/Gauge Cutters ............................................................................ 208 181.0 WWK01.02 Safety Valve Integrity .................................................................................. 208

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141.0 Wireline Wireline was first used in the oilfield the early 1920s as a means of accurately measuring well depth. It started as a flat steel measuring line. Otis was the first company to use a circular wire and to create special wireline units, often mounted on trailers. Slickline uses small diameter continuous solid wire for manipulating various tools in live or dead wells. Wireline equipment is very portable and rig-up time can be quite fast.

High deviations can cause problems with Slickline, as gravity is required to keep the wire moving down the wellbore. In highly deviated wells, the wireline tool string lies against the side of the tubing and the weight comes off causing the tools to stop moving downwards. Slickline can be used for a very wide range of jobs such as: 

Running and pulling flow control devices.



Opening and closing circulation devices.



Checking the inside of the tubing for debris, waxes, scale, corrosion, etc.



Cleaning the inside of the tubing and the completion components.



Running and pulling gas lift or chemical injection equipment.



Running and pulling DHSVs.



Bottom hole sampling.



Running temperature and pressure surveys.



Depth measurement.



Fishing for lost objects and debris.

Slickline uses a continuous length of single solid strand wire (like piano wire) whereas braided line uses a continuous length of stranded wire (like logging cable). This may have one or more electrical conductor wires inside in which case it is called Electric Line or e-line .or it may be for heavy-duty work. The principles are exactly the same although the well control mechanisms are slightly different.

141.1 Slickline Slickline is a method of mechanical manipulation of devices downhole and is only capable of pulling or pushing (by jarring action). Rotation is not possible. There are thousands of different tools that have been designed for use with slickline although they all P a g e | 180

operate in much the same way. The main advantages of Slickline are the relatively low cost compared to other intervention Methods such as portability speed of rig up/down, running/pulling speed and the ability to work on live wells. The main disadvantage is that it is very easily damaged due to its thin and flexible nature. It also has limited use when well deviation is approaching 70o There are various sizes of Slickline available today; the main ones are listed below.



0.072"



0.082"



0.092"



0.105"



0.108"



0.125"

The last two sizes are probably the most commonly used. The lines themselves can be made out of a great variety of exotic steels to withstand the harsh downhole environment and are available in reels of up to 30000 ft. Modern technology has ensured that the quality and consistency of a spool of Slickline is to a very high standard. H2S resistance is very good. Reels of Slickline have a finite life and the wireline service companies check to ensure that the wire remains up to standard. There is a simple torsion test (by twisting) which is performed to check the wire. The manufacture and testing of slickline should be to API 9A specification. Typically, a reel of 0.108" wire will have a breaking strength of between 1720 lbf and 2730 lbf. When used, the wire should not be worked past its elastic limit, which is usually approximately 50% of the breaking strength. The strength of a particular size of wire will vary according to the material from which it is made. 141.2 Surface Equipment A Slickline Package is composed of 3 basic components: 

Power pack



Winch



Pressure Control Equipment

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141.2.1

Power Pack

Power units (power packs) come in a variety of types and sizes to suit the well location and the work to be performed. They can be very small trailer mounted units for simple shallow land well jobs that do not require heavy downhole work or large containerised units with very sophisticated controls for deep and deviated offshore wells etc. Most power units are diesel driven although some offshore units that regularly work on the same platform are electrically powered. The unit drives one or two hydraulic pumps to control the winch. Most slickline units have their power packs and winches separate, however modern, larger units tend to be enclosed in one container including a cabin for the operator.

141.2.2

Winch

The wire is stored on a drum located in front of the operator on the winch unit. Power from the hydraulic power pack is applied to the drum usually via a four-speed gearbox. There are controls that can select forward or reverse and a handbrake for the drum. There may be more than one drum of wire on a winch unit but only one drum is in use at a time and combinations of slick-line and braided line or slick-line and electric line are common. Many units are capable of running at wire speeds of up to 3000 ft./min. The wire is spooled off the drum and is wrapped around the measuring head to give the operator depth measurement. Before running in the hole each time, the operator resets the depth counter a weight indicator displays the weight of the tools and the tool-string as well as any additional forces generated during jarring etc. zero.

141.2.3

Wireline Classification – Electric Line

Braided Line with one or more electric conductors in the middle is called Electric Line and is used exclusively for conveying tools down hole that require or generate an electric signal. Electric lines have a much-reduced breaking strain compared to braided line without any conductors. Some electric lines have only one conductor and are called mono-conductor cables. They are commonly 3/16", 7/32", 5/16", 3/8" or 7/16". The smaller sizes are used for through tubing well servicing work whilst the larger sizes are usually used for smaller suites of open-hole logs. Other electric lines have 7 conductors (logging cables), are used exclusively for open-hole logging and are usually 15/32" or 17/32".

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These logging cables are normally used on drilling rigs with well control using a full column of kill fluid. Occasionally cables with 2 conductors are used.

The main uses of electric line are: 

Data gathering



Perforating



Chemical cutting



Setting packers and bridge plugs



Determining free point (stuck point)

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141.3 Slickline

Slickline is a high-strength monofilament steel line and is available in common sizes of 0.082”, 0.092”, 0.108” and 0.125”. These are also supplied for various service conditions. Being slick the OD of the wire is easy to seal around using a simple packing device called a stuffing box whereas the cable requires a grease seal arrangement.

Braided Line Braided line is available in a variety of sizes (ODs) and in two basic types, with or without electric conductor cables. Braided Line without an electric conductor in the middle is sometimes called sand line and is used for heavy-duty wireline. Heavy- duty fishing winches are nearly always braided line and do exactly the same as slick-line. It has a very much greater breaking strain than slick-line and is commonly 3/16 inch, 7/32 inch, 1/4 inch or 5/16 inch diameter.

141.4 Hay Pulley The wire from the winch is guided into the well from via a hay pulley and a sheave set on top of the wireline PCE. The weight indicated by the load cell is dependent on the angle of the wire between the sheave and the winch. If the angle of incidence is greater than 90 degrees the load indicated on the load cell is less than the actual load. If the angle of incidence is less than 90 degrees, the load indicated on the load cell is more than the actual weight. Weight Indicator Reading @110° = 811Lbs

811Lbs ÷ 1.14716 (constant at 110°) x 1.41422 (constant at 90°) 811Lbs ÷ 1.14716 = 706.963 Lbs 763.963Lbs x 1.41422 = 1000Lbs

Actual weight reading = 1000 Lbs

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142.0 Wireline Operations 143.0 WWA01.01 Surface Equipment Wireline relies entirely on the lubricator system to provide primary pressure control. Secondary pressure control is provided by the wireline BOPs and tertiary well control may be available in the form of another wireline cutting valve, either contained in the Xmas tree or as a shear/seal valve or BOP installed on top of the Xmas tree. The various pressure control barrier systems are:

Primary 

Stuffing box and lubricator system.



Check valve (Internal BOP) if the wireline breaks and is ejected from the lubricator.



Xmas tree valves when installing into, or removing tools from, the lubricator

Secondary 

Wireline BOP rams/valve which can close and seal around the wire.



Xmas tree upper master, if the wire is broken and ejected.



SCSSV, if wire is above it.

The BOP rams can be used for stripping wire out of a well but only when absolutely necessary. Stripping through the BOPs is only carried out to find the free end of the wire to enable wireline recovery.

Tertiary



Wireline cutting valve/BOP.



Xmas tree valve, if absolutely necessary.

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144.0 WWA01.02 Slickline Rig-Up Configuration The correct function and the method of installation of surface pressure control components required for the operation

144.1 Slickline lubricator Single Stack BOP Stack arrangement

Operating Elements 

The stuffing box is adjustable (manually, or more commonly hydraulically) to cater for packing wear.



The lubricator is an intrinsic part of the primary well control system along with the stuffing box.



If the stuffing box leaks, the wireline BOP wire/blind rams can be closed on the wire to repair the packing.



If the rams leak, the wire can be cut with a wire cutting actuator or the upper master valve, although this may lead to valve damage.

Slickline lubricator Dual Stack BOP Stack arrangement

Operating Elements o

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Stuffing box is adjustable (manually, or more commonly hydraulically) to cater for packing wear.

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o

Lubricator is an intrinsic part of the primary well control system along with the stuffing box.

o

If the stuffing box leaks, the upper wireline BOP wire/blind rams can be closed on the wire to repair the packing.

o

If the upper rams leak, the lower rams can be used.

o

If the wire is broken and expelled from the lubricator, the swab valve will be closed

o

If the rams leak, the wire can be cut with a wire cutting actuator or the upper master valve, although this may lead to valve damage

145.0 WWA01.02 Braided Rig-Up Configuration

o

The grease seal pressure is adjustable for varying well pressures.

o

If the grease seal fails, both rams can be closed on the wire. The lower ram is inverted so that grease can be injected to create a seal.

o

If the wire is broken and expelled from the lubricator, two Xmas tree valves must be closed to provide double isolation.

o

If the rams leak, the wire can only be cut with a wire cutting actuator.

145.1 Electric Line Lubricator/Triple BOP Stack Arrangement

Operating Elements o

The grease seal pressure is adjustable for varying well pressures.

o

The lubricator is an intrinsic part of the primary well control system along with the grease seal.

o

If the grease seal fails, both the wireline BOP wire rams can be closed on the wire. The lower ram is inverted so that grease can be injected to create a seal.

o

If the wire is broken and expelled from the lubricator, the blind ram plus a

o

Xmas tree valves must be closed to provide double isolation (or two tree valves). The safety check valve would also be closed preventing hydrocarbons or gas into the atmosphere.

o

If the rams leak, the wire can only be cut with a wire cutter

146.0 WWA01.03 BOP Positioning LOI- L3.10/L4.10 The BOP is used to control well pressure and to operate safely at all times. It seals around the wire when stationary. It can be single, double, or triple. It is comprised of a shut-in arrangement of rams and a sealing surface called a ram seal. The shut-in operation can be mechanical or hydraulic. All BOPs can be closed manually in an emergency but can only be opened under hydraulic pressure

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147.0 WWA01.06 Grease Control Head Since a braided cable quickly wears out rubber packers and because there will be leakage between the strands of the cable, a fluid based system is developed to create a seal around and inside the cable when it is run into the well. The cable can also rotate freely so that it does not break. We call this system a grease injection control system. The most important part of this system is the grease control head. Liquid grease is pumped into the grease head where it settles around the cable and penetrates into it. This happens at the same time as the cable is run through small tubes with little clearance, so that only a thin film is spread between the tube and cable. The tubes are called “flow tubes” and it is the fluid friction in the liquid grease that prevents the well bore fluid from leaking out. A head is built up of several tubes, depending on how large a pressure is to be contained. One tube holds about 1000 to 1450 psi and one head cannot be made up of less than 2 tubes. Normally, we use a minimum of three and often four or five sections of flow tubes. Flow tubes are available in a range of sizes with small increments to provide the most efficient seal over the life of the cable, which will reduce in the overall OD of the cable with usage. The fit of the wire v flow tube should be as tight a fit as possible to create a better seal. If the flow tubes are too large for the cable then it will not create an effective barrier and too much grease will be used.

2 - 3 Flow tubes =

0 – 2,000 psi

3 - 4 Flow tubes = 2,000 – 5,000psi 4 -5 Flow Tubes = 5,000 – 10,000psi

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If problems develop with the seal, we can stop running the line and tighten a stuffing box for braided cable that is placed at the top of the grease control head. This can only be used when the wireline is standing still until the system works again. At the very top of the grease control head there is usually a wiper; it can be rubber elements that carefully tighten around the wireline while it is being pulled out of the hole, or it can be a pneumatic wiper that blows the wiper clean. In the lower part of the grease control head we most often find some form of a check valve based on a seat that the wireline runs through. A ball that fits the seat lies waiting on the side of the wireline.

148.0 WWA01.07 Stuffing Box The stuffing box is the most central element in the rig-up for operations with slick line. There are several different types and manufacturers. We will look at the basic structure and function of stuffing boxes with mechanical and hydraulic pressure. In the picture above you can see some common packer types. It is common to use a combination of hard and soft types, with hard on the top and bottom and soft in the middle. Be sure that there is the right amount of packers or it may lead to the piston and upper Bushing/gland not contacting the packing. This can lead to the packers being blown out and having an uncontrolled hydrocarbon release. Damage to the stuffing box can also occur. A stuffing box for wireline operations is not assisted by well pressure. We tighten by compressing the piston, using hydraulic fluid, downwards forcing the upper gland against the packing and the lower gland. There are two ways of doing this, either by a mechanically or hydraulically.

Hydraulically - using a hydraulic hand pump, pressure is applied to the packing nut, which can usually be tightened manually if necessary when rigging up. The mechanical packing nut is composed of a hollow screw that is tightened by hand. There is usually a “snaptite” coupling installed on the hydraulic packing nut. A hose and a hand pump is connected to this for remote operation Check that the return mechanism in the piston works and that the pressure is bled off before the hose is disconnected and the stuffing box is repacked. Each time the packing is replaced, the stuffing box must be inspected for damage and wear. Make note of whether there are spacious or oval holes, and if there are shavings of cable. A stuffing box shall be overhauled regularly so that we have good packing at all times when we are running wireline into the hole. A newly packed stuffing box should stay tight without the need to apply hydraulic pressure. With wire in the hole, the stuffing box is the primary barrier; if the wire is broken for any reason then the primary barrier is the “internal BOP/plunger” This is used when a wireline operation with slick line is performed in a well that is under pressure. It creates a pressure seal between the well pressure and atmosphere while allowing the wireline to move freely through it. It is comprised of a packer chamber that contains a stack of packers that can be tightened around the wireline as the packers get worn out. The stuffing box has a piston with a P a g e | 190

rubber cone that is pressed up, creating a seal between the well pressure and atmosphere that prevents leakage/blowout if the wireline snaps and comes out. 148.1 Internal BOP In the lower part of the stuffing box sits a plunger with hole through which the wireline goes through. If the wireline is cut and blown out of the hole, well pressure will push the plunger up, and a rubber cone on the end is compressed by well pressure and seals the hole. This part is often called the internal BOP or plunger.

148.2 Hydraulic Stuffing Box Packer The stuffing box packing nut is operated by hydraulic from a hand pump. The pump should only be operated when the wire is stationary. When pressure is applied to the packing nut it pushes the piston down against the upper packing gland, which in turn compresses the packing against the lower packing gland, thus sealing the pressure in the well.

149.0 WWA01.08 Ball Check Valve If the wireline is cut and blown out of the grease control head, the ball will be filled up in the seat and stop the flow of well fluids. This part is not incorporated on older versions of the grease control head. Instead, one can use a separate valve, which is designed for this It has a quick release union on the top and bottom. It can also be used in connection with slick-line operations if is desired.

150.0 Test Sub In-situ test subs are installed between the lower lubricator section and the wireline valve and are designed to significantly reduce operating costs, by removing the need to pressure test with glycol before every wireline run. After the initial pressure test of the complete pressure control package, the tools are changed out via the special TIS acme, secondary quick union connection on the pressure test sub. The secondary quick union connection has stepped seal bore diameters complete with o’ ring seals and an injection port, that allows the union to be externally pressure tested. Due to the small volume of fluid required, testing of the secondary union can be carried out with a hand.

151.0 Insitu Test Sub The Tool-catcher is designed to engage the fishing neck of a rope socket. The Tool- catcher is placed on top of the lubricator just below the Ball Check Valve. The rope socket is released from the Toolcatcher by hydraulic pressure (typically 1200psi). It operates by hydraulic pressure moving a piston down onto a set of finger collets, which open and release the tool-string. P a g e | 191

152.0 Chemical Injection Sub The Chemical Injection Sub is designed to allow the injection of either a de- icing agent (i.e. Methanol or Glycol) or a corrosion inhibitor. It is mounted just below the Stuffing Box or Grease Injection Head. It has replaceable felt packing which are kept constantly wet by chemical injection and therefore act as wipers to the wireline passing through it.

153.0 Quick Unions Quick Unions have Acme type square threads and seal using an O-ring. The connection should be made up only hand tight and then backed off part of a turn. It is important that the O-ring is inspected for damage prior to making a connection. The lowest section of lubricator is usually of a larger diameter as it must contain the tool that is being run or pulled. The upper sections only have to contain the tool-strings and can therefore be of smaller diameter. The bottom section is fitted with a needle valve for bleeding off any trapped pressure above the BOP or wellhead before breaking out the lubricator and changing the tool-strings. Hydrocarbons are usually bled to a closed drain. Prior to applying any pressure, the lubricator section must be checked to ensure that its rated pressure is sufficient for the work being performed and that all seals and sealing surfaces are in good condition.

154.0 Lubricators The lubricator allows the tool-strings to be inserted into or removed from the well under pressure and is installed between the BOP's and the stuffing box. There will probably be three or more sections of lubricator in use. As with all wireline surface equipment, the sections are usually connected by Quick Unions. A second needle valve should be fitted to the bottom lubricator section to provide double barrier protection and so that a pressure gauge can be fitted. Typically, lubricator sections are 8 ft. long and sufficient lubricator must be used to accommodate tool-strings being recovered from the well including the item that is being pulled. Additional lengths of lubricator will be required for fishing operations. Lubricators are available in different pressure ratings for both standard and "sour" service. It is usually considered that all lubricators used for pressures over 5000 psi should have the quick unions welded rather than screwed to the main tube. Pressure Testing Lubricators are normally tested to manufacturers test pressure or working pressure at regular intervals to satisfy certification requirements. P a g e | 192

Field Testing Lubricator sections are usually pressure tested after rigging up on location prior to opening the well. Various company policies may have different testing requirements for pressure testing on the well however, it is common practice at most locations to pressure test to a minimum of expected Closed In Tubing Head Pressure (CITHP).

Maximum Working Pressure (psi) 3,000 5,000 10,000 15,000

Colour Red Dark Green White Yellow

Colour Coding and Pressure Rating of Pressure Control Equipment

The first band indicates if the service is standard or sour: 

Standard service has no band.



Sour service has an orange band.

The second band indicates the temperature of the service: 

Standard service (-30°C to 250°C) has no band.



Low temperature service (below –30°C) has a blue band.



High temperature service (above 250°C) has a purple band.

155.0 WWA02.01 Principles of Operation Slickline BOP The BOP is mounted below the lubricator and, in normal operations; it is usually the connection above the BOP that is broken to allow the insertion or removal of the tool-string. This is where the quick test sub is situated. The BOP is the secondary barrier when there is wire in the hole and they are usually mounted as close as possible to, or on top of the Xmas tree, for ease of access and to minimise the number of potential leak paths (connections) below the BOP. Fitting the BOP close to the Xmas tree also serves to maximise the length of the lubricator. With the BOP closed and sealing around the wire, equipment above can be depressurised and repaired. If tools become stuck in the hole, a means must be found to cut the wire as close to the top of the toolstring as possible. In this case, the wireline BOP's would have be closed as the tree valves cannot close because of the wire through them.

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With the BOP closed and sealing around the wire: 

Close the manual locking stems on the BOP



Bleed down the lubricator



Inflow test the BOP



Break out the lubricator

A cutter can then be attached to the wire ready to be dropped to cut the wire at the rope socket when the BOP is opened.

155.1 Additional BOPs If a routine operation turns into a fishing job, additional BOP's may be required as well as additional lubricator to accommodate the fished tool-string.

155.2 Equalising Valves

BOP's are fitted with equalising valves across the rams. Before opening the rams, pressure must be equalised to prevent damage. Occasionally, if wireline work is to be done using both slickline and braided line, both sets of BOP's will be installed at all times so that there is less work changing from one to the other. Triple BOP's are available which can be dressed, for example, with slickline rams at the top and dual braided line rams at the bottom. Slick-line BOP's hold pressure from below only. Wellbore pressure acts to help keep the BOP closed and maintains the seal around the cable.

This is a list over situations where a BOP will be activated:

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

If a leak occurs anywhere above the BOP.



Fishing operations.



Spooling broken wire back onto the drum.



Dropping cutter bars when fishing.

156.0 WWA02.02 The Principles of Pressure/Inflow Testing Slick line BOP The BOP is pressure can be pressure tested on the tree or stump to ensure when the BOP is closed it maintains a seal and holds pressure from below. The rod should be manufactured for purpose and not homemade. When the BOP is closed on the wire while well is under pressure, the pressure above the BOP is bled down and monitored to ensure the BOP holds a seal before any PCE above are broken down.

157.0 WWA02.03 Operating Principles of Braided Line BOP

Using slick-line requires only one BOP ram that will seal around the wire when the ram is closed. Using braided cable on the other hand requires two rams, where the top ram is normal and the lower ram is inverted, which allows grease to be pumped in between the rams and form a seal around the cable when the BOP is shut-in. Braided cable BOP is designed to seal around a static cable all movement should cease. Dual rams should be configured with the lower set of rams inverted and the top set of rams normal with a grease injection port in between this allows the grease to be injected into the cavity between the two rams and maintain pressure control. By filling the cavity with grease at a higher wellhead pressure, the grease fills the spaces and prevents escape. A dual BOP should be tested prior to rigging up on a test stump. The BOP should be tested after rigging it up by filling the stack, place a one-piece test rod across both the rams, close them, and apply pressure thru the grease injection port. If the design incorporates a weep hole then particular attention must be made to monitor and check that the weep hole does not leak. If mud or completion fluids be seen, coming from the weep hole then the shaft mud seal is leaking. Operations should cease immediately and the seal replaced. If hydraulic fluid is leaking from the port then the same action must take place as the mud seal leak. If it is not possible to repair leak, given the present ongoing operations then plastic packing can be used as a temporary solution. It would be normal for the grease pump to stroke on an intermittent basis, this is due to the grease seeping from the rams and the pump pressure compensating for the pressure loss. A dual BOP with an inverted ram holds grease pressure not well pressure.

157.1 BOP Conversion Procedure

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

Lower rams must be inverted for using braided cable or E-Line



Ram seals and guides must be inspected or changed for the specific cable being used



A grease injection line with a one way check valve to the injection port on the dual BOP



The wireline valve must be pressure tested on a stump with a one piece test rod.



After rigging up the valve should be function tested



Snaptite connections to be checked and functioned to ensure the one way check valve is fitted.

158.0 WWA02.04 Principles of Pressure Braided Line BOP 

Close inverted ram.



Fill BOP with test fluid only, above inverted ram.



Test rams at 300 psi for 5 min.



Test rams at 1.5 times expected wellhead pressure for 10 mins.



Test is valid for 14 days and shall be documented on test chart. Use only one piece test rods.

159.0 WWA02.05 Braided Line Barriers The system for braided line is very similar to slickline. Pressure control is provided by:

Primary 

Grease seal and lubricator system.



Check valve if the wire breaks and is ejected from the lubricator.



Xmas tree valves when installing into, or removing tools from, the riser.

Secondary 

Two wireline BOP rams (in conjunction with a grease pump) that can close and seal around the wire.



Xmas tree upper master, if the wire is broken and ejected.



SCSSV, if wire is above it.

Tertiary

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

Wireline cutting valve.



Shear/seal valve or BOP installed directly onto the top of the Xmas tree.

159.1 BOPs Placement and Application

On a land well, it is natural to set the BOP directly on top of the tree. This achieves the best access and minimizes possible leaks paths in the rig up. This will often be different offshore, as we use risers to place the BOP at the deck level where it is easier to access it. If you are placed in a situation, where wireline has to be fished out of the well, one must ensure that there is enough lubricator over the BOP that the entire fishing string can be pulled in plus at least one metre. If fishing with another cable type than the one that was lost, the BOP must be rigged up for all the types of cable in the well. It is often an advantage to have a lot of room in the PCE during complex fishing operations. If possible, rig up from the drill floor and use an extra BOP and shear ram down at the Xmas tree. Also, remember to ensure that you have the means to lift off and on the lubricator and BOPs as required during the operation.

160.0 WWA02.08 Shear/Seal BOP The shear ram is used to cut the wireline and secure the well if it is not possible to achieve a seal around the wire. It can also be used to cut the cable in a controlled fashion, for example during fishing operations. In some cases, it is the master valve on the Xmas tree that is defined as the shear ram (by design). Otherwise, either it is rigged up as a manual shear ram or a shear ram integrated in the lowest part of the BOP. This BOP will cut more than one strand of wire or cable but will not cut a tool string. When used in conjunction with sub-sea tree plugs a modified short tool string should be used or a sacrificial piece of hollow stem needs to be aligned across the shear seal BOP to affect a cut.

161.0 WWA07.01 Changing a Seal in the BOP From time to time in the span of an operation, we need to change the equipment setup. This can, for example, involve changing the inner seal from slick to braided wireline, or vice versa, or changing from one dimension to another. If you are informed about the equipment being used and what the next step in the operation is, you will know what needs to be changed. While changing packer elements in the BOP, you should check for the presence of significant damage to the equipment. Today, variable seals are most commonly used, which seal around the most common types of wireline.

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162.0 WWA07.03 Sealing Elements Check the seals and see if we need to change them due to damage or wear. Usually, O-rings and packing elements are used until 80 % is left if there is no damage on them.

163.0 WWA07.04 Sealing Elements Inspection

164.0 WWA07.05 Assess Equipment/Seal Damage If the equipment or seals are damaged, we must consider the impact this has or can have on the operation. If the damage is insignificant, work may continue, but if it is big, the operation should be halted until parts or the entire module is replaced.

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165.0 WWA07.06 Explosive Decompression Explosive decompression (ED), also referred to as rapid gas decompression (RGD), is a failure mechanism of elastomer seals, which is due to the rapid decompression of gaseous media. When elastomer seals are exposed to high-pressure gas at elevated temperatures for a prolonged period of time the gas absorbs into the polymer compound. When the external pressure is reduced, the gas dissolved within the elastomer comes out of solution to form micro bubbles. As the gas expands, it will permeate out of the seal. However, if the rate of decompression and expansion is high, the trapped gas within the seal expands beyond the elastic limit to contain the gas bubbles, will causing fissuring, resulting in seal failure.

165.1 Secondary Barriers In NORSOK, gate valves are regarded as secondary barriers. This can be a hydraulic main valve or a separately rigged up gate valve that can cut wireline. This can also include a BOP that is equipped with shear rams to cut a wireline at the same time as it is equipped with packers that seal the well after the cutting. If we work with ordinary slick line we can use all of the above mentioned alternatives, but if we have braided cable, greater force is required to cut. This is achieved with cutting rams in the BOP. If a situation arises where more than one cable must be cut at the same time, this kind of BOP has the necessary capacity, to cut no more than 8-10 wirelines at the same time. It is also worth noting that all the mentioned shear rams are designed to cut wireline, not tools or tool strings. If heavier operations take place on a well, an appropriate sized shear valve is rigged up directly on the Xmas tree. This kind of shear valve also has the task of cutting tools and tool strings that are run in the well.

166.0 WWD01.01 Rig Up Checks Prior to Installation Before a job is to be carried out, check what type of equipment is needed with respect to the pressure, dimensions and well fluids. This is information the operator shall provide in connection with the intervention preparation if the information is unknown to the service company. The job is then planned with regards to what should be done and what downhole equipment is to be used. Finally, a list of specifications for the necessary equipment can be set up. Ensure that all equipment needed is available.

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167.0 WWD01.02 Equipment Check The first thing that must be done before rigging up is to ensure that the equipment is labelled and has the required certificates. When rig-up commences, all protectors should be removed, all threads, sealing surfaces cleaned and verified. The O-rings are checked and replaced if necessary. The BOP should be function tested, leak tested on the test stump before the well is shut-in. Before the well is entered, the PCE must be function and leak tested as described in the company procedure. The whole rig-up is to be tested up to the well’s highest expected shut-in pressure, or a minimum of CITHP. Before pressure/leak testing of the whole rig-up, the tool string must be pulled to the top of the lubricator so that we avoid damaging the rope socket at the underside of the stuffing box, or accidentally damaging the tool-string by surging pressure. Checklists are to be used to ensure that nothing is forgotten or committed. If some part of the equipment does not work or there is a leak, it must be repaired before the job can be restarted.

168.0 WWD01.03 Critical Isolation Requirements 

Before well intervention, the well intervention team (WIS) shall assume control of the Xmas tree and the subsurface safety valve (DHSV) for the well in question.

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Well control shall be assumed when the area authority Production, signs the form for Take-over of well control to WIS or the tool pusher. All handover between operation and well intervention team must be followed by an isolation confirmation certificate.

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An Isolation confirmation certificate shall be used for rigging that may reduce the integrity level of the Xmas tree and removal of hydraulic connections for emergency shutdown.

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In connection with well intervention, operation of the Xmas tree valves and/or subsurface safety valves (DHSV) shall be conducted by WIS without requiring a separate isolation certificate. 168.1 Exceptions

Valve interface from well intervention to process facility (e.g. wing valve, valves to closed drain) and production header that require a separate isolation confirmation certificate When well intervention is complete, WIS shall deliver the Xmas tree and subsurface safety

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valve (DHSV) to the area authority production by signing the form for Takeover of well control.

168.2 Exceptions

The barriers described are barriers when wire is in the hole. If the UMV does not have wirecutting ability, there should be a cutter valve on top of the tree to act as the tertiary barrier. If the wire breaks and is blown out of the stuffing box, the swab valve becomes the secondary barrier and the stuffing box remains the primary barrier. Once the swab valve has been closed and the lubricator bled down and broken out, the swab valve becomes the primary barrier. It is important to remember that the barrier classification can change during an operation. e.g. The barriers available with a tool-string in the hole will be different to the barriers available when the tools are in the lubricator.

168.3 Wireline PCE Pressure Retention Every BOP should be labelled with the pressure class it is certified for. When parts or packing elements are to be replaced, it should be in accordance with the part number for the BOP in question. When shut-in, common ram type BOP pressure assisted if the pressure from above the ram is lower than that on well side. Male and female couplings are usually installed on the hydraulic cylinders so that they cannot be incorrectly connected. Even so, it is still important to check that the hoses are correctly connected and that the BOP is function tested after connecting. A number of different seals are used depending on what the BOP is to be used for. Therefore, you just be able to distinguish between the different types available

169.0 WWE01.01 Testing Requirements Whenever a live well is being worked on or being tested, consideration must be given to the surface handling of produced wellbore fluids. When bleeding off intervention surface pressure equipment and when circulating a well, there will be gas and/or oil produced. These fluids must be disposed of in a safe manner. Gas would generally go to the flare and hydrocarbons to an enclosed tank or drain. There is no one correct method of handling wellbore fluids since the circumstances of each job will be different. The venting of surface equipment may require a line to a closed drain on a platform but can be safely allowed to escape to atmosphere in a desert location. Circulation may be required to the production facility, test separator and the flare on a P a g e | 201

platform or just to a flare pit in a desert location.

The following questions must all be considered. 

How much fluid will be produced?

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Will it be gas or oil?

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Is there any H2S present?

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Is venting from the equipment safe without additional precautions?

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Can the fluids be flared or is there too much water?

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What facilities already exist for handling the fluids?

170.0 WWE01.02 Certification and Compatibility Equipment manufacturers perform shell body test, which is above the equipment’s rated working pressure to provide a margin of safety and reduce the chance of equipment failure on site. The shell body test carried periodically (every 2 years) to ensure fit for purpose.

171.0 WWE01.03 Test Procedures All equipment that is used in operations on the well are to be pressure classified and certified. Pressure testing and certification occurs at an approved workshop. It is still necessary to test the equipment each time it is used. This is normally regarded as leak testing, even though it P a g e | 202

is most often called pressure testing, something that, according to NORSOK, there is only an opportunity for if testing on the equipment occurs at maximum work pressure. A low pressure and high-pressure test are used in accordance with applicable procedures. In most cases, the BOP is tested before rigging upon a test stump but if it is not, testing must occur after the equipment is rigged up. The test procedures for wireline operations will vary somewhat from place to place and country to country. Procedures will be found in the company based or in API Make sure that you have access to the relevant procedures and that you follow them. Whatever details are given in the procedure must be adapted to the equipment rig up. This means that one must consider, for example, whether an inverted BOP is used. An inverted BOP must always be tested from above. Testing of the BOP in a pressure control situation is called an inflow test. It will be carried out approximately as follows: 

Close the BOP.

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Screw the stems in for mechanical protection.

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Bleed off the lubricator.

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Stop bleeding and monitor pressures

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If the pressure does not rise, the lubricator can be removed.

This description of closing and testing the BOP will primarily be used if a leak occurs on equipment above the BOP and when fishing. In other, more general alarm and emergency situations, we will primarily prioritize pulling out of hole and possibly getting ready to cut the wireline so that the Xmas tree and (if necessary) the sub surface safety valve can be closed.

171.1 Inflow Test Testing of the BOP in a pressure control situation is called an inflow test. It will be carried out approximately as follows: 

Close the BOP.

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Screw the stems in for mechanical protection.

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Bleed off the lubricator.

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Stop bleeding and monitor pressures

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If the pressure does not rise, the lubricator can be removed.

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This description of closing and testing the BOP will primarily be used if a leak occurs on equipment above the BOP and when fishing. In other, more general alarm and emergency situations, we will primarily prioritize pulling out of hole and possibly getting ready to cut the wireline so that the Xmas tree and (if necessary) the sub surface safety valve can be closed.

171.2 Emergency Procedures

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Pull out of the well and shut-in if there is time/opportunity. If it is not possible to pull all the way to the surface, then pull so far back that the wire end will be pulled below a possible DHSV, before cutting. Shut-in the BOP and secure it if the problem on your well is leakage.

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If necessary, cut the wire with a shear ram or master valve (or tongs!) before the Xmas tree’s upper valves and if necessary the sub-surface safety valve are shut-in, maximally securing the well. 171.3 Braided Cable Procedures

During any abnormal situation, it is the intervention operator at the controls of the unit who will probably be the first to realise that there is a problem. He is also the person who has control of the equipment and will be present during the intervention. It is therefore the intervention equipment operator's responsibility to make the well safe in the event of any problem occurring. It is usually necessary to remove the DHSV, if it is wireline retrievable, so that deep-set large diameter tools may be run. If the valve cannot be removed, its control must be isolated from any shut down system and the pressure in the control line must be monitored. Similarly, the control for the UMV (or any other tree valve) must be removed from the shutdown system and the valve must be locked open where possible.

172.0 WWG01.01 Leak at the Stuffing Box The first reaction to a leak in the stuffing box would be to stop the wire, using the hydraulic hand pump apply a little pressure to stop the leak. If the above is successful, Pull out of the hole and replace the packing. If the leak cannot be controlled by the addition of further hydraulic pressure, close the BOP, screw in the manual handles, bleed off pressure above, inflow test then open the equipment and repair the leak. It may be possible to replace the top two packing elements as temporary measure to get you out of the hole.

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173.0 WWG01.02 Leak in Surface Equipment Above BOP In the event of such a leak, close the BOP, screw in the manual handles bleed off pressure above, inflow test then open the equipment and repair the leak.

174.0 WWG01.03 Maintaining a Grease Seal When using braided line a grease seal must be maintained around the wire. Leaks from the grease head can occur for a number of reasons: 

Insufficient grease pressure

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Contaminated grease

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Rise in wellhead pressure

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Section of cable that has become too thin

In all such cases, it is necessary to stop the movement of the wire, re-establish the grease seal, and continue with the work. 174.1 Regain a Lost Seal When the Grease Seal is lost, it is usually caused by pulling out speeds being too high, or contamination of the grease. To regain the Grease Seal, stop the winch and increase the Grease Pump pressure and monitor until the Grease Seal has been recovered. If the Seal has not been recovered, the Pack-Off should be applied and the Grease Return Flow Line Valve closed in that order. If this process does not regain the Grease Seal then the Wireline Valve should be closed and grease injected between the Wireline Valve Rams to 1.2 times Wellhead pressure. Seal Recovery: 1. Stop winch 2. Increase injection pressure and observe returns from the return line. 3. If the leak persists, pressure up the pack off and close the return line. 4. If the leak stabilizes, bleed off the return line and pack off to zero. 5. Slowly start pulling out of hole while monitoring the pressure and returns.

Note: Inspect the cable for damage. If the cable is good and there is no leak continue with the operation.

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If the above steps cannot recover the Grease Seal, the BOP (Wireline Valve) should then be closed and Grease injected between the rams. When the Grease Seal has been recovered, the process should be done in the reverse order. Always equalise the Wireline Valve rams before opening the rams to prevent ram seal damage.

175.0 WWG01.04 Cable Rupture One problem that can occur with braided line is that a single outer strand of wire can get broken in the hole and cause a birds nest when pulling out. In severe cases, this can lead to the wire getting stuck in the bottom of the grease head. The winch operator should notice this from a dark spiral mark in the cable being spooled onto the drum where the strand is missing. The weight indicator reading may well fluctuate also as the broken strand balls up in the lubricator. In most cases, if the broken strand is noticed in time, the BOP's can be carefully closed around the wire whilst checking that there is no unusual resistance to closing. This could indicate that the birds nest is across the face of the BOP. After bleeding off above the BOP, the lubricator can be lifted and the damaged strand of wire can be temporarily spliced back in to the main cable to allow it to pass through the grease head.

175.1 Cable Rupture Procedure 1. Stop the cable, close the Wireline Valve and inject grease between the rams until a Grease Seal has been confirmed. 2. Open Needle Valve on Lubricator to bleed off pressure above BOP’s. Ensure that the Wireline Valve is holding before removing Lubricator. 3. Raise the Lubricator a few feet and attach a line clamp to the wireline above the BOP’s. 4. Slack off the cable from the winch and check the clamp is holding. Pull the cable down through the Grease Head and inspect the damage on the cable. 5. There will be a ball of stranded cable, which will have to be cut off and repaired 6. After the cable has been repaired, pick up the tension on the cable and remove the line clamp. Lower the lubricator onto the Wireline Valve and close the needle valve on the lubricator. 7. Inject grease through the Grease Head and equalize pressure across the Wireline Valve before opening the rams. 8. Once the rams are open, slowly move the cable out of the hole.

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In gas wells it may prove more difficult to re-establish the grease seal because the flowing gas can more easily strip the grease out of the flow tubes and the cooling effect of the gas as it expands can thicken the grease. Hydrate formation can also be a problem at this time. Similarly, if the BOP's have to be closed, the top (normal) ram must be closed, the bottom (inverted) ram is then closed and the grease injected between them to establish a seal. The BOP's are designed to maintain a seal with the cable stationary only.

176.0 WWG01.05 Hydraulic Master Valve Control Line Leak In the event that a maser valve loses total hydraulic pressure with wire or cable in the hole will result in that wire being cut with possible valve damage. Efforts should be made to maintain increased pump pressure to allow the wire to be pulled from the well in time to shut the well in. Some hydraulic master valves have a lock out facility to affect temporary repairs.

177.0 WWG01.06 DHSV Control Line Leak In the event that a master valve loses total hydraulic pressure with wire or cable in the hole will result in that wire being cut with possible valve damage. Efforts should be made to maintain increased pump pressure to allow the wire to be pulled from the well in time to shut the well in without accidentally severing the wire.

178.0 WWG01.07 BOP Hydraulic Control Panel Malfunction In the event of power pack failure during the job, apply the hand brake and clamp the wire to the lubricator before commencing repairs. Hydraulic stuffing boxes and BOP's are either hand pump operated, powered from a standalone unit or, if using engine driven hydraulics, will have a small accumulator to allow them to continue to work.

179.0 WWG01.08 Wire Pulled Out of Rope Socket If for some reason (such as running in to an obstruction whilst POOH too quickly or running into the stuffing box) the wire is pulled out of the rope socket when near the surface, there is a chance of the wire being blown out of the top of the stuffing box. In this case, the blow out plug (plunger) inside the stuffing box is designed to stop the wellbore fluids from blowing out.

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180.0 WWK01.01 Drift Runs/Gauge Cutters Most often, a gauge ring will be the first tool ran on a slickline operation. A gauge ring that is just undersized will allow the operator to ensure clear tubing down to the deepest projected working depth; for example, 2 7/8" tubing containing 2.313" profiles would call for a gauge ring between 2.25" - 2.30". A gauge ring can also be used to remove light paraffin that may have built up in the tubing. Often a variety of different sized gauges and/or scratchers will be run to remove paraffin little by little. Gauge cutter can be used for drift runs.

181.0 WWK01.02 Safety Valve Integrity

It is usually necessary to remove the DHSV, if it is wireline retrievable, so that deep-set large diameter tools may be run. If the valve cannot be removed, its control must be isolated from any shut down system and the pressure in the control line must be monitored. Similarly, the control for the UMV (or any other tree valve) must be removed from the shutdown system and the valve must be locked open where possible.

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