Flow Assurance Training Course-1 Underlined (IOGPT) [PDF]

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IOGPT Flow Assurance Training

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TRAINING MANUAL ON FLOW ASSURANCE COURSE DESIGN BY :

AJIT KUMAR, GGM(P) C P SINGHAL, GM(P) RAJAN JAIRAM, DGM(P) A K VARMA, DGM(P) S K VIJ, CE(P) RAJEEV BANSAL, SE(P) – CO-ORDINATOR B RAVISHANKAR, SE(P) NANDINI PANDEY,AEE(P) OMPRAKASH PAL, DGM(CHEMISTRY),HEAD TRG VIPUL GARG, CHIEF CHEMIST, I/C TRG

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CONTENTS • • • • • • • • • • •

Introduction Flow assurance issues and standard terminology Fluid properties & Phase determination Fluid flow analysis for single phase & multiphase Surge Analysis Slug prediction & management Hydrate Formation & Prevention Wax formation & Prevention Asphaltene Prediction & remediation Pigging operation Start up & Shut down

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CHAPTER -1 : INTRODUCTION “Flow assurance is the ability to maintain the flow of oil & gas from reservoir to processing facilities (and beyond to sales point) throughout the field life with minimum life cycle costs” Institute of Oil and Gas Production Technology (IOGPT) envisages to develop flow assurance skills of ONGC personnel. The objective of this course is to transfer and exchange knowledge in flow assurance and operability issues encountered during FDP studies for Onshore ans offshore fields including deepwater and ultradeepwater fields. The purpose of this document is to provide an in-depth review of flow assurance and operability issues and how they relate to system design and day to day operation.

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CHAPTER -2 : FLOW ASSURANCE ISSUES AND STANDARD TERMS The following section summarizes a list of flow assurance basic terminology, commonly used within the industry. Active Heating: Term used to describe an actively insulated system, where energy is added in the form of electricity or heat, in order to maintain the thermal energy of the production fluid. Anti-agglomerate (AA): A substance that is used to prevent hydrate crystals from agglomerating to form a blockage. AA’s are a subset of a group of low dosage hydrate inhibitors (LDHIs), which are a relatively new technology designed to treat production fluids. AA’s typically allow small hydrate particles to form, but prevent their accumulation/blockage of the pipeline. AA’s require a hydrocarbon liquid phase to work and are not particularly suitable for low condensate gas systems. Artificial Lift: Means of increasing production rates and/or decreasing line sizes. Artificial lift provides additional ways to decrease the pressure requirements on a system. Gas Lift – Physically injecting gas either downhole (in the wellbore) or at the base of the riser. Gas lift at the base of the riser is typically only possible for vertical riser towers, and not catenary risers, due to fatigue concerns near the touchdown point. Gas lift may decrease arrival temperatures due to the Joule-Thomson cooling of the additional gas added. Multiphase Pumping – Physical apparatus that allows pumping of a multiphase fluid. From a flow assurance perspective, multiphase pumping offers significant benefits by increasing production rates without additional Joule-Thomson cooling (gas lift) or removing the water (subsea separation). Subsea Separation – Physical apparatus that separates gas, hydrocarbon liquid, and water at the seafloor. The gas is typically sent up an un-insulated flowline, while the liquid is sent up another flowline. Water may be re-injected in disposal wells. This enables two smaller, single-phase flowlines than a large, multiphase flowline. However, by removing the water, the hydrocarbon liquid often arrives at a lower temperature. Further, if water is not separated from the gas/water in sufficient quantities to eliminate a hydrate formation risk, hydrates will still pose a problem. Asphaltenes: Asphaltenes are defined by the ASTM D-3279-90 (IP143/90) test as a solid that precipitates when an excess of n-heptane or n-pentane is added to a crude oil. Chemically, asphaltenes are high molecular weight, polynuclear aromatic, polar compounds containing carbon, hydrogen, oxygen, nitrogen, sulphur and some heavy metals such as vanadium and nickel. The diagram gives a representation of an asphaltene molecule; however, asphaltenes do not have a single, unique structure or molecular weight. •

Asphaltenes are dark brown to black solids.

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Unlike waxes, asphaltenes do NOT melt. Consequently, thermal methods such as insulation, hot oiling, etc. do not work to prevent or remediate asphaltene deposition.

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Asphaltenes are believed to be solids suspended by resins as micelles in the crude oil.

The asphaltene flocculation point is the pressure at which asphaltenes first begin to precipitate given a fixed temperature. Typically the "live" sample is reconditioned to reservoir conditions and the sample is slowly depressurized while observing for asphaltene flocculation. The test method may use one of a number of techniques for detecting the asphaltene flocculation including visual observation, light scattering, filter plugging, etc. If a number of these measurements are made over a range of temperatures, then an asphaltene flocculation phase envelope can be generated as shown below.

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The first pass test is to plot the reservoir pressure minus the bubble point against the in-situ density on a de Boer plot. The de Boer plot was published by Shell and is based upon a number of crude oil samples that have been studied. The de Boer Plot simply identifies regions where asphaltenes are likely to pose a problem. Client - Project de Boer Plot - Asphaltene Prediction 11000

Fluid

Reservoir pressure - Saturation pressure (psia)

10000

Severe Problem

Slight Problem

9000 8000 7000 6000 5000 4000 No Problem

3000 2000 1000 0 500

550

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In-situ crude density (kg/m³)

BML: Below Mud Line. Distance given for reservoir/wellbore depths, measured as the distance below the mudline. This is the distance from the bottom of the sea floor below the earth. BOPD: Barrels of oil per day. BWPD: Barrels of water per day. Bare Pipe: Un-insulated pipe that is common of gas/condensate systems. Typical U-values for bare pipe may be 30 BTU/hr-ft2-°F, depending on the burial depth and sea current velocity. Bathymetry: Seafloor topography that defines any dips and undulations along the flowline route. Bathymetry profiles are used to map out the route and may induce terrain slugging.

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Bottom Hole: Traditional term used to refer to the point at which the fluid enters the production wellbore. This is typically the lowest point modeled in Pipesim/OLGA simulations. The bottom hole is located above the reservoir and typically operates at a lower pressure. The difference between the pressure at the reservoir and the bottom hole defines the inflow performance of the reservoir. Bubble Point: Pressure at which the first bubble of gas appears. For black oil systems, this is the lowest pressure at which the fluid will still be right near the edge of the single-phase region on the phase envelope (single phase liquid). The bubble point is typically a critical parameter used to tune reservoir fluid compositions to measured data. Typically, the bubble point measurements are accurate to within a few psi and the tuning parameters should be set accordingly. Bundles: A number of bundled flowline configurations have been or are currently being installed. There are two main types of bundles, passive and actively heated bundles. Both kinds bundle the flowlines, test lines, methanol lines and umbilicals together inside of a larger carrier pipe. Many different bundle configurations have been proposed. The most common is a simple pipe-in-pipe arrangement. Except for the simple pipe-in-pipe, these bundles require very specialized modeling to accurately simulate the heat transfer in the system, particularly for transient operations such as start-up and shutdown. Unsymmetrical geometries are especially difficult to model. Bundles are most commonly used for hydrate prevention and in the process also prevent or reduce wax formation. They may be used for wax prevention but most likely, only in cases where pigging is not possible. Actively Heated Bundles – Include hot water circulation or electrical heating cables (example diagrams) to maintain operating temperatures above hydrate and/or wax formation temperatures during both steady state and transient operations. These are typically more expensive to build and difficult to operate. The advantages are that methanol/glycol are not required except to protect wellheads and manifolds and the system is protected even during shutdown and start-up. Passive Bundles – Provide a much lower overall heat transfer coefficients than can be obtained with single insulated lines primarily because good insulating materials would be crushed if exposed directly to the hydrostatic pressures in deepwater. For many production systems the passive bundles will allow the operating temperatures to be maintained above the hydrate and/or wax formation temperatures under a range of steady state operating conditions. The passive bundles will also provide a much longer cooldown period during shut-in. However, under startup and long shut-in conditions, methanol or glycol will be required until the system is above the hydrate formation temperature.

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When do you need a bundle? • Perform steady state simulations to determine the pressure/temperature profile of the system assuming perfect insulation (i.e., no heat loss to the surroundings). There will still be some temperature drop due to the Joule-Thomson expansion and potential energy changes. •

If the resulting arrival temperature is below the hydrate and/or wax formation temperature then you will need to consider an actively heated bundle to add energy to the system. No amount of insulation alone will keep the system above the hydrate formation temperature.

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If the system can stay above the hydrate formation temperature with perfect insulation, then determine the actual overall heat transfer coefficient required to stay above the hydrate formation temperature plus some conservatism. One should consider the accuracy of the predictions, projected versus actual flow rates and reliability of fluid samples.

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Identify the most technically feasible and cost effective method to achieve the required heat transfer coefficient. If the required heat transfer coefficient is beyond the range of standard insulation applicable for the producing environment then consider a passive bundle to allow the use of materials with higher insulating values.

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When choosing a bundle, keep symmetry in mind, as it will be much easier to model. Find a company with the capability to perform transient modeling on bundles.

C-Factor: The C-Factor is a measure of erosion tendency for a given system, based on the API RP 14E standard. The equation below contains the formula for calculating the C-Factor in multiphase flow: C − Factor = (3.2808 ⋅ ((BE ⋅ VL ) + (G A ⋅ V D ) + ((1 − HOL) ⋅ VG ))) ⋅ 0.0624 ⋅ ((HOL ⋅ ρ L ) + ((1 − HOL) ⋅ ρ G ))

BE: Liquid Film Volume Fraction GA: Liquid Droplet Volume Fraction HOL: Total Liquid Holdup (BE + GA)

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VL: Average Liquid Film Velocity (m/s) VD: Average Liquid Droplet Velocity (m/s) VG: Average Gas Velocity (m/s)

ρL: Liquid Density (kg/m³) ρG: Gas Density (kg/m³) Essentially, the C-Factor equation given above takes an average density and an average velocity for all phases present. Typical C-Factor limits are 150 for carbon steel and 200 for corrosion-resistant alloy. Flexible pipes have been known to exceed 250-300+. The guidelines provided above are to be used unless otherwise specified by the operator. CGR (Condensate/Gas Ratio): For gas/condensate systems, CGR is the ratio of condensate to gas, typically measured at stock tank conditions. The CGR is typically reported in units of bbl/mmscf and are on the order of 0-50. The CGR is highly dependant on the conditions that it is reported at. You should always determine whether the CGR is reported at stock tank conditions or at pipeline conditions. Casing: One of the many physical barriers used in wellbores to set the production tubing. Casings are typically 9-5/8”, 12-1/4”, 13-5/8”, etc. The casing profile is provided with the wellbore and helps determine the overall heat transfer coefficient (U-value). Within OLGA, the entire casing program is built into the simulation and defined in the radial direction from the production tubing.

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Catenary: Geometric shape for riser trajectory that is typical for steel pipes, as well as flexible pipes. The key dimension required for catenary riser shape definition is the ‘touchdown point”, or the point closest to the topsides facility where the riser is still touching the seafloor.

Typical Catenary Profile 600 TOPSIDES

550 500

Vertical Distance (m)

450 400 350 300 250 200 150 100 50

TOUCHDOWN POINT

0 0

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50

75

100

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Horizontal Distance (m)

Lazy-S – Modified catenary riser profile where the riser is anchored in the mid-point by a buoy, creating a wave in the riser, or a “Lazy-S” shape. This type of riser is particularly prone to slugging.

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Choke: Any valve that is used to control the flowrate, such as a “subsea choke” or a “topsides choke”. The terminology may also be used to describe the action of controlling the flowrate. Cloud Point (a.k.a. Wax Appearance Temperature, WAT): The cloud point or Wax Appearance Temperature (WAT) is the temperature at which the first waxes crystallize from the crude oil. As soon as the pipe wall temperature drops below the cloud point, wax can deposit on pipe walls even though the bulk fluid temperature is still higher than the cloud point. The cloud point is probably the single most important piece of information for evaluating the waxing potential for a new project. For Gulf of Mexico fluids, the WAT is typically near 100°F. If measured correctly, it can be used along with production profiles and thermal modeling of the production scenarios to determine when and where waxes may cause operational problems.

The WAT is directly proportional to the pressure. Cloud points are pressure dependant, and are typically reported for the dead oil only. For live oils, where the pressure may be much higher, the WAT can be significantly higher; the cloud point increases as the pressure decreases below the bubble point. Coiled Tubing: Device used for hydrate remediation, where a long-reaching wire is inserted down a flowline towards the hydrate blockage. Completion Fluid: Fluid placed within the innermost annulus in the wellbore. Typically, the completion fluid is a brine solution that is defined by weight (salt content). Compositional Models: Approach used to characterize a reservoir fluid for flow assurance analysis. Typically, these are broken down into two primary categories: “black oil model” and “compositional model” Black Oil Model – Simplifies composition into a “gas phase” and “liquid phase” and is most applicable to predominantly oil systems. This approach does a fair job of predicting steady state hydraulics, but the compositional effects on wax/hydrates will not be captured. This is an empirical approach to evaluating the phase splits and transport property generation. Compositional Model – More rigorous fluid characterization approach, whereby the entire composition is used as input to generate the physical/transport properties of the fluid. This is required to better predict the interfacial relationships between the gas/liquid phases, particularly

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in gas/condensate systems, where the liquid holdup is critical. The accuracy of the compositional model is highly dependant on the accuracy of the PVT data (i.e. contamination levels, etc.) Conversion Factors: Gas – Conversion factor that converts MMSCFD to kg/s. The gas conversion factor is typically on the order of 0.25 kg/s/MMSCFD. The conversion factor is strictly a function of the molecular weight of the fluid, and is highly dependant on the conditions (phase, pressure) at which the molecular weight is taken. Liquid – Conversion factor that converts BPD to kg/s. The liquid conversion factor is typically on the order of 1.80-2.20 kg/s/1000 BPD. The conversion factor is a function of the conditions (molecular weight, density, phase fractions) at stock tank conditions. Cooldown Time: The time, following initiation of a shutdown, for the system to cool from normal operating temperatures to hydrate formation temperature at shut-in pressure. Dead Fluid (Dead Oil): Oil that contains no dissolved gas, hydrocarbon fluid that has generally been flashed to stock tank conditions and does not present a hydrate formation issue. Typically, dead oils have been de-gassed and de-watered, containing only the hydrocarbon liquid. Depressurization (Blowdown): Transient operation where the system is reduced to a lower pressure (~30 psi for flare systems) following a shutdown in an effort to get the pressure below hydrate formation conditions. For deepwater developments, depressurization often does not reduce the pressure low enough to keep the system out of the hydrate formation region. Key parameters to be evaluated during depressurization analysis are the minimum flowline pressure, minimum topsides temperature, and outlet gas/liquid flowrates. Dew Point: Pressure at which the first droplet of liquid appears. For gas/condensate systems, this is the lowest pressure at which the fluid will still be right near the edge of the single-phase region on the phase envelope (single phase gas). The dew point is typically a critical parameter used to tune reservoir fluid compositions to measured data. Typically, the dew point measurements are accurate to within a few psi and the tuning parameters should be set accordingly. Displacement (Crude Oil Displacement): Transient operation where de-gassed/de-watered crude oil is circulated throughout the flowline. To utilize displacement, a looped flowline configuration must be in place. This is done in an attempt to preserve the flowline from hydrate formation by replacing the resident fluid with non-hydrate formation fluids. Crude oil displacement must be accomplished prior to reaching the cooldown time. Displacement operations must consider the available crude storage, the time to displace the flowlines, and the pump discharge pressures on the crude oil pumps. Typical displacement rates are 1 m/sec and may be increased slightly if time is of the essence. Downhole: Term used to describe the area below the mudline where chemicals may be injected, typically near the bottom of the wellbore. For example, downhole chemical injection assumes that the chemicals will be delivered near the perforations/bottom hole. Drill Center: Concentrated area where multiple wells may be drilled. A drill center may contain a cluster of wells and potentially multiple manifolds. Each drill center may have unique flow assurance challenges, depending on seafloor bathymetry, flowrate, and tieback length. Emergency Shutdown (ESD): Unplanned shutdown of all operations, possibly triggered by a fire on the host facilities or some other catastrophic event. In the event of an ESD, the production fluids will remain in the flowline and are subject to hydrate formation. ESDs present the most severe operating conditions that must be addressed in the design stages of the flow assurance work. Emulsions: Emulsions are two immiscible fluids, with one of the liquids dispersed in the second liquid. Under normal conditions, the two liquids would naturally settle-out and separate into layers. If an emulsion is formed, the liquids become quite difficult to separate, impacting the transport properties of

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the fluid. Emulsions tend to have high viscosities, which can be an order of magnitude higher than either of the two liquids that comprise the emulsion. FBE: Fusion Bonded Epoxy – Coating material, typically applied to the outside of pipes for protection. FBE is applied in thin layers, particularly to bare pipes, and does generally not provide any significant insulating benefits. FBHP: Flowline Bottom Hole Pressure FBHT: Flowline Bottom Hole Temperature FSO (FPSO): Floating (Production,) Storage and Offloading vessel

FWHP: Flowing Wellhead Pressure FWHT: Flowing Wellhead Temperature Finite Element Modeling (FEM): Specialized computational fluid dynamics that involves thermal and hydraulic analysis of complex geometries. Often, FEM is required for hybrid riser towers to ensure the overall heat transfer coefficient (U-value), for heating medium hydraulics within production bundles, and for thermal analysis of subsea equipment such as manifolds, trees, and jumpers. Flash Calculation: Calculation used to determine thermodynamic and transport properties at a given set of conditions. “Flashing” a fluid to a given set of conditions essentially means instantaneously exposing the fluid to those conditions. Flexible Pipe: Pipe that is constructed of several ancillary layers and is typically used for catenary risers and short subsea tiebacks. Roughness values for flexible pipe are considerably higher than steel pipe. Uvalues are on the order of 1.00-1.50 BTU/hr-ft2-°F. Typically, flexible pipes may not be used in highpressure services. Flow Regime: Type of flow that is defined by fluid properties, velocities, etc.

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Annular (Mist) – Flow regime where gas velocity exceeds that for stratified flow and the liquid forms a complete annular ring around the surface of the pipe. Some liquid is entrained as a mist in the gas core.

Bubble (Dispersed) – Flow regime where the gas velocity is very high and the flow-induced turbulence causes the liquid and gas to become well mixed. The gas phase is distributed more or less uniformly in the form of discrete bubbles in a continuous liquid phase.

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Slug – Flow regime that occurs at low gas velocities. The fluids are ordered as alternate slugs of liquid and bubbles of vapor. This flow regime is highly undesirable, and will be discussed in more detail in a later section.

Stratified – Flow regime characterizes by low gas and liquid velocities where the phases segregate with the liquid flowing along the bottom, and the gas flowing through the upper part of the pipe. The interface between the phases is relatively smooth.

Flowline: Portion of the pipeline that spans from the mudline at the tree/manifold through to the riser. Gas/Condensate: Traditional terminology used for a predominantly gas system. Gas/condensates are traditionally found in the North Sea, as well as the Middle East. Gas/condensate systems are typically produced via un-insulated flowlines and continuous hydrate inhibition is used for cold ambient conditions. Primary areas of concern among gas/condensate systems involve liquids handling during transient conditions such as turndown and ramp-up. Gas Injection: Process of injecting gas in disposal wells, typically for reservoir pressure maintenance or for lack of processing facilities on the host facilities. Gas injection may result in changes in the fluid GOR over time, depending on the proximity of the gas injection wells. Gel Strength: The yield stress (gel strength) is the force required to break down the wax structure developed below the pour point, and it determines the pumping pressure required to restart flow in a line. As with pour points, the effects of sample history, the temperature of the fluids before shutdown, the cooling rates, the time of the shutdown and the final fluid temperature can all be significant. These parameters all influence the amount of precipitated wax, the gel structure, gel strength and consequently the pressure required to break it. In pipelines, when a shutdown occurs, the precise effects will differ for

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crudes in various parts of the line. Following a shutdown, crude will cool from a different temperature and at a different rate, depending upon its position in the pipeline. Yield stress is usually measured using model pipelines or controlled strain rheometers. Laboratory data can be scaled up to full size pipelines using the equation below: Restart pressure (Pa) = (4 x length (m) x yield stress (Pa))/diameter (m) Gelled Fluids: Either a water-based or oil-based fluid that is used especially in dry tree riser annuli for thermal insulation. Gelled fluids may be subject to thermal breakdown where the fluid starts convecting, significantly degrading the overall thermal performance. Typically, water-based gelled fluids have a greater overall thermal mass (+), but a higher thermal conductivity (-); oil-based gelled fluids have a lower overall thermal mass (-), but a lower thermal conductivity (+). Geothermal Gradient: Temperature gradient of the ambient soil below the mudline. Typically, a linear geothermal gradient is assumed between the reservoir temperature and the seabed temperature. GOR (Gas/Oil Ratio): For black oil systems, GOR is the ratio of the gas to oil, typically measured at stock tank conditions. The GOR is obtained by flashing the fluid from reservoir (or other, high-pressure) conditions down to stock tank conditions. The GOR is typically reported in units of scf/stb and are on the order of 500-5000. Over time, the GLR is likely to stay constant or increase due to a decline in oil production. The GOR is path-dependant, meaning that a single-stage flash will provide a different GOR than a multi-stage flash to the same final conditions. You should always determine whether the GOR is reported for a single-stage or multi-stage flash. GLR (Gas/Liquid Ratio): For black oil systems, GLR is the ratio of the gas to liquid, typically measured at stock tank conditions. Similar to the GOR, the GLR includes the oil and the water. Over time, as the water cut increases, the GLR is likely to stay constant or even decrease. GUTS (Grand Unified Thermodynamic Simulator): MSi’s proprietary phase equilibria package. Developed as part of a joint industry project with BP, Conoco, Arco, etc., GUTS provides various phase equilibria calculations, as well as detailed wax, hydrate, and asphaltene predictions. The wax module was developed in conjunction with the University of Tulsa, and the hydrate module was developed in conjunction with the Colorado School of Mines hydrate module. HP/HT System (High Pressure/High Temperature): System where the reservoir fluid is at high pressure (10,000+ psi) and high temperature (250+ °F). HP/HT systems often have Joule-Thomson Heating across the wellbore perforations/subsea choke. Additionally, HP/HT systems have the unique challenge of arriving too hot for the topsides processing facilities, so temperature loss during steady state operation is preferred, while maintaining temperature under transient conditions such as cooldown. Hydrate: Natural gas hydrates (or clatharites) are crystalline compounds formed by water with natural gases and associated liquids. The hydrates are solid ice-like crystals composed of cages of water molecules surrounding ‘guest’ hydrocarbon gas molecules such as methane, ethane, propane, etc. Like pure ice, hydrates can block any type of flowline, production tubing, and pipeline. However, unlike ice, hydrates can form at much higher temperatures than 32ºF. Gas hydrates of interest to the petroleum industry are composed of water and the following eight molecules: methane, ethane, propane, isobutane, normal butane, nitrogen, carbon dioxide and hydrogen sulfide.

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Hydrates can form in gas, gas-condensate and black oil systems.

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One cubic foot of hydrates can contain 180 standard cubic feet of gas.

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Hydrate blockages can occur very rapidly. Transient operations such as start-up, shutdown, and blowdown are very susceptible to hydrate blockages because this is when the production system is likely to drop into the hydrate formation region.

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Hydrate formation temperatures are very dependent upon the gas composition. Richer gases (those with higher propane and butane concentrations) will tend to form hydrates at higher temperatures and lower pressures.

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Hydrate formation temperatures are inhibited by brine concentrations.

Hydrate Curves: Temperature/pressure relationships at which hydrates will or will not form. Hydrate formation is exacerbated at high pressure and low temperatures. When presented with a hydrate formation curve, any area to the left of the curve falls within the hydrate formation region, while any area to the right of the curve falls outside of the hydrate formation region.

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Hydrate Dissociation: The process by which hydrates may be remediated through natural dissociation. By reducing the pressure below the hydrate formation pressure at ambient temperature, the hydrate will be in equilibrium with the hydrate formation conditions. Hydrate Formation Conditions 300 280 260 240

AMBIENT TEMPERATURE

220

Pressure (psia)

200 180 160 140 120 100 80 60 40 HYDRATE EQUILIBRIUM TEMPERATURE

20 0 -30

-20

-10

0

10

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30

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50

Temperature (°F)

In doing so, the ambient seabed temperature will be warmer than the hydrate equilibrium temperature so heat will be added to the system. The rate of heat transfer is highly dependant on the U-value of the flowline, as well as the temperature gradient. Hydrate dissociation may be a very time-consuming process, taking on the order of weeks, or longer. Hydrate Inhibitors: Chemicals that inhibit hydrate formation by permanently reducing the temperature at which hydrates will form by changing the thermodynamics. This is the same as adding anti-freeze to water to lower the freezing point. Conventional hydrate inhibitors are methanol and glycols. The hydrate inhibition rates will determine how fast a system may be restarted, as well as the “Light-Touch” time required to treat multiple wells during a shutdown. Hydrate inhibition rates must take into account loses to the vapor phase. Typical hydrate inhibitor rates for methanol are 0.5 BBL MeOH/BBL H2O.

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Hydrate Propensity: Measure of the likelihood for hydrates to form. The difference between the actual temperature and the hydrate formation temperature at operating pressure is calculated. If the actual temperature is above the hydrate formation temperature, then the hydrate propensity is above zero and hydrate formation will not occur. If the actual temperature is below the hydrate formation temperature, then hydrate formation may occur and the amount of sub-cooling is the hydrate propensity. Joule-Thomson Effect: Isenthalpic expansion of a fluid. The result of a Joule-Thomson expansion (JTexpansion) is either an increase or decrease in temperature. The nature of the temperature change is strictly defined by the enthalpy behavior of the fluid over a range of operating conditions. •

A loss in temperature is referred to as “Joule-Thomson Cooling” and often occurs at low pressures (< 6000 psia). The lower the pressure, the more pronounced the impact of the JouleThomson effect. This often occurs as the fluid travels up the riser and loses pressure, or as the fluid is let down to separator pressure across the topsides valve.

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A gain in temperature is referred to as “Joule-Thomson Heating” and often occurs at high pressures (6000+ psia). For deepwater developments, or HP/HT systems, any pressure drop taken across the wellbore perforations or across the subsea choke may result in a slight increase in temperature.

Jumper: Pipe work that links either the tree to the manifold or from the manifold to the flowline. The jumper is often insulated to a much lesser degree than the flowline and may be subject to more stringent hydrate formation criteria. Kick-off Point (KOP): Point below mudline in the wellbore where the well deviates from a strictly vertical trajectory and starts to extend outwards in a sidetrack direction. Kinetic Hydrate Inhibitors: Hydrate inhibitor that does not thermodynamically lower the hydrate formation temperature. What they do is prevent crystals from forming (i.e., they prevent nucleation) and thereby temporarily allow the fluids to be supercooled (cooled below the actual freezing point without crystallization). Typically a kinetic inhibitor will allow 10ºC of supercooling. Margin technology for hydrate control. Kinetic inhibitors prevent hydrate crystal nucleation and growth without emulsifying water into the hydrocarbon phase and thereby temporarily allow the fluids to be supercooled (cooled below the actual freezing point without crystallization). Prevention of nucleation prevents hydrate crystals from growing to a critical radius. Growth inhibition maintains hydrates as small crystals, inhibiting progress to larger crystals. Hydrate inhibitor that does not thermodynamically lower the hydrate formation temperature. Typically the measure of the effectiveness of the kinetic inhibitor is the degree of subcooling a system can operate without forming hydrates. Subcooling (∆T) is the measure of the lowest temperature that the system can be operated relative to the hydrate formation temperature at a given pressure. Typically a kinetic inhibitor will allow 10ºC of supercooling. Marginal technology for hydrate control. “Light-Touch” Time: The time interval, starting at the conclusion of the “No-Touch” Time, where the only actions required to prevent hydrate formation do not impact a subsequent restart. Generally, wells/trees, jumpers, and manifolds are spot treated with thermodynamic inhibitor in this time interval. The “Light-Touch” time requirements are dictated by the number of wells to treat, as well as the chemical deliverability constraints. Line Pack: Line pack is the excess gas stored in a pipeline during normal operation due to operating pressures beyond the minimum required. This is typically done by closing the topsides outlet valve and allowing the reservoir to continue to produce. The pressure will rise in the system due to the additional mass added to the system, combined with the compressibility of the gas.

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Liquid Holdup: Measure of the amount of liquid in the flowline. Liquid holdup may be given as a volume fraction of the pipeline, with 0 equating to no liquid and 1 equating to a liquid-filled pipeline. Additionally, the liquid holdup may refer to the volumetric amount of liquid in the pipeline. For black oil systems, the liquid holdup is relatively insensitive to flowrate. However, for gas/condensate systems, the liquid holdup is a strong function of flowrate. The figure below illustrates a typical liquid holdup profile for a gas/condensate system. Live Fluid (Live Oil): Oil with dissolved gas present, hydrocarbon fluid at elevated pressure/temperature, or other typical conditions that the fluid may be exposed to while in the production system. Live fluids may be prone to hydrate formation. Liquid Holdup vs. Flow Rate 50

45

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Liquid Holdup (BBL)

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Flow Rate (MMSCFD)

Low-Dosage Hydrate Inhibitor (LDHI): Hydrate inhibitor that is injected at a very low concentration, relative to traditional hydrate inhibitors such as methanol. Typical dosage levels are approximately 1/10 that of methanol, but are highly dependant on the maximum degree of subcooling below the hydrate formation region. LDHIs are often very viscous, requiring greater pump discharge pressures. Additionally, LDHIs may not be stable for extended periods of time if left resident in the chemical delivery lines. Manifold: Apparatus, located on the seafloor, which provides a gathering point for multiple wells/trees. A cluster of trees is often linked together, via well jumpers, and all production is routed to the manifold and then directed through the flowline. The manifold is often un-insulated and subject to rapid cooldown during a cooldown.

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Measured Depth (MD): Actual depth below mudline, surface, etc. The measured depth accurately represents the flowing length along which the fluid will traverse. The MD is used in combination with the TVD to accurately define the routing profile. Methanol: Hydrate inhibitor used in most black oil systems. Typical injection rates are up to 25 gpm per well. Mitigation Time: The time interval, starting at the conclusion of the “Light-Touch” Time and ending at the Cooldown Time, where actions are required to prevent hydrate formation throughout the system in a long-term shutdown. Typical example operations are depressurization and fluid displacement. Monoethylene Glycol (MEG): Hydrate inhibitor typically used in gas/condensate services. Mudline (a.k.a. Seafloor): Place where land meets the water. The wellbore is located below the mudline and the seawater is located above the mudline. “No-Touch” Time: The time, following initiation of a shutdown, where no action is required to prevent hydrate formation in a long-term shutdown. No touch times may be different for different components such as trees and flowlines. Typical “No-Touch” times range from 2-4 hours, depending on the number of wells and chemical deliverability. Operating Envelope: Range of flowrates, water cuts, and gas lift rates that can be delivered and do not undergo severe slugging, wax deposition, hydrate formation, or other detrimental operational procedures. PVT Report: Compositional analysis of the reservoir fluids, provided by sampling laboratories such as Oilphase or Corelabs. The PVT report typically contains the reservoir fluid composition, pseudocomponent properties (if any), viscosity, API gravity, GOR, and bubble point. The PVT report may be the single-most critical piece of information required for a proper flow assurance analysis. The fluid properties will significantly impact the overall thermal and hydraulic performance of a proposed design. Perforations: Point in the system where the production tubing in the wellbore “perforates” the reservoir sands. Pipe-in-Pipe: Insulation system where an inner production pipe is surrounding by an outer pipe and the annulus is filled with insulation. The insulation must be protected from the seawater (“dry insulation”), thus the reason for the outer pipe. Typically, the outer pipe must be 2 line sizes larger than the inner pipe (6” x 10”, 8” x 12”) and the U-value is 0.2 BTU/hr-ft2-°F.

IOGPT Flow Assurance Training

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Pigging: Transient operation where a pig is inserted into the flowline and circulated for liquid control in gas/condensate systems or for wax removal in black oil systems. Key parameters to evaluate during pigging operation are the backpressure requirements to prevent gas breakout behind the pig, pump discharge pressures, and pig velocities. Pig: Small, sphere or disc apparatus that is used to sweep a flowline. Primary reasons for pigging may be (1) line cleaning (commissioning, debris cleaning), (2) line management (liquid removal, corrosion inhibitor dispersal, and wax removal), and (3) line inspection (intelligent pigging). A “scraper” type pig may be used for wax removal from the pipe walls, whereas a “foam” type pig may be used to simply clean a flowline and remove any liquids. The drive fluid, or the fluid that forces the pig around, may either be the live production fluid, oil, or gas. For pigging with gas, pig velocity control is a significant challenge.

Pig Launcher: Process equipment that launches a pig Pig Receiver: Process equipment that receives a pig Platform: Collective term given to a host facility that is anchored to the seabed, rather then tethered from a vessel such as an FPSO.

Pour Point: The pour point is defined as the lowest temperature at which the crude oil can be poured under force of gravity. When an oil is at a temperature significantly below its cloud point or Wax Appearance Temperature (WAT), wax crystals can interact to form a matrix structure. Under static conditions, the structure may eventually extend throughout the entire sample, gelling the crude oil. Once this occurs, the crude is said to be below its pour point. However, if a pipeline is shutdown and the fluids in it cool to below the pour point, a semi-solid gel will form which requires an initial yield force to be applied before the gel structure breaks and the fluid begins to flow.

IOGPT Flow Assurance Training

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Productivity Index (PI): Measure of the reservoir performance and is defined by the flowrate achievable for a given pressure drop across the reservoir perforations. As the PI increases, the achievable flowrate increases. Typical PIs for black oil reservoirs range anywhere from 2 bbl/psi to 100 bbl/psi. RKB (Rotary Kelly Bushing): Term given to the point where most measurements are taken from. MD/TVD measurements are often reported as the distance from RKB. Typically, the RKB is located approximately 80 feet above the sea level, so this distance must be subtracted from any measurements to get the true depth subsea or below mudline. Ramp-up: Terminology used to describe the process of increasing the flowrate Reservoir: Location of the hydrocarbon reserves. Reservoir Fluid: Multi-component mixture which is to be produced from the reservoir. Typically, the reservoir fluid composition is the starting point for all flow assurance analysis. The reservoir fluid composition may be defined in a PVT report, supplied by the various testing laboratories. It is useful to categorize fluids into broad categories in order to quickly identify some of the key flow assurance concerns that are likely to occur: Dry gas: Primarily methane gas, which is typically solely gas under all temperature/pressure conditions. In general, no hydrocarbon liquids are formed from the gas (water condensation can occur). In general, gas hydrates are the typical flow assurance concern for dry gas fluids. Wet gas: Similar to dry gas, but containing heavier components. The fluid may be single-phase gas at reservoir conditions. However, a hydrocarbon liquid phase is typically present at pipeline temperature/pressures. As the pressure drops in the system, liquid condensate occurs. Hydrate formation and liquid holdup management are the primary concerns. Depending on the level of condensate, wax may be an issue. Liquid loadings are defined by the condensate/gas ratio (CGR), which typically range from 1 – 50 bbl liquid/mmscf gas Retrograde condensate: Similar to wet gas, but generally containing higher liquid loadings. At high pressures, a pressure drop tends to induce hydrocarbon liquid dropout. At low pressures, the liquid may re-dissolve into the gas phase, resulting in lower liquid loadings. The magnitude of the liquid dropout is highly dependant on the fluid phase envelope and path of production (temperature/pressure profiles). Condensates are generally low molecular weight systems, with methane concentrations still in excess of ~70 mole%. Volatile oil: A fluid that exhibits both gas/condensate behavior and black oil behavior. Volatile oils contain more heavy components than condensates, but have a low enough molecular weight to not necessarily be considered black oils. Fluid conditions at the reservoir are often near the critical point, which may induce two-phase flow from the reservoir as the pressure is decreased.

IOGPT Flow Assurance Training

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Volatile oils may start out as single-phase oils in early-life, but can become multiphase mixtures as the reservoir pressure declines. Black oil: Common term for a predominantly liquid-filled system. Black oil is a generic term that encompasses a wide range of heaver molecular weight fluids. As the pressure drops along the pipeline, gas is released from the liquid and forms a gas phase. Black oils are typically characterized by their gas/oil ratio (GOR), which may range from