Allocation Measurement [PDF]

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ALLOCATION MEASUREMENT

Class #7010 Jeffrey L. Savidge “ The first requirement of gas measurement is accuracy” D.A .Tefankjian ISHM Lawrence Reid Award Recipient, 2000

INTRODUCTION

Allocation is the process of assigning the proper portions of aggregated product flows back to individual source streams, owners, leases or measurement point. The assignment process is a standard method that is agreed upon and used by contracting parties. It is designed and intended to be fair, cost efficient and practical. By providing an efficient product sales transaction mechanism, allocation measurement helps to reduce capital and operating costs without jeopardizing the principal goal of fair treatment among parties. Reducing fluid measurement costs facilitates the development of marginal fields. Allocation measurement can fall under federal or regulatory guidelines. Individual agreements must meet or exceed those guidelines. API MPMS Chapter 20.1 is the industry’s allocation measurement standard. Without it volumes of technical measurement documents would be required to accompany commercial contracts. The first edition of API 20.1 was prepared in 1993 and recently reaffirmed in 2006. Its scope is to provide a set of design and operating guidelines for implementing liquid and gas allocation measurement systems. As such, it provides recommendations for metering, static measurement, sampling, proving, calibrating, and calculation procedures. Due to the breadth of the measurement topics covered under allocation measurement, API Chapter 20.1 focuses on identifying procedures, providing practical and technical guidance in implementing allocation metering systems, and acts, in part, as a master guide to other important measurement guidelines. Individual allocation meters determine the portion of flow that is attributable to an individual source stream. The allocation meters may or may not meet custody transfer standards, although the total production should be determined with custody transfer quality systems and procedures. For example, it may be necessary to use multiphase metering with a higher degree of uncertainty at some sites in order to reduce the requirement for separation equipment. Commingling of fluids with differing qualities and properties leads to the need for periodic testing and validation in order to better define the quality and quantity of the streams. Design, measurement equipment, and practice choices must be made but they must be applied in a fair and uniform manner throughout the system. Ultimately, the quality and quantity determinations in an allocation system must represent the contributions from each individual source stream - lease contribution. Existing custody transfer standards form much of the basis for the measurement methods used in allocation. If Chapter 20.1 does not specifically address a measurement issue, then it should be assumed that the appropriate custody transfer standards apply for that issue.

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Allocation measurement is a vast subject and requires volumes to cover it in its entirety. The purpose of this paper is to serve as an introduction to allocation measurement. It is not a complete exposition of allocation measurement. It is intended to identify some basic concepts, terminology and definitions that are at the foundation of allocation measurement systems. Students are referred to API MPMS Chapter 20.1 for further guidance. ALLOCATION BACKGROUND

A conceptual allocation measurement system can be visualized by first considering an idealized allocation system. The idealized system would consist of numerous liquid and gas inputs and a single gas and liquid output. In a perfectly idealized measurement system the sum of the liquid and gas inputs into the allocation system would be exactly equal to the total liquid and gas output from the system over a given time interval. A particular input stream meter would read the exact contribution of the stream relative to all of the other stream contributions for a given fluid phase. It would provide a perfect material balance of all of the fluid mass into the system at different points and all of the fluid mass out of the system. There would be no measurement discrepancies. Everything into the system would be completely accounted for and output from the system. Such a hypothetical idealized system would be where: (1) measured product(s) would not change their fluid state condition (phase and physical properties) with changes in operating conditions, (2) one meter type can make perfect measurements at all operating conditions, in any fluid phase, for any fluid type, and over any flow range, (3) all meters in the entire system work perfect out of the box, do not wear out, do not have problems regardless of weather, do not have corrupted data, do not need adjustment factors and accurately correct for missing data and data intervals, (4) the exact amount of product (hold-up) that is remaining in the entire system is known and no product loss occurred within a given time interval. Clearly the above hypothetical system does not exist. Allocation measurement systems and procedures are used to provide the designs, equipment, measurement methods, corrections and, processes that are necessary to account for the uncertainties that arise in everyday allocation measurement applications. Allocation measurement is the process of accounting for all of the physical changes that occur to fluid products and to the system that is used to measure and contain them. Some concepts behind allocation that makes corrections to the idea hypothetical system are listed below. (1) The first concept is one of normalizing higher uncertainty input measurement quantities into an aggregated flow stream and then scaling all of the input quantities based on the assumption of a more accurate measurement of the total flow. The first

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assumption is that normalization works and the errors are proportionally applied and fair for all parties. (2) The second concept behind allocation is one of separating the phase streams to try to reduce the uncertainty in the overall measurement process. (Multiphase technologies are offering challenges to the concept of separating the phases). In general, separating the phases has a lower uncertainty and is simpler (i.e. the application of the K.I.S.S. principal in measurement). (3) The third concept behind allocation is an extension of (2). It is to choose the appropriate (translated as the most practical with lowest risk) measurement technology suited to the particular phase, task, and risk tolerance. (4) The fourth concept behind allocation is that the input fluid characteristics must be corrected to standard output sales conditions due to the changes that occur to the physical properties of the fluids from the fluid injection points into the system to the sales point. Correction factors are applied to account for fluid property changes. (5) The last idea is one of inventory management. The entire allocation system holds a certain amount of product in it. It takes time to move the product from the injected metering point to the stock tank and beyond consequently a time based balance is required.

Allocation, as practiced in API Chapter 20.1 covers range of measurement methods that includes liquid metering, gas metering, and multiphase metering. Volumes (vs. masses) of books, standards and articles have been written on the many aspects of metering technologies that are used in allocation. The type of meter selected for a specific application depends on the fluid phase that is being measured and the targeted level of performance. Many different types and designs of meters are common and in use. The purpose here is not to review all meter types and their performance, rather it is to provide a general overview and identify concepts that are important to remember regardless of the type of meter. The most widely used meters in liquid measurement are positive displacement and turbine meters. The most common meter for gas measurement is the orifice meter. Multiphase metering consists of hybrid measurement systems and concepts to deduce the proportion and flow rate of each fluid phase.

LIQUID QUANTITY MEASUREMENT Different types of liquid measurement meters are used in allocation. They include displacement meters, differential meters, tanks, direct mass measurement devices, indirect mass measurement devices and others. Each meter has its own issues. The reader is referred API Chapter 20.1 and to the appropriate standard document listed in the references for their type of meter. Properly characterizing the fluid phase is important for accurate measurement.

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When liquids are measured at operating temperatures and pressure gases evolve. The evolved gases will affect the performance of the meter and fluid properties. Gases measured at or near saturation conditions will contain condensable components that affect the gas and liquid phase quantities. Special effort should be made to minimize the pressure drop in the system to avoid erroneous measurement due to gas break out from the liquid. The following general procedure should be used: 1. 2. 3. 4.

Select and size the flow meter Install the flow meter upstream of a control valve Minimize the distance between the separator outlet and the flow meter Locate the flow meter below the liquid level in the test separator

The meter should be constructed of a material that reduces the possibility of erosion and corrosion due to abrasives, corrosive chemicals, temperature and pressure of the produced stream. If temperature affects the performance of the meter then insulation or heat tracing the meter should be considered. Liquid Meters Positive displacement meters A number of factors influence the performance of displacement meters. The factors manifest themselves through changes in the fluid viscosity and are caused by water cut, oil density or gravity, and temperature. Consistent meter performance can be achieved by using similar measurement procedures, proving methods and types of equipment at all allocation facilities. System design and equipment selection should follow API MPMS Chapter 5.2. Positive displacement meters (PD) are volumetric meters. They measure discrete volumes mechanically as liquid passes through the meter. The volumes are measured by means of rotating compartments or cavities which are repeatedly filled and discharged. The sum of the discrete volumes is the quantity of fluid measured through the device during a given time period. The device works by internally rotating defined volumes that permit well defined amounts of liquid to pass through the device. The number of rotations per second provides a frequency which gives a known volume per second. The total volume is counted and displayed on a totalizer. Positive displacement meters produce one pulse per unit volume. The basic flow rate equation can be expressed as:

Qv = Volume per _ revolution x Rotational speed − leakage The equation illustrates the issues that can arise with the output from the meter. Anything that influences any of the terms in the equation will affect the measurement results. The influences can be mechanical ones caused by the installation of the meter or fluid ones caused by the state of the fluid. For example, if the fluid flashes into the two phase region in a PD meter, the rotational speed (frequency) with increase and the readings from the meter will be overstated.

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This can cause over- spin which will not only result in inaccurate measurement but may damage the meter internals. Positive displacement meters are accurate as long as they operated within their specifications.

Turbine meters Turbine meters are bladed rotors that rotate due to the flow of fluid in the pipe. They are velocity sensing devices. Ideally, one revolution of the rotor represents on complete length of the axial screw giving a calculable volume of fluid. The meter outputs a sinusoidal wave form which provides input to the pulse stream for the totalizer or flow computer. The speed of rotation is proportional to the flow rate. Turbine meters determine the flow by producing a stream of pulses which is proportional to the fluid flow rate through the meter. The pulses are totalized to obtain the measured volume obtained over a given time period. The meter must be calibrated and the totalizer must be programmed with the correct k-factor in order to obtain an accurate gross amount. Fluid drag forces impede rotation and can lead to non-linear performance. Turbine meters are sensitive to a number of fluid and flow stream effects. Poor performance will be achieved if a turbine meter is located downstream of bends or in commingled flow locations with high swirl and turbulence. These conditions should be avoided. Flow conditioners placed upstream of a turbine meter will aid in producing a consistent flow profile and performance for the meter. If a flow conditioner is not used than the upstream length should be at least twenty pipe diameters and the downstream length at least ten. METER CORRECTIONS

Allocations systems must meter fluids from multiple wells and fluid types. The individually metered streams are then combined with other fluids from other streams into a commingled stream. The measured volumes and analysis are used to determine what fraction of the amount in the commingled stream is to be “allocated” to a specific well. As mentioned in the introductory section one of the challenges is to convert gross indicated volumes, Qindicated from the allocation skid to net volumes, Qnetat the output meter. API Chapter 20.1 provides a more detailed discussion of these quantities. This is only an overview. A number of corrections must be made to obtain net volumes from the indicated volumes. Meter Factor (MF) This factor corrects the indicated volume to actual volume metered. It is determined by meter proving. If the indicated volume is 100 barrels and the meter factor is .99 then the actual volume is simply the indicated volume times the meter factor which in this case would be 99 barrels. CTL factor The factor provides a correction that converts gross volumes to standard volumes at the temperature base, 60 °F. This is to be applied only when there is not mechanical correction or a real-time system that is doing it. This is found in Table 6-A for

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generalized crudes. The API gravity is first determined and then corrected to base conditions using Table 5A. This is important. Different fluids expand differently to changes in temperature. The rate of expansion is the coefficient of expansion, C of E. After the corrected gravity is obtained and the flowing temperature determined, CTL is obtained from Table 6A and then applied to the gross volume. Shrinkage factor (SF) Allocation measurement points are typically at conditions which are in the two phase region. Consequently, the liquid is at its bubble point condition (equilibrium vapor pressure condition for the mixture), and the gas phase is at its dew point condition. When the liquid is depressurized to stock tank conditions at atmospheric pressure, the light hydrocarbons and gases evolve from the liquid phase. This causes a reduction in the volume of the liquid, i.e. shrinkage. A term needs to be applied to account for the change in the measured liquid volume from its high pressure metering condition to the stock tank condition. If oil is metered at a pressure above atmospheric then light hydrocarbons will be absorbed into the oil and the meter will indicate a larger volume than will be recovered at the sales point which is atmospheric. The oil needs to be stabilized to insure equilibrium conditions. The volume correction may be determined by direct measurement or by various calculation procedures that utilize measured values. A representative sample needs to be obtained to determine it in the laboratory. The sample must be handled and transferred into a known volume properly. Various laboratory tests are applied to provide a measured shrinkage. Sediment and Water (S&W) Sediment and water are in the flow stream and are important quantities that must be determined for the final result of the allocation measurement process. S&W must be deducted from the delivered volume by multiplying their percentage against the delivered volume. Any stream delivering production to a gathering system requires a sediment and water analysis. In general this is defined by contract which is typically stringent and in the worst case cannot exceed 1%. The total S&W barrel correction is determined by multiplying the total volume measured by the percentage of S&W. The barrels S&W are then subtracted from the total barrels metered. Techniques used to determine water in liquids samples include: 1. Centrifuge method (API MPMS Chp.10.3,10.4) 2. Distillation method (API MPMS Chp 10.2) 3. Karl Fischer method (API MPMS Chp. 10.9) Determiniation of the sediment and water content should be in accordance with API MPMS (Chps 10.1, 10.3, 10.4, 10.8). Net Volume The net volume is the indicated volume corrected for all of the changes that can be accounted for to the reading by the meter factor, CTL factor, shrinkage factor and sediment and water factor. In equation form it is expressed simply as:

Qnet = Qindicated × MF × CTL × SF × S & W

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CPL factor This factor corrects volumes to standard condition volumes. It is a small correction for low pressure crude oil where the system pressure is low or near atmospheric conditions. In light crudes it can be significant. This depends on the gravity, temperature and pressure conditions. CPL – correction used to correct volumes back to the standard base pressure of 0 psig (atmospheric or 14.696). This correction factor is found in API tables 11.2.1. CPL = 1 / (1 – (Po-Pe)F Where, Pe = equilibrium pressure of the fluid measured Po = operating pressure in psig Where F = compressibility factor This factor is often misapplied, consequently it is important to understand the context for the application of the factor. Special care must be exercised when applying this factor so review its application in API 20.1. METER PROVING

No meter is perfect. The goal of liquid meter proving is to establish a factor to get obtain the corrected volume. The factor is multiplied by the meter pulses from a turbine or PD meter and divided by the nominal K-factor to obtain the corrected volume. In general a known volume is used to determine the discrepancy between a meter’s indicated volume and the actual volume. The known volume can be provided by a volumetric prover or by a master meter. Explanations for the terms in the equations listed below are provided in API Chapter 20.1. They are not repeated here for brevity. In general they are used to provide corrections to the meter volume, e.g. correction for temperature, pressure and performance. The prover meter factor is given by:

MF =

BPV × (CTS p × CPS p × CTLp × CPLp ) MRV × (CTLm × CPLm )

A master meter is a meter that acts as a secondary standard for proving another meter. Typically a turbine or PD that meets proving performance criteria is used as a master meter. Master meters must be proved at a rate approximating the service flow rate and the fluid used to prove the master meter must be similar to the line fluid. This prevents changes in the meter factor due to changes in the flow rate or changes in the fluid

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calibration curve due to fluid properties. Every meter is different so a new meter factor is required along with the operating range for the master meter.

The master meter factor is:

MF =

MMV × ( MMF × CTLmm × CPLmm ) MRV × (CTLm × CPLm )

LIQUID SAMPLING

The components of the liquid stream are important to be accounted for both qualitatively and quantitatively. Spot sampling or automatic sampling may be used. A representative sample is required to complete the proving process and is needed to correct the metered liquid for the API gravity. Samples should be collected at the time of proving and include a third party sample for independent validation. Care is required to present losses of light ends when transferring samples. Samples should be collected by a proportional to flow sampler. Calibrated centrifuge tubes and certified hydrometers should be used to determine the gravity and S&W content of the liquid. ACCOUNTING

Allocation accounting quantifies each of the items identified at the start of this paper. (1) Corrections for the production amounts for the input meters. These are theoretical amounts based on the input. They have not been balanced by the total output from the system Theoretical production = Indicated volume × MF × CSW × CTL (2) Normalization of all the input quantities over the entire system relative to the output quantities. This is used to make the entire allocation system whole and to eliminate measurement discrepancies due to uncertainties in the entire system.

Corrected production =

Source theoretical production × Total system corrected production Total system theoretical production

(3)Time period based inventory accounting is used for the total quantities and the injection points. The volumes stored in the system are the inventories or stock. Opening inventories are the previous accounting period’s closing inventory. Closing inventories for the accounting period are the production plus the opening inventory minus the sales.

Total system corrected production

= Sales + Closing inventories − Opening inventories

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GAS QUANTITY MEASUREMENT

Custody transfer measurement requires the quantities metered to be as accurate and precise as practically achievable. In allocation it is essential that individual metering systems be similar and treated equally. In practice this may be difficult to achieve since it depends on the characteristics of the fluid stream. The gas stream measurement determines quantities that affect the liquid stream and visa versa. The effect depends on the composition of the gas and the composition of the liquid streams. The presence of liquids in the gas stream will cause errors in the measurement. The size of the error depends on the amount of liquid and the type of meter. It is not possible to predict flow coefficients or meter factors for two or three phase flows. It is nevertheless assumed that since all of the systems are operated and designed in a similar fashion, the allocation resulting from the indicated volume will be fair and representative for all producers and interest owners. Periodic well tests are utilized to determine the quality and quantity of each phase in the well stream. Factors are used for the gross indicated volume that approximates the volumes of gas, water and hydrocarbon liquid that may actually be flowing through the meter run. Tests may be performed monthly, quarterly, semiannually, or annually. The factors are used for the entire period of time between test periods. For systems which are not multiphase, chromatographic analysis is the workhorse. It is used to develop the information necessary to perform the allocation calculations. The analysis is also used to determine the energy content as well as the recoverable hydrocarbon content from the gas stream. By knowing the gross metered volume and the quality of the stream determined the chromatograph at each location and the custody transfer quality determines of the total quantity of gas and liquid streams derived from the allocation system, both the gas volumes and the liquid volumes from the production can be allocated. It is critical to have a reliable and consistent gas stream measurement that is reflective of the volumes and quality of gas injected into the system. Multiple types of gas meters may be used in allocation measurement of the gas stream. This includes differential devices such as orifice, venture and wedge type meters, displacement meters, turbine meters, mass meters, insertion turbine meters, vortex shedding meters and ultrasonic meters. The scope of the discussion here is limited to an overview. It will not discuss each metering technology. Other sessions address these devices in much greater depth. GAS METER PROVING AND CALIBRATION

API 20.1 recommends that proving for the determination of oil, water and gas production rates be performed at least semi-annually. GOR should be determined at least annually. Differential pressure measurement devices and associated instrumentation shall be tested and recalibrated at least every six months. The orifice plate shall be removed, inspected and replaced (if necessary) at least every six months. The meter tube shall be inspected and repaired at least every six months. Depending on the results of meter tube inspections it may be necessary to change the frequency of changes in order to maintain the primary element within specifications. All

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calibration equipment must be traceable to a National Institute of Standards and Technology (NIST) standard. Calibration equipment should be certified at least every two years against a NIST traceable standard. Certification must be documented. GAS SAMPLING

Gas allocation measurement requires that the quality of the gas be determined. This is accomplished using proper sampling procedures. The sample must be obtained from the flowing stream through a probe inserted at the top of the pipe. The location of the probe is critical to its ability to provide a representative sample and should follow procedures in API 14.1. It should protrude into the pipe to a location that samples from the center third of the pipeline. This procedure includes both spot and automatic/composite sampling. The same sampling procedure should be used at each sampling location, i.e. consistent application of the sampling method. Gas sampling procedures are necessary to insure both accurate gas and liquid allocation results. Inaccurate gas analysis will propagate into inaccurate allocation results. Gas sampling should be performed at a minimum semi-annually. Refer to API 14.1 for details on sampling procedures. In general there are multiple spot sampling procedures. These include: (1) (2) (3) (4) (5) (6) (7)

Purge and fill methods Constant purge methods Evacuated cylinder method Reduced pressure method Liquid displacement method Helium displacement method Free floating piston method

Automatic/composite sampling collects many small representative increments of gas of a given time period. If individual samples are obtained proportional to the flow then a more representative sample may be obtained. This is important when the composition of the gas varies during the sampling period. The value of the gas volume measured at the wellhead or producing location it is necessary to determine the energy content or the recoverable liquid content from the flow stream. It is especially important that the gas be of sufficient quality to meet marketable quality specifications prior to delivery into the transportation system. The energy content of a stream determines its relative value. A gas stream with high energy contains significant quantities of hydrocarbon liquids. The liquids may be extracted in a natural gas processing plant and sold as raw or fractionated product at the outlet of the plant. The energy content may be determined by multiple methods including calorimeters, therm-titrators, energy flow meters, or they may simply be calculated from the gas composition of the stream determined by a gas chromatograph. The recoverable hydrocarbons liquid serves a means to evaluate the quality of the gas stream. The higher hydrocarbon ends may be determined using compression test gar apparatus, charcoal testing or chromatography. The higher the concentration of heavier hydrocarbons, the higher the quality or value of the stream tends to be. By knowing the approximate percentages of each

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component from the analysis of the gas stream from each producing location, it is possible to estimate the quantity of liquids and the remaining residue gas from each producing location. GAS ALLOCATION CALCULATIONS

Each gathering system tends to be unique and will have its own allocation needs. Methods to account for the fuel gas, lift gas, flare and other uses must be included in the design of the allocation system. The gas allocation system should be review by all production, design, operations, and accounting groups for validity and consistency. Gas allocation is an exercise in normalizing the compositions and volumes of the input gas streams to the actual output amounts. In practice it may be difficult to determine all of the necessary quantities so assumptions may be necessary to make when data are not available or provided by other parties. Regulatory groups require that the total gas produced be determined on a periodic basis. It is useful to calculate this number and report it on all locations. Allocation calculations should account for 100 percent of sales and shrinkage caused by phase changes and changes in operating conditions. This can be done on a volume basis or energy basis. The last step in the gas allocations prorates each volume to actual field or system sales.

MULTIPHASE QUANTITY MEASUREMENT

Multiphase meters are hybrid metering systems. They can use elements from other phase measurement technologies and combine them into a single package. The goal is to simultaneously determine the amount of gas, oil and water. Multiphase meters provide a raw aggregate volume reading that is converted into volumes for each phase. The amount of each phase may be determined during periodic well tests or determined from the meter depending on the type of technology that is used. The composite volume is then used in allocation calculations. Full stream densities (gravities), phase densities (gravities), and factors that establish the relation among the gas and liquid phase volumes relative to their aggregate volumes are established periodically. The factors should be established at representative rates, and operating conditions for the system. It is difficult to prove these systems. Proving should not be conducted at conditions that are substantially different than the range of conditions experienced in the field multiphase system otherwise the uncertainty will be significantly increased. Equipment that is used to determine the rates and properties of single phase streams in the proving system need to be calibrated in accordance with appropriate industry practice, guidelines and procedures. A.G.A. /API MPMS guidelines should be used for gas meter proving. Oil/condensate proving should be conducted using API MPMS procedures. Water meter proving should be traceable to N.I.S.T. standards. Proving with a single phase metering device away from the metering location should be performed with fluids as similar to the fluid being metered as practical. A flow test laboratory such as CEESI’s Wet Gas / Multiphase Flow Laboratory or others with similar fluid and range capabilities can be utilized to validate over all multiphase procedures from single phase to multiphase.

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MULTIPHASE SAMPLING

There are no methods or standards available that guarantee a representative sample of a multiphase fluid to a known level of uncertainty. This is a problem in that it can significantly increase analytical uncertainty. In general, the gas, liquid hydrocarbon phase, and liquid water phase have to be separated into single phases and then independently sampled. Once a full well stream is separated, sampling can be achieved by spot sampling or composite sampling proportional to the flow. Flow test laboratories should be utilized to validate the results obtained from multiphase sampling procedures to establish uncertainty limits for particular fluid types and fluid loadings. CEESI’s Wet Gas / Multiphase Flow Laboratory or similar capability laboratories can be used to validate multiphase sampling procedures. PROVING AND CALIBRATION

Currently, no method exists to prove multiphase flow meters within clearly defined uncertainty targets. The multiphase stream must be separated into individual phases that are proven or calibrated using single phase methods. Separation is accomplished using a three phase separator. The volume of gas, liquid hydrocarbon and water are then metered. Again, CEESI’s Wet Gas / Multiphase Flow Laboratory or similar capability laboratories should be utilized to provide definitive uncertainties for a given set of fluid characteristics, operating conditions and fluid loadings. MULTIPHASE CALCULATION PROCEDURES

Liquid and gas samples must be recombined mathematically based on analytical and gas-oil ratio data as measured in the field. The liquid condensate yield of the gas stream is estimated from the separator analysis and is expressed in gallons per standard cubic feet (GPM), barrels per million standard cubic feet (bbl/mmscf), or gas-oil ratio. Volumetric data and analytical data are collected to perform a full-well stream recombination and subsequently used in volume calculations for allocation purposes. The total effluent from two or more wells may be delivered as “commingled” streams into a common separator. This is efficient in that it reduces installation and maintenance costs and centralizes separation. However, it can raise questions and may lead to errors. Production and deliveries of liquids and gas are reported in a single set of records. An equitable distribution of the products in the stream of each well contributing to the system must be accomplished. State and federal agencies mandate that accurate records of the volumes of both gases and liquids produced by each well be kept. Independent information is also needed to settle questions arising on mineral ownership, proration, legal positions, taxes, and to provide data for reservoir evaluation. When there is no separation equipment used at a location, the amount of stock tank fluid produced by a single well cannot be determined. Separator testing must be performed at regular intervals to determine the quantity and quality of the effluent from each well. The frequency of the tests is usually determined by the contract

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between participating parties. Typically these tests are conducted on a quarterly or semi-annual basis. In some cases monthly tests may be needed. CONCLUSION

The purpose of this paper has been to provide just an overview of allocation. Since the industry and measurement technology is quickly evolving it is important to keep up with developments. Technologies like multiphase metering and ultrasonic measurement are improving. Technicians need to keep abreast of these technologies and their value and utility for allocation measurement. Lastly, as previously stated by others, measurement results must be proven, not assumed. TERMINOLOGY

Below is a listing of terms and definitions that are commonly applied in fluid allocation applications. Allocation measurement Measurement using metering systems for individual production leases or wells and specific procedures to determine the percentage of hydrocarbons and associated fluids or energy contents to attribute to each lease, well, or working interest owner, when compared to the total production from the entire affected reservoir, production system or gathering system. Charcoal test A GPA test method that can be used to determine the natural gasoline content of natural gas. Commingle Streams of fluids (generally hydrocarbons) which have been combined from two or more wells or production facilities into a common pipeline, tank or vessel. Compressibility factor The ratio of the actual volume of gas at a given temperature and pressure and gas composition to the volume of the same gas when calculated by the ideal gas law. Condensate Liquid formed by the condensation of a vapor. In the context of allocation, it is the hydrocarbon liquid that is separated from natural gas because of changes in pressure and temperature when the gas from the reservoir is delivered to surface separators. CPL CPL is the volume correction factor for the effects of pressure on liquid.

Cricondenbar

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The highest pressure at which liquid and vapor phases can exist at equilibrium in a multicomponent system. Cricondentherm The highest temperature at which liquid and vapor phases can exist at equilibrium in a multicomponent system.

CSW Sediment and water correction factor to adjust for material coexisting with, yet foreign to, petroleum liquid. CSW = (1 – S&W 1100).

CTL CTL is the volume correction factor for the effects of temperature on liquid (refer to API MPMS Chapter 12.2, Paragraph 12.2.5.3). Full Well Stream The total quantity of produced fluids from a producing well. Gas-oil ration (GOR) The ratio of gas to liquid hydrocarbon produced from a well. It may be expressed as standard cubic feet of gas per barrel of stock tank liquid. GPM Liquids in gallons of hydrocarbon components per 1000 standard cubic feet (mcf) of natural gas. Indicated volume The difference between opening and closing meter reading. Immiscible Liquids which do not mix to give a homogenous single phase solution. LNG Natural gas which has been completely liquefied by using extremely low temperature processes. It is predominately methane but can contain other light hydrocarbon components. It is very dry. MCF Abbreviation for thousand cubic feet of gas. MMCF Abbreviation for million cubic feet of gas. Multiphase

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Fluid from a well or flow line that is composed of any combination of distinct fluid phases, e.g. vapor phase and one or more liquid phases. Typically it is a combination of a hydrocarbon vapor phase, a hydrocarbon liquid phase, and a water liquid phase. NGL (natural gas liquids) Natural gas liquids are those hydrocarbons that are liquefied at the surface in field facilities or in gas processing plants. Natural gas liquids include ethane, propane, butanes and natural gasoline. Pipeline condensate The liquid formed in a pipeline caused by a phase change from gas to liquid. Phase changes occur due to changes in temperature, pressure and composition.

Raw composite volume The uncorrected, indicated multiphase volume determined by a full well stream metering system. Shrinkage Reduction in volume caused by the removal of constituents from a fluid due to changes in the operating conditions. Shrinkage factor (SF) It is the ratio of liquid volume at stock tank or some defined intermediate conditions to the liquid volume at some other condition (e.g. metering condition). Changes in the liquid volume occur due to changes in pressure, temperature and composition, i.e. PVT. Retrograde condensation Condensation that occurs with a decrease in pressure or increase in temperature. Specific gravity The ratio of mass of a given volume of a substance to of another substance of equal volume used as a standard, e.g. air is the standard for gases and water is the standard for liquids with the volumes measured at 60°F. Stabilized liquid It is used to refer to a hydrocarbon liquid which has reached it equilibrium condition. The equilibrium condition means that there are no temperature, pressure or composition gradients in the fluid which will cause it to change it properties, e.g. its density or volume. Stabilized condensate Condensate that has been stabilized to a definite vapor pressure. Stock tank Storage tank used to store hydrocarbon liquids (stock). Stock tank conditions are defined to be atmospheric pressure and 60°F.

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Temperature correction factor A factor for correcting the volume at a given temperature to that at a specific reference temperature, e.g. reference temperature is typically 60°F. Theoretical production This is the volume of liquid product (e.g. crude oil) corrected to stock tank conditions of temperature and pressure. Uncorrected totalized volume The volume that is registered on a totalize to which no adjustments for temperature and pressure have been applied. Water cut The volume percent of water in a hydrocarbon and water stream. Weathering The evaporation of components from a liquid caused by exposing it to atmospheric temperature and pressure conditions. Use of heat causes partial weathering. Weathered oil Stabilized condition (equilibrium condition) for crude oil. No changes in fluid composition or liquid volume due to shrinkage.

ACKNOWLEDGEMENTS Appreciation is expressed to Ray Gray for his ISHM 2005 paper on allocation which helped provide a framework of material for this paper without getting into all of the details associated with allocation and to L. Zeringue for his patience. Students are referred to the references to obtain an understanding of detail allocation and metering methods that are beyond the scope of this class paper. ALLOCATION RESOURCES R. Gray, Liquid Allocation Measurement, ISHM 2005. MPMS CHAPTER 20.1 – Section 1, Allocation Measurement, API, 1st Ed. 1993 Code 101-43 Standard Compression and Charcoal Test for Determining Natural Gasoline of Natural Gas AGA Report No. 7 Measurement of Gas by Turbine Meters RP 12R1 Recommended Practice for Setting, Connecting, Maintenance, and Operation of Lease Tanks Std 2545 Method of Gauging Petroleum and Petroleum Products Std 2550 Measurement and Calibration of Upright Cylindrical Tanks Std 2551 Measurement and Calibration of Horizontal Tanks Manual of Petroleum Measurement Standards Chapter 2.2B, "Calibration of Upright Cylindrical Tanks Using Optical Reference Line Method"

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Chapter 3.1B, "Standard Practice for Level Measurement of Liquid Hydrocarbons in Stationary Tanks by Automatic Tank Gauging" Chapter 4, "Proving Systems" Chapter 5, "Metering" Chapter 5.2, "Measurement of Liquid Hydrocarbons by Displacement Meters" Chapter 5.3, "Measurement of Liquid Hydrocarbons by Turbine Meters" Chapter 6, "Metering Assemblies" Chapter 7, "Temperature Determination" Chapter 8, "Sampling" Chapter 8.1, "Manual Sampling of Petroleum and Petroleum Products" Chapter 8.2, "Automatic Sampling of Petroleum and Petroleum Products" Chapter 9.1, "Hydrometer Test Method for Density, Relative Density (Specific Gravity) or API Gravity Crude Petroleum and Liquid Petroleum Products" Chapter 9.2, "Pressure Hydrometer Test for Density or Relative Density" Chapter 9.3, "Thermohydrometer Test for Density, Relative Density and API Gravity" (under development) Chapter 10.1, "Determination of Sediment in Crude Oils and Fuel Oils by the Extraction Method" Chapter 10.2, "Determination of Water in Crude Oil by Distillation" Chapter 10.3, "Determination of Water and Sediment in Crude Oil by the Centrifuge Method" (Laboratory Procedure) Chapter 10.4, "Determination of Sediment and Water in Crude Oil by the Centrifuge Method" (Field Procedure) Chapter 10.8, "Standard Test Method for Sediment in Crude Oil by Membrane Filtration" Chapter 10.9, "Coulemetric Karl Fischer (under development)" Chapter 11.1, "Volume Correction Factors" Chapter 11.2.1, "Compressibility Factors for Hydrocarbons: 0-90 °API Gravity Range" Chapter 11.2.2, "Compressibility Factors for Hydrocarbons 0.350-0.637 Relative Density (60°F/60°F) and -50°F to 140°F Metering Temperature" Chapter 12.2, "Calculation of Liquid Petroleum Quantities Measured by Turbine or Displacement Meters" Chapter 14.1, "Collecting and Handling of Natural Gas Samples for Custody Transfer" Chapter 14.3, "Concentric, Square-Edged Orifice Meters" (A.G.A. Report No. 3) Chapter 14.3, Part 2, "Specification and Installation Requirements" Chapter 14.6, "Continuous Density Measurement" Chapter 14.8, "Liquefied Petroleum Gas Measurement" Chapter 18.1, "Measurement Procedures for Crude Oil Gathered from Small Tanks by Truck" ASTM D1240 (ASTM–IP4) Petroleum Measurement Table (Table 3) GPA 2145 Physical Constants for Paraffin Hydrocarbons and Other Components of Natural Gas GPA 2177 Analysis of Demethanized Hydrocarbon Liquid Mixtures Containing Nitrogen and Carbon Dioxide by Gas Chromatography GPA 2186 Tentative Method for the Extended Analysis of Hydrocarbon Liquid Mixtures Containing Nitrogen and Carbon Dioxide by Temperature Programmed Gas Chromatography

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