It is necessary in many cases that the allocation system and methodology provide a fair, equitable and auditable means of sharing out the hydrocarbon products produced by the system to the original entry sources and associated partners.
Whilst also recognizing the specific delivery requirements for each participant and also having some alignment with the legal/fiscal (government) requirements in force for the region were the system is operated(see Figure 1).
This paper briefly describes some of the allocation methodology and measurement techniques used and implemented in the natural gas upstream area, whether in a single-phase or multiphase state which can have a large economic impact on an oil and gas business operating in these exacting times!
It is not unusual to take between one and two years to negotiate all the terms of a gas and condensate allocation agreement.
A wide array of negotiating skill, technical knowledge and common sense is required to understand the diverse topics in the development of an allocation system, negotiation with partners and government bodies can also be a hot topic and fraught with issues!
To successfully conclude an agreement it is good practice to form a team with expertise in the following multi-disciplines:
•Commercial negotiation.
•Gas legislation.
•Gas marketing.
•Measurement and allocation.
•Production operation.
•IT.
It is required during the preparation of the commercial agreement to develop simultaneously a business processes to manage the day-to-day operation for such an agreement to function efficiently and correctly.
It is also imperative to establish responsibilities and ownership for the following parameters:
•Hydrocarbon stream meter data.
•Hydrocarbon stream analysis.
•Production forecast information.
•Allocation system operation.
The business processes development will require a review of almost all areas and departments within a gas production entity/organization.
This will be necessary to ensure that the workload associated with the operation of the allocation system can be performed adequately and to identify whether additional personnel or external resources are needed.
Typically the scope / methodology for an allocation system may be depicted in Figure 2.
Capital expenditures for production facilities, test separators, test lines, multi-phase / wet-gas flow meters, etc. can all be assessed relatively easily using good forethought.
It should also be noted that the higher the accuracy requirement required for a particular meter or system, the more expensive the meter hardware will be.
This is usually the easiest part in the total cost estimate and depends on the level capital outlay versus level of uncertainty that the partners and local authorities, (taxation) will agree to.
The more accurate that a system is called to be generally the higher the cost it will be (see Figure 3)!
This is because the measurement devices that are used in these predominantly upstream locations are usually designed and standardized for single phase operation in areas of downstream processed fluids thus causing the need to use extra methodology and usually cost to improve the measurement and meet the need!
With respect to uncertainty and costs we may wish to consider two hypothetical extreme cases (a & b)
a) One extreme is a production system with very high accuracy in production measurements. Due to increased hardware costs and intensive operator involvement the project and operating costs will be higher, but with the increased and more accurate information better reservoir management and production optimization can be carried out.
Consequently, the uncertainty band in the Ultimate Recovery will decrease, giving a lower spread in project and operating risks. Realizing that the value of the oil in the ground is limited, we can also conclude that at a certain cost level the development will become economically unattractive.
b) The other extreme is a poor accuracy in the production measurements or production is not measured at all Giving - "Poor Reservoir Management", "Suboptimal Production Optimization", and "Potential Loss of Revenues" as the result!
In the final analysis, the uncertainty band for the "Ultimate Recovery" will stay large and the development might unknowingly become unattractive from an economic and risk viewpoint.
Somewhere between these extremes there is an optimized accuracy point, with the associated costs for the measurement and allocation processes versus uncertainty.
This is illustrated below in Figure 3 in which costs (arbitrary units) are shown plotted against "Acceptable Uncertainty".
This optimum may be totally different for each individual hydrocarbon development and allocation system!
It may be the case, that for a particular development, an accuracy of 10% in gas flow rate is sufficient and acceptable, or in another development a 2% accuracy level is required to meet the user specifications.
During the measurement and allocation of natural gas and condensate in a multi-user pipeline transportation systems the system will typically comprise of production facilities, pipelines, reception facilities, processing facilities and sales points.
Each of these elements can be shown in an allocation system in physical representation diagram as described/drawn in Figure 4.
The physical system may also be represented to compliment the physical system as a single line nodal diagram, representing all the (production) sources, sinks (gas used for fuel, flare, vent, gas lift, injection gas, etc.) as well as flow paths of product, the following are various descriptors used in the development of an allocation system planning see Figure 5 and Table 1.
Any product feed entering a system node. This is generally a production stream coming from one or more wells or production facilities.
Any product feed leaving a system node. This is generally gas and condensate sales streams but also water disposal streams, flare gas flows, blow-off gas, etc.
Any point in the system defined for the purpose of quantifying the quantity and quality of product passing through it.
To combine product streams from two or more wells or production facilities into a common separator, pipeline or tank.
Reconciliation is the process of dealing with any quantity imbalance between sources and sinks. Possible phase changes between the gas and condensate phase can be taken into account as well. Reconciliation can take place at any node in the system and is usually done at agreed periodic intervals.
This is the process by which a quantity of hydrocarbon gas and hydrocarbon condensate, measured at a sink (e.g. sales point) is allocated to one or more contributing sources as in Figure 6.
From the System Diagram a supporting table will be developed to describe what each node in the system represents, which could be the name of the producing field asset, the equity ownership interests, etc.
It could further describe any product processing, calculations, simulations, yield factors etc., as well as the allocation protocol for the node concerned.
In the upstream area it is not the case that all fluid streams are properly conditioned to one single-phase and indeed stay in a single phase over a large range of pressure and temperature.
In the upstream area, the fluids are often un-stabilized, and any pressure and temperature change (even a generated Δp in a measurement device or across a valve) may cause a phase change and change a single-phase fluid into a multiphase fluid.
Therefore definitions should be referred to the operation ranges of temperature and pressure that occur in the system under consideration when reviewing the design and implementation of allocation systems ISO/TC 193 WG4 has defined a level of vocabulary to meet the need which is used in the various standards that TC 193 produces allocation system methodology has particularly special needs.
These are met within the new issue of the vocabulary standard ISO/CD14532 which was approved in 2010 at the plenary meeting in Houston TX USA.
Prior to entering into a gas allocation system negotiation, it is important to understand the underlying framework of commercial agreements (either existing or being negotiated) and the technical characteristics of the production system, pipeline and terminal.
For example, each system user's perception of the local gas market will influence the importance that party places on different aspects of the allocation agreement - common sense plays a part here!
For example:
Security of gas supply with the aim to sell gas on a long-term contract:
•Allocation and attribution period set at a day.
•Limited re-nomination with relatively long lead times.
•Priority system for the attribution process.
•Mechanisms for notified and system substitution.
•Pipeline stock controlled by the pipeline system operator.
•exibility of gas supply in a de-regulated system with the aim to sell gas on the spot market:
•Allocation period set at less than a day.
•No priority system with the allocation process.
•No gas substitution.
•All nominations and re-nominations treated as firm.
•Line-pack controlled by the system users.
•Within day production changes to supplement gas delivery.
The specific situations will never be as clear cut as outlined above and there will be other issues that impact on the gas buyers and/or the system users, e.g. independence and capacity rights.
However, unless a high level analysis is undertaken and the main issues evaluated prior to entering into negotiations, then there is likelihood that the allocation system will not fulfill the system users' requirements and objectives.
In the extreme situation the poor quality of the allocation system may impinge on the operation of the offshore production facility and/or may limit the opportunity to sell gas in the open market. Allocation agreements are commercial agreements with technical input and not the other way around.
Attempting to develop a gas allocation system in isolation has the potential to produce an allocation system that is not fit for either commercial or technical purpose.
Consideration and concrete steps to minimize risk must be given to the following issues:
•Is gas being sold to single or multiple buyers?
•Is there one or are there multiple gas sales points?
•Is gas to be sold on a short term or long-term contract basis?
•Is there a spot market available for gas sales?
•Penalties for under-delivery or off-spec delivery
•Are there any restrictions in use of system capacity by a system user?
•How is the gas from the production system to be used within a system user's gas sales portfolio?
•What is the flexibility in the production system to respond to required changes in flow rate?
•Are there any local statutory regulations/considerations with respect to measurement devices, reporting and/or gas balancing?
To develop a gas allocation system requires an understanding from a technical standpoint of all aspects of the overall process design and operation, (including the implications on the Terminal product of variations in processing conditions and gas compositions), and from a commercial standpoint of the gas sales agreements and the overall commercial structure that has been developed.
By its very nature, a gas allocation system encompasses a wide range of topics including measurement methods and standards, laboratory techniques, data auditing, allocation principles and procedures, nomination, substitution and attribution procedures, statutory requirements, IT system development, audits, tax and related commercial transportation, operating and processing system agreements.
Measurement includes metering and sampling and is required to establish the quantity and associated quality of the gas exported from the production system into the pipeline and the product leaving the terminal.
An understanding is required of the different types of metering systems, sampling installations and associated analytical techniques. This information is required to ensure that the meter is specified for the correct service and accuracy and that the sampling installation is installed in the appropriate location.
The specification of metering and sampling equipment at each Measurement Point should be designed in accordance with applicable standards and local regulations, although it should be noted that commercial considerations may have an impact on this specification, for example it maybe agreed that a marginal field may use a standard of metering with a higher uncertainty if the overall financial risk is mitigated.
Measurement Points include:
•Pipeline entry measurement point(s) - gas and liquid.
•Terminal entry measurement point.
•Terminal measurement exit point(s) - gas and liquid.
•Terminal fuel gas.
•Terminal flare gas.
•Liquid storage.
In addition, the sampling systems are utilized to monitor the entry and exit streams to ensure that the composition specifications are achieved.
Terminal product slate relates to the onshore processing of the commingled gas stream is required to ensure that the sales gas and associated liquid product(s) meet the required specifications. In general, more liquid products will require a more complex allocation procedure. An understanding is required of the terminal process design to ensure that the developed procedures correctly reflect each Field's allocated entitlement.
Pipeline capacity relates to the steady state and transient operation of the gas pipeline. It is important to ensure that the allocation mechanisms do not inhibit pipeline operation and vice versa.
System response time relates to the speed at which the offshore process, the pipeline and the onshore terminal can individually respond to a required change in system throughput. An understanding is required because it is necessary to ensure the process reflects the dynamics of the system.
Gas sales agreement specifies the gas specification at the re-delivery point, nomination procedures, forecasting and gas measurement required and therefore directly impacts the allocation process. An understanding is required to ensure that the allocation agreement enables the principles of the gas sales agreement to be applied or that the gas sales agreement can be negotiated to fit with the system's allocation agreement.
Commercial agreements relates to transportation and processing agreements that specify amongst other things capacity rights, specifications and system wide capacity constraint procedures.
Statutory obligations specific reporting requirements need to be incorporated within the agreements, may be technical e.g. measurement.
Tax implications allocation processes should be developed which recognize fields that are liable to pay specific taxes and those that are not liable.
Note: Consideration should be given to most tax efficient option when developing the allocation procedures.
Allocation is the procedure for sharing out the terminal's gas and liquid production between the participating Fields based on the measured data. Allocation relates to the physical movement of fluids through the system.
A series of mathematical formulae that traces the physical flow of gas exported from a Field through the pipeline to the terminal. The procedures are used to determine each Fields and the associated system users share of the terminal production (gas and liquids) based on the physical quantity of gas entering the pipeline.
Attribution is the procedure for sharing out the terminal's gas production between the participating Fields primarily based on nomination data. Attribution relates to the commercial movement of gas through the system and may be independent of the measured input quantities. A series of mathematical formulae used to establish each system user's share of the gas exported from the terminal. The procedures are based on the user's gas allocation, nomination and specific substitution rights.
Nomination relates to the quantity of gas requested by a buyer to a system user for delivery from the terminal. The aggregate nominations of all system users (from a Field) are used to establish the Field's production into the pipeline system.
Substitution is the mechanism that enables one user to lend or borrow gas (exported from the terminal) to/from another system user to meet either system user's nominations.
The difference between a Fields allocated and attributed quantities is substitution. Substitution is basically a mutual self help process, which is controlled at the terminal by the terminal operator.
The terminal operator will be aware if a producing area is having difficulties meeting the production targets and will find another operating area who can help and vice versa if that producing area has the ability to produce excess gas. Limitations will be imposed on the level of lending, borrowing and the payback period
Units relates to the base unit of the allocation and attribution processes, for example component mass and/or energy.
Time period for the allocation and attribution calculations. Consideration is given to daily, hourly or another allocation period. The allocation period may not be linked to the nomination period, e.g. quite often there exists an hourly allocation period but a daily nomination period.
In addition there often exists a downstream gas transporters "balancing" periods. This balancing period is the time frame that the downstream gas transporter will levy penalties over for imbalances between inflow and outflow e.g. the allocation period could be hourly but the balancing period 4 or 6 hourly (this gives the gas time to travel from the input point to the output point). The allocation period is shorter as this enables the Shippers to manage their imbalance positions within the balancing period.
Forecasting is necessary to ensure that the lead times for provision of data required by the gas sales agreements and the production and planning targets for the Terminal and Platform operators are incorporated.
Pipeline stock relates to the use of pipeline stock to help achieve gas. Consideration needs to be given to which commercial party controls the level of stock in the pipeline, e.g. the Pipeline/Terminal Operator or the System Users.
Existing systems it is necessary to ensure that the gas allocation system seamlessly integrates with the existing procedure associated with existing downstream systems.
Data timing needs to ensure that nominations and any potential re-nominations timing within the allocation agreement coincides with the requirement of the gas sale agreements and operational requirements.
Data flow and reporting must be evaluated to ensure that sufficient information is provided to check the allocation and attribution reports prepared by the system operator. Where within day individual parties receive data it is necessary to check that all parties receive the same information at the same time. Business processes are required for the Terminal Operator to advise the Field Operators to increase/decrease flow of production into the pipeline system.
Auditing is critical to provide a means of checking the overall operation of the system operator in the event that errors are found within the allocation statement. This issue must be a priority item within any Allocation Agreement negotiations.
Fallback a detailed plan is required to establish how nominations, data flow will be provided in the event that the normal communication processes fail or meter data does not exist.
The results from allocation calculations establish each participant's revenue from the system and it must be stressed that a gas allocation agreement is not a technical agreement.
During an allocation negotiation system users should be wary of statements that imply that the allocation agreement is purely a technical arrangement and hence should be developed by the technical departments.
In conclusion, when gas from two or more entry sources are commingled and processed in a common pipeline and terminal system and the sources have different ownership and/or operate under different tax regimes, then a gas allocation system is required.
The allocation system must provide a fair, equitable and auditable means of sharing out the products from the system to the entry sources and to the associated partners recognizing the specific delivery requirements of each participant.
It should be stressed that:
(a) All allocation procedures are unique and are specifically designed for a given system driven by commercial considerations.
(b) For an allocation system, technical solutions are developed to meet the specific commercial requirements.
(c) There is no such thing as a standard allocation procedure but there are standard elements/approaches that combine to produce the overall allocation system.
(d) As with any other commercial agreement, allocation agreements are finalized as a result of negotiation and compromise, therefore it is not good practice to take an existing agreement and attempt to modify it without discussing the terms of the agreement with the personnel that negotiated it.
(e) An allocation/attribution system must not be developed in isolation from the system other commercial agreements, e.g. Transportation and Operating agreement.
Dry gas is defined as a gaseous fluid for which there is no liquid dropout over the expected temperature and pressure operating ranges at the metering point. Various devices are available to measure dry gas and some methods are covered by international standards or documents giving best practice.
Gas from a two or three phase separator is usually liquid saturated gas, just above its hydrocarbon dew-point.
When applying dry gas metering principles, care should be taken to prevent liquid drop out due to pressure and temperature fluctuations at the measurement point, resulting in two-phase conditions and corresponding difficulties in measuring the flow.
Other parameters to be considered are correct meter sizing and installation to prevent unnecessary pressure drop, and line insulation to maintain temperature in the system at the metering point.
Gas conditioning devices installed between the measurement point and the separator can change the measurement conditions at the measuring point and possible effects from their installation should be addressed.
Dry gas flow measurement shall be performed using methods and standards which are generally accepted by the E & P industry and which shall be mutually agreed upon by the parties having interests in the gas transportation system (for example, Gas Shippers, partners in the field development, field operator, relevant authorities).
The selection of the measurement method shall be on the basis of demonstrated reliability and accuracy. The design of new installations or revision of existing installations shall also be subject to the agreement of the above parties.
The following single phase gas flow metering methods are used most often for allocation flow rate measurement, other methods are not excluded and available if they meet the need:
•Orifice Plates
•Turbine meters.
The produced quantity of gas is displayed in:
•kg/day or tonne/day, Mass flow rate for allocation and hydrocarbon accounting purposes.
•Sm3/day or Nm3/day, Volume flow rate for capacity planning and hydrocarbon accounting purposes.
•GJ/day or TJ/day, Energy flow rate for allocation and hydrocarbon accounting purposes.
Equilibrium gas is defined as separated gas that basically has no free liquids but may develop a small liquid content by changes in process conditions or meter/pipe-work interaction.
Any process changes of the gas may cause a shift in the definition of the gas as wet or dry. These changes may affect the GOR, GCR, the Lockhart-Martinelli parameter and the gas and liquid properties.
Close to critical conditions small changes may cause large variations in the liquid and gas fractions and in the fluid properties. Care should be taken in meter selection so as not to cause additional impact on the line process conditions.
The measurement devices that can be used for equilibrium gas are similar to the devices mentioned for dry gas application. However, in the design care should be taken that as soon liquids start to be formed (e.g. due to pressure drop in the meter) the effect on the reading should be established.
Ultrasonic meters are increasingly being used for this service, and the following comments are relevant.
•At present ultrasonic meters are not suitable for measuring gas above 0.5% LVF (Liquid Volume Fraction) as the units produce unstable readings.
•Care should be taken in systems subject to carry over or liquid entrainment when the ultrasonic meter has a poor location. If the meter is too close to bends, valves or other obstructions, the resulting swirl / turbulence can seriously affect the accuracy of the mathematical techniques used to find the velocity profile and therefore the flow-rate.
•If the operating temperature is too high there is a question mark over the strength of the bonding material used in the manufacture of some Ultrasonic transducers. Testing has shown the transducers can fail at temperatures in excess of 150 ℃ or when there is a sudden pressure fluctuation (a common occurrence in production pipelines).
•Other installation parameters or concerns that need care are that signals read by the meter are verysusceptible to background noise from other components in or close to the line on some designs.
•Work is however underway to develop ultrasonic meters for wet gas above current norms.
This term is used to denote a natural gas flow containing a relatively small amount of free liquid by volume, up to about 10%. There are presently few techniques available which can measure this type of fluid regime to a high degree of accuracy. The phenomenon occurs in several ways. For example:
•Over time as dry natural gas wells age changes in flow conditions including a reduction in line pressure may result in the heavier hydrocarbon gases condensing in flow-lines and transportation pipelines.
•Production wells for gas condensate fields usually have wet gas flow.
•The quantity of lift gas injected to increase production from many oil wells brings them to flow conditions that can be termed wet gas.
Many gas wells worldwide are now approaching these latter stages of their production life and wet gas metering is becoming common. Current trends indicate approximate ranges of liquid/gas ratios found in most producing gas fields as having GVF > 90%~3% or Lockhart Martinelli parameters to a maximum of approx. 0.3. Meter performance requirements in this area are not covered in current standards but an API recommended practice (RP 85) describes the use of wet gas meters in an allocation system.
Representation of the fluid velocities, measured volumes, and mass has not been exactly defined and various regions of the world use different terminology to obtain a measurement result. Accordingly, wet gas measurement methods are discussed in more detail in this document to give the current best guidance The gas flowing through a 'Gas Only' system must be that categorized as Dry.
Such a system would possibly use an alternative means to export the hydrocarbon liquids, separate to the allocation and metering system in question.
If it is assumed no hydrocarbon liquids are produced from the field or are transported through the measurement node this must be stated in the allocation agreement, together with the actions that will be taken if hydrocarbon liquid products are received at the measurement node.
Such liquids should be defined as either a valued or waste products and there should be a method specifying how to determine ownership.
Gas flow measurement for Custody transfer (also referred to as Fiscal metering) by means of differential pressure devices shall be according to the relevant edition of ISO 5167 using a square edge orifice plate with flange tapings installed in a meter run or a Venturi design also shown in ISO 5167.
These documents give detailed guidance on design, installation and flow computation, note up and down stream pipe straight run requirements are needed for both these device types as detailed in the relevant standards. Newer D.P. cone meter technologies are also emerging in the market place today generally used in the upstream environment at the well head or on separators offering reduced up and downstream lengths which can save space on a platform.
Gas flow measurement for Custody transfer by means of turbine meters shall be in accordance with ISO 9951. Turbine meters should not be used where frequently interrupted and/or strongly fluctuating flow or pressure pulsations or liquid carry over are present.
The turbine meter shall be of demonstrated reliability and accuracy. For each turbine meter a certificate of the calibration at a high pressure shall be available. The calibration data provided in the certificate shall include the error of the meter for at least 6 points over the whole range of the meter according to ISO 9951.
Multi-path ultrasonic flow meters offer extensive technical and economical advantages as compared to other type of flow meters with respect to, amongst others, high accuracy, low pressure losses, high range-ability (turn down), bi-directional flow, low sensitivity to dirt, trouble free operation, reduced maintenance and calibration costs.
The application of ultrasonic flow meters should therefore be seriously considered for new applications. Application of these meters shall be in accordance with field proven installation practices. The ultrasonic flow meter shall be of demonstrated reliability and accuracy.
The influence of chemicals on the epoxy transducers should be reviewed. The ultrasonic flow meter shall be calibrated in accordance with the manufacturer's procedures.
A certificate of the calibration of the ultrasonic flow meter at a high pressure and over the Reynolds number range it is to be used shall be available if required by parties involved.
The calibration data provided in the certificate shall include the error of the meter for at least 6 points over the whole range of the meter according to ISO 9951 on air or natural gas.
Allocation measurement of produced hydrocarbon gas in the upstream area require different measurement techniques and strategies than those used for standard pipeline quality gas measurement due to the nature of the fluids in the system.
Wet gas, hydrate formation, liquid slugging, well clean-up debris and short meter runs all add to the difficult task of collecting meaningful data from High Pressure Full Well Stream (HPFWS) allocation metering points.
Various meter types have been employed for these flow regimes in order to meet the necessary accuracy requirements and the arduous duty that normally occurs in these applications.
The location of the subject field is in West Central Wyoming consisting of remote well pad locations where access can pose problems during the winter months due to various environmental factors such as weather and animal migrations.
From a sustainability standpoint, the remote measurement systems must operate effectively with minimum maintenance during these months with limited access (see Figure 7).
Metering is required to fulfill a number of functions driven by regulatory, industry and internal requirements. The metering function relates to process control, sales quantity and quality, and hydrocarbon accounting.
Consistent with a need to simplify facilities, metering equipment is minimized to that deemed necessary to run the business.
The measurement systems are designed "Fit for Purpose" in order to reduce capital and operating expense, and simplify volume reconciliation procedures.
Metering devices, flow conditioning equipment and ancillaries will be designed to meet the necessary level of accuracy only. Such accuracy requirements must be in accordance with BLM and Wyoming Oil and Gas Conservation Commission regulations, API standards, legal, accounting, Sarbanes-Oxley (Sox) compliance, and reservoir management requirements.
Continuous readings are taken during the well testing process. The test separator gas volumes are compared to the (HPFWS) Differential Pressure Meters (e.g. Cone Meter, Conditioning Orifice Plate, or similar devices) readings and a gas volume correction factors are calculated.
Once the gas volume correction factor (GVCF) is obtained, the gas only volumes from the HPFWS Meter will be used to calculate liquid volumes. Liquid yields will be calculated based on the gas volume produced during the test. The well test is used to calculate a daily well theoretical contribution percentage for oil, water, and gas.
This percentage is calculated using algorithms involving the daily readings from the HPFWS Meter and the well test factors. Once the theoretical daily volumes are calculated, they are compared with daily readings from the applicable sales meter for accuracy.
The daily sales are then allocated to each well based on each wells calculated contribution percentage. The fiscal allocation occurs when the daily sales readings are replaced with final sales readings and the same daily theoretical contribution percentage is applied.
The use of Differential Pressure Technology (D.P.) to measure the full well stream wet gas is favored because these types of devices appear to be less susceptible to the effects caused by the multiphase aspects of the fluid.Although there is an effect of liquid in gas for all D.P. devices, it is known from research that the main issue here is one of repeatable results from well test to well test with minimum impact caused by liquid load changes.
Since a correction factor/allocation factor is calculated for each well location the most important requirements are that the full well stream meter is robust, has a predictable and repeatable operating envelope, and is representative between well tests. The normal well test period is 24 hours once per month per full well stream meter to determine a gas volume correction factor (GVCF) that is used for the time till the next well test period.
A well test manifold is installed in the flow line downstream of the HPFWS meters. There are chokes situated upstream of the HPFWS meters on most of the locations. Samples are taken at least semi-annually from each gas and condensate stream.
Shrinkage factors are applied to the gross volume obtained by the well test separator condensate/oil turbine meters to determine the net stock tank condensate volumes(see Figure 8).
During the well testing process, the volume of gas is measured at the outlet of the test vessel and recorded as the Standard Gas Volume (SGV). The indicated Full Well Stream Volume (FWSV) is also recorded during the same time frame. Then the SGV divided by the FWSV which yields a Gas Volume Correction Factor (GVCF) that is used to ascertain the gas volumes delivered through the HPFWS meter.
Thus:
Where:
SGTV=Standard Gas Test Volume (MCF).
GVCF=Full Well Stream Standard Volume.
FWSMF=Full Well Stream Meter Factor.
Volumes of condensate produced during the well test are also recorded. The indicated "gross" volumes usually are corrected to standard conditions (net volumes) in accordance with API MPMS 20.1.latest revision.
The resulting net volume is used as well as the gas volumes from above in ascertaining the barrels of condensate per million cubic feet of gas yield (BBL/MMCF) un its usually used in USA or usually in m3 for other world areas.
CBMCF=Condensate Barrels per MMCF.
CTV=Condensate Test Volume.
Produced water volumes are ascertained in the same manner as the condensate volumes detailed before, since water at ambient temperature is assumed to be non-compressible.
The only difference in the method is that there is no correction from gross to net volumes during the well test period required.
The meters were installed in separate streams situated in a steel cabin. D.P., temperature and static pressure data was collected and transmitted to a locally mounted Supervisory Control Data Acquisition System (SCADA) to allow computation of the flow rate.
The process conditions varied over the well life so a meter sizing was selected to manage the following natural gas metering needs:
(a) Initial condition-11 799 m3/hr (10 MMcf/day), @134 barg(2000 psig), density 0.709 6 kg/m3 0.044 3 lbm/ft3
(b) Majority condition-7 079 m3/hr (6 MMcf/day), @ 40 barg (600 psig), density 0.709 6 kg/m3 0.044 3 lbm/ft3
(c) End life (new) -1 770 m3/hr (1.5 MMcf/day), @ 40 barg (600 psig), density 0.709 6 kg/m3 0.044 3 lbm/ft3
(d) Old end life data-1 179 m3/hr (1.0 MMcf/day), @ 40 barg (600 psig), density 0.709 6 kg/m3 0.044 3 lbm/ft3
Meter sizes were determined electronically from a propriety software which gave a 3 inch - 0.55 Beta cone meter as the selection to fit the existing pipe-work and flow needs.
Pressure rating for the piping was ANSI Class # 2500. Meters were manufactured from carbon steel with 316 stainless steel cone assemblies.
Average daily rate = 41 385 Sm3/day (1 461.5-MSCF/day) (see Figure 10).
a) It is important to make sure that all agreements are well thought out and assembled in a way that minimizes risk for all parties. Reservoir management and or production optimisation might call for individual well installation and reduced separator usage, economic considerations today (steel prices, labour) are a big driver in this!
b) Production/Allocation Measurement Management should cover the entire chain of actions from sensor to final report.
c) Accuracy is negotiable, should be determined through a methodology rather that using fixed numbers.
d) Production/Allocation Measurement Team should carry responsibility for corporate metering issues.
2012, Vol. 41 Issue (2): 125-139
2012, Vol. 41 Issue (2): 125-139