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Search accuracy: production test
...78-1-880653-92-0; ISSN 1946-0066 Monitoring System for Seafloor Deformation during Methane Hydrate Production Test Tatsuya Yokoyama, Mio Shimoyama, Shinji Matsuda, Koichi Tago and Junya Takeshima OYO Corporation ...rmation The system under development is expected to be applied to the 1st MH during Methane Hydrate production test. Seafloor deformation is ...production test scheduled in the end of FY2012. The ...
...r two weeks Fig. 5 Flow chart of data processing in acoustic communication system In Shallow Water Test All eight monitoring devices completed were installed in the shallow sea floor of about 30 m depth,...about for one weeks hour on the sea floor, and raised up on the sea surface. It took three days to test all devices. The work procedure of shallow water ...test is shown in PERFORMANCE TESTS IN OFFSHORE Figure 6. As a result, all monitoring devices were conf...
... system first for evaluation 30 and its practical resolution is approximately 0.05 . The sensor has test, then complete a final model for actual operation as described in almost no temperature drift since...
ABSTRACT We have developed a monitoring system for seafloor deformation during Methane Hydrate production test. Seafloor deformation is monitored by measuring subsidence and inclination of the seafloor. Subsidence is measured with change of water pressure on the seafloor. An inclinometer we selected is applied liquid electrolyte. According to simulation of seafloor deformation around the production hole, the range of subsidence will be from 0.1 m to 0.3 cm. This system has been installed and monitored on the seafloor at East Nankai trough during the production test of Methane Hydrate. We will continue the measurement by September 2013.
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Integration of geomechanics in models (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (0.99)
- Reservoir Description and Dynamics > Non-Traditional Resources > Gas hydrates (0.92)
...ium of Japan, September 27 - 28, 2012 MONITORING SYSTEM OF SEAFLOOR SUBSIDENCE FOR METHANE HYDRATE PRODUCTION TEST B Tatsuya Yokoyama 1 , Mio Shimoyama 1 , Shinji Matsuda 1 , Koichi Tago 1 , Junya...ATION 2. JOGMEC This paper was selected for presentation by a JFES program committee following test result of sensors, and performance ...test of them under review of an abstract submitted by the author(s). actual conditions. ABSTRACT OUTL...
...e monitoring will start two shape with approximately 1m on each side, and has a months prior to the production of MH and continue for transmitter/receiver at the top of it for communication approximately two mo...nths after ceasing production in transponder and weight release transponder, float for self order to confirm the long term behavi...ormation monitoring system measures water pressure and inclination of the location. The PERFORMANCE TEST OF PRESSURE GAUGE pressure gauge indicates water pressure that corresponds AND INCLINOMETER to the ...
...posium of Japan, September 27 - 28, 2012 Figure 12: Pressure and Inclinations data in the deep sea test. SUMMARY Monitoring system for seafloor deformation was developed newly. This system measures the ...most performances of this system are confirmed as practical level. We will do a final check for the production test of methane hydrate at East Nankai trough on the end of TY2012. ACKNOWLEDGEMENT This is a part of r...
ABSTRACT We have been developing a monitoring system for seafloor deformations during Methane Hydrate production test. Seafloor deformations are evaluated by measuring subsidence and inclination of the seafloor. Subsidence is measured with change of water pressure on the seafloor. As a sensor for the selected pressure gauge, quartz crystal resonator is applied. The range of the pressure gauge is 0 to 1,400 m, the resolution is 0.014 mm, and actual accuracy is around 10 mm in conversion to water level. As a sensor for the selected inclinometer, liquid electrolyte is applied. The range of the inclinometer is ±30 degree, resolution is 0.001 degree, and actual accuracy is around 0.02 degree depending on measuring condition. According to simulation of seafloor deformation around the production well, the range of subsidence will be from 10 cm to 30 cm. This system has been examined in the offshore of Suruga Bay which has water depth more than 1000 m. All the features of this system were confirmed by examination of deep sea area in Suruga Bay We will do a final check prior to the production test of Methane Hydrate at East Nankai trough on the end of FY2012. This work was carried out by OYO Corporation with the support of JOGMEC which is a member of MH21 consortium sponsored by Ministry of Economy, Trade and Industry in Japan
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Japan Government (0.35)
...SPE-152768 Tracking Subsea Gas Wells performance without Periodic Production Testing on ...Test Separator Selim, I. El-S., Rashid Petroleum Company, Shokir, E. M. El-M., Cairo University Copyri...lso, tracking wells performance for multi-fields company with multi joint ventures is important for production allocation for fair company revenue distribution. Regular well testing is required for tracking wel...
...2 SPE 152768 Downhole flow control valves for control the production from each zone separately. Permanent downhole gauge (PDG) with venturi housing. This smart solutio...n is a good replacement to test separator and slick line gauges and also allows real time data monitoring to wells performance remo...on and checking measurement validity. Venturi and WGM measurements validity can be done by tracking production allocation of wells relative to received gas to the onshore plant,using IAM model that simulate sub...
...SPE 152768 9 Also production rates back effects on neighbours' wells are identified and to avoid tuning distortion due to increa...ng from bottom hole flowing pressures (BHFP). However reservoir pressure (P R ) is changed with production as reservoir depletion. So it is important to keep shifting IPR with expected average reservoir pre...ssure that come from well test analysis or/and material balance calculations or reservoir simulation model this IPR shift,assuming...
Abstract Tracking well performance is essential in understanding reservoir behaviour, reservoir management and matching reservoir simulation models with historical data. It results in forecasting reservoir performance accurately. Also, tracking wells performance for multi-fields company with multi joint ventures is important for production allocation for fair company revenue distribution. Regular well testing is required for tracking well performance but in a subsea environment using traditional testing tools such as test separators and slick line downhole gauges to measure production rates and bottom hole pressures, would cost millions of dollars. So these types of tools don't suit a subsea environment therefor other tools to track subsea wells performance are required. This paper presents tools to tracking subsea wells performance without test separator and by using interventionless tools such as; permanent down hole gauges, venturi and wet gas meter (WGM) with identifying uncertainty in rates measurements with these tools and focusing on measured rate validity techniques by using quality checking (QC) tools such as: a) tracking field production allocation factor b) Sensitivity on measured rates by Integrated asset model (IAM), c) using shifted well inflow performance relationship (IPR) and d)Comparing pressure drops along flow paths with initialized selected well flow correlations. Successful applying of QC techniques on monitored rate of subsea wells for gas field Z allows for identifications of errors in rates measurements and predicting the actual well rate. These assist in simulation history matching and fair distribution to company revenues between JV partners companies.
Automatic Well Test Validation Empowered By Machine Learning and Natural Language Processing
Gao, Chao (SLB, Houston, Texas, United States of America) | Vo, Nghia Tri (SLB, Kuala Lumpur, Wilayah Persekutuan Kuala Lumpur, Malaysia) | Zam, Fathin Shalihah Hasnol Zam (PETRONAS, Kerteh, Terengganu, Malaysia) | Salleh, Nurul Fadhilah Bt (PETRONAS, Kerteh, Terengganu, Malaysia) | Sidek, Sulaiman B (PETRONAS, Kuala Lumpur, Wilayah Persekutuan Kuala Lumpur, Malaysia)
...OTC-32692-MS Automatic Well Test Validation Empowered By Machine Learning and Natural Language Processing Chao Gao, SLB, Houston, ...cknowledgment of OTC copyright. Abstract The standard operating procedure (SOP) requires a well test monthly for every active producer to assess performance behavior. With over 100 new well tests dail...causing high accumulated amounts throughout the month and spill over to the next month. If the well-test quality does not meet the expectation, it should be rejected and required to retest immediately to ...
...ent fields' needs, offering a more flexible and efficient alternative to hard-coded rule-based well test validation. Introduction In the oil and gas industry, it is crucial to conduct ...production well tests to evaluate oil producers' performance and productivity time after time. ...Production tests can be performed with multiphase meters installed at each well or tests' separator. This is m...
...OTC-32692-MS 3 better decision-making, improved reservoir management, and optimized production operations in the oil and gas industry. Solution Approach Figure 1--Well ...test validation business process with ML and NLP...
Abstract The standard operating procedure (SOP) requires a well test monthly for every active producer to assess performance behavior. With over 100 new well tests daily, a busy operation schedule can lead to delayed validation, causing high accumulated amounts throughout the month and spill over to the next month. If the well-test quality does not meet the expectation, it should be rejected and required to retest immediately to comply with SOP. The significant effort and delayed well-test validation will cause inaccuracy in production performance analysis, diagnostics, and potential issue detection. This solution aims to significantly reduce processing time from gathering enough historical information to validating with engineering models and limits human error by checking all available well tests and preparing detailed analysis for engineers to make the final decision. By having more updated accepted well tests to update well engineering models, the solution helps to improve accuracy and more confident outputs in other engineering workflows like production back allocation, well rate estimation, well and network model calibrations, and production optimization. The proposed solution leverages artificial intelligence (AI) capability learns from historical well test data with accepted and rejected flag to build a rule-based deterministic machine learning (ML) model to automatically validate and detect the possible rejected or accepted well test. The solution also considers well test comments or remarks provided by well-testing engineers which are processed via Natural Language Processing (NLP) engine. ML model can propose to accept a well test with confidence score to automate the validation and support engineer's decision. On the other hand, if the model detects a possible rejected well test, it suggests engineer to review the new well test information versus historical performance and takes actions, where early rejection triggers retesting requirement to the offshore team to prioritize the well to the test plan. Periodically, the ML model may require updates based on the most recent well test data in order to maintain its accuracy. The solution significantly reduces well test validation time from weeks to hours, improving the accuracy of other production performance analysis and optimizations. The data-driven approach can easily be adapted to different fields’ needs, offering a more flexible and efficient alternative to hard-coded rule-based well test validation.
- South America > Brazil (0.46)
- Asia > Malaysia (0.29)
- Asia > Middle East (0.28)
- North America > United States (0.28)
...A PRACTICAL METHOD FOR IMPROVING THE ACCURACY OF WELL TEST ANALYSIS T.H. LESHCHYSHYN S.M. FAROUQ ALI M. CHAN this article begins on the next page THE PETROL...EUM SOCIETY OF CIM ABSTRACT Well test analyses are normally performed using a combination of type-curve and semi-log analysis. Unfortunat...practical approach is introduced in this paper which requires a single solution to two or more well test analysis methods. This is accomplished by coupling the multiple solution parameters to derive a tes...
...and Lime, t, from a \\o'alcr proper slopes are still met. The more unique the answer, the injection/production well to obtain greater the confidence in using the values for formation and Q r e-u economic ...and changing hydraulic head with lime. pressure match points or slopes. respectively, and Q is the production rate. Two examples are presented here, the first is well testing Substituting the integral by lhe w... saturated, very " u viscous oil sands reservoir. Equation (2) becomes Q EXAMPLE 1: INTERFERENCE TEST ANALYSIS s h o - h (r,t) W(u) () ON A CONFINED AQUIFER 4nT The two most important aquifer ...
...LEUM SOCIETY OF CIM PAPER 95·52 ., . ,:- A Practical Method for Improving the Accuracy of Well Test Analysis T.H. Leshchyshyn Canadian Fracmaster Ltd. S.M. Farouq Ali University of Alberta M. Chan ...onstrate the universality ofthe method and show the ABSTRACT actual change in results. ... IVell test analyses are normally performed using a For example, a previously reported value offormation combi... of, reservoir properties generaled from such tests, requires a single solution to two or more well test analysis methods, This is accomplished by coupling the multiple Whelher a geologist is analyzing a ...
Abstract Well test analyses are normally performed using a combination of type-cun1e and semi-log analysis. Unfortunately, calculated values of reservoir rock properties such as permeability (transmissivity) or near wellbore damage can vary by a significant amount between the two methods, Unless a history match is conducted, the best value to use is ambiguous. A practical approach is introduced in this paper which requires a single solution to two or more well test analysis methods, This is accomplished by coupling the multiple solution parameters to derive a testing criterion for a unique solution, i.e. first combining two equations into one, then using this single formulation to determine whether the analyzed data points meet certain requirements simultaneously between the two or more solutions. It is assumed that initial boundary conditions used in deriving the previously separate solutions are the same or very similar. Two examples are presented, one from a high transmissivity groundwater flow (water source) and one from a low permeability oil sands reservoir. The purpose is to demonstrate the universality of the method and show the actual change in results. For example, a previously reported value of formation compressibility was changed by 100 percent. Introduction We present a new, practical approach to well test analysis with the intent of improving the confidence in, and the accuracy of, reservoir properties generated from such tests. Whether a geologist is analyzing a falloff well test from a permeable confined aquifer to estimate water supply or, an engineer is analyzing a production buildup test from a twenty-year old producing oil well, to identify any formation damage, the problems encountered during analysis are quite similar. Standard practice is to perform at least two types of analyses:type-curve fitting on log-log or semi-log paper and, semi-log straight line plots. One tries to arrive at comparable values for transmissivity (hydrogeological term) r permeability (petroleum engineering term) from each method and normally report what is thought to be the best answer. The method outlined below is intended to give a generalized approach to the coupling of H2O or more analytical techniques so that only one answer is feasible, while the requirements of curve matching or drawing of proper slopes are still met. The more unique the answer, the greater the confidence in using the values for formation and economic evaluations. The technique used to essentially lock analysis methods together is described by example rather than as a stepwise procedure, the reason being that each set of analysis pairs, or groups, usually provide a slightly different or even uniqueapproach to obtaining the correct solution. For example, nalysis could concentrate on time intercepts rather than pressure match points or slopes. Two examples are presented here, the first is well testing from a hydrogeologist's view of flow through an aquifer and the second is well testing from an engineer's perspective on water (or steam) injection into a highly oil saturated, very viscous oil sands reservoir.
...Field Test of a Wet Gas Meter P. Andreussi, University of Pisa, P. Ciandri, TEA Sistemi SpA, S. Boschi, ENI E...: 1.8m in length and 1.5m in height. The meter was installed on February 2006. A preliminary set of test was made by injecting known quantities of liquid during the normal process. The results obtained wi... basis of these results, a full scale MPFM was installed in Allegheny TLP, GOM, in August 2002, for production allocation and monitoring. In this application VEGA measurements have been compared with data obtai...
...Table A: Ripalta test VEGA Date ...Test Press. Temp. Gas TEG Inj. Time meas. Difference Velocity LVF n Bar-g C kSm3/h liters min. liters % ...f-calibrating. Preliminary tests also indicated that the VEGA meter can be safely adopted as an oil production meter. In Ripalta installation, the relative error in the measurement of the liquid flow rate is ap...
ABSTRACT: At Ripalta, Italy, the natural gas stocked in an exhausted reservoir is dehydrated before its input into the gas network. Normally the liquid carry over from these columns is 1.3 Kg/106 Sm3. This could be a hundred times greater in case of malfunctioning. In order to monitor the liquid carry over, STOGIT decided to install a wet gas meter based on isokinetic sampling. This type of flow meter has been used in the past by ENI E&P for another challenging application: the measurement of a liquid volume fraction about equal to 0.2% and a water fraction about equal to 0.02% in the Allegheny TLP (Gulf of Mexico) [1]. At Ripalta the natural gas flows in a 12" pipeline at 40-50 Bar of static pressure. Due to the size of the pipeline, for the first time it was decided to install the flow meter in a horizontal configuration. The innovative design of the horizontal multiphase flowmeter allowed a very compact dimension: 1.8m in length and 1.5m in height. The meter was installed on February 2006. A preliminary set of test was made by injecting known quantities of liquid during the normal process. The results obtained without performing any type of calibration were excellent: The meter was able to detect liquid when the liquid volume fraction was 0.00002% with a scatter between injected and measured liquid flow rates equal to or less than 10% relative. To our knowledge it is unique that a multiphase meter is able to work under these conditions. The instrument is now being operated by STOGIT. STOGIT has also installed a second instrument in another gas plan
- Europe > Italy (0.25)
- North America > United States (0.25)
- North America > Mexico (0.25)
...A PREPRINT --- SUBJECT TO CORRECTION Uses of Short-Term Tests in a Computer-Contra I I ed We I I Test System By John T. Womack, Amoco ...Production Co. and Lee R. Scoles, Amoco Canada Ltd., Members AIME Copyright 1973 American Institute of Minin...er, 1970; and the system was fully A computer-controlled automatic well operational by March, 1971. test system using short-term tests for both flow indication and ...
...? USES OF SHORT-TERM TESTS IN A COMPUTER CONTROLLED WELL TEST SYSTEM SPE 4402 Short-Term Tests the six ...test separators and the equipment status sensors. Control, status, and pulse In late 1968 a study was ma...de to determine generating circuits are 26 VDC loops. Status if short, frequent well test would be sensors are relays and position, temperature, accurate enough for both flow indication and...
... SCOLES 3 Daily Reports and correct any abnormal equipment conditions. During the day, any printed test results indicating Every day at 6 AM the Morning Report is low or zero ...production are immediately printed on the Riverton Office teletype and investigated. Printout of changes in st...eld office printer. permits monitoring field equipment from the The first page lists LACT sales and test production office during the working day and provides for the last 24 hours for each battery a record of event...
American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. This paper was prepared for the Rocky Mountain Regional Meeting of the Society of Petroleum Engineers of AIME, to be held in Casper, Wyo., May 15–16, 1973. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract A computer-controlled automatic well test system using short-term tests for both flow indication and production testing was installed in Amoco Production Company's Winkleman Dome Field, Wyoming, in late 1970. Tests of 30 to 60 minutes duration are used to test every well at least once a day. Over a year of operating experience has proven the success of short-term tests in locating rapid production declines and evaluating equipment changes and workovers. The system also monitors the operating status of secondary recovery and tank battery equipment. Short-term test accuracy is reviewed, field equipment described, and operations under automation discussed. Economic evaluation indicates payout of the installation in 2.1 years through increased production and reduced costs. Introduction Engineering studies conducted in late 1968 determined the accuracy of short-term well tests at Winkleman Dome Field and demonstrated the economic feasibility of installing a computer-controlled automatic well test and equipment alarm system. Approval for a system was obtained in April, 1969; equipment installation was completed in December, 1970; and the system was fully operational by March, 1971. WINKLEMAN DOME FIELD Winkleman Dome Field, located 30 miles WNW of Riverton, Wyoming, produces 9,500 BOPD and 40,700 BWPD from 98 wells over approximately 1,000 acres. Secondary recovery projects include a steamflood in the Nugget formation, waterflooding of the Phosphoria, and alternate gas-water injections into the Tensleep. The field is produced at capacity with any deferred production resulting in loss of current income. SYSTEM DESCRIPTION A computer-controlled automatic well test and equipment monitoring system was installed, because it offered the optimum savings in man-hours spent testing wells, checking equipment, and making reports. The system is designed to gather well test and production data, monitor equipment status points, and control only production data, monitor equipment status points, and control only the well testing equipment.
- North America > United States > Wyoming > Fremont County (1.00)
- North America > United States > Oklahoma > Osage County (0.86)
- North America > United States > Wyoming > Winkleman Dome Field (0.99)
- North America > Canada > Alberta > Lost Field > Adamant Et Al Lost 10-3-84-1 Well (0.99)
...Society of Petroleum Engineers SPE 24806 Well Test Systems: Designing for Accuracy B.M. Tuss and R.A. Kendrick, Conoco Inc. Copyright 1992, Society ... meters large enough to handle the highest expected flow (including instantaneous Conventional well test systems often generate slug flow). Careful selection of liquid outlet inaccurate results. Separatio... to liquid properties are part of the liquid discharge rates and meter capacities are problem. Well production sensitivity to back compatible. Three phase separators of the pressure is another. bucket and weir...
...essure ( f 50 ACCURACY AS A PRIORITY psi) higher than the separator pressure. The evolution of well test systems has been An oillwater analyzer is located in the liquid line shaped by priorities relating ...to production just downstream of the pump and connected to allocation for oil or gas reservoirs for purposes the ...r. This prime design objective for a gas property fraction is applied to the liquid meter output to production, while oil properties focused on oil report oil and water volumes leaving the volumes. Measurement ...
...s shown in figures 3 & 4. The liquid transfer pump supplied another upgrade objective for 'the well test system by providing a means to ...test wells at their normal producing wellhead pressure. Extra back pressure on the well is practically e...liminated during test because the pump provides a means to move the liquid out of the separator. This not only improves w...
Abstract Conventional well test systems often generate inaccurate results. Separation and measurement problems due to liquid properties are part of the problem. Well production sensitivity to back pressure is another. Well test accuracy can be improved by upgrading the test system with a liquid transfer pump and an oil/water analyzer. Simultaneous conversion or retrofitting an existing three phase separator to two phase operation will increase liquids capacity five fold. Introduction Determining the production rate for each well in a multi-well commingled producing system requires well test facilities to:separate the multiphase well stream into measurable phases, measure the quantity of each well stream component, and maintain normal well flow conditions during the test period. Conventional test facilities are shown in figure 1 and figure 2 wherein three phase separators direct oil, water, and gas streams to single phase meters. The motive force to push the liquid and gas streams through metering devices is supplied by separator (ie well stream) pressure. Test systems for multi-well service must have separators and meters large enough to handle the highest expected flow (including instantaneous slug flow). Careful selection of liquid outlet controls and meters is required to ensure that liquid discharge rates and meter capacities are compatible. Three phase separators of the bucket and weir configuration equipped with snap action liquid dump valves have evolved as the most flexible of the conventional test system. However, the best of conventional system are plagued by a host of problems that lead to inaccurate test results. DESIGNING FOR ACCURACY Establishing the design objectives for improving the accuracy and reliability of well test facilities requires eliminating problems in the following key areas.Conducting well tests without increasing wellhead backpressure. Eliminating oil and water separation problems. Reducing the effects of viscosity on liquid meters. Eliminating metering errors due to liquid volatility. Minimizing gas flow surges and providing flow integration capabilities for gas measurement. P. 419^
...ject Pro-ration values of monthly plant bitumen volumes 10 consisting of 53 injection wells and 163 production well ...test bitumen volumes, formerly averaging 1.5 wells direclionally drilled from eight pad locations (rangi...er the use of nel oil operations, 1986-1991. monitors was adopted. Improvements 10 field-wide well test accuracy are depicted in Figure 3. Although both PRISP and PREP continue to meet pertormance target...
...WELL TEST IMPROVEMENTS AT SHELL CANADA'S PEACE RIVER THERMAL PROJECT W. LENTZ this article begins on the nex...CIM and AOSTRA PAPER NO. CIM/ AOSTRA 91 -79 ATMB-12 THIS IS A PREPRINT - SUBJECT TO CORRECTION WELL TEST IMPROVEMENTS AT SHELL CANADA'S PEACE RIVER THERMAL PROJECT BY Wayne Lentz Shell Canada Limited PUB...uent addition to achieve liquid phase separation. Since it was too costly to supply diluent to each test satellite at this project, two-phase ...
...ETY OF CIM and AOSTRA PAPER NO. CIM! AOSTRA 91-79 THIS IS A PREPRINT - SUBJECT TO CORRECTION WELL TEST IMPROVEMENTS AT SHELL CANADA'S PEACE RIVER THERMAL PROJECT BY Wayne Lentz Shell CMada Umllftd P...ion have been implemented. Improved The 8 API gravity bITumen produced at Shell reliability of well test water cuts and increased Canada's Peace River Oil Sands Project requires operating safety during we...e resulted from the field-wide use of the net oil Since it was too costly to supply diluent to each test monitors. satellite at this project, two-phase lest separators were installed and manually collecte...
Abstract The 8 ° API gravity bitumen produced at Shell Canada's Peace River Oil Sands Project requires diluent addition to achieve liquid phase separation. Since it was too costly to supply diluent to each test satellite at this project, two-phase lest separators were installed and manually collected fluid samples were used to determine water cuts. This test method showed consistently poor repeatability and poor accuracy with respect to plant balances. The use of an in-line, full-range (0–100%) net oil monitor capable of operating at the extreme temperature conditions encountered at Peace River has significantly improved well test accuracy. The instrument utilizes the inherent differences in microwave energy absorption between water and a liquid hydrocarbon phase to differentiate between the relative amounts of each in a flowing medium. Several improvements to the unit's electronics and alterations to the installation / calibration have been implemented. Improved reliability of well test water cuts and increased operating safety during well testing are benefits that have resulted from the field-wide use of the net oil monitors. Introduction A Brief History Shell Canada's Peace River Complex is located in northern Alberta, 400 km northwest of Edmonton (Figure 1). The Complex processes bitumen produced from the lower Cretaceous upper Bullhead formation. The produced bitumen is an 8 ° API gravity crude with a viscosity range of 200,000 cp at 20 ° C to 20 cp at 150 ° C. Shell Canada's efforts to investigate potential recovery strategies for extraction of the Peace River oil sands began in the early 1960's. Extensive research, physical model experiments, numerical modelling and field tests led to the development of the Peace River In Situ Pilot (PRISP) in 1979. PRISP is presently entering its twelfth year of operations, 1979–1991. The technical success of PRISP led 10 the development of the Peace River Expansion Project (PREP) in 1986. PREP is a commercial scale project consisting of 53 injection wells and 163 production wells directionally drilled from eight pad locations (Figure 2). PREP is presently entering its fifth year of operations, 1986–1991. Although both PRISP and PREP continue to meet performance targets, significant potential exists to enhance bitumen recovery and thermal efficiency. One of the most valuable tools available for evaluating project performance is well test data. Well Tesling Three-phase separators requiring the addition of a diluent to enable separation of the 8" API bitumen from water are utilized at PRISP. Well test data at PRISP has been very accurate within 5% of the plant lank balance. At the time of the field expansion in 1986, three-phase separators and diluent lines to the remote PREP satellites were deemed too costly. Less expensive two-phase separators were installed in the PREP field and manually obtained grab samples for water cut analysis were taken downstream of the separator. PREP well tests based on grab samples proved to have consistently poor repeatability, poor accuracy, limited frequency (one test per day) and operator safety concerns. Well Test Improvements Alternate sampling techniques using mechanically obtained samples were investigated during 1987 in an effort to mitigate the shortcomings inherent in the grab sampling technique.
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Facilities Design, Construction and Operation > Unconventional Production Facilities > Oil sand/shale/bitumen (1.00)
- Facilities Design, Construction and Operation > Processing Systems and Design (1.00)
...OLEum conFEREnCE " A PRACT ICAL METHOD OF ACH IEV ING GOOD WEll PRODUCT ION AllOCATI ONS FROM WEll TEST DATA INTHE PRUDHOE BAY FIELD " & EKHIBITlon by Kenneth F. Chadwick, The British Petroleum Co. Ltd...management demands fitting technique are obtained from a series vf three accurate fundamental well test data for reservoir well tests run at different ...production rates. study and predictions to obtain the best reservoir engineering possible. In order to mainta...
... These constants are calculated from a ser es of on line real time computer which controls the production three well tests each run at a different rate and are rate from each well. This computer also perfo...ance of the well, but in general is of the order of one month. The method of perform ng the The production from the wells is taken through allocation is as follows: individual 6" flow lines to the Gathering...ator. and stored. At the end of the day these incremental volumes Four banks of separators plus one test bank are of oil are summed for each well and the sum of the set up in parallel and the 24 wells are...
... a similar manner As a check on the accuracy of the control system to the gas allocation. The last test water out, usually the computer scans the choke position of each well a laboratory measurement on a... insufficient relates choke diameter to flow for a constant pressure purge time of the well in the test bank downstream of the choke. Although we had a good correlation and it is now clear that in order ...to achieve quality between "manifold" pressure and flow this well testing the test separator and its feed well must could not be used for control purposes, since if a be in complete...
ABSTRACT A curve fitting technique has been developed for use in the West Operating Area of the Prudhoe Bay Field Unit that allows the operators to make daily well allocations for accounting purposes to an accuracy of better than +0/-5%. The data required to allow the use of this curve fitting technique are obtained from a series of three well tests run at different production rates. In order to maintain the above allocation accuracy, quality control criteria were evolved in order to determine the acceptability of well tests for this purpose. INTRODUCTION The Prudhoe Bay Field is the largest oil field in North America with an estimated ultimate recovery of 9.8 billion barrels. (1.56 × 10 Cu. Metres). It is also a unitised field owned by 16 working interest owners and operated on behalf of those owners by Sohio Petroleum Company in the western half and ARCO in the eastern half of the field. Because the field is located in the Arctic and with the consequent difficulty of storing crude at very low ambient temperatures, only about 460,000 barrels (73,000 cu. metres) of crude tankage is provided at the northend of the TAPS pipeline. This is less than 8 hours of storage time at the full throughput rate of the line. As a result the field is run on "flow control"with the field necessarily following the TAPS pumping rate almost on an hour to hour basis. These three facts combine to produce very stringent conditions in regard to well allocation accuracy, well rate control and well test accuracy. In order to achieve equitable allocations of produced volumes of oil, gas and water to the working interest owners, very accurate allocations of these fluids on a per well basis are necessary. In order to have the flexibility and speed of response to follow TAPS'pumping rate variations and guarantee maximum utilisation of the pipeline capacity, accurate control of rate on a per well basis is necessary. Because of the size of the field, efficient reservoir management is mandatory to maximise the hydrocarbon recovery. Efficient reservoir management demands accurate fundamental well test data for reservoir study and predictions to obtain the best reservoir engineering possible.