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Abstract This paper describes the measurement of crude oil volume in an oil/water mixture that discharges from an oilfield. Measurement is carried out using a turbine meter, a densitometer and a flow computer. The system is capable of determining the volume of crude oil in a flowing stream of a crude oil/water mixture within 2% of the total liquid volume. Introduction Baram Delta is located off the coast of Sarawak, East Malaysia. The producing fields within the Basram Delta comprise the Betty, Bokor, Siwa, Tukau, Baronia, Bakau, Baram, Fairley-Baram and West Lutong fields. Betty, Bokor, Siwa and Tukau are currently being operated by Sarawak Shell Bhd (SSB) under a Production Sharing Contract (PSC), signed between the Malaysian National Oil Company (PETRONAS) and SSB in 1976. The remaining fields are also being operated by SSB, but for and on behalf of a Joint Venture between SSB and Petronas Carigali Sdn Bhd (PCSB) under a PSC signed in 1985 between PETRONAS and the Joint Venture parties. The said fields, Baronia, Bakau, Baram, Fairley-Basram and West Lutong, were relinquished by SSB under the terms of the PSC signed in 1976. The existing liquid measurement and reallocation procedures are in general sufficiently accurate to meet the requirements for fields and reservoir management. However, the process of reallocation of crude oil between the fields operated under the terms of the 1976 PSC and the fields operated under the 1985 PSC, leaves a non-quantifiable uncertainty which could introduce errors larger than 2% of the gross volume. This was the maximum error specified by a Task Force comprising PETRONAS, SSB and PCSB and agreed by all parties in early 1986. Hence, a new measurement system was proposed. As its use for the application intended is without precedent, a laboratory simulation and a pilot test of the system were carried out. This paper deals with the tests carried out to prove the reliability and suitability of this system in oilfield conditions. 2.0 THEORY OF THE MEASUREMENT SYSTEM The theory of calculating the net oil volume and the mixture volume flowrate at standard conditions is summarized in the flowchart below. Volume flowrate Computation of % of mixture at mass of oil in line conditions oil/water mixture Q(m1) Density of mixture at line conditions> D(m1) Mass flowrate of > mixture M(m) Mass flowrate of Density of oil M(o) mixture at standard > conditions D(ms) Density of oil < at standard Volume flowrate conditions D(os) of mixture at standard conditions Q(ms) Volume flowrate of oil at standard conditions Q(os) Totaliser P. 331^
- Government > Regional Government > Asia Government > Malaysia Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract A numerical two-phase modal is developed to simulate the production performance of the Mobara-type water-dissolved natural gas reservoir in Japan. By using this model, the behavior of producing gas-water ratio and reservoir pressure is matched successfully. This paper also presents some calculation examples by the matched model which describe the effect of permeability, relative permeability and initial gas saturation on the above production performance. Introduction Water-dissolved natural gas is the natural gas dissolved in subsurface brine. It is the main Japanese hydrocarbon resource. Because the primary composition is methane, containing almost no hydrogen sulfide, it is demanded considerably both as a town gas or domestic fuel and as feed-stock for chemical industry. About 80% of the water-dissolved gas production comes from the Southern Kanto region, just east of Tokyo, and Mobara gas field is one of the main fields in this region (see Fig.1). The characteristic of the Mobara gas field is that producing gas-water ratio increases rapidly with the drainage of water (see Fig.2). The mechanism was discussed qualitatively by Ueno, et al., Kanto Natural Gas Development Co. Ltd., and Marsden, et al. However this paper presents a two-phase simplified model to simulate the production performance numerically. History matching of the producing gas-water ratio and reservoir pressure by this model shows very good agreement with the actual data. On the other hand, it has been of great interest how the production performance is affected by the reservoir permeabilities, the relative permeability and initial gas saturation after the gas field is put into operation. This paper presents some calculation examples to show these effects by the history matched model. MOBARA GAS FIELD Kanto Natural Gas Development Co. Ltd. and Marsden, et al. discussed the technology of methane and iodine production in the Mobara gas field. Some pertinent reservoir description information from these papers is repeated for convenience. Reservoirs in the Mobara gas field are chiefly composed of unconsolidated fine sand within the alternate facies of the Kazusa group, which is composed of thick marine sediments of Pliocene age extending over the Southern Kanto district (see Fig.1). The Kazusa group dips gently northwestwards with monoclinical structure. P. 582^
- Asia > Japan > Honshu Island (1.00)
- Asia > Japan > Kantō > Tokyo Metropolis Prefecture > Tokyo (0.24)
- Asia > Middle East > Israel > Mediterranean Sea > Southern Levant Basin > Gal Field (0.99)
- Asia > Japan > Honshu Island > Mobara Field (0.99)
CONDENSATE PRODUCTION OPTIMIZATION IN THE ARUN GAS FIELD Abstract In the Arun Field, Mobil Oil Indonesia Inc. (MOI) has implemented a condensate production optimization program on its Supervisory Control and Data Acquisition (SCADA) system. This program has been proven successful in improving 3200 BPD at 2,270 MMSCF daily average separator gas flowrate. 1.0. Introduction The Arun gas field is located in the Aceh province, about 350 kms. southeast of its capital city, Banda Aceh, Sumatra Island, Indonesia. The reservoir is a carbonate reef reservoir. The net volume is 11.5 million acre-feet with the average net pay thickness of 494 feet. The 10,000 feet subsea, while the highest encountered limestone top is 9400 feet subsea. The production facilities are located within four (4) individual clusters which contain the producing wells, well stream coolers and separators. Cluster II and Cluster III have one (1) and two (2) gas reinjection compressors respectively. There are 35 production wells currently in the four clusters and ten (10) gas injection wells (GIWs) into the thickest part of the formation around the North, West and South flanks of the field. Gas condensate and water are separated at each cluster through two (2) identical process trains. The gas and condensate are gathered at a central pipeline manifold and metering station at Point A. Point-A is situated between Cluster II and Cluster III at the center of the field as per Figure 1. This is also the location of the field administrative offices, power generators, warehouses, maintenance shops and Central Control Room (CCR). CCR coordinates field production and emergency communications. 2.0 FIELD OPERATION Each cluster was designed to be identical. Each cluster has locations for up to 16 production wells, most of which are deviated to achieve maximum spread of bottom hole locations as per Figure 2. Well and individual cluster process controls are located in, and mainly operated from, the Cluster Control Room. The operation of Cluster Control Rooms and CCR are connected by the SCADA system. This enables operators at CCR to monitor cluster operating conditions and to coordinate production. P. 871^
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment > Reef Environment (0.75)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.54)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Facilities Design, Construction and Operation > Measurement and Control > SCADA (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
Abstract In order to minimize the tubing corrosion during production in a gas well, it is necessary to determine the factors such as wettability of tubing and critical erosional velocity etc. for the design of tubing corrosion prevention. The purpose of this work is to study the phase behavior of the production fluid in a production tubing in connection with the flowing velocity and wettability of tubing. Data from a CO2-rich offshore gas well of Taiwan are analyzed by a procedure developed in this study. It is shown by our calculation that the tubing in the well should not be corroded seriously during production because the tubing inner wall is oil-wet and the flowing velocities are much less than the critical erosional velocities. Introduction A gas reservoir may be filled with natural gases, water, and possibly water vapor, condensate vapor saturated in natural gases may condense due to changes in pressure and temperature in the production tubing. The water and carbon dioxide may form carbonic acid which is corrosive to the tubing wall. The degree of tubing corrosion is affected by two major factors:the wettability of the tubing wall; the tubing flowing velocity. The wettability of tubing is determined by the amount of water and oil (condensate) adhering to the tubing wall. The amount of condensed water and oil is related to the phase behavior of flowing fluids in tubing. The pressure in tubing, playing an important role in the phase behavior, is varied with the production rate which is in turn related to the tubing flowing velocity. Therefore, two factors mentioned above have close relation with phase behavior of production fluids. Determination of the phase behavior can provide information for locating the occurrence of condensed oil and water which are important for the possibility of forming carbonic acid and for determining the wettability of tubing. In addition, a critical erosional velocity, a threshold value to increase tubing corrosion rate of a factor of four, should be estimated for the production control to prevent tubing corrosion. The purpose of this work is to study the phase behavior of the production fluid in a production tubing and to determine the wettability of tubing, critical erosional velocity, and flowing velocities for corrosion control. The result of the study is intended to provide key information for corrosion prevention design. PRESSURE DISTRIBUTION In order to estimate the amount of condensed oil and water in tubing, it is necessary to determine the flowing pressure distribution. The pressure distribution in tubing can be calculated by the equation suggested by Cullender and Smith for a vertical well. Productivity of a Horizontal Well 18334 Copyright 1988 Society of Petroleum Engineers, Inc. This paper was prepared for presentation at the 63rd Annual Technical Conference and Exhibition of the Society of Petroleum Engineers held in Houston, TX, October 2-5, 1988. This paper was selected for presentation by an SPE Program Committee following information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. 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. Write Publications Manager, SPE, P.O. Box 833836, Richardson, TX 75083-3836. Telex, 730989 SPEDAL. APPENDIX A Two appendices describe the mathematical and algebraic details that led to the formulas provided in the text of this paper. Appendix A presents the general solution, and briefly describes the techniques for deriving simple, closed form expressions for single, double, and triple sums of infinite series. Appendix B describes these procedures in a little more detail, and also indicates certain methods for averaging the variable wellbore pressures in the general anisotropic cases. Uniform Flux Boundary Condition For well problems similar to the one treated in this paper, a uniform flux, or a uniform pressure is commonly imposed as a boundary condition at the well surface. Recognizing that neither is entirely correct, the question that has been debated is whether one is preferable to the other, or whether both give satisfactorily accurate solutions. Muskat showed that the uniform flux boundary condition gives values accurate to 0.5 percent. We also investigated the implication of the uniform flux assumption. We used our exact solution (Equations A1-A3) and computed the wellbore pressure, Pwf at various locations y along the well length L. We did this for isotropic and anisotropic systems where the wells were located at the center, or away from the center. For the anisotropic runs the value of kx was equal to, or twice as large as, that of ky, and was ten times that of kz. Also L/b=0.5. We found that the maximum variation in Pwf values was 7 psi for the worst case. This was the anisotropic case with kx=2ky, kx=10kz, and the well was located away from the center. P. 885^
- Asia > Taiwan (0.35)
- North America > United States > Texas > Harris County > Houston (0.24)
- North America > United States > Texas > Dallas County > Richardson (0.24)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Abstract Huffco Indonesia has developed and installed a computerized database system called PARM System - Production and Reserves Monitoring System. This integrated database handles data that includes reservoir, geological, production, operations and mechanical well data. while the PARM System data are acquired and controlled from many technical and operations disciplines within the it is always input as close to the original source as possible. The PARM System, as an integrated production and reserves data source for Huffco Indonesia, has applications across a wide range of engineering and operations disciplines. Daily production and operations reports, monthly production allocation and product distribution reports, daily drilling reports and summary reports and many other necessary routine reports are. generated by the PARM System. Benefits of analysis of large volumes of data, which were previously very cumbersome to attempt, are now being realized by engineering groups. Ad-hoc data retrievals provide consistent current and historical data for production and reservoir engineering applications. An integrated computerized database system such as the PARM System, provides a cost and time efficient engineering and operations tool. It provides unparalleled accessibility to any data likely to affect or resulting from the oil and gas production of a well, zone or field. Accuracy of original data is improved due to multi-user review and built-in integrity chocks. Development of a system, such as the PARM System, should be done on a prototype basis under direct engineering management. Application of computer technology to the petroleum industry is manifested in the PARM System by virtue of capturing and handling of the basic oil and gas operations and engineering data. This paper describes the design and implementation concepts of the PARM System as well as engineering and operations applications ranging from simple reports and data retrievals to interfacing with reservoir simulation software. Introduction Huffco Indonesia is the operator of an oil and gas Production Sharing Contract (PSC) area in East Kalimantan, Indonesia. Wells in the PSC area currently range to 15,000 feet in depth with producing horizons being completed in various intervals between 1000 feet to 12000 feet. In one of the four currently producing fields, Badak, there are more 200 unique zones. Producing and producing fields have a total of 336 wells. Many of the wells in the producing fields have dual or multiple completions with some having commingled zone production. while the four currently producing fields produce approximately 37000 barrels of oil and condensate per day, the major production is natural gas where the capability is in excess of 1 billion standard cubic feet per day. The natural gas production, after processing at the respective fields, is supplied to the Bontang LNG plant where it is liquefied and utilized to fulfill contracts with offshore buyers. With firm long-term contracts in effect, it is imperative that the supply be able to meet the demand. To insure that this criterion is maintained it is essential to have an accurate, current, accessible database of the various parameters affecting the ability to supply. Huffco, with consulting assistance, performed project definition and planning study which aided in defining objectives and the philosophy of operation of a Production and Reserves monitoring System. In assessing the large volume of interrelated data to be handled the objectives of Production and Reserves Monitoring System were defined to be as follows:–Provide timely common access to basic data for performance monitoring. Under the existing system considerable time could pass before basic data such as well tests, would reach personnel responsible for monitoring and analysing well performance. –Minimize redundancy of information handling, transcribing, summarizing and copying of data resulting in time loss and frequent data transcribing errors. P. 614^
- Asia > Indonesia > East Kalimantan (0.54)
- Asia > Middle East > Israel > Mediterranean Sea (0.24)
Abstract Earth, barometric and ocean tide effects hove been observed for many years, principally in hydrogeolgical work. During testing of wells in the Timor sea we have observed ocean tide effects in the reservoir with an amplitude of - 0.07 bar (1 psi) about 70 times larger than earth or barometric tide effects. This paper has two aims: to provide an overview of analytical interpretation of tidal affects from a petroleum engineering viewpoint and second, based petroleum engineering viewpoint and second, based upon our simulations and observations, to propose that in addition to previous methods of interpretation the phase shift of ocean tide effects can be used to gain an insight into the presence of major reservoir heterogeneities, particularly fluid contacts. There is a need for more field data and further investigations, however we believe we have demonstrated the existence of a useful and previously unused aspect of pressure measurement in offshore wells. Introduction The effects of a periodic tidal stress - having their origin in the gravitational attraction between the sun, moon and the earth - on the fluid accumulations in porous strata in the earth have been observed for more than one hundred -years-). The majority of the observations were made in mines and open water wells in which even the smallest periodic fluctuation of water level was easily detectable and recordable. It was only in about the last decade, after the advent of high sensitivity pressure gauges (crystal and strain gauges). that a similar observation could be made in petroleum reservoirs. In these circumstances it is understandable that the main theoretical analysis of this phenomenon and all attempts at its practical interpretation and application ere accomplished in the field of hydrogeology. Yet we can expect that in future the tidal effect will be observed and recorded more frequently during the testing of petroleum wells and that it will eventually be accepted as a new piece of information which will be worthwhile interpreting. The tidal effect on the fluid pressure in buried porous strata is a complex one. The cyclic porous strata is a complex one. The cyclic fluctuation of pressure as it is measured in aquifers and reservoirs is generally a consequence of a tidal dilatation of the porous system (AA). However there are three different mechanisms by way of which the prime cyclic fluctuation of the strength of gravity prime cyclic fluctuation of the strength of gravity field produces this final effect. The total dilatation (AA) can be considered as a sum of three independent partial effects:the solid earth tide dilatation the barometric tidal dilatation the ocean tide dilatation so that ........................... (1) All the components naturally arise from the same lunar and solar tide generating forces however each of them will have a different magnitude (amplitude), efficiency, frequency and phase 5. The complexity of this phenomenon is further aggravated by the complex nature of the tide generating potential itself which consists of several tidal components with varying frequency and amplitude. 1. .) Consequently the final product of these forces is a complex periodic pressure fluctuation with many harmonic constituents. For each particular tidal constituent of angular frequency (w) the variation of the induced dilatation (AA) with time (t) can be described by the equation (2) in which 0 A' 0 El (D B and (Do are phase differences between the tide generating potential under consideration and the aquifer or reservoir dilatation the earth tide dilatation A El the barometric dilatation 1/2. the ocean tide dilatation A. The main results of past studies are summarised in Sections 2 and 3 of this paper. The majority of these studies had several assumptions in common:–they were based on data from onshore wells and therefore concentrated on earth and barometric tide effects; –they assumed a closed, homogeneous reservoir with no induced flow; –the earth, barometric and ocean tide dilatations were assumed to occur in phase with their respective tidal generating forces. There is, in principle, no obstacle to the application of these results in petroleum reservoir engineering once sufficiently accurate data is available. However, the petroleum engineer now has available a new piece of information for offshore wells: observation and accurate measurement of the ocean tide effect, an effect which we can expect will be measurable in many offshore reservoirs. The importance of the ocean tide effect is that:–it has a much greater amplitude (we have measured a value of 0.07 bar, I poi) than the earth or barometric tide effects (a typical value being 0.001 bar, 0.015 psi). Thus, when interpreting ocean tide effects, all others can be ignored. –As can be seen in Section two of this paper, interpretation of ocean (and barometric) tide effects is based upon a cyclic change to the head of water (or air) which alters the overburden and thus the reservoir pressure. Accurate measurements of surface ocean tide are simple to make and can be compared in phase to (simultaneous) measurements of the reservoir pressure. Thus. not only can we gain a measure of formation compressibility and porosity (as was possible previously) but we may also be able to investigate the previously) but we may also be able to investigate the variation of compressibility away from the wellbore through interpretation of the shift of phase between surface and bottomhole measurements. The main objective of this paper is to present our current understanding of these effects and the results arising from them. This is done in Sections 4 and 5 with the aid of mathematical modelling and the results from observed ocean tide effects in the Timor Sea. P. 139
- Geology > Geological Subdiscipline > Geomechanics (0.70)
- Geology > Rock Type > Sedimentary Rock (0.46)
- Geology > Geological Subdiscipline > Environmental Geology > Hydrogeology (0.34)
- Oceania > Timor-Leste > Timor Sea > Bonaparte Basin > Jabiru Field (0.99)
- Oceania > Australia > Timor Sea > Bonaparte Basin > Jabiru Field (0.99)
- Oceania > Australia > Tasmania > Bass Strait > Gippsland Basin (0.99)
The use of a polymeric drag reducer to increase the flow capacity of crude oil pipelines is described in this paper. The first commercial drag reducer application began in July 1979, in the Trans Alaska Pipeline. By 1980, flow through the TAPS line had increased to the 1.5 million bbl/D (9,940 m3/h) level. Approximately 200,000 bbl/D (1,300 m3/h) of this throughput was a direct result of injecting a drag reducing additive. In 1981, drag reducers continue to contribute to the TAPS throughput In commercial operations, a drag reducer must be shear stable during line flow and must be effective at very low concentrations. In addition, the treated crude must not cause any downstream refining problems. CDR Drag Reducer meets these requirements and has proven to be viable means of increasing pipeline flow rates. Recent modifications of the polymeric additive have raised drag reducer performance levels. New performance data from 8, 12, and 48-inch diameter performance levels. New performance data from 8, 12, and 48-inch diameter pipelines are discussed. Offshore production operations would clearly pipelines are discussed. Offshore production operations would clearly benefit from improved performance. Shipping and handling of products present a special problem in offshore operations … particularly in present a special problem in offshore operations … particularly in periods with bad weather. Reducing the required storage will periods with bad weather. Reducing the required storage will proportionally reduce platform space and weight requirements. proportionally reduce platform space and weight requirements. Introduction Drag reducers have been known for many years., Drag reduction has been defined as the increase in pumpability of a fluid caused by the addition of small amounts of an additive to the fluid. The relative performance of a drag reducer may be expressed in terms of percent drag reduction. At a constant flow rate, percent drag percent drag reduction. At a constant flow rate, percent drag reduction is defined as (1) where Delta P is the pressure drop of the untreated fluid and Delta P' is the pressure drop of the fluid containing the drag reducer. The increased pumpability can usually be used to increase flow rate by increasing the pressure drop. P', back to the initial level for the untreated fluid. The percent throughput increase, %F.I., can be estimated using the following equation: (2) Drag reducers received a great deal of attention in the 1960's. A number of polymer candidates were identified. However, the incentives for pipeline use were not attractive enough to justify commercial use. During 1977 discussions between Alyeska Pipeline Service Company and Conoco began on the use of drag reducers. This led to the First commercial use of CDR (TM) Drag Reducer in 1979. This test program leading to this application was described in a previous publication. This paper briefly reviews that test program and describes several other subsequent pipeline tests. It also describes the development of a more effective drag reducer. To qualify as a drag reducer candidate for crude oil pipelines a polymer must (1) be effective at low concentrations, (2) be relatively polymer must (1) be effective at low concentrations, (2) be relatively shear stable during the flow, and (3) cause no downstream refining problems. problems. Low concentration levels are necessary since continued injection is required. The drag reducer reduces the energy lost in turbulent flow by modifying the sublaminar layer and interaction between the fluid and pipe wall. However, it does not treat or coat the pipe wall. The drag reducer must maintain its effectiveness as the fluid moves down the pipeline between booster pump stations. In dilute solutions. the polymer molecules are degraded by the shearing action of the pipeline booster pumps. Therefore. the drag reducer must be injected in a concentrated form downstream of the pipeline pumps. pumps. For the past two years the 1.5 million bbl/D (9,940 m3/h) of North Slope crude, or approximately ten percent of all crude oil refined in the United States, has contained drag reducers. By law, North Slope crude cannot be exported and, therefore, has been shipped to U.S.A. refineries. No problems have been encountered either during the initial carefully monitored full scale refinery tests or in normal operations of refineries throughout the U.S. Initially TAPS was constructed without Pump Stations No. 2,5,7, and 11. Its capacity with this configuration was 1.2 million bbl/D (7,952 m3/h). The 1979 tests were designed to evaluate the flow improvement capabilities of drag reducer as a partial substitute for two of the booster pump stations. In July 1979 continuous injection of drag reducer was begun. During 1980, the mechanical capacity of the pipeline was increased and the daily flow rate was increased to over 1,500,000 bbl/D (9,940 m3/h). About 200,000 bbl/D (1,300 m3h) of this flow increase was the result of injecting a drag reducer. The improved drag reducer performance described in this paper could result in more wide spread use of drag reducers both onshore and offshore. It could even become an economic substitute for part of the pumping energy for many pipelines, particularly with the forecasted increase of energy cost in the future. Pipeline Drag Reduction Tests Pipeline Drag Reduction Tests Drag reduction tests were performed in four different pipelines ranging from 8-inch to 48-inch. Each test was designed to test drag reducer products at two or more velocities.
- North America > United States > Oklahoma > Anadarko Basin > Billings Field (0.89)
- North America > United States > Montana (0.89)
Producing hot, high rate, high pressure wells can subject tubing threads to Producing hot, high rate, high pressure wells can subject tubing threads to compression and tensile forces that exceed the scope of current published data and specifications. Mobil Oil Indonesia, contractor to Pertamina, Indonesia's National Oil Company initiated the development of test apparatus and test procedures to simulate actual downhole stresses on tubulars. Mobil's intention was to fill the gap in the published data and to determine the cause of thread leaks in Arun wells. It was postulated that the leaks were the result of extreme compression and tensile forces acting on the tubing threads. Wells completed in the Arun Limestone are capable of producing 250 MMSCFD at well-head pressures and temperatures of 4000 psi and 347 degrees F. Forces on the tubing string varying from 350,000 lbs compression to nearly 500,000 lbs tension during pressure and temperature reversals between conditions of shut-in, producing and stimulating. The test apparatus and procedure can detect thread leaks while subjecting test specimens to:7500 psi internal pressure Compression and tensile loads up to 500,000 lbs. Temperatures up to 350 degrees F Quenching of internal pin surface such that the temperature is reduced from 350 degrees F to 150 degrees in Application of the equipment and test procedures confirmed the failure mechanism and helped evaluate other thread designs for use in the harsh Arun wellbore environment. Introduction Tubulars, worldwide, are being subjected to a more severe environment as the economics of oil and gas production permit the industry to produce from formations that are deep, hot, sour and high pressure. Producing from these horizons introduce tubing connections to compression and tensile forces that exceed the range of currently published data. Mobil found it necessary to fill the gap between the conditions of published tubular performance data and actual producing conditions. Mobil published tubular performance data and actual producing conditions. Mobil Oil Indonesia operates the Arun Field in Northern Sumatra. High annular pressures in Arun wells suggested that tubing leaks were compromising an pressures in Arun wells suggested that tubing leaks were compromising an otherwise competent completion system. It was postulated that abnormally high wellbore temperatures and pressures were exerting forces on the tubing that exceeded the strength of the connections. Test apparatus and procedures were developed to stimulate actual downhole conditions. Use of procedures were developed to stimulate actual downhole conditions. Use of the equipment and techniques permits detection of thread leaks while subjecting test specimens to:7500 psig internal pressure Axial loads from 500.00 lb tension to 500,000 lb compression. Temperatures up to 350 degrees F. Quenching of the internal pin surface such that the temperature is reduced from 350 degrees F to 150 degrees F in 30 seconds. Test Apparatus Figure 1 is a schematic illustrating the test equipment. A 10-¾ inch I>D. environmental test chamber (1) is mounted via an adapter flange (2) to a load cell (3). The chamber is rated at 10,000 psig burst pressure. The load cell is in the form of a hydraulic press capable of exerting 500,000 lb compression or tension. Two side outlets are fitted with blind hubs (40 and tapped for ½ inch NPT for recording chamber pressure and providing a relief valve. The test specimen is made up of two 7-inch, 35 pounds per foot nipples or pup joints (5) joined by a coupling (6). The specimen has had the threads pup joints (5) joined by a coupling (6). The specimen has had the threads cut that are to be evaluated. A load cell crossover (7) and a 10-¾ inch × 7 inch casing hanger (8) has been attached to the test specimen. The specially fabricated hanger has been tapped to provide: * Water injection to two spray nozzles (9) that direct a cold water sprayon to the seal area of the connection at each end of the coupling. * Nitrogen injection (10) to pressures up to 7500 psig. The pressure inside the test specimen is also recorded at this point. * A vent pipe to extract water and nitrogen and provide a means of stabilizing the internal pressure while injecting water. * Temperature recording (11) from a thermocouple attached to the inside of the top nipple near the lower seal area. * Two high pressure monitoring lines to record pressure from holes (12)tapped in each nipple opposite the sealing area of the connection. This monitors leakage within the connections. The specimen is attached to the load cell piston (13) inside the chamber. The annular volume between the specimen and the chamber is filled with oil. The purpose of the oil is to effect homogeneous heat transfer from the chamber exterior to the test specimen. The specimen assembly is held in position by a seal clamp (14) and hold-down ring (15). Heat is provided by position by a seal clamp (14) and hold-down ring (15). Heat is provided by twelve electrical heater strips that are wrapped around the exterior length of the environmental chamber. Figure 2 illustrates the peripheral attachments to the environmental chamber. Mobil used nitrogen to test the connections. A high pressure gas pump (A) and nitrogen gas supply (B) was used to pressure the test fixture. pump (A) and nitrogen gas supply (B) was used to pressure the test fixture. The spray nozzles are fed by a high pressure pump (C) capable of delivering 12 to 14 gpm against the internal test pressure. The water pump was manifolded (C) to circulate water through a 1/3 inch choke or to pump water to the fixture. A vent line (D) was provided to control the bleed-off of water and excess nitrogen pressure during the water injection cycle. The temperature control panel (E) regulates the heater strips. A strip recorder (F) monitors temperature and pressure exerted on the specimen. A relief valve (G) on the chamber upper port regulates the chamber annular pressure. pressure. Arun Test Apparatus The test facility is designed to simulate wellbore conditions. Table 1 shows the Arun wellbore parameters. Flow rates of up to 250 MMSCFOD through 7-inch tubing cause flowing wellhead temperatures to approach the 350 degrees F bottom hole temperature. Wellhead temperatures have been recorded at 342 degrees F at flowing pressure of 3500 to 4500 psig.