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^

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^

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^

Abstract Custody transfer metering is part and parcel of the petroleum production operations. Every cubic metre of hydrocarbon produced has to be accurately measured. Measurement systems in the oil and gas industry have developed rapidly in terms of sophistication and usage of modern technology and Malaysia has to keep abreast of this development to ensure not only the accuracy of measurement, but also the reliability and accountability of the measurement systems. Introduction Sales or custody transfer metering generally forms the basis for contractual arrangements between sellers and buyers, different producers and owners, and governments. The quantity of oil or gas that passes through the delivery point, and the amount of money that changes hands would depend almost exclusively on the measurement registered by the metering system. In Malaysia, oil production started in 1910. However, it is only recently that metering has become a subject of very close scrutiny. This can be attributed to the following reasons: PETRONAS' requirements for the highest possible accuracy and standard of measurement; The price of crude oil has greatly increased over the last 10 years;and Advances in electronics have resulted in many improvements in the design and control of metering systems. PETRONAS, the Malaysian National Oil Company, has the full ownership and PETRONAS, the Malaysian National Oil Company, has the full ownership and the right to explore, produce and sell petroleum and petroleum products. PETRONAS has therefore the unique responsibility to ensure that its PETRONAS has therefore the unique responsibility to ensure that its contractors explore, produce and operate the oil and gas fields in a workmanlike manner and in accordance with international and industry standards. PETRONAS has issued several operating procedures and guidelines governing PETRONAS has issued several operating procedures and guidelines governing certain aspects of its contractors' operations. These procedures cover the areas of exploration, production, transportation, processing and export of oil and gas. In formulating the guidelines and procedures for metering, PETRONAS has drawn on the experience of other oil and gas producing PETRONAS has drawn on the experience of other oil and gas producing countries. This is to ensure that the guidelines and procedures are technically acceptable and are being practised in other parts of the world. p. 5–85 p. 5–85

The present situation of the geothermal energy developments in Japan is such that six geothermal power stations are being operated and one under construction. Although there are still many geothermal areas to be explored, it will take a long time to realize them. For such a geothermal field development, it is expected to develop a simulation model which can give rational data for planning strategies. With a view to it, the model should be able to simulate physical phenomena in the geothermal field. The system shown in this paper is composed mainly of two principal physical models; Reservoir Model and Well Model. The former is based on the mathematical description of fluid flow through porous media and the latter through vertical pipes. The final purpose of this study is to develop simulation models for optimizing the scheme of geothermal field development. Introduction The present situation of the geothermal energy development in Japan is such that six geothermal power stations are being operated and one under construction. Although there are still many geothermal areas to be explored, it will take a long time to realize them. Up to this day, the target of geothermal exploration has mainly been the areas determined by surface geological survey and the existing geothermal reservoirs are located not deeper than 1,500m depth. Recent geothermal energy development shows a trend from the study on vapor dominated or liquid dominated hydrothermal resources in shallow zones to that on hydrothermal resources in the deeper zones (3,000m - 4,000m depth). An exploration well of 3,000m depth class has been drilled in the northern part of Kyushu. For such a geothermal field development, it is expected to develop a simulation model which can give rational data for planning strategies. In view of this, the model should be able to simulate physical phenomena through the fife of the geothermal field. The physical phenomena through the fife of the geothermal field. The development system is composed mainly of two principal physical models; Reservoir Model and Well Model. The former is based on the mathematical description of fluid flow through porous media and the latter through vertical pipes. The equations of mass balance and energy balance are solved simultaneously by numerical methods. The input data to this system is compiled in the exploration investigation stage. Static physical characteristics of objective reservoir and allocations and dimensions of production/ injection wells are provided in the models. The trial purpose of this study is to develop a simulation model for optimizing the scheme of geothermal field development. Three-dimensional Reservoir Model This model simulates the behaviors of fluid flow in a geothermal reservoir, assuming water influx and heat conduction from heat sources under the reservoir. Basic Equations: The following three equations describe a system, where mass transfer and heat conduction occur. Mass conservation equation ------------(1) Energy balance equation ------------(2) Equation of state (in case of water-steam equilibrium) ------------(3) where, = =1 The boundary conditions for solving the above equations are= 0 nd = 0 for mass and heat flow, respectively. Both mass and heat production terms are also considered to account for water encroachment and heat flow through the boundaries. Potential equilibrium and heat equilibrium are adopted for the Potential equilibrium and heat equilibrium are adopted for the initial conditions which in turn imply no mass flow and steady state heat flow. Difference Equations: Equations 1 through 3 ar-e approximated by the finite difference equations as follows. -----------(4) -----------(5) -----------(6) The right hand sides of the eqs. 4 and 5 are expressed in terms of delta P using Z. The eqs. 4 and 5 can be written in the following matrix form with delta Sw, delta T and delta P as independent variables.

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.

Discovery and delineation wells which proved the Udang Field did not yield sufficient data to indicate the complexity of the reservoir. Development drilling showed the Udang pay section to be a series of interbedded shales and sands having individuals gas caps and water/oil contacts. The initial plan, to complete the wells by perforating a 40-foot section and installing a screen with slurry pack, was quickly changed in favour of multi-zone single selective completions. This paper describes the various types of completions and equipment used, and the success achieved by utilizing single selective completions to control excessive gas and water production. The field commenced production in January 1979. Since then to the present, about 100 trips have been made with wireline tools to oen or close sliding sleeves with only one failure. In 3 wells the same sliding sleeve was successfully actuated six times. This has been achieved even though some wells have 65 degree inclinations and most all wells produce measurable amounts of sand. It is concluded that these type completions have substantially increased present and projected oil recovery from the Udang Field. Introduction Conoco, as operator for itself, Java Gulf Limited, Getty Oil International (Indonesia) Ltd. and Inpex Natuna Limited, has completed development of the Udang offshore field in the Natuna Sea, Indonesia. It is located approximately 1000 Km north of Jakarta as shown in Figure 1 . Water depth at this location is 300 feet. Production commenced January 18, 1979 with completion of well A-1 and reached 40,000 BOPD after completion of development drilling in the â??Bâ?¿ platform early October 1981. Exploration and Discovery On October 16, 1968 a Production Sharing Contract was signed between Pertamina and conoco Indonesia to explore for and develop hydrocarbons in the Block â??Bâ?¿ contract in the Indonesia South China Sea. The Udang anticline in Figure 2 was primarily delineated by data from seismic surveys run between 1968 and 1975, with most detailed data being acquired in the period 1973 – 1975. In 1977 additional detailed seismic data were obtained in the northeast and north areas of the structure, and in 1979 in the southwest portion of the anticline. Four exploratory wells, Udang 1, 2, 3, and 4, were drilled on the Udang anticline between July 1974 and May 1975. All wells tested hydrocarbons; however, Udang 1 and 3 had the most significant oil flows. Development The results of the first four exploratory wells justified the placing of a production platform (Udang â??Aâ?¿) in the central part of the anticline and the drilling of 13 development wells in the period December 1978 to November 1979. An additional platform (Udang â??Bâ?¿) was set in September 1980 from which an additional 13 wells were drilled with the last well completed on September 23, 1981. (See Figure 2 ). The producing reservoir in the Udang Field in the Udang Field is the Gabus Sandstone of Oligocene age. The sand was deposited from a very large deltaic fan identified to be 1500 feet thick and extending 30-40 miles in length with a width of 3 to 5 miles. Udang production occurs in the top 300 feet of this sand/shale sequence, hence the entire field is underlain with water. Several individual sand members have been identified in the immediate field area and given nomenclature as shown on Figure 3 . An example log is shown on Figure 4 . Most producing zones have average permeabilities exceeding one Darcy. The complexity of the reservoir was not known when initial development plans were formulated based on information obtained from exploratory wells, 1, 2, 3, and 4. The reservoir was described as two separate accumulations as shown by Figure 5 , the Upper Gabus as a thin sand having a large gas cap and a small oil ring; the Main Gabus as a massive sand, with interbedded shales, containing undersaturated oil. The development plan called for all Main Gabus wells to be completed by perforating a 40-foot section in the 7" production string and doing a single inside gravel pack completion using 40–60 mesh Ottawa sand resieved to meet specifications of less than 5% coarse or 2% fine particles. The screen and tell-tale was 8 gauge wrapped all-welded type 316 stainless steel double annealed wire having a controlled Rockwell â??Câ?¿ hardness of less than 22. Development well A-1, completed on 18 January 1979, did not substantiate the original concept of two main hydrocarbon bearing units, (Upper and Massive Gabus Sands), within the Gabus reservoir. It was temporarily completed as a single well without gravel pack in order to evaluate the sensitivity of sand production and check the performance of the reservoir under this producing condition. Well A-2 found an additional and distinct oil bearing sand not seen in other Udang wells; it was completed as dual single selective with the lower zone gravel packed as per original plans ( Figure 6 ).

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.