Miscible Flooding Project Research Articles

Electric Submersible Pumps —Reducing Failures Through Improved Field Procedures In The South Swan Hills Unit

Abstract The Amoco Canada-operated South Swan Hills Unit is currently producing under a combined water, hydrocarbon miscible and dry gas flood. Nearly 85 per cent of the daily production of 6 500 m3 oil and 25 000 m3 water is lifted by 106 submersible pump installations. The average run life of a submersible pump in the Unit has historically been about six months. The adverse conditions contributing to this relatively short operating time include high temperatures, high pressures, the depth of the reservoir, small casing diameter, corrosion, changing gas/oil ratios with the associated problems of gas breakthrough and asphaltene plugging. These combined factors have hampered attempts to lengthen the average run life of a submersible pump installation. Concentrated efforts in the past two years, aimed at improving field operations, are now being seen as having a positive impact on submersible pump performance. This paper describes procedures which were initiated and the resulting advancements which have been made in this area. Introduction The South Swan Hills Unit is located 225 km northwest of Edmonton, Alberta (Fig. 1). The Unit (Fig. 2), formed in 1962 and operated by Amoco Canada Petroleum Company Ltd., consists of 191 production and 60 injection wells. Production is from the Swan Hills formation of the Beaverhill Lake Group, which is a limestone reef complex. Bottomhole temperature is 112 °C at a depth of 2500 mKB. FIGURE 1. Location of the South Swan Hills Unit. (Available in full paper) In 1963, the west side of the Unit was put on a secondary recovery water flood. In 1973, a secondary miscible flood project was initiated in the central portion of the Unit. The enriched gas solvent injection is nearing completion, with all injection wells to be converted to dry gas by August 1982. In 1978, the east portion of the field was placed on waterflood. The number of submersible pump installations peaked at 118 in 1980 and has since been reduced to 106. Previous and present local ions are also shown on Figure 2. History The South Swan Hills Unit currently produces about 6 500 M3/d of oil and 25 000 m3/d of water (Fig. 3). Since the first submersible pump was installed in the Unit in January 1971, production has become increasingly dependent on this form of artificial lift (Fig. 4). Currently, 58 per cent of all production wells utilize submersible pumps, representing 85 per cent of total Unit production. With the exception of the first year of submersible pump operation, the annual failure rate has always been higher than the number of installations (Fig. 5) as a result of the harsh operating environment. During 1980, the 118 locations had experienced 239 failures. Because of the increasing failure rate and the tremendous associated operating cost (approximately $45 000 per changeout), Amoco began an intensified study in early 1980 in an attempt to reduce this failure rate. The study reinforced that the major causes of failure were the result of electrical problems, gas interference (often causing mechanical failures), foreign material and corrosion as well as operational procedures.

A Production Logging Tool With Simultaneous Measurements

A new tool provides simultaneous recording of measurements from all downhole production-logging sensors used in the analysis of production or injection wells. The system was used to evaluate production-well profiles in the South Swan Hills miscible flood project in Alberta, Canada. The dynamic reservoir picture obtained from the information proved useful in improving reservoir performance. Introduction Production logs have been used for many years to Production logs have been used for many years to evaluate producing and injection wells. In the past, when reservoirs with excess capacity were limited by allowables, production logs were used basically to diagnose a problem on an individual well, such as locating a source of water production or defining a mechanical problem such as a packer leak. Today, with the increased demand for oil and the declining capacity of mature reservoirs, combined with more sophisticated recovery schemes, the oil industry is becoming increasingly aware of the importance of improving fieldwide reservoir performance. With this shift in emphasis, the role of production logging has taken on a much wider scope.For the evaluation and management of a reservoir, the reservoir engineer may get the information he needs by running production logs on selected production and injection wells throughout the production and injection wells throughout the reservoir. By repeating this on an appropriate time scale, a dynamic description of the reservoir can be evolved. This information can be integrated with formation evaluation logs, such as the TDT log and the initial openhole logs, to compare actual performance with indicated reservoir potential. performance with indicated reservoir potential. The analysis of producing wells is rarely simple. Downhole flow usually involves different fluids (oil, water, and gas) having different densities and moving at different velocities. Furthermore, these may vary with time because of well instability. Typically, several measurements are needed to resolve the problem. The effect of well instability can be reduced problem. The effect of well instability can be reduced by obtaining the measurements simultaneously. Much has been published in the literature on the use of flowmeter, thermometer, manometer, Gradiomanometer TM and caliper tools to analyze downhole flow. In addition, a casing-collar locator and a gamma-ray log are useful for depth control and correlation with the formation evaluation logs.In this paper we describe a new 1 11/16-in. (42.9-mm) diameter telemetry-based tool - the PLT (TM) (simultaneous production logging tool) - capable of transmitting all these measurements simultaneously during one trip in the well. It is relatively easy to add new sensors to this flexible system. A new dual tracer ejector tool and a high-precision pressure gauge, which have been added to the above family of sensors, also are discussed.This paper presents the results of a 15-well logging program in which the PLT tool was used to evaluate program in which the PLT tool was used to evaluate a miscible flood project in the South Swan Hills pool in Alberta, Canada. While tracer materials were used to monitor the lateral progress of the flood front, production logging was used to monitor the vertical production logging was used to monitor the vertical distribution in both injection and production wells. JPT P. 191

Deep-hole, High-temperature Submersible Pumping

Abstract There were 96 electric submersible pumps operating in the harsh environment of the 230 °F (110 °C) Beaverhill Lake formation of the South Swon Hills Unit at the end of 1977. Here 95% of the pumps are installed in 4-1/2-in. (114-mm) and 5-1/2-in. (140-mm) casing at an average depth of 8,000 ft (2,438 mi. A miscible flood covering half of the Unit contributes to an average producing GOR of 1,100scf/STB (195) and a number of wells produce with GOR's in excess of 2,000 scf/STB (354). These conditions of close tolerances, high temperature and high GOR have resulted in many operational problems. A number of procedures which have been developed to improve pump performance are presented. Introduction The Swan Hills oil field is located 140 miles (225 km) northwest of Edmonton, Alberta (Fig. 1). The Amoco-operated South Swan Hills Unit (Fig. 2) was formed in 1962, with 193 wells on 160-acre (64.8-hectare) spacing. Production is from the 230 °F (110 °C) Swan Hills formation of the Beaverhill Lake group, a limestone reef complex. Waterflooding commenced in 1963, and was expanded from 5 to 22 injection wells by 1972. In 1973, a secondary recovery miscible flood project was initiated in the central portion of the field. This project consists of alternate injection of enriched gas solvent and water (1973-1978), dry gas (1979-1987) and then water (198B-200B). The first electric submersible pump was run in January, 1971. By the end of 1977 there were 96 submersible pump installations. The Unit was producing approximately 60,000 BOPD (9,540 m3/day) and 60,000 BWPD (9,540 m3/day) at this time. Production History Production performance for the miscible flood area, since the first submersible pump was installed in 1971, is detailed in Figure 3. There are 95 producing wells in this area. By the end of 1977, 63 (66%) were submersibly pumped, producing 80% of the oil. Twelve of the producers were flowing, and the remainder were beam pumped. The average GOR's has risen from the solution GOR of about 750 scf/STB (133) to as high as 1,330 scf/STB (229) in 1976. Miscible fluid breakthrough in several wells has resulted in periodic GOR's as high as 10,000 scf/STB (1,772). The combination of small production casing I.D.'s and high GOR's has caused severe submersible pump operating problems. Figure 4 is a production plot for the west waterflood area. There are 52 producers in this area. By the end of 1977, 33 (63%) were submersibly pumped, producing 85% of the oil. The remaining producers were beam pumped. No submersible pumps have been installed in the east waterflood area of the South Swan Hills Unit- This area is located off the main reef build-up and total production averages less than 200 BOPD (32 m3/d). Submersible Pump Equipment Configuration The downhole submersible pumping equipment (Fig. 5) consists of the pump assembly (centrifugal pump, gas separator, motor protector and motor), No. 4 lead sheathed flat cable to the top of the pump, and high-temperature No.6 flat cable to the pothead connection at the motor.

Performance of a Miscible Flood in the Bear Lake Cardium Unit, Pembina Field, Alberta, Canada

Field data and interpretation of project performance are given on a rich gas-drive miscible flood project that has been in progress for more than 5 years. Production has been good, but early solvent breakthrough occurred at two wells. In developing explanations for the breakthrough, computer models were used to analyze field data and the displacement mechanism. Introduction In Feb. 1968, a secondary recovery project was begun in the Pembina Bear Lake Cardium Unit 1 in Alberta, Canada. The major part of the secondary scheme was a rich gas-drive miscible flood conducted in the central region of the unit. The miscible process was used because of its potential for recovering oil unrecoverable by conventional waterflooding. This potential results from displacement efficiencies approaching 100 percent in the region of the reservoir swept by the solvent. Presented here is a general description of the reservoir, followed by a discussion of the miscible project scheme. The performance of the project is reported and analyzed. Information derived from reservoir simulation studies is also presented. The paper is a summary of several engineering studies and progress reports that are on file as public documents with the Energy Resources Conservation public documents with the Energy Resources Conservation Board of Alberta. These documents contain detailed reservoir data not reported in this paper. General Description of the Reservoir Reservoir Location and Layout The Pembina Bear Lake Cardium Unit 1 is located in the northwest portion of the Pembina field in Alberta, Canada, as shown in Fig. 1. The unit boundary and well locations are indicated in Fig. 2. Originally, the wells were developed on 160-acre spacing, but in the last 2 years some infill wells have been added. Currently, there are 29 wells in the unit; three are used as injectors, 25 are producers, and one well has been shut in. producers, and one well has been shut in. Formation Description The Cardium oil reservoir occurs at an average depth of 4,857 ft (-2,054 ft subsea). The oil accumulation is found in a sand bar development about 1 1/2 miles wide and 6 miles long. The Cretaceous sand was deposited under a deltaic condition and then was deeply eroded over most of the unit area. A highly permeable conglomerate-type chert was deposited over the eroded area. Fig. 3 is a cross-section of the reservoir showing the geometry of the sand and conglomerate layers. Maximum thickness of the conglomerate along the major axis of the bar is 41 ft. The underlying sand varies in thickness from 0 to 35 ft. The conglomerate layer is thickest in the northwest, and thins down and disappears in the southeast. It is important to note the vertical scale exaggeration on Fig. 3. The reservoir is actually extremely thin compared with its areal extent. Fig. 4 shows the depth to the top of the pay zone. The crest of the structure follows close to the major axis and dips downward from southeast to northwest. The amount of relief is small compared with the areal extent. Typical or average characteristics for the formation are included in Table 1. In the conglomerate layer, the average horizontal permeability is about 700 md. Permeability in the sand averages only about 20 md. The Permeability in the sand averages only about 20 md. The porosity is about 11 percent in both the conglomerate and porosity is about 11 percent in both the conglomerate and the sand. Permeability data taken from tests on core samples indicate that horizontal permeability of the conglomerate is generally 10 to 20 times greater than the vertical permeability. Geological analysis of core samples indicates that this difference results from the presence of essentially horizontal lithologic zones (beds) of relatively low permeability. In most cases, these zones consist of permeability. In most cases, these zones consist of conglomerate containing abundant sandstone matrix. JPT P. 672

Progress Report of LPG Injection in the Meadow Creek Unit, Lakota B Reservoir

Abstract Results of a field test of oil displacement by liquid propane and butane are presented. Since March, 1956, an LPG miscible flood project has been in operation in the Lakota B reservoir, a small reservoir of nine wells located in the Sussex area, Johnson County, Wyo. The Lakota in this reservoir consists of two zones separated by a shale break of 10 to 12 ft. Injection has been into the upper zone only. The average producing depth is 7,350 ft and as of July, 1958, the average bottom-hole pressure at datum (–2,120 ft) was 589 psig. Data on GOR, injected volumes and individual well performance are discussed. During the 28-month period the flood was in operation, 275,000 bbl of propane and butane were injected into two wells, and 72,000 bbl of oil were recovered over normal decline. The reservoir was shut-in July, 1958, to build up pressure to obtain miscibility between LPG and gas. Introduction LPG injection has been carried out in the Meadow Creek Unit, Lakota B upper zone since March, 1956. From March 29, 1956, to July 15, 1958, 275,000 bbl of LPG were injected into the reservoir to recover approximately 72,000 bbl of secondary oil. The purpose was to initiate a field test of miscible displacement, a process which promises to increase oil recovery beyond that obtainable by conventional methods of water flooding and gas injection. The basic process involves the injection of LPG followed by the injection of a gas. A preferred method of operation maintains the pressure in the reservoir above that required for miscibility between the LPG and gas. Operations at a lower pressure, where the oil and LPG are still miscible but the LPG and gas are not, are also possible; however, recoveries comparable to the completely miscible operation require the injection of larger quantities of LPG and gas. In either case, essentially 100 per cent of the oil in place can be recovered in that portion of the reservoir swept by the LPG, although the high pressure operation more efficiently utilizes the relatively expensive LPG.