SPE Member Abstract Case histories described in this paper demonstrate the technical and economic value of using a specific work process coupled with advances in gel technology to improve vertical and areal injection fluid distribution at the Wertz Field carbon dioxide (CO2) Tertiary Flood in Bairoil, Wyoming. The Wertzcase histories incorporate results from ten injection well gel conformance workover repairs with fluid performance response at offset producing wells. Post appraisal findings confirmed individual pattern life for tertiary processing was extended by nearly two years resulting in incremental oil recoveries of up to 140,000 barrels per pattern. Introduction The Wertz Tensleep waterflood was developed during 1980 and tertiary recovery was implemented during 1986. Until patented advances in gel technology developed by Marathon Oil Company were released for oil and gas industry use during 1991, typical workovers for controlling vertical and area injection fluid distribution (conformance) were limited to near-wellbore techniques. Most commonly used were low cost sandback operations at $4,000 per treatment and higher cost cement work at $35,000 per repair. Injection profiles often confirmed both methods achieved success for lower zone near-wellbore injection control. However, even the best designed sand and cement work were occasionally rendered ineffective because of behind-pipe channeling between perforation intervals. In addition, neither sand nor cement techniques offered an effective way to repair middle and upper zone injection conformance. Hence the need for an advanced method of injection conformance control. Liquid alpha olefin sulfonate surfactant foam work offered the first step to advancing Wertz injection conformance. These repairs averaged $35,000 per treatment and proved to be a technically viable alternative for temporarily controlling lower, middle, and upper zone injection conformance. Once the surfactant was in place, an in-situ foam was generated for injection fluid diversion. However, only short term and nonpermanent injection conformance control was realized. Foam diversion longevity was reduced considerably when natural fractures were present. By definition, the Wertz Tensleep sandstone is an eolian deposit with a gross thickness of about 470 feet. It has nearly 240 feet of net pay that has an average 10 percent porosity, 13 millidarcy permeability, and some natural fractures. The latter condition makes injection conformance control using foam very difficult, and produces a need for a different workover method. A specific work process and acrylamide-polymer/chromium(III)-carboxylate gel technology offered the next step for improved Wertz injection conformance control. WORK PROCESS ANALYSIS The macro work process analysis map shown in Figure 1 offers one basic engineering approach to identifying candidates for workover repair, which assists with continually improving Wertz Tensleep injection well conformance. For publication, the structure of this map has been intentionally limited in detail and does not show virtually hundreds of minor work process sub-steps contained within each major step. The map also deliberately shows preference for injection over producing well conformance repairs. While some producing well conformance work is necessary, actual experience shows injection well repairs result in the largest incremental reserve impact for extending the economic life of the Wertz Tensleep tertiary operation. P. 469^
Summary A multiphase flowmeter (MPFM) installed in offshore Egypt has accurately measured three-phase flow in extremely gassy flow conditions. The meter is completely nonintrusive, with no moving parts, requires no flow mixing before measurement, and has no bypass loop to remove gas before multiphase measurement. Flow regimes observed during the field test of this meter ranged from severe slugging to annular flow caused by the dynamics of gas-lift gas in the production stream. Average gas-volume fraction ranged from 93 to 98% during tests conducted on seven wells. The meter was installed in the Gulf of Suez on a well protector platform in the Gulf of Suez Petroleum Co. (Gupco) October field, and was placed in series with a test separator located on a nearby production platform. Wells were individually tested with flow conditions ranging from 1,300 to 4,700 B/D fluid, 2.4 to 3.9 MMscf/D of gas), and water cuts from 1 to 52%. The meter is capable of measuring water cuts up to 100%. Production was routed through both the MPFM and the test separator simultaneously as wells flowed with the assistance of gas-lift gas. The MPFM measured gas and liquid rates to within "10% of test-separator reference measurement flow rates, and accomplished this at gas-volume fractions from 93 to 96%. At higher gas-volume fractions up to 98%, accuracy deteriorated but the meter continued to provide repeatable results. Introduction The October field is located in the northern Gulf of Suez of Egypt and was discovered by Gupco in late 1979 with the drilling of the GS195-1 well (Fig. 1). The Nubia sandstone was found to contain a 27°API, undersaturated oil with an initial solution gas/oil ratio (GOR) of about 300 scf/bbl. By 1986, reservoir pressure had declined to the point that gas lift was installed to maintain production. The Nubia reservoir has a waterdrive recovery mechanism, and by 1986, water cuts had also begun to increase. Today, October production is characterized by three-phase flow. However because of the presence of gas-lift gas in the flowstream, gas-volume fractions at the surface are approximately 95% of pipeline volume, with the remaining 5% occupied by oil and water. In recent years, October drilling development has out-paced infrastructure development (flowlines and gas-lift compression). This has caused testlines to be used full-time for transporting production. The number and quality of well tests for a typical October well have declined because of the production-deferral effect of flowing one well through the testline while routing all other wells through the production line. In addition, the test separator at the production platform is used full-time for routine separation of production to minimize backpressure on all of the other platform risers. When a well is switched into the test separator, forcing the remaining field production to be separated in the three production separators, riser pressure at other platforms can increase by an average of 15 psi. Because of the pressure on the company to maximize production on a daily basis, wells at October field are only tested once every 3 to 6 months. A typical test lasts only 4 to 6 hours and rarely involves producing only one well through the testline. Again, because of the issue of deferred production, two or more wells (including the well to be tested) are initially placed in the testline to the test separator and their collective rate is established. The following day, the well of interest is shut in and the remaining wells are tested. The decrease in total tested rate is assumed to be from the well that was shut in. This method of testing obviously has several disadvantages and potential errors in assumptions. Multiphase metering in the October field provides a means of acquiring the frequency and quality of well tests that are needed to manage the Nubia reservoir without deferring production. Other advantages include minimal maintenance, savings on test pipelines, rapid identification of well problems, and improved gas-lift-gas allocation. Meter Description The MPFM chosen for installation at the October field was the Fluenta 1900VI. The meter was designed to measure oil, water, and gas phases of a multiphase flow without separation of the well stream. The instruments are completely nonintrusive, with no moving parts, requiring no gas bypass line, having no mixing device, and providing real-time output in standard conditions. The meter measures the phase fractions and velocities, and then determines the flow rates of oil, water, and gas. The MPFM consists of the following sensors: a capacitance sensor unit, an inductive sensor unit, a gamma-densitometer, a venturi meter, and pressure and temperature transmitters. The sensors are mounted on a portable skid, as shown in Fig. 2. An explosion-proof (Ex-d) capsule mounted on the skid contains all the necessary electronics and computer cards to receive and process the signals from the different sensors. These electronics and computer cards are called the system computer. The processor card inside the Ex-d capsule is equipped with two communication ports. One of the ports is dedicated to the remote terminal unit (RTU) for transmitting all measurements (such as flow rates, pressure, and temperature) by radio to the October production-complex computer. The other port is used to connect a laptop computer to the meter for servicing and onsite monitoring of readings. The recorded data will be stored in the system computer even if no laptop computer or RTU is connected. The meter skid weighs approximately 3,300 lbm, and was lifted onto the October H platform using a workboat crane. Space requirements for the meter are minimal, as the meter is about 6 ft wide by 4 ft deep by 8 ft high. The meter is powered by automotive batteries, which are recharged by four solar panels. Measurement Principle The MPFM measures the fractions and velocities of the different phases using a capacitance sensor, an inductive sensor, a gamma-densitometer, a venturi meter, and pressure and temperature transmitters.
The Lost Soldier Tensleep field tertiary performance has a noteworthy case history that demonstrates how an incremental 13% of original oil in place will be recovered from this sandstone reservoir using carbon dioxide. Located in south central Wyoming, the Lost Soldier Tensleep has been under carbon dioxide (CO2) injection since 1989. From 1989 through 1995, a 61% hydrocarbon pore volume (HCPV) slug of CO2 was injected into the reservoir to recover an incremental 13.6 million barrels of tertiary oil. Prior to CO2 injection, the reservoir was producing 2,500 bopd at a 97% watercut. Within one year, oil production exceeded 10,000 bopd and is currently 6,000 bopd. Since its start-up in 1989 with 47 producers and 40 injectors the subject flood has used a water-alternating-gas (WAG) method and line drive pattern to process approximately 840 acres of reservoir. Illustrations of actual WAG injection cycles and resultant offset production response are included in this case history. The Lost Soldier flood has been so successful that one producing well had an incremental rate of 1700 bopd, carrying the unique distinction of having the highest peak incremental CO2 response that the authors could find documented in U.S. literature. Information contained in this paper provides observations and conclusions about field performance optimization as well as reservoir management philosophy. Several actions were completed during the early to mid-1990's to maximize recovery and profitability. These included maintaining miscible reservoir pressure, increasing natural gas liquid recovery, converting to sour reinjection, and exploiting downdip oil potential. Introduction The Lost Soldier Tensleep field is located in the Great Divide Basin of Wyoming approximately 40 miles northwest of the city of Rawlins (Figure 1). Lost Soldier is the larger of two fields located near the town of Bairoil, Wyoming, the other being Wertz field. Combined Lost Soldier and Wertz field production is 10,000 bopd and 1,500 bbl/day of natural gas liquids. The majority of current production comes from the Pennsylvanian age Tensleep and the Mississippian age Madison carbonate. The original oil in place (OOIP) in all horizons in both fields approaches 1 billion barrels. Currently, besides the Lost Soldier Tensleep, CO2 is being injected into the Wertz Tensleep1 and the Lost Soldier Darwin/Madison reservoirs. CO2 for the Bairoil fields is supplied from Exxon's LaBarge project2. The CO2 is transported via pipeline 120 miles from its Shute Creek plant in southwest Wyoming to a point 19 miles northwest of Bairoil, where it is transferred to an operator-owned spur line for final delivery. Field History and Development The Lost Soldier Field was discovered in 1916 when Bair Oil Company drilled a well 265 feet into the first Frontier formation. The well produced 200 bopd. The Dakota, Lakota, Morrison, and the Sundance sands were discovered prior to 19263. In 1930, the Tensleep was discovered, and the initial well flowed 2,435 bopd. In 1947, the Darwin sandstone and Madison carbonate were discovered and produced at a combined rate of 1,045 bopd. In 1948, the Flathead sandstone was discovered immediately above the granitic basement. Amoco purchased the properties in 1975. Development was slow for the Lost Soldier Tensleep until 1942. During the early 1940's, 16 wells were completed, producing between 2,500 and 8,000 bopd. Since its discovery, the Tensleep has been the most prolific of the nine productive horizons in the Lost Soldier Field. Primary production is attributed to a combination of fluid expansion, water influx, and gravity drainage. Peripheral water injection began in 1962, and pattern waterflood was initiated in 1976. The pattern development in the late 1970's resulted in a 16 acre north to south line drive pattern still used today. Cumulative production from the Lost Soldier Tensleep through 1995 is 120 million barrels of oil (50% of OOIP).
Through-tubing bridge plug (TTBP) water shut-off (WSO) workovers in the October Field have resulted in an average incremental initial production increase of 2500 bopd per job. Average water cut (WC) was reduced from 55% to 16%. Seventy-eight WSO workovers have been completed since December 1991. Technical and economic success approach 90%. Just under $4.8 million dollars has been spent for an average cost of $61,500 per job. Costs paid out in less than two days using a normalized $13 per barrel crude price. Based on results achieved during the past 4.5 years, these WSO workovers establish the October Field as a notable and on-going case history for lower zone water control. Water production from the October Field has gradually increased during the past decade. As a result, steeper production declines and gas lift operational problems developed. Based on reservoir characteristics, lower zone water was isolated using TTBP's conveyed by way of portable mast electric line units. A dump bailer was used to place a 14 foot cement cap over the TTBP to provide a permanent pressure seal. After a 24-hour shut in cement cure period, wells were almost always returned to production at a significantly higher oil rate and dramatically reduced WC. The cost of a rigless TTBP WSO workover is much less than conventional rig deployed WSO work which averaged over $500,000 per job. Prior to December 1991, rig WSO's were the only method used in the October Field. Hence, rigless WSO workovers have become vital for cost control. Rigless WSO work has also become a useful reservoir management tool for maximizing oil production and minimizing water production thereby conserving reservoir energy and optimizing lift gas. Introduction The October Field is located offshore in the Gulf of Suez (GOS) approximately 200 miles southeast of Cairo and 70 miles north of the operating base in Ras Shukheir, Egypt (Figure 1). The October Field area is the largest of seven major producing areas in the GOS operated by the Gulf of Suez Petroleum Company (GUPCO); a joint venture between Amoco Egypt Oil Company and the Egyptian General Petroleum Corporation. Combined GUPCO GOS production averaged 365,000 bopd during early 1996. Gas lift is the most widely used form of artificial lift. Original oil in place (OOIP) for all fields approached 10 billion barrels by 1996.
This paper is the first in a series describing results and lessons learned from longer run life across 13,176 Electric Submersible Pump (ESP) systems in TNK-BP. ESP artificial lift is the dominant method for producing approximately 90% of TNK-BP's oil volume, which averages more than 200,000 tons (1.5 million barrels) per day. A sustainable economic benefit for TNK-BP was defined during 2006, and this benefit directly results from increased ESP run life. The 5-year value was estimated at $350 million and long-term forecast was $1 billion. An indirect benefit from longer run life was better HSE performance due to reduced exposure to oil field hazards from fewer rig days pulling ESPs. Since 2006, TNK-BP has gradually changed the way it thinks about ESP run life and lessons learned are provided in this paper as a case history. ESP run life was about 300 days MTBF when the project started and the 5-year goal was set at 600 days MTBF by year end 2011. Elements for success included leadership structure, coordinated teamwork across multiple internal business segments and continuous equipment improvement using root cause failure analysis. Reducing frequent failures was a basic priority as was technical equipment innovation and pilot project expansions. Results have been impressive with run life steadily increasing each month. Run life improved to 410 days MTBF during August 2008 from 296 days in January 2006. This 114 day run life increase has already prevented 550,000 tons (4 million barrels) of deferred oil, reduced $50 million of operating costs and saved rig time. The $350 million project value did not include redeployment of rigs to complete other oil enhancing work such as hydraulic fracturing and acid stimulations. During 2004, TNK-BP joined the ESP-RIFTS Joint Industry Project. The ESP-RIFTS System allowed TNK-BP to further develop and implement a unified way to classify and analyze ESP data for a huge well stock. The result was strategic operating changes, one of which was stopping the purchase of the lowest reliability equipment. Failure analysis was fundamental in helping TNK-BP with its initiative to get the right equipment into the right well. Introduction TNK-BP is a Russian oil company that is a privately owned joint venture (1). The Company was formed in 2003 and for the past five years its upstream oil and gas producing operations have been located primarily in West Siberia (Khanty-Mansiysk and Yamalo-Nenets Autonomous Districts, Tyumen Region), East Siberia (Irkutsk Region), and Volga-Urals (Orenburg Region) (Figure 1). TNK-BP operates approximately 250 hydrocarbon bearing fields that have about 15,000 active oil producing wells and 10,000 water injection wells. Approximately 90% (or 13,176 wells) have ESP systems, which include both surface and downhole equipment components (Figure 2).Surface equipment usually included transformers, switchboard or variable speed motor controller and surface power cable.Major downhole equipment components included a pump, intake or gas separator, seal element, motor and a long cable to transfer power from the surface to the motor. These ESP systems are distributed throughout TNKBP's 14 regional business locations.
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