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Collaborating Authors
Improve Heavy Oil Recovery by Separated-Zones Horizontal Well Steam Stimulation
Zhong, Liguo (Northeast Petroleum University) | Zhang, Shoujun (Liaohe Oilfield) | Wu, Fei (Liaohe Oilfield) | Lang, Baoshan (Liaohe Oilfield) | Liu, Heng (Liaohe Oilfield) | Liu, Tao (Daqing Oilfield) | Liu, ShuXia (Daqing Oilfield) | Gao, Wenlong (Greatwall Drilling)
Abstract Horizontal well steam injection is effective to recover heavy oil for its large reservoir contact. To date, more than 150 horizontal wells have been drilled in Shuguang oil region, most of them are operated in steam stimulation and SAGD processes, and completed with slotted liner at length from 100 m to 500 m. But it is much challenging to recover oil from reservoir along horizontal well proportionally because of steam characteristics, large well length and reservoir heterogeneity. Results of simulation and field temperature testing show that only about half of reservoir along horizontal wellbore is recovered well, and average OSR (defined as ratio of oil production to steam injection) is less than 0.28, and it is not satisfying for the large cost of horizontal well drilling and completion. Furthermore, steam crossflow between wells and pressure depletion in local reservoir well steamed could also result in reduction in oil production and OSR. To improve horizontal well steam injection, separated-zones horizontal well steam stimulation technology is developed, in which temperature sensitive packers, outlets, pressure sensitive valves and ball sealers are involved. The steam injection of different zones separated by packer(s) could be regulated or controlled according to engineering design. There are four techniques developed including dual-zones steam injection in sequence or at one time, selected zone steam injection, and simultaneous multizones steam injection. In order to investigate temperature and steam injection of different reservoir zones along horizontal well in different steam stimulation process, experiment, numerical simulation and field testing are carried out in past three years. In this work, laboratory experiments are carried out with large simulation apparatus packed with sampled oil sand and equipped with temperature sensors and pressure sensors at first. Secondly, structure of steam injection pipes and steam injection scheme are optimized based on numerical simulation, and primarily reservoir selection requirements are also provided. Thirdly, result of application of separated-zones steam injection to 76 wells and monitoring of temperature and pressure is presented, and considerable improvement of steam injection and heavy oil recovery obtained. At last, the future of intelligent separated-zones horizontal well steam injection is prospected.
- Asia > China (0.69)
- North America (0.68)
- Asia > China > Liaoning > Bohai Basin > Liaohe Basin > Liaohe Field (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
- North America > United States > Louisiana > China Field (0.97)
Introduction During the past 15 years, steam-injection processes have become an importantmeans of exploiting heavy oil reserves. Traditionally, these processes havebeen classified as either steam soaks or steam drives. With combinations, suchas presoaking drive wells and partially driving steam soaks, the distinction isnot always applocable. Furthermore, our experience auggests that oil/steamratios from most mature processes converge to a calue determined only byreservoir and steam properties and time. To date, the steam-soak process has proven the more attractive, partlybecause the immediate response allows an early evaluation of a reservoir andpartly because oil rates from initial soak cycles tend to be better than latercycles. Successful steam soaks are limited to reservoirs where natural recoverymechanisms (gravity drainage, pressure depeletion, and solition gas drive)areineffective because of the low oil mobilities. Successful steam drives requiregood conformance, a means ofstarting the process because high oil saturations can limit injectivityseverely and prevent effective initial reservoir heating, and sustainedhigh injectivity throughout the process life. Unlike steam soaks, steam drivesdo not respond until built-up oil banks and heat reach the production wells. Because peak production rates may not be observed for several years after thestart of injection, piloting is expensive and expansion to full scale issoemwhat hazardous. For those reasons, screening methods that predict ultimateoil/steam ratio are useful in planning new projects or in modifying existingones. In the past, steam injection has been applied to a wide spectrum ofreservoir conditions, many of which have proven unsuitable. In retrospect, wecan explain the varied response withh a simple mathematical model thatincorporates reservoir and steam properties in the prediction. This paperdescribes the model and compares prediction from it with laboratory and fieldresults.
- North America > United States > California (1.00)
- Europe (0.93)
- South America > Venezuela > Zulia > Maracaibo Basin > Tia Juana Field (0.99)
- North America > United States > California > San Joaquin Basin > Midway-Sunset Field > Webster Formation (0.99)
- North America > United States > California > San Joaquin Basin > Midway-Sunset Field > Monterey Formation (0.99)
- (7 more...)
Members SPE-AIME Abstract Gravity segregation (steam override) and poor areal and vertical sweep efficiencies have limited recoveries in many heavy oil reservoirs since the first thermal projects were initiated in the 1960's. In many instances the injected steam prematurely breaks through into producing wells creating steam channels. In-situ steam foams have proven effective at reducing the mobility in these steam channels and diverting the injected steam into alternate flow paths, thus improving the sweep efficiency of the steam drive process. This paper describes the efforts associated with the performance under two Department of Energy (DOE) cost-sharing contracts to reduce steam channeling in a conventional steam drive using in-situ steam foam additives. Three steam injection patterns, each being treated with a different steam foam additive, will be presented. In each of the cases, the steam foam presented. In each of the cases, the steam foam additive altered the sweep efficiency and incremental oil production was noted. The cost to produce an production was noted. The cost to produce an incremental bbl of oil varied from $1.50 to $48.81. Introduction Two of the steam injection patterns (Witmer B2-3 and Witmer B2-5) are located in the northern end of the Kern Front Field and one steam injection pattern (McManus 208) is located in the southern end of the Kern River Field, situated in the San Joaquin Valley in Central California (Figure 1). Both properties are owned and operated by Petro Lewis Corporation (PLC) of Denver, Colorado. Witmer B2-3 and Witmer B2-5, were two of four steam injection patterns receiving commercially available steam foam additives under a completed three year cost-sharing contract issued by the DOE to PLC with Chemical Oil Recovery Company (CORCO) of Bakersfield, California, as the administrator. McManus 208 is a steam injection. pattern receiving an experimental steam foam additive under an ongoing cost-sharing contract issued by DOE to Stanford University Petroleum Research Institute (SUPRI) with CORCO as the field administrator. In each contract, observation wells were drilled, cored, logged, and periodic cased hole logs were run. Chemical tracer surveys, radioactive tracer surveys, and special pressure fall-off tests were conducted along with collection of temperature and production data. For purposes of this paper, a comparison of only the production performance and radioactive injection profiles will be discussed. STEAM FOAM APPLICATION Witmer B2-3 The first steam injection pattern being evaluated is Witmer B2-3, which is an inverted 9-spot, 10 acre pattern located in the Kern Front Field (Figure 2) with a depth of 1,565 ft. Witmer B2-3 was the first well in the Witmer leases to be converted from a producing well to an injection well in January 1978. Steam foam slug treatments of COR-180 began in March 1980 and continued through September 1982. Initially, the well was treated with 110 gal of 40% active COR-180 once per week. The aqueous COR-180 was injected into the steam at the Witmer B2-3 wellhead at 3.0 โ 3.5 gal/min with a positive displacement pump. On September 2, 1980, the slug size was reduced to 55 gal, with the frequency of treatment remaining unchanged. By injecting the COR-180 steam foam as an aqueous solution into the steam, the steam acts as a carrying agent to place the steam foam in the steam channel. As the aqueous steam foam is moving through the steam channel with the steam, the formation provides a mechanical shearing effect, thus allowing the provides a mechanical shearing effect, thus allowing the steam foam to activate in-situ utilizing the vapor phase of the steam present. Once the foam is phase of the steam present. Once the foam is generated, it plugs a number of the individual pore throats in the steam channel, thus reducing the mobility of the steam in this "previous steam channel." The foam continues to reduce the mobility of the steam until the foam is forced to collapse through mechanical or thermal degradation or by the steam vapor condensing. P. 367
- Europe > United Kingdom > Irish Sea > East Irish Sea > Liverpool Bay (0.25)
- North America > United States > Colorado > Denver County > Denver (0.24)
- North America > United States > California > Kern County > Bakersfield (0.24)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.54)
- Geology > Geological Subdiscipline (0.54)
- North America > United States > California > San Joaquin Basin > Kern River Field (0.99)
- North America > United States > California > Kern Front Field (0.99)
- North America > Canada > Alberta > Doe Field > Altia 102 Doe 10-26-81-13 Well (0.99)
ABSTRACT Because of the favorable properties of CO2, it has been used to enhance the recovery of oil for a long time. But this technology is under slow development in China for lack of rich CO2 resource until some CO2 reservoirs were found in recent years. Using simulation and reservoir-engineering method, this paper presents the feasibility study of CO2 injection for heavy oil reservoirs following cyclic steam stimulation. Pilot tests were conducted to several wells in Lengjiabao heavy oil reservoirs in Liaohe oilfield, China. Some wells got good effect, while some wells got poor effect. And the results from the simulation and field pilot tests are evaluated economically. Study shows that for common heavy oil reservoir after cyclic steam stimulation, the higher the oil viscosity, the greater the CO2 utilization ratio, and the more feasible CO2 stimulation process; for extra-super heavy oil, 1โ3 cycles steam huff-n-puff were performed as necessary, followed by CO2 stimulation process so that good benefit could be gained. These results are of significance for field operation and production of heavy oil. Introduction In recent years, many heavy oil reservoirs or blocks in China have entered their late stage of cyclic steam stimulation. With the increasing of steam huff-n-puff cycles, the cost is getting higher and the profit is getting poorer, hence, the development effects are getting worse. The technology of steam huff-n-puff can not meet the needs of heavy oil production. While, there is no mature technology to substitute it. It is necessary to seek new methods to exploit heavy oil reservoirs for which steam stimulateon is not suitable. It has been known for many years that as CO2 dissolves in oil, it swells the oil and reduces oi viscosity. In 1945 Poettmann and Katz discussed phase behavior of CO2 and paraffin systems[1]. They estimate that for a heavy crude there is 10 to 22 percent augmentation in oil volume, and the crude viscosity reduces to less than 0.1 of its original value at 120F(49?) and 800 to 1200 psi (55 to 83 bars) [2]. At lower temperature, the augmentation in volume is greater. In China, CO2 injection technology has been applied to oil production only recently, the major reason being lack of rich CO2 resource. In recent years, some medium and small CO2 reservoirs have been found in Jiangsu oilfield, Shengli oilfield and Jilin oil field, etc. Meanwhile, most of oilfields in east China are entering the late-life production and requiring appropriate EOR technologies. Hence, CO2 injection is becoming more attractive in China. CO2 injection technology has been studied in China since the late 1980's, and pilot tests were conducted in the eastern Sanan of Daqing oilfield, Jiangsu oilfield and Xinli 288 area of Jilin oilfield[3โ5] and satisfactory results were obtained. Unfortunately, there has been little study of injection CO2 for heavy oil reservoir in China so far, especially for reservoirs at their late stage of cyclic steam stimulation. For heavy oil, the major EOR mechanisms of CO2 injection are viscosity reduction and volume swelling. Three blocks of Lengjiaobao heavy oil reservoir are selected for our study: block Leng 41, block Leng 42, and block Leng 43. The range of crude oil viscosities of these three blocks varies widely (from 327mPa.s to72700 mPa.s), and several cyclic steam stimulation have been conducted in these three blocks. Several problems exist in the production of these blocks: (1) Back production of injected water is low, which is harmful to improving the effect of steam huff-n-puff at late stage; (2) Wells completed with non-thermal technology can not produce normally using steam injection for more than a few cycles; (3) Oil production is affected by invasion of edge and bottom water in the western edge of blocks; (4)Some wells produce sand.
- Asia > China > Liaoning Province (0.70)
- Asia > China > Jilin Province (0.54)
- Europe > United Kingdom > North Sea > Central North Sea (0.25)
- Asia > China > Heilongjiang Province > Daqing (0.24)
- Asia > China > Shandong > North China Basin > Shengli Field (0.99)
- Asia > China > Liaoning > Bohai Basin > Liaohe Basin > Liaohe Field (0.99)
- Asia > China > Jilin > Yanji Basin > Jilin Field (0.99)
- (3 more...)
Introduction When two fluids of differing densities, such as liquid water and steam vapor, flow through circular conduits, they tend to segregate. Investigators of two-phase flow in steam injection wells have documented the occurrence of two-phase annular flow in the injection tubing when steam quality is moderate to high. Most of the liquid flows as an annular film adjacent to the tubing wall; the center of the injection tubing is filled with vapor and a small amount of entrained liquid. Upon reaching the injection interval, the segregated liquid and vapor will not be evenly distributed to the formation. Elson observed nearly complete segregation of air and liquid water in a perforated acrylic column used to simulate wet steam injection. Irrespective of the tubing size and location employed, vapor preferentially entered the uppermost perforations. Kasraie and Farouq Ali used a numerical model of wellbore heat transfer to investigate the effect of multiple off take points on steam quality. They concluded that quality declined in lower segments of the tubing due to steam off take. Kumar and Hong studied the effect of vapor and liquid segregation on steamflood performance. They found that the assumption of uniform quality steam injection across the injection interval led to optimistic oil recoveries. Nguyen and Steven employed radioactive inert gas tracers to profile the vapor phase during steam injection. In a field test, all of the vapor exited through the upper two of five sets of perforations; standing liquid prevented vapor from entering the lower three sets of perforations. They concluded that a large amount of phase segregation occurs in steam injection wells. Conventional thermal simulations ignore the segregation of liquid and vapor. Variations in quality across the injection interval result solely from the effect of pressure on the liquid-vapor ratio and are, in consequence, small. This does, however, simplify the modeling. In this paper, segregation of liquid water and steam vapor in the injection interval is incorporated into the modeling of stimulation of a prototypical heavy oil reservoir. A novel technique, location of two wells at the same point with the steam injection well completed above the hot water well, is used to include steam segregation. The distribution of steam in the reservoir and the effect on production following uniform and segregated injection are compared. Description of Reservoir And Fluid Properties A prototypical heavy oil reservoir 15.2 m (50 ft) thick was used for the study. The reservoir was divided into 9 vertical layers and 15 logarithmically-spaced radial blocks. The wellbore radius was 0.125 m (hole diameter of 9โ7/8 inches). The mid-point of the first grid block was at a distance of 1.22 m (4 ft) from the wellbore centerline and the outer boundary of the 15th grid block was 1000 m from the wellbore centerline. The top of the reservoir was 622 m (2040 ft) subsurface and the reservoir was horizontal. A schematic of the reservoir grid system is shown in Figure 1.