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Abstract In oil producing regions like the US Mid-Continent, there are a large number of mature conventional oil fields that have reached or are approaching their production limit by conventional techniques, however, current strong oil prices and security issues justify additional EOR/IOR efforts. Air injection-based techniques (fireflooding or in situ combustion) have been demonstrated to provide commercially successful recovery from medium and light oils reservoirs. While the history of air injection-based EOR is littered with the perception of failed projects, many of the failures were associated with low oil prices. In other cases, failures were due to compressor problems, or incorrect concepts of how air injection processes operate. Ineffective ignitions, failure to inject enough air, and applications in reservoirs that had no hope of success explain the trouble with many past projects. This paper reviews some of the successful air injection projects in higher gravity oil reservoirs and discusses the elements that are critical for success. These include the ability to ignite and continuously burn a fraction of the oil at reservoir conditions, the suitability of the reservoir for a gas-injection based recovery process, the availability and suitability of preexisting infrastructure, and a reasonable prediction of how much air should be injected and how much oil recovery could be expected. The paper also discusses possible options for taking advantage of the product gas stream. The purpose of this paper is to arm the petroleum engineer with the relevant information and the right set of questions to ask when considering the application of air injection in a given field.
- North America > United States (1.00)
- Asia (0.93)
- North America > Canada > Alberta (0.68)
- Europe (0.68)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.81)
- North America > United States > South Dakota > Williston Basin > Buffalo Field > Red River Formation (0.99)
- North America > United States > Nebraska > Sloss Field (0.99)
- North America > United States > Montana > Williston Basin (0.99)
- (2 more...)
Abstract Recovery of 400-cp oil from a 4,500-ft deep reservoir by forward combustion was successfully demonstrated. Of the 226,000 bbl produced during the project, at least 132,000 bbl represent additional recovery over primary. Vertical conformance was estimated at 75 per cent. Sixty percent of the oil was produced after completion of air injection. Reservoir and performance data are given. Introduction This in situ combustion pilot test was undertaken to investigate the possibility of recovering heavy (9 to 12 deg. API) oil from deep (4,500 ft) reservoirs. Mene Grande Oil Co. holds or operates concessions in Eastern Venezuela with considerable reserves of these heavy crudes. Primary recovery from these very flat reservoirs is generally low (2 to 7 per cent), and viscosities range upward from 400 cp. Conventional water and gas injection have in most cases been economically impractical. Only combustion holds hope of sweeping a sufficient fraction of these reservoirs to make secondary recovery projects feasible. As a modest initial venture, but to yield maximum information in the shortest possible time. an isolated two-spot pattern with 100-meter spacing was selected. Test Site Description The sand selected for this project is highly unconsolidated, with a porosity of 35 per cent and permeabilities ranging from 2 to 5 darcies. Initial oil saturation was estimated to be 94 per cent, with connate water occupying the remaining 6 per cent. The initial reservoir pressure was 1,600 psi, but had dropped to about 1,360 psi by the time air injection commenced. Although many wells had penetrated this sand, virtually all are completed in other reservoirs. However, one existing well was found which could serve as an injectors Some 23 ft of net oil sand was present in two tenses, an upper of 10 ft and a lower of 13 ft. Although a 2-ft shale section separated the lenses, the entire interval was perforated. Prior to inception of the air-injection project, the injection well had produced 89,000 bbl of 9.5 deg. API crude. Its initial rate was 225 BOPD, and a decline- curve analysis yields an estimated cumulative recovery of 183,000 bbl of oil. Following selection of the location and spacing for the proposed two-spot, a second well was drilled 100 m northeast of the injector. It encountered only a disappointing 10-ft sand. considered inadequate for a good producing well. Another well was then drilled 100 m to the southwest. A single 15-ft sand was found, and the well was cased and completed. An isopach map of the sand had previously been prepared from logs of all wells penetrating the section. Spacing is 600-m hexagonal. Most nearby wells are completed in other sands. In view of the rapid changes in thickness found over 100-m distances, this map was rendered meaningless. Thus the effective size of the reservoir could be obtained only from a material balance. An effective volume of 3.56 million bbl of oil in place was computed. The producing mechanism was pure fluid expansion. Equipment and Completions The producing well was equipped with 9 5/8-in. casing, gravel packed, and completed with a 5 1/2 -in. OD slotted liner (see Fig. 2). Two parallel tubing strings were run-a 3 1/2-in. OD production string with a pump holddown nipple, and a 2 7/8-in. OD observation string which swaged to 2 3/8-in. OD to enter the liner. This latter string was plugged on bottom, and a thermocouple line was run inside of it. Three thermocouple junctions were spaced at 5-ft intervals oppositive the perforations. JPT P. 994ˆ
- South America > Venezuela (0.35)
- North America > United States (0.29)
Abstract High-Pressure Air Injection (HPAI) is an EOR process in which compressed air is injected into a deep, light-oil reservoir, with the expectation that the oxygen in the injected air will react with a fraction of the reservoir oil at an elevated temperature to produce carbon dioxide. Over the years, HPAI has been considered as a simple fluegas flood, giving little credit to the thermal drive as a production mechanism. The truth is that, although early production during a HPAI process is mainly due to repressurization and gasflood effects, once a pore volume of air has been injected the combustion front becomes the main driving mechanism. This paper presents laboratory and field evidence of the presence of a thermal front during HPAI operations, and its beneficial impact on oil production. Production and injection data from the Buffalo Field, which comprises the oldest HPAI projects currently in operation, were gathered and analyzed for this purpose. These HPAI projects are definitely not behaving as simple immiscible gasfloods. This study shows that a HPAI project has the potential to yield higher recoveries than a simple immiscible gasflood. Furthermore, it gives recommendations on how to operate the process to take advantage of its full capabilities. Introduction High-Pressure Air Injection (HPAI) is an emerging technology for the enhanced oil recovery of light oils that has proven to be a valuable process especially in deep, thin, low permeability reservoirs . A number of successful high-pressure air injection projects in light oil reservoirs have been documented in the literature 8–10. Most of these projects have been operating for many years, attesting to their technical and economic success. The improvement in recovery of light oil by HPAI involves a combination of complex processes, each contributing to the overall recovery. These processes include: flue gas sweeping, field re-pressurization, oil swelling, viscosity reduction, stripping of the lighter components of the oil, and thermal effects. Early production during the HPAI process is related to re-pressurization and gasflood effects; hence, the influence of the thermal zone is secondary during the early life of an injector. The oil displaced directly by the combustion front will depend on the effectiveness of the generated flue gas on oil displacement from outside the thermal region. For many years, there has been some discussion regarding the effective driving mechanisms associated with the HPAI process; some authors have assumed it is essentially attributable to the in-situ generated flue gas displacement and consequently the process is analogous to a flue-gas injection, while others recognize the thermal nature of the process. Clara et al, explained the air injection technique applied to light-oil reservoirs, and proposed a laboratory strategy for evaluation of an air injection project. It was stated that regardless of the oxidation zones, the air injection process in a light oil reservoir is comparable to a flue-gas injection process. Hunedi et al., presented results of an exhaustive EOR screening based on successful field trials and physics of the oil recovery mechanisms for each method; with the possibility to be applied in eight oil fields (30.2 to 41.3 ° API) in the Euphrates Graben.
- North America > United States > California (0.68)
- North America > United States > Texas (0.49)
- North America > United States > Texas > East Texas Salt Basin > Buffalo Field (0.99)
- North America > United States > South Dakota > Williston Basin (0.99)
- North America > United States > North Dakota > Williston Basin (0.99)
- (3 more...)
Abstract High Pressure Air Injection (HPAI) is a potentially attractive enhanced recovery method for deep, high-pressure light oil reservoirs. The clear advantage of air over other injectants, like hydrocarbon gas, carbon dioxide, nitrogen, or flue gas is its availability at any location. Although, the process has successfully been applied in the Williston Basin for more than two decades, the potential risks associated with the presence of oxygen in air are a significant hurdle for implementation in other locations. Thermal simulations that include combustion are required to quantify the incremental oil, the oxygen consumption and resulting oxygen distribution from the application of HPAI in a given field. Once such a simulation model is available, it can be used to optimize the injection strategy: strategies that have a good incremental recovery while reducing the amount of gas injected are key to a successful project. The injection rate is bounded by a technical lower limit and an economic upper limit: there is a minimum rate required to maintain the combustion and higher rates require larger compressors that are more expensive. This paper focuses on the optimization of the injection strategy for HPAI in a 3D model with realistic geological features. Numerical simulations with a thermal model that includes combustion were conducted for continuous versus alternating air injection. A critical assumption for alternating air injection is that the remaining oil spontaneously re-ignites. This study shows that water alternating air injection has a great potential to improve HPAI projects: project life can be extended and incremental recovery is improved when compared with continuous air injection. In addition, the variation in distribution of oxygen between different cycles is presented. This also illustrates that the numerical model can be used as an oxygen management tool. The effects of alternating air injection are comparable to the effects of alternating gas injection: the saturation in the swept areas changes due to the alternating (re-) invasion of gas, oil and water. This paper illustrates that modeling oxygen consumption is essential for the evaluation of potential risks and optimization of the HPAI process.
- North America > United States > South Dakota (0.49)
- North America > United States > Montana (0.34)
- North America > Canada > Alberta (0.34)
- North America > United States > South Dakota > Williston Basin > Buffalo Field > Red River Formation (0.99)
- North America > United States > North Dakota > Williston Basin (0.99)
- North America > United States > Nebraska > Sloss Field (0.99)
- (5 more...)
Investigation on In-Situ Combustion in D66, a Multilayered Heavy Oil Reservoir, Liaohe Oilfield
Teng, L.. (Northeast Petroleum University) | Song, H.. (Northeast Petroleum University) | Zhang, S.. (Liaohe Oilfield Company, CNPC) | Wu, F.. (Liaohe Oilfield Company, CNPC) | Xu, D.. (Liaohe Oilfield Company, CNPC) | Gong, Y.. (Liaohe Oilfield Company, CNPC) | Jiang, Z.. (China University of Petroleum) | Gao, H.. (China University of Petroleum) | Wang, C.. (China University of Petroleum) | Zhong, L.. (China University of Petroleum)
Abstract In-situ combustion (ISC) has been investigated worldwide as a potential EOR process both for heavy oil and conventional oil, and there are some successful field applications such as industrial test in Suplacu and many tests in deep reservoir with low permeability. Most of heavy oil reservoirs recovered by In-situ combustion are known for favor reservoir properties such as limited layers (single layer is best) and appropriate heavy oil viscosity (usually hundreds to thousands of mPa•s). Obviously, it is challenging to recover multilayered heavy oil reservoirs by in-situ combustion method in consideration of heterogeneity between layers. For instance, Du 66 reservoir is a typical multilayered heavy oil reservoir in Liaohe Oilfield, it was not effectively recovered by cyclic steam stimulation (CSS in short) before 2005, and both oil production and OSR were unsatisfactory. There are no alternative but to test in-situ combustion for the purpose of improve oil recovery for such multilayered heavy oil reservoir. As a result, there are up to 91 well groups operated in inverted nine-spot pattern fireflood combined with CCS for production wells in past 10 years. In this work, feasibility analysis and engineering design of in-situ combustion for multilayered D66 reservoir are primarily investigated based on reservoir engineering study and numerical simulation. Furthermore, recovery performance such as air injection profile and gas production and channeling are discussed based on field measurement and performance. Particularly, principles and treatment of gas channeling and casing collapse are discussed. Additionally, both experience and lessons are presented based on statistical results and typical cases. The results show that considerable increase in oil production and improvement in ratio of oil production to steam injection (OSR in short) are observed at lower ratio of air injection to oil production (AOR in short). However, gas channeling occurs in some production wells in form of rapid increase in AOR, and it has significant effect on production performance. At the same time, casing collapse are found in many air injection wells, according remedial well treatment had to be carried out considering risk of high temperature, backfire and even explosion, and casing collapse has a much greater impact on injection performance and oil recovery. Therefore, investigation on gas channeling and profile control treatment of air injection wells were extensively carried out to eliminate gas channeling and casing collapse. In summary, the principles and engineering design of in-combustion in multilayered heavy oil reservoir are much more complex than single layer reservoir. Gas channeling and casing collapse are two extremely difficult problems in such combustion process, which could be eliminated or weakened based on rational engineering design and effective technologies.
- Asia > China > Shandong > North China Basin > Shengli Field (0.99)
- Asia > China > Liaoning > Bohai Basin > Liaohe Basin > Liaohe Field (0.99)
- North America > United States > Louisiana > China Field (0.97)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)