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Collaborating Authors
Results
Physical and Numerical Simulations of Steamflooding in a Medium Crude Oil Reservoir, Lake Maracaibo, Venezuela
Ovalles, Cesar (PDVSA Intevep) | Angel, Rico (PDVSA Intevep) | Perez-Perez, Alfredo (PDVSA Intevep) | Hernandez, Miguel (PDVSA Intevep) | Guzman, Nora (PDVSA Intevep) | Anselmi, Lorenzo (PDVSA Intevep) | Manrique, Eduardo (PDVSA Intevep)
Abstract Physical and numerical simulations of steamflooding were carried out to determine the technical feasibility of applying this technology to a medium crude oil reservoir (25ยฐ API) located in the Lake Maracaibo, Western Venezuela, specifically, 3rd phase LL-03 reservoir. A one-dimension cell with steam injection (80% quality and 400 psi) was used to study the steamflooding behavior at laboratory scale. Oil rates cumulative oil productions and temperature profiles were reported and the results showed an increase of 14โ20 percent of oil recovery with respect to original oil in place after waterflooding. Additionally, the use of steam drive as primary recovery method showed an additional of 5% in cumulative oil production. Compositional-thermal numerical simulations were carried out and validated using the laboratory scale results. Based on analysis of the crude oil true boiling point curve, the oil fraction was represented by a three pseudo-components model. The results (oil rates and cumulative oil productions) showed a reasonable match between the calculated and experimental simulations. Using this model, a numerical simulation study was carried out in a seven-spot inverted pattern (300 m) in order to provide performance forecast and other useful information for the design, implementation and operation of a field scale steamflooding test. After seven-year of steamflooding, the simulation showed only 15 percent of incremental oil recovery in comparison with waterflooding. However, using a five-spot inverted pattern (100 m), 2. 5-fold increase in cumulative oil production can be predicted with respect to waterflooding during the same period. Based on these results, it can be concluded that steamflooding technology in a Lake Maracaibo medium crude oil reservoir (25ยฐ API) represents a feasible alternative with high potential applications. Introduction Since the first commercial project in 1952, steam injection processes have been successfully applied to heavy and extra-heavy crude oils. Mainly, two general schemes for enhanced oil recovery (EOR) are used, i. e. steam stimulation (Huff and Puff) and steamdrive. In field applications, the first process precedes over the second due to higher costs related to continuos steam generation and injection. For heavy and extra-heavy crude oils, the production mechanisms are associated with viscosity reduction and changes in rock wettability. Nowadays, the application of steamdrive in medium/light oil reservoir has a relevant position in thermal EOR projects. Due to low viscosity (at reservoir conditions) and high volatility of light and medium crude oils, the principal recovery mechanisms are expected to be different than those reported for the heavier counterparts. Thermal expansion and distillation of light hydrocarbons are the most important production mechanisms for medium/light oil. Also, enhanced solution gas drive and accelerated depletion from zones that are heated but not displaced results in very low residual oil saturation where steam displacement occurs. In a recent benchmarking study, 43 steamflooding field projects in light/medium crude oils were analyzed in order to find out reservoir characteristics and operational practices used on a worldwide scale. More than 30 successful projects were considered and summarized in an extended database. Properties such as reservoir characterization, best operational practices and results obtained during steamflooding projects were included. On average, an incremental oil recovery of 19% with respect to original oil in place (OOIP) was obtained by steamflooding, during a project lifetime of seven years. According to published data of successful projects, a numerical model was developed, in order to rank potential reservoirs. A statistical model was developed to rank the different properties using a standardized score scale. Based on the numerical model, 3rd phase LL-03 reservoir (La Rosa sand) was selected as a potentially successful reservoir to apply steamflooding technology.
- South America > Venezuela > Lake Maracaibo > Maracaibo Basin > La Salina Field (0.99)
- North America > United States > California > San Joaquin Basin > Buena Vista Hills Field (0.99)
Abstract Experiments were conducted to study the feasibility of using propane as a steam additive to accelerate oil production and improve steam injectivity in the Hamaca field, Venezuela. The experiments utilized a vertical injection cell into which a mixture of sand, oil and water was tamped. The Hamaca oil sample had an oil gravity of 8ยฐAPI and a viscosity of 25,000 cp at 50ยฐC. The injection cell was placed inside a vacuum jacket, set at the reservoir temperature of 50ยฐC. Superheated steam at 170ยฐC was injected at 3. 5 ml/min (cold-water equivalent) simultaneously with propane at the top of the cell. The cell outlet pressure was maintained at 50 psig. Four propane:steam mass ratios were used, namely, 0:100 (pure steam), 2. 5:100, 5:100, and 10:100. Produced liquid samples from the bottom of the cell were collected, treated to break emulsion, and analyzed to determine oil and water volumes, and density and viscosity of the oil. The oil was subjected to SARA analysis to determine the degree of in-situ oil upgrading. Composition of the produced gas was determined using a gas chromatograph. Each run lasted three hours. Experimental results indicated the following. First, with steam-propane injection, start of oil production was accelerated by 17% compared to that with pure steam injection. In the field, this could translate into significant gains in discounted revenues and reduction in steam injection costs. Second, steam injectivity with propane as an additive was up to three times higher than that for pure steam injection. Third, oil production acceleration and injectivity increase were practically the same for runs with propane as a steam additive (irrespective of the propane:steam mass ratios). Propane appears to be a viable steam additive at propane:steam mass ratios as low as 2. 5:100. Introduction Several studies have been carried out to test the effect of injecting steam along with other gaseous additives. In this section, previous experiences with the combined use of steam and gaseous additives are presented. Redford (1982) conducted experiments to study the effect of adding carbon dioxide, ethane and/or naphtha in combination with steam. Results showed that the addition of carbon dioxide or ethane improved oil recovery. Further recovery was reached when naphtha was added. Harding et al. (1983) presented both experimental and simulation results suggesting that the co-injection of carbon dioxide or flue gas with steam yielded higher recoveries when compared to pure steam injection. Stone and Malcolm (1985) performed several tests to study the benefit of injecting carbon dioxide along with steam. Higher production rates were obtained for the case of steam-carbon dioxide injection. Good agreement was found between the experimental data and numerical simulation results. Stone and Ivory (1987) carried out further investigations using the model from Stone and Malcolm. This time, experiments with CO2 presoak and CO2 co-injection with a solvent were conducted. They found that under certain conditions, carbon dioxide pre-soaking increased oil recovery above the conventional CO2-steam injection. Nasr et al. (1987) presented results of experiments conducted to test the effect of injecting CO2, N2 and flue gas with steam. Both continuous and cyclic injection were tested. The addition of gasses increased bitumen recovery. The use of CO2 resulted in higher oil recoveries when compared to that with N2 and flue gas injection. Frauenfeld et al. (1988) presented results showing that for oils without an initial gas saturation, co-injection of CO2 with steam was capable of improving oil recovery over that obtained with steam alone. On the other hand, when an initial non-zero gas saturation was present, co-injection of CO2 was not beneficial.
- North America > United States > Texas (0.28)
- North America > United States > Oklahoma (0.28)
- South America > Venezuela > Anzoรกtegui (0.24)
- Europe > Switzerland > Thurgau > Frauenfeld (0.24)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.89)
- South America > Venezuela > Morichal Field (0.99)
- South America > Venezuela > Anzoรกtegui > Eastern Venezuela Basin > Maturin Basin > Hamaca Area > Hamaca Area Field (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Lindbergh Field (0.99)
Abstract Hunton Formation is one of the most promising formations producing oil and gas in Oklahoma. The formation has an anomalous producing behavior. At the inception, the wells produce at relatively high water -oil and gas-oil ratios. Eventually, both the WOR and GOR decrease. This results in an increase in oil cut and hence reduction in lifting costs over time. Because of relatively high WOR's, many operators are discouraged from completing the wells, and hence abandoning the effort to produce oil from these formations. This particular behavior has been addressed with different names: de-watering, reverse coning, to name a few. We call this behavior ROC (retrograde oil cut) mechanism. Our goal is to explain various anomalous behaviors in the field production, which can be reproduced by geologically defensible reservoir model. We tested several models by comparing the field data with the simulated behavior. Finally, we converged on to a three-layer model - which is geologically and core data consistent - and can produce various anomalous characteristics. These include decrease in WOR over time, increase in GOR after the well has been shut-in, long transient state behavior of oil production, and the decline in pressure (instead of pressure build-up) after some of the wells have been shut-in for 24 hour periods. We have integrated available core and log data, relative permeability data, geological understanding as well as PVT data to build this model. We tested this model by mimicking production from several wells in West Carney Field in Oklahoma. The implications of understanding the mechanism are enormous. Although we only concentrated on Hunton Formation in one county, Hunton formation extends over 2 million acres in Oklahoma alone. Similar formations also exist in other states, which were deemed unproductive in the past. By correctly understanding the production mechanism, the viability of producing from other similar formations can be better investigated. Introduction The objective of this study was to establish a primary production mechanism by which oil is being produced from the Hunton formation by incorporating engineering and geological information. Hunton formation, though promising in nature, has not been fully developed because of its anomalous behavior. Initially, field development was sporadic and many of the earlier wells were abandoned due to high water production and limited surface facilities for disposing off the excess produced water. With the depletion of the reservoir, oil cut increased, making it feasible to develop the field. Hunton Formation covers approximately 2.7 million acres in Oklahoma (Figure 1a) and in surrounding states of Texas, Arkansas and New Mexico. We concentrated our study to one county, West Carney county, in Oklahoma (Figure 1b). Formation is highly fractured and discontinuous and local variations in geology affect the performance to a great extent. Properties observed at the wellbore are sometimes misleading and the well behaves contrary to the observed properties. Some of the unique characteristics of the field are decrease in WOR over time, increase in GOR after the well has been shut-in, decline in pressure (rather than pressure build-up) after some of the wells have been shut-in, and long transient state behavior of oil production. We have tried to explain these unique characteristics using numerical model and the results from this could be extrapolated to other fields producing in a similar manner.
- North America > United States > Oklahoma > Anadarko Basin > Carney Field (0.99)
- North America > United States > Texas > Anadarko Basin > Hunton Field > Hunton Limestone Formation (0.98)
- North America > United States > Oklahoma > Anadarko Basin > Hunton Field > Hunton Limestone Formation (0.98)
- North America > United States > Arkansas > Anadarko Basin > Hunton Field > Hunton Limestone Formation (0.98)
Abstract THAI - โToe-to-Heel Air Injectionโ is a new, short-distance displacement process, that achieves high recovery efficiency by virtue of its stable operation and ability to produce mobilised oil directly into an active section of the horizontal producer well, just ahead of the combustion front. THAI, therefore, avoids the pitfalls inherent in most conventionally operated in situ combustion (ISC) processes, which employ vertical injection-vertical producer wells to achieve long-distance displacement. However, the problem of achieving efficient ignition and start-up still requires critical attention, in order to ensure optimal process operation. A series of 3-D tests on heavy Wolf Lake crude (10. 5 ยฐAPI) and Athabasca Tar Sand Bitumen (8 ยฐAPI) were made using well configurations: vertical (VI) or horizontal injection (HI) and horizontal producer (HP) wells in direct line drive (VIHP, HIHP); staggered line drive (VI2HP) and line drive (2VIHP). Experimentally, the horizontal injector configuration (HIHP) was found to be the most efficient for achieving rapid start-up, i. e. the shortest time to achieve stable combustion front propagation. However, injection of air via a horizontal well is not a very practical design for field operation. The single vexrtical injector configuration (VI2HP) was slow to achieve stable operation, due to the development of a much smaller ignition zone, initially, compared with the HIHP configuration. When hot air was used for ignition, the time delay for oil production is related to the reservoir temperature. When the initial temperature in the sandpack was 15ยฐC, then a vertical injector, placed high in the sandpack, combined with a horizontal producer well (VIHP) achieved slower start-up than VI2HP for post-steam flood THAI, with the initial sandpack at 100ยฐC. All of the tests achieved very high oil recoveries, averaging greater than 80% OOIP, except in the VIHP test. The recovery in the latter case was only 70% OOIP due to the loss of air injectivity during later stages of the combustion. Significantly, THAI also preserves the very substantial thermal upgrading which occurs in the mobile oil zone, averaging an increase of 6 to 8 API points. 1. Introduction The three natural oil recovery mechanisms include solution gas drive, gas cap expansion drive, and water drive. Water or gas injection drives are known as secondary recovery methods. Enhanced Oil Recovery (EOR) is usually considered to apply at the tertiary stage, but can also be applied as primary or secondary methods. For light oil reservoirs, the ultimate oil recovery by conventional methods can reach up to 50%, or more, using water injection. However, for highly viscous oils, comparable recoveries would only be about 5% to 15%, and essentially zero in the case of extremely viscous oils, or bitumen. The main objective of an EOR process is to achieve high oil recovery and high production rate. The low recovery for heavy oil is mainly due to its high viscosity, i. e. too viscous to flow to the producer wells at rates sufficient to support an economic operation. Thermal EOR methods are required for heavy oil production. Thermal EOR processes are achieved by injecting a hot fluid (steam), or air for combustion, with the aim of increasing the reservoir temperature to reduced the viscosity of the heavy oil. Because of the dramatic effect of temperature on heavy oil viscosity, more oil is mobilised at a higher temperature and is capable of being displaced.
- North America > United States (1.00)
- North America > Canada > Alberta > Athabasca Oil Sands (0.27)
Abstract The application of artificial intelligence tools such as fuzzy logic and neural networks is evolving as an oilfield technology. Log analysis work done in 1989 by Halliburton focused on applying backpropagation neural networks to identify total porosity and to identify lithofacies. In 1996 PRRC researchers used fuzzy logic to prioritize the significance of petrographic attributes to minipermeameter permeability measurements. Recently (2001), Zadeh Institute workers revisited the use of these tools in a manner consistent with soft computing terminology. In this paper, fuzzy ranking is used to prioritize inputs to neural networks that are trained, tested, and used to forecast oil production. Patterns related to oil production are sometimes obvious in datasets from easy-to-interpret logs, but sometimes they are not, such as those in datasets from logs run through thin-bedded turbidite zones. The correlation between the individual log charts and core measurements varies from "good" to "bad" (fuzzy). A neural network can be used to generate regressions when given the "good" log charts. The regression equations are developed with several log charts and core measurements and the resulting pseudo-logs are then correlated with known production. The resulting correlations can be used to estimate future oil production from potential producing wells. Two field examples are used to demonstrate the fuzzy ranking technique and production forecasting correlations. The method to generate fuzzy curves is presented and sources of public domain neural networks are included in the references. The pitfalls involved in training and testing a neural network to predict oil production are also presented. Introduction The need to forecast oil production is well known. From AFEs to bank loans, a supporting production forecast is required. Forecasting methods vary from decline curve extrapolation to computer simulation to analogy. This paper applies fuzzy ranking and neural networks (artificial intelligence tools) to develop correlations (analogies) to forecast oil production, given open-hole log information in one example and regulatory hearing information in another The neural networks are trained, tested, and then used to forecast oil production. The application of artificial intelligence tools such as fuzzy logic and neural networks is evolving as an oilfield technology. Log analyses work done in 1989 by Halliburton focused on applying backpropagation neural networks to identify total porosity and to identify lithofacies. In 1996 PRRC researchers used fuzzy logic to prioritize the significance of petrographic attributes to minipermeameter permeability measurements. Recently (2000), Zadeh Institute workers revisited the use of these tools in a manner consistent with soft computing terminology. Statement of Theory and Definitions Decline curve analysis, black oil model history matching, exploration analogies and exploration trend extrapolations are often considered statistical methods of forecasting oil production based on previous experience. However, it is generally difficult to forecast oil production because these sorts of analyses include data interpretation that is subjective and does not clearly relate to the future. For example, the proper decline rate must be established (pick the right slope), the computer model must be tuned to match production history, the depositional environment and oil source must be identified, and the reservoir geology must be understood. Oil forecasts of this nature can also be considered as inverse problems that are well suited to multivariate correlating techniques such as neural networks, but neural networks require input variables that relate to production performance. Selection of the proper variables available in the historical record is needed to most accurately forecast oil production. The variables included in data collected during the past that best relate to oil production can be identified with fuzzy ranking technology.
- Geology > Rock Type (0.74)
- Geology > Sedimentary Geology > Depositional Environment (0.54)
- Geology > Geological Subdiscipline > Petrology > Petrography (0.45)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (22 more...)
Abstract The impact of fracture permeability on oil recovery from moderately-water-wet chalk has been determined. Nuclear Tracer Imaging was used to measure local fluid movement and to identify locations of trapped oil resulting from waterflooding a sleeved, fractured chalk block. Increasing the confinement pressure between experiments decreased the permeability of an interconnected fracture network for each sequential waterflood. The experiments showed that the dominant oil recovery mechanism was spontaneous imbibition, however, viscous oil recovery added significantly to the total oil production when the permeability ratio between the fractured system and the matrix was less than 20. The amount of oil viscously recovered increased as the fracture permeability decreased. Introduction Previous work has investigated waterfloods in fractured chalk blocks using Nuclear Tracer Imaging (NTI) to obtain the local in-situ saturation development during waterfloods at various wettabilities (ref. 1โ3). Recovery mechanisms were found to change when wettability was altered (ref. 3,4). Using iterative comparisons between large-scale experiments and numerical simulations, previous results concluded that, at strongly-water-wet conditions, a matrix-by-matrix block waterflood, governed by spontaneous imbibition, was dominant. At moderately-water-wet conditions, a dispersed waterfront swept across fractures apparently adding oil to the total oil recovery possibly by viscous displacement (ref. 5). A proposed mechanism for obtaining viscous recovery in a fractured reservoir by establishing capillary continuity across open fractures has recently been published (ref. 6). Objective The objectives of this study were to 1) determine if viscous displacement could be a significant recovery mechanism in fractured chalk at moderately-water-wet conditions, when interconnected fractures were present and 2) determine the impact of fracture permeability on the total oil recovery. Experimental Rock and Fluid Characteristics. The limited supply of reservoir core from chalk reservoirs often requires the use of outcrop chalk as the physical reservoir model in the laboratory. To obtain enough similar material to investigate the simultaneous interaction between capillary forces, viscous forces and gravity, and to reduce the impact of capillary end effects, blocks of outcrop rock have been used in this study instead of small plugs from actual reservoir core. The R rdal chalk from the Portland quarry in lborg, Denmark, has been identified to be representative of most North Sea chalk and has been used as the reservoir analogue in this work. Scaled-up laboratory waterflood imaging experiments have been performed using an outcrop chalk block labeled CHP-17. For mechanistic studies of oil recovery in fractured reservoirs brine and decane or parafinic lamp oil have been used as model fluids to obtain a high degree of reproducibility in the experiments (ref. 7). These fluids exhibit a viscosity ratio at room temperature representative of the reservoir fluids at reservoir temperature and pressure. The chalk block, approximately 20 cm ร 10 cm ร 5 cm thick, was cut from a large piece of Rรธrdal outcrop chalk. This chalk material had never been contacted by oil and was strongly-water-wet. The procedures for preparing and assembling the physical reservoir model was described in previously published papers, ref. 1โ5, 7 and 8. The difference from earlier experiments which used epoxy to seal the block from the confinement fluid was the use of a square Viton sleeve in this study. Porosity and fluid permeability were measured at 47% and 2. 5mD, respectively. Rock and Fluid Characteristics. The limited supply of reservoir core from chalk reservoirs often requires the use of outcrop chalk as the physical reservoir model in the laboratory. To obtain enough similar material to investigate the simultaneous interaction between capillary forces, viscous forces and gravity, and to reduce the impact of capillary end effects, blocks of outcrop rock have been used in this study instead of small plugs from actual reservoir core. The R rdal chalk from the Portland quarry in lborg, Denmark, has been identified to be representative of most North Sea chalk and has been used as the reservoir analogue in this work. Scaled-up laboratory waterflood imaging experiments have been performed using an outcrop chalk block labeled CHP-17. For mechanistic studies of oil recovery in fractured reservoirs brine and decane or parafinic lamp oil have been used as model fluids to obtain a high degree of reproducibility in the experiments (ref. 7). These fluids exhibit a viscosity ratio at room temperature representative of the reservoir fluids at reservoir temperature and pressure. The chalk block, approximately 20 cm ร 10 cm ร 5 cm thick, was cut from a large piece of Rรธrdal outcrop chalk. This chalk material had never been contacted by oil and was strongly-water-wet. The procedures for preparing and assembling the physical reservoir model was described in previously published papers, ref. 1โ5, 7 and 8. The difference from earlier experiments which used epoxy to seal the block from the confinement fluid was the use of a square Viton sleeve in this study. Porosity and fluid permeability were measured at 47% and 2. 5mD, respectively.
- North America > United States (1.00)
- Europe > United Kingdom > North Sea (0.45)
- Europe > Norway > North Sea (0.45)
- (2 more...)
Abstract China's Liaohe Oilfield is the country's largest heavy oil field and contains numerous smaller, individually named, reservoirs (oilfields) with oil viscosity ranging from 100 cp to over 50,000 cp. Because of pressure depletion, steam huff-n-puff (cyclic steam) has reached its economic limit in a number of the heavy oil reservoirs in Liaohe. Recently, a flue (exhaust) gas-steam slug process has been tested in an attempt to improve recovery of medium heavy oil, oil with a viscosity less than 1,000 cp. Pilot tests, which started in September 1998, used one injection well and 9 production wells. The pilot test conducted in the eastern part of Block Du-66 of Shuguang Oilfield showed encouraging results. Average oil production increased from 1.8 t/d before the test to 20 t/d after more than 65 days production, with a peak oil rate of 29.2 t/d. The water-cut dropped from 84% to 39%. Drop in watercut reduced operating and water disposal costs. Cost of the entire operation of the flue gas-steam is about half of the cost of steam generated by a boiler. This paper describes the design, construction and operation of gas-steam slug project. The economics of the project and success to date are encouraging. This has prompted application of the gas-steam process to recover lower viscosity heavy oil from other Chinese reservoirs. Background The heavy oil reservoirs in Liaohe Oilfield belong to terrestrial positive rhythm deposition systems (fluvial cyclic deposition with each cycle fining upward). The reservoirs in this region are very complex. Faults are well developed and divide the reservoirs into many blocks. Within a fault block, the cyclic deposition shows highly heterogeneous layers (vertical) which exhibit great differences in fluid and rock properties. Liaohe has large reserves of the medium heavy oil (viscosity of less than 1,000 cp). To recover the medium heavy oil, steam huff-n-puff has been applied in most cases. Steam huff-n-puff is a pressure depletion recovery process. As the number of steam huff-n-puff cycles increase, the formation pressure and oil/steam ratio drop, substantially. At present, the average oil/steam ratio is 0.57 after an average 6.7 cycles of steam huff-n-puff. Formation pressure has dropped 70 to 90%. Pressure in major blocks is about 1โ3 MPa (at 1,000 - 1,500 m vertical depth). Oil/steam ratio in a number of wells has fallen to less than 0.3. Parts of the reservoir have reached the economic limit of thermal recovery by steam huff-n-puff. Some wells have had to be shut-in. New recovery methods need to be found, tested, and the successful methods need to be implemented to reduce declining oil production and improve the field's economics.
- North America > United States (1.00)
- Asia > China > Liaoning Province (0.55)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.50)
Restriction of Gas Coning by a Novel Gel/ Foam Technique
Lakatos, I. (Research Institute of Applied Chemistry, Univ. Miskolc, Miskolc-Egyetemvaros) | Lakatos-Szabo, J. (Research Institute of Applied Chemistry, Univ. Miskolc, Miskolc-Egyetemvaros) | Kosztin, B. (Hungarian Oil and Gas Co.) | Palasthy, Gy (Hungarian Oil and Gas Co.)
Abstract The laboratory and field studies were focused on development of a well treatment technology which can be used for restriction of gas coning in the Algyo reservoir. The method is based on simultaneous placement of a polymer/silicate gel at the GOC and a supporting foam pillow into the oil bearing layer. Extensive laboratory studies were carried out to tailor the chemical system to the field conditions. Use of short chain alcohol and natural protein as additives improved the efficiency of chemical mechanism. Special attention was paid to implementation of the technology. Two-point injection regime was elaborated to develop a horizontal barrier between the oil and gas bearing zones. The field test resulted only in a partial success: the hydrodynamic measurement definitely shown that the barrier was correctly placed, the oil flow in the pay zone was not effected, the GOR temporarily improved and the WOR positively changed. The long-term observations are, however, discourages: the investment and the return rate of expenditure is not balanced. The Hungarian experts take a stand on extending the observation period for more cycles and to collect abundant arguments to continue or to suspend the R&D activities and the field projects. P. 491
- North America > United States (0.46)
- Europe > Hungary (0.28)
Abstract Driver Production was one of four companies awarded a grant from the US Department of Energy as a result of a competitive procurement for small independent producers to demonstrate economic application of gas repressurization of oil reservoirs. Driver Production proposed a Flue Gas Injection (N2 and CO2) project in a five-spot pattern in the East Edna Field, Okmulgee County, Oklahoma, USA. The paper describes the design, construction, start-up, expansion and operation of a flue gas project that uses produced natural gas as the energy source for combustion and compression. Changing the engine to a larger unit to allow for higher gas injection capacity and for injection at higher pressure demonstrated the need for critical control of flue gas quality to minimize corrosion problems associated with CO2 injection. The project has demonstrated that even small operators can successfully implement gas repressurization to increase oil production from a pressure-depleted reservoir. The project, initiated in 1996, continues to increase oil and natural gas production as long as flue gas is injected. The economics of the project and success to date have prompted the project operator and other operators who have visited and analyzed the project to consider application of flue gas in their small pressure depleted reservoirs. P. 359
- North America > United States > Texas > Jackson County (0.26)
- North America > United States > Oklahoma > Oklahoma County (0.25)
- North America > United States > Oklahoma > Okmulgee County (0.25)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.87)
Abstract The Marmul field in Oman is exhibiting a low oil recovery caused by the high oil viscosity (80 mPa.s) and the moderate to strong edge water drive. The poor mobility ratio has resulted in early increased water production through water channeling and coning. The technology evaluated to reduce the water production made use of a so-called relative permeability modifier system which was composed of a cationic polyacrylamide and the crosslinker glyoxal. This gel system reduces the relative permeability for water, while only marginally affecting the relative permeability for oil. The aim of a relative permeability modifier system is a decreased water production and potentially an increased oil production. The major advantages for such a system are that the treatment is bullheaded down the well and detailed information on the inflow performance is not required. This was advantageous for the Marmul field in which all the wells have been gravelpacked. Selection criteria were used to establish which wells would be treated and the final candidates were randomly located over the field. The treatment design consisted of the injection of three equal sized polymer/crosslinking stages with increasing polymer concentration. Five of the initially six treated wells showed a positive response to the gel treatment, i.e. (large) water-cut reduction and increased oil production. A simulation study on one of these treatments was performed to understand the behaviour of these treatments. Initial results could not match the observed field behaviour and only after introduction of flow barriers (shale layers) in the reservoir model a match between simulation and field could be achieved showing the significance of small details in local geology around the well. However, these flow barriers could not be seen on the open hole logs. Subsequently eight treatments have been performed. However, they were disappointing and no clear explanation for the deviating behaviour could yet be given. The causes for the poor performance could be poor candidate selection and/or a poor understanding of the gel system. Poor candidate selection is considered doubtful because the wells in the first six and the last eight treatments were randomly chosen throughout the field. Therefore, the emphasis is now on the gel system to determine more accurately its chemistry (e.g. polymer/crosslinker concentrations needed) and the volumes required to obtain an optimum result with respect to decreased water production and increased oil production. P. 307