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Collaborating Authors
Results
Summary The unusually high primary recovery factors (RFs) observed in numerous heavy-oil reservoirs are often attributed to foamy oil flow (i.e., the non-Darcy flow involving formation and flow of gas-in-oil dispersion). It occurs when the wells are produced aggressively at high drawdown pressures that led to conditions in which the viscous forces become sufficiently strong to overcome the capillary forces in pushing dispersed bubbles through pore throats. The role of gravitational forces in generating such dispersed flow has not been studied adequately. This work was intended to evaluate the contribution of gravitational forces in primary depletion of heavy-oil formations under foamy flow conditions. Primary-depletion tests were conducted in a 200-cm-long sandpack that was held in either horizontal or vertical orientation. The results of horizontal depletion tests were compared with the depletion tests conducted with the sandpack in the vertical direction. Vertical depletions showed better recoveries at slower depletion rates compared with horizontal depletions. The RFs of both horizontal and vertical depletions were correlated against the average drawdown pressure available to move the oil. It was found that the RF shows a strong dependence on the average drawdown pressure. It was also found that the curve of RF vs. average drawdown pressure moves slightly toward higher recoveries in the presence of an added foaming agent (i.e., with increased oil foaminess).
- Research Report > New Finding (0.68)
- Research Report > Experimental Study (0.46)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Summary Solvent-vapour extraction (SVX) processes offer an attractive alternative to thermal recovery processes by being less energy intensive and are more suitable for thinner, partially depleted reservoirs. A typical SVX process uses solvent injection to dilute the heavy oil by reducing its viscosity, allowing it to be mobilized for production. During this process, the injection of hydrocarbon solvents results in partial deasphalting of the heavy oil, thus reducing its viscosity and enhancing the process performance further. This work examined the formation and growth of solvent chambers in laterally and vertically spaced horizontal injector/producer well pairs in porous media with five different permeabilities and three different solvent-vapour qualities. Consolidation of the porous media caused by asphaltene precipitation was also analyzed. Thermal-imaging and model excavation studies were performed to investigate the formation and growth of solvent chambers for seven different experiments conducted on a large 3D-physical-model apparatus. The important findings from this study are as follows: During solvent injection, one or more solvent fingers develop between the injector and producer. The dominant solvent finger becomes a conduit that grows into a solvent chamber connected to the injection well in the upper portion of the reservoir, and develops into an oil-drainage conduit connected to the production well in the lower portion of the reservoir. Solvent dispersion layers are located on the margins of both the solvent chambers and the oil-drainage conduits. The location and development of these nonuniform solvent chambers and oil-drainage conduits are unpredictable, and the oil-drainage conduits do not grow significantly in diameter once connected to the production wellbore, limiting the wellbore inflow efficiency and conformity. Asphaltene precipitation and migration can aggravate this inflow problem, reducing the SVX process performance further. SVX performance can be improved by increasing the number and diameter of oil-drainage connections between the solvent chamber and the production well, and by controlling the oil deasphalting process. This can be performed by optimizing injection- and production-wellbore geometries, and by optimizing solvent-injection rates and vapour quality.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Steam-solvent combination methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Summary For stratified reservoirs with free crossflow and where fractures do not cause severe channeling, improved sweep is often needed after water breakthrough. For moderately viscous oils, polymer flooding is an option for this type of reservoir. However, in recent years, an in-depth profile-modification method has been commercialized in which a block is placed in the high-permeability zone(s). This sophisticated idea requires that (1) the blocking agent have a low viscosity (ideally a unit-mobility displacement) during placement, that (2) the rear of the blocking-agent bank in the high-permeability zone(s) outrun the front of the blocking-agent bank in adjacent less-permeable zones, and that (3) an effective block to flow form at the appropriate location in the high-permeability zone(s). Achieving these objectives is challenging but has been accomplished in at least one field test. This paper investigates when this in-depth profile-modification process is a superior choice over conventional polymer flooding. Using simulation and analytical studies, we examined oil-recovery efficiency for the two processes as a function of (1) permeability contrast, (2) relative zone thickness, (3) oil viscosity, (4) polymer-solution viscosity, (5) polymer- or blocking-agent-bank size, and (6) relative costs for polymer vs. blocking agent. The results reveal that in-depth profile modification is most appropriate for high permeability contrasts (e.g., 10:1), high thickness ratios (e.g., less-permeable zones being 10 times thicker than high-permeability zones), and relatively low oil viscosities. Because of the high cost of the blocking agent relative to conventional polymers, economics favors small blocking-agent-bank sizes (e.g., 5% of the pore volume in the high-permeability layer). Even though short-term economics may favor in-depth profile modification, ultimate recovery may be considerably less than from a traditional polymer flood.
- North America > United States > Texas (0.46)
- Asia > China > Heilongjiang Province (0.28)
- North America > United States > Alaska > North Slope Borough (0.28)
- North America > United States > Alaska > North Slope Basin > Prudhoe Bay Field (0.99)
- North America > United States > Alaska > North Slope Basin > Kuparuk River Field > Kuparuk Field (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- (3 more...)
Summary In-situ extraction of ultraviscous deposits from the vast bitumen resources in western Alberta, Canada, requires significant water and energy usage, which consequently leads to greenhouse-gas emissions. Currently proven steam-based recovery schemes include cyclic-steam-stimulation (CSS), steamflooding, and steam-assisted gravity-drainage (SAGD) processes, which are accompanied by many economic and environmental challenges. Coinjection of solvent with steam is a technology that has the potential to improve the efficiency of steam processes as well as reduce energy usage and carbon dioxide emissions. In recent years, researchers and industry professionals have attempted to develop the process further by conducting fundamental research as well as field pilot trials, with varying degrees of success. However, the current level of understanding of the process and the knowledge surrounding the fundamental physics and mechanisms involved are not entirely satisfactory. In this paper, a parametric simulation study was performed to address the key aspects of the solvent-coinjection (SCI) process that contribute to further understanding and development of the process. Simulation observations were verified with experimental evidence where available to support the results and conclusions. Effects of several operational and geological parameters were evaluated on the performance of the SCI process, and the relative performance benefits were assessed over normal SAGD operations. These parameters included solvent type, solvent concentration, initial-solution gas/oil ratio (GOR), relative permeability curves, and pay thickness. The results revealed that the optimal solvent should not be chosen only on the basis of mobility-improvement capability, but also under consideration of other operational, phase- and flow-behavioral and/or geological conditions that are set or present. Higher concentrations of solvents showed more energy-saving upsides than rate-acceleration benefits. It was also observed that the reservoir steam-intake rate is still likely to be the prime performance indicator of the SCI process. In addition, SCI showed that the potential exists for accessing more resources, particularly below the producer level. Furthermore, steam trap control on the producer seems to be problematic when used for SCI simulation. With the current well-control capacity of simulators, a higher degree of subcool is likely to be needed to avoid live vapor-phase production from the producer.
- North America > Canada > Alberta (0.67)
- Europe > United Kingdom > North Sea > Central North Sea (0.24)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > McMurray Formation (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > Firebag Oil Sands Project > Wabiskaw-McMurray Formation (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > Leismer Oil Sands Project (0.98)
This paper provides a simple procedure for evaluation of depth The present paper shows how to assess the depth of permeability of permeability impairment within the wellbore zone using drillstem-testing impairment using DST flow-period data. Also computed are skin (DST) flow-period data. Also computed are skin factor, permeability of the wellbore zone, and permeability of the factor, permeability of the wellbore zone, and permeability of the reservoir. The presented method may be used for analysis of the bottomhole reservoir.
Summary An ensemble-based history technique has been applied to implicitly estimate three-phase relative permeability curves from production data. A power law representative of relative permeability curves is used. Both endpoints and shape factors of relative permeability curves are included in state vectors that are updated sequentially by assimilating observation data. This method has been validated by accurately evaluating relative permeability in a synthetic reservoir with 2D, three-phase flow. It is shown from the synthetic case that good estimation of relative permeability curves can be obtained by assimilating the observed oil rates, gas/oil ratios, and bottomhole pressures of production wells. Both shape factors and endpoints of relative permeability curves are accurately evaluated; however, a larger ensemble size is needed to avoid filter divergence. Compared with the existing implicit methods, the ensemble-based history matching technique does not require the gradient of the objective function, which makes the technique easy to implement.
- Asia > China (0.46)
- North America > United States (0.46)
- North America > Canada (0.28)
- Asia > China > Xinjiang Uyghur Autonomous Region > Tuha Field (0.99)
- Oceania > Timor-Leste > Timor Sea > Bonaparte Basin > Oliver Field (0.93)
- Oceania > Australia > Timor Sea > Bonaparte Basin > Oliver Field (0.93)
Summary In Alberta and British Columbia, a huge amount of tight gas is trapped inrelatively low-permeability rock formations. Physical fracturing of theseformations could enhance the overall formation permeability and thus improvetight gas extraction. One of the outstanding issues in rock fracturing is todetermine the magnitude of applied effective stress. The generaleffective-stress law is defined as seff =sc - asp, where sc andsp are total confining stress and fluid pore pressure,respectively. Each physical quantity of rock responds to total stress and porepressure in a different way, and thus each quantity has its own unique Biot'seffective-stress coefficient. The main objective of this study is toexperimentally determine the Biot's coefficient for permeability of Nikanassinsandstone. A series of permeability measurements was conducted on Nikanassinsandstone core samples from the Lick Creek region in British Columbia undervarious combinations of confining stress and pore pressure. In addition,permeability values were measured both along and across bedding planes toinvestigate any anisotropy in the Biot's coefficient.
- North America > United States (1.00)
- North America > Canada > British Columbia (0.55)
- North America > Canada > Alberta (0.52)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.55)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Block BM-C-41 > Tubarao Tigre Field (0.89)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Block BM-C-41 > Tubarao Gato Field (0.89)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Block BM-C-41 > Pipeline Field (0.89)
- Europe > Spain (0.89)
Summary In naturally fractured reservoirs, fractures are the main flowing channels, while matrix is the dominant storage space. The oil/water relative permeability curve for the fracture in this kind of reservoir is very important to water-injection field development. In this study, we conducted experiments on the oil/water relative permeability of carbonate cores from Kenkiyak oil field and compared the differences in relative permeability curves between natural matrix cores and artificial-fracture cores. After the fracturing process, the two-phase flow area of tested cores becomes narrower, the permeability of the equal-permeability point gets higher, the relative permeability curve rises or drops more rapidly, and the displacement recovery efficiency decreases. The stress-sensitivity characteristics of the relative permeability curves were also studied on the basis of experiments on naturally fractured cores. With increasing effective confining pressure, the irreducible water saturation increases, the residual-oil saturation changes slightly, the equal-permeability point moves downward, and the displacement recovery efficiency declines. Numerical-simulation results indicate that for a given recovery factor, the water cut would increase more slowly but ultimate recovery factor would decrease using the relative permeability curve under higher confining pressure. Therefore, the water injection should be operated when the reservoir pressure is relatively higher to maintain formation pressure during waterflooding and lower the impact of stress sensitivity accordingly.
- Asia > Kazakhstan > Aktobe Region (0.34)
- North America > United States > California (0.28)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.69)
Summary Slickwater fracturing has been increasingly applied to stimulate unconventional shale-gas reservoirs. Comparing with crosslinked fluids, slickwater used as a fracturing fluid has several advantages, including low cost, a higher possibility of creating complex fracture networks, less formation damage, and ease of cleanup. An enormous amount of water is injected into the formation during the treatment. Even with a good recovery of injected water from flowback, large quantities of water are still left within the reservoir. The dynamics of the water phase within the created hydraulic fractures and reactivated natural fractures (induced fractures) has significant impact on both short- and long-term performance of a hydraulically fractured well. The dynamics of the water phase within fractures is controlled by many mechanisms, such as relative permeability, capillary pressure, gravity segregation, and stress-sensitive fracture conductivities. In this paper, reservoir-simulation models for a generic gas-shale reservoir are constructed to investigate the changes of water-saturation distribution in fractures over time during production and their impact on gas-production performance. It is demonstrated that water imbibitions caused by capillary pressure and gravity segregation can play important roles in water-saturation distribution and redistribution, particularly during extended shut-in, which in turn affects gas flow significantly. Moreover, an unfavorable combination of relative permeability, capillary pressure, stress-sensitive fracture conductivities, and invasion-zone permeability damage can lead to water-blockage problems.
- North America > United States > Texas (0.69)
- North America > United States > West Virginia (0.47)
- North America > United States > Ohio (0.46)
- North America > United States > West Virginia > Appalachian Basin > Utica Shale Formation (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- (12 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
Summary Western Sichuan deep tight gas reservoirs are characterized by ultralow permeability, natural fractures, partial ultralow water saturation, and a hard brittle shale interlayer. The matrix permeability varies from 0.001 to 0.1 md. The natural-fracture width varies from several micrometers to 3.0 mm, but it could be up to 5.0 mm during well operations. Lost circulation--inducing severe reservoir damage and increasing nonproductive time--has frequently occurred during well drilling and cementation during the past 10 years. The traditional lost-circulation-control techniques such as physical, chemical, or physicochemical methods, which used to permanently choke the lost-circulation passage of the nonpay zone, are not suitable for the pay zone. Several technologies, including air underbalanced-drilling fluids, noninvasive drilling fluids, and traditional temporary-shielding-fluids (TSF) technology, were tried to prevent formation damage owing to lost circulation but none of them worked well. Air underbalanced drilling has to be given up because of formation-water influx and wellbore instability. Noninvasive drilling fluids are ineffective because of the low percentage of return permeability and low bearing strength of the mudcake in the fractured formation. Traditional TSF technology is applicable for the damage prevention only in reservoirs with fractures less than 100 um in width. Temporary-sealing-loss (TSL) fluids with millimeter-sized agents take advantage of acid-soluble bridging particles to rapidly form a tight plugging zone near the wellbore that efficiently seals the pore throats and fractures. TSL fluids were developed to prevent formation damage in leaky fractured reservoirs. With the application of the new TSL fluids, Well W2, in the second member of the Xujiahe formation, obtained a gas-production rate of 52.16×10 m/d. Furthermore, lost circulation never occurred during drilling of Well W101.
- Asia > China > Sichuan Province (0.41)
- North America > United States > California (0.28)
- Geology > Mineral (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.48)
- North America > United States > California > San Joaquin Basin > Elk Hills Field (0.99)
- Asia > China > Sichuan > Sichuan Basin > Xujiahe Formation (0.99)