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Pennsylvania
This paper seeks answers, through a'philosophical' approach, to the questions of whether enhanced oil recovery projects are purely driven by economic restrictions (i.e. oil prices) or if there are still technical issues to be considered, making companies refrain from enhanced oil recovery (EOR) applications. Another way of approaching these questions is to ask why some EOR projects are successful and long-lasting regardless of substantial fluctuations in oil prices. To find solid answers to these two, by'philosophical' reasoning, further questions were raised including: (1) has sufficient attention been given to the'cheapest' EOR methods such as air and microbial injection, (2) why are we afraid of the most expensive miscible processes that yield high recoveries in the long run, or (3) why is the incubation period (research to field) of EOR projects so lengthy? After a detailed analysis using sustainable EOR example cases and identifying the myths and facts about EOR, both answers to these questions and supportive data were sought. Premises were listed as outcomes to be considered in the decision making and development of EOR projects. Examples of said considerations include: (1) Every EOR process is case-specific and analogies are difficult to make, hence we still need serious efforts for project design and research for specific processes and technologies, (2) discontinuity in fundamental and case-specific research has been one of the essential reasons preventing the continuity of the projects rather than drops in oil prices, and (3) any EOR project can be made economical, if technical success is proven, through proper optimization methods and continuous project monitoring whilst considering the minimal profit that the company can tolerate. Finally, through the'philosophical' reasoning approach and using worldwide successful EOR cases, the following three parameters were found to be the most important factors in running successful EOR applications, regardless of oil prices and risky investment costs, to extend the life span of the reservoir and warrant both short and long-term profit: (1) Proper technical design and implementation of the selected EOR method through continuous monitoring and re-engineering the project (how to apply more than what to apply), (2) good reservoir characterization and geological descriptions and their effect on the mechanics of the EOR process, and (3) paying attention to experience and expertise (human factor). It is believed that the systematic analysis and philosophical approach followed in this paper and the outcome will provide proper guidance to EOR projects for upcoming decades. 2 SPE-196362-MS
- South America (1.00)
- North America > Mexico (1.00)
- North America > Canada > Alberta (1.00)
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- Research Report (0.68)
- Overview > Innovation (0.45)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.93)
- Geology > Geological Subdiscipline (0.67)
- North America > United States > Texas > Tanner Field (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
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- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
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Abstract Electromagnetic (EM) heating has been proposed to recover heavy oil due to its great environmental friendliness. Previous studies focused on investigating the feasibility and enhancing the oil recovery of such non-aqueous method. However, the effect of EM heating on the variations of formation rock properties is still elusive. Detailed experiments/measurements are required to understand the effect of EM heating on changing the petrophysical properties of formation rocks. A commercial microwave oven is used to conduct the EM heating experiments. Different types of formation rocks (shale, Berea-sandstone, tight sandstone, and Indiana-carbonate) are investigated. Various techniques, including scanning electron microscopy (SEM), energy dispersive X-ray (EDX), N2 adsorption/desorption, and X-Ray fluorescence (XRF), are used to characterize the properties of shale samples before/after experiments. The porosity and permeability measurement are performed to Berea sandstone, tight sandstone, and Indiana carbonate. An infrared thermometer is used to measure the samples’ surface temperatures. Furthermore, oven-heating experiments are conducted to distinguish the effects of conductive-heating and EM heating on the property changes of rock-samples. Results show that different types of rocks exhibit different responses to EM heating; shale samples exhibit a higher temperature compared with sandstone and carbonate because of the better EM energy absorbance of clays and pyrite. The shale samples are crumbled into pieces or fractured after EM heating, while the sandstone and carbonate samples remain almost unchanged after EM heating. The SEM results reveal that EM heating causes tensile failure, shrinkage of clay, and release of volatile organic content to the shale sample. The N2 adsorption/desorption measurements demonstrate that the pore volume significantly increases due to clay shrinkage, while part of the pore can be blocked by the converted bituminous kerogen after EM heating. EM heating has almost no effect on Berea sandstone and Indiana carbonate due to the transparency of quartz and calcite to EM waves. However, the EM heating can fracture the tight sandstone that is saturated with water because of the rapid rise of pore pressure under EM heating.
- North America > United States > West Virginia (0.67)
- North America > United States > Pennsylvania (0.67)
- North America > United States > Ohio (0.67)
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- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.70)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Mineral (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- Asia > China > Shanxi > Ordos Basin (0.99)
- Asia > China > Shaanxi > Ordos Basin (0.99)
- Asia > China > Gansu > Ordos Basin (0.99)
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- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (0.89)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (0.87)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (0.67)
Abstract The roughness of fractures may play an important role in affecting the migration and placement of proppants during hydraulic fracturing operations. Previous studies focused on investigating the proppant transport in smooth vertical fractures, which did not consider the effect of the fracture-surface roughness. We examine the migration of proppants in rough and vertical fractures and then quantitatively reveal the effect of roughness on the instantaneous proppant transport and final proppant placement. Two types of rock samples (marble and granite) are fractured with the Brazilian test and molded to manufacture 20 × 20 × 5 cm transparent replicas. The surface roughness of these rock samples was first characterized by fractal dimensions. Then, the dyed fracturing fluid with a given proppant loading was injected into the rough vertical fracture. In each test, the inlet pressures were continuously monitored in order to obtain the differential pressure across the fracture model while the proppants were being transported in the fracture. The process was videotaped to real-time track the proppant distribution in the rough fracture. The proppant-transport behavior in the rough and vertical fracture was observed to be totally different from that in the smooth fracture. The major experimental findings include the following: 1) The proppant in a rough vertical fracture does not progress as a regular sand bank that commonly occurs in the smooth fracture, but rather an irregular-shape sand clusters with fractal characteristics; 2) In the rough and vertical fracture, the phenomenon of proppant bridging is visually observed, and such phenomenon is more likely to occur in the location with a larger roughness height. This implies rough fracture could promote a wider spreading of the proppant in the fracture compared to smooth fractures, and; 3) The existence of roughness enhances the vertical displacement of fluid containing proppants. These effects are also favorable for obtaining a better filling of the proppants in the fracture. Our experimental study reveals the mechanisms of proppant transport and distribution in real vertical fractures under the influence of roughness effect.
- Asia (0.68)
- North America > United States > Texas (0.28)
- Research Report > New Finding (0.85)
- Research Report > Experimental Study (0.84)
- 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)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (3 more...)
Summary This study investigates optimum matrix-oil-recovery strategies in naturally fractured reservoirs (NFRs) for different wettabilities and rock types. We compare the recovery efficiencies of two cases:primary countercurrent spontaneous imbibition followed by the diffusion of a miscible phase (secondary recovery) and primary diffusion of miscible fluid without preflush of matrix by spontaneous imbibition. For these recovery strategies, the effects of the matrix shape factor, matrix wettability, and type of miscible displacing phase on the rate of recovery and development of residual-oil saturation were clarified experimentally. Cylindrical Berea-sandstone and Indiana-limestone samples with different shape factors were obtained by cutting the plugs 1, 2.5, and 5 cm in diameter and 2.5, 5, and 10 cm in length. The external surface except one end was coated with epoxy. Static imbibition experiments were conducted on vertically situated samples in which the fractures were at the bottom and matrix/fracture interaction took place in an upward direction. Mineral oil and crude oil were used as oleic phases. Brine was selected as aqueous phase for the primary spontaneous-imbibition recovery. For primary- and secondary-miscible-displacement experiments, n-heptane was used as solvent. Wettability of water-wet Berea-sandstone samples was altered by aging to observe its effects on the dynamics of spontaneous countercurrent imbibition and diffusion. Parametric analyses were performed for the appraisal of the secondary- and tertiary-recovery potential of NFRs by immiscible- and miscible-fluid injections. The optimal recovery strategies (recovery rate, recovery time, and ultimate recovery) for different rock properties were identified and classified. In water-wet cases, starting the recovery with capillary imbibition followed by diffusion was found to be the optimal way (i.e., both effective and efficient). For limestone or aged-sandstone samples, starting the recovery by diffusion yielded a faster recovery rate and higher ultimate recovery. Introduction For an efficient recovery of oil from weakly water-wet NFRs, interaction between matrix and fracture needs to be accelerated by use of different enhanced-oil-recovery (EOR) techniques. Different conditions lead to different recovery mechanisms. For example, recovery is obtained by spontaneous imbibition if the matrix is water-wet and an immiscible wetting phase exists in the fracture. For oil-wet rocks, miscible displacement or heat injection is more favorable because spontaneous imbibition does not take place and recovery by gravity drainage is a relatively slow process, especially for heavy oils. It is apparent that any type of EOR other than imbibition would be costlier in terms of infrastructure and expenses. However, in certain circumstances listed above, expensive techniques are inevitable because less-expensive water or gas injection does not contribute significantly to matrix recovery. This study investigates different EOR strategies for weakly water-wet matrix types. Typically, countercurrent-type interaction was considered, and tests were performed on Berea-sandstone and Indiana-limestone samples in which the outer surface except one end was coated with epoxy. For purposes of comparison and to establish a base case, tests from a matrix with all sides open to flow were also provided. This study is a continuation of previous work (Hatiboglu and Babadagli 2004) that aimed to describe matrix/fracture interaction by spontaneous imbibition and diffusion for strongly water-wet matrix types. Recovery by capillary imbibition may be effective if the matrix is water-wet. It is well known that a substantial amount of oil (residual oil) might be left in the matrix even for strongly water-wet systems (Hatiboglu and Babadagli 2004; Kantzas et al. 1997; Bourbiaux and Kalaydjian 1990; Mattax and Kyte 1962; Ma et al. 1995; Schembre et al. 1998; Zhou et al. 2002; Zhang et al. 1996). Tertiary recovery of this remaining oil using heat or solvent could be very costly and inefficient because the process is uncontrollable because the high-permeability fracture network controls the flow direction of the injected fluid. Starting the process with heat or solvent injection could be more effective for the rock types that do not yield any capillary-imbibition recovery (Stubos and Poulou 1999; Morel et al. 1993; Zakirov et al. 1991; Le Romancer and Fernandes 1994; da Silva and Belery 1989; Lenormand et al. 1998; LaBolle et al. 2000; Polak et al. 2003; Rangel-German and Kovscek 2002; Hatiboglu and Babadagli 2005). All these efforts require a clear understanding of the processes, especially for countercurrent interaction. The objective of this paper is to clarify the mechanisms of countercurrent displacement of the nonwetting phase by both capillary forces and diffusion. Different shape factors and rocks with different wettabilities were tested. We compared the cases of recovery by diffusion only to cases of diffusion preceded by capillary imbibition so that we could propose the most effective and efficient recovery strategies on the basis of the uncontrollable parameters: matrix shape factor and wettability.
- North America > United States > West Virginia (0.69)
- North America > United States > Pennsylvania (0.69)
- North America > United States > Ohio (0.69)
- (2 more...)
- Research Report > Experimental Study (0.68)
- Research Report > New Finding (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.91)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.71)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.34)
- North America > United States > West Virginia > Appalachian Basin > Berea Sandstone Formation (0.89)
- North America > United States > Pennsylvania > Appalachian Basin > Berea Sandstone Formation (0.89)
- North America > United States > Ohio > Appalachian Basin > Berea Sandstone Formation (0.89)
- (2 more...)
- 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)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Abstract Development of mature oil fields has been, and will increasingly be, an attractive subject.Mature field development practices can be divided into two major groups:well engineering and reservoir engineering.This paper focuses on the reservoir engineering aspects. An extensive review of previously reported reservoir management practices for mature field development is provided.After the definition of mature field and an overview, different aspects of mature field development are outlined.The first issue covered is the estimation of remaining reserves focusing on the determination of the amount and location of the residual oil after primary and secondary recovery using field, log, and core data.After valuing the remaining oil, methods to recover it are classified.They include tertiary recovery, infill drilling, horizontals, optimal waterflooding design for mature fields, optimal well placement and other reservoir management practices.Suggested or implemented field application examples for big fields owned by majors and small fields owned by independents are presented. Special attention is given to tertiary oil recovery.An extensive review and critical analysis of tertiary recovery techniques covering the theoretical, practical, and economical aspects of it are provided.The emphasis is on their applicability in mature field development in terms of effectiveness (incremental recovery) and efficiency (cost and recovery time).Laboratory and field scale applications of different tertiary recovery techniques, i.e., gas (double displacement, WAG, and miscible-immiscible HC, CO[2], and N[2]), chemical (dilute surfactant, polymer, and micellar injection), and thermal (air and steam) injection, conducted to develop mature fields are included.Specific examples of big/giant fields, fields producing for decades, and mid to small size fields were selected.Differences in reservoir management strategies for majors, independents, and national oil companies are discussed. Introduction The world average of oil recovery factor is estimated 35%.Additional recovery over this "easy oil" depends on the availability of proper technologies, economic viability, and effective reservoir management strategies.On the other hand, chance of discovering giant fields remarkably decreases1. The discovery rate for the giant fields peaked in the late 60s and early 70s and declined remarkably in the last two decades. About thirty giant fields comprise half of the world oil reserves and most of them are categorized as mature field.The development of those fields entails new and economically viable techniques, and proper reservoir management strategies. Mature field development is a broad subject.It can, however, be divided into two main parts:Well development, and reservoir development.Depending on the field type, history, and prospects, the development plans could be done on either one or both. This paper covers reservoir engineering aspects of mature field development.Determination of the amount and location of the remaining oil is the key issue in this exercise.Techniques to improve the recovery factor such as tertiary recovery, infills, horizontals, and optimal placement of the new wells are the other elements of reservoir development. Definition and elements of mature field development Oil fields after a certain production period are called mature field.A more specific definition of mature fields is the fields reached the peak of their production or producing fields in declining mode.A third definition could be the fields reached their economic limit after primary and secondary recovery efforts.Fig. 1 shows a typical production life of a field.Any points indicated by a question mark can be considered as the time when the maturity is reached.The tendency, however, is to define the decline period indicated by the arrow in Fig. 1, which is typically reached after having some secondary recovery efforts.Increasing water and gas production, decreasing pressure, and aging equipment are other indicators of maturity.
- North America > United States > Louisiana (1.00)
- North America > Canada > Alberta (1.00)
- North America > United States > Texas > Midland County (0.46)
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- Overview (0.48)
- Research Report > New Finding (0.46)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.30)
- South America > Venezuela > Zulia > Maracaibo Basin > Tia Juana Field (0.99)
- North America > United States > Wyoming > Kiehl Field (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
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Abstract Gas water counter-current matrix-fracture interaction due to capillary forces was studied.The focus was on the rate of capillary imbibition and the development of residual gas phase under low (20 °C) and high temperatures (90 °C).Berea sandstone and Indiana limestone samples with different shape factors were obtained by cutting the plugs 1, 2.5, and 5 cm in diameter and 2.5, 5, and 10 cm in length.All sides were coated with epoxy except one end. Static imbibition experiments were conducted on vertically and horizontally situated samples where the matrix-fracture interaction took place upward and lateral directions, respectively.The effects of the matrix shape factor, wettability, surface tension, and core position on the recovery rate and ultimate recovery were investigated. The experimental scheme followed was useful in identification of the development of residual gas saturation for fully counter-current matrix-fracture interaction.We investigated and clarified to what degrees the rock/fluid properties (wettability and matrix shape factor) and existing conditions (temperature, causing lowered IFT and brine viscosity, and gravity) become effective on the residual gas saturation.It was observed that the residual gas saturation is sensitive to the matrix shape factor.The effect of surface tension on the recovery rate and ultimate recovery was also critical.The vertical cases yielded different recovery rates and ultimate recoveries with increasing temperature. Lower residual gas saturation with increasing temperature was obtained only for large diameters.That was attributed to the reduction in surface tension. Finally, critical matrix and fluid properties were correlated to the residual gas saturation and different dimensionless groups were tested for scaling. Introduction Liquid-gas interaction between matrix and fracture driven by capillary or gravity forces is commonly encountered in naturally fractured gas and geothermal reservoirs.Mechanism is counter-current, i.e., displacement of non-wetting gas phase by wetting liquid phase (water) takes place from the same side of the matrix if the boundary conditions physically restricting the contact of wetting phase with matrix from other sides exist.Understanding the dynamics of counter-current imbibition is crucial to cure recovery problems in gas and geothermal reservoirs. Recovery rate and the development of residual gas phase saturation are two critical issues that need to be focused on.Development of residual gas (non-wetting phase) saturation at ambient conditions has been investigated in the past for spontaneous (capillary) imbibition[1–7].Although different water-gas contact scenarios causing co-or counter-current imbibition transfer were tested, these studies used cores without any coating, i.e., all sides are open to flow.Counter-current imbibition of liquid-liquid systems was studied in comparison to the other types of interactions[8–13].It is highly expected that the capillary imbibition of gas-liquid systems differs from that of liquid-liquid systems, especially for counter-current imbibition.Hatiboglu and Babadagli[14] recently reported that the residual non-wetting phase saturation in gas-liquid systems is highly dependent on the boundary condition at ambient conditions if the interaction is counter-current.Although the mobility ratio and wettability are more favorable in gas-liquid systems, high surface tension may cause the entrapment of non-wetting phase gas phase.This is more prominent in case of counter-current flow of gas-liquid systems as the boundary effects also play a significant role in the development of residual non-wetting phase compared to the liquid-liquid interactions.Pore structure is expected to be critical as shown by Suzanne et al.[15] for viscous displacement as well as the matrix boundary condition for the displacement due to capillary imbibition[14]. The matrix boundary conditions (can also be described as the matrix shape factor) can be a critical parameter on the residual non-wetting phase saturation in case of counter-current imbibition.Zhou et al.[10] discussed this for oil-water systems.They observed that the residual oil distribution is more sensitive to local heterogeneity in case of counter-current imbibition and a frontal displacement of air by water in diatomite samples is obtained due to capillary imbibition.They also reported that the counter-current imbibition initially yields a higher recovery rate than co-current but the residual oil saturation is 20% less than that of co-current.
- North America > United States > Indiana (0.29)
- North America > United States > West Virginia (0.27)
- North America > United States > Pennsylvania (0.27)
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- North America > United States > West Virginia > Appalachian Basin > Berea Sandstone Formation (0.89)
- North America > United States > Pennsylvania > Appalachian Basin > Berea Sandstone Formation (0.89)
- North America > United States > Ohio > Appalachian Basin > Berea Sandstone Formation (0.89)
- (2 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Reduction of residual oil saturation (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (0.68)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (0.68)