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Collaborating Authors
Reservoir Description and Dynamics
Abstract Shale gas reservoir developments have steadily increased over the past few years throughout North America. A significant amount of the produced gas in shales is stored in complex submicron pore structures. The absence of an intensive hydraulic flow unit (HFU) model for these shale gas source rocks makes the prediction of economic gas productivity and hydraulic fracturing risky. Therefore, understanding of pore size distribution, permeability, pore connectivity, and other petrophysical properties is crucial for accurate performance prediction and effective reservoir management. This study utilizes the dualbeam (SEM-FIB) instrument for shale gas tomography. The reconstructed 3D sub-micron pore model provides insights into the petrophysical properties of shale gas, including pore size distribution and porosity. These properties were used to define the shale gas hydraulic unit and permeability. The identified flow units were able to fit into existing flow unit models for unconventional reservoirs. The comparison between the proposed method and mercury injection capillary measurements (MICP) revealed similar data range however MICP method tends to slightly overestimate the flow unit. Flow simulation based on 3D Stokes equation using image segmentation was performed and consistent permeability value was found compared to the estimation in SEM-FIB tomography. However, the permeability simulation results tend to underestimate the permeability value in reality. A case example from Utica shale illustrated the use of this approach.
- North America > United States > Texas (1.00)
- North America > Canada > Quebec (1.00)
- North America > United States > Pennsylvania (0.93)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Wyoming > Powder River Basin > Hartzog Draw Field > Shannon Formation (0.99)
- North America > United States > Wyoming > Powder River Basin > Hartzog Draw Field > Cody Formation (0.99)
- North America > United States > West Virginia > Appalachian Basin > Utica Shale Formation (0.99)
- (15 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Abstract Manipulating the injected brine composition can favorably alter the reservoir wetting state; this hypothesis has been validated in sandstone reservoirs by several scientists. A total of214 coreflooding experiments were conducted to evaluate low salinity waterflooding (LSWF) secondary recovery and 188 experiments were conducted to evaluate tertiary recovery, for sandstone reservoirs. Although the incremental recovery potential in carbonate reservoirs is greater than in sandstones, only a few imbibition and coreflooding experiments have been conducted. The simulator and recovery mechanisms presented by Aladasani et al. (2012) are used and their suitability and validity to low salinity waterflooding in carbonate reservoirs has been confirmed. This has been achieved by comparing simulated LSWF secondary and tertiary recoveries with published coreflooding experiments. Furthermore, the prediction profiler in JMP was used to examine incremental recovery for the following variables: (a) acid number and interfacial tension (IFT) sensitivities, and (b) 2 stage injected brine and 3 stage injected brine anion contents. In weak water-wet conditions, the incremental recovery is driven by low capillary pressures, and the underlining recovery mechanism is the increase in oil relative permeability. Therefore, wettability modification is ideal when achieved by shifting the wetting state from oil-wet or water-wet to a maintained intermediate wetting condition irrespective of the injected brine salinity dilution. If the wettability is shifted to a strong water-wet system, then it would be more favorable to use brine with anions to shift the wettability back to an intermediate wetting state. IFT has a bigger impact on LSWF in carbonate reservoirs; however, contact angle is more significant to the final oil recovery. Future work should consider studying the impact of cationic and anionic ions on coreflooding recovery separately and using cores with different initial wetting states, preferably strong oil-wet cores.
- Asia > Middle East (1.00)
- North America > United States > Texas (0.28)
- North America > Canada > Alberta (0.28)
Abstract Numerous core-flooding experiments have shown that Low-Salinity Water Flooding (LSWF) could improve oil recovery in sandstone reservoirs. However, LSWF recovery mechanisms remain highly contentious primarily because of the absence of crucial boundary conditions. The objective of this paper is to conduct a parametric study using statistical analysis and simulation to measure the sensitivities of LSWF recovery mechanisms in sandstone reservoirs. The summary of 411 coreflooding experiments discussed in this paper highlights the extent and consistency in reporting boundary conditions, which has two implications for statistical analysis: (1) Even though statistical correlations of the residual oil saturation to chlorite (0.7891) and kaolinite (0.4399) contents, as well as the wettability index (0.3890), are comparably strong, the majority of dataset entries are missing, and a prediction model cannot be generated; (2) If a prediction model is generated without clay content values and a wettability index, even though LSWF emphasizes wettability modification by virtue of oil aging time and the strong influence of brine cation and divalent ion concentrations on Sor, the prediction model's regression curve and confidence level are poor. Reservoir simulations conducted to examine LSWF recovery sensitivities conclude that LSWF recovery mechanisms are governed based on the initial and final wetting states. In strong water-wet conditions, the increase in oil relative permeability is the underlying recovery mechanism. In weak water-wet conditions, the incremental recovery of LSWF is driven by low capillary pressures. In weak oil-wet conditions, the primary LSWF recovery mechanism is the increase in oil relative permeability, and the secondary mechanism is the change of the non-wetting phase to oil. In strong oil-wet conditions, the underlining LSWF recovery mechanism is the increase in oil relative permeability. In all cases, an appreciable decrease in interfacial tension (IFT) is realized at the breakthrough recovery however that is rapidly overshadowed by the increase in oil relative permeability and decrease in contact angle.
- Europe (1.00)
- Asia > Middle East (1.00)
- North America > United States > Texas (0.68)
- North America > United States > California (0.68)
- North America > United States > Alaska > North Slope Basin > Duck Island Field > Endicott Field > Kekiktuk Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > South Viking Graben > PL 102 > Block 25/5 > NOAKA Project > Frøy Field > Brent Group Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > South Viking Graben > PL 102 > Block 25/2 > NOAKA Project > Frøy Field > Brent Group Formation (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
Abstract The use of miscible carbon dioxide (CO2) flooding has increased significantly in the past decade. What makes CO2 unique is its low miscibility pressure, which extends the candidacy of CO2 to reservoirs with lower API gravity, shallower depths and lower fracture pressure gradients compared to reservoirs in which miscible nitrogen or miscible hydrocarbon flooding might be used. Furthermore, the financial incentives associated with the removal of a greenhouse gas offset development costs and operating expenditures. Therefore, this paper focuses primarily on selection criteria for CO2 Enhanced Oil Recovery (EOR) and the dispersion modeling of high-pressure CO2 release, as these are critical in offsetting capital investments and managing legal liabilities. The available EOR selection criteria, which are based on reported EOR projects were developed initially by Taber in 1983 and then updated by Taber et al. in 1996 and again by Aladasani & Bai in 2010. Recent publications by Aladasani & Bai (2011) regarding discussions surrounding EOR selection criteria focus on dataset distribution to refine EOR candidacy selection. The work presented in this paper further develops the tools with which to screen miscible CO2 for EOR applications by offering detailed distributions and correlations of reservoir properties reported in miscible CO2 projects, as well as a prediction model for miscible CO2 recovery. The screening tools presented in this paper are intended as a new detailed and systematic approach to selecting miscible CO2 flooding and to developing EOR as a whole. The increase in Carbon Sequestration Projects (CSP) and CO2 EOR projects has resulted in the expansion of the CO2 pipeline network in the United States (US). An overview of the CO2 network in the US, the transit pipeline incident history in North America and Europe, and the scope of pipeline risk studies are presented. Finally, recent developments in CO2 consequence modeling inform the dispersion modeling of critical CO2 releases, highlighting the toxicity risk of H2S in anthropogenic CO2 streams.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
Technology Focus In spite of continued investment and advances in exploiting alternative-energy sources, oil and natural gas will continue to be a significant portion of US and global energy portfolios for decades. Enhanced oil recovery (EOR) uses unconventional hydrocarbon-recovery methods that target the approximately two-thirds of the oil volume remaining in reservoirs after conventional-recovery methods have been exhausted. Though limited by high capital and operating costs, EOR techniques will have a substantial effect on the future supply of oil. In 2011, SPE hosted an EOR conference in Kuala Lumpur, and three workshops to address EOR technologies in Malaysia, Kuwait, and the Syrian Arab Republic. The Malaysia workshop focused on chemical-EOR methods, the Kuwait workshop addressed opportunities and for challenges of EOR methods in the Middle East, and the Syrian Arab Republic workshop discussed EOR in carbonate reservoirs. More than 300 EOR papers were published in SPE conferences, with many additional presentations in EOR workshops. These papers address important issues related to practical application of conventional EOR methods and the development of novel EOR technologies. The topics cover experience with, opportunities for, and challenges of EOR technologies; fundamental study of EOR mechanisms for different methods; feasibility study and improvement of an EOR method for a specific reservoir; EOR-screening criteria; reservoir surveillance, monitoring, and evaluation technologies; reservoir simulation and modeling; lessons learned from EOR pilot and field trials; and some novel EOR methods. Polymer flooding has been proved the most cost-effective chemical-EOR method in the laboratory and in the field. A recent focus on polymer flooding evaluated associative polymers because of their advantage over traditional hydrolyzed polyacrylamide (HPAM) polymers; thus, one paper about comparing the flow behavior of associative polymer and HPAM in porous media was selected for this feature. CO2 injection is a win/win strategy because it can enhance oil recovery and be used for CO2 storage in reservoirs to reduce greenhouse-gas levels in the atmosphere. However, CO2 EOR targets maximum oil recovery while CO2 sequestration targets maximum storage capacity without leakage. One paper featured here provides some guidance to balance the two technologies. Steamflooding has been applied successfully in heavy-oil reservoirs. However, one paper synopsized in this feature will describe successful steamflooding in a light-oil reservoir. Recommended additional reading at OnePetro: www.onepetro.org. SPE 142668 Enhanced Waterflood for Middle East Carbonate Cores—Impact of Injection-Water Composition. By Robin Gupta, ExxonMobil Upstream Research, et al. SPE 142105 A Simplified Model for Simulations of Alkaline/Surfactant/Polymer Floods. By Mojdeh Delshad, SPE, University of Texas at Austin, et al. SPE 144294 Large-Scale High-Viscous-Elastic-Fluid Flooding in the Field Achieves High Recoveries. By Wang Demin, SPE, Daqing Oil Company, et al. \ SPE 144599 A Combined Experimental and Simulation Workflow To Improve Predictability of In-Situ Combustion. By M. Bazargan, Stanford University, et al. SPE 147858 In-situ Combustion Using Sugar Dust, ‘Sweet Reservoirs’—A Smart and Better Alternative by Panchamlal, SPE, Maharashtra Institute of Technology, et al. SPE 147999 Lessons Learned From Nine Years of Immiscible-Gas-Injection Performance and Sector-Modeling Study of Two Pilots in a Heterogeneous Carbonate Reservoir by Lakshi Konwar, SPE, Zakum Development Company, et al.
- Asia > Middle East > Syria (0.47)
- Asia > Middle East > Kuwait (0.47)
- North America > United States > Texas > Travis County > Austin (0.26)
- (2 more...)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.57)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.57)