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Petroleum Engineering, University of Houston, 2. Metarock Laboratories, 3. Department of Earth and Atmospheric Sciences, University of Houston) 16:00-16:30 Break and Walk to Bizzell Museum 16:30-17:30 Tour: History of Science Collections, Bizzell Memorial Library, The University of Oklahoma 17:30-19:00 Networking Reception: Thurman J. White Forum Building
- Research Report > New Finding (0.93)
- Overview (0.68)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Mineral (0.72)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.68)
- (2 more...)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.93)
- North America > United States > Texas (1.00)
- Europe (0.93)
- Research Report > New Finding (0.93)
- Overview (0.88)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.47)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.93)
Abstract The Goldsmith-Landreth San Andres Unit (GLSAU) in the Permian Basin has been under waterflood since 1963, and CO2 WAG flood since 2009. In January 2020, the asset team initiated a flood management workflow using a numerical Streamline Surveillance (SLSV) model approach. Starting in March 2020, because of the oil price collapse due to the pandemic, only produced CO2 was reinjected (harvest operation). Reduced availability of CO2 led to the field-wide voidage replacement ratio (VRR) declining and injectors unable to maintain their pre-harvesting CO2 rates. The approach described in this work outlines how SLSV was used to prioritize CO2 usage in the water-alternating-gas (WAG) scheduling process and to manage water and CO2 injection rate targets to improve the effectiveness of CO2 and minimize oil decline despite the reduction in VRR. Before using SLSV, injection targets were calculated assuming fixed geometric (FG) defined injection patterns and a per pattern processing rate of 10% to 15% HCPV/Yr. The WAG scheduling was then derived from the total injection volume by using a predetermined number of days of water and CO2 injection. In this work, we describe a novel WAG management approach by including injector efficiencies (offset oil produced per volume of fluid injected) computed from an SLSV model able to quantify injector-producer relationships. Fifty-three injectors were included in the Area of Interest (AOI) as candidates for new rate targets. The estimated incremental tertiary oil recovery on January 2020 was 3.9% at a CO2 maturity of 53.3%, slightly above the target defined by the field prototype curve. After applying SLSV as of this writing, incremental tertiary oil recovery is 4.9% at a CO2 maturity of 58.5%. Using the SLSV model, injection rates were increased or decreased depending on the efficiency of each injector-producer pair and additionally constrained by surface facility limits, the availability of CO2 volume to inject, and individual well injectivities. The injection rate target calculations were repeated in March and August of 2020, in January and August of 2021, and in January and June of 2022 using the latest measured well responses as a starting point. Due to the limited volume of CO2 available for re-injection with the start of harvest operation, all injectors that were scheduled to be switched to CO2 cycle (based on the water injection time and designed WAG ratios) were prioritized using injector efficiencies calculated by the SLSV model. The higher an injector efficiency, the higher the probability that a well would be switched to a CO2 cycle. Incremental oil recovery has outperformed the field's prototype for the given CO2 maturity using the SLSV approach. Across the 53 sets of injector rate targets, some injectors had rate increases up to 25%, while other injectors had rate decreases of 25%. During this same period of incremental oil response, overall CO2 injection volumes were reduced from 40.5 MMscf/d to 11.6 MMscf/d (a 71% decrease), water injection volumes were reduced from 38,400 stb/d to 26,400 stb/d (a 31% decrease), and total produced voidage rates dropped from 60,000 rb/d to 33,000 rb/d (a 45% decrease). GLSAU went from an established VRR > 1 (~1.09) before March 2020 to a constant VRR of 0.98 after March 2020 due to CO2 harvesting, yet oil recovery improved.
- North America > United States > Texas (1.00)
- Europe (1.00)
- North America > United States > Alaska > North Slope Borough (0.28)
- Phanerozoic > Paleozoic > Permian (0.68)
- Phanerozoic > Cenozoic > Tertiary (0.54)
- 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)
- (25 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Miscible methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Experimental Study of Surfactant Flooding on Organic Shale with Integrated Characterization
Jiang, T. | El-Sobky, H. F. (ConocoPhillips) | Bonnie, R. J. M. (ConocoPhillips) | Bone, R. (ConocoPhillips) | Beveridge, W. (ConocoPhillips) | Carman, P. S. (ConocoPhillips) | Jweda, J. (ConocoPhillips) | Long, H. (ConocoPhillips) | MacMillan, A. (ConocoPhillips) | Nguyen, V. H. (ConocoPhillips) | Warren, L. (ConocoPhillips) | McLin, K. S. (ConocoPhillips)
Abstract Enhanced oil recovery from organic shale reservoirs has increasingly gained interest from oil and gas industry in recent years. The recovery factor of organic shale oil production depends on formation wettability and pore fluid trapping mechanisms. A combination of hydraulic fracturing and surfactant flooding can be used to reduce oil trapping and increase oil recovery by reducing the interfacial tension and decreasing oil wettability. A novel experimental workflow has been developed based on fluid flow monitoring and NMR characterization to study the effect of surfactant flooding on organic-rich shales in the lab. Two blends of surfactants (cationic and nonionic) were carefully selected from prior contact angle (CA) and interfacial tension (IFT) measurements for the surfactant flooding tests. Micro-CT screening was used to select fracture-free samples for these tests. Prior to flooding we acquired nuclear magnetic resonance (NMR) T1-T2 measurements on as-received core samples to establish base-line water and oil saturations. Next, the core samples were pressure-saturated with crude oil at reservoir pressure and temperature, and we continued the aging process for a given time. Following aging, core samples were flooded using continuous crude oil injection from one end of the core sample whilst monitoring fluid flow rate, temperature, and pressure. Robust initial effective oil permeability was computed when the flow system reached steady state. Next, fracturing fluids -with and without surfactants- were injected from the opposite end of the core plugs to simulate the forced imbibition of fracturing fluid along with hydraulic fracturing in real field operations. Finally, the injection of crude oil was resumed from the original end of the core sample to establish the flowback effective oil permeability after hydraulic fracturing and surfactant flooding. We acquired NMR data after each fluid injection step to monitor fluid saturation and wettability changes in the core samples. Additionally, porosity and saturation measurements, X-ray diffraction (XRD), rock-eval pyrolysis and mercury injection capillary pressure (MICP) tests are performed to characterize fluid distribution, mineralogy and pore throat sizes of the rock samples. The results of fracturing fluid injection in all core samples clearly indicate that the water from the fracturing fluid does partially displace the crude oil in the core, effectively making this oil recoverable. Samples injected with the blend of cationic surfactants show less than 3% incremental recovery over samples with no surfactant injection. The flowback effective oil permeabilities of all core samples are much lower than the initial effective oil permeabilities prior to fracturing fluid injection. This observation is corroborated by the differences in MICP results before and after fracturing fluid injection, showing smaller pore throat sizes after fracturing fluid injection. Our novel workflow has successfully characterized the impact of surfactant flooding on organic-rich shale samples in lab-scale tests. and can be used for screening of surfactant enhanced oil recovery before running more expensive field trials.
- North America > United States > Texas (0.46)
- North America > United States > Colorado (0.28)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline (1.00)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (3 more...)
Experimental Study on Supercritical CO2 Enhanced Oil Recovery and its Sequestration Potential with Different injection Modes for Carbonate Oil Reservoirs Under Reservoir Conditions
Zhou, Xianmin (King Fahd University of Petroleum & Minerals, Saudi Arabia) | Yu, Wei (King Fahd University of Petroleum & Minerals, Saudi Arabia) | Elsayed, Mahmoud (King Fahd University of Petroleum & Minerals, Saudi Arabia) | Al-Abdrabalnabi, Ridha (King Fahd University of Petroleum & Minerals, Saudi Arabia) | Wu, Yu-Shu (Colorado School of Mines, Golden Co. U.S.A.) | Khan, Sarmad Zafar (King Fahd University of Petroleum & Minerals, Saudi Arabia) | Kamal, Muhammad Shahzad (King Fahd University of Petroleum & Minerals, Saudi Arabia)
Abstract The release of CO2 into the atmosphere has been verified as a significant reason for global warming and climate change. To prevent a large amount of CO2 from being emitted into the atmosphere, its utilization and storage become very important for human survival. Regarding the utilization of CO2 in oil reservoir engineering practice, CO2 enhanced oil recovery (CO2EOR) as a mature technology has been widely applied in several types of reservoirs, such as sandstone, carbonate, and shale gas/oil reservoirs, and scientists and reservoir engineers aim to improve displacement efficiency with different injection modes and study its influencing factors over the past few decades. However, related to the experimental evaluation of storage capacity potential with the CO2EOR displacement mode and the long-term storage of CO2 in situ in the formation experienced by CO2 flooding is rarely studied experimentally. In this study, we investigated the effect of injection mode and reservoir heterogeneity on CO2EOR and its storage potential. Several core flooding experiments on displacing remaining oil and water by scCO2 after water flooding have been performed, including injection modes, which are horizontal, vertical, and tapered WAG injections, using reservoir carbonate rock, live crude oil, and seawater under reservoir conditions. The dual-core core flooding experiment was used to study the effect of reservoir heterogeneity on scCO2 storage capacity. As a result of this study, the previously proposed experimental methodology was used to calculate the scCO2 storage capacity, which involved that the scCO2 dissolves into residual water and oil after scCO2 injection, and evaluate the CO2 storage capacity efficiency for different injection modes. The vertical-continuous injection mode of scCO2 flooding can maximize the process of its storage advantage. This study found that the main scCO2 storage mechanism is mainly pore storage (structural trapping) for depleted oil reservoirs. Based on experimental results, the storage efficiency is related permeability of rocks, which expresses the logarithmic relation and increases with an increase in air permeability. The experimental results show that the scCO2 injectivity is not strongly affected, although the relative permeability to scCO2 decreased somewhat after the scCO2EOR process. In addition, the effect of rock heterogeneity on scCO2 storage efficiency is also discussed. The highlights of this study are that the comparison of the scCO2 storage potential was made based on experimental results of different injection modes, and improving the displacement efficiency in the low permeable zone also increases scCO2 storage efficiency. Furthermore, the experimental results can be applied directly to be helpful for the evaluation and strategy of scCO2 storage and can be used to simulate the performance during the injection process of scCO2 storage.
- Europe (1.00)
- Asia > Middle East (0.93)
- North America > United States > Texas > Ward County (0.28)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.34)
- North America > United States > Texas > Permian Basin > North Ward Estes Field (0.99)
- North America > United States > Texas > Permian Basin > NW Shelf Basin > Word Group > San Andreas Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 046 > Utsira Formation (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (7 more...)
Experimental Investigation and Modeling of a Nanoparticle-Based Foam: Core Scale Performance for Enhanced Oil Recovery
Ahmadi, Khashayar (Memorial University) | Akrong, Dorcas Annung (Memorial University) | Sripal, Edison Amirtharaj (Memorial University) | Sahari Moghaddam, Farzan (Memorial University) | Ovwigho, Ejiro Kenneth (Memorial University) | Esene, Cleverson (Memorial University) | Machale, Jinesh (Memorial University) | Telmadarreie, Ali (CNERGREEN) | James, Lesley Anne (Memorial University)
Abstract Nanoparticle-based foam shows promise to enhance oil recovery; however, there is limited experimental investigation on the influence of injection sequence on recovery. The objective of the present study is to systematically compare the injection sequence of SiO2 nanoparticle-based foam, viz, brine-gas-foam-gas (N2) and brine-foam-brine, using core flooding experimental and simulation analyses. Relative permeability endpoints and Corey exponents are found by history matching the experimental production data using a commercial software. To match foam parameters and assess recovery considering underlying physics a software was used. Three coreflooding experiments using a novel nanoparticle-based foam were conducted on two unaged and one aged sandstone cores to investigate two injection sequences (i.e., water (brine)-gas-foam-gas and water-foam-water) at reservoir conditions. The stability and solubility of the nanofoam were studied in high-pressure and high-temperature interfacial tension experiments. Experimental results indicate that the water (brine)-gas-foam-gas sequence results in higher recovery at core scale with a 13.2% increase in recovery after foam injection and total recovery of 80.2% after respective injections of 2.0, 1.8, 1.2 and 0.5 PV of water-gas-foam-gas. The water-foam-water sequence results in a 4.4% increase in recovery after foam injection and total recovery of 61.6% after respective injections of 0.9, 2.9 and 2 PVs in water-wet core and a 6.6% increase after foam injection and total recovery of 73.3% after respective injections of 1.2, 0.6, and 0.6 PV (brine-foam-brine) in an oil-wet core. Increased oil recovery in all experiments ranged from 6.6 to 30.6%. Unlike previous studies, we investigate different nanofoam injection sequences in different wetting condition (aged/unaged cores). A limited number of studies for nanofoam on highly permeable sandstones (500โ750 mD) have been reported. Results of this study show that the generated nanoparticle-based foam can be used to favorably control mobility and enhance oil recovery. The numerical simulation efforts led to several critical learnings on the physics of incremental oil recovery from dry-out effects of the foam, as well as the limitations of current commercial simulators in properly replicating the entire physics.
- North America > Canada (0.68)
- North America > United States > Texas (0.46)
- 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)
- (21 more...)
A Look Ahead to the Future of Surfactant Flooding EOR in Carbonate Reservoirs under Harsh Conditions of High Temperature and High Salinity
Adel, Imad A. (Khalifa University of Science and Technology, UAE) | Hassan, Anas Mohammed (Khalifa University of Science and Technology, UAE) | Al-Shalabi, Emad W. (Khalifa University of Science and Technology, UAE) | AlAmeri, Waleed (Khalifa University of Science and Technology, UAE)
Abstract Carbonate reservoirs under harsh conditions of high temperature and high salinity (HTHS) have been exploited through primary and secondary recovery methods. This leaves substantial untapped reserves that require the use of enhanced oil recovery (EOR) techniques. Chemical EOR (CEOR) applications, particularly surfactants, in improving recovery under these HTHS conditions are challenging. Developing suitable surfactants that withstand these conditions can improve water imbibition into the low permeability rock matrix, alter the rock wettability, and significantly lower the interfacial tension. The assessment and evaluation of potential surfactants as EOR agents is of great interest and has a strategic role in unlocking further reserves from the vast accumulations of light oil in low permeability carbonates. However, the implementation of surfactants under these conditions faces various challenges, such as stability, compatibility, and high retention values, which need to be overcome for successful applications. This paper provides comparative review analyses and critical discussions on the recent developments to overcome these obstacles and the promising potential for successful surfactant flooding implementations in carbonates. Surfactant selection is a complicated process, where the surfactant formulation needs to pass several screening techniques. In this paper, limitations, requirements, and aspects affecting the IFT, microemulsion phase behavior, and retention were thoroughly reviewed. Surfactant retention remains the primary factor limiting the implementation of surfactants in carbonate reservoirs under harsh conditions. Nevertheless, recent laboratory studies (screening and corefloods) showed that chemical formulations, including new classes of surfactants with suitable solvents and alkalis, showed excellent performance with minimal retention values under these conditions. Field studies and pilots of surfactant EOR in carbonate reservoirs were also reviewed, highlighting procedures, achievements, challenges, and the way forward to successful applications. A list of recommendations and conclusions is provided at the end of the study based on the literature and our expertise in this area. Surfactant EOR has long been considered impractical in the high temperature and high salinity conditions present in carbonate reservoirs. This study reviews the latest developments and positive outcomes that change this perception and aid in unlocking these reserves. The study is also considered a guide to starting surfactant flooding projects in carbonates under harsh conditions in the Middle East region and elsewhere.
- North America > United States > Texas (0.93)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.16)
- Overview (0.86)
- Research Report > New Finding (0.46)
- Geology > Rock Type > Sedimentary Rock (1.00)
- Geology > Mineral (0.94)
- Geology > Geological Subdiscipline (0.69)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Dynamic Characteristics of Supercritical CO2 Injection in Depleted Carbonate Oil Reservoir for its Sequestration Potential: An Experimental Study
Zhou, Xianmin (King Fahd University of Petroleum & Minerals, Saudi Arabia) | Yu, Wei (King Fahd University of Petroleum & Minerals, Saudi Arabia) | Wu, Yu-shu (Colorado School of Mines, Golden Co. U.S.A.) | Al-Abdrabalnabi, Ridha (King Fahd University of Petroleum & Minerals, Saudi Arabia) | Khan, Sarmad Zafar (King Fahd University of Petroleum & Minerals, Saudi Arabia) | Kamal, Muhammad Shahzad (King Fahd University of Petroleum & Minerals, Saudi Arabia) | Elsayed, Mahmoud (King Fahd University of Petroleum & Minerals, Saudi Arabia)
Abstract To reduce the amount of CO2 in the atmosphere and mitigate the severe consequences of climate change, capturing, utilizing, and storing CO2 has become very important for human survival. For utilization of CO2 in reservoir engineering practice, CO2-enhanced oil recovery (CO2EOR) as a mature technology has been widely applied in several types of reservoirs such as sandstone, carbonate, and shale gas/oil reservoirs, and the focus of concern is to study oil recovery efficiency and its influencing factors over the past few decades. Recently, more and more researchers are paying great attention to the geological storage of carbon dioxide in depleted oil reservoirs where scCO2 is injected as a displacing agent for secondary and tertiary oil recovery. Unfortunately, there is a lack of laboratory research on scCO2 sequestration in such reservoirs in terms of capacity, two-phase flow (the mixture of scCO2 and residual oil and water), injectivity of scCO2, and permeability loss of rocks. In this study, we evaluate the dynamic characteristics mentioned above subjective is based on laboratory results. Several experiments, including different injection modes such as horizontal and vertical injections, and their effects on displacing residual oil and water by scCO2 after water flooding has been performed using reservoir carbonate rock, live crude oil, and seawater under reservoir conditions. As a result of this study, the experimental methodology to obtain the scCO2 storage capacity of the depleted oil reservoir was proposed for the first time, and the calculation of scCO2 storage capacity assumes that the scCO2 dissolves into residual water and oil after scCO2 injection. This study found that the main scCO2 storage mechanism is pore space storage (structural trapping) for depleted oil reservoirs. Based on experimental results, the storage efficiency is found to be closely related to the permeability of rocks. In addition, the scCO2 injectivity and permeability loss of the rock were evaluated for a depleted carbonate reservoir, which was displaced by scCO2 injection at the final stage of the oil recovery process. The experimental results show that the scCO2 injectivity is not strongly affected, although the relative permeability to scCO2 slightly decreased after the scCO2EOR process. The experimental results can be applied directly for the evaluation and strategy of scCO2 storage and can be used to simulate the performance of the injection process of scCO2 storage.
- Europe (1.00)
- Asia > Middle East (1.00)
- Africa (0.67)
- North America > United States > Texas > Ward County (0.28)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Geology > Rock Type > Sedimentary Rock (0.89)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- 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)
- (25 more...)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- (3 more...)
Long-Term Microbial DNA-Based Monitoring of the Mature Sarukawa Oil Field in Japan
Kobayashi, H. (The University of Tokyo (Corresponding author)) | Goto, A. (Japan Petroleum Exploration Co., Ltd. (JAPEX)) | Feng, X. (The University of Tokyo) | Uruma, K. (The University of Tokyo) | Momoi, Y. (The University of Tokyo) | Watanabe, S. (The University of Tokyo) | Sato, K. (The University of Tokyo) | Zhang, Y. (Tsinghua University) | Horne, R. N. (Stanford University) | Shibuya, T. (Japan Petroleum Exploration Co., Ltd. (JAPEX)) | Okano, Y. (Japan Petroleum Exploration Co., Ltd. (JAPEX))
Summary Microbial DNAbased monitoring is a promising tool for reservoir monitoring that has been used mainly for shale reservoir development. In this study, long-term microbial DNAbased monitoring was applied to the Sarukawa oil field, which has a complex reservoir structure with no practical simulation model available. Fluid samples were collected periodically from nine production wells and two injection wells from October 2019 to July 2021. DNA was extracted from the samples, and the microbial composition was analyzed by 16S ribosomal ribonucleic acid (rRNA) gene amplicon sequencing and real-time polymerase chain reaction (PCR). Based on similarities between the microbial profiles, the samples were classified into seven clusters that corresponded closely to the original fluid type (i.e., injection or production fluid) and specific environment (e.g., geological strata or compartments). A comparative analysis of the microbial profiles suggested possible well connectivity and water breakthrough. These results demonstrate that microbial DNAbased monitoring can provide useful information for optimizing production processes (e.g., waterflooding) in mature oil fields. Introduction In oil and gas production, reservoir monitoring is vital to understanding the subsurface structures, geological conditions, and fluid flow for optimizing the field productivity. Recently, microbial community analysis has been applied to reservoir monitoring, in which microbes present in the subsurface environment and/or injection fluid are used as markers and/or tracers to gather information on the subsurface environment and to track fluid flow in the reservoir (Tayyib et al. 2019; Zhang et al. 2019). In particular, microbial DNA extracted from the formation water, crude oil, drill cuttings, and injection fluid is assessed by comprehensive amplicon sequencing, most often the 16S rRNA gene as a phylogenetic marker.
- North America > United States > Texas (0.93)
- Asia > Japan > Honshu Island > Akita Prefecture (0.72)
- 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)
- (25 more...)
Coreflood Tests to Evaluate Enhanced Oil Recovery Potential of Wettability-Altering Surfactants for Oil-Wet Heterogeneous Carbonate Reservoirs
Shi, Yue (The University of Texas at Austin) | Mohanty, Kishore (The University of Texas at Austin (Corresponding author)) | Panda, Manmath (Kinder Morgan Inc)
Summary Oil-wetness and heterogeneity are two main factors that result in low oil recovery (OR) by waterflood in carbonate reservoirs. The injected water is likely to flow through high-permeability regions and bypass the oil in the low-permeability matrix. In this study, systematic coreflood tests were carried out in both "homogeneous" cores and "heterogeneous" cores with a wettability-altering surfactant. The homogeneous coreflood tests were conducted to evaluate surfactant retention, as well as to compare tertiary surfactant flooding with secondary surfactant flooding. The heterogeneous coreflood test was proposed to model bypassing in low-permeability matrix during waterfloods, and dynamic imbibition of surfactant into the low-permeability matrix. Surfactant retention results suggest that retention increases as initial oil saturation decreases. The retention of selected surfactant in the target reservoir cores was measured to be within a range of 0.07-0.12 The results of homogeneous coreflood tests showed that both secondary waterflood and secondary surfactant flood can achieve high OR ( 50%) from relatively homogeneous oil-wet cores. A shut-in phase after the surfactant injection resulted in a surge in oil production, which suggests that enough time should be given for wettability alteration by surfactants. The results of heterogeneous coreflood tests showed that more oil is bypassed in the tighter matrix by waterflood if the permeability is higher in the flooded layer and this bypassed oil is the target for the wettability-altering surfactant floods. Slow wettability-altering surfactant injection leads to imbibition into bypassed regions. When the oil-wet carbonate reservoirs have large unswept regions after waterflood, wettability-altering surfactants can significantly improve OR if enough time is given for imbibition. Introduction Carbonate reservoirs tend to be oil-wet/mixed-wet due to positively charged rock surface and negatively charged acidic and/or asphaltic components from crude oil.
- North America > United States > Texas (1.00)
- Asia > Middle East (0.93)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.47)
- Geology > Mineral > Silicate > Phyllosilicate (0.46)
- North America > United States > Texas > Permian Basin > Central Basin > Seminole Field > Word Group > San Andres Formation (0.99)
- North America > United States > Texas > Permian Basin > Central Basin > Seminole Field > Wolfcamp Reef Formation > San Andres Formation (0.99)
- North America > United States > Texas > Permian Basin > Central Basin > Seminole Field > Wolfcamp Lime Formation > San Andres Formation (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)