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Collaborating Authors
Kuwait
A Successful Acid Fracturing Treatment in Asphaltene Problematic Reservoir, Burgan Oilfield Kuwait
Al-Shammari, A. (Kuwait Oil Company, Kuwait) | Sinha, S. (Kuwait Oil Company, Kuwait) | Sheikh, B. (NAPESCO, Kuwait) | Youssef, A. (NAPESCO, Kuwait) | Jimenez, C. (Kuwait Oil Company, Kuwait) | Al-Mahmeed, F. (Kuwait Oil Company, Kuwait) | Al-Shamali, A. (Kuwait Oil Company, Kuwait)
Abstract The Burgan Marrat Reservoir is a challenging high-pressure, high-temperature carbonate oil reservoir dating back to the Jurassic age. This specific reservoir within the Burgan Field yields light oil, but it has a significant issue with Asphaltene deposition in the wellbore. Additionally, its well productivity is hampered by low matrix permeability. Addressing these challenges is crucial, and a successful acid fracturing process can not only enhance well productivity but also address Asphaltene-related problems. This study delves into a comprehensive methodology that was employed. The focus of well selection was on ensuring good well integrity and maintaining a considerable distance from the oil-water contact (OWC). The approach involved conducting a Multi-Rate test followed by pressure build-up to establish a baseline for understanding the reservoir's behavior, including darcy and non-darcy skin. The treatment design aimed at better fluid loss control and initiating highly conductive fractures in the reservoir. Specific measures, such as using suitable diverters and acid, were employed to maximize the length of the fractures. To validate the approach, a nodal analysis model was fine-tuned to predict how the well would perform under these conditions. The results post-stimulation were impressive. There was a substantial improvement in well production and flowing bottom hole pressure. In fact, the productivity index of the well increased significantly, representing a substantial enhancement in output. The pressure build-up test after the fracture demonstrated a linear flow within the fracture, indicating a successful treatment with a fracture half-length of approximately 110 feet and a negative skin, which signifies an improvement in flow efficiency. Furthermore, the treatment effectively mitigated the risk associated with Asphaltene deposition, a significant accomplishment given the historical challenges faced in this reservoir. This success can be attributed to an innovative workflow that incorporated a meticulous surveillance plan, a well-thought-out fracturing treatment design, and the application of advanced nodal analysis. Together, these components not only optimized the well's performance but also paved the way for the development of similar high-pressure, tight carbonate reservoirs. This approach not only enhances productivity but also ensures successful mitigation of Asphaltene-related issues, marking a significant advancement in reservoir engineering techniques.
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Wara Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Ratawi Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Mauddud Formation (0.99)
- (15 more...)
Shallow-water carbonate structures are characterized by different shapes, sizes and identifying features, which depend, among other factors, on the age of deposition and on the carbonate factory associated with a specific geologic period. These variations have a significant impact on the imaging of these structures in reflection seismic data. This study aims at providing an overall, albeit incomplete, picture of how the seismic expression of shallow-water carbonate structures has evolved through deep time. 297 shallow-water carbonate systems of different ages, spanning from Precambrian to present, with a worldwide distribution of 159 sedimentary basins, have been studied. For each epoch, representative seismic examples of shallow-water carbonate structures were described through the assessment of a selection of discriminating seismic criteria, or parameters. The thinnest structures, commonly represented by ramp systems, usually occurred after mass extinction events, and are mainly recognizable in seismic data through prograding clinoform reflectors. The main diagnostic seismic features of most of the thickest structures, which were found to be Precambrian, Late Devonian, Middle-Late Triassic, Middle-Late Jurassic, some Early Cretaceous pre-salt systems, #8220;middle#8221; and Late Cretaceous, Middle-Late Miocene and Plio-Pleistocene, are steep slopes, and reefal facies. Slope-basinal, resedimented seismic facies, were mostly observed in thick, steep-slope platforms, and they are more common, except for megabreccias, in post-Triassic structures. Seismic-scale, early karst-related dissolution features were mostly observed in icehouse, platform deposits. Pinnacle structures and the thickest margin rims are concentrated in a few epochs, such as Middle-Late Silurian, Middle-Late Devonian, earliest Permian, Late Triassic, Late Jurassic, Late Paleocene, Middle-Upper Miocene, and Plio-Pleistocene, which are all characterized by high-efficiency reef builders.
- South America (1.00)
- North America > United States > Texas (1.00)
- North America > Canada (1.00)
- (5 more...)
- Phanerozoic > Paleozoic > Devonian (1.00)
- Phanerozoic > Mesozoic > Triassic (1.00)
- Phanerozoic > Mesozoic > Jurassic (1.00)
- (5 more...)
- Geology > Structural Geology > Tectonics (1.00)
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment > Reef Environment (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- (3 more...)
- Geophysics > Seismic Surveying > Seismic Interpretation (1.00)
- Geophysics > Seismic Surveying > Seismic Processing (0.93)
- Geophysics > Seismic Surveying > Surface Seismic Acquisition (0.67)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.45)
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.45)
- South America > Venezuela > Caribbean Sea > Gulf of Venezuela > Gulf of Venezuela Basin > Cardon IV Block > Perla Field (0.99)
- Oceania > Australia > Western Australia > Western Australia > Timor Sea > Browse Basin (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Timor Sea > Browse Basin (0.99)
- (82 more...)
Lithofacies identification from well-logging curves via integrating prior knowledge into deep learning
Jiang, Chunbi (Southern Institute of Industrial Technology) | Zhang, Dongxiao (Eastern Institute of Technology, Department of Mathematics and Theories, Southern University of Science and Technology)
ABSTRACT Lithofacies is a key parameter in reservoir characterization. With advances in machine learning, many researchers have attempted to predict lithofacies from well-log curves by using a machine-learning algorithm. However, existing models are built purely on data, which do not provide interpretability. In addition, lithofacies distribution is highly imbalanced. We incorporate domain knowledge into a gated recurrent unit network to force the model to learn from the data and knowledge. The domain knowledge that we use is expressed as first-order logic rules and is incorporated into the machine-learning pipeline through additional loss terms. Specifically, these rules are: (1) if the density is smaller than or equal to , then the lithofacies is coal; (2) if the density is larger than or equal to or the neutron porosity is smaller than or equal to , then the lithofacies is anhydrite; and (3) if the gamma-ray value is larger than or equal to , then the lithofacies is shale. Here, , , , and are the parameters that are learned by the model. By applying this domain knowledge, we aim to elucidate why the model predicts lithofacies as coal, anhydrite, or shale and reduce the effect of imbalanced data on the model’s performance. We evaluate the method on a data set from the North Sea, and the machine-learning pipeline with domain knowledge embedded is slightly superior compared with the baseline model that does not consider domain knowledge. One drawback of the method is that the domain knowledge that we provide only works for coal, anhydrite, and shale, which is incomplete. In future work, we will attempt to develop more rules that work for other types of lithofacies.
- Europe > United Kingdom > North Sea (0.49)
- Europe > Norway > North Sea > Central North Sea (0.28)
- Asia > Middle East > Iraq > Basra Governorate > Arabian Basin > Widyan Basin > Mesopotamian Basin > Rumaila Field > Zubair Formation (0.99)
- Asia > Middle East > Iraq > Basra Governorate > Arabian Basin > Widyan Basin > Mesopotamian Basin > Rumaila Field > Shuaiba Formation (0.99)
- Asia > Middle East > Iraq > Basra Governorate > Arabian Basin > Widyan Basin > Mesopotamian Basin > Rumaila Field > Nahr Umr Formation (0.99)
- (2 more...)
Lithofacies identification from well-logging curves via integrating prior knowledge into deep learning
Jiang, Chunbi (Southern Institute of Industrial Technology) | Zhang, Dongxiao (Eastern Institute of Technology, Department of Mathematics and Theories, Southern University of Science and Technology)
ABSTRACT Lithofacies is a key parameter in reservoir characterization. With advances in machine learning, many researchers have attempted to predict lithofacies from well-log curves by using a machine-learning algorithm. However, existing models are built purely on data, which do not provide interpretability. In addition, lithofacies distribution is highly imbalanced. We incorporate domain knowledge into a gated recurrent unit network to force the model to learn from the data and knowledge. The domain knowledge that we use is expressed as first-order logic rules and is incorporated into the machine-learning pipeline through additional loss terms. Specifically, these rules are: (1) if the density is smaller than or equal to , then the lithofacies is coal; (2) if the density is larger than or equal to or the neutron porosity is smaller than or equal to , then the lithofacies is anhydrite; and (3) if the gamma-ray value is larger than or equal to , then the lithofacies is shale. Here, , , , and are the parameters that are learned by the model. By applying this domain knowledge, we aim to elucidate why the model predicts lithofacies as coal, anhydrite, or shale and reduce the effect of imbalanced data on the model’s performance. We evaluate the method on a data set from the North Sea, and the machine-learning pipeline with domain knowledge embedded is slightly superior compared with the baseline model that does not consider domain knowledge. One drawback of the method is that the domain knowledge that we provide only works for coal, anhydrite, and shale, which is incomplete. In future work, we will attempt to develop more rules that work for other types of lithofacies.
- Europe > United Kingdom > North Sea (0.49)
- Europe > Norway > North Sea > Central North Sea (0.28)
- Asia > Middle East > Iraq > Basra Governorate > Arabian Basin > Widyan Basin > Mesopotamian Basin > Rumaila Field > Zubair Formation (0.99)
- Asia > Middle East > Iraq > Basra Governorate > Arabian Basin > Widyan Basin > Mesopotamian Basin > Rumaila Field > Shuaiba Formation (0.99)
- Asia > Middle East > Iraq > Basra Governorate > Arabian Basin > Widyan Basin > Mesopotamian Basin > Rumaila Field > Nahr Umr Formation (0.99)
- (2 more...)
The Lower Saxony Basin is located in the northwestern region of Germany. It is an important petroleum basin for Germany as it provides as a principle oil province. The petroleum production yield for the Lower Saxony Basin is calculated to eighty-five percent of Germany's total oil production [1]. It is characterized by researchers as a sedimentary basin that underwent large tectonic changes including strong inversion and uplift. The first extraction and production of the basin began in 1864 [2].
- Phanerozoic > Mesozoic > Jurassic (1.00)
- Phanerozoic > Mesozoic > Cretaceous > Upper Cretaceous (0.37)
- Phanerozoic > Paleozoic > Carboniferous > Pennsylvanian (0.34)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (1.00)
- Geology > Sedimentary Geology (0.99)
- Geology > Sedimentary Basin (0.93)
- (2 more...)
- Europe > Germany > Lower Saxony > Lower Saxony Basin (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.94)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.94)
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)
Estimating Recovery by Quantifying Mobile Oil and Geochemically Allocating Production in Source Rock Reservoirs
Adams, Jennifer (Stratum Reservoir, Houston) | Flannery, Matt (Stratum Reservoir, Houston) | Ruble, Tim (Stratum Reservoir, Houston) | McCaffrey, Mark A. (Stratum Reservoir, Houston) | Krukowski, Elizabeth (Stratum Reservoir, Houston) | Kolodziejczyk, Daniel (GeoLab Sur S.A., Buenos Aires, Argentina) | Villar, Héctor (GeoLab Sur S.A., Buenos Aires, Argentina)
Abstract Due to highly variable well performance, unconventional reservoir (UR) field development relies heavily on production monitoring to predict total recovery, assess well interference, delineate drained rock volume, and diagnose mechanical issues. Completion design and well spacing decisions depend on accurate recovery estimates from reservoir models, and these can be limited by non-uniqueness in the history matching. Geochemical production allocation can greatly improve operators’ understanding of well performance when integrated with reservoir characterization and in-reservoir P/T monitoring. There are several long-standing challenges in the characterization of UR fluid flow: (i) collecting reservoir samples representative of mobile oil, (ii) accounting for production fractionation over the life of a well, and (iii) determining recoverable original oil in place (OOIP) from contributing zones. Although many metrics and correlations are commonly used, ultimate recovery requires accurate quantification of the provenance of produced fluids and proportion of total OOIP. We have developed a rapid method for quantifying mobile and total oil saturations from water-based mud (WBM) collected, tight cuttings and sidewall core samples using low temperature hydrous pyrolysis (EZ-LTHP). These mobile oils commonly include even the gasoline range compounds, which are the dominant compounds of produced liquids in most mid-continent UR fields, making EZ-LTHP-derived oils representative end-members for geochemical production allocation studies. EUR estimates and production forecasts by zone, are more accurate when calibrated to the mobile oil fraction, rather than to total oil saturation. EZ-LTHP provides this step-change by quantifying the mobile oil fraction in WBM cuttings and, when paired with reservoir volumetrics, allows for better reservoir model calibration and field management. Other industry techniques, such as solvent extraction and vaporization, suffer from the same limitations as log-derived values which are known to overestimate mobile oil in kerogen-rich intervals by incorrectly including kerogen-bound immobile oil. In this paper, we present quantified mobile oil recovery estimates based on integrated geochemical allocation studies from the Vaca Muerta, Neuquén basin, and the Niobrara, Denver basin. In the Vaca Muerta play (Argentina), the organic-rich Cocina and Organico intervals in the Vaca Muerta expelled liquid into intervening good quality reservoir lithologies. However, liquids dominantly are produced from the most organic-rich zones, with evidence of a larger drained rock volume (DRV) during early production. Gas and oil allocations show different DRVs explained by fluid mobility. The Montney play (Canada) shows contribution of liquid from non-target zones. Interbedded zones of indigenous Montney oil mixed with migrated more mature fluid - and major discontinuities in mud gas isotopes - document minimal vertical mixing. Horizontal wells produce gas and oil dominantly from better-quality reservoirs regardless of landing zone, with natural gas bypassing low permeability zones. Accurate estimations of out-of-zone contributions therefore require cuttings/core-based geochemical allocation. A subset of these wells requires additional consideration of production fractionation.
- North America > United States > Texas (1.00)
- North America > United States > Colorado (1.00)
- North America > Canada > British Columbia (1.00)
- (3 more...)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.35)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- North America > United States > Wyoming > Powder River Basin (0.99)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- (59 more...)
Novel Cement Design for Water Shutoff Application in North Kuwait Heavy Oil Field
Pullanikkottil, S. (Superior Energy Services) | Ibrahim, M. (Superior Energy Services) | Elghoul, S. (Superior Energy Services) | Bosilca, D. (Shell Kuwait Heavy Oil ETSA) | Gupta, P. (Kuwait Oil Company) | Al-Hammadi, E. K. (Kuwait Oil Company) | Al-Sairafi, F. A. (Kuwait Oil Company) | Abdullah, A. S. (Kuwait Oil Company) | Al-Ajmi, A. M. (Kuwait Oil Company) | Monteiro, K. (Kuwait Oil Company)
Abstract Kuwait Oil Company (KOC) have been actively recovering hydrocarbons from Heavy-oil reservoirs located in the Northern Kuwait (NK) Fields. Northern Kuwait Heavy Oil (NKHO) reserves are mainly located in two major fields: Field-1 (cold well) and Field-2 (thermal well). Currently, this heavy oil field is in the developmental phase, and KOC plans to add additional wells yearly. Field-2 is a thermal field, currently producing with a water cut of approximately 45%. Typically, water coning is a major challenge that hinders thermal recovery in a heavy oil reservoir with a bottom or boundary aquifer. This situation typically occurs when the production zone is near an aquifer or a water-bearing formation with a permeable connection, based on the ratio of horizontal to vertical permeability between the oil production zone and water formation. Coning occurs with pressure drawdown, causing water to migrate from the bottom to the wellbore. This is strictly a near-wellbore phenomenon that occurs only once the pressure forces drawing fluids toward the wellbore exceed the natural buoyancy forces that segregate gas and water from oil. Coning is a rate-sensitive phenomenon generally associated with high production rates. Although it can be controlled by decreasing the production rates, this approach is unfavorable because oil production is reduced and water production impacts the economic life of reservoirs and ultimate recovery. Moreover, it increases the operating expenses such as pumping, water/oil separation, and equipment costs. Additionally, excess water production causes wellbore corrosion, scaling, and sand production problems. Because of the chemical complexity of the produced water, its disposal is a major environmental concern. This also increases the disposal costs. Therefore, developing a proper and economical method to shut off or lower excess water has become one of the most significant concerns of the KOC in the NKHO field. Field-2 is a relatively new emerging field with increased intervention complexity due to an increase in water cuts. Early remedial job trials using conventional thermal slurries were unsuccessful in Field-2. This study illustrates the deployment of a novel cementing solution to address the challenges associated with conventional thermal cement for low-pressure, low-temperature, water-shut-off cement squeeze jobs. The slurry design and approach have good potential for vast applications in Kuwait and heavy oil fields worldwide.
- North America (1.00)
- Asia > Middle East > Kuwait (1.00)
A Unique Methodology and Successful Implementation While Testing Exploratory Well in Bahrah Field with Several Challenges: A Case Study in North Kuwait
Alotaibi, F. Z. (Kuwait Oil Company, Ahmadi, Kuwait) | Al-Ibrahim, A. (Kuwait Oil Company, Ahmadi, Kuwait) | Ibrahim, A. (Kuwait Oil Company, Ahmadi, Kuwait) | Binsafar, A. (Kuwait Oil Company, Ahmadi, Kuwait) | Alkhulaifi, O. (Kuwait Oil Company, Ahmadi, Kuwait)
Abstract Objectives/Scope This paper presents a unique successful application and implementation of testing procedures in an exploratory cretaceous well in Bahrah field (North Kuwait). Used to evaluate productivity and characteristics of a reservoir and clearly understand the reservoir's potential, which helps in reducing the risks related to developing the field for a long-term with sustainable production, and selecting the optimum completion and artificial lift method. Methods, Procedures, Process The exploratory vertical well BH-X drilled to explore the hydrocarbon potential within the Northern Area of the Bahrah field targeting cretaceous Sandstone formation, with a total drilling depth 10,780 ft. Open-hole logs and collected WL open-hole fluid sample post drilling proved the oil bearing in the sandstone formation. The cement bond evaluation behind slim casing liner showed some doubt in quality in particularly cement image of ultrasonic tool. Decision was taken to proceed with testing without cement remediation, and perform a DST with down-hole real-time pressure gauges. The Formation interval was perforated using dynamic underbalance casing guns post displacing the completion fluid in hole OBM with filtrated brine. The Nitrogen (N2) lifting through Coiled tubing (CT) was used for well activation and to evaluate the well productivity on rig since the well ceased to flow naturally. Since these pressure events and analysis are crucial in making decisions in a low cost environment, It was decided to retrieve the downhole pressure data for preliminary Pressure Transient Analysis (PTA), which indicated that the formation skin was positive. Therefore, acid wash was performed to the sensitive sandstone formation to enhance the production rate. Results, Observations, Conclusions However, the results post the acid wash treatment showed increment in water cut. RIH with Water-Flow Log (WFL) to check the water source and identified channels behind pipe was challenging due to unavailability of E-coiled tubing. Thus, a unique solution was used to achieve a drawdown and dynamic condition while recording conventional WFL against the testing zone by using N2 and utilizing the DST tools functions. WFL results indicated the source of water behind casing above the test interval. Therefore, a cement squeeze job was performed and cement bond log was recorded again post the remedial job, which confirmed a good improvement in cement bond. The targeted interval was re-perforated utilizing dynamic underbalance perforation with STIM guns, the well was activated by CT using N2 lifting and showed clear improvement in production with zero water cut. Novel/Additive Information Overall, a unique methodology while using real time data has delivered better decision making and operational capabilities during rig and testing operations, which assists in reducing well testing operations cost and time.
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Bahrah Field > Marrat Formation (0.99)
- Asia > Middle East > Iraq > Basra Governorate > Arabian Basin > Widyan Basin > Mesopotamian Basin > Zubair Field > Zubair Formation (0.98)
- Asia > Middle East > Iraq > Basra Governorate > Arabian Basin > Widyan Basin > Mesopotamian Basin > Zubair Field > Mishrif Formation (0.98)
First Application of LWD High-Resolution Ultrasonic Imaging in an Unconventional Horizontal Well in the Najmah Formation: Case Study from Kuwait
Al-Naqeeb, Mohamed Nizar (Kuwait Oil Company) | Ghneej, Ali Faleh Abu (Kuwait Oil Company) | Al-Khabbaz, Mohammed (Kuwait Oil Company) | Abdulkarim, Anar (Halliburton)
Abstract The unconventional Jurassic Najmah carbonate-shale formation in northern Kuwait has been tested and found to be a prolific source rock as well as a producer of gas, condensate, and light oil in different wells. The flow-controlling system, given the very low porosity, is highly dependent on the presence of a natural fracture network. The Najmah kerogen member, formally known as the Najmah shale, is the source reservoir composed of highly organic-rich argillaceous and calcareous clay, represented by very high total gamma ray values associated with high uranium on spectral gamma ray logs. Average matrix porosity ranges from 2 to 6%, low permeability from 0.01 to 1.5 mD, and total organic content (TOC) from 7 to 12%. Identification and interpretation of fractures, bed boundaries, and borehole breakout from high-resolution images plays a crucial role in optimizing completion design. Using wireline has been a challenge in horizontal wells, making logging-while-drilling (LWD) acquisition preferable. The case study is from a horizontal exploration well drilled with a rotary steerable system combined with gamma ray and resistivity sensors in the Najmah formation of north Kuwait, where a multi-stage fracking completion was planned. The logging program also included density, neutron porosity, sonic, and high-resolution ultrasonic borehole imaging measurements. To minimize the risk of stuck events, it was decided to use LWD acquisition. Wells in the area are typically drilled in the minimum stress direction (SHmin) to cross natural fractures perpendicularly, to optimize fracking. However, surprisingly, most of the natural fractures were almost parallel to SHmin. Overall, high data quality was achieved, and the results exceeded the end data users’ expectations. In total 96 natural fractures, 16 bed boundaries, and a few breakout intervals were interpreted within a measured-depth interval of 1,610 feet. Some of the fractures could be identified with high confidence on a 1:200 scale log. The new information about fracture orientation will be considered for future well design planning. The results were also used to facilitate the optimization of future field development and completion design. Further field analysis and studies are planned to be performed to confirm the interpreted results.
- Asia > Middle East > Kuwait (1.00)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.15)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.74)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.35)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Abdalli Field (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Tayarat Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Wara Formation (0.99)
- (8 more...)
Pore-Scale Study on the Flow Dynamics of Coupled Low Salinity and Nanofluid Flooding in Carbonate Formations
Khalilinezhad, Seyed Shahram (Faculty of Engineering and Applied Science, Memorial University of Newfoundland, St. John’s, NL, Canada) | Duan, Xili (Faculty of Engineering and Applied Science, Memorial University of Newfoundland, St. John’s, NL, Canada) | Singh, Kuldeep (Department of Earth Sciences, Kent State University, Kent, OH, USA)
Abstract A significant volume of annual world oil production comes from carbonate reservoirs like the giant Middle East and Caspian Sea reservoirs. However, the production enhancement is complicated by geological heterogeneities of carbonate formations, such as a complicated network of natural fractures leading to highly permeable paths or shale streaks leading to discontinuous flow barriers. The primary objective of this paper is a feasibility study of coupled low salinity and nanofluid flooding for oil recovery enhancement from carbonate reservoirs. Accordingly, diluted seawater and two different types of nanoparticles (NPs) were exploited to prepare low-salinity nanosuspensions to understand the synergistic effects of low-salinity nanofluid (LSN) injection on oil droplet remobilization. As the multiphase flow experiments were performed using glass micromodels, surface wettability analysis was also conducted on flat glass plates to clarify the role of NPs at the interfaces. The fluid flow around shale barriers and fracture/matrix interactions were qualitatively scrutinized at the pore scale using multiphase flow tests on the oil-wet microfluidic chips inspired by the pore structures of rock samples of carbonate reservoirs. The results of contact angle experiments showed that the inclusion of NPs into low-salinity water can ameliorate the ability of the aqueous solution to reverse the surface wettability of the oil-wet samples to a more water-wet state due to the improved adsorption isotherm of NPs into the glass surface. Microscopic and macroscopic observations of the porous media flow tests also disclosed that the LSN injection could significantly improve breakthrough time as well as microscopic and macroscopic sweep efficiencies. In other words, a slight viscosity improvement of injected water due to the presence of NPs could relatively diminish the extension of fingering patterns in porous media and create a better displacement front, resulting in a higher breakthrough time of displacing fluid. Furthermore, due to surface wettability reversal, LSN injection reduced the amount of untouched oil behind the shale streaks and showed better intrusion into the matrix and a higher fluid exchange rate between the matrix and fractures. This study proves the effectiveness of LSN injection in improving the efficiency of enhanced oil recovery from carbonate formations. Besides, we highlighted the flow characteristics of LSN around the shale streaks and high permeable fractures.
- Asia > Middle East (0.28)
- North America > Canada (0.28)
- Asia > Kazakhstan > Mangystau Oblast > Precaspian Basin > Tengiz Field > Tengiz Formation (0.99)
- Asia > Kazakhstan > Mangystau Oblast > Precaspian Basin > Tengiz Field > Korolev Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Fields > Burgan Field > Wara Formation (0.98)
- (12 more...)