The Experts below are selected from a list of 264 Experts worldwide ranked by ideXlab platform
Ahzegbobor Philips Aizebeokhai - One of the best experts on this subject based on the ideXlab platform.
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Prospect Analysis and Hydrocarbon Reservoir Volume Estimation in an Exploration Field, Shallow Offshore Depobelt, Western Niger Delta, Nigeria
Natural Resources Research, 2019Co-Authors: Kehinde David Oyeyemi, Mary T. Olowokere, Ahzegbobor Philips AizebeokhaiAbstract:The daunting challenge in the exploration and production of oil and gas in the face of continual rise in the world’s energy consumption has long been how to economically recover bypassed reserves within existing assets. This research is focused on the analysis of prospects and Volumetric estimation of the Hydrocarbon reservoirs delineated within an exploratory field using 3D seismic data and suites of wireline logs. The prospectivity of the delineated reservoir was carried out using seismo-structural interpretation and formation evaluation towards the assessment of the prolific Hydrocarbon occurrence within the field. The reservoirs have porosity (0.29–0.32) for H1, (0.20–0.31) for H2 and (0.30–0.40) for H3 and the average computed Hydrocarbon saturation of (0.31–0.62) for H1, (0.16–0.52) for H2 and (0.64–0.73) for H3, Hydrocarbon Pore Volume (HCPV) of 28,706.95, 33,081.2 and 45,731.49 barrels for H1, H2 and H3, respectively, while the estimated stock tank oil initially-in-place (STOIIP) range (136.8–140.73) MMSTB for H1, (36.77–489.64) MMSTB for H2 and (166.62–308.14) MMSTB for H3. The observed porosity and Hydrocarbon saturation for the delineated reservoirs as well as the estimated Hydrocarbon Pore Volume and storage total oil in place indicate that the reservoirs are highly prolific. The study has therefore contributed to the understanding of Hydrocarbon resource potential within the study area.
Sumon Chatterjee - One of the best experts on this subject based on the ideXlab platform.
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co 2 storage associated with co 2 enhanced oil recovery a statistical analysis of historical operations
International Journal of Greenhouse Gas Control, 2015Co-Authors: Nicholas A Azzolina, David V Nakles, Charles D Gorecki, Wesley D Peck, Scott C Ayash, Stephen L Melzer, Sumon ChatterjeeAbstract:Abstract This work analyzes a database of 31 existing CO2 enhanced oil recovery (EOR) projects that was compiled for the estimation of oil reserves to better understand the CO2 retention, incremental oil recovery, and net CO2 utilization for these oil fields. The measured data begin at the start date of the CO2 flood and extend through the year 2007. Cumulative CO2 retention (in the formation), incremental oil recovery factors, and net CO2 utilization factors were calculated for each of the sites. To express all site data on a common dimensionless scale, the data were extrapolated to 300% cumulative Hydrocarbon Pore Volume (HCPV) by fitting nonlinear functions. Summary statistics were then calculated from 0% to 300% HCPV. Across all 31 sites, the 10th, 50th (median), and 90th percentile values for the three factors at 300% HCPV were: CO2 retention: 23.1%, 48.3%, and 61.8% retained; incremental oil recovery: 5.3%, 12.2%, and 21.5% of OOIP (original oil in place); and net CO2 utilization: 4.8, 8.7, and 10.5 Mscf/STB (stock-tank barrel). This work employs a novel approach that incorporates nonlinear functions to quantify uncertainty in the estimated values as a function of HCPV and to describe the shape of the CO2 retention or incremental oil recovery response with a handful of parameters, providing insight into the behavior of the reservoir across the entire timeline of the CO2 flood. These nonlinear curve fits are focused on statistical inference – i.e., what is the likely outcome and uncertainty ranges for CO2 retention, incremental oil recovery, and net CO2 utilization given the historical data from the 31 CO2 EOR sites? However, the approach described in this work also provides useful information for prediction – i.e., given a set of inputs from another site with similar geology, what are plausible ranges in outcomes for each of these factors? Consequently, the results of this work can be used to estimate the potential range of expected performance for similar candidate oil fields that are not currently undergoing CO2 injection, including estimates of the associated CO2 storage potential of these candidate fields. The results of this work allow estimation of CO2 storage capacity in CO2-EOR operations with various degrees of confidence. The sites in the dataset reflect water – alternating gas CO2 floods – all within the continental United States and heavily dominated by the West Texas carbonate floods. Other floods outside of this region, where the data were available, are also included in this study (i.e., the Rocky Mountain region and the State of Oklahoma).
Kehinde David Oyeyemi - One of the best experts on this subject based on the ideXlab platform.
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Prospect Analysis and Hydrocarbon Reservoir Volume Estimation in an Exploration Field, Shallow Offshore Depobelt, Western Niger Delta, Nigeria
Natural Resources Research, 2019Co-Authors: Kehinde David Oyeyemi, Mary T. Olowokere, Ahzegbobor Philips AizebeokhaiAbstract:The daunting challenge in the exploration and production of oil and gas in the face of continual rise in the world’s energy consumption has long been how to economically recover bypassed reserves within existing assets. This research is focused on the analysis of prospects and Volumetric estimation of the Hydrocarbon reservoirs delineated within an exploratory field using 3D seismic data and suites of wireline logs. The prospectivity of the delineated reservoir was carried out using seismo-structural interpretation and formation evaluation towards the assessment of the prolific Hydrocarbon occurrence within the field. The reservoirs have porosity (0.29–0.32) for H1, (0.20–0.31) for H2 and (0.30–0.40) for H3 and the average computed Hydrocarbon saturation of (0.31–0.62) for H1, (0.16–0.52) for H2 and (0.64–0.73) for H3, Hydrocarbon Pore Volume (HCPV) of 28,706.95, 33,081.2 and 45,731.49 barrels for H1, H2 and H3, respectively, while the estimated stock tank oil initially-in-place (STOIIP) range (136.8–140.73) MMSTB for H1, (36.77–489.64) MMSTB for H2 and (166.62–308.14) MMSTB for H3. The observed porosity and Hydrocarbon saturation for the delineated reservoirs as well as the estimated Hydrocarbon Pore Volume and storage total oil in place indicate that the reservoirs are highly prolific. The study has therefore contributed to the understanding of Hydrocarbon resource potential within the study area.
Hua Zhang - One of the best experts on this subject based on the ideXlab platform.
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Monitoring on CO2 migration in a tight oil reservoir during CCS-EOR in Jilin Oilfield China
Energy, 2016Co-Authors: Liang Zhang, Guoli Chen, Hua ZhangAbstract:Jilin Oilfield is conducting a large-scale demonstration project on CO2 EOR (enhanced oil recovery) and storage in China. CO2 separated from a nearby natural gas reservoir (15–30 mol% CO2) is injected into the northern part of H59 oil block with permeability and porosity of 3.5 mD and 12.7%, respectively. After about six years of operation, nearly 0.26 million tons of CO2 (0.32 HCPV (Hydrocarbon Pore Volume)) has been injected into the thin oil layers with well-developed natural fractures. In order to track the movement of CO2 in the oil reservoir, a microseismic monitoring program has been implemented to map the CO2 flow anisotropy and estimate its sweeping efficiency. Gas tracer testing has also been conducted to examine the inter-well connectivity. The temporal change of produced CO2 has been analyzed in a real-time mode to monitor the dynamic response in production wells. It is demonstrated that the migration of CO2 in the thin oil layers can be successfully detected by the microseismic technique, and the sweeping profiles of CO2 obtained from the inverted microseismic are in good agreement with the produced CO2 rate from production wells as well as the reservoir's petrophysical properties.
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Performance evaluation and mechanisms study of near-miscible CO2 flooding in a tight oil reservoir of Jilin Oilfield China
Journal of Natural Gas Science and Engineering, 2015Co-Authors: Liang Zhang, Guoli Chen, Haidong Huang, Hua ZhangAbstract:Abstract Jilin Oilfield has been conducting a large-scale demonstration project on CO 2 EOR and storage in China. CO 2 separated from a nearby natural gas reservoir (15–30 vol% CO 2 ) has been injected into the northern part of H-59 oil block with the permeability of 3.0 mD and porosity of 12.7%. After six years of operation, nearly 0.26 million ton of CO 2 (0.32 Hydrocarbon Pore Volume) has been injected under a miscible or near-miscible flooding mode with CO 2 utilization efficiency of 6.3 MScf/bbl, and an expected enhanced oil recovery of over 10% would be achieved. A systematic and thorough reservoir surveillance program has been conducted to facilitate efficient operation and evaluation. Casing annulus gas composition was analyzed to monitor gas breakthrough in production wells as well as the gas tracer to detect CO 2 flow across the reservoir. Bottom hole pressure (BHP) survey of producers and fluid sampling were combined to evaluate the miscibility effect in conjunction with the injection-production data analysis. It is revealed that the designed miscible flooding is best described as near-miscible due to the large pressure difference between injector and producer, and the gas channeling and fractures/heterogeneities cause the miscibility instability. Gravity-stabilized displacement may develop in the downdip part of the reservoir during the flooding process. The vaporization and condensation effects have been observed and confirmed through laboratory core flooding and field produced oil compositions analysis. A key insight from the evaluation study is that CO 2 near-miscible flooding is more flexible and easily realizable relative to miscible, particularly in the tight oil reservoir. Further study would be necessary to optimize the reservoir development program under the near-miscible flooding design.
Liang Zhang - One of the best experts on this subject based on the ideXlab platform.
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Displacement mechanisms of air injection for IOR in low permeability light oil reservoirs
International Journal of Oil Gas and Coal Technology, 2017Co-Authors: Justin Ezekiel, Liang Zhang, Yuting Wang, Junyu Deng, Guibin WangAbstract:Air injection into light oil reservoirs has been proven to be a valuable improved oil recovery (IOR) process and is being successfully implemented worldwide in many oilfields. It specially offers unique technical and economic opportunities for tertiary or secondary oil recovery in light oil reservoirs with low permeability in which conventional water injection techniques have been unsuccessful and/or uneconomical. This paper provides a comprehensive overview on the oxidation and IOR process of air injection into low permeability light oil reservoir based on detailed analysis of some field projects and the results of laboratory testing and reservoir simulation of a typical light oil reservoir, the Q131 Block. The reaction mechanisms of low temperature oxidation (LTO) and high temperature oxidation (HTO or in-situ combustion) are particularly addressed in this study. Air flooding displacement efficiency experiment was carried out without water injection, and an oil recovery of more than 40% of Hydrocarbon Pore Volume (HCPV) was observed. A series of high-pressure oxidation experiments using the typical light oil were conducted in the temperature range of 98°C to 180°C. The results showed high oxidation and carbon dioxide (CO2) conversion rates, which are both favourable in terms of oxygen consumption. A conceptual full field compositional reservoir simulation model of the targeted low permeability block was also used to examine the reaction schemes, thermal effect of LTO reactions and IOR mechanisms. [Received: March 22, 2014; Accepted: February 7, 2016]
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Monitoring on CO2 migration in a tight oil reservoir during CCS-EOR in Jilin Oilfield China
Energy, 2016Co-Authors: Liang Zhang, Guoli Chen, Hua ZhangAbstract:Jilin Oilfield is conducting a large-scale demonstration project on CO2 EOR (enhanced oil recovery) and storage in China. CO2 separated from a nearby natural gas reservoir (15–30 mol% CO2) is injected into the northern part of H59 oil block with permeability and porosity of 3.5 mD and 12.7%, respectively. After about six years of operation, nearly 0.26 million tons of CO2 (0.32 HCPV (Hydrocarbon Pore Volume)) has been injected into the thin oil layers with well-developed natural fractures. In order to track the movement of CO2 in the oil reservoir, a microseismic monitoring program has been implemented to map the CO2 flow anisotropy and estimate its sweeping efficiency. Gas tracer testing has also been conducted to examine the inter-well connectivity. The temporal change of produced CO2 has been analyzed in a real-time mode to monitor the dynamic response in production wells. It is demonstrated that the migration of CO2 in the thin oil layers can be successfully detected by the microseismic technique, and the sweeping profiles of CO2 obtained from the inverted microseismic are in good agreement with the produced CO2 rate from production wells as well as the reservoir's petrophysical properties.
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Performance evaluation and mechanisms study of near-miscible CO2 flooding in a tight oil reservoir of Jilin Oilfield China
Journal of Natural Gas Science and Engineering, 2015Co-Authors: Liang Zhang, Guoli Chen, Haidong Huang, Hua ZhangAbstract:Abstract Jilin Oilfield has been conducting a large-scale demonstration project on CO 2 EOR and storage in China. CO 2 separated from a nearby natural gas reservoir (15–30 vol% CO 2 ) has been injected into the northern part of H-59 oil block with the permeability of 3.0 mD and porosity of 12.7%. After six years of operation, nearly 0.26 million ton of CO 2 (0.32 Hydrocarbon Pore Volume) has been injected under a miscible or near-miscible flooding mode with CO 2 utilization efficiency of 6.3 MScf/bbl, and an expected enhanced oil recovery of over 10% would be achieved. A systematic and thorough reservoir surveillance program has been conducted to facilitate efficient operation and evaluation. Casing annulus gas composition was analyzed to monitor gas breakthrough in production wells as well as the gas tracer to detect CO 2 flow across the reservoir. Bottom hole pressure (BHP) survey of producers and fluid sampling were combined to evaluate the miscibility effect in conjunction with the injection-production data analysis. It is revealed that the designed miscible flooding is best described as near-miscible due to the large pressure difference between injector and producer, and the gas channeling and fractures/heterogeneities cause the miscibility instability. Gravity-stabilized displacement may develop in the downdip part of the reservoir during the flooding process. The vaporization and condensation effects have been observed and confirmed through laboratory core flooding and field produced oil compositions analysis. A key insight from the evaluation study is that CO 2 near-miscible flooding is more flexible and easily realizable relative to miscible, particularly in the tight oil reservoir. Further study would be necessary to optimize the reservoir development program under the near-miscible flooding design.