Accurate and realistic geological modeling is the core of oil and gas development and production. In recent years, process-based methods are developed to produce highly realistic geological models by simulating the physical processes that reproduce the sedimentary events and develop the geometry. However, the complex dynamic processes are extremely expensive to simulate, making process-based models difficult to be conditioned to field data. In this work, we propose a comprehensive generative adversarial network framework as a machine-learning-assisted approach for mimicking the outputs of process-based geological models with fast generation. The main objective of our work is to obtain a continuous parametrization of the highly realistic process-based geological models which enables us to calibrate the models and condition the models to data. Numerical results are presented to illustrate the capability of our proposed methodology.
{"title":"Stochastic representation and conditioning of process-based geological model by deep generative and recognition networks","authors":"S. W. Cheung, A. Kushwaha, H. Sun, X.-H. Wu","doi":"10.1144/petgeo2022-032","DOIUrl":"https://doi.org/10.1144/petgeo2022-032","url":null,"abstract":"Accurate and realistic geological modeling is the core of oil and gas development and production. In recent years, process-based methods are developed to produce highly realistic geological models by simulating the physical processes that reproduce the sedimentary events and develop the geometry. However, the complex dynamic processes are extremely expensive to simulate, making process-based models difficult to be conditioned to field data. In this work, we propose a comprehensive generative adversarial network framework as a machine-learning-assisted approach for mimicking the outputs of process-based geological models with fast generation. The main objective of our work is to obtain a continuous parametrization of the highly realistic process-based geological models which enables us to calibrate the models and condition the models to data. Numerical results are presented to illustrate the capability of our proposed methodology.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2024-02-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140428940","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The effective electrical conductivity of organic-rich mudrocks can be influenced by the presence of clay, pyrite, and thermally mature organic matter. In this paper, we investigate the impacts of conductivity, volumetric concentrations, and spatial distribution/connectivity of clay, pyrite, and kerogen networks on the effective conductivity of the rock and how this affects the assessment of water/hydrocarbon saturation. This quantification enables an understanding of when such components need to be considered in interpreting resistivity measurements in organic-rich mudrocks. We perform sensitivity analysis on the impacts of (a) thermal-maturity-dependent kerogen conductivity, (b) volumetric concentration/spatial distribution of kerogen, (c) conductivity and volumetric concentration/spatial distribution of pyrite, and (d) cation exchange capacities of various clay minerals and their concentration/spatial distribution on the effective conductivity of the rock. The sensitivity analysis showed that with increasing pyrite concentration, the effective conductivity of the rock increased. This increment became significant when the concentration of pyrite was above 2%. Lastly, we observed that thermally mature kerogen increased the conductivity of the rock, with a significant increment occurring when the kerogen conductivity was above 0.01 S/m. Results confirmed that the incorporation of conductive rock components such as clay, pyrite, and kerogen into the electrical rock physics model improved the estimates of hydrocarbon reserves.
{"title":"Impacts of Solid Rock Components on Resistivity-based Reserves Evaluation in Organic-Rich Mudrocks","authors":"Sabyasachi Dash, Z. Heidari","doi":"10.1144/petgeo2023-135","DOIUrl":"https://doi.org/10.1144/petgeo2023-135","url":null,"abstract":"The effective electrical conductivity of organic-rich mudrocks can be influenced by the presence of clay, pyrite, and thermally mature organic matter. In this paper, we investigate the impacts of conductivity, volumetric concentrations, and spatial distribution/connectivity of clay, pyrite, and kerogen networks on the effective conductivity of the rock and how this affects the assessment of water/hydrocarbon saturation. This quantification enables an understanding of when such components need to be considered in interpreting resistivity measurements in organic-rich mudrocks. We perform sensitivity analysis on the impacts of (a) thermal-maturity-dependent kerogen conductivity, (b) volumetric concentration/spatial distribution of kerogen, (c) conductivity and volumetric concentration/spatial distribution of pyrite, and (d) cation exchange capacities of various clay minerals and their concentration/spatial distribution on the effective conductivity of the rock. The sensitivity analysis showed that with increasing pyrite concentration, the effective conductivity of the rock increased. This increment became significant when the concentration of pyrite was above 2%. Lastly, we observed that thermally mature kerogen increased the conductivity of the rock, with a significant increment occurring when the kerogen conductivity was above 0.01 S/m. Results confirmed that the incorporation of conductive rock components such as clay, pyrite, and kerogen into the electrical rock physics model improved the estimates of hydrocarbon reserves.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2024-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140443464","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This study develops an innovative workflow to identify discrete lithofacies distributions with respect to the well-log records exploiting two tree-based ensemble learning algorithms: extreme gradient boosting (XGBoost) and adaptive boosting (AdaBoost). In the next step, the predicted discrete lithofacies distribution is further assessed with well-log data using an XGBoost regression to predict reservoir permeability. The input well logging records are gamma ray, neutron porosity, bulk density, compressional slowness and deep and shallow resistivity. These data originate in a carbonate reservoir at the Mishrif basin of southern Iraq's oil field. To achieve solid prediction of lithofacies permeability, random subsampling cross-validation was applied to the originated dataset to formulate two subsets, training for model tuning and testing for prediction of subsets that are not observed during model training. The values of total correct percentage (TCP) of lithofacies predictions for the entire dataset and testing subset were 98% and 93% by the XGBoost algorithm; and 97% and 89% using the AdaBoost classifier, respectively. The XGBoost predictive models led to attain the least uncertain lithofacies and permeability records of the cored data. For further validation, the predicted lithofacies and reservoir permeability were then compared with the porosity-permeability values derived from the Nuclear-Magnetic Resonance (NMR) log, the secondary porosity of the Full-bore Micro Imager (FMI) and the production contribution from the Production-Logging Tool (PLT). Therefore, it is believed that the XGBoost model is capable of making accurate predictions of lithofacies and permeability for the same well's non-cored intervals and other non-cored wells in the investigated reservoir.
{"title":"Integration of electromagnetic, resistivity-based, and production logging data for validating lithofacies and permeability predictive models with tree ensemble algorithms in heterogeneous carbonate reservoirs","authors":"W. Al-Mudhafar, Mohammed A. Abbas, David A. Wood","doi":"10.1144/petgeo2023-067","DOIUrl":"https://doi.org/10.1144/petgeo2023-067","url":null,"abstract":"This study develops an innovative workflow to identify discrete lithofacies distributions with respect to the well-log records exploiting two tree-based ensemble learning algorithms: extreme gradient boosting (XGBoost) and adaptive boosting (AdaBoost). In the next step, the predicted discrete lithofacies distribution is further assessed with well-log data using an XGBoost regression to predict reservoir permeability. The input well logging records are gamma ray, neutron porosity, bulk density, compressional slowness and deep and shallow resistivity. These data originate in a carbonate reservoir at the Mishrif basin of southern Iraq's oil field. To achieve solid prediction of lithofacies permeability, random subsampling cross-validation was applied to the originated dataset to formulate two subsets, training for model tuning and testing for prediction of subsets that are not observed during model training. The values of total correct percentage (TCP) of lithofacies predictions for the entire dataset and testing subset were 98% and 93% by the XGBoost algorithm; and 97% and 89% using the AdaBoost classifier, respectively. The XGBoost predictive models led to attain the least uncertain lithofacies and permeability records of the cored data. For further validation, the predicted lithofacies and reservoir permeability were then compared with the porosity-permeability values derived from the Nuclear-Magnetic Resonance (NMR) log, the secondary porosity of the Full-bore Micro Imager (FMI) and the production contribution from the Production-Logging Tool (PLT). Therefore, it is believed that the XGBoost model is capable of making accurate predictions of lithofacies and permeability for the same well's non-cored intervals and other non-cored wells in the investigated reservoir.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139814664","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This study develops an innovative workflow to identify discrete lithofacies distributions with respect to the well-log records exploiting two tree-based ensemble learning algorithms: extreme gradient boosting (XGBoost) and adaptive boosting (AdaBoost). In the next step, the predicted discrete lithofacies distribution is further assessed with well-log data using an XGBoost regression to predict reservoir permeability. The input well logging records are gamma ray, neutron porosity, bulk density, compressional slowness and deep and shallow resistivity. These data originate in a carbonate reservoir at the Mishrif basin of southern Iraq's oil field. To achieve solid prediction of lithofacies permeability, random subsampling cross-validation was applied to the originated dataset to formulate two subsets, training for model tuning and testing for prediction of subsets that are not observed during model training. The values of total correct percentage (TCP) of lithofacies predictions for the entire dataset and testing subset were 98% and 93% by the XGBoost algorithm; and 97% and 89% using the AdaBoost classifier, respectively. The XGBoost predictive models led to attain the least uncertain lithofacies and permeability records of the cored data. For further validation, the predicted lithofacies and reservoir permeability were then compared with the porosity-permeability values derived from the Nuclear-Magnetic Resonance (NMR) log, the secondary porosity of the Full-bore Micro Imager (FMI) and the production contribution from the Production-Logging Tool (PLT). Therefore, it is believed that the XGBoost model is capable of making accurate predictions of lithofacies and permeability for the same well's non-cored intervals and other non-cored wells in the investigated reservoir.
{"title":"Integration of electromagnetic, resistivity-based, and production logging data for validating lithofacies and permeability predictive models with tree ensemble algorithms in heterogeneous carbonate reservoirs","authors":"W. Al-Mudhafar, Mohammed A. Abbas, David A. Wood","doi":"10.1144/petgeo2023-067","DOIUrl":"https://doi.org/10.1144/petgeo2023-067","url":null,"abstract":"This study develops an innovative workflow to identify discrete lithofacies distributions with respect to the well-log records exploiting two tree-based ensemble learning algorithms: extreme gradient boosting (XGBoost) and adaptive boosting (AdaBoost). In the next step, the predicted discrete lithofacies distribution is further assessed with well-log data using an XGBoost regression to predict reservoir permeability. The input well logging records are gamma ray, neutron porosity, bulk density, compressional slowness and deep and shallow resistivity. These data originate in a carbonate reservoir at the Mishrif basin of southern Iraq's oil field. To achieve solid prediction of lithofacies permeability, random subsampling cross-validation was applied to the originated dataset to formulate two subsets, training for model tuning and testing for prediction of subsets that are not observed during model training. The values of total correct percentage (TCP) of lithofacies predictions for the entire dataset and testing subset were 98% and 93% by the XGBoost algorithm; and 97% and 89% using the AdaBoost classifier, respectively. The XGBoost predictive models led to attain the least uncertain lithofacies and permeability records of the cored data. For further validation, the predicted lithofacies and reservoir permeability were then compared with the porosity-permeability values derived from the Nuclear-Magnetic Resonance (NMR) log, the secondary porosity of the Full-bore Micro Imager (FMI) and the production contribution from the Production-Logging Tool (PLT). Therefore, it is believed that the XGBoost model is capable of making accurate predictions of lithofacies and permeability for the same well's non-cored intervals and other non-cored wells in the investigated reservoir.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139874550","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
More than twenty pinnacle reefs have been discovered in the southeast of Ajdabiya Trough within the Paleocene carbonate sediments, most of which are oil-bearing. However, detailed reservoir characterization and conditions governing oil fill-up in this reef remained unresolved. The major faults provide paths for significant vertical movement of fluids at the edges of the Intisar reef reservoirs. At the same time, the ongoing karst-solution collapse also creates vertical zones for fluids encroachment both outside of and within the productive area of the Intisar reef reservoirs. The seismic data shows numerous karst-collapse features up to 300 m in diameter which developed shortly after the final drowning of Intisar ‘B’ and ‘C’ reefs. These karst-collapse features may be the main contributing factor to the escape of hydrocarbons within these reefs, which could explain the high-water cuts in the Intisar ‘B’ and ‘C’ reefs. On the other hand, the porosity of the southeastern part of the Intisar ‘A’ reef was significantly improved by fracturing and dissolution, where faults associated with fractures are most common in this part of this reef.
{"title":"Impact of Paleokarst on the Pinnacle Reef Reservoirs in the Sirt Basin, Libya","authors":"Abdeladim M. Asheibi, Asghar Shams","doi":"10.1144/petgeo2023-008","DOIUrl":"https://doi.org/10.1144/petgeo2023-008","url":null,"abstract":"More than twenty pinnacle reefs have been discovered in the southeast of Ajdabiya Trough within the Paleocene carbonate sediments, most of which are oil-bearing. However, detailed reservoir characterization and conditions governing oil fill-up in this reef remained unresolved. The major faults provide paths for significant vertical movement of fluids at the edges of the Intisar reef reservoirs. At the same time, the ongoing karst-solution collapse also creates vertical zones for fluids encroachment both outside of and within the productive area of the Intisar reef reservoirs. The seismic data shows numerous karst-collapse features up to 300 m in diameter which developed shortly after the final drowning of Intisar ‘B’ and ‘C’ reefs. These karst-collapse features may be the main contributing factor to the escape of hydrocarbons within these reefs, which could explain the high-water cuts in the Intisar ‘B’ and ‘C’ reefs. On the other hand, the porosity of the southeastern part of the Intisar ‘A’ reef was significantly improved by fracturing and dissolution, where faults associated with fractures are most common in this part of this reef.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2024-01-31","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140470683","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Understanding the genesis and relationships among oil and gas accumulations is of prime importance in exploration and development programs. This will not only help better identify and delineate petroleum systems, but also aid in evaluating seals – one of the most critical elements in petroleum systems. Integrating geochemistry and pressure-volume-temperature (PVT) data of reservoir fluids offer tools for the assessment of fault and top seal integrity. Examples from fields at different levels of delineation, development and management from different Paleozoic and Mesozoic basins in the Middle East are discussed to demonstrate the role of fluid geochemistry in aiding the evaluation of top, lateral and fault seal integrity, and in providing insights into the sealing and buffering effects of reservoir heterogeneity on hydrocarbon fluid flow. Examples discussed include (1) detection of petrophysical sealing using PVT fluid composition data, (2) geochemical detection of partial sealing, (3) the development of top seal by solid reservoir bitumen immediately below a regional unconformity, (4) geochemical recognition of possible strike-slip fault seal, and (5) geochemical detection of fault-controlled reservoir compartmentalisation in a field at an appraisal stage where PVT data are limited or inconclusive. Thematic collection: This article is part of the Fault and top seals 2022 collection available at: https://www.lyellcollection.org/topic/collections/fault-and-top-seals-2022
{"title":"Assessment of Seal Integrity and Dynamic Fault Character Using Hydrocarbon Geochemistry and PVT Analysis: Examples from the Middle East","authors":"Khaled R. Arouri","doi":"10.1144/petgeo2023-068","DOIUrl":"https://doi.org/10.1144/petgeo2023-068","url":null,"abstract":"Understanding the genesis and relationships among oil and gas accumulations is of prime importance in exploration and development programs. This will not only help better identify and delineate petroleum systems, but also aid in evaluating seals – one of the most critical elements in petroleum systems. Integrating geochemistry and pressure-volume-temperature (PVT) data of reservoir fluids offer tools for the assessment of fault and top seal integrity. Examples from fields at different levels of delineation, development and management from different Paleozoic and Mesozoic basins in the Middle East are discussed to demonstrate the role of fluid geochemistry in aiding the evaluation of top, lateral and fault seal integrity, and in providing insights into the sealing and buffering effects of reservoir heterogeneity on hydrocarbon fluid flow. Examples discussed include (1) detection of petrophysical sealing using PVT fluid composition data, (2) geochemical detection of partial sealing, (3) the development of top seal by solid reservoir bitumen immediately below a regional unconformity, (4) geochemical recognition of possible strike-slip fault seal, and (5) geochemical detection of fault-controlled reservoir compartmentalisation in a field at an appraisal stage where PVT data are limited or inconclusive.\u0000 \u0000 Thematic collection:\u0000 This article is part of the Fault and top seals 2022 collection available at:\u0000 https://www.lyellcollection.org/topic/collections/fault-and-top-seals-2022\u0000","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2024-01-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139615868","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
S. Ahmad, Faizan Ahmad, Sohail Raza, Suleman Khan, B. Wadood, M. Mohibullah
In this study Jurassic-Paleogene strata were investigated to understand the litho-biostratigraphic framework and hydrocarbon source rock potential of various stratal packages. Biostratigraphic controls were used to establish the chronostratigraphic framework of Jurassic-Paleogene strata in the area. The Lower Jurassic (Hettangian) clastics saw an uconformity during Sinmurian-Pliensbachian, while the Lower Jurassic (Toracian) – Middle Jurassic (Bajocian) clastic-carbonate mixed strata is also separated by a Bathonian Unconformity from the Middle Jurassic (Callovian)-Upper Jurassic (Tithonian) carbonate sequence. The Upper Jurassic Oxfordian strata are missing while the Upper Jurassic (Kimmeridgian)- Lower Cretaceous (Velanginian) glaucoconatic sandstone-clays are the conformable sequences. The Lower- Cretaceous (Hauterivian)-Upper Cretaceous (Turonian) clastics is a conformable sequence which is separated by a Coniacian-Santonian unconformity from the Upper Cretaceous (Campanion) pelegic carbonates. The Cretaceous-Tertairy Boundary is marked by laterites while the Paleocene (Thanetian) sequence is represented by a shale and sandstone dominated sequence. The Paleocene (Thanetian)-Early Eocene (Ilerdian) siliciclastic-carbonates mixed sequence marks the last episode of Tethyan sedimentattion. Total Organic Content (TOC), organic petrography and Rock Eval Pyrolysis (REP) techniques were used to evaluate the hydrocarbon source rock potential, kerogen type, level of maturity of the hydrocarbons. The majority of studied samples show the occurrence of type IV kerogen. However, the Middle Jurassic (Callovian)-Upper Jurassic (Tithonian) carbonate sequence of the Samana Suk Formation, the Kimmeridgian-Velanginian Chichali Formation, the Paleocene (Thanetian) sequence of the Hangu Formation, and Paleocene (Thanetian)-Early Eocene (Ilerdian) Patala Formation confirms the Type III kerogen, poor-fair source rock quality, immature-mature, gas-oil prone indigenous hydrocarbon occurrence in the region.
本研究对侏罗纪-古近纪地层进行了调查，以了解不同地层组的岩石-生物地层框架和油气源岩潜力。生物地层控制用于建立该地区侏罗纪-古近纪地层的年代地层框架。下侏罗统（海唐统）碎屑岩在新元古代-liensbachian时期出现了uconformity，而下侏罗统（托拉千统）-中侏罗统（巴约千统）碎屑岩-碳酸盐混合地层也被中侏罗统（卡洛维统）-上侏罗统（提托尼统）碳酸盐序列的Bathonian Unconformity分隔开来。上侏罗世牛津统地层缺失，而上侏罗世（金梅里吉统）-下白垩统（维朗基尼统）釉质砂岩-粘土则是顺应层序。下白垩统（豪特里维安统）-上白垩统（都朗基安统）碎屑岩是一个顺层序列，与上白垩统（坎帕尼昂统）侏罗纪碳酸盐岩之间存在一个科尼亚-山统不整合层位。白垩纪-白垩纪界线以红土为标志，而古新世（塔尼蒂）序列则以页岩和砂岩为主。古新世（塔尼蒂）-早始新世（伊勒底）硅碎屑岩-碳酸盐混合序列标志着泰西沉积的最后一段时期。总有机含量（TOC）、有机岩相学和岩石评价热解（REP）技术被用来评估碳氢化合物源岩的潜力、角质类型和碳氢化合物的成熟度。所研究的大多数样本显示存在 IV 型角质。不过，萨马纳苏克地层的中侏罗世（卡洛维期）-上侏罗世（提多尼期）碳酸盐岩序列、金美里季-白垩纪的奇查里地层、汉古地层的古新世（他尼西纪）序列以及古新世（他尼西纪）碳酸盐岩序列都显示出烃源岩的潜力、以及古新世（他尼地层）-早始新世（伊勒地层）帕塔拉地层证实了该地区存在第三类角质、岩源质量差-一般、未成熟-成熟、易产气-油的本土碳氢化合物。
{"title":"Litho-biostratigraphy and hydrocarbon source rock potential of the Jurassic-Paleogene strata in the Kala Chitta Range, northwestern Himalayas, Pakistan","authors":"S. Ahmad, Faizan Ahmad, Sohail Raza, Suleman Khan, B. Wadood, M. Mohibullah","doi":"10.1144/petgeo2022-075","DOIUrl":"https://doi.org/10.1144/petgeo2022-075","url":null,"abstract":"In this study Jurassic-Paleogene strata were investigated to understand the litho-biostratigraphic framework and hydrocarbon source rock potential of various stratal packages. Biostratigraphic controls were used to establish the chronostratigraphic framework of Jurassic-Paleogene strata in the area. The Lower Jurassic (Hettangian) clastics saw an uconformity during Sinmurian-Pliensbachian, while the Lower Jurassic (Toracian) – Middle Jurassic (Bajocian) clastic-carbonate mixed strata is also separated by a Bathonian Unconformity from the Middle Jurassic (Callovian)-Upper Jurassic (Tithonian) carbonate sequence. The Upper Jurassic Oxfordian strata are missing while the Upper Jurassic (Kimmeridgian)- Lower Cretaceous (Velanginian) glaucoconatic sandstone-clays are the conformable sequences. The Lower- Cretaceous (Hauterivian)-Upper Cretaceous (Turonian) clastics is a conformable sequence which is separated by a Coniacian-Santonian unconformity from the Upper Cretaceous (Campanion) pelegic carbonates. The Cretaceous-Tertairy Boundary is marked by laterites while the Paleocene (Thanetian) sequence is represented by a shale and sandstone dominated sequence. The Paleocene (Thanetian)-Early Eocene (Ilerdian) siliciclastic-carbonates mixed sequence marks the last episode of Tethyan sedimentattion. Total Organic Content (TOC), organic petrography and Rock Eval Pyrolysis (REP) techniques were used to evaluate the hydrocarbon source rock potential, kerogen type, level of maturity of the hydrocarbons. The majority of studied samples show the occurrence of type IV kerogen. However, the Middle Jurassic (Callovian)-Upper Jurassic (Tithonian) carbonate sequence of the Samana Suk Formation, the Kimmeridgian-Velanginian Chichali Formation, the Paleocene (Thanetian) sequence of the Hangu Formation, and Paleocene (Thanetian)-Early Eocene (Ilerdian) Patala Formation confirms the Type III kerogen, poor-fair source rock quality, immature-mature, gas-oil prone indigenous hydrocarbon occurrence in the region.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2024-01-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139528479","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
J. Nakajigo, Tor Arne Johansen, J. M. Kiberu, E. Jensen, J. Tiberindwa
In this study, we use the concept of inverse rock physics modelling to analyse reservoir properties of the Kanywataba Exploration area and with focus on their lateral distribution away from the Kanywataba well. The procedure employs rock physics models calibrated for the basin constrained by seismic inversion data where also non-uniqueness and data error propagation issues are taken into account. Both seismic and well log datasets are used in the data calibration. The procedures enable us to obtain the most likely estimate mean, weighted mean and posterior mean of the reservoir properties. We obtain a good match between measured and modelled porosity values. Misfit between observed and predicted lithology is mainly attributed to the uncertainties in defining the correct mineral properties. The integrated approach reveals that high porosities correlates with low clay volumes, furthermore, indicating two distinct reservoir units in the basin interpreted as Oluka and Kakara Formations. Fluid saturation data were less successfully predicted, but was most probably a result of lack of real saturation logs for use in the calibration of rock physics model, instead, predicted saturation logs based on Archie's law were used in the calibration process. This analysis is first of its kind in this basin and therefore exhibits high level of novelty in reservoir property determination of this area.
{"title":"Prediction of reservoir properties using inverse rock physics modelling in Kanywataba Exploration area Albertine Graben","authors":"J. Nakajigo, Tor Arne Johansen, J. M. Kiberu, E. Jensen, J. Tiberindwa","doi":"10.1144/petgeo2023-031","DOIUrl":"https://doi.org/10.1144/petgeo2023-031","url":null,"abstract":"In this study, we use the concept of inverse rock physics modelling to analyse reservoir properties of the Kanywataba Exploration area and with focus on their lateral distribution away from the Kanywataba well. The procedure employs rock physics models calibrated for the basin constrained by seismic inversion data where also non-uniqueness and data error propagation issues are taken into account. Both seismic and well log datasets are used in the data calibration. The procedures enable us to obtain the most likely estimate mean, weighted mean and posterior mean of the reservoir properties. We obtain a good match between measured and modelled porosity values. Misfit between observed and predicted lithology is mainly attributed to the uncertainties in defining the correct mineral properties. The integrated approach reveals that high porosities correlates with low clay volumes, furthermore, indicating two distinct reservoir units in the basin interpreted as Oluka and Kakara Formations. Fluid saturation data were less successfully predicted, but was most probably a result of lack of real saturation logs for use in the calibration of rock physics model, instead, predicted saturation logs based on Archie's law were used in the calibration process. This analysis is first of its kind in this basin and therefore exhibits high level of novelty in reservoir property determination of this area.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2024-01-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139620429","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
J. Greve, Benjamin Busch, Dennis Quandt, Mathias Knaak, C. Hilgers
Former coal mines hosted in Upper Carboniferous silt- and sandstones in the Ruhr Basin, NW Germany, are currently examined for post-mining applications (e.g., geothermal energy) and are also important tight-gas reservoir analogs. Core material from well Pelkum-1, comprising Westphalian A (Bashkirian) delta deposits, was studied. The sandstones and siltstones are generally tight (mean porosity 5.5 %; mean permeability 0.26 mD). Poor reservoir properties primarily result from pronounced mechanical compaction (mean COPL 38.8 %) due to deep burial and high contents of ductile rock fragments. Better reservoir properties in sandstones (> 8 %; > 0.01 mD) are due to (1) lower volumes of ductile grains (< 38 %) that deform during mechanical compaction and (2) higher volumes in feldspar and unstable rock fragments. During burial these form secondary porosity (> 1.5 %) resulting from acidic pore water from organic matter maturation. Still, sandstones with enhanced porosities only show a small increase in permeability since authigenic clays (i.e., kaolinite and illite) or late diagenetic carbonates (i.e., siderite and ferroan dolomite/ankerite) clog secondary porosity. Quartz cementation has a minor impact on reservoir properties. Evaluating the Si/Al ratio can be a suitable proxy to assess grain sizes and may be a convenient tool for further exploration. Supplementary material: https://doi.org/10.6084/m9.figshare.c.7003156
{"title":"The influence of sedimentary facies, mineralogy, and diagenesis on reservoir properties of the coal-bearing Upper Carboniferous of NW Germany","authors":"J. Greve, Benjamin Busch, Dennis Quandt, Mathias Knaak, C. Hilgers","doi":"10.1144/petgeo2023-020","DOIUrl":"https://doi.org/10.1144/petgeo2023-020","url":null,"abstract":"Former coal mines hosted in Upper Carboniferous silt- and sandstones in the Ruhr Basin, NW Germany, are currently examined for post-mining applications (e.g., geothermal energy) and are also important tight-gas reservoir analogs. Core material from well Pelkum-1, comprising Westphalian A (Bashkirian) delta deposits, was studied. The sandstones and siltstones are generally tight (mean porosity 5.5 %; mean permeability 0.26 mD). Poor reservoir properties primarily result from pronounced mechanical compaction (mean COPL 38.8 %) due to deep burial and high contents of ductile rock fragments. Better reservoir properties in sandstones (> 8 %; > 0.01 mD) are due to (1) lower volumes of ductile grains (< 38 %) that deform during mechanical compaction and (2) higher volumes in feldspar and unstable rock fragments. During burial these form secondary porosity (> 1.5 %) resulting from acidic pore water from organic matter maturation. Still, sandstones with enhanced porosities only show a small increase in permeability since authigenic clays (i.e., kaolinite and illite) or late diagenetic carbonates (i.e., siderite and ferroan dolomite/ankerite) clog secondary porosity. Quartz cementation has a minor impact on reservoir properties. Evaluating the Si/Al ratio can be a suitable proxy to assess grain sizes and may be a convenient tool for further exploration.\u0000 \u0000 Supplementary material:\u0000 https://doi.org/10.6084/m9.figshare.c.7003156\u0000","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2024-01-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139444903","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Natural fractures are pervasive in southern Sichuan Basin marine shales, China, and provide a desired opportunity to understand subsurface fracture network in shale reservoirs. Based on cores and electrical imaging logs from vertical and horizontal petroleum wells in southern Sichuan Basin, four types of natural fractures are identified in terms of orientation, size, filling properties, and spatial distribution. The uncemented bed-parallel shear fracture is developed at or in the vicinity of the mechanical interfaces and inclined to present in shale layers with dip angles greater than 12°. The cemented bed-parallel fracture is characterized with crack-seal texture marked by multiple bands of fibrous cement, and its intensity decreases upwards and shows a positive relation with the TOC values. The uncemented bed-oblique fracture is barely developed, and bears limited open space. The cemented bed-oblique/perpendicular fracture is the most developed fracture type and distributed on a regional scale with a pattern of two systematic sets. The results imply that these shale fractures could be formed sequentially by local and regional tectonic deformation, and by abnormally high-pressure. Most natural fractures cannot contribute to reservoir storage or efficiently enhance its permeability yet can act as planes of weakness and be potentially reactivated during hydraulic fracture treatments.
{"title":"Natural fractures at depth in shale reservoirs: new insights from the southern Sichuan Basin marine shales","authors":"Tao Nian, Yuhan Tan, Fengsheng Zhang, Heng Wu, Chengqian Tan, Pengbao Zhang","doi":"10.1144/petgeo2023-071","DOIUrl":"https://doi.org/10.1144/petgeo2023-071","url":null,"abstract":"Natural fractures are pervasive in southern Sichuan Basin marine shales, China, and provide a desired opportunity to understand subsurface fracture network in shale reservoirs. Based on cores and electrical imaging logs from vertical and horizontal petroleum wells in southern Sichuan Basin, four types of natural fractures are identified in terms of orientation, size, filling properties, and spatial distribution. The uncemented bed-parallel shear fracture is developed at or in the vicinity of the mechanical interfaces and inclined to present in shale layers with dip angles greater than 12°. The cemented bed-parallel fracture is characterized with crack-seal texture marked by multiple bands of fibrous cement, and its intensity decreases upwards and shows a positive relation with the TOC values. The uncemented bed-oblique fracture is barely developed, and bears limited open space. The cemented bed-oblique/perpendicular fracture is the most developed fracture type and distributed on a regional scale with a pattern of two systematic sets. The results imply that these shale fractures could be formed sequentially by local and regional tectonic deformation, and by abnormally high-pressure. Most natural fractures cannot contribute to reservoir storage or efficiently enhance its permeability yet can act as planes of weakness and be potentially reactivated during hydraulic fracture treatments.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2024-01-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139384958","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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