Tatsuya Yamada, Kei Yamamoto, Alyazia Alqubaisi, Sami Al Jasmi, H. Uematsu, Keitaro Kojima, Toshiaki Shibasaki, F. Al-Jenaibi
Reservoir simulation is widely used for field development planning in many fields and the evaluation of uncertainty range in production forecast is indispensable to make decision for further investment. Reservoir simulation model consists of geological, petrophysical and reservoir engineering parameters for each cell and cell boundary. These reservoir model parameters are usually defined based on limited available data in consideration of their uncertainty range. Therefore, the identification of influential parameters and the reduction of uncertainty range for these parameters are key components to mitigate the prediction uncertainty. An Upper Jurassic carbonate reservoir in Field A located in offshore Abu Dhabi has long production history for more than 30 years. Field A experienced several development schemes including natural depletion, crestal gas injection and crestal water injection. The current reservoir simulation model reasonably replicates historical performance on pressure, water cut evolution and GOR trend in field and well-by-well scales. On the other hand, we identified some reservoir model parameters have high uncertainty due to reservoir complexity and lack of reliable data. In this study, we focused on the identification of influential parameters on production forecast and the reduction of parameter uncertainty range using an experimental design approach. More than 200 simulation cases were generated with different combination of selected parameters using Latin Hypercube Sampling method. In each case, we evaluated history matching quality in field scale and relationship between history matching quality and each parameter. We found some parameters have correlation with history matching quality independently from the other parameters settings. This means that the uncertain range of those parameters can be reduced to achieve an acceptable history match irrespective of the other parameters. Furthermore, the prediction uncertain range was analyzed using the selected cases showing reasonable history matching quality to investigate the relationship between cumulative oil production and each parameter. The results indicated some parameters have a stronger impact on production forecast and their uncertainty range need to be reduced by further data gathering or considering other mitigation plans. This study successfully demonstrated that the proposed multiple parameter sensitivity analysis by effective use of experimental design approach enables to reduce the parameter uncertain range and identify the key influential parameters. Furthermore, this study result contributes to the prioritization and optimization of future data gathering plan in Field A.
{"title":"Risk Mitigation for Further Development of a Mature Field through Multiple Parameter Sensitivity Study","authors":"Tatsuya Yamada, Kei Yamamoto, Alyazia Alqubaisi, Sami Al Jasmi, H. Uematsu, Keitaro Kojima, Toshiaki Shibasaki, F. Al-Jenaibi","doi":"10.2118/193231-MS","DOIUrl":"https://doi.org/10.2118/193231-MS","url":null,"abstract":"\u0000 Reservoir simulation is widely used for field development planning in many fields and the evaluation of uncertainty range in production forecast is indispensable to make decision for further investment. Reservoir simulation model consists of geological, petrophysical and reservoir engineering parameters for each cell and cell boundary. These reservoir model parameters are usually defined based on limited available data in consideration of their uncertainty range. Therefore, the identification of influential parameters and the reduction of uncertainty range for these parameters are key components to mitigate the prediction uncertainty.\u0000 An Upper Jurassic carbonate reservoir in Field A located in offshore Abu Dhabi has long production history for more than 30 years. Field A experienced several development schemes including natural depletion, crestal gas injection and crestal water injection. The current reservoir simulation model reasonably replicates historical performance on pressure, water cut evolution and GOR trend in field and well-by-well scales. On the other hand, we identified some reservoir model parameters have high uncertainty due to reservoir complexity and lack of reliable data.\u0000 In this study, we focused on the identification of influential parameters on production forecast and the reduction of parameter uncertainty range using an experimental design approach. More than 200 simulation cases were generated with different combination of selected parameters using Latin Hypercube Sampling method. In each case, we evaluated history matching quality in field scale and relationship between history matching quality and each parameter. We found some parameters have correlation with history matching quality independently from the other parameters settings. This means that the uncertain range of those parameters can be reduced to achieve an acceptable history match irrespective of the other parameters. Furthermore, the prediction uncertain range was analyzed using the selected cases showing reasonable history matching quality to investigate the relationship between cumulative oil production and each parameter. The results indicated some parameters have a stronger impact on production forecast and their uncertainty range need to be reduced by further data gathering or considering other mitigation plans. This study successfully demonstrated that the proposed multiple parameter sensitivity analysis by effective use of experimental design approach enables to reduce the parameter uncertain range and identify the key influential parameters. Furthermore, this study result contributes to the prioritization and optimization of future data gathering plan in Field A.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88831583","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The Air Compliance Management Program (ACMP) is a unique project undertaken by the Kuwait Oil Company to identify and address the impact of air pollutants originating from upstream exploration and production operations on the environment in general and on human health in particular. It was the first-ever joint venture of its type between the industry (Kuwait Oil Company) and regulators (Kuwait Environment Public Authority) in this region. The objectives of the project was to utilize various advanced technologies to provide an exemplary way of managing emissions from KOC's operations and reducing their impact on human health. The project included establishing an air quality-monitoring network, developing emissions inventories with dispersion modelling techniques to determine human health risk, developing visual based emission information, using hyperspectral remote imagery for surrogate estimation and remote sensing information for tracking pollutant masses during the project. Subsequently, an innovative source apportionment study was undertaken, utilizing satellite based techniques to define pollutant source contributions from various sources and develop abatement strategies. The study utilized emission data from all sources within Kuwait as well as emissions from marine vessels, road traffic and included regional emissions from other countries as well to estimate KOC's contribution to emissions based on monitored air quality data.
{"title":"Emissions Management and Ambient Air Quality Monitoring in Upstream Oil and Gas Sector - Highlights of KOC's Air Compliance Management Program ACMP as an International Best Practice","authors":"Z. Hussain, Mohammad Haider, Ali Z. Asker","doi":"10.2118/193215-MS","DOIUrl":"https://doi.org/10.2118/193215-MS","url":null,"abstract":"\u0000 The Air Compliance Management Program (ACMP) is a unique project undertaken by the Kuwait Oil Company to identify and address the impact of air pollutants originating from upstream exploration and production operations on the environment in general and on human health in particular. It was the first-ever joint venture of its type between the industry (Kuwait Oil Company) and regulators (Kuwait Environment Public Authority) in this region. The objectives of the project was to utilize various advanced technologies to provide an exemplary way of managing emissions from KOC's operations and reducing their impact on human health.\u0000 The project included establishing an air quality-monitoring network, developing emissions inventories with dispersion modelling techniques to determine human health risk, developing visual based emission information, using hyperspectral remote imagery for surrogate estimation and remote sensing information for tracking pollutant masses during the project. Subsequently, an innovative source apportionment study was undertaken, utilizing satellite based techniques to define pollutant source contributions from various sources and develop abatement strategies. The study utilized emission data from all sources within Kuwait as well as emissions from marine vessels, road traffic and included regional emissions from other countries as well to estimate KOC's contribution to emissions based on monitored air quality data.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"17 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88902930","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
As the industry advances on horizontal drilling and slim hole design, well completion and specifically hydraulic fracture stimulation remains the most expensive part of the well construction process in Unconventionals. Proppant and fluid make up a significant portion of the stimulation cost of a well, it is therefore a key lever in cost reduction. This submission will examine the transition from Conventional to Unconventional stimulation designs with respect to technical and economic factors that drive fluid and proppant optimization. The authors will then focus on the industry journey in multiple step change transitions from high viscosity fluid system with high strength premium proppants towards low viscosity fluid system and lower strength natural proppant. In each case, technical justifications based on theory, laboratory testing, or field trial data from Shell unconventional basins will be discussed. The authors will also briefly review several strategic approaches in proppant and fluid sourcing from the logistics perspective. Relevant cost data will also be used to reflect the overall impact of the evolution. This paper reveals that significant cost reduction can be achieved by right sizing fracture conductivity through reduction on premium high strength proppants and shifting towards a low viscosity system, as well as leveraging appropriate supply chain strategy.
{"title":"Impact of Low Cost Proppant and Fluid Systems in Hydraulic Fracturing of Unconventional Wells","authors":"Bettina Cheung, Scott Hilling, Sean Paul Brierley","doi":"10.2118/193333-MS","DOIUrl":"https://doi.org/10.2118/193333-MS","url":null,"abstract":"\u0000 As the industry advances on horizontal drilling and slim hole design, well completion and specifically hydraulic fracture stimulation remains the most expensive part of the well construction process in Unconventionals.\u0000 Proppant and fluid make up a significant portion of the stimulation cost of a well, it is therefore a key lever in cost reduction. This submission will examine the transition from Conventional to Unconventional stimulation designs with respect to technical and economic factors that drive fluid and proppant optimization.\u0000 The authors will then focus on the industry journey in multiple step change transitions from high viscosity fluid system with high strength premium proppants towards low viscosity fluid system and lower strength natural proppant. In each case, technical justifications based on theory, laboratory testing, or field trial data from Shell unconventional basins will be discussed. The authors will also briefly review several strategic approaches in proppant and fluid sourcing from the logistics perspective. Relevant cost data will also be used to reflect the overall impact of the evolution.\u0000 This paper reveals that significant cost reduction can be achieved by right sizing fracture conductivity through reduction on premium high strength proppants and shifting towards a low viscosity system, as well as leveraging appropriate supply chain strategy.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"38 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85703210","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Jose Ardila Jaimes, Adnan Al Menhali, Sultan Al Yamani, Ayoub Hadj-moussa, M. Saleh
Reservoir-A is a tight oil reservoir (<1 mD) with four subzones. Production from existing wells in this reservoir has been low due to the reservoir tightness (< 500 BPD), dual phases injection program is implemented to support the wells productivity and to increase the overall recovery factor (RF). Building on the success of the Underbalance Drilling and completion technology (UBD) in similar tight reservoirs in ADNOC Onshore fields, the asset team decided to drill one pilot well (Well-1) to minimize the formation damage, practicaly increasing the Productivity Index (PI) and to measure the individual contribution of each subzone to the total well production in order to optimize the lateral length in each subzone to reduce the Unit Technical Cost (TUC). A transient hydraulic flow modelling software was utilized to study how to achieve underbalance conditions and to estimate the reservoir production during the UBD operations The UBD mythology proposed to drill Well-1 includes using crude native oil as a drilling fluid instead of Water Based Mud to minimize the formation damage. Membrane Nitrogen was chosen as a gaseous phase to reduce the effective Bottom Hole Pressure (BHP) below the reservoir pressure to create underbalance condition allowing the reservoir to flow through a four phases separation package that allows separating produced oil and gas to enable reservoir characterisation. To eliminate the need to kill the well during tripping and completion, a Downhole Deployment Valve (DDV) was proposed to be rung on a retrievable tie back casing string that extends from the top of the liner to surface. A transient hydraulic flow modelling software was utilized to study how to achieve underbalance conditions and to estimate the reservoir production during the UBD operations. The engineering evaluation study concluded that UBD is feasible on Well-1, it provided the required UBD equipment capacities to drill Well-1 maintaining UB condition during drilling, tripping and completion operations. A detailed UBD program was compiled by ADNOC onshore and Weatherford teams taking into consideration different anticipated scenarios and contingency plans. Weatherford set up classroom and on-site UBD training for the teams involved in the operation, including ADNOC onshore, rig contractor and other services providers. Having Well-1 in a cluster field adds complexity to the UBD operations and raises new HSE concerns. Moreover, the field exists in environmentally sensitive place close to urban areas and surrounded by sea and mangrove trees. The project team set a detailed HSE plan for the UBD operations on Well-1 involving all stakeholders. A three days HAZID/HAZOP workshop was conducted to identify potential hazards by applying what-if approach to ensure that adequate safeguards are in place before starting the UBD operations. The uniqueness of Well-1 UBD design lies in its comprehensiveness in addressing multiple operational scenarios and in its ability to a
{"title":"Design of Underbalanced Drilling Program to Improve Wells Productivity Index and Characterize Multi Layered Tight Oil Reservoir in an Environmentally Sensitive Field","authors":"Jose Ardila Jaimes, Adnan Al Menhali, Sultan Al Yamani, Ayoub Hadj-moussa, M. Saleh","doi":"10.2118/192827-MS","DOIUrl":"https://doi.org/10.2118/192827-MS","url":null,"abstract":"\u0000 Reservoir-A is a tight oil reservoir (<1 mD) with four subzones. Production from existing wells in this reservoir has been low due to the reservoir tightness (< 500 BPD), dual phases injection program is implemented to support the wells productivity and to increase the overall recovery factor (RF). Building on the success of the Underbalance Drilling and completion technology (UBD) in similar tight reservoirs in ADNOC Onshore fields, the asset team decided to drill one pilot well (Well-1) to minimize the formation damage, practicaly increasing the Productivity Index (PI) and to measure the individual contribution of each subzone to the total well production in order to optimize the lateral length in each subzone to reduce the Unit Technical Cost (TUC).\u0000 A transient hydraulic flow modelling software was utilized to study how to achieve underbalance conditions and to estimate the reservoir production during the UBD operations The UBD mythology proposed to drill Well-1 includes using crude native oil as a drilling fluid instead of Water Based Mud to minimize the formation damage. Membrane Nitrogen was chosen as a gaseous phase to reduce the effective Bottom Hole Pressure (BHP) below the reservoir pressure to create underbalance condition allowing the reservoir to flow through a four phases separation package that allows separating produced oil and gas to enable reservoir characterisation. To eliminate the need to kill the well during tripping and completion, a Downhole Deployment Valve (DDV) was proposed to be rung on a retrievable tie back casing string that extends from the top of the liner to surface. A transient hydraulic flow modelling software was utilized to study how to achieve underbalance conditions and to estimate the reservoir production during the UBD operations.\u0000 The engineering evaluation study concluded that UBD is feasible on Well-1, it provided the required UBD equipment capacities to drill Well-1 maintaining UB condition during drilling, tripping and completion operations. A detailed UBD program was compiled by ADNOC onshore and Weatherford teams taking into consideration different anticipated scenarios and contingency plans. Weatherford set up classroom and on-site UBD training for the teams involved in the operation, including ADNOC onshore, rig contractor and other services providers. Having Well-1 in a cluster field adds complexity to the UBD operations and raises new HSE concerns. Moreover, the field exists in environmentally sensitive place close to urban areas and surrounded by sea and mangrove trees. The project team set a detailed HSE plan for the UBD operations on Well-1 involving all stakeholders. A three days HAZID/HAZOP workshop was conducted to identify potential hazards by applying what-if approach to ensure that adequate safeguards are in place before starting the UBD operations.\u0000 The uniqueness of Well-1 UBD design lies in its comprehensiveness in addressing multiple operational scenarios and in its ability to a","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"60 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86015256","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
B. D. Ribet, Peter K. H. Wang, M. Meers, H. Renick, R. Creath, R. McKee
The objective was to leverage prestack and poststack seismic data in order to reconstruct 3D images of thin, discontinuous, oil-filled packstone pay facies of the Upper and Lower Wolfcamp formation (Sakmarian time: 293-296 Ma). The well-to-seismic tie was carefully established using synthetic seismograms, which enabled the facies log to be properly associated with the corresponding seismic samples. The seismic data were all resampled from 2 ms to 0.5 ms in anticipation of being able to recover facies thicknesses on the order of 2 m. Six neural networks with diverse learning strategies were trained to recognize the nine facies classes in the high-resolution seismic stack: Instantaneous Frequency, Instantaneous Q Factor, Inversion (P-Impedance), Semblance, Dominant Frequency, Most Negative Curvature, and eight Angle Stacks, using a two-stage learning and voting process. At the wells, the nine facies were reconstructed from seismic at a 97% accuracy rate. The bootstrap classification rate, a proxy for blind well testing, was over 80%, which indicates a high-quality modeling process. The pay facies was described with no false positives or false negatives. In the 3D seismic volume between the wells, the procedure produced a Most Likely Facies volume (unsmoothed and smoothed), and nine individual Facies Probability volumes. The pay facies was visualized in a 3D voxel visualization canvas using opacity, and also in a two-way time thickness map. The usable vertical and horizontal resolution was much greater than that of the original seismic. Based on these classification results, additional drilling locations were chosen to further target the oil-filled packstones. The classification results were created by neural networks, which can be used as a substitute for traditional AVO, inversion and cross-plotting techniques for seismic reservoir characterization. The time need to create the Machine Learning results for this small dataset was on the order of ten minutes.
{"title":"Exploring for Wolfcamp Reservoirs, Eastern Shelf of the Permian Basin, USA, Using a Machine Learning Approach","authors":"B. D. Ribet, Peter K. H. Wang, M. Meers, H. Renick, R. Creath, R. McKee","doi":"10.2118/193002-ms","DOIUrl":"https://doi.org/10.2118/193002-ms","url":null,"abstract":"\u0000 \u0000 \u0000 The objective was to leverage prestack and poststack seismic data in order to reconstruct 3D images of thin, discontinuous, oil-filled packstone pay facies of the Upper and Lower Wolfcamp formation (Sakmarian time: 293-296 Ma).\u0000 \u0000 \u0000 \u0000 The well-to-seismic tie was carefully established using synthetic seismograms, which enabled the facies log to be properly associated with the corresponding seismic samples. The seismic data were all resampled from 2 ms to 0.5 ms in anticipation of being able to recover facies thicknesses on the order of 2 m. Six neural networks with diverse learning strategies were trained to recognize the nine facies classes in the high-resolution seismic stack: Instantaneous Frequency, Instantaneous Q Factor, Inversion (P-Impedance), Semblance, Dominant Frequency, Most Negative Curvature, and eight Angle Stacks, using a two-stage learning and voting process.\u0000 \u0000 \u0000 \u0000 At the wells, the nine facies were reconstructed from seismic at a 97% accuracy rate. The bootstrap classification rate, a proxy for blind well testing, was over 80%, which indicates a high-quality modeling process. The pay facies was described with no false positives or false negatives. In the 3D seismic volume between the wells, the procedure produced a Most Likely Facies volume (unsmoothed and smoothed), and nine individual Facies Probability volumes. The pay facies was visualized in a 3D voxel visualization canvas using opacity, and also in a two-way time thickness map. The usable vertical and horizontal resolution was much greater than that of the original seismic. Based on these classification results, additional drilling locations were chosen to further target the oil-filled packstones.\u0000 \u0000 \u0000 \u0000 The classification results were created by neural networks, which can be used as a substitute for traditional AVO, inversion and cross-plotting techniques for seismic reservoir characterization. The time need to create the Machine Learning results for this small dataset was on the order of ten minutes.\u0000","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"81 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91152770","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Riaz Khan, M. Salib, Ali Ba Hussain, Atiqurrahman Bin Abd Rashid, G. Aydinoglu, U. Farooq
In this study field, the objective was to identify the causes of low resistivity pay that was limited towards the southwest of the field. Restricting the focus only on diagenesis has not yielded conclusive explanations to delineate the affected area. Alternatively, investigating the influence of structural evolution (folding and tilting) on hydrocarbon charging mechanism and diagenesis has significantly contributed to a reasonable explanation. This, in turn, can potentially impact decisions related to reservoir characterization and field development planning. The field has adequate coverage of data from vertical (appraisal and observers) and horizontal wells (producers and injectors). The approach of structural flattening at different time intervals was applied in understanding the structural evolution of the field as part of regional tectonic history of the area. The delineation of areas in different paleo-positions has helped in grouping Wells into categories for thorough investigation. Detailed analyses of conventional and advanced logs, and core data were performed which included: petrographic analysis, pore throat and bound water evaluation, and assessment of resistivity log signatures in reference to the paleo-positions of the Wells. The structural evolution and corresponding hydrocarbon charging mechanisms (drainage and imbibition) have influenced the reservoir hydrocarbon saturation in the field from northeast to southwest. The northeast tilting was triggered by Zagros loading, combined with thermal uplift associated with Red Sea opening. This resulted in imbibition in the extreme northeast and second phase of primary drainage in the extreme southwest of the field. As a result, the area that was previously in water leg during early Tertiary provided more exposure to diagenetic processes which enhanced the total porosity (up to 5p.u.) with high bound water and low resistivity pay. The areal coverage within water leg has been well defined in this study by evaluating the positions of paleo structural closures and hydrocarbon charging mechanisms. This would be useful in capturing diagenetic overprint in properties modeling as well as defining appropriate rock types for better saturation height function and volumetric estimations in this area. Consequently, the field development strategy was to develop the central area, in the first phase, since it was less affected by fluids saturation variations caused by the structural evolution. The study has provided improvement in reservoir characterization techniques for well placement and enhanced field development planning. The methodology and approach used in this study are usually applied, to some extent, during exploration stages or basin modeling at regional scale with limited data availability and it is not utilized enough for Well placement and reserves estimations in the development stage. The approach applied here, with substantial data availability and integration, can potentially help i
{"title":"Understanding the Influence of Structural Evolution Folding and Tilting on Hydrocarbon Accumulation Drainage and Imbibition and Reservoir Quality Diagenesis for Enhanced Field Development Planning, a Case Study of Lower Cretaceous Carbonate Reservoir, Abu Dhabi, UAE","authors":"Riaz Khan, M. Salib, Ali Ba Hussain, Atiqurrahman Bin Abd Rashid, G. Aydinoglu, U. Farooq","doi":"10.2118/193237-MS","DOIUrl":"https://doi.org/10.2118/193237-MS","url":null,"abstract":"\u0000 In this study field, the objective was to identify the causes of low resistivity pay that was limited towards the southwest of the field. Restricting the focus only on diagenesis has not yielded conclusive explanations to delineate the affected area. Alternatively, investigating the influence of structural evolution (folding and tilting) on hydrocarbon charging mechanism and diagenesis has significantly contributed to a reasonable explanation. This, in turn, can potentially impact decisions related to reservoir characterization and field development planning.\u0000 The field has adequate coverage of data from vertical (appraisal and observers) and horizontal wells (producers and injectors). The approach of structural flattening at different time intervals was applied in understanding the structural evolution of the field as part of regional tectonic history of the area. The delineation of areas in different paleo-positions has helped in grouping Wells into categories for thorough investigation. Detailed analyses of conventional and advanced logs, and core data were performed which included: petrographic analysis, pore throat and bound water evaluation, and assessment of resistivity log signatures in reference to the paleo-positions of the Wells.\u0000 The structural evolution and corresponding hydrocarbon charging mechanisms (drainage and imbibition) have influenced the reservoir hydrocarbon saturation in the field from northeast to southwest. The northeast tilting was triggered by Zagros loading, combined with thermal uplift associated with Red Sea opening. This resulted in imbibition in the extreme northeast and second phase of primary drainage in the extreme southwest of the field. As a result, the area that was previously in water leg during early Tertiary provided more exposure to diagenetic processes which enhanced the total porosity (up to 5p.u.) with high bound water and low resistivity pay. The areal coverage within water leg has been well defined in this study by evaluating the positions of paleo structural closures and hydrocarbon charging mechanisms. This would be useful in capturing diagenetic overprint in properties modeling as well as defining appropriate rock types for better saturation height function and volumetric estimations in this area. Consequently, the field development strategy was to develop the central area, in the first phase, since it was less affected by fluids saturation variations caused by the structural evolution. The study has provided improvement in reservoir characterization techniques for well placement and enhanced field development planning.\u0000 The methodology and approach used in this study are usually applied, to some extent, during exploration stages or basin modeling at regional scale with limited data availability and it is not utilized enough for Well placement and reserves estimations in the development stage. The approach applied here, with substantial data availability and integration, can potentially help i","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"37 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88575104","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
S. Hati, Hemlata Chawla, Arnab Ghosh, U. Guru, B. Ray, R. Guru, Sambit Pattanaik
As oil and gas exploration and development forays into unconventional plays, more specifically, basement exploration, its characterization and understanding have become very important. The present study aims at understanding the reservoir quality in terms of complex mineralogy and lithology variations, porosity, fracture properties and distribution near and away from the borehole using an integrated approach with the help of elemental spectroscopy, borehole acoustic imager, borehole micro-resistivity imager, nuclear magnetic resonance and borehole acoustic reflection survey. A comprehensive petrophysical characterization of different mineralo-facies of basement was carried out using elemental spectroscopy, formation micro-resistivity imager, borehole acoustic imager and combinable magnetic resonance along with basic open-hole data. Two distinct rock groups were identified – silica rich, iron poor zones having open fractures with good fracture density, porosity and aperture and silica poor, iron rich zones with no open fractures, poor fracture density, porosity and apertures. The zones with open fractures were the prime zones identified for further testing and completion. However, the near well bore analysis could not explain the oil flow from one zone having open fractures, whereas another similar zone showed no flow. Borehole Acoustic Reflection Survey processing was attempted to understand how extent of fractures beyond the borehole wall contributed to productivity from a well. The presence of laterally continuous fracture network at an interval that coincides with the depths from which the well is flowing, in turn validated from production log data, explained fluid flow from basement. Furthermore, the absence of such network can cause no flow even though near well-bore possible open fractures are present. Present study established the fact that, identification of potential open fractured zones in basement is a lead for reservoir zone delineation, however, a lateral extent of such basement reservoir facies is the key for successful basement hydrocarbon exploration.
{"title":"A Comprehensive Reservoir Quality Characterization for Fractured Basements in India","authors":"S. Hati, Hemlata Chawla, Arnab Ghosh, U. Guru, B. Ray, R. Guru, Sambit Pattanaik","doi":"10.2118/193092-MS","DOIUrl":"https://doi.org/10.2118/193092-MS","url":null,"abstract":"\u0000 As oil and gas exploration and development forays into unconventional plays, more specifically, basement exploration, its characterization and understanding have become very important. The present study aims at understanding the reservoir quality in terms of complex mineralogy and lithology variations, porosity, fracture properties and distribution near and away from the borehole using an integrated approach with the help of elemental spectroscopy, borehole acoustic imager, borehole micro-resistivity imager, nuclear magnetic resonance and borehole acoustic reflection survey.\u0000 A comprehensive petrophysical characterization of different mineralo-facies of basement was carried out using elemental spectroscopy, formation micro-resistivity imager, borehole acoustic imager and combinable magnetic resonance along with basic open-hole data. Two distinct rock groups were identified – silica rich, iron poor zones having open fractures with good fracture density, porosity and aperture and silica poor, iron rich zones with no open fractures, poor fracture density, porosity and apertures. The zones with open fractures were the prime zones identified for further testing and completion. However, the near well bore analysis could not explain the oil flow from one zone having open fractures, whereas another similar zone showed no flow.\u0000 Borehole Acoustic Reflection Survey processing was attempted to understand how extent of fractures beyond the borehole wall contributed to productivity from a well. The presence of laterally continuous fracture network at an interval that coincides with the depths from which the well is flowing, in turn validated from production log data, explained fluid flow from basement. Furthermore, the absence of such network can cause no flow even though near well-bore possible open fractures are present.\u0000 Present study established the fact that, identification of potential open fractured zones in basement is a lead for reservoir zone delineation, however, a lateral extent of such basement reservoir facies is the key for successful basement hydrocarbon exploration.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84097772","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Sasidharan Adiyodi Kenoth, John Kottappuram, S. Henry
The oil and gas industry is in continuous look out of innovative means to improve the efficiency of its energy-intensive oil- and gas-processing operations through improved energy use and waste-heat recovery. This paper details about an integrated pilot application of two waste-heat-recovery units designed and implemented in an Offshore platform off Caspian Sea. Actual results are compared with simulation / design results. A thermodynamic analysis of a gas generator engine waste-heat-recovery cycle is carried out. The offshore platform has a water injection plant supporting water flooding project for reservoir pressure maintenance. The Sea Water Lift and Main Injection Pumps are powered by multiple Gas Engine Generators of @ 1000 kW power rating. The exhaust gas from each of these gas engine contains approximately 10 million Btu/hr recoverable heat. Also the heat energy from the jacket cooling water used for engine cooling is used for heating the waxy crude oil and natural gas. A Shell & Tube Heat exchanger is used for recovering the heat energy. By utilizing the heat energy of flue gas and jacket cooling water the energy efficiency of gas engine can be doubled from 35% to 75 %. Two such Gas Generators with Heat Recovery system has been introduced which collectively creates an energy saving of approximately 1500 KW daily for crude oil heating. Approximately 8000 bbl oil with 100 scf/bbl gas oil ratio was able to heat to get a temperature differential of 25-35 degree C. The cooling water temperature was dropped to 60 degree C. With rising fuel costs, energy conservation has taken on added significance. Installation of waste heat recovery units (WHRU's) on gas turbines is one method used in the past to reduce gas plant fuel consumption. More recently, waste heat recovery on multiple reciprocating compressor engines also has been identified as having energy conservation potential. This paper reviews the development and implementation of a WHRU potential. This enhance hydrocarbon recovery, and reduce utility cost in a plant. In an era when energy conservation and fuel shortages are not uncommon, mechanical systems designed to improve the thermal efficiency of fuel-consuming equipment have become a necessity. This paper presents an energy efficient process and mechanical design along with footprint saving.
{"title":"Case Study of Pilot Application and Efficiency Analysis of Waste Heat Recovery from Gas Engine Generator Jacket Cooling Water to Heat Waxy Multiphase Fluid at Offshore Platform","authors":"Sasidharan Adiyodi Kenoth, John Kottappuram, S. Henry","doi":"10.2118/192654-MS","DOIUrl":"https://doi.org/10.2118/192654-MS","url":null,"abstract":"\u0000 The oil and gas industry is in continuous look out of innovative means to improve the efficiency of its energy-intensive oil- and gas-processing operations through improved energy use and waste-heat recovery. This paper details about an integrated pilot application of two waste-heat-recovery units designed and implemented in an Offshore platform off Caspian Sea. Actual results are compared with simulation / design results. A thermodynamic analysis of a gas generator engine waste-heat-recovery cycle is carried out.\u0000 The offshore platform has a water injection plant supporting water flooding project for reservoir pressure maintenance. The Sea Water Lift and Main Injection Pumps are powered by multiple Gas Engine Generators of @ 1000 kW power rating. The exhaust gas from each of these gas engine contains approximately 10 million Btu/hr recoverable heat. Also the heat energy from the jacket cooling water used for engine cooling is used for heating the waxy crude oil and natural gas. A Shell & Tube Heat exchanger is used for recovering the heat energy.\u0000 By utilizing the heat energy of flue gas and jacket cooling water the energy efficiency of gas engine can be doubled from 35% to 75 %. Two such Gas Generators with Heat Recovery system has been introduced which collectively creates an energy saving of approximately 1500 KW daily for crude oil heating. Approximately 8000 bbl oil with 100 scf/bbl gas oil ratio was able to heat to get a temperature differential of 25-35 degree C. The cooling water temperature was dropped to 60 degree C.\u0000 With rising fuel costs, energy conservation has taken on added significance. Installation of waste heat recovery units (WHRU's) on gas turbines is one method used in the past to reduce gas plant fuel consumption. More recently, waste heat recovery on multiple reciprocating compressor engines also has been identified as having energy conservation potential. This paper reviews the development and implementation of a WHRU potential. This enhance hydrocarbon recovery, and reduce utility cost in a plant.\u0000 In an era when energy conservation and fuel shortages are not uncommon, mechanical systems designed to improve the thermal efficiency of fuel-consuming equipment have become a necessity. This paper presents an energy efficient process and mechanical design along with footprint saving.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82471644","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Mingsheng Lv, Saeed K. Al Suwaidi, Yingzhang Ji, A. S. Swain, M. A. Shehhi, Beiwei Luo, D. Mao, Minqiang Jia, Douhong Zi, Jin Zhu, Yungang Ji
Western Abu Dhabi locates in the west of Rub Al Khali Basin, which is an intra-shelf basin during the Late Cretaceous. The Shilaif source, Mishrif reservoir and Tuwayil seal forms one of the Upper Cretaceous important petroleum systems in the western Abu Dhabi Onshore. However, less commercial discoveries have been achieved within Mishrif Formation during the past 60 years since the large scale structures were not developed in western Abu Dhabi and the stratigraphic traps have not been attracted attention. This study aims to investigate the exploration potential of both Mishrif structural and stratigraphic traps. It provided detailed study on Shilaif source rock, Mishrif shoal/reef reservoir and Tuwayil seal capability. Oil-source rock correlation, reservoir predication and basin modeling have been carried out for building Mishrif hydrocarbon accumulation model by integration of samplings, wire loggings and 2D&3D seismic data. Shilaif Formation is composed of laminated, organic-rich, bioclastic and argillaceous lime-mudstones and its generated hydrocarbon migrated trending to high structures. Three progradational reefs/shoals in Mishrif Formation were deposited along the platform margin, which are characterized by high porosity and permeability. Tuwayil Formation consists of 10-15ft shale interbedding with tight sandstone, acting as the cap rock of Mishrif reservoirs. Mishrif hydrocarbon accumulation mechanism has been summarized as a model of structural background controls on hydrocarbon migration trend and shoal/reef controls on hydrocarbon accumulation. It is consequently concluded that Mishrif reefs/shoals overlapping with structural background are the favorable exploration prospects, and oil charging is controlled by heterogeneity inside a reef/shoal, the higher porosity and permeability, the higher oil saturation. Two wells have been proposed based on the hydrocarbon accumulation model, and discovered a stratigraphic reservoir with high testing production. This discovery encourages a new idea for stratigraphic traps exploration, as well as implicates the great exploration potential in western Abu Dhabi.
Abu Dhabi西部位于Rub Al Khali盆地西部，该盆地是晚白垩纪时期的陆架内盆地。Shilaif烃源、Mishrif储层和Tuwayil密封构成了阿布扎比西部上白垩统重要的油气系统之一。然而，在过去的60年里，由于阿布扎比西部没有大规模的构造发育，地层圈闭也没有引起人们的注意，Mishrif组的商业发现较少。本研究旨在探讨Mishrif构造圈闭和地层圈闭的勘探潜力。详细研究了石莱夫烃源岩、Mishrif滩礁储层和图瓦伊尔封印能力。通过采样、有线测井和二维、三维地震资料相结合，进行了油源对比、储层预测和盆地建模，建立了Mishrif油气成藏模型。石莱夫组由层状、富有机质、生物碎屑、泥质灰岩组成，生烃向高层构造运移。米什里夫组沿台地边缘沉积了3个前积礁滩，具有高孔隙度和高渗透率的特点。Tuwayil组由10-15英尺的页岩与致密砂岩互层组成，是Mishrif储层的盖层。Mishrif成藏机制被总结为构造背景控制油气运移趋势和滩礁控制油气成藏的模式。认为与构造背景重叠的Mishrif礁滩具有良好的勘探前景，油气充注受礁滩内部非均质性控制，孔隙度和渗透率越高，含油饱和度越高。根据油气成藏模式，提出了两口井，发现了一个测试产量高的地层储层。这一发现为地层圈闭勘探提供了新的思路，也暗示了阿布扎比西部地区巨大的勘探潜力。
{"title":"Hydrocarbon Accumulation Model of Upper Cretaceous Mishrif Formation and Oilfield Discovery in Western Abu Dhabi","authors":"Mingsheng Lv, Saeed K. Al Suwaidi, Yingzhang Ji, A. S. Swain, M. A. Shehhi, Beiwei Luo, D. Mao, Minqiang Jia, Douhong Zi, Jin Zhu, Yungang Ji","doi":"10.2118/192635-MS","DOIUrl":"https://doi.org/10.2118/192635-MS","url":null,"abstract":"\u0000 Western Abu Dhabi locates in the west of Rub Al Khali Basin, which is an intra-shelf basin during the Late Cretaceous. The Shilaif source, Mishrif reservoir and Tuwayil seal forms one of the Upper Cretaceous important petroleum systems in the western Abu Dhabi Onshore. However, less commercial discoveries have been achieved within Mishrif Formation during the past 60 years since the large scale structures were not developed in western Abu Dhabi and the stratigraphic traps have not been attracted attention.\u0000 This study aims to investigate the exploration potential of both Mishrif structural and stratigraphic traps. It provided detailed study on Shilaif source rock, Mishrif shoal/reef reservoir and Tuwayil seal capability. Oil-source rock correlation, reservoir predication and basin modeling have been carried out for building Mishrif hydrocarbon accumulation model by integration of samplings, wire loggings and 2D&3D seismic data. Shilaif Formation is composed of laminated, organic-rich, bioclastic and argillaceous lime-mudstones and its generated hydrocarbon migrated trending to high structures. Three progradational reefs/shoals in Mishrif Formation were deposited along the platform margin, which are characterized by high porosity and permeability. Tuwayil Formation consists of 10-15ft shale interbedding with tight sandstone, acting as the cap rock of Mishrif reservoirs.\u0000 Mishrif hydrocarbon accumulation mechanism has been summarized as a model of structural background controls on hydrocarbon migration trend and shoal/reef controls on hydrocarbon accumulation. It is consequently concluded that Mishrif reefs/shoals overlapping with structural background are the favorable exploration prospects, and oil charging is controlled by heterogeneity inside a reef/shoal, the higher porosity and permeability, the higher oil saturation. Two wells have been proposed based on the hydrocarbon accumulation model, and discovered a stratigraphic reservoir with high testing production. This discovery encourages a new idea for stratigraphic traps exploration, as well as implicates the great exploration potential in western Abu Dhabi.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"29 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81740128","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The Lower Cretaceous McMurray Formation in western Canada has over 1.8 trillion barrels of bitumen resource in place. Due to the bitumen in its natural state having a very low API (6-12°) and corresponding high viscosity, traditional primary (pump jacks) and secondary (water flood) recovery techniques cannot be used. Instead, economic extraction of the bitumen occurs via surface mining and subsurface steam-assisted gravity drainage (SAGD). Using the Pike and Jackfish oil sands project areas as a case study, it will be shown that successful SAGD operations requires a thorough understanding of the depositional fabric and stratigraphic architecture of the reservoir. Within the study area, reservoir intervals in the form of cross-bedded sandstones and sandy inclined heterolithic strata (IHS) are present within both the middle and upper McMurray. Overlying the middle McMurray are upper McMurray parasequence cycles reflective of brackish bays and deltaic embayment deposits. In many areas, however, these parasequences are absent and instead substituted by fluvial channels with brackish water overprint. The facies within these fluvial channels are very similar in character to the those seen within the middle McMurray. To help progress our understanding of baffles and barriers to flow within these aforementioned reservoir facies, dip meter and seismic data are presented as data that can be used. From this, a better understanding of the complex interplay of facies and stratigraphic relationships can be made. More importantly, clearer insights into SAGD performance (pre- and post-steam) can also be achieved. Using the McMurray Formation as an underpinning, the wider implications of understanding fluvial sedimentation will be addressed by using reservoirs from the Middle East as examples. For example, many siliciclastic reservoirs in locations such as Kuwait (Wara Formation) and Iraq (Zubair Formation) are also influenced to a large degree by fluvial sedimentation. Not unlike SAGD, any successful secondary recovery techniques applied within these reservoirs will also require a detailed characterization of the channel stacking patterns and channel orientations prior to implementation.
{"title":"Overview of Reservoir Deposits in the Pike and Jackfish Oil Sands Project Areas, Southern Athabasca Oil Sands, Canada","authors":"G. Baniak, E. M. Caddel, Kelly G. Kingsmith","doi":"10.2118/193065-MS","DOIUrl":"https://doi.org/10.2118/193065-MS","url":null,"abstract":"\u0000 The Lower Cretaceous McMurray Formation in western Canada has over 1.8 trillion barrels of bitumen resource in place. Due to the bitumen in its natural state having a very low API (6-12°) and corresponding high viscosity, traditional primary (pump jacks) and secondary (water flood) recovery techniques cannot be used. Instead, economic extraction of the bitumen occurs via surface mining and subsurface steam-assisted gravity drainage (SAGD). Using the Pike and Jackfish oil sands project areas as a case study, it will be shown that successful SAGD operations requires a thorough understanding of the depositional fabric and stratigraphic architecture of the reservoir.\u0000 Within the study area, reservoir intervals in the form of cross-bedded sandstones and sandy inclined heterolithic strata (IHS) are present within both the middle and upper McMurray. Overlying the middle McMurray are upper McMurray parasequence cycles reflective of brackish bays and deltaic embayment deposits. In many areas, however, these parasequences are absent and instead substituted by fluvial channels with brackish water overprint. The facies within these fluvial channels are very similar in character to the those seen within the middle McMurray. To help progress our understanding of baffles and barriers to flow within these aforementioned reservoir facies, dip meter and seismic data are presented as data that can be used. From this, a better understanding of the complex interplay of facies and stratigraphic relationships can be made. More importantly, clearer insights into SAGD performance (pre- and post-steam) can also be achieved.\u0000 Using the McMurray Formation as an underpinning, the wider implications of understanding fluvial sedimentation will be addressed by using reservoirs from the Middle East as examples. For example, many siliciclastic reservoirs in locations such as Kuwait (Wara Formation) and Iraq (Zubair Formation) are also influenced to a large degree by fluvial sedimentation. Not unlike SAGD, any successful secondary recovery techniques applied within these reservoirs will also require a detailed characterization of the channel stacking patterns and channel orientations prior to implementation.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":" 44","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91412011","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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