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}
Mahmoudreza Jazayeri Noushabadi, A. Brisset, S. Thibeau
Carbon Capture, Utilization and Storage (CCUS) accounts for around 14% of the cumulative emissions reductions needed through 2050 (IEA, 2016) in its 2°C scenario. Deep saline aquifers were recognized as the largest potential storage resource available worldwide for CO2 storage into geological formations. Securing the geological storage of CO2 is mandatory with this kind of project. Indeed, under specific conditions, the resulting pressure build-up of a CO2 injection into an aquifer can possibly lead to leak into shallow geological aquifers or atmosphere through preferential pathways such as geological faults and wells. The brine extraction is envisaged to decrease the reservoir pressure build-up while injecting CO2. In this study, an investigation was made to use a part of this extracted brine to increase the CO2 storage security by accelerating both residual and solubility trapping mechanisms through the deployment of water (W) alternative CO2 (G) injection (WAG_CCS) at field scale. If this alternative CO2 injection process gives interesting results, then this approach will also lead to the reduction of the duration of post-injection site monitoring. In addition, the WAG_CCS process may help increasing the sweep efficiency of CO2 by controlling the mobility ratio and consequently improving the storage capacity. Several WAG_CCS pattern models were simulated with Eclipse software to investigate the impact of the method. A real geological model of an aquifer (Sleipner model, public data) was used for the simulations. As simulation base case, the CO2 is injected into the aquifer through one injection well for a period of 25 years followed by a 3500 years post injection simulation. Several other injection scenarios are simulated where water (W) is extracted from the same formation and partly reinjected alternatively with CO2 (G). The injection period schedules are as follow: 3months(G)-3months(W) to 1year(G)-1year(W). The mobile gas volume (structural trapping) and residual gas volume and dissolved gas volume (solubility trapping) are compared for all simulated cases. An experimental design screening was implemented in order to investigate the impact of several parameters such as well numbers, permeability, critical gas saturation… The results of this study gave answers to the WAG_CCS process efficiency in CO2 geological storage. It can be concluded that it can (1) be efficient under realistic geological conditions; (2) speed up the capillary trapping mechanism; (3) accelerate the dissolution trapping mechanism; (4) control the CO2 mobility and increase the sweep efficiency of CO2; and (5) help to manage project risks. The water extraction from an aquifer during the CO2 storage is a subject which was already studied and proposed in several publications but the utilization of the extracted water is still a research subject. Extracted water desalinization, reinjection in depleted formations, surface dissolution of CO2 within the extracted water b
{"title":"Investigation of CO2 Storage Security Increase by Brine Alternative CO2 Injection WAG_CCS","authors":"Mahmoudreza Jazayeri Noushabadi, A. Brisset, S. Thibeau","doi":"10.2118/193250-MS","DOIUrl":"https://doi.org/10.2118/193250-MS","url":null,"abstract":"\u0000 Carbon Capture, Utilization and Storage (CCUS) accounts for around 14% of the cumulative emissions reductions needed through 2050 (IEA, 2016) in its 2°C scenario. Deep saline aquifers were recognized as the largest potential storage resource available worldwide for CO2 storage into geological formations. Securing the geological storage of CO2 is mandatory with this kind of project. Indeed, under specific conditions, the resulting pressure build-up of a CO2 injection into an aquifer can possibly lead to leak into shallow geological aquifers or atmosphere through preferential pathways such as geological faults and wells. The brine extraction is envisaged to decrease the reservoir pressure build-up while injecting CO2. In this study, an investigation was made to use a part of this extracted brine to increase the CO2 storage security by accelerating both residual and solubility trapping mechanisms through the deployment of water (W) alternative CO2 (G) injection (WAG_CCS) at field scale. If this alternative CO2 injection process gives interesting results, then this approach will also lead to the reduction of the duration of post-injection site monitoring. In addition, the WAG_CCS process may help increasing the sweep efficiency of CO2 by controlling the mobility ratio and consequently improving the storage capacity.\u0000 Several WAG_CCS pattern models were simulated with Eclipse software to investigate the impact of the method. A real geological model of an aquifer (Sleipner model, public data) was used for the simulations. As simulation base case, the CO2 is injected into the aquifer through one injection well for a period of 25 years followed by a 3500 years post injection simulation. Several other injection scenarios are simulated where water (W) is extracted from the same formation and partly reinjected alternatively with CO2 (G). The injection period schedules are as follow: 3months(G)-3months(W) to 1year(G)-1year(W). The mobile gas volume (structural trapping) and residual gas volume and dissolved gas volume (solubility trapping) are compared for all simulated cases.\u0000 An experimental design screening was implemented in order to investigate the impact of several parameters such as well numbers, permeability, critical gas saturation…\u0000 The results of this study gave answers to the WAG_CCS process efficiency in CO2 geological storage. It can be concluded that it can (1) be efficient under realistic geological conditions; (2) speed up the capillary trapping mechanism; (3) accelerate the dissolution trapping mechanism; (4) control the CO2 mobility and increase the sweep efficiency of CO2; and (5) help to manage project risks.\u0000 The water extraction from an aquifer during the CO2 storage is a subject which was already studied and proposed in several publications but the utilization of the extracted water is still a research subject. Extracted water desalinization, reinjection in depleted formations, surface dissolution of CO2 within the extracted water b","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":"81079374","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}
Abu Al Bukhoosh (ABK) is an oil and gas field located 180 kilometers away from the Abu Dhabi's coast and has been in operation since 1974. The complex was gradually developed over the past forty years, and has some aging platforms and facilities. As a consequence the problems related to Asset Integrity is one of the most important with regards to Operations Risk Management. Repairs or intervention activities must have very specific and rigorous plans for addressing barriers to prevent uncontrollable loss of containment from the wellbore to the external environment. Hence continuous monitoring and integrity management of the field is mandatory for long-term profitability and HSE performance in an aging asset like ABK. Asset Integrity is usually well covered during technical discussions and meetings, and is usually considered as a subject matter expert topic. However Asset Integrity and its associated technological risks are usually less discussed during general events involving the whole organization. This is more limited to operational safety KPI's, the protection of the environment and the prevention of accidents to people. These are easier topics to discuss and are more suited to the corporate communication materials.
Abu Al Bukhoosh (ABK)是一个油气田，距离阿布扎比海岸180公里，自1974年以来一直在运营。该综合体是在过去四十年中逐步发展起来的，有一些老化的平台和设施。因此，与资产完整性相关的问题是运营风险管理中最重要的问题之一。维修或干预活动必须有非常具体和严格的计划来解决障碍，以防止从井筒到外部环境的不可控制的密封泄漏。因此，对于像ABK这样的老旧资产来说，为了长期盈利和HSE表现，必须对油田进行持续监测和完整性管理。资产完整性通常在技术讨论和会议中被很好地涵盖，并且通常被认为是一个主题专家主题。然而，在涉及整个组织的一般事件中，通常很少讨论资产完整性及其相关的技术风险。这更局限于操作安全KPI，保护环境和防止人员事故。这些是比较容易讨论的话题，也更适合公司沟通材料。
{"title":"GIS: The Global Risk Mapping Towards Digital","authors":"Benoit Gouviez, B. George, Mouna Nizar","doi":"10.2118/192977-MS","DOIUrl":"https://doi.org/10.2118/192977-MS","url":null,"abstract":"\u0000 Abu Al Bukhoosh (ABK) is an oil and gas field located 180 kilometers away from the Abu Dhabi's coast and has been in operation since 1974. The complex was gradually developed over the past forty years, and has some aging platforms and facilities.\u0000 As a consequence the problems related to Asset Integrity is one of the most important with regards to Operations Risk Management. Repairs or intervention activities must have very specific and rigorous plans for addressing barriers to prevent uncontrollable loss of containment from the wellbore to the external environment. Hence continuous monitoring and integrity management of the field is mandatory for long-term profitability and HSE performance in an aging asset like ABK.\u0000 Asset Integrity is usually well covered during technical discussions and meetings, and is usually considered as a subject matter expert topic. However Asset Integrity and its associated technological risks are usually less discussed during general events involving the whole organization. This is more limited to operational safety KPI's, the protection of the environment and the prevention of accidents to people. These are easier topics to discuss and are more suited to the corporate communication materials.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"35 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":"79624081","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}
S. Hirano, Toshiyuki Sunaba, Manea Saeed Al Jaberi, Faisal Al Alawi
CO2 corrosion is a vital problem in oil and gas production. The carbon steel pipe can suffer a long-term use economically under the CO2 corrosion environment by choosing an appropriate corrosion inhibitor. The performance of several corrosion inhibitors at elevated temperature & high salinity CO2 rich condition was evaluated for a field application. The performance of corrosion inhibitors was evaluated with an electrochemical measurement namely Liner Polarization Resistance (LPR) and weight loss coupons in autoclaves. LPR measures in-situ corrosion rate and it shows the inhibitor adhesion behavior on the metal surface. In the weight loss test, test coupons were mounted in a rotating cage and immersed in the test solution for a week. Test solution was synthetic brines with Total Dissolved Solids (TDS) 17%. The test solution was aerated with CO2 at ambient temperature and pressure before the corrosion test. It is well known that the inhibitor efficiency is encumbered with many variables, such as temperature, pressure, pH, flow speed and chemical composition of the production fluid. Salt content of formation water varies dependent on the location. Sometimes a production water analysis of a Middle East oil well shows more than 10% by weight. The inhibitors evaluated here had the temperature tolerance up to 100 °C and the same was the maximum test temperature. Some corrosion inhibitors performed better at low temperature than at high temperature. They showed poor inhibitor efficiency in case of pre-corrosion with high salinity at high temperature condition. This study also confirmed the validity of ILSS (Inhibitor Likelihood Success Score) introduced by Crossland et al. The score which was later acknowledged by HSE Office (UK) provided a useful information for inhibitor selection for pipelines in various field conditions. Several corrosion testing procedures were carried out to confirm the associated impact with/without pre-corrosion on the overall performance of the corrosion inhibitors. It seems that high salinity affects the inhibitor adhesion competing with corrosion product. The pre-corrosion test is an indispensable step for a qualification of corrosion inhibitors for a high salinity field.
{"title":"Evaluation of Corrosion Inhibitor Performance Under High Temperature / High Salinity Sweet Conditions","authors":"S. Hirano, Toshiyuki Sunaba, Manea Saeed Al Jaberi, Faisal Al Alawi","doi":"10.2118/193016-MS","DOIUrl":"https://doi.org/10.2118/193016-MS","url":null,"abstract":"\u0000 CO2 corrosion is a vital problem in oil and gas production. The carbon steel pipe can suffer a long-term use economically under the CO2 corrosion environment by choosing an appropriate corrosion inhibitor. The performance of several corrosion inhibitors at elevated temperature & high salinity CO2 rich condition was evaluated for a field application.\u0000 The performance of corrosion inhibitors was evaluated with an electrochemical measurement namely Liner Polarization Resistance (LPR) and weight loss coupons in autoclaves. LPR measures in-situ corrosion rate and it shows the inhibitor adhesion behavior on the metal surface. In the weight loss test, test coupons were mounted in a rotating cage and immersed in the test solution for a week. Test solution was synthetic brines with Total Dissolved Solids (TDS) 17%. The test solution was aerated with CO2 at ambient temperature and pressure before the corrosion test.\u0000 It is well known that the inhibitor efficiency is encumbered with many variables, such as temperature, pressure, pH, flow speed and chemical composition of the production fluid. Salt content of formation water varies dependent on the location. Sometimes a production water analysis of a Middle East oil well shows more than 10% by weight. The inhibitors evaluated here had the temperature tolerance up to 100 °C and the same was the maximum test temperature. Some corrosion inhibitors performed better at low temperature than at high temperature. They showed poor inhibitor efficiency in case of pre-corrosion with high salinity at high temperature condition. This study also confirmed the validity of ILSS (Inhibitor Likelihood Success Score) introduced by Crossland et al. The score which was later acknowledged by HSE Office (UK) provided a useful information for inhibitor selection for pipelines in various field conditions.\u0000 Several corrosion testing procedures were carried out to confirm the associated impact with/without pre-corrosion on the overall performance of the corrosion inhibitors. It seems that high salinity affects the inhibitor adhesion competing with corrosion product. The pre-corrosion test is an indispensable step for a qualification of corrosion inhibitors for a high salinity field.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90062955","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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