Bernardo Jose Franco, Maria Agustina Celentano, Desdemona Magdalena Popa
Aptian (Shuaiba-Bab) and Cenomanian (Mishrif-Shilaif) intra-shelf basins were extensively studied with their genesis focused on environmental/climatic disturbances (Vahrenkamp et al., 2015a). Additionally, local tectonic events can also affect the physiography of these basins, especially the Cenomanian intra-shelf basin subjected to NE compressional regime. As this ongoing regime increased at Late-Cretaceous and Miocene, it led to more tectonic-driven basin physiography. This paper investigates the areal extent, interaction, and commonalities between the extensional Aptian intra-shelf basin, compressional Late-Cretaceous intra-shelf basin, Late-Cretaceous-Paleogene foreland basin, and Late Oligocene-Miocene salt basin. To understand the genesis, driving forces, and distribution of these basins, we used a combination of several large-scale stratigraphic well correlations and seismic, together with age dating, cores, and extensive well information (ADNOC proprietary internal reports). The methodology used this data for detailed mapping of 11 relevant time stratigraphic intervals, placing the mapped architecture in the context of the global eustatic sea level and major geodynamic events of the Arabian Plate. Aptian basin took place as a consequence of environmental/climatic disturbances (Vahrenkamp et al., 2015a). However, environmental factors alone cannot explain isolated carbonate build-ups on salt-related structures at the intra-shelf basin, offshore Abu Dhabi. Subsequently, the emplacement of thrust sheets of Tethyan rocks from NE, and following ophiolite obduction (Searle et al., 1990; Searle, 2007; Searle and Ali, 2009; Searle et al., 2014), established a compressional regime in the Albian?-Cenomanian. This induced tectonic features such as: loading-erosion on eastern Abu Dhabi, isolated carbonate build-ups, and reactivation of a N-S deep-rooted fault (possibly a continuation of Precambrian Amad basement ridge from KSA). This N-S feature was probably the main factor contributing the basin axis change from E-W Aptian trend to N-S position at Cenomanian. Further compression continued into the Coniacian-Santonian, leading to a nascent foreland basin. This compression established a foredeep in eastern Abu Dhabi, separated by a bulge from the northern extension of the eastern Rub’ Al-Khali basin (Ghurab syncline) (Patton and O'Connor, 1988). Numerous paleostructures were developed onshore Abu Dhabi, together with several small patch-reefs on offshore salt growing structures. Campanian exhibits maximum structuration associated to eastern transpression related to Masirah ophiolite obduction during India drift (Johnson et al., 2005, Filbrandt et al., 2006; Gaina et al., 2015). This caused more differentiation of the foredeep, onshore synclines, and northern paleostructures, which continued to cease through Maastrichtian. From Paleocene to Late-Eocene, paleostructure growth intensity continued decreasing and foreland basin hydrolog
Aptian (Shuaiba-Bab)和Cenomanian (Mishrif-Shilaif)陆架内盆地被广泛研究，其成因主要是环境/气候干扰(Vahrenkamp等，2015)。此外，局部构造事件也会影响这些盆地的地貌，特别是受NE向挤压作用的Cenomanian陆架内盆地。随着这种持续的机制在晚白垩世和中新世的增加，它导致了更多的构造驱动的盆地地貌。本文研究了伸展性阿普田陆架内盆地、挤压性晚白垩世陆架内盆地、晚白垩世—古近系前陆盆地和晚渐新世—中新世盐盆地的面积范围、相互作用和共性。为了了解这些盆地的成因、驱动力和分布，我们结合了几个大型地层井对比和地震数据，以及年龄测年、岩心和大量的井信息(ADNOC专有的内部报告)。该方法使用这些数据详细绘制了11个相关时间地层间隔，将绘制的结构置于全球海平面上升和阿拉伯板块主要地球动力学事件的背景下。Aptian盆地的形成是环境/气候扰动的结果(Vahrenkamp et al.， 2015)。然而，仅靠环境因素无法解释阿布扎比近海陆架内盆地与盐有关的构造上孤立的碳酸盐堆积。随后，东北向的特提斯岩石逆冲层位进，蛇绿岩逆冲(Searle et al.， 1990;塞尔,2007;Searle and Ali, 2009;Searle et al.， 2014)在Albian -Cenomanian建立了挤压机制。这导致了Abu Dhabi东部的负荷侵蚀、孤立的碳酸盐堆积以及N-S深根断裂的重新激活(可能是KSA前寒武纪Amad基底脊的延续)等构造特征。这种南北向特征可能是导致盆地轴线在塞诺曼期由东西向转向南北向的主要因素。进一步的挤压作用持续到coniian - santonian，形成了一个新生的前陆盆地。这种挤压在阿布扎比东部建立了一个前深，由东部Rub ' Al-Khali盆地(Ghurab向斜)北部延伸的凸起分隔(Patton和O' connor, 1988)。阿布扎比海岸上发育了许多古构造，以及近海盐生长构造上的几个小块状礁。坎帕层系表现出与印度漂移期间Masirah蛇绿岩逆冲相关的东挤压相关的最大构造(Johnson et al.， 2005; Filbrandt et al.， 2006;Gaina et al.， 2015)。这导致了前深、陆上向斜和北部古构造的更多分化，这些分化在马斯特里赫特时期继续停止。从古新世到晚始新世，古构造生长强度持续减弱，前陆盆地水文限制开始于新特提斯期闭合。从渐新世到布迪加利亚，这种情况一直持续到新特提斯纪与扎格罗斯造山运动结束(Sharland et al.， 2001)，造成了一个新的环境/气候扰动期。这些扰动阻止了碳酸盐岩工厂向前深的继续推进，导致了明显的地盆分异。此外，扎格罗斯造山运动使板块向东北方向倾斜，破坏了晚塞诺曼期的古构造。最后，在布里迪亚纪至中中新世的干旱气候中，封闭的新近纪海以大量的蒸发岩填满了前深的容纳空间。关于阿布扎比这些盆地的轮廓和结构，以及使用地下信息导致其形成的详细情况，出版物很少。
{"title":"Regional Tectonics to Basin Fill Architecture from Aptian Shuaiba Fm to Miocene Fars Gp of Abu Dhabi","authors":"Bernardo Jose Franco, Maria Agustina Celentano, Desdemona Magdalena Popa","doi":"10.2118/207722-ms","DOIUrl":"https://doi.org/10.2118/207722-ms","url":null,"abstract":"\u0000 \u0000 \u0000 Aptian (Shuaiba-Bab) and Cenomanian (Mishrif-Shilaif) intra-shelf basins were extensively studied with their genesis focused on environmental/climatic disturbances (Vahrenkamp et al., 2015a). Additionally, local tectonic events can also affect the physiography of these basins, especially the Cenomanian intra-shelf basin subjected to NE compressional regime. As this ongoing regime increased at Late-Cretaceous and Miocene, it led to more tectonic-driven basin physiography. This paper investigates the areal extent, interaction, and commonalities between the extensional Aptian intra-shelf basin, compressional Late-Cretaceous intra-shelf basin, Late-Cretaceous-Paleogene foreland basin, and Late Oligocene-Miocene salt basin.\u0000 \u0000 \u0000 \u0000 To understand the genesis, driving forces, and distribution of these basins, we used a combination of several large-scale stratigraphic well correlations and seismic, together with age dating, cores, and extensive well information (ADNOC proprietary internal reports). The methodology used this data for detailed mapping of 11 relevant time stratigraphic intervals, placing the mapped architecture in the context of the global eustatic sea level and major geodynamic events of the Arabian Plate.\u0000 \u0000 \u0000 \u0000 Aptian basin took place as a consequence of environmental/climatic disturbances (Vahrenkamp et al., 2015a). However, environmental factors alone cannot explain isolated carbonate build-ups on salt-related structures at the intra-shelf basin, offshore Abu Dhabi. Subsequently, the emplacement of thrust sheets of Tethyan rocks from NE, and following ophiolite obduction (Searle et al., 1990; Searle, 2007; Searle and Ali, 2009; Searle et al., 2014), established a compressional regime in the Albian?-Cenomanian. This induced tectonic features such as: loading-erosion on eastern Abu Dhabi, isolated carbonate build-ups, and reactivation of a N-S deep-rooted fault (possibly a continuation of Precambrian Amad basement ridge from KSA). This N-S feature was probably the main factor contributing the basin axis change from E-W Aptian trend to N-S position at Cenomanian. Further compression continued into the Coniacian-Santonian, leading to a nascent foreland basin. This compression established a foredeep in eastern Abu Dhabi, separated by a bulge from the northern extension of the eastern Rub’ Al-Khali basin (Ghurab syncline) (Patton and O'Connor, 1988). Numerous paleostructures were developed onshore Abu Dhabi, together with several small patch-reefs on offshore salt growing structures. Campanian exhibits maximum structuration associated to eastern transpression related to Masirah ophiolite obduction during India drift (Johnson et al., 2005, Filbrandt et al., 2006; Gaina et al., 2015). This caused more differentiation of the foredeep, onshore synclines, and northern paleostructures, which continued to cease through Maastrichtian. From Paleocene to Late-Eocene, paleostructure growth intensity continued decreasing and foreland basin hydrolog","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90047399","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}
A. Khanifar, Benayad Nourreddine, Mohd Razib Bin Abd Raub, Raj Deo Tewari, Mohd Faizal Bin Sedaralit
A major Malaysian offshore oilfield, which is currently operating under waterflooding for a quite long time and declining in oil production, plan to convert as chemical enhanced oil recovery (CEOR) injection. The CEOR journey started since the first oil production in year 2000 and proximate waterflooding, with research and development in determining suitable method, encouraging field trial results and a series of field development plans to maximize potential recovery above waterflooding and prolong the production field life. A comprehensive EOR study including screening, laboratory tests, pilot evaluation, and full field reservoir simulation modelling are conducted to reduce the project risks prior to the full field investment and execution. Among several EOR techniques, Alkaline-Surfactant (AS) flooding is chosen to be implemented in this field. Several CEOR key parameters have been studied and optimized in the laboratory such as chemical concentration, chemical adsorption, interfacial tension (IFT), slug size, residual oil saturation (Sor) reduction, thermal stability, flow assurance, emulsion, dilution, and a chemical injection scheme. Uncertainty analysis on CEOR process was done due to the large well spacing in the offshore environment as compared to other CEOR projects, which are onshore with shorter well spacing. The key risks and parameters such as residual oil saturation (Sorw), adsorption and interfacial tension (IFT) cut-off in the dynamic chemical simulator have been investigated via a probabilistic approach on top of deterministic method. The laboratory results from fluid-fluid and rock-fluid analyses ascertained a potential of ultra-low interfacial tension of 0.001 dyne/cm with adsorption of 0.30 mg/gr-of-rock, which translated to a 50-75% reduction in Sor after waterflooding. The results of four single well chemical tracer tests (SWCTT) on two wells validated the effectiveness of the Alkaline Surfactant by a reduction of 50-80% in Sor. The most suitable chemical formulation was found 1.0 wt. % Alkali and 0.075 wt. % Surfactant. The field trial results were thenceforth upscaled to a dynamic chemical simulation; from single well to full field modeling, resulting an optimal chemical injection of three years or almost 0.2 effective injection pore volume, coupled with six months of low salinity treated water as pre-flush and post-flush injection. The latest field development study results yield a technical potential recoverable volume of 14, 16, and 26 MMstb (above waterflooding) for low, most likely, and high cases, respectively, which translated to an additional EOR recovery factor up to 5.6 % for most-likely case by end of technical field life. Prior to the final investment decision stage, Petronas’ position was to proceed with the project based on the techno-commerciality and associated risks as per milestone review 5, albeit it came to an agreement to have differing interpretations towards the technical basis of the project in
{"title":"Historical Overview and Future Perspective of Chemical EOR Project for Major Malaysian Offshore Oilfield: Case Study","authors":"A. Khanifar, Benayad Nourreddine, Mohd Razib Bin Abd Raub, Raj Deo Tewari, Mohd Faizal Bin Sedaralit","doi":"10.2118/207261-ms","DOIUrl":"https://doi.org/10.2118/207261-ms","url":null,"abstract":"\u0000 A major Malaysian offshore oilfield, which is currently operating under waterflooding for a quite long time and declining in oil production, plan to convert as chemical enhanced oil recovery (CEOR) injection. The CEOR journey started since the first oil production in year 2000 and proximate waterflooding, with research and development in determining suitable method, encouraging field trial results and a series of field development plans to maximize potential recovery above waterflooding and prolong the production field life.\u0000 A comprehensive EOR study including screening, laboratory tests, pilot evaluation, and full field reservoir simulation modelling are conducted to reduce the project risks prior to the full field investment and execution. Among several EOR techniques, Alkaline-Surfactant (AS) flooding is chosen to be implemented in this field. Several CEOR key parameters have been studied and optimized in the laboratory such as chemical concentration, chemical adsorption, interfacial tension (IFT), slug size, residual oil saturation (Sor) reduction, thermal stability, flow assurance, emulsion, dilution, and a chemical injection scheme. Uncertainty analysis on CEOR process was done due to the large well spacing in the offshore environment as compared to other CEOR projects, which are onshore with shorter well spacing. The key risks and parameters such as residual oil saturation (Sorw), adsorption and interfacial tension (IFT) cut-off in the dynamic chemical simulator have been investigated via a probabilistic approach on top of deterministic method.\u0000 The laboratory results from fluid-fluid and rock-fluid analyses ascertained a potential of ultra-low interfacial tension of 0.001 dyne/cm with adsorption of 0.30 mg/gr-of-rock, which translated to a 50-75% reduction in Sor after waterflooding. The results of four single well chemical tracer tests (SWCTT) on two wells validated the effectiveness of the Alkaline Surfactant by a reduction of 50-80% in Sor. The most suitable chemical formulation was found 1.0 wt. % Alkali and 0.075 wt. % Surfactant. The field trial results were thenceforth upscaled to a dynamic chemical simulation; from single well to full field modeling, resulting an optimal chemical injection of three years or almost 0.2 effective injection pore volume, coupled with six months of low salinity treated water as pre-flush and post-flush injection. The latest field development study results yield a technical potential recoverable volume of 14, 16, and 26 MMstb (above waterflooding) for low, most likely, and high cases, respectively, which translated to an additional EOR recovery factor up to 5.6 % for most-likely case by end of technical field life.\u0000 Prior to the final investment decision stage, Petronas’ position was to proceed with the project based on the techno-commerciality and associated risks as per milestone review 5, albeit it came to an agreement to have differing interpretations towards the technical basis of the project in","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"245 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86704721","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}
Flavio Ferrari, Riccardo Naselli, Paolo Brunetti, J. Michelez, Edoardo Zini
Drilling activities are energy intensive, in order to support, for example, heavy loads, high volumes circulation, and high torque equipment. As of today, this energy is mainly provided by diesel generators consuming tons of fuel every day. Hence, drilling activities are a significant producer of greenhouse gases (GHG) in the upstream industry, therefore drawing attention on the potential for emissions reduction. There are two ways for reducing emissions: changing the source of energy, and reducing the consumption. This paper is focusing on the latter, addressing the potential for GHG reduction thanks digitalization of the rig operations. The process is structured in two phases: Rig operations provide different data sources from rig sensors and daily reporting. The digitalization process in place in Saipem is gathering and consolidating these data on rig site and in headquarters in real time. On one hand, dedicated algorithms are applied to identify the rig state (type of ongoing operation) every 5 seconds. On the other hand, engines’ consumptions data are provided either through reporting or from engines monitoring systems (where available). All these data are then consolidated and displayed on interactive dashboards, providing insightful information on fuel efficiency and energy consumption by type of operations for each rig. By analysing the power needs according to a given environment (eg. depth) and operational conditions (eg. tripping) the system provides the best statistical performance recorded from the rig fleet and set it as a target for low emission operations. Then the operators on the rig have clear instructions on how to utilize their diesel generators to ensure both operational safety and emissions reduction. In addition, the use of the engines at an optimal level supports also availability (less failures) and maintainability (longer lifetime). The system in place has produced valuable results in less than 6 months, by offering a clear visibility on the most consuming activities and the definition of best-in-class energy-efficient operations. These instructions are distributed among the rigs, and the operators can proactively optimize the use of their engines according to the upcoming activities and the operating environment. GHG emissions are constantly monitored and reductions have been recorded on a monthly basis. Considering that the cleaner energy is the one that is not consumed, this digitalization process of rig sensor data and operation reporting offers an unprecedented vision of the activities and their related GHG emissions. A cautious analysis of these data provides practical indicators for the most efficient use of diesel generators. This proactive energy management supports operators and contractors in delivering a proactive sustainability strategy with measurable results.
{"title":"Digitalization for Reducing Carbon Footprint in Drilling Operations","authors":"Flavio Ferrari, Riccardo Naselli, Paolo Brunetti, J. Michelez, Edoardo Zini","doi":"10.2118/207407-ms","DOIUrl":"https://doi.org/10.2118/207407-ms","url":null,"abstract":"\u0000 \u0000 \u0000 Drilling activities are energy intensive, in order to support, for example, heavy loads, high volumes circulation, and high torque equipment. As of today, this energy is mainly provided by diesel generators consuming tons of fuel every day. Hence, drilling activities are a significant producer of greenhouse gases (GHG) in the upstream industry, therefore drawing attention on the potential for emissions reduction. There are two ways for reducing emissions: changing the source of energy, and reducing the consumption. This paper is focusing on the latter, addressing the potential for GHG reduction thanks digitalization of the rig operations.\u0000 \u0000 \u0000 \u0000 The process is structured in two phases:\u0000 \u0000 \u0000 \u0000 Rig operations provide different data sources from rig sensors and daily reporting. The digitalization process in place in Saipem is gathering and consolidating these data on rig site and in headquarters in real time. On one hand, dedicated algorithms are applied to identify the rig state (type of ongoing operation) every 5 seconds. On the other hand, engines’ consumptions data are provided either through reporting or from engines monitoring systems (where available). All these data are then consolidated and displayed on interactive dashboards, providing insightful information on fuel efficiency and energy consumption by type of operations for each rig.\u0000 \u0000 \u0000 \u0000 By analysing the power needs according to a given environment (eg. depth) and operational conditions (eg. tripping) the system provides the best statistical performance recorded from the rig fleet and set it as a target for low emission operations. Then the operators on the rig have clear instructions on how to utilize their diesel generators to ensure both operational safety and emissions reduction. In addition, the use of the engines at an optimal level supports also availability (less failures) and maintainability (longer lifetime).\u0000 \u0000 \u0000 \u0000 The system in place has produced valuable results in less than 6 months, by offering a clear visibility on the most consuming activities and the definition of best-in-class energy-efficient operations. These instructions are distributed among the rigs, and the operators can proactively optimize the use of their engines according to the upcoming activities and the operating environment. GHG emissions are constantly monitored and reductions have been recorded on a monthly basis.\u0000 \u0000 \u0000 \u0000 Considering that the cleaner energy is the one that is not consumed, this digitalization process of rig sensor data and operation reporting offers an unprecedented vision of the activities and their related GHG emissions. A cautious analysis of these data provides practical indicators for the most efficient use of diesel generators. This proactive energy management supports operators and contractors in delivering a proactive sustainability strategy with measurable results.\u0000","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"66 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76383437","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}
Abdul Saboor Khan, Salah Alqallabi, A. Phade, A. Skorstad, F. Al-Jenaibi, Mohamed Tarik Gacem, Mustapha Adli, Sheharyar Mansur, Lyes Malla
The aim of this study is to demonstrate the value of an integrated ensemble-based modeling approach for multiple reservoirs of varying complexity. Three different carbonate reservoirs are selected with varying challenges to showcase the flexibility of the approach to subsurface teams. Modeling uncertainties are included in both static and dynamic domains and valuable insights are attained in a short reservoir modeling cycle time. Integrated workflows are established with guidance from multi-disciplinary teams to incorporate recommended static and dynamic modeling processes in parallel to overcome the modeling challenges of the individual reservoirs. Challenges such as zonal communication, presence of baffles, high permeability streaks, communication from neighboring fields, water saturation modeling uncertainties, relative permeability with hysteresis, fluid contact depth shift etc. are considered when accounting for uncertainties. All the uncertainties in sedimentology, structure and dynamic reservoir parameters are set through common dialogue and collaboration between subsurface teams to ensure that modeling best practices are adhered to. Adaptive pluri-Gaussian simulation is used for facies modeling and uncertainties are propagated in the dynamic response of the geologically plausible ensembles. These equiprobable models are then history-matched simultaneously using an ensemble-based conditioning tool to match the available observed field production data within a specified tolerance; with each reservoir ranging in number of wells, number of grid cells and production history. This approach results in a significantly reduced modeling cycle time compared to the traditional approach, regardless of the inherent complexity of the reservoir, while giving better history-matched models that are honoring the geology and correlations in input data. These models are created with only enough detail level as per the modeling objectives, leaving more time to extract insights from the ensemble of models. Uncertainties in data, from various domains, are not isolated there, but rather propagated throughout, as these might have an important role in another domain, or in the total response uncertainty. Similarly, the approach encourages a collaborative effort in reservoir modeling and fosters trust between geo-scientists and engineers, ascertaining that models remain consistent across all subsurface domains. It allows for the flexibility to incorporate modeling practices fit for individual reservoirs. Moreover, analysis of the history-matched ensemble shows added insights to the reservoirs such as the location and possible extent of features like high permeability streaks and baffles that are not explicitly modeled in the process initially. Forecast strategies further run on these ensembles of equiprobable models, capture realistic uncertainties in dynamic responses which can help make informed reservoir management decisions. The integrated ensemble-based mo
{"title":"Demonstrating Flexibility and Cost-Efficiency of Integrated Ensemble-Based Modeling – One Approach on Three Reservoirs","authors":"Abdul Saboor Khan, Salah Alqallabi, A. Phade, A. Skorstad, F. Al-Jenaibi, Mohamed Tarik Gacem, Mustapha Adli, Sheharyar Mansur, Lyes Malla","doi":"10.2118/207738-ms","DOIUrl":"https://doi.org/10.2118/207738-ms","url":null,"abstract":"\u0000 The aim of this study is to demonstrate the value of an integrated ensemble-based modeling approach for multiple reservoirs of varying complexity. Three different carbonate reservoirs are selected with varying challenges to showcase the flexibility of the approach to subsurface teams. Modeling uncertainties are included in both static and dynamic domains and valuable insights are attained in a short reservoir modeling cycle time.\u0000 Integrated workflows are established with guidance from multi-disciplinary teams to incorporate recommended static and dynamic modeling processes in parallel to overcome the modeling challenges of the individual reservoirs. Challenges such as zonal communication, presence of baffles, high permeability streaks, communication from neighboring fields, water saturation modeling uncertainties, relative permeability with hysteresis, fluid contact depth shift etc. are considered when accounting for uncertainties. All the uncertainties in sedimentology, structure and dynamic reservoir parameters are set through common dialogue and collaboration between subsurface teams to ensure that modeling best practices are adhered to. Adaptive pluri-Gaussian simulation is used for facies modeling and uncertainties are propagated in the dynamic response of the geologically plausible ensembles. These equiprobable models are then history-matched simultaneously using an ensemble-based conditioning tool to match the available observed field production data within a specified tolerance; with each reservoir ranging in number of wells, number of grid cells and production history.\u0000 This approach results in a significantly reduced modeling cycle time compared to the traditional approach, regardless of the inherent complexity of the reservoir, while giving better history-matched models that are honoring the geology and correlations in input data. These models are created with only enough detail level as per the modeling objectives, leaving more time to extract insights from the ensemble of models. Uncertainties in data, from various domains, are not isolated there, but rather propagated throughout, as these might have an important role in another domain, or in the total response uncertainty. Similarly, the approach encourages a collaborative effort in reservoir modeling and fosters trust between geo-scientists and engineers, ascertaining that models remain consistent across all subsurface domains. It allows for the flexibility to incorporate modeling practices fit for individual reservoirs. Moreover, analysis of the history-matched ensemble shows added insights to the reservoirs such as the location and possible extent of features like high permeability streaks and baffles that are not explicitly modeled in the process initially. Forecast strategies further run on these ensembles of equiprobable models, capture realistic uncertainties in dynamic responses which can help make informed reservoir management decisions.\u0000 The integrated ensemble-based mo","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84851023","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}
A continual improvement in energy efficiency of existing plants is imperative to achieve ADNOC target to reduce greenhouse gas emissions (GHG) intensity of operations by 25% in year 2030. The waste heat recovery (WHR) from incinerator stacks of existing Sulphur Recovery Units (SRUs) in ADNOC Gas Processing exhibits a substantial potential & contributor of energy savings and emission abatement. A high level assessment was carried out for various heat sources, results showed substantial WHR potential can be availed from SRUs. Consequently, a feasibility study was carried out to evaluate several options to recover energy from incinerator stacks of existing Sulphur Recovery Units (SRUs). The feasibility study addressed three options of recovering energy from SRUs incinerator stack exhaust; generating saturated steam, generating power and combined solution of steam & power. Those options were assessed in terms of technical feasibility and commercial viability. The study indicated that steam generation by HRSGs is technically viable and economically feasible, and considered as the best option for WHR from the existing SRU Incinerator Stacks. The WHR benefits that can be realized from just one incinerator stack by recovering the waste heat and reducing the flue gas temperature by 400 °C only (from 700 to 300 °C) are: More than 80 TPH saturated HP steam generationFuel gas savings and corresponding monetary benefitsSignificant abatement in GHG emissions The study revealed that WHR does not pose acid condensation risk due to the safe margin between the acid dew point and the actual flue gas temperature. The study also established that other constraints like pressure drop, space, tie-in location and emissions dispersion are not the showstoppers.
{"title":"Boosting Gas Processing Energy Efficiency by Waste Heat Recovery","authors":"Waneya Al Ketbi, S. Sajjad, Eisa Salem Al Jenaibi","doi":"10.2118/207809-ms","DOIUrl":"https://doi.org/10.2118/207809-ms","url":null,"abstract":"\u0000 A continual improvement in energy efficiency of existing plants is imperative to achieve ADNOC target to reduce greenhouse gas emissions (GHG) intensity of operations by 25% in year 2030. The waste heat recovery (WHR) from incinerator stacks of existing Sulphur Recovery Units (SRUs) in ADNOC Gas Processing exhibits a substantial potential & contributor of energy savings and emission abatement. A high level assessment was carried out for various heat sources, results showed substantial WHR potential can be availed from SRUs. Consequently, a feasibility study was carried out to evaluate several options to recover energy from incinerator stacks of existing Sulphur Recovery Units (SRUs). The feasibility study addressed three options of recovering energy from SRUs incinerator stack exhaust; generating saturated steam, generating power and combined solution of steam & power. Those options were assessed in terms of technical feasibility and commercial viability.\u0000 The study indicated that steam generation by HRSGs is technically viable and economically feasible, and considered as the best option for WHR from the existing SRU Incinerator Stacks. The WHR benefits that can be realized from just one incinerator stack by recovering the waste heat and reducing the flue gas temperature by 400 °C only (from 700 to 300 °C) are: More than 80 TPH saturated HP steam generationFuel gas savings and corresponding monetary benefitsSignificant abatement in GHG emissions\u0000 The study revealed that WHR does not pose acid condensation risk due to the safe margin between the acid dew point and the actual flue gas temperature. The study also established that other constraints like pressure drop, space, tie-in location and emissions dispersion are not the showstoppers.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"23 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87027354","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}
Felix Leonardo Castillo, Roswall Enrique Bethancourt, M. Sarhan, Abd Al Sayfi, Imad Al Hamlawi, Luis Ramon Baptista, Sultan Saeed Al Mansoori, Ali Mubarak Al Braiki, Gennadys Ferrer, Alejandro Cortes, M. Husien, Nader Jouzy, Delimar Cristobal Herrera, Praveen Joseph Benny, R. Aubakirov, Joey Roberie
Significant mud losses during drilling often compromises well integrity whenever sustainable annular pressure (SAP), is observed due to poor cement integrity around 9-5/8-in casing in wells requiring gas lift completion. Heavy Casing Design (HCD) is applied as a solution; whereby, two casing strings are used to isolate the aquifers and loss zones, thus ensuring improved cement integrity around the 9 5/8-in intermediate casing. Casing While Drilling (CWD) is a potential solution to mitigate mud losses and wellbore instability enabling an optimized alternative to HCD by ensuring well integrity is maintained while reducing well construction cost. This paper details the first 12 ¼-in × 9-5/8-in non-directional CWD trial accomplished in Abu Dhabi onshore The Non-Directional CWD Technology was tested in a vertical intermediate hole section of a modified heavy casing design (MHCD) aimed at reducing well construction cost over heavy casing design (HCD) as shown in the figure 1. A drillable alloy bit with an optimized polycrystalline diamond cutters (PDC) cutting structure was used to drill with casing through a multi-formation interval with varying hardness and mechanical properties. Drilling dynamics, hydraulics and casing centralization analysis were performed to evaluate the directional tendency of the drill string along with the optimum drilling parameters to address the losses scenario, hole cleaning, vibration, and maximum surface torque. The CWD operation was completed in a single run with zero quality, health, safety, and environment (HSE) events and minimum exposure of personal to manual handling of heavy tubulars. Exceptional cement bonding was observed around the 9 5/8 in casing indicative of good hole quality despite running a significant number of centralizers (with smaller diameter), compared with the conventional drilled wells (cement bond logging was done after the section). CWD implementation saved two days of rig operations time relative to the average of the offset wells with the same casing design. The rate of Penetration (ROP) was slightly lower than the conventional drilling ROP in this application. The cost savings are mainly attributed to the elimination of casing-running flat time and Non-Productive Time (NPT) associated with clearing tight spots, BHA pack-off, wiper trips. The application of CWD in the MHCD wells deliver an estimated saving of USD 0.8MM in well construction cost per well compared to the HCD well design. Additional performance optimization opportunities have been identified for implementation in future applications. The combination of the MHCD and CWD technology enhances cementing quality across heavy loss zones translating into improved well integrity. Implementing this technology on MHCD wells could potentially save up to USD 200MM (considering 250 wells drilled). This is the first application of the technology in Abu Dhabi and brings key learning for future enhancement of drilling efficiency. The CWD tec
{"title":"First Abu Dhabi 9.625in × 12.25in Non-Directional Casing While Drilling CWD Run for Intermediate Hole Section Saves Two Days Rig Time, Enhancing Drilling Efficiency & Improving Well Integrity","authors":"Felix Leonardo Castillo, Roswall Enrique Bethancourt, M. Sarhan, Abd Al Sayfi, Imad Al Hamlawi, Luis Ramon Baptista, Sultan Saeed Al Mansoori, Ali Mubarak Al Braiki, Gennadys Ferrer, Alejandro Cortes, M. Husien, Nader Jouzy, Delimar Cristobal Herrera, Praveen Joseph Benny, R. Aubakirov, Joey Roberie","doi":"10.2118/207565-ms","DOIUrl":"https://doi.org/10.2118/207565-ms","url":null,"abstract":"\u0000 Significant mud losses during drilling often compromises well integrity whenever sustainable annular pressure (SAP), is observed due to poor cement integrity around 9-5/8-in casing in wells requiring gas lift completion. Heavy Casing Design (HCD) is applied as a solution; whereby, two casing strings are used to isolate the aquifers and loss zones, thus ensuring improved cement integrity around the 9 5/8-in intermediate casing. Casing While Drilling (CWD) is a potential solution to mitigate mud losses and wellbore instability enabling an optimized alternative to HCD by ensuring well integrity is maintained while reducing well construction cost. This paper details the first 12 ¼-in × 9-5/8-in non-directional CWD trial accomplished in Abu Dhabi onshore\u0000 The Non-Directional CWD Technology was tested in a vertical intermediate hole section of a modified heavy casing design (MHCD) aimed at reducing well construction cost over heavy casing design (HCD) as shown in the figure 1. A drillable alloy bit with an optimized polycrystalline diamond cutters (PDC) cutting structure was used to drill with casing through a multi-formation interval with varying hardness and mechanical properties. Drilling dynamics, hydraulics and casing centralization analysis were performed to evaluate the directional tendency of the drill string along with the optimum drilling parameters to address the losses scenario, hole cleaning, vibration, and maximum surface torque.\u0000 The CWD operation was completed in a single run with zero quality, health, safety, and environment (HSE) events and minimum exposure of personal to manual handling of heavy tubulars. Exceptional cement bonding was observed around the 9 5/8 in casing indicative of good hole quality despite running a significant number of centralizers (with smaller diameter), compared with the conventional drilled wells (cement bond logging was done after the section). CWD implementation saved two days of rig operations time relative to the average of the offset wells with the same casing design. The rate of Penetration (ROP) was slightly lower than the conventional drilling ROP in this application. The cost savings are mainly attributed to the elimination of casing-running flat time and Non-Productive Time (NPT) associated with clearing tight spots, BHA pack-off, wiper trips. The application of CWD in the MHCD wells deliver an estimated saving of USD 0.8MM in well construction cost per well compared to the HCD well design. Additional performance optimization opportunities have been identified for implementation in future applications.\u0000 The combination of the MHCD and CWD technology enhances cementing quality across heavy loss zones translating into improved well integrity. Implementing this technology on MHCD wells could potentially save up to USD 200MM (considering 250 wells drilled).\u0000 This is the first application of the technology in Abu Dhabi and brings key learning for future enhancement of drilling efficiency. The CWD tec","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"1989 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90376942","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}
M. T. Al-Murayri, A. Hassan, Naser Alajmi, Jimmy Nesbit, B. Thery, Philippe Al Khoury, A. Zaitoun, J. Bouillot, N. Salehi, M. Pitts, K. Wyatt, E. Dean
Mature carbonate reservoirs under waterflood in Kuwait suffer from relatively low oil recovery due to poor volumetric sweep efficiency, both areal, vertically, and microscopically. An Alkaline-Surfactant-Polymer (ASP) pilot using a regular five-spot well pattern is in progress targeting the Sabriyah Mauddud (SAMA) reservoir in pursuit of reserves growth and production sustainability. SAMA suffers from reservoir heterogeneities mainly associated with permeability contrast which may be improved with a conformance treatment to de-risk pre-mature breakthrough of water and chemical EOR agents in preparation for subsequent ASP injection and to improve reservoir contact by the injected fluids. Each of the four injection wells in the SAMA ASP pilot was treated with a chemical conformance improvement formulation. A high viscosity polymer solution (HVPS) of 200 cP was injected prior to a gelant formulation consisting of P300 polymer and X1050 crosslinker. After a shut-in period, wells were then returned to water injection. Injection of high viscosity polymer solution (HVPS) at the four injection wells showed no increase in injection pressure and occurred higher than expected injection rates. Early breakthrough of polymer was observed at SA-0561 production well from three of the four injection wells. No appreciable change in oil cut was observed. HVPS did not improve volumetric sweep efficiency based on the injection and production data. Gel treatment to improve the volumetric conformance of the four injection wells resulted in all the injection wells showing increased of injection pressure from approximately 3000 psi to 3600 psi while injecting at a constant rate of approximately 2,000 bb/day/well. Injection profiles from each of the injection well ILTs showed increased injection into lower-capacity zones and decreased injection into high-capacity zones. Inter-well tracer testing showed delayed tracer breakthrough at the center SA-0561 production well from each of the four injection wells after gel placement. SA-0561 produced average daily produced temperature increased from approximately 40°C to over 50°C. SA-0561 oil cuts increased up to almost 12% from negligible oil sheen prior to gel treatments. Gel treatment improved volumetric sweep efficiency in the SAMA SAP pilot area.
{"title":"Field Implementation of In-Depth Conformance Gel Treatment Prior to Starting an ASP Flooding Pilot","authors":"M. T. Al-Murayri, A. Hassan, Naser Alajmi, Jimmy Nesbit, B. Thery, Philippe Al Khoury, A. Zaitoun, J. Bouillot, N. Salehi, M. Pitts, K. Wyatt, E. Dean","doi":"10.2118/207850-ms","DOIUrl":"https://doi.org/10.2118/207850-ms","url":null,"abstract":"\u0000 Mature carbonate reservoirs under waterflood in Kuwait suffer from relatively low oil recovery due to poor volumetric sweep efficiency, both areal, vertically, and microscopically. An Alkaline-Surfactant-Polymer (ASP) pilot using a regular five-spot well pattern is in progress targeting the Sabriyah Mauddud (SAMA) reservoir in pursuit of reserves growth and production sustainability. SAMA suffers from reservoir heterogeneities mainly associated with permeability contrast which may be improved with a conformance treatment to de-risk pre-mature breakthrough of water and chemical EOR agents in preparation for subsequent ASP injection and to improve reservoir contact by the injected fluids. Each of the four injection wells in the SAMA ASP pilot was treated with a chemical conformance improvement formulation. A high viscosity polymer solution (HVPS) of 200 cP was injected prior to a gelant formulation consisting of P300 polymer and X1050 crosslinker. After a shut-in period, wells were then returned to water injection. Injection of high viscosity polymer solution (HVPS) at the four injection wells showed no increase in injection pressure and occurred higher than expected injection rates. Early breakthrough of polymer was observed at SA-0561 production well from three of the four injection wells. No appreciable change in oil cut was observed. HVPS did not improve volumetric sweep efficiency based on the injection and production data. Gel treatment to improve the volumetric conformance of the four injection wells resulted in all the injection wells showing increased of injection pressure from approximately 3000 psi to 3600 psi while injecting at a constant rate of approximately 2,000 bb/day/well. Injection profiles from each of the injection well ILTs showed increased injection into lower-capacity zones and decreased injection into high-capacity zones. Inter-well tracer testing showed delayed tracer breakthrough at the center SA-0561 production well from each of the four injection wells after gel placement. SA-0561 produced average daily produced temperature increased from approximately 40°C to over 50°C. SA-0561 oil cuts increased up to almost 12% from negligible oil sheen prior to gel treatments. Gel treatment improved volumetric sweep efficiency in the SAMA SAP pilot area.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"27 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90588570","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}
Sheldon Seales, Ahmed Rashed Alaleeli, Jan Erik Tveteraas, Daniel M. Roberts, Glenn Aasland, Patrick Ray Billomos
This paper outlines a new and innovative technology for brine recovery after the displacement of Reservoir Drill-In Fluid Non-Aqueous Fluid (RDF NAF) to Completion Brine and the associated operational, logistical, environmental and economic benefits associated with it. A unique slop treatment technology has been utilized to recover and reuse more than 2,168 bbl per well of expensive contaminated completion fluid to help manage losses and avoid injecting valuable completion fluid into operator's injection well. This has also resulted in reducing impact to the life of the injection well and burden on formation, thereby minimizing impact to subsurface environment and contributing to lower well cost. The contaminated brine was transferred from the displacement of RDF NAF to brine and processed using a novel slop treatment technology to reduce the NTU and TSS to completion brine specifications required for completion operations. After displacing the well from RDF NAF to brine, typical contaminants would be RDF NAF and hi-vis spacer (water-based). The oil-contaminated brine was usually transferred to the tanks of the cuttings treatment contractor, treated and injected into the operator's cuttings re-injection (CRI) well. The new procedure isolated the contaminated brine to be processed through the slop treatment technology to separate and remove the oil and solids from the brine. The slop treatment involved passing the contaminated fluid through a decanter, solids particulate filter, three-phase separator and then a polishing filter to process the fluid to the required NTU and TSS specifications. The slops treatment unit was implemented for brine processing in 2020 and since then, the solution has achieved desirable operational, logistical, sub-surface environmental and cost related benefits. 2,168 bbl of expensive, contaminated completion brine has been processed per well, for subsequent reuse in the completion operations. Utilization and implementation of this mechanical process, versus the historical filter press process, at the source has had clear tangible savings that can be achieved in all areas of the operation, due to the capability to process oil-contaminated brine at a higher clarity and also the viscous brine at a faster rate. This new processing strategy allowed the operator to set new standards with regards to the recovery of oil-contaminated brine, in the UAE. This is the first successful processing of oil-contaminated brine to be completed in the UAE utilizing a mechanical technology. This process has established new baselines for the operator to be able to recover oil-contaminated brine. By adapting the existing site-based slop treatment technology, this solution has bridged a gap in the market by using a novel mechanical process to optimize oil-contaminated brine recovery efficiency and maximize returns for operators.
{"title":"Maximizing Brine Recovery After the Displacement of Reservoir Drill-in Fluids to Reduce Well Cost Via New, Alternate Technology In a Reservoir Offshore Abu Dhabi","authors":"Sheldon Seales, Ahmed Rashed Alaleeli, Jan Erik Tveteraas, Daniel M. Roberts, Glenn Aasland, Patrick Ray Billomos","doi":"10.2118/207785-ms","DOIUrl":"https://doi.org/10.2118/207785-ms","url":null,"abstract":"\u0000 \u0000 \u0000 This paper outlines a new and innovative technology for brine recovery after the displacement of Reservoir Drill-In Fluid Non-Aqueous Fluid (RDF NAF) to Completion Brine and the associated operational, logistical, environmental and economic benefits associated with it. A unique slop treatment technology has been utilized to recover and reuse more than 2,168 bbl per well of expensive contaminated completion fluid to help manage losses and avoid injecting valuable completion fluid into operator's injection well. This has also resulted in reducing impact to the life of the injection well and burden on formation, thereby minimizing impact to subsurface environment and contributing to lower well cost.\u0000 \u0000 \u0000 \u0000 The contaminated brine was transferred from the displacement of RDF NAF to brine and processed using a novel slop treatment technology to reduce the NTU and TSS to completion brine specifications required for completion operations. After displacing the well from RDF NAF to brine, typical contaminants would be RDF NAF and hi-vis spacer (water-based). The oil-contaminated brine was usually transferred to the tanks of the cuttings treatment contractor, treated and injected into the operator's cuttings re-injection (CRI) well. The new procedure isolated the contaminated brine to be processed through the slop treatment technology to separate and remove the oil and solids from the brine. The slop treatment involved passing the contaminated fluid through a decanter, solids particulate filter, three-phase separator and then a polishing filter to process the fluid to the required NTU and TSS specifications.\u0000 \u0000 \u0000 \u0000 The slops treatment unit was implemented for brine processing in 2020 and since then, the solution has achieved desirable operational, logistical, sub-surface environmental and cost related benefits. 2,168 bbl of expensive, contaminated completion brine has been processed per well, for subsequent reuse in the completion operations. Utilization and implementation of this mechanical process, versus the historical filter press process, at the source has had clear tangible savings that can be achieved in all areas of the operation, due to the capability to process oil-contaminated brine at a higher clarity and also the viscous brine at a faster rate. This new processing strategy allowed the operator to set new standards with regards to the recovery of oil-contaminated brine, in the UAE.\u0000 \u0000 \u0000 \u0000 This is the first successful processing of oil-contaminated brine to be completed in the UAE utilizing a mechanical technology. This process has established new baselines for the operator to be able to recover oil-contaminated brine. By adapting the existing site-based slop treatment technology, this solution has bridged a gap in the market by using a novel mechanical process to optimize oil-contaminated brine recovery efficiency and maximize returns for operators.\u0000","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73129710","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}
Maximum Reservoir Contact wells (MRCs) are a potential alternative to reduce the number of wells required to develop hydrocarbon reservoirs, improve sweeping efficiency and delay gas and water breakthrough. The well completions design is critical for the success of MRCs. In this study we present a case study of a MRC well completion design using Limited Entry Liners (LEL) in a mature carbonate reservoir under water and miscible gas injection. We developed an integrated workflow that considered a high-resolution numerical simulation model calibrated to static and dynamic data and wellbore-reservoir models coupling, for capturing the details of the flow interaction between both systems. Flow restrictions in the form of additional pressure drops to the flow from the reservoir into the wellbore were used to simulate the effect of small open flow areas, i.e.shot densities, in the LELs. Our work allowed identifying the most likely entry points of gas and water and design the well to minimize their impact on oil production. We observe that longer lengths open to flow outweighs the detrimental effect of producing from intervals closer to the water saturated zones. We also observed that balancing the inflow profile along the wellbore did not report beneficial results to oil production as it stimulates production from the reservoir zone from which the gas breakthrough is expected (middle of the producing section); this result is particularly relevant as it shows that designing the well completions with base only on static data could lead to poor production performance. The suggested completion for the MRC well encompasses four segments; a segment covering almost 50 % of the well length and located at the middle of the producing section with a blind liner (close to flow for gas control) and the remaining three with slotted liners with enough open area as to avoid causing significant pressure drops.
{"title":"A Geoengineering Approach to Maximum Reservoir Contact Wells Design: Case Study in a Carbonate Reservoir Under Water and Miscible Gas Injection","authors":"A. Freites, Victor Segura, Muhammad Muneeb","doi":"10.2118/207300-ms","DOIUrl":"https://doi.org/10.2118/207300-ms","url":null,"abstract":"\u0000 Maximum Reservoir Contact wells (MRCs) are a potential alternative to reduce the number of wells required to develop hydrocarbon reservoirs, improve sweeping efficiency and delay gas and water breakthrough. The well completions design is critical for the success of MRCs. In this study we present a case study of a MRC well completion design using Limited Entry Liners (LEL) in a mature carbonate reservoir under water and miscible gas injection. We developed an integrated workflow that considered a high-resolution numerical simulation model calibrated to static and dynamic data and wellbore-reservoir models coupling, for capturing the details of the flow interaction between both systems. Flow restrictions in the form of additional pressure drops to the flow from the reservoir into the wellbore were used to simulate the effect of small open flow areas, i.e.shot densities, in the LELs. Our work allowed identifying the most likely entry points of gas and water and design the well to minimize their impact on oil production. We observe that longer lengths open to flow outweighs the detrimental effect of producing from intervals closer to the water saturated zones. We also observed that balancing the inflow profile along the wellbore did not report beneficial results to oil production as it stimulates production from the reservoir zone from which the gas breakthrough is expected (middle of the producing section); this result is particularly relevant as it shows that designing the well completions with base only on static data could lead to poor production performance. The suggested completion for the MRC well encompasses four segments; a segment covering almost 50 % of the well length and located at the middle of the producing section with a blind liner (close to flow for gas control) and the remaining three with slotted liners with enough open area as to avoid causing significant pressure drops.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73120881","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}
Rakan Al Yateem, Mohammad S. Al-Kadem, Suliman Alodhiani, Majed Kishi
Rate testing has evolved over the years. From a simple composite separator system, the scope of rate testing has morphed into a broad spectrum of sophisticated downhole and surface technologies. Knowing well behavior, performance, and associated rate are the key factors of operating an entire field with the most reliable operating strategy, assuring maximum well-life time. In regard to well modeling and optimization, valid rate test data are crucial to predict well performance efficiently. An in-house rate testing mechanism was developed to ensure proper delivery, accuracy, and validity of rate tests. The mechanism comprises a rate testing procedure and decision-making tree. The rate testing procedure includes regular checks of rate testing data reports. Also, the immediate resolution of rate testing equipment or communication issues is implemented through the utilization of an MPFM Advanced Monitoring System with automated logics. A decision-making tree constitutes pre- and post-testing process phases. The pre-testing process phase involves an assessment for rate testing readiness in terms of testing equipment and communication. The post-testing process phase includes an assessment for testing operation and rate test validity where rate test data are checked and validated based on production operational status. The enhanced testing mechanism is a user-friendly guideline for testing requirements to ensure the completion of tests captured from testing equipment. The proper implementation of this rate testing mechanism enabled a high quality and accuracy of rate test data, resulting in an increase in rate testing validity by 30%. Also, the rate testing mechanism inspired a culture of continuous effective communication for all involved parties during the testing operation. The decision-making tree transforms the validation process from subjective thinking to a systematic workflow while integrating data from nearby wells with similar behavior. A high ownership level is exhibited by taking the immediate resolution of issues results in achieving high rate testing validity percentage. Running the process through standardized operating procedures is critical in generating consistent and predictable results of well performance. Additionally, accurate optimization and prediction of well performance have been realized by feeding the well model's data before and after attaining valid rate test data, which attests to the quality of the proposed rate testing mechanism. Considering the importance of having a strategic rate testing mechanism, it is highly advised to have more frequent measurements to raise the accuracy of the measurements presented. An ideal strategic rate testing mechanism has to be economical enough to be placed in many production wells, allow the tests to be performed in an organized manner, improve measurement accuracy, and, more importantly, achieve automated and supervised well tests processes.
{"title":"Flourishing Production Optimization thru the Development of an Enhanced Testing Validity Methodology","authors":"Rakan Al Yateem, Mohammad S. Al-Kadem, Suliman Alodhiani, Majed Kishi","doi":"10.2118/207351-ms","DOIUrl":"https://doi.org/10.2118/207351-ms","url":null,"abstract":"\u0000 Rate testing has evolved over the years. From a simple composite separator system, the scope of rate testing has morphed into a broad spectrum of sophisticated downhole and surface technologies. Knowing well behavior, performance, and associated rate are the key factors of operating an entire field with the most reliable operating strategy, assuring maximum well-life time. In regard to well modeling and optimization, valid rate test data are crucial to predict well performance efficiently.\u0000 An in-house rate testing mechanism was developed to ensure proper delivery, accuracy, and validity of rate tests. The mechanism comprises a rate testing procedure and decision-making tree. The rate testing procedure includes regular checks of rate testing data reports. Also, the immediate resolution of rate testing equipment or communication issues is implemented through the utilization of an MPFM Advanced Monitoring System with automated logics. A decision-making tree constitutes pre- and post-testing process phases. The pre-testing process phase involves an assessment for rate testing readiness in terms of testing equipment and communication. The post-testing process phase includes an assessment for testing operation and rate test validity where rate test data are checked and validated based on production operational status.\u0000 The enhanced testing mechanism is a user-friendly guideline for testing requirements to ensure the completion of tests captured from testing equipment. The proper implementation of this rate testing mechanism enabled a high quality and accuracy of rate test data, resulting in an increase in rate testing validity by 30%. Also, the rate testing mechanism inspired a culture of continuous effective communication for all involved parties during the testing operation. The decision-making tree transforms the validation process from subjective thinking to a systematic workflow while integrating data from nearby wells with similar behavior. A high ownership level is exhibited by taking the immediate resolution of issues results in achieving high rate testing validity percentage. Running the process through standardized operating procedures is critical in generating consistent and predictable results of well performance. Additionally, accurate optimization and prediction of well performance have been realized by feeding the well model's data before and after attaining valid rate test data, which attests to the quality of the proposed rate testing mechanism.\u0000 Considering the importance of having a strategic rate testing mechanism, it is highly advised to have more frequent measurements to raise the accuracy of the measurements presented. An ideal strategic rate testing mechanism has to be economical enough to be placed in many production wells, allow the tests to be performed in an organized manner, improve measurement accuracy, and, more importantly, achieve automated and supervised well tests processes.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"319 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78000003","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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