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":null,"pages":null},"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":null,"pages":null},"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":null,"pages":null},"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":null,"pages":null},"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":null,"pages":null},"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":null,"pages":null},"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":null,"pages":null},"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}
M. Jaya, Ghazali Ahmad Riza, Ahmad Fuad M. Izzuljad, Mad Sahad Salbiah
The prediction of fluid parameter related to hydrocarbon presence using seismic data has often been limited by the performance of probability density function in estimating fluid properties from seismic inversion results. A novel fluid bulk modulus inversion (fBMI) is a pre-stack seismic inversion technique that has been developed to allow a direct estimation of pore fluid bulk modulus (Kf) from seismic data. Real data application in Malay basin showcases that Kf volume can be used to pinpoint areas with high probability of hydrocarbon presence. The fluid term AVO reflectivity (Russell et al., 2011) is used as the basis of our formulation and has been extended to allow direct estimation of pore fluid bulk modulus, shearmodulus, porosity parameter and density through standard least-square inversion. The novel formulation is able to relax the dependency of fluid terms on the porosity. To demonstrate this, verifications were made against standard linear AVO approximations. Our observation shows that the young tertiary basins such as the Malay basin the fluid bulk modulus values have a big contrast between hydrocarbon saturated and water bearing reservoirs with a minimum of 60% ratio difference. The inverted fluid bulk modulus volume provides thus a direct assessment of areas with high probability of hydrocarbon saturation. In this paper, the fBMI technique is showcased on a field in the Malay basin. The outcome is demonstrated on a well panel analysis for four wells located across the study area (Figure 1). The inverted fluid bulk modulus extracted along a horizon representing the top of target reservoir is shown in Figure 2b. The blue color indicates high bulk modulus corresponds to water-bearing zone, while the yellow-red color range corresponding to low hydrocarbon-bearing zones. The areas of low fluid bulk modulus values at the north-western region are calibrated to known production zones in that region. fBMI shows areas that delineate high probability of hydrocarbon presence and provides a quantitative measure in terms of fluid parameter directly related to the presence of hydrocarbon saturations. Figure 1: Comparison analysis of water saturation (blue curve) and fluid bulk modulus (red curve) of well log data in the Malay basin. Black strips indicate the coal intervals. Figure 2: a) Inverted acoustic impedance extracted from the top reservoir horizon of a field in the Malay basin. b) The corresponding fluid bulk modulus values from fBMI. The fBMI is a new four parameters linear amplitude-versus-offset inversion technique that provides quantitative fluid parameter directly related to fluid bulk modulus from seismic data. It is utilized as a tool for direct hydrocarbon prospect assessment to differentiate gas, oil, condensate and water.
利用地震资料预测与油气存在相关的流体参数，往往受到地震反演结果估计流体性质时概率密度函数性能的限制。一种新型流体体积模量反演(fBMI)是一种叠前地震反演技术，可以从地震数据中直接估计孔隙流体体积模量(Kf)。在马来盆地的实际数据应用表明，Kf体积可以用来确定油气存在的高可能性区域。流体项AVO反射率(Russell et al.， 2011)作为我们公式的基础，并进行了扩展，可以通过标准最小二乘反演直接估计孔隙流体体积模量、剪切模量、孔隙度参数和密度。新配方能够减轻流体项对孔隙度的依赖。为了证明这一点，对标准线性AVO近似进行了验证。研究表明，马来盆地等年轻第三系盆地的流体体积模量在含水与饱和储层之间存在较大的对比，比差最小可达60%。因此，倒置的流体体积模量可以直接评估油气饱和度高的区域。本文以马来盆地某油田为例，介绍了fBMI技术。通过对研究区域内4口井的面板分析，结果得到了验证(图1)。图2b显示了沿目标储层顶部的水平面提取的反向流体体积模量。蓝色表示高体积模量对应含水区，而黄红色表示低含油区。将西北地区流体体积模数值较低的区域校准为该地区已知的生产区域。fBMI显示了烃存在的高可能性区域，并提供了与烃饱和度存在直接相关的流体参数的定量测量。图1马来盆地测井资料含水饱和度(蓝色曲线)与流体体积模量(红色曲线)对比分析黑色条表示煤间隔。图2:a)马来盆地某油田顶部储层反演声阻抗图。b)由fBMI得到的相应流体体积模量值。fBMI是一种新的四参数线性振幅-偏移反演技术，可以从地震数据中提供与流体体积模量直接相关的定量流体参数。将其作为油气远景直接评价的工具，用于区分气、油、凝析油和水。
{"title":"Accurate Pore Fluid Indicator Prediction Using Seismic Fluid Bulk Modulus Inversion","authors":"M. Jaya, Ghazali Ahmad Riza, Ahmad Fuad M. Izzuljad, Mad Sahad Salbiah","doi":"10.2118/208174-ms","DOIUrl":"https://doi.org/10.2118/208174-ms","url":null,"abstract":"\u0000 \u0000 \u0000 The prediction of fluid parameter related to hydrocarbon presence using seismic data has often been limited by the performance of probability density function in estimating fluid properties from seismic inversion results. A novel fluid bulk modulus inversion (fBMI) is a pre-stack seismic inversion technique that has been developed to allow a direct estimation of pore fluid bulk modulus (Kf) from seismic data. Real data application in Malay basin showcases that Kf volume can be used to pinpoint areas with high probability of hydrocarbon presence.\u0000 \u0000 \u0000 \u0000 The fluid term AVO reflectivity (Russell et al., 2011) is used as the basis of our formulation and has been extended to allow direct estimation of pore fluid bulk modulus, shearmodulus, porosity parameter and density through standard least-square inversion. The novel formulation is able to relax the dependency of fluid terms on the porosity. To demonstrate this, verifications were made against standard linear AVO approximations. Our observation shows that the young tertiary basins such as the Malay basin the fluid bulk modulus values have a big contrast between hydrocarbon saturated and water bearing reservoirs with a minimum of 60% ratio difference. The inverted fluid bulk modulus volume provides thus a direct assessment of areas with high probability of hydrocarbon saturation.\u0000 \u0000 \u0000 \u0000 In this paper, the fBMI technique is showcased on a field in the Malay basin. The outcome is demonstrated on a well panel analysis for four wells located across the study area (Figure 1). The inverted fluid bulk modulus extracted along a horizon representing the top of target reservoir is shown in Figure 2b. The blue color indicates high bulk modulus corresponds to water-bearing zone, while the yellow-red color range corresponding to low hydrocarbon-bearing zones. The areas of low fluid bulk modulus values at the north-western region are calibrated to known production zones in that region. fBMI shows areas that delineate high probability of hydrocarbon presence and provides a quantitative measure in terms of fluid parameter directly related to the presence of hydrocarbon saturations. Figure 1: Comparison analysis of water saturation (blue curve) and fluid bulk modulus (red curve) of well log data in the Malay basin. Black strips indicate the coal intervals. Figure 2: a) Inverted acoustic impedance extracted from the top reservoir horizon of a field in the Malay basin. b) The corresponding fluid bulk modulus values from fBMI.\u0000 \u0000 \u0000 \u0000 The fBMI is a new four parameters linear amplitude-versus-offset inversion technique that provides quantitative fluid parameter directly related to fluid bulk modulus from seismic data. It is utilized as a tool for direct hydrocarbon prospect assessment to differentiate gas, oil, condensate and water.\u0000","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81424667","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}
Sawsan M. Ali, MEng, CEng, MIChemE, Santhanam Thyagarajan, Ashwani Kataria, Sami Al Ankar, Amal Al Marzooqi
Numerous CO2 injection pipeline applications have been developed and implemented in the past decades in the UAE and all around the globe. Transporting the CO2 in dense phase, rather than in gas or liquid phases, is well recognized of being techno-economically attractive with respect to its major CAPEX benefits of optimized pipeline material of construction; which is driven by the high water solubility in dense phase CO2 as well as the optimized pipeline size which is greatly influenced by the density and viscosity characteristics of supercritical/dense phase CO2. In light of the active deployment of dense phase CO2 injection EOR pipeline transportation across the various existing and future CO2 capture facilities across the UAE, ADNOC onshore technical expertise team has been conducting intensive research analysis on the unique thermodynamic aspects of dense phase CO2 pipeline systems. The focus was directed towards understanding the transient characteristics, which directly influence crucial design strategies including and not limited to CO2 purity specifications, CO2 pipeline pressure and temperature operating envelopes as well as the developed operating philosophy which involves start-up, shutdown and depressurization. While optimizing the economics of the carbon capture units (CCUS) is a pivotal strategy mandating rationalizing the dictated purity level of the captured CO2 and valorizing the projects. However, such thrifty initiatives to moderate the costs of the selected CO2 removal technologies can lead to underlying cascading effects of the lower purity recovered CO2 on systems design and its operation. As part of the nation's strategic objective to reduce carbon footprint, CO2 has been recovered for EOR re-injection applications. Relaxing the purity specification met by the CO2 capture units can positively improve the cost of the recovery plant while may potentially have adverse impacts on CO2 pipeline integrity. This paper provides a comprehensive analysis of the impact of the CO2 purity specification on the flow assurance safety performance of dense phase CO2 pipeline. It is worth highlighting that the design of CO2 systems is challenged by the paucity of the available reference design guidelines since domain of CO2 itself is still evolving under an active area of research. Although some previous publications have demonstrated the latent underlying effects of imputiries such as (N2, H2, SO2, NO2, CH4, C2H6, and Argon) on the physical and thermodynamic behavior of CO2 systems, however, this was supported by literature experimental modelling without transient analysis. In this paper, the behavior of varying CO2 purity levels on the design and operational aspects of CO2 pipeline is substantiated and both steady state and transient flow assurance modelling are presented. Gauging the system's design integrity cannot be solely assured from the perspective of steady state behavior and hence this paper's findings provide additional infor
{"title":"Impact of CCUS Impurities on Dense Phase CO2 Pipeline Surface Engineering Design","authors":"Sawsan M. Ali, MEng, CEng, MIChemE, Santhanam Thyagarajan, Ashwani Kataria, Sami Al Ankar, Amal Al Marzooqi","doi":"10.2118/207354-ms","DOIUrl":"https://doi.org/10.2118/207354-ms","url":null,"abstract":"\u0000 Numerous CO2 injection pipeline applications have been developed and implemented in the past decades in the UAE and all around the globe. Transporting the CO2 in dense phase, rather than in gas or liquid phases, is well recognized of being techno-economically attractive with respect to its major CAPEX benefits of optimized pipeline material of construction; which is driven by the high water solubility in dense phase CO2 as well as the optimized pipeline size which is greatly influenced by the density and viscosity characteristics of supercritical/dense phase CO2.\u0000 In light of the active deployment of dense phase CO2 injection EOR pipeline transportation across the various existing and future CO2 capture facilities across the UAE, ADNOC onshore technical expertise team has been conducting intensive research analysis on the unique thermodynamic aspects of dense phase CO2 pipeline systems. The focus was directed towards understanding the transient characteristics, which directly influence crucial design strategies including and not limited to CO2 purity specifications, CO2 pipeline pressure and temperature operating envelopes as well as the developed operating philosophy which involves start-up, shutdown and depressurization.\u0000 While optimizing the economics of the carbon capture units (CCUS) is a pivotal strategy mandating rationalizing the dictated purity level of the captured CO2 and valorizing the projects. However, such thrifty initiatives to moderate the costs of the selected CO2 removal technologies can lead to underlying cascading effects of the lower purity recovered CO2 on systems design and its operation.\u0000 As part of the nation's strategic objective to reduce carbon footprint, CO2 has been recovered for EOR re-injection applications. Relaxing the purity specification met by the CO2 capture units can positively improve the cost of the recovery plant while may potentially have adverse impacts on CO2 pipeline integrity.\u0000 This paper provides a comprehensive analysis of the impact of the CO2 purity specification on the flow assurance safety performance of dense phase CO2 pipeline. It is worth highlighting that the design of CO2 systems is challenged by the paucity of the available reference design guidelines since domain of CO2 itself is still evolving under an active area of research.\u0000 Although some previous publications have demonstrated the latent underlying effects of imputiries such as (N2, H2, SO2, NO2, CH4, C2H6, and Argon) on the physical and thermodynamic behavior of CO2 systems, however, this was supported by literature experimental modelling without transient analysis. In this paper, the behavior of varying CO2 purity levels on the design and operational aspects of CO2 pipeline is substantiated and both steady state and transient flow assurance modelling are presented. Gauging the system's design integrity cannot be solely assured from the perspective of steady state behavior and hence this paper's findings provide additional infor","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85031267","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}
Christna Golaco, Siddharth Jain, Shams Obaid, Faisal Al Nakeeb
Sharjah National Oil Corporation (SNOC) operates 4 onshore gas condensate reservoirs of which 3 are very mature consisting of 50+ wells producing corrosive hydrocarbons for over 30 years. The integrity of these legacy wells is frequently questioned before any development is conceptualized, thus making it critical to evaluate the well integrity. The cost associated with pulling completions for their evaluation and running logs in all wells is significant and the availability of various emerging technologies for corrosion analysis in the market makes it challenging to choose the most reliable one. This paper focuses on the detailed analysis and comparison of electromagnetic thickness logs run in 10% of the well stock from 2016 to post-workover surface inspection of the downhole recovered tubing's in 2020/21. It also quantifies how correlating different logging technologies for well integrity increases the reliability of the electromagnetic technology applied on offset wells. The paper also showcases a comparison between mechanical and electromagnetic thickness evaluation of the production casing in-situ. Data from all the available logs from past 5 years was compiled for 6 wells. On recovery of the downhole completion tubings via a hydraulic workover, an ultrasonic (UT) inspection was performed on them at surface. Both sets of results (logs and surface inspection) were analyzed on the same logging track to give a comprehensive comparison of actual observation on surface vs the measurement by in-situ logging. Another multi-barrier corrosion and caliper log were run in the production casing to analyze their outcomes alongside older results. The final step was a comparison of all available data to create a broad well integrity profile. It was observed that the remaining production tubing metal thickness detected by electromagnetic tool (logs) and surface ultrasonic measurements were in good conformance (+/-10%). In the corrosion evaluation of the production casing, the electromagnetic tool matched extremely well with the caliper log results. This shows a large reliability of this technology to quantify corrosion in offset wells. The correlation of logs with surface inspection results across wells in the same reservoir did not indicate a strong presence of external corrosion. The study enables the management to make critical business decisions on utilizing the well stock for the future. This work is the first time a comprehensive and critical analysis on the electromagnetic thickness logging technology has been done, comparing their results of remaining wall thickness to various technologies in-situ and on surface. The analysis not only compares technology from various providers, but also mechanical vs electromagnetic measurements along with their respective advantages in quantifying well integrity assurance. The paper also gives an idea on the condition of L-80 tubulars under service for 30+ years.
{"title":"Generating Value from Mature Gas Fields by Quantifying Well Integrity Assurance with a Critical Analysis of Multiple Logs & Retrieved Tubular Surface Inspection","authors":"Christna Golaco, Siddharth Jain, Shams Obaid, Faisal Al Nakeeb","doi":"10.2118/208204-ms","DOIUrl":"https://doi.org/10.2118/208204-ms","url":null,"abstract":"\u0000 Sharjah National Oil Corporation (SNOC) operates 4 onshore gas condensate reservoirs of which 3 are very mature consisting of 50+ wells producing corrosive hydrocarbons for over 30 years. The integrity of these legacy wells is frequently questioned before any development is conceptualized, thus making it critical to evaluate the well integrity. The cost associated with pulling completions for their evaluation and running logs in all wells is significant and the availability of various emerging technologies for corrosion analysis in the market makes it challenging to choose the most reliable one.\u0000 This paper focuses on the detailed analysis and comparison of electromagnetic thickness logs run in 10% of the well stock from 2016 to post-workover surface inspection of the downhole recovered tubing's in 2020/21. It also quantifies how correlating different logging technologies for well integrity increases the reliability of the electromagnetic technology applied on offset wells. The paper also showcases a comparison between mechanical and electromagnetic thickness evaluation of the production casing in-situ.\u0000 Data from all the available logs from past 5 years was compiled for 6 wells. On recovery of the downhole completion tubings via a hydraulic workover, an ultrasonic (UT) inspection was performed on them at surface. Both sets of results (logs and surface inspection) were analyzed on the same logging track to give a comprehensive comparison of actual observation on surface vs the measurement by in-situ logging. Another multi-barrier corrosion and caliper log were run in the production casing to analyze their outcomes alongside older results. The final step was a comparison of all available data to create a broad well integrity profile.\u0000 It was observed that the remaining production tubing metal thickness detected by electromagnetic tool (logs) and surface ultrasonic measurements were in good conformance (+/-10%). In the corrosion evaluation of the production casing, the electromagnetic tool matched extremely well with the caliper log results. This shows a large reliability of this technology to quantify corrosion in offset wells. The correlation of logs with surface inspection results across wells in the same reservoir did not indicate a strong presence of external corrosion. The study enables the management to make critical business decisions on utilizing the well stock for the future.\u0000 This work is the first time a comprehensive and critical analysis on the electromagnetic thickness logging technology has been done, comparing their results of remaining wall thickness to various technologies in-situ and on surface. The analysis not only compares technology from various providers, but also mechanical vs electromagnetic measurements along with their respective advantages in quantifying well integrity assurance. The paper also gives an idea on the condition of L-80 tubulars under service for 30+ years.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89419739","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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