Muktar Kindi, Carmen Hamm, S. Kindi, Shaymaa Al Toqi, Majdi Breiki, Zuwayda Saadi, A. Harthy, Mohsin Jahwari, H. Gheilani, Shaymaa Al Farsi, Bogdan Suchta, S. Persac
This paper discusses the outcome of a hydraulic fracturing concept in a complex commingled water flood field with dense infill well spacing. The objective was to prove this concept of fracturing in a graywater flood field to improve oil production and increase the recovery factor. A mature oil field in the central Sultanate of Oman is facing production decline. The flank part of the field is not meeting the expected production even with water flooding. The main challenge is how to communicate between the injector wells and the producer wells. The 5-spot patterns are not showing effectiveness in the flank area. The heterogeneous reservoir complexity and tightness are the main factors for that. The water zones are very close to or imbedded in between the reservoirs. A careful candidate selection exercise was conducted from the field's 140+ wells. Factors assessed included spacing between producers and injectors, multiple commingled reservoirs, proximity to the Oil Water Contact (OWC), and petrophysical parameters. A successful fracturing trial in one of the wells, located in the southern part of the field and five kms away from nearest oil producer, was followed with a selection of fracture candidates inside the main field. The method of selection was to gather all well data and select criteria to narrow the list to those wells with a higher success probability to help prove a new concept of fracturing in the middle of water injectors and oil producers by controlling fracture length propagation and height containments. A candidate was selected and the fracturing design was manipulated with different scenarios to overcome challenging oil water contact and control fracture propagation to avoid nearby producers and water injectors. The fracture was design selected and the operation successfully implemented, which resulted in a contained fracture confirmed by the low water cut, salinity results, and the radioactive tracer. One lesson learned from the first fractured well was that the pump design should be optimized to sustain a new production profile after the fracture treatment. Triple production resulted from the initial production stage and a fracturing proposal was prepared to follow the success of the operation.
{"title":"Will Hydraulic Fracturing Enhance the Production Recovery in a Complex Comingled Water Flood Field?","authors":"Muktar Kindi, Carmen Hamm, S. Kindi, Shaymaa Al Toqi, Majdi Breiki, Zuwayda Saadi, A. Harthy, Mohsin Jahwari, H. Gheilani, Shaymaa Al Farsi, Bogdan Suchta, S. Persac","doi":"10.2118/200066-ms","DOIUrl":"https://doi.org/10.2118/200066-ms","url":null,"abstract":"\u0000 This paper discusses the outcome of a hydraulic fracturing concept in a complex commingled water flood field with dense infill well spacing. The objective was to prove this concept of fracturing in a graywater flood field to improve oil production and increase the recovery factor.\u0000 A mature oil field in the central Sultanate of Oman is facing production decline. The flank part of the field is not meeting the expected production even with water flooding. The main challenge is how to communicate between the injector wells and the producer wells. The 5-spot patterns are not showing effectiveness in the flank area. The heterogeneous reservoir complexity and tightness are the main factors for that. The water zones are very close to or imbedded in between the reservoirs.\u0000 A careful candidate selection exercise was conducted from the field's 140+ wells. Factors assessed included spacing between producers and injectors, multiple commingled reservoirs, proximity to the Oil Water Contact (OWC), and petrophysical parameters.\u0000 A successful fracturing trial in one of the wells, located in the southern part of the field and five kms away from nearest oil producer, was followed with a selection of fracture candidates inside the main field. The method of selection was to gather all well data and select criteria to narrow the list to those wells with a higher success probability to help prove a new concept of fracturing in the middle of water injectors and oil producers by controlling fracture length propagation and height containments. A candidate was selected and the fracturing design was manipulated with different scenarios to overcome challenging oil water contact and control fracture propagation to avoid nearby producers and water injectors. The fracture was design selected and the operation successfully implemented, which resulted in a contained fracture confirmed by the low water cut, salinity results, and the radioactive tracer. One lesson learned from the first fractured well was that the pump design should be optimized to sustain a new production profile after the fracture treatment. Triple production resulted from the initial production stage and a fracturing proposal was prepared to follow the success of the operation.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80452720","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}
P. Cavassi, Vittorio Chiodini, Stefano Franci, L. Torri
The paper gives an overview of recent issues in Oil & Gas material selection, as resistance to high levels of H2S, and quality control during production of Carbon Steel and Clad pipes for pipelines, with reference to real cases. Each topic under discussion is first described showing the relevant issues in terms of materials available on the market, failure mechanisms and possible consequences during the service life. Then the challenges are analyzed by mean of a brief review based on the main and most recent corrosion related conferences. Then, making reference to case histories taken from recent offshore development projects, the Company experience is described, highlighting the technical solutions taken and the main results obtained. The first challenge discussed is the corrosion resistance of pipeline materials for transportation of fluids with high levels of H2S. The carbon steel pipes used for large diameters pipes are commonly manufactured with the TMCP, Thermo-Mechanical Controlled Process method. In severe sour service applications they showed to be susceptible to SSC, Sulfide Stress Cracking, due to hard zones that can originate at surface during pipe manufacturing. New non-destructive tests have been developed for the detection of hard zones during pipe production. Besides, SSC tests have been performed on API 5L X52 and X60 pipes samples at H2S partial pressure higher than 10 bar, which gave surprising results. Clad and lined pipes represent alternative materials to TMCP carbon steel, but they are expensive and only few manufacturers are available, with consequence in terms of long delivery time. Furthermore, these materials are not immune to technical problems, as the precipitation of intermetallic phases in the nickel alloy layer during heat treatment. The paper describes the Company experience made in offshore projects where both TMCP carbon steel and clad pipes have been used for pipelines and buckle arrestors. The corrosion and cracking problems described in the paper are relatively new, as well as the technical solutions adopted. New field experience represents additive information to existing literature.
{"title":"Challenges in O&G Material Selection: Experiences and Case Histories","authors":"P. Cavassi, Vittorio Chiodini, Stefano Franci, L. Torri","doi":"10.2118/200077-ms","DOIUrl":"https://doi.org/10.2118/200077-ms","url":null,"abstract":"\u0000 The paper gives an overview of recent issues in Oil & Gas material selection, as resistance to high levels of H2S, and quality control during production of Carbon Steel and Clad pipes for pipelines, with reference to real cases.\u0000 Each topic under discussion is first described showing the relevant issues in terms of materials available on the market, failure mechanisms and possible consequences during the service life. Then the challenges are analyzed by mean of a brief review based on the main and most recent corrosion related conferences. Then, making reference to case histories taken from recent offshore development projects, the Company experience is described, highlighting the technical solutions taken and the main results obtained.\u0000 The first challenge discussed is the corrosion resistance of pipeline materials for transportation of fluids with high levels of H2S. The carbon steel pipes used for large diameters pipes are commonly manufactured with the TMCP, Thermo-Mechanical Controlled Process method. In severe sour service applications they showed to be susceptible to SSC, Sulfide Stress Cracking, due to hard zones that can originate at surface during pipe manufacturing. New non-destructive tests have been developed for the detection of hard zones during pipe production. Besides, SSC tests have been performed on API 5L X52 and X60 pipes samples at H2S partial pressure higher than 10 bar, which gave surprising results.\u0000 Clad and lined pipes represent alternative materials to TMCP carbon steel, but they are expensive and only few manufacturers are available, with consequence in terms of long delivery time. Furthermore, these materials are not immune to technical problems, as the precipitation of intermetallic phases in the nickel alloy layer during heat treatment.\u0000 The paper describes the Company experience made in offshore projects where both TMCP carbon steel and clad pipes have been used for pipelines and buckle arrestors.\u0000 The corrosion and cracking problems described in the paper are relatively new, as well as the technical solutions adopted. New field experience represents additive information to existing literature.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79994318","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}
Abdullah Al Shibli, Hilal Al Maamari, Csimiro Griborio, Simeon Adeponle, Hamed AL Wahaibi, Khalid AL Zuhaimi, Hamoud Al Saadi, Mohammad Bdair
FH is one of the largest oil producing assets in the Sultanate of Oman. With more than 30 years of production, the current recovery mechanism from the naturally fractured carbonates is relying 80% on the gas oil gravity drainage (GOGD) process whereby produced formation gas is re-injected into the reservoir for pressure maintenance. Optimizing the GOGD process and hence maximizing oil production is the main objective in FH WRFM strategy. Controlling the formation gas production from subsurface and surface gas capacity handling are the main challenges to unlock reservoir oil potential. Down hole gas shut-off technology has been proposed in 2018 to control high GOR (+1000) producers and minimize formation gas production for more efficient GOGD process. The technology provides a mean for blocking formation gas through autonomous valve compartments installed within a production liner in the open hole section of the horizontal wells. The independent compartments are positioned against the open fractures and the inflow from the fractures to the open hole is controlled autonomously based on the fracture GOR. The valves in each compartment is designed to close against low viscosity fluid (gas) and allow high viscosity (liquids) to flow into the liner. Screening process has identified up to 80 candidates for the technology with a potential gain of up to 6% of the total field production. Formation GOR, well uptime and lateral fracture interference are the top criteria for candidate selection. The full field deployment started in July 2018 after a six months trial period with a target to complete the full scope by 2022. 90% reduction in formation gas has been observed in the wells where gas shut-off technology have been installed. A sustainable oil gain up to 50% has been realized after the gas reduction from the first 14 candidates. In addition to that, a significant improvement in the well uptime from 40% to 80% has also been recognized due to low producing GOR after the technology deployment. The technology has also enabled the re-instatement of long term closed-in wells due to high producing GOR. The originality of the technology lies on the ability of the downhole inflow control valves to react to the gas autonomously and successfully shut off the gas contribution and the same time allow oil to flow.
{"title":"Autonomous Gas Shut-Off in Gas Oil Gravity Drainage Reservoir, Sultanate of Oman","authors":"Abdullah Al Shibli, Hilal Al Maamari, Csimiro Griborio, Simeon Adeponle, Hamed AL Wahaibi, Khalid AL Zuhaimi, Hamoud Al Saadi, Mohammad Bdair","doi":"10.2118/200102-ms","DOIUrl":"https://doi.org/10.2118/200102-ms","url":null,"abstract":"\u0000 FH is one of the largest oil producing assets in the Sultanate of Oman. With more than 30 years of production, the current recovery mechanism from the naturally fractured carbonates is relying 80% on the gas oil gravity drainage (GOGD) process whereby produced formation gas is re-injected into the reservoir for pressure maintenance. Optimizing the GOGD process and hence maximizing oil production is the main objective in FH WRFM strategy. Controlling the formation gas production from subsurface and surface gas capacity handling are the main challenges to unlock reservoir oil potential.\u0000 Down hole gas shut-off technology has been proposed in 2018 to control high GOR (+1000) producers and minimize formation gas production for more efficient GOGD process. The technology provides a mean for blocking formation gas through autonomous valve compartments installed within a production liner in the open hole section of the horizontal wells. The independent compartments are positioned against the open fractures and the inflow from the fractures to the open hole is controlled autonomously based on the fracture GOR. The valves in each compartment is designed to close against low viscosity fluid (gas) and allow high viscosity (liquids) to flow into the liner.\u0000 Screening process has identified up to 80 candidates for the technology with a potential gain of up to 6% of the total field production. Formation GOR, well uptime and lateral fracture interference are the top criteria for candidate selection. The full field deployment started in July 2018 after a six months trial period with a target to complete the full scope by 2022.\u0000 90% reduction in formation gas has been observed in the wells where gas shut-off technology have been installed. A sustainable oil gain up to 50% has been realized after the gas reduction from the first 14 candidates. In addition to that, a significant improvement in the well uptime from 40% to 80% has also been recognized due to low producing GOR after the technology deployment. The technology has also enabled the re-instatement of long term closed-in wells due to high producing GOR.\u0000 The originality of the technology lies on the ability of the downhole inflow control valves to react to the gas autonomously and successfully shut off the gas contribution and the same time allow oil to flow.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88830722","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. Khan, Abinash Barooh, Muhammad Yousuf Khan, Mohammad Sohel Rahman, Ibrahim Hassan, Rashid Hassan
In horizontal drilling, inefficient hole cleaning causes multiple operational issues and increased pressure loss. In-situ measurement of the cutting transport is essential to understand the hydrodynamics and operational parameters required for the effective hole cleaning. The electrical resistance tomography (ERT) is becoming a promising tool in many industrial applications. The purpose of this study was to provide detailed information about the application of non-invasive ERT system to analyze the volume fraction of solids in the presence of non-Newtonian fluid (0.5 wt% Flowzan) in a drilling annulus. The experiments were conducted in a horizontal flow loop system where the annulus section was 240 (6.16 m) inch long contains the inner and outer diameters of 2.5 inch (6.4 cm) and 4.5inches (11.4 cm), respectively. The obtained results suggested that the ERT system could effectively detect the volume fraction of the solids in the presence of non-Newtonian fluid (Flowzan) at different drilling conditions. Results also revealed that with an increase in fluid velocity, the efficient hole cleaning was observed. Moreover, the drill pipe rotation also positively influenced the cutting transport. Therefore, this study will provide the avenue for the industrial application of in situ ERT measurement technique in the multiphase systems, especially in the presence of the non-Newtonian drilling fluids.
{"title":"Investigating Non-Newtonian Multiphase Cutting Transport in an Extended Reach Well","authors":"M. Khan, Abinash Barooh, Muhammad Yousuf Khan, Mohammad Sohel Rahman, Ibrahim Hassan, Rashid Hassan","doi":"10.2118/200240-ms","DOIUrl":"https://doi.org/10.2118/200240-ms","url":null,"abstract":"\u0000 In horizontal drilling, inefficient hole cleaning causes multiple operational issues and increased pressure loss. In-situ measurement of the cutting transport is essential to understand the hydrodynamics and operational parameters required for the effective hole cleaning. The electrical resistance tomography (ERT) is becoming a promising tool in many industrial applications. The purpose of this study was to provide detailed information about the application of non-invasive ERT system to analyze the volume fraction of solids in the presence of non-Newtonian fluid (0.5 wt% Flowzan) in a drilling annulus. The experiments were conducted in a horizontal flow loop system where the annulus section was 240 (6.16 m) inch long contains the inner and outer diameters of 2.5 inch (6.4 cm) and 4.5inches (11.4 cm), respectively. The obtained results suggested that the ERT system could effectively detect the volume fraction of the solids in the presence of non-Newtonian fluid (Flowzan) at different drilling conditions. Results also revealed that with an increase in fluid velocity, the efficient hole cleaning was observed. Moreover, the drill pipe rotation also positively influenced the cutting transport. Therefore, this study will provide the avenue for the industrial application of in situ ERT measurement technique in the multiphase systems, especially in the presence of the non-Newtonian drilling fluids.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90857469","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}
Hamdan Saidi, Mohammed A-Aamri, A. Al - Senani, Khalid AL-Aani
Knowledge of in-situ stresses and geomechanical properties is important for wellbore stability and hydraulic fracture optimization applications. Both mechanical rock properties (e.g., Young's modulus and Poisson's ratio) and the stresses represent the initial step in constructing a geomechanical model that will eventually require static calibration from the lab or field tests. Nonetheless, a wellbore deformation-based inverse analysis solution has become an alternative method that characterizes in-situ stress in particular. In this paper, a genetic algorithm and probabilistic analysis methods are proposed and integrated into a well-drilled known analytical method to characterize both stresses and geomechanical properties. Systematic steps have been applied to this analysis. First, borehole geometry (i.e., multi-arm caliper), mud weight, and vertical pressure (from the density log) are well-defined inputs for deformation-stress relationships. Unknown parameters have also been determined and include horizontal stress, Poisson's ratio, and Young's modulus. Subsequently, the minimum and maximum expected values for each unknown parameter have been defined. Thousands of combinations have been created by the analytical equation (fitness function). In addition, the semi-genetic algorithm concept was used as an optimization method to find the best solution from a wide range of inputs for a given fitness function. The first hundred strongest fitness combinations were then chosen for the next level, which had a noticeably higher frequency number using the statistical analysis technique. The approach was checked with a real field example, the results indicated the measured values of geomechanical properties, and horizontal stress were reasonably consistent with the actual field data and previous studies in the field. In particular, the proposed approach allows for a realistic estimate of the most difficult stress (i.e., Max horizontal stress), which was ~45 % higher than minimum horizontal stress. The proposed technique was developed to reduce in-situ pressure uncertainties and geomechanical properties for the studied area. Results from this paper presented a simple and practical alternative method for the determination of geomechanical parameters using a simple logging tool (e.g., a caliper) that theoretically provides a robustness guide for wellbore stability and hydraulic fracture models for tight gas fields.
{"title":"In-Situ Stresses and Geomechanical Properties Characterization Using Robust Optimization Approach, Tested in a Tight Gas field, Sultanate of Oman","authors":"Hamdan Saidi, Mohammed A-Aamri, A. Al - Senani, Khalid AL-Aani","doi":"10.2118/200097-ms","DOIUrl":"https://doi.org/10.2118/200097-ms","url":null,"abstract":"\u0000 Knowledge of in-situ stresses and geomechanical properties is important for wellbore stability and hydraulic fracture optimization applications. Both mechanical rock properties (e.g., Young's modulus and Poisson's ratio) and the stresses represent the initial step in constructing a geomechanical model that will eventually require static calibration from the lab or field tests. Nonetheless, a wellbore deformation-based inverse analysis solution has become an alternative method that characterizes in-situ stress in particular. In this paper, a genetic algorithm and probabilistic analysis methods are proposed and integrated into a well-drilled known analytical method to characterize both stresses and geomechanical properties.\u0000 Systematic steps have been applied to this analysis. First, borehole geometry (i.e., multi-arm caliper), mud weight, and vertical pressure (from the density log) are well-defined inputs for deformation-stress relationships. Unknown parameters have also been determined and include horizontal stress, Poisson's ratio, and Young's modulus. Subsequently, the minimum and maximum expected values for each unknown parameter have been defined. Thousands of combinations have been created by the analytical equation (fitness function). In addition, the semi-genetic algorithm concept was used as an optimization method to find the best solution from a wide range of inputs for a given fitness function. The first hundred strongest fitness combinations were then chosen for the next level, which had a noticeably higher frequency number using the statistical analysis technique. The approach was checked with a real field example, the results indicated the measured values of geomechanical properties, and horizontal stress were reasonably consistent with the actual field data and previous studies in the field. In particular, the proposed approach allows for a realistic estimate of the most difficult stress (i.e., Max horizontal stress), which was ~45 % higher than minimum horizontal stress.\u0000 The proposed technique was developed to reduce in-situ pressure uncertainties and geomechanical properties for the studied area. Results from this paper presented a simple and practical alternative method for the determination of geomechanical parameters using a simple logging tool (e.g., a caliper) that theoretically provides a robustness guide for wellbore stability and hydraulic fracture models for tight gas fields.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91537706","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The studied field is located in North Oman asset and developed through waterflood line-drive since 1980s with top quartile recovery factor. In the period between 2010 and 2012, production has declined faster than expected reaching to a peak decline rate of 19% per year resulted to significant associated oil production loss. This abstract summarizes the recovery process for waterflood development supported with lean approach by WRFM team not only to arrest production decline but also to flip the coin to production incline in 2015-2016. The major reasons that led to the ineffective waterflood performance in this field were several surface and subsurface issues related to water distribution, low injection efficiency and low level of integration within the team. The success achieved through focused proactive waterflood management (Asset's WRFM Plan, 2016) and seamless integration with field operations and asset leadership with below key steps: Setting a firm WRFM Waterflood Strategy focusing on waterflood management, field/reservoir operating envelope and pressure maintenance. Goal Deployment value stream metrics aimed to improve reservoir operating envelope compliance by improving water-injectivity compliance that ensures effective and even injection water distribution etc. The pressure maintenance strategies include priorities the injection optimization in the low-pressure blocks and continuous monitoring of reservoir pressure through periodic acquisition of pressure surveys. This resulted in significant improvement of average reservoir pressure. Standardized regular field, pattern/ sector and well reviews (Chatterjee, Someshwar et.al., 2017) resulted in effective sweep monitoring strategy by using latest FDP static and dynamic models calibrated with recent surveillance data (RST, MPLT etc.). This process helps to generate and optimize the WRFM opportunities to maximize the production. Periodic waterflood health checks by external and internal experts mainly focused on accessing waterflood improvements and benchmarked with other fields of the asset during 2014, 2016 and 2018. The waterflood health check score improved with time and field achieved the highest score across all the other matured fields in North Oman. More importantly, the noticeable improvement in integration between different teams i.e. petroleum, operation, and engineering on daily to weekly basis ensures stability of the WI performance, meeting injection target and honest transparent communications to work as ONE TEAM through different session using Leader Standard Work (LSW). These efforts by the integrated team resulted in: Arresting the production decline from 19% annual effective to 6% within 3 years Reversing the decline trend of 3% between 2015-2016 Safeguard more than a mln m3 of asset's reserves A gain of average oil rate for reversing the decline trend This project is an excellent example of being innovative with lean structure and simple "Going Back
该油田位于阿曼北部，自20世纪80年代以来一直通过注水线驱进行开发，采收率最高。在2010年至2012年期间，产量的下降速度比预期的要快，达到了每年19%的峰值，导致了严重的石油产量损失。该摘要总结了WRFM团队在精益方法支持下的水驱开发的采收率过程，不仅可以阻止产量下降，还可以扭转2015-2016年的产量趋势。导致该油田注水效果不佳的主要原因是与水分布、注入效率低以及团队内部整合水平低有关的几个地面和地下问题。通过专注于主动注水管理(资产的WRFM计划，2016年)以及与现场作业和资产领导的无缝集成，通过以下关键步骤取得了成功:制定坚定的WRFM注水战略，重点关注注水管理、油田/油藏操作包封和压力维护。目标部署价值流指标旨在通过提高注水能力，确保有效、均匀的注水分配等，来提高油藏作业包层的合规性。压力维持策略包括优先优化低压区块的注入，以及通过定期采集压力测量来持续监测储层压力。这使得平均储层压力显著提高。标准化的常规油田、模式/部门和井评价(Chatterjee, Someshwar等)。， 2017)通过使用最新的FDP静态和动态模型校准最新的监测数据(RST, MPLT等)，产生了有效的扫描监测策略。该过程有助于产生和优化WRFM机会，以最大限度地提高产量。在2014年、2016年和2018年期间，外部和内部专家定期进行水驱健康检查，主要关注水驱改善措施，并与该资产的其他油田进行基准测试。随着时间的推移，该油田的注水健康检查得分有所提高，在阿曼北部所有成熟油田中得分最高。更重要的是，不同团队(石油、作业和工程)之间的整合在每日到每周的基础上显著改善，确保了WI性能的稳定性，满足了注入目标，并通过使用Leader Standard work (LSW)的不同会话作为一个团队进行诚实透明的沟通。综合团队的努力取得了以下成果:在三年内将产量从19%的年有效产量下降到6%，扭转了2015-2016年3%的下降趋势，保障了超过100万立方米的资产储量，提高了平均产油率，扭转了下降趋势。该项目是一个很好的例子，采用精益结构和简单的“回归基础”原则进行水驱管理。以商业思维交付项目，遏制衰退，维护储量;通过对注水评估和强整合的基准进行外部关注，显示出最高标准的改进组织行为。
{"title":"Journey of Waterflood Excellence in a Matured Field, North of Sultanate of Oman","authors":"S. Chatterjee, Nasser Riyami, Ali Ruqaishi","doi":"10.2118/200107-ms","DOIUrl":"https://doi.org/10.2118/200107-ms","url":null,"abstract":"\u0000 \u0000 \u0000 The studied field is located in North Oman asset and developed through waterflood line-drive since 1980s with top quartile recovery factor. In the period between 2010 and 2012, production has declined faster than expected reaching to a peak decline rate of 19% per year resulted to significant associated oil production loss. This abstract summarizes the recovery process for waterflood development supported with lean approach by WRFM team not only to arrest production decline but also to flip the coin to production incline in 2015-2016.\u0000 \u0000 \u0000 \u0000 The major reasons that led to the ineffective waterflood performance in this field were several surface and subsurface issues related to water distribution, low injection efficiency and low level of integration within the team. The success achieved through focused proactive waterflood management (Asset's WRFM Plan, 2016) and seamless integration with field operations and asset leadership with below key steps:\u0000 Setting a firm WRFM Waterflood Strategy focusing on waterflood management, field/reservoir operating envelope and pressure maintenance. Goal Deployment value stream metrics aimed to improve reservoir operating envelope compliance by improving water-injectivity compliance that ensures effective and even injection water distribution etc. The pressure maintenance strategies include priorities the injection optimization in the low-pressure blocks and continuous monitoring of reservoir pressure through periodic acquisition of pressure surveys. This resulted in significant improvement of average reservoir pressure. Standardized regular field, pattern/ sector and well reviews (Chatterjee, Someshwar et.al., 2017) resulted in effective sweep monitoring strategy by using latest FDP static and dynamic models calibrated with recent surveillance data (RST, MPLT etc.). This process helps to generate and optimize the WRFM opportunities to maximize the production. Periodic waterflood health checks by external and internal experts mainly focused on accessing waterflood improvements and benchmarked with other fields of the asset during 2014, 2016 and 2018. The waterflood health check score improved with time and field achieved the highest score across all the other matured fields in North Oman. More importantly, the noticeable improvement in integration between different teams i.e. petroleum, operation, and engineering on daily to weekly basis ensures stability of the WI performance, meeting injection target and honest transparent communications to work as ONE TEAM through different session using Leader Standard Work (LSW).\u0000 \u0000 \u0000 \u0000 These efforts by the integrated team resulted in:\u0000 Arresting the production decline from 19% annual effective to 6% within 3 years Reversing the decline trend of 3% between 2015-2016 Safeguard more than a mln m3 of asset's reserves A gain of average oil rate for reversing the decline trend\u0000 This project is an excellent example of being innovative with lean structure and simple \"Going Back","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84787324","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}
N. Varma, Yash Koshatwar, Manish Kumar, A. Savelyev, Aneesh Jha, Rekha Kumari, Ankesh Nagar, Preyas Srivastav, Pranay Srivastav, Satish Nekkanti, A. Bohra, Sanjeev Veermani
This paper aims to describe a model created to determine various important parameters to monitor oil producer wells with different artificial lift types: Jet Pump (JP) and Electric Submersible Pump (ESP) of Mangala & Aishwarya fields. The fields contain medium gravity viscous crude (10-40cp) in high permeability (1-5 Darcy) sands. In order to overcome adverse mobility ratio and improve sweep efficiency, polymer flooding was adopted. As the Polymer flooding proceeded, polymer breakthrough in producer wells was observed. The major challenges faced in producer wells is polymer/scale depositions realized during well interventions. This issue has surfaced in field due to polymer breakthrough in oil producers and mixing of produced polymer concentration in well fluid with scales, wax or other bivalent ions. Major concerns due to polymer deposition included, fouling of artificial lift system, decrease of well uptime, jet pump (type of artificial lift) & ESP efficiency decrease. ESP & Reverse jet pumping are the major artificial lifts for the field, where power fluid is pumped through annulus and production is taken through tubing. With continued jet Pump fouling due to Polymer, wax & scale agglomerate, well uptime decreased. During jet pump redressing, polymer deposition has been observed in the body X-over (reservoir liquid path), check valve assembly, throat and spacer nozzle to throat inside jet-pump. Thus, a necessity was felt to address the issue with a proactive approach. Continuous chemical dosing method was tried and proven successfully, but it was not cost effective. Hence empirical based modelling was required which can quantify these parameters to plan for well intervention & well clean-up jobs. The developed model is "intelligent" and determines various parameters like – Productivity index(PI) of jet pump well without having suction pressure data, jet pump nozzle loss coefficient, ESP pump efficiency (ESP wear), annulus deposition & debris deposition in tubing reducing effective ID of annulus & tubing respectively. The model calculates from every newly logged Multiphase flowmeter rates, water cut, Annulus pumping pressure & tubing head pressure (THP) events and determines its approach of marking the risk levels of a well. With continued JP/ESP fouling, tubing deposition & PI drop due to Polymer, wax & scale agglomerate, well uptime & production rate is decreased.
{"title":"Deterministic Approach Towards Well Intervention Candidate Selection & Quantification of Parameters in Esp & Jet Pump Wells","authors":"N. Varma, Yash Koshatwar, Manish Kumar, A. Savelyev, Aneesh Jha, Rekha Kumari, Ankesh Nagar, Preyas Srivastav, Pranay Srivastav, Satish Nekkanti, A. Bohra, Sanjeev Veermani","doi":"10.2118/200174-ms","DOIUrl":"https://doi.org/10.2118/200174-ms","url":null,"abstract":"\u0000 This paper aims to describe a model created to determine various important parameters to monitor oil producer wells with different artificial lift types: Jet Pump (JP) and Electric Submersible Pump (ESP) of Mangala & Aishwarya fields. The fields contain medium gravity viscous crude (10-40cp) in high permeability (1-5 Darcy) sands. In order to overcome adverse mobility ratio and improve sweep efficiency, polymer flooding was adopted. As the Polymer flooding proceeded, polymer breakthrough in producer wells was observed. The major challenges faced in producer wells is polymer/scale depositions realized during well interventions. This issue has surfaced in field due to polymer breakthrough in oil producers and mixing of produced polymer concentration in well fluid with scales, wax or other bivalent ions. Major concerns due to polymer deposition included, fouling of artificial lift system, decrease of well uptime, jet pump (type of artificial lift) & ESP efficiency decrease.\u0000 ESP & Reverse jet pumping are the major artificial lifts for the field, where power fluid is pumped through annulus and production is taken through tubing. With continued jet Pump fouling due to Polymer, wax & scale agglomerate, well uptime decreased. During jet pump redressing, polymer deposition has been observed in the body X-over (reservoir liquid path), check valve assembly, throat and spacer nozzle to throat inside jet-pump. Thus, a necessity was felt to address the issue with a proactive approach. Continuous chemical dosing method was tried and proven successfully, but it was not cost effective. Hence empirical based modelling was required which can quantify these parameters to plan for well intervention & well clean-up jobs. The developed model is \"intelligent\" and determines various parameters like – Productivity index(PI) of jet pump well without having suction pressure data, jet pump nozzle loss coefficient, ESP pump efficiency (ESP wear), annulus deposition & debris deposition in tubing reducing effective ID of annulus & tubing respectively. The model calculates from every newly logged Multiphase flowmeter rates, water cut, Annulus pumping pressure & tubing head pressure (THP) events and determines its approach of marking the risk levels of a well. With continued JP/ESP fouling, tubing deposition & PI drop due to Polymer, wax & scale agglomerate, well uptime & production rate is decreased.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86014263","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}
Fluid sampling and accurate PVT characterization is an important part of any field development planning and its long term management. Accurate characterization of the fluid gives confidence to project economics and can help avoid big losses due to improper facilities design and forecasting. In the oil & gas industry there is a lack of understanding in the requirements for high precision sampling for impurities and analytical methodologies to accurately characterize gas condensate for facilities design. The objective of this paper is to evaluate the current industry sampling best practices and define a new workflow for reliable gas condensate and impurities characterization for facilities development during the exploration/delineation phase of a field's life. The proposed methodology is significantly impacted by reservoir fluid saturation pressure relative to the static reservoir and flowing bottomhole pressures. It allows better profiling of complex gas condensate impurities such as H2S, and its sulfur intermediate species like polysulfides and elemental sulfur, volatile organic sulfur species such as mercaptans and carbonyl sulfides, and as well as Mercury, Arsenic, Benzene Toluene, Ethylbenzene and Xylene (BTEX), water, solids, N2, CO2, He, Radon. The application of the new proposed workflow provides accurate and reproducible PVT data sets for reservoir studies and facilities design.
{"title":"High Precision Fluid Sampling for Gas Condensate Reservoirs and Facilities Concept Development","authors":"Kabir Akim, Nengkoda Ardian, Senan H. Bokhamseen","doi":"10.2118/200216-ms","DOIUrl":"https://doi.org/10.2118/200216-ms","url":null,"abstract":"\u0000 Fluid sampling and accurate PVT characterization is an important part of any field development planning and its long term management. Accurate characterization of the fluid gives confidence to project economics and can help avoid big losses due to improper facilities design and forecasting. In the oil & gas industry there is a lack of understanding in the requirements for high precision sampling for impurities and analytical methodologies to accurately characterize gas condensate for facilities design.\u0000 The objective of this paper is to evaluate the current industry sampling best practices and define a new workflow for reliable gas condensate and impurities characterization for facilities development during the exploration/delineation phase of a field's life. The proposed methodology is significantly impacted by reservoir fluid saturation pressure relative to the static reservoir and flowing bottomhole pressures. It allows better profiling of complex gas condensate impurities such as H2S, and its sulfur intermediate species like polysulfides and elemental sulfur, volatile organic sulfur species such as mercaptans and carbonyl sulfides, and as well as Mercury, Arsenic, Benzene Toluene, Ethylbenzene and Xylene (BTEX), water, solids, N2, CO2, He, Radon. The application of the new proposed workflow provides accurate and reproducible PVT data sets for reservoir studies and facilities design.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83464024","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}
Several techniques have been applied to improve fluid conformance of injection wells to increase water flooding performance and eventually field oil recovery. Normal outflow control devices (OCDs) are effective solutions for this problem in reservoirs with static properties, however, they fail in reservoirs with complex/dynamic properties including growing fractures. There, the continuously increasing contrast in the injectivity of a section with the fractures compared to the rest of the well causes diverting a great portion of the injected fluid into the thief zone thus creating short-circuit to the nearby producer wells. A new autonomous outflow control device (AOCD) has been developed recently to choke the injection fluid into the propagating fractures crossing the well autonomously after reaching a designed flowrate thus maintaining a balanced/prescribed injection distribution. This work focuses on modelling design workflow to find the optimum completion design and demonstrates its added value through an extensive dynamic reservoir simulation study. Like other OCDs, this device should be installed in several zones in the injection well. The device is a bi-stable flow control device with two operating conditions, one, devices operate as normal passive OCDs initially, and two, if the injected flowrate flowing through the valve exceeds a designed limit, the device will automatically shut off. This allows the denied fluid to that specific zone to be distributed among the neighbouring zones. This performance enables the operators to minimise the impacts of thief zones on the injected fluid conformance and to react to a dynamic change in reservoirs properties specifically the growth of fractures. This also reduces the injection cost and improving the reliability of the injection well systems. A sector reservoir-model coupled with a Geomechanics model via commercial reservoir simulation software was established to study the impacts of temperature and flowrate of injection fluids on the performance of injection wells completed with various completions. The simulation study showed less imposed pressure and much more efficient fluid conformance and fracture growth was delivered with the new device compared to various other completions. The results showed how the new device may change the sequence of thermal fractures initiation and the extends of their growth. This autonomously reactive control on the injection fluid conformance resulted in an increased sweep and ultimate oil recovery (up to 20%) while reducing the total volume of injected fluid (by 30%), so significantly increased field NPV. This study illustrates how efficiently the new injection valve chokes/restricts water into dynamic thief zones in a reservoir. This new device is autonomous and reacts to the rate of fluid passing through and eliminates the cost of alternative techniques including running PLT and following intervention actions.
{"title":"The Dynamic Performance Evaluation of the New Generation of Outflow Control Devices Autonomously Controlling the Conformance of Injection Fluids","authors":"M. Moradi, S. Todman","doi":"10.2118/200177-ms","DOIUrl":"https://doi.org/10.2118/200177-ms","url":null,"abstract":"\u0000 Several techniques have been applied to improve fluid conformance of injection wells to increase water flooding performance and eventually field oil recovery. Normal outflow control devices (OCDs) are effective solutions for this problem in reservoirs with static properties, however, they fail in reservoirs with complex/dynamic properties including growing fractures. There, the continuously increasing contrast in the injectivity of a section with the fractures compared to the rest of the well causes diverting a great portion of the injected fluid into the thief zone thus creating short-circuit to the nearby producer wells.\u0000 A new autonomous outflow control device (AOCD) has been developed recently to choke the injection fluid into the propagating fractures crossing the well autonomously after reaching a designed flowrate thus maintaining a balanced/prescribed injection distribution. This work focuses on modelling design workflow to find the optimum completion design and demonstrates its added value through an extensive dynamic reservoir simulation study. Like other OCDs, this device should be installed in several zones in the injection well. The device is a bi-stable flow control device with two operating conditions, one, devices operate as normal passive OCDs initially, and two, if the injected flowrate flowing through the valve exceeds a designed limit, the device will automatically shut off. This allows the denied fluid to that specific zone to be distributed among the neighbouring zones. This performance enables the operators to minimise the impacts of thief zones on the injected fluid conformance and to react to a dynamic change in reservoirs properties specifically the growth of fractures. This also reduces the injection cost and improving the reliability of the injection well systems.\u0000 A sector reservoir-model coupled with a Geomechanics model via commercial reservoir simulation software was established to study the impacts of temperature and flowrate of injection fluids on the performance of injection wells completed with various completions. The simulation study showed less imposed pressure and much more efficient fluid conformance and fracture growth was delivered with the new device compared to various other completions. The results showed how the new device may change the sequence of thermal fractures initiation and the extends of their growth. This autonomously reactive control on the injection fluid conformance resulted in an increased sweep and ultimate oil recovery (up to 20%) while reducing the total volume of injected fluid (by 30%), so significantly increased field NPV. This study illustrates how efficiently the new injection valve chokes/restricts water into dynamic thief zones in a reservoir. This new device is autonomous and reacts to the rate of fluid passing through and eliminates the cost of alternative techniques including running PLT and following intervention actions.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88455073","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}
Karimova Marzhan, Pourafshary Peyman, Fani Mahmood
The application of low salinity water and ion management of the injected water affects the oil recovery in carbonate formations. Different forced and spontaneous imbibition experiments have been practiced on the carbonate core samples to show the performance of this smart water injection. Various experimental and modeling approaches have been applied by different researchers to optimize the smart waterflooding process. To achieve more practical conditions, the injection time of the smart water should be reduced to control the preparation cost on the field scale. In this paper, we present findings from different modeling/experimental studies to improve the performance of smart water flooding in carbonate formations by the idea of shock/soaking. Different researches showed that the presence of active ions such as Mg2+ and SO42- in the injection water alters the wettability of carbonates to more water-wet state and also reduces the IFT between the oil and the injected brine. Hence, spiking active ions concentration in the low salinity water improves oil recovery from carbonate formation. In this work, the optimized smart brine was used for injection with novel injection scheme. The optimized brine was set to be injected as the shock slug between two slugs of high salinity water. This smart water shock flooding was designed to reduce the pore volume of low salinity water flooding. The effect of the slug on relative permeability curves was modeled and analyzed in the core and sector scales. Also we experimentally studied the effect of soaking time after the shock on wettability alteration and improvement in recovery by re-injection of high salinity normal brine. Characterization tests such as contact angle measurement confirmed the effect of shock/soaking on alteration of governing mechanisms such as multi-ion exchange which leads to wettability alteration in the process. Our core flooding experiments showed that the shock injection at the best design can improve the tertiary recovery up to 7.8%. Also, modeling at the reservoir sector shows noticeable incremental oil recovery during the shock injection and high salinity water injection after it. Our modeling/experimental studies clearly illuminated a new approach to improve the performance of low salinity water flooding in an efficient and cheaper way. By this approach, higher oil recovery can be achieved by the application of less amount of diluted water which is beneficial for the oil industry.
{"title":"Shock/Soaking Injection Scheme to Improve Oil Recovery in Carbonate Formations by Low Salinity Water Flooding","authors":"Karimova Marzhan, Pourafshary Peyman, Fani Mahmood","doi":"10.2118/200226-ms","DOIUrl":"https://doi.org/10.2118/200226-ms","url":null,"abstract":"\u0000 The application of low salinity water and ion management of the injected water affects the oil recovery in carbonate formations. Different forced and spontaneous imbibition experiments have been practiced on the carbonate core samples to show the performance of this smart water injection. Various experimental and modeling approaches have been applied by different researchers to optimize the smart waterflooding process. To achieve more practical conditions, the injection time of the smart water should be reduced to control the preparation cost on the field scale. In this paper, we present findings from different modeling/experimental studies to improve the performance of smart water flooding in carbonate formations by the idea of shock/soaking.\u0000 Different researches showed that the presence of active ions such as Mg2+ and SO42- in the injection water alters the wettability of carbonates to more water-wet state and also reduces the IFT between the oil and the injected brine. Hence, spiking active ions concentration in the low salinity water improves oil recovery from carbonate formation. In this work, the optimized smart brine was used for injection with novel injection scheme. The optimized brine was set to be injected as the shock slug between two slugs of high salinity water. This smart water shock flooding was designed to reduce the pore volume of low salinity water flooding. The effect of the slug on relative permeability curves was modeled and analyzed in the core and sector scales. Also we experimentally studied the effect of soaking time after the shock on wettability alteration and improvement in recovery by re-injection of high salinity normal brine.\u0000 Characterization tests such as contact angle measurement confirmed the effect of shock/soaking on alteration of governing mechanisms such as multi-ion exchange which leads to wettability alteration in the process. Our core flooding experiments showed that the shock injection at the best design can improve the tertiary recovery up to 7.8%. Also, modeling at the reservoir sector shows noticeable incremental oil recovery during the shock injection and high salinity water injection after it.\u0000 Our modeling/experimental studies clearly illuminated a new approach to improve the performance of low salinity water flooding in an efficient and cheaper way. By this approach, higher oil recovery can be achieved by the application of less amount of diluted water which is beneficial for the oil industry.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78229078","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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