I. Altaf, B. Towler, J. Underschultz, S. Hurter, Raymond L. Johnson
A fault stability study constitutes a fundamental element of any subsurface injection project that involves faults within a storage complex, yet the transient geomechanical effects introduced due to CO2-rock chemical interactions are rarely considered. This paper presents a review of the published work investigating the potential alteration of rock properties due to short to long term CO2-host rock chemical interactions during commercial scale carbon capture and storage (CCS) operations. Furthermore, the authors of this paper are attempting to highlight the potential significance of these mechanical-chemical effect on the fault reactivation potential for a commercial scale carbon capture and storage (CCS) operation. The reactive nature between CO2 dissolved in formation water and the storage reservoir can significantly alter the hydraulic and mechanical properties of the host rock, which could in turn affect the storage potential of the target reservoir. Alteration of the host rock mineralogy due to chemical interactions with CO2 have been well studied (Farquhar et al. 2015), but little is available in the published literature on the resulting changes in rock elastic properties (i.e. Young's modulus and Poisson's ratio) due to these reactions. Some recent experimental studies have suggested significant changes in rock properties occur. When we incorporated the geomechanical effects, induced by the rock elastic property changes documented in these published cases, into both 1D analytical and 3D numerical models based fault stability analyses for a Surat Basin reservoir, we observed significant modification of the reservoir storage capacity prior to reaching fault reactivation criteria. Based on our review of the published literature and our fault stability analyses, we conclude that the chemical effects of CO2 interaction with host rock needs to be experimentally tested to confirm if these effects are significant. If yes, then these effects should constitute an integral part of the geomechanical study for any large scale CO2 injection exercise if there is a critically stressed fault as part of the storage complex.
断层稳定性研究是任何涉及储层断层的地下注入项目的基本要素，但由于二氧化碳-岩石化学相互作用而引入的瞬态地质力学效应很少被考虑。本文综述了在商业规模的碳捕集与封存(CCS)过程中，由于短期到长期的二氧化碳宿主岩石化学相互作用，岩石性质可能发生变化的研究成果。此外，本文的作者试图强调这些机械-化学效应对商业规模碳捕集与封存(CCS)操作的断层再激活潜力的潜在意义。溶解在地层水中的CO2与储层之间的反应性质会显著改变储层岩石的水力和力学性质，进而影响目标储层的储集潜力。由于与二氧化碳的化学相互作用，宿主岩石矿物学的变化已经得到了很好的研究(Farquhar et al. 2015)，但在已发表的文献中，由于这些反应导致的岩石弹性特性(即杨氏模量和泊松比)的变化很少。最近的一些实验研究表明，岩石性质发生了重大变化。当我们将这些已发表案例中记录的岩石弹性特性变化所引起的地质力学效应纳入基于苏拉特盆地油藏断层稳定性分析的一维解析和三维数值模型时，我们观察到在达到断层再激活标准之前，油藏存储能力发生了显著变化。根据我们对已发表文献的回顾和断层稳定性分析，我们得出结论，二氧化碳与宿主岩石相互作用的化学效应需要进行实验测试，以确认这些效应是否显著。如果是，那么这些影响应该构成地质力学研究的一个组成部分，用于任何大规模的二氧化碳注入作业，如果有一个临界应力断层作为储层的一部分。
{"title":"A Review of Current Knowledge with Geomechanical Fault Reactivation Modelling: The Importance of CO2 Mechano-Chemical Effects for CO2 Sequestration","authors":"I. Altaf, B. Towler, J. Underschultz, S. Hurter, Raymond L. Johnson","doi":"10.2118/192024-MS","DOIUrl":"https://doi.org/10.2118/192024-MS","url":null,"abstract":"\u0000 A fault stability study constitutes a fundamental element of any subsurface injection project that involves faults within a storage complex, yet the transient geomechanical effects introduced due to CO2-rock chemical interactions are rarely considered. This paper presents a review of the published work investigating the potential alteration of rock properties due to short to long term CO2-host rock chemical interactions during commercial scale carbon capture and storage (CCS) operations. Furthermore, the authors of this paper are attempting to highlight the potential significance of these mechanical-chemical effect on the fault reactivation potential for a commercial scale carbon capture and storage (CCS) operation.\u0000 The reactive nature between CO2 dissolved in formation water and the storage reservoir can significantly alter the hydraulic and mechanical properties of the host rock, which could in turn affect the storage potential of the target reservoir. Alteration of the host rock mineralogy due to chemical interactions with CO2 have been well studied (Farquhar et al. 2015), but little is available in the published literature on the resulting changes in rock elastic properties (i.e. Young's modulus and Poisson's ratio) due to these reactions. Some recent experimental studies have suggested significant changes in rock properties occur. When we incorporated the geomechanical effects, induced by the rock elastic property changes documented in these published cases, into both 1D analytical and 3D numerical models based fault stability analyses for a Surat Basin reservoir, we observed significant modification of the reservoir storage capacity prior to reaching fault reactivation criteria.\u0000 Based on our review of the published literature and our fault stability analyses, we conclude that the chemical effects of CO2 interaction with host rock needs to be experimentally tested to confirm if these effects are significant. If yes, then these effects should constitute an integral part of the geomechanical study for any large scale CO2 injection exercise if there is a critically stressed fault as part of the storage complex.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"120 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79140653","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}
H. Shuber, Ahmad Al-Awadi, D. Belal, Saif Al-Hashmi, Vinayak Verma, Tareq AI-Sarraf, A. Najaf, Bader Al-Telaihi, Abdulla Al-Sumaiti
With the Oil business expanding day by day and with the demand for oil increasing many challenges were introduced, Kuwait Oil Company's South-East Asset (SEK) played a major role in tackling those challenges to meet Kuwait Petroleum Company production targets. In order to ensure operational excellence strategy is implemented, multidisciplinary teams founded (Well Delivery Task Force Team) to ensure the optimization of production and the full utilization of resources available in order to heed for the KPC requirements. Today Well Delivery TFT has grown to become a symbol of defining success criteria, which goes beyond technology implementation and setting the right framework for efficiency, coordination & commitment by ensuring an effective synergy between different teams of SEK directorate. Before the Task Force was formed the teams encountered several barriers to centralization plans. Challenges like inter-dependencies, miscommunications, understanding size, time and type of operation workflows, materials availability created strong barriers to an effective plan implementation. This lead to substandard work outcome due to conveying message between one parts of the team to multiple teams located in different locations resulting in time and effort waste and eventually deviate from the desired application. As SEK core business is to meet expected oil targets, it is critical to ensure that the company standards or work practices are preserved and applied irrespective of the challenges.
{"title":"Well Delivery Task Force Team Approach to Increase Operation Efficiency","authors":"H. Shuber, Ahmad Al-Awadi, D. Belal, Saif Al-Hashmi, Vinayak Verma, Tareq AI-Sarraf, A. Najaf, Bader Al-Telaihi, Abdulla Al-Sumaiti","doi":"10.2118/192138-MS","DOIUrl":"https://doi.org/10.2118/192138-MS","url":null,"abstract":"\u0000 With the Oil business expanding day by day and with the demand for oil increasing many challenges were introduced, Kuwait Oil Company's South-East Asset (SEK) played a major role in tackling those challenges to meet Kuwait Petroleum Company production targets. In order to ensure operational excellence strategy is implemented, multidisciplinary teams founded (Well Delivery Task Force Team) to ensure the optimization of production and the full utilization of resources available in order to heed for the KPC requirements.\u0000 Today Well Delivery TFT has grown to become a symbol of defining success criteria, which goes beyond technology implementation and setting the right framework for efficiency, coordination & commitment by ensuring an effective synergy between different teams of SEK directorate.\u0000 Before the Task Force was formed the teams encountered several barriers to centralization plans. Challenges like inter-dependencies, miscommunications, understanding size, time and type of operation workflows, materials availability created strong barriers to an effective plan implementation. This lead to substandard work outcome due to conveying message between one parts of the team to multiple teams located in different locations resulting in time and effort waste and eventually deviate from the desired application. As SEK core business is to meet expected oil targets, it is critical to ensure that the company standards or work practices are preserved and applied irrespective of the challenges.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89783939","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}
Value Creation can be achieved through FDP optimisation initiative for offshore fields that have been impacted by recent slump in activities and investments in the Oil and Gas industry. Each stage of the FDP process can be reviewed and respective value and cost target be revised. It is to ensure that process for the opportunity still carry business value, and aligned with business objectives at current industry outlook. Alongside the opportunity maturation process, there should also be emphasis on value assurance to maximise value and chance of success. Offshore development of a green field gas development in Peninsular Malaysia was a successful story of Integration and engagement of various functions and disciplines throughout the FDP optimisation efforts, by keeping the FDP stages as "live" cycles. It let the optimisation process to encompass all activity spectrum from subsurface to surface, and warranted the project to be fully assessed from uncertainties and risk management to optimising the value of the project. Early determination and understanding of the objectives and area of focus for maximum impact on value creation initiatives were chosen to be the road map. Moreover, collaboration between the teams to revise drilling, completion and the depletion strategies with capital cost phasing were identified to be key areas for a successful development and cost optimisation of the project. Drilling and completion strategies for the wells selected in a manner that they focused on most productive zones at the beginning, with development of the shallower reservoirs by workover and intervention activities upon depletion and pressure equalisation with the lower zones. The strategy also led the capital cost to be classified as operational as future expense without compromising the reserve to be developed. The result of the work led to a significant cost saving which in turn allowed execution of the project from preservation to drilling stage in almost 6 months. This paper will highlight the initiatives and activities that made the project to be successfully move from preservation to execution mode.
{"title":"From Preservation to Execution: Value Creation through Successful FDP Optimisation for an Offshore Green Field Gas in Peninsular Malaysia","authors":"Ali Sabzabadi, Aida Binti Daeng, N. Hamza","doi":"10.2118/191930-MS","DOIUrl":"https://doi.org/10.2118/191930-MS","url":null,"abstract":"\u0000 Value Creation can be achieved through FDP optimisation initiative for offshore fields that have been impacted by recent slump in activities and investments in the Oil and Gas industry. Each stage of the FDP process can be reviewed and respective value and cost target be revised. It is to ensure that process for the opportunity still carry business value, and aligned with business objectives at current industry outlook. Alongside the opportunity maturation process, there should also be emphasis on value assurance to maximise value and chance of success.\u0000 Offshore development of a green field gas development in Peninsular Malaysia was a successful story of Integration and engagement of various functions and disciplines throughout the FDP optimisation efforts, by keeping the FDP stages as \"live\" cycles. It let the optimisation process to encompass all activity spectrum from subsurface to surface, and warranted the project to be fully assessed from uncertainties and risk management to optimising the value of the project.\u0000 Early determination and understanding of the objectives and area of focus for maximum impact on value creation initiatives were chosen to be the road map. Moreover, collaboration between the teams to revise drilling, completion and the depletion strategies with capital cost phasing were identified to be key areas for a successful development and cost optimisation of the project. Drilling and completion strategies for the wells selected in a manner that they focused on most productive zones at the beginning, with development of the shallower reservoirs by workover and intervention activities upon depletion and pressure equalisation with the lower zones. The strategy also led the capital cost to be classified as operational as future expense without compromising the reserve to be developed.\u0000 The result of the work led to a significant cost saving which in turn allowed execution of the project from preservation to drilling stage in almost 6 months.\u0000 This paper will highlight the initiatives and activities that made the project to be successfully move from preservation to execution mode.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"99 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80564891","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
As oil fields mature, the produced water content of the production stream will often increase over time, and produced water management will eventually become a bottleneck in production. Subsea separation of produced water enables prolonged lifetime of brown field installations, increased recovery rates and more energy efficient production. In addition, implementation of subsea water separation will also enable future tie-ins to existing facilities, and reduce the need for new and expensive transport lines. Existing installed subsea produced water bulk separator technologies are limited to gravity and compact gravity vessels, such as Troll and Tordis, and the Marlim pipe separator. These are large installations, which are costly to manufacture, transport and install. In addition, the gravity and compact gravity vessels are not suited for deep-water installations, and there is a need for novel solutions to both reduce the weight and size of bulk water separators, making the technology more attractive for new business cases. In order to investigate improved subsea bulk water separation technologies, a multiphase oil-water test loop has been developed at the Norwegian University of Science and Technology (NTNU). Facility test fluids are ExxsolD60 and distilled water with wt%3.4 NaCl. In this paper, a new separator design, utilizing multiple parallel pipes will be presented. The design allows reduction of required wall thickness at large water depths, shorter residence times and hence a shorter separator length compared to traditional gravity based technologies. Initial performance data of a constructed medium scale prototype will be reported, including separation efficiency estimations over a range of flow rates, water cuts (WC) and water extraction rates (ER). Tested flow rates vary from 250L/min to 750L/min at 30%, 50% and 70% WC. Water extraction rates are varied from 50% to 100% of the inlet water rate. Based on this initial test campaign, the concept proves promising, displaying good separation efficiencies (>98%) for both water continuous and oil continuous inlet flows at moderate flow velocities. At higher flow rates, performance decreases, and water extraction rates must be limited in order to maintain high efficiencies. Photos of flow conditions at the water outlet are included, providing a visualization of the occurring two-phase flow phenomena inside the separator. The presented concept adds to an expanding portfolio of proposed subsea separation solutions, and displays a new way of utilizing parallel pipes to achieve oil-water bulk separation.
{"title":"An Experimental Study of a Novel Parallel Pipe Separator Design for Subsea Oil-Water Bulk Separation","authors":"H. S. Skjefstad, M. Stanko","doi":"10.2118/191898-MS","DOIUrl":"https://doi.org/10.2118/191898-MS","url":null,"abstract":"\u0000 As oil fields mature, the produced water content of the production stream will often increase over time, and produced water management will eventually become a bottleneck in production. Subsea separation of produced water enables prolonged lifetime of brown field installations, increased recovery rates and more energy efficient production. In addition, implementation of subsea water separation will also enable future tie-ins to existing facilities, and reduce the need for new and expensive transport lines. Existing installed subsea produced water bulk separator technologies are limited to gravity and compact gravity vessels, such as Troll and Tordis, and the Marlim pipe separator. These are large installations, which are costly to manufacture, transport and install. In addition, the gravity and compact gravity vessels are not suited for deep-water installations, and there is a need for novel solutions to both reduce the weight and size of bulk water separators, making the technology more attractive for new business cases.\u0000 In order to investigate improved subsea bulk water separation technologies, a multiphase oil-water test loop has been developed at the Norwegian University of Science and Technology (NTNU). Facility test fluids are ExxsolD60 and distilled water with wt%3.4 NaCl. In this paper, a new separator design, utilizing multiple parallel pipes will be presented. The design allows reduction of required wall thickness at large water depths, shorter residence times and hence a shorter separator length compared to traditional gravity based technologies. Initial performance data of a constructed medium scale prototype will be reported, including separation efficiency estimations over a range of flow rates, water cuts (WC) and water extraction rates (ER). Tested flow rates vary from 250L/min to 750L/min at 30%, 50% and 70% WC. Water extraction rates are varied from 50% to 100% of the inlet water rate.\u0000 Based on this initial test campaign, the concept proves promising, displaying good separation efficiencies (>98%) for both water continuous and oil continuous inlet flows at moderate flow velocities. At higher flow rates, performance decreases, and water extraction rates must be limited in order to maintain high efficiencies. Photos of flow conditions at the water outlet are included, providing a visualization of the occurring two-phase flow phenomena inside the separator.\u0000 The presented concept adds to an expanding portfolio of proposed subsea separation solutions, and displays a new way of utilizing parallel pipes to achieve oil-water bulk separation.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90998616","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. Renteria, A. Maleki, I. Frigaard, B. Lund, A. Taghipour, J. D. Ytrehus
Anywhere between 0%-80% of cemented wells have integrity failures, suggesting both geological and operational factors. One way geology affects cementing is via irregular wellbores, e.g. washouts. Here we study the effects of washouts on mud removal in strongly inclined wellbores, experimentally and via 2-D computational simulations, with aim of identifying key control parameters. Experiments were performed with 2 fluids with properties representative of drilling mud and cement (or spacer), displaced at constant flow rate through a 10 m long annular flow loop. A downstream "washout" section of the annulus had an enlarged outer diameter. Twenty-four conductivity probes tracked the arrival times of the displacing fluid by measuring the conductivity of fluids as they pass. The experimental matrix includes 8 experiments with 2 eccentricities (standoff = 1, 0.58), 4 angles of inclination and slightly variable rheology. The simulation study covered wider ranges of variables. The results of simulations and experiments agree qualitatively on the main effects, as shown in [7]. Here we extend the study using the 2D simulation to study the effects of washout length and diameter, for both concentric and eccentric wells, all oriented horizontally. The simulations provide detailed information on the evolution of the fluid-fluid interfaces as they pass through the washout, as well as information on the velocity fields and stresses. In any near-horizontal section there is a delicate balance of buoyancy and eccentricity influences, in both regular and irregular geometries. Under some circumstances an irregular section seems to have a positive stabilizing effect on the interface. However, this positive message is balanced practically by uncertainty of washout size and in-situ mud properties and the positive effects are not universal. We find that increasing the washout diameter always appears to decrease the displacemnt efficiency, for both concentric and eccentric annuli. Increasing the washout length is less clear in its effects. In all cases, the main risk from residual drilling mud in isolated washouts is that it can contaminate the cement slurry as it passes.
{"title":"Displacement Efficiency for Primary Cementing of Washout Sections in Highly Deviated Wells","authors":"A. Renteria, A. Maleki, I. Frigaard, B. Lund, A. Taghipour, J. D. Ytrehus","doi":"10.2118/191989-MS","DOIUrl":"https://doi.org/10.2118/191989-MS","url":null,"abstract":"\u0000 Anywhere between 0%-80% of cemented wells have integrity failures, suggesting both geological and operational factors. One way geology affects cementing is via irregular wellbores, e.g. washouts. Here we study the effects of washouts on mud removal in strongly inclined wellbores, experimentally and via 2-D computational simulations, with aim of identifying key control parameters.\u0000 Experiments were performed with 2 fluids with properties representative of drilling mud and cement (or spacer), displaced at constant flow rate through a 10 m long annular flow loop. A downstream \"washout\" section of the annulus had an enlarged outer diameter. Twenty-four conductivity probes tracked the arrival times of the displacing fluid by measuring the conductivity of fluids as they pass. The experimental matrix includes 8 experiments with 2 eccentricities (standoff = 1, 0.58), 4 angles of inclination and slightly variable rheology. The simulation study covered wider ranges of variables. The results of simulations and experiments agree qualitatively on the main effects, as shown in [7].\u0000 Here we extend the study using the 2D simulation to study the effects of washout length and diameter, for both concentric and eccentric wells, all oriented horizontally. The simulations provide detailed information on the evolution of the fluid-fluid interfaces as they pass through the washout, as well as information on the velocity fields and stresses. In any near-horizontal section there is a delicate balance of buoyancy and eccentricity influences, in both regular and irregular geometries. Under some circumstances an irregular section seems to have a positive stabilizing effect on the interface. However, this positive message is balanced practically by uncertainty of washout size and in-situ mud properties and the positive effects are not universal. We find that increasing the washout diameter always appears to decrease the displacemnt efficiency, for both concentric and eccentric annuli. Increasing the washout length is less clear in its effects. In all cases, the main risk from residual drilling mud in isolated washouts is that it can contaminate the cement slurry as it passes.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87476338","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}
Shashank Pathak, R. Tibbles, A. Bohra, S. Tiwari, Preeti Godiyal, Aniket Deo
Frac Hit is an inter-well communication event where an offset well is affected by the pumping of a hydraulic fracturing treatment in a new well. Close well spacing, increased fracture density (number of fracs per well), and larger fracture treatments increase the chance of a Frac Hit. This paper demonstrates how a Geographic Information System (GIS) was used in the Barmer Hill oil reservoir to quantify the risks of a Frac Hit on a well by well basis. The Aishwarya Barmer Hill (ABH) field (<1 mD/cp) overlies the prolific Aishwarya Fatehgarh (AF) field (>3 Darcy's). The AF field was developed first with 71 wells. All of these wells for AF reservoir penetrated through shallower ABH reservoir at an average spacing of ∼100 m. The ABH field development plan calls for 1000 m long horizontal laterals with a ∼180 m distance between the wells to efficiently drain the entire ABH structure. The hydraulic fractures planned in ABH wells had an average fracture half-length of ∼100 m with 10 stages per well. With the spacing equal to the fracture half length, the likelihood of a Frac Hit between ABH horizontal wells was high. The presence of the nearby AF wells only added to the risk. GIS enabled software was used to evaluate the risk magnitude and the observations were used to prepare a mitigation plan. All the well trajectories for both reservoirs were mapped inside the 3D reservoir structure. As a first case, a potential strike zone (PSZ) with a radius equal to the frac half-length was generated around the planned ABH wells. Wells were considered at risk if a PSZ intersected another well or another PSZ. Then all of the planned hydraulic fractures were mapped in 3 dimensions using the known fracture propagation azimuth (from appraisal well micro-seismic data) and the simulated fracture dimensions (Half-lengths & heights) using fully 3D frac modeling software. The procedure clearly identified the cases (well/stage) which had a high potential for a Frac Hit. After identifying the high-risk cases, appropriate steps were taken to minimize the risk. The available options were to change the well trajectory, modify the fracture location (shift or remove stages), or propose additional surveillance. The Frac Hit phenomena is a sub-surface integrity related concern which has been reported on in many technical papers. This work proposes a method for quantifying and minimizing the risks using a GIS platform. A method for categorizing the various risk cases based on well spacing, perforation and fracture initiation points is proposed. This method was studied for the ABH wells during the well planning phase and shall be applied in order to minimize Frac Hit risks. The information provided could also be directly utilized for in-fill development project for tight fields.
压裂冲击是井间通信事件，当邻井受到新井水力压裂处理泵送的影响时。缩小井距、增加裂缝密度(每口井的裂缝数量)以及加大压裂处理力度，都增加了压裂命中的几率。本文演示了如何在Barmer Hill油藏中使用地理信息系统(GIS)，以每口井为基础量化压裂冲击风险。Aishwarya Barmer Hill (ABH)油田(3 Darcy’s)。AF油田首先开发，共71口井。所有AF油藏的井均以平均100 m的井距穿透较浅的ABH油藏。ABH油田开发计划要求1000米长的水平分支井，井间距离为180米，以有效地排出整个ABH结构。在ABH井中计划的水力裂缝平均半长为~ 100 m，每口井有10级压裂。当间距等于裂缝的一半长度时，ABH水平井之间发生压裂冲击的可能性很高。附近AF井的存在只会增加风险。利用支持地理信息系统的软件评估风险程度，并利用观测结果编制减灾计划。这两个油藏的所有井眼轨迹都被绘制在三维油藏结构内部。作为第一个案例，在计划的ABH井周围产生了一个半径等于压裂半长的潜在走向带(PSZ)。如果一个射孔区与另一口井或另一口射孔区相交，则认为该井存在风险。然后，利用已知的裂缝扩展方位角(来自评价井微地震数据)和模拟裂缝尺寸(半长和高度)，利用全三维裂缝建模软件，将所有计划的水力裂缝绘制成三维图。该程序可以清楚地识别出可能发生压裂冲击的情况(井/段)。在确定高危病例后，采取适当措施将风险降至最低。可用的选择包括改变井眼轨迹、修改裂缝位置(移位或移除分段)，或者提出额外的监控措施。压裂冲击现象是一个与地下完整性相关的问题，在许多技术论文中都有报道。这项工作提出了一种使用GIS平台量化和最小化风险的方法。提出了一种基于井距、射孔和裂缝起裂点对各种风险情况进行分类的方法。该方法是在井规划阶段针对ABH井进行的研究，旨在将压裂冲击风险降至最低。所提供的信息也可直接用于致密油田的充填开发项目。
{"title":"Evaluation of Frac Hit Risks in Aishwarya Barmer-Hill Field Development Utilising GIS Platform","authors":"Shashank Pathak, R. Tibbles, A. Bohra, S. Tiwari, Preeti Godiyal, Aniket Deo","doi":"10.2118/192117-MS","DOIUrl":"https://doi.org/10.2118/192117-MS","url":null,"abstract":"\u0000 Frac Hit is an inter-well communication event where an offset well is affected by the pumping of a hydraulic fracturing treatment in a new well. Close well spacing, increased fracture density (number of fracs per well), and larger fracture treatments increase the chance of a Frac Hit. This paper demonstrates how a Geographic Information System (GIS) was used in the Barmer Hill oil reservoir to quantify the risks of a Frac Hit on a well by well basis.\u0000 The Aishwarya Barmer Hill (ABH) field (<1 mD/cp) overlies the prolific Aishwarya Fatehgarh (AF) field (>3 Darcy's). The AF field was developed first with 71 wells. All of these wells for AF reservoir penetrated through shallower ABH reservoir at an average spacing of ∼100 m. The ABH field development plan calls for 1000 m long horizontal laterals with a ∼180 m distance between the wells to efficiently drain the entire ABH structure. The hydraulic fractures planned in ABH wells had an average fracture half-length of ∼100 m with 10 stages per well. With the spacing equal to the fracture half length, the likelihood of a Frac Hit between ABH horizontal wells was high. The presence of the nearby AF wells only added to the risk.\u0000 GIS enabled software was used to evaluate the risk magnitude and the observations were used to prepare a mitigation plan. All the well trajectories for both reservoirs were mapped inside the 3D reservoir structure. As a first case, a potential strike zone (PSZ) with a radius equal to the frac half-length was generated around the planned ABH wells. Wells were considered at risk if a PSZ intersected another well or another PSZ. Then all of the planned hydraulic fractures were mapped in 3 dimensions using the known fracture propagation azimuth (from appraisal well micro-seismic data) and the simulated fracture dimensions (Half-lengths & heights) using fully 3D frac modeling software.\u0000 The procedure clearly identified the cases (well/stage) which had a high potential for a Frac Hit. After identifying the high-risk cases, appropriate steps were taken to minimize the risk. The available options were to change the well trajectory, modify the fracture location (shift or remove stages), or propose additional surveillance.\u0000 The Frac Hit phenomena is a sub-surface integrity related concern which has been reported on in many technical papers. This work proposes a method for quantifying and minimizing the risks using a GIS platform. A method for categorizing the various risk cases based on well spacing, perforation and fracture initiation points is proposed. This method was studied for the ABH wells during the well planning phase and shall be applied in order to minimize Frac Hit risks. The information provided could also be directly utilized for in-fill development project for tight fields.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"71 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86406729","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}
Multiphase metering has enabled addressing a number of flow assurance challenges, including the detection of scale formation. This capability is especially appreciated in subsea fields, where the physical access is restricted and flow assurance challenges can be detrimental to maintaining production with a reasonable cost. The scale detection capability of the multiphase flowmeters using live multiphase flow data facilitates a proactive approach by the operators to detect and remediate productivity and flow assurance issues arising out of scale deposition. A successful early-stage detection of scales in an oil well in deepwater field offshore Ghana via remote monitoring of multiphase metering data is reported. The displacement of the operating point of the multiphase meter and the swift developments in a matter of days provided the necessary live data for the hypothesis of the scale formation in the meter's venturi. Necessary mitigation action was taken and increases in production due to removal of scale demonstrated presence of scale. An in-house-developed remote surveillance and diagnostic system carried out this detection. The results of this project demonstrate the practical capability of remote monitoring of multiphase metering data for flow assurance purposes.
{"title":"Early-Stage Detection of Scales in a Deepwater Field Offshore Ghana via Remote Monitoring of Multiphase Meter","authors":"M. Darab, R. Nygaard, A. Singh","doi":"10.2118/191960-MS","DOIUrl":"https://doi.org/10.2118/191960-MS","url":null,"abstract":"\u0000 Multiphase metering has enabled addressing a number of flow assurance challenges, including the detection of scale formation. This capability is especially appreciated in subsea fields, where the physical access is restricted and flow assurance challenges can be detrimental to maintaining production with a reasonable cost. The scale detection capability of the multiphase flowmeters using live multiphase flow data facilitates a proactive approach by the operators to detect and remediate productivity and flow assurance issues arising out of scale deposition.\u0000 A successful early-stage detection of scales in an oil well in deepwater field offshore Ghana via remote monitoring of multiphase metering data is reported. The displacement of the operating point of the multiphase meter and the swift developments in a matter of days provided the necessary live data for the hypothesis of the scale formation in the meter's venturi. Necessary mitigation action was taken and increases in production due to removal of scale demonstrated presence of scale. An in-house-developed remote surveillance and diagnostic system carried out this detection. The results of this project demonstrate the practical capability of remote monitoring of multiphase metering data for flow assurance purposes.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"33 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89496635","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}
R. Masoudi, Muhammad Afiq Abd. Wahab, E. Motaei, A. Ataei
Among the key uncertainties and risks as part of development of a high CO2 offshore gas carbonate field; production well deliverability, produced CO2 management, and cap rock integrity have been identified as potential techno-commercial showstoppers that need further appraisal and studies. CO2 storage and sequestration in the aquifer of the same field was identified as the most feasible and economic option for the Produced CO2 management and hence the injectivity within the targeted intervals and aquifer become part of the appraisal and study scope. An extensive over 200 m coring program covering various intervals including overburden, caprock, carbonate hydrocarbon intervals and aquifer has been designed as part of data acquisition and surveillance plan. The main plan scope were designed as:To establish reservoir properties & characterizationTo measure formation pressure and acquire fluid sampleTo establish reservoir injectivity and productivity at the prospective intervalsTo acquire data for flow assurance analysis, facilities design and well material selection studies for development planning. The test and analysis has been successfully conducted covering the intended scope of the plan. Based on the Well test and PTA, the reservoir permeability is calculated and is more or less aligned with the core permeability with the total high skin which the majority comes from geometrical/limited-entry skin. The productivity index is calculated to be 21 STB/day/psi. There is difficulty to analyze the Injectivity test due to non-isothermal effects during injection and fall-off test where the fluid property of both injected water and reservoir water is a function of temperature and time. An approximate method is applied using the average temperature during the fall-off to simplify the case by considering a constant fluid property. Injectivity Index is estimated from rate and pressure data to be around 26 STB/day/psi. However, it declined by time to reach a value close to 13 STB/day/psi. In the second test, Based on pressure transient analysis the homogeneous, vertical well with limited entry, and infinite boundary model with underneath aquifer was accepted as representative for S2 reservoir. To capture the non-Darcy effect, the rate dependent skin model is selected. Non-Darcy coefficient is extracted from well model for IRP in well model (1.0073E-4 (Mscf/day)-1. Generally, the well test and injectivity and productivity analysis objectives are achieved as the fluid type is also confirmed. The paper will detail out the actual test results, methodology and evaluation approaches in this surveillance plan.
{"title":"Injectivity and Well Deliverability Test and Analysis in an Offshore Complex High CO2 Gas Carbonate Asset","authors":"R. Masoudi, Muhammad Afiq Abd. Wahab, E. Motaei, A. Ataei","doi":"10.2118/191961-MS","DOIUrl":"https://doi.org/10.2118/191961-MS","url":null,"abstract":"\u0000 Among the key uncertainties and risks as part of development of a high CO2 offshore gas carbonate field; production well deliverability, produced CO2 management, and cap rock integrity have been identified as potential techno-commercial showstoppers that need further appraisal and studies. CO2 storage and sequestration in the aquifer of the same field was identified as the most feasible and economic option for the Produced CO2 management and hence the injectivity within the targeted intervals and aquifer become part of the appraisal and study scope.\u0000 An extensive over 200 m coring program covering various intervals including overburden, caprock, carbonate hydrocarbon intervals and aquifer has been designed as part of data acquisition and surveillance plan. The main plan scope were designed as:To establish reservoir properties & characterizationTo measure formation pressure and acquire fluid sampleTo establish reservoir injectivity and productivity at the prospective intervalsTo acquire data for flow assurance analysis, facilities design and well material selection studies for development planning.\u0000 The test and analysis has been successfully conducted covering the intended scope of the plan. Based on the Well test and PTA, the reservoir permeability is calculated and is more or less aligned with the core permeability with the total high skin which the majority comes from geometrical/limited-entry skin. The productivity index is calculated to be 21 STB/day/psi. There is difficulty to analyze the Injectivity test due to non-isothermal effects during injection and fall-off test where the fluid property of both injected water and reservoir water is a function of temperature and time. An approximate method is applied using the average temperature during the fall-off to simplify the case by considering a constant fluid property. Injectivity Index is estimated from rate and pressure data to be around 26 STB/day/psi. However, it declined by time to reach a value close to 13 STB/day/psi. In the second test, Based on pressure transient analysis the homogeneous, vertical well with limited entry, and infinite boundary model with underneath aquifer was accepted as representative for S2 reservoir. To capture the non-Darcy effect, the rate dependent skin model is selected. Non-Darcy coefficient is extracted from well model for IRP in well model (1.0073E-4 (Mscf/day)-1.\u0000 Generally, the well test and injectivity and productivity analysis objectives are achieved as the fluid type is also confirmed. The paper will detail out the actual test results, methodology and evaluation approaches in this surveillance plan.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"15 6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78337253","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}
Turaj Nuralishahi, Maryam Vahmani, Erni Dharma Putra, Moh Hsiao Wun, K. Thakur, Phyoe Wai Aung, Chris Coman, S. Delfani, Kyle Wimbridge, N. Rodriguez, Johny Samaan
In 2017, APLNG drilled the first horizontal wells within the Surat Basin targeting the Walloon coal seam gas (CSG) measures. This reservoir is quite shallow with the potential for relatively low pressures. To address this uncertainty, a study was performed to identify an optimum operational strategy to maximise the cumulative gas production of a well over the first five years of production. This was achieved by using a Latin Hypercube sampler and a Genetic Algorithm optimiser to identify optimum reservoir simulation scenarios. The optimized simulation scenarios were then modelled within a multiphase transient simulation model, to better understand the flow regime behaviour within the wellbore. This predicted the flowing potential of the well whilst modelling flow assurance risks such as wellbore slugging. The result was an innovative workflow that identified optimum operational strategies whilst accounting for the uncertainties in reservoir pressure and the fluid hydraulics in the wellbore. After completing the reservoir optimisation studies, the optimised cumulative gas production showed increases between 3% – 6% compared to the base case. Other improvements included; higher peak gas production, higher peak water production resulting in earlier desorption of gas, shorter time to initial gas, and shorter time to peak gas. After running the optimised reservoir simulation cases through the transient models, it was found that the days to peak gas was reduced by 80-90%, whilst the slugging periods were reduced by 90-100%. The models were also used to quantify the impacts of changing operational/design parameters such as horizontal well length, casing sizes, pump speeds, and choke settings. APLNG used these results to design their well start-up and ramp-up strategies, and successfully kick off their horizontal wells. The results of this innovative workflow for reservoir and wellbore modelling in a CSG field highlights the new insights that can be gained by combining traditional reservoir simulation with mathematical optimization and transient well flow modelling. These workflows enhance our understanding of how to improve efficiencies and maximise production volumes within CSG fields.
{"title":"Optimising Horizontal Coal Seam Gas Wells by Combining Reservoir Simulation and Transient Well Modelling","authors":"Turaj Nuralishahi, Maryam Vahmani, Erni Dharma Putra, Moh Hsiao Wun, K. Thakur, Phyoe Wai Aung, Chris Coman, S. Delfani, Kyle Wimbridge, N. Rodriguez, Johny Samaan","doi":"10.2118/192010-MS","DOIUrl":"https://doi.org/10.2118/192010-MS","url":null,"abstract":"\u0000 In 2017, APLNG drilled the first horizontal wells within the Surat Basin targeting the Walloon coal seam gas (CSG) measures. This reservoir is quite shallow with the potential for relatively low pressures. To address this uncertainty, a study was performed to identify an optimum operational strategy to maximise the cumulative gas production of a well over the first five years of production.\u0000 This was achieved by using a Latin Hypercube sampler and a Genetic Algorithm optimiser to identify optimum reservoir simulation scenarios. The optimized simulation scenarios were then modelled within a multiphase transient simulation model, to better understand the flow regime behaviour within the wellbore. This predicted the flowing potential of the well whilst modelling flow assurance risks such as wellbore slugging. The result was an innovative workflow that identified optimum operational strategies whilst accounting for the uncertainties in reservoir pressure and the fluid hydraulics in the wellbore.\u0000 After completing the reservoir optimisation studies, the optimised cumulative gas production showed increases between 3% – 6% compared to the base case. Other improvements included; higher peak gas production, higher peak water production resulting in earlier desorption of gas, shorter time to initial gas, and shorter time to peak gas. After running the optimised reservoir simulation cases through the transient models, it was found that the days to peak gas was reduced by 80-90%, whilst the slugging periods were reduced by 90-100%. The models were also used to quantify the impacts of changing operational/design parameters such as horizontal well length, casing sizes, pump speeds, and choke settings. APLNG used these results to design their well start-up and ramp-up strategies, and successfully kick off their horizontal wells.\u0000 The results of this innovative workflow for reservoir and wellbore modelling in a CSG field highlights the new insights that can be gained by combining traditional reservoir simulation with mathematical optimization and transient well flow modelling. These workflows enhance our understanding of how to improve efficiencies and maximise production volumes within CSG fields.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"380 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76443549","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}
This paper presents a case study reviewing the systematic optimization of fluid transport, consumption and waste in large hydraulic fracturing development campaigns. With a focus on reducing consumption, re-thinking transport, and creating value from waste fluid through recycling and reuse, the methodology applied has resulted in very real gains in economic, environmental, social and safety outcomes. The objective of this case study is to provide practical information and guidance for planning, execution and ongoing optimization to not only reduce the footprint of hydraulic fracturing activities but also reduce cost. By applying the methodology within this paper, the following was achieved over a 90 well development program: Fluid transport via trucking to wellsite virtually eliminated through use of the water production gathering network;Total fluid requirements reduced by 50%;Chemical costs reduced by 35%;Fluid disposal volume via trucking reduced by 95%; andFluid waste disposal costs reduced by 90%. While the case study presented is based on a coal bed methane (CBM) development where between 3,000 to 6,000 barrels of clean fluid was required per well, some or all of the methodologies may be applied to shale and conventional markets. With trends in stimulation volumes within the United States shale plays increasing more than threefold in recent years to upwards of 160,000 barrels per well (Dunkel, M. R., 2017), it is the responsibility of the industry to ensure that further growth into Australian shale markets – such as in the Northern Territory – are managed sustainably. For optimal results, fluid logistics cannot be an afterthought in development planning left to the hydraulic fracturing operation, but a key consideration in the overall project strategy.
{"title":"The Lean Fluid Lifecycle: Optimizing Consumption and Waste in Hydraulic Fracturing Operations","authors":"R. Jukes","doi":"10.2118/192068-MS","DOIUrl":"https://doi.org/10.2118/192068-MS","url":null,"abstract":"\u0000 This paper presents a case study reviewing the systematic optimization of fluid transport, consumption and waste in large hydraulic fracturing development campaigns. With a focus on reducing consumption, re-thinking transport, and creating value from waste fluid through recycling and reuse, the methodology applied has resulted in very real gains in economic, environmental, social and safety outcomes. The objective of this case study is to provide practical information and guidance for planning, execution and ongoing optimization to not only reduce the footprint of hydraulic fracturing activities but also reduce cost.\u0000 By applying the methodology within this paper, the following was achieved over a 90 well development program: Fluid transport via trucking to wellsite virtually eliminated through use of the water production gathering network;Total fluid requirements reduced by 50%;Chemical costs reduced by 35%;Fluid disposal volume via trucking reduced by 95%; andFluid waste disposal costs reduced by 90%.\u0000 While the case study presented is based on a coal bed methane (CBM) development where between 3,000 to 6,000 barrels of clean fluid was required per well, some or all of the methodologies may be applied to shale and conventional markets. With trends in stimulation volumes within the United States shale plays increasing more than threefold in recent years to upwards of 160,000 barrels per well (Dunkel, M. R., 2017), it is the responsibility of the industry to ensure that further growth into Australian shale markets – such as in the Northern Territory – are managed sustainably. For optimal results, fluid logistics cannot be an afterthought in development planning left to the hydraulic fracturing operation, but a key consideration in the overall project strategy.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"27 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73401904","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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