Ajay Addagalla, Iain Maley, Ishaq G. Lawal, Prakash Jadhav, Moro Luigi
Wells drilled in the direction of minimum stress are potentially more favorable for reservoir development and optimal production. In such a situation, hydraulic fractures grow transversely to the wellbore axis, allowing placement of multiple fractures without the overlapping fractures. However, wells that have been drilled in the minimum horizontal stress direction typically encounter drilling-related problems such as stuck pipe, wellbore breakout and lost circulation. These problems can result in increased well costs due to significant periods of non-productive time and in the worst case, loss of the well. To address this, wellbore strengthening techniques can be applied to bridge or plug fractures and increase near-wellbore stability via hoop stresses. Designing drilling fluids from a wellbore strengthening point of view has proved successful at managing problems associated with wells that have high overbalance pressure and low formation strength. As more challenging wells are drilled, though, overbalance pressures are exceeding the wellbore strengthening capabilities of existing fluid designs. These high-overbalance pressures significantly increase the risks associated with drilling in the minimum stress direction. This paper describes an improved, environmentally acceptable, customized high-performance system that can be used in water-based and oil-based mud systems, enabling wells to be drilled with more than 4500 psi overbalance pressure and mud weights beyond 145 pcf. This newly designed system helps the operator increase operational efficiency by:Minimizing the risk of differential stickingReducing downhole lossesImproving wellbore stabilityReducing torque and drag through enhanced lubricity Laboratory data is presented outlining the design of the new system and field case studies show how this new, improved bridging system reduces the risks associated with drilling in the minimum stress direction through highly depleted reservoirs or reservoir sections where multiple targets may be separated by high-pressure zones that require higher mud weights.
{"title":"Minimum Stress, Maximum Pressure: A New High Performance Bridging System Facilitates Drilling Depleted Formations at High Overbalance in Middle East","authors":"Ajay Addagalla, Iain Maley, Ishaq G. Lawal, Prakash Jadhav, Moro Luigi","doi":"10.2118/192051-MS","DOIUrl":"https://doi.org/10.2118/192051-MS","url":null,"abstract":"\u0000 Wells drilled in the direction of minimum stress are potentially more favorable for reservoir development and optimal production. In such a situation, hydraulic fractures grow transversely to the wellbore axis, allowing placement of multiple fractures without the overlapping fractures. However, wells that have been drilled in the minimum horizontal stress direction typically encounter drilling-related problems such as stuck pipe, wellbore breakout and lost circulation. These problems can result in increased well costs due to significant periods of non-productive time and in the worst case, loss of the well.\u0000 To address this, wellbore strengthening techniques can be applied to bridge or plug fractures and increase near-wellbore stability via hoop stresses. Designing drilling fluids from a wellbore strengthening point of view has proved successful at managing problems associated with wells that have high overbalance pressure and low formation strength. As more challenging wells are drilled, though, overbalance pressures are exceeding the wellbore strengthening capabilities of existing fluid designs. These high-overbalance pressures significantly increase the risks associated with drilling in the minimum stress direction.\u0000 This paper describes an improved, environmentally acceptable, customized high-performance system that can be used in water-based and oil-based mud systems, enabling wells to be drilled with more than 4500 psi overbalance pressure and mud weights beyond 145 pcf. This newly designed system helps the operator increase operational efficiency by:Minimizing the risk of differential stickingReducing downhole lossesImproving wellbore stabilityReducing torque and drag through enhanced lubricity\u0000 Laboratory data is presented outlining the design of the new system and field case studies show how this new, improved bridging system reduces the risks associated with drilling in the minimum stress direction through highly depleted reservoirs or reservoir sections where multiple targets may be separated by high-pressure zones that require higher mud weights.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"42 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82055501","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}
Gong Hongliang, Su Yan-an, Shujin Zhang, Qi Xing, Guochen Shi, Chun-long Sun, Guoqing Wang, Zhang Deshi, Wei Feng, Hou Yu, Changrui Qing, Guoxing Zheng, Yulong Zhao, Yang Gao
A new technology of the non-stop intermittent pumping production for beam pumping units has been widely used in PetroChina Daqing oil field. This technology solves the problems that existed in conventional intermittent pumping production, such as a large fluctuation in fluid level, a long idle time, high labor intensity, frozen wellhead in winter, and difficulty in management, etc. This technology adopts a new strategy. It transforms a long-period intermittent pumping into several short-period intermittent pumping, and changes the crank from shutdown into low-energy swinging motion, at the same time, the plunger piston at downhole is kept stationary while the crank does do non-stop swing operation. Based on the maximum elastic deformation of sucker rods, the optimal swing range and rotary speed of crank are designed by kinematics and load analysis. Meanwhile, the inverter increases the swinging amplitude of crank to build up the gravitational potential energy. With conversion effects from gravitational potential energy to kinetic energy, as well as active control of swing power, a non-impact low energy swinging scheme is formed. The flexible switch between complete-cycle pumping operation and swing operation is successfully realized. According to the situation of a single well, the corresponding working system is formulated. A total of 124 wells had been used this new technology in petroChina Daqing oil field, the filed application shows that, the non-stop intermittent pumping production stabilizes the fluid level within a reasonable range and guarantees a better pump fillage. Compared with the conventional intermittent pumping prodution, the pump efficiency improved 6.54%, the average energy-saving rate ran up to 34.59%. It is significantly improved the pump efficiency and system efficiency, and achieved the purpose of energy saving. The technology of the non-stop intermittent pumping production for beam pumping units is appropriate for the low-yield well and insufficient liquid well. It will be of great significance for the high-efficiency development of low-yield well.
{"title":"Research of Non-Stop Intermittent Pumping Production for Beam Pumping Units","authors":"Gong Hongliang, Su Yan-an, Shujin Zhang, Qi Xing, Guochen Shi, Chun-long Sun, Guoqing Wang, Zhang Deshi, Wei Feng, Hou Yu, Changrui Qing, Guoxing Zheng, Yulong Zhao, Yang Gao","doi":"10.2118/191890-MS","DOIUrl":"https://doi.org/10.2118/191890-MS","url":null,"abstract":"\u0000 A new technology of the non-stop intermittent pumping production for beam pumping units has been widely used in PetroChina Daqing oil field. This technology solves the problems that existed in conventional intermittent pumping production, such as a large fluctuation in fluid level, a long idle time, high labor intensity, frozen wellhead in winter, and difficulty in management, etc.\u0000 This technology adopts a new strategy. It transforms a long-period intermittent pumping into several short-period intermittent pumping, and changes the crank from shutdown into low-energy swinging motion, at the same time, the plunger piston at downhole is kept stationary while the crank does do non-stop swing operation. Based on the maximum elastic deformation of sucker rods, the optimal swing range and rotary speed of crank are designed by kinematics and load analysis. Meanwhile, the inverter increases the swinging amplitude of crank to build up the gravitational potential energy. With conversion effects from gravitational potential energy to kinetic energy, as well as active control of swing power, a non-impact low energy swinging scheme is formed. The flexible switch between complete-cycle pumping operation and swing operation is successfully realized. According to the situation of a single well, the corresponding working system is formulated.\u0000 A total of 124 wells had been used this new technology in petroChina Daqing oil field, the filed application shows that, the non-stop intermittent pumping production stabilizes the fluid level within a reasonable range and guarantees a better pump fillage. Compared with the conventional intermittent pumping prodution, the pump efficiency improved 6.54%, the average energy-saving rate ran up to 34.59%. It is significantly improved the pump efficiency and system efficiency, and achieved the purpose of energy saving. The technology of the non-stop intermittent pumping production for beam pumping units is appropriate for the low-yield well and insufficient liquid well. It will be of great significance for the high-efficiency development of low-yield well.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"141 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80061173","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}
Alistair Jones, Chris Mijnssen, Andrew Burton, M. Ewin
Recoverable hydrocarbon resource assessments underpin decision making and business planning in the oil and gas industry. Understanding the uncertainty associated with the resource assessments are key to sound decisions that are robust against low or high outcomes. This paper outlines a probabilistic approach to resource assessment in order to characterise resource uncertainty in a portfolio containing primarily Coal Seam Gas resources. The Probabilistic Resource Assessment (PRA) process outlined in this paper allows calculation of risked and unrisked probabilistically derived commercially recoverable resources at a field or permit level as well as at a portfolio level. This process incorporates Undiscovered ("Prospective") resources and Contingent Resources as well as resources that are producing or are under development. The key steps in this process include: definition of input distributions, probabilistic calculation of technically recoverable resources at a field level, estimation of economic chance of success, probabilistic estimate of commercially recoverable resource and aggregation of resources to a portfolio level. This process has been applied within an integrated joint venture supplying Liquefied Natural Gas (LNG) and domestic gas markets. The process has been used primarily to understand the uncertainty range of the total resource as well as the production profile within the upstream portfolio. Sensitivities to product prices or development costs can be investigated to enable a deep understanding of the key drivers and variables of the resource assessment. Various methods for determining recoverable hydrocarbon resources have been well documented. Broadly speaking, these methods can be categorised as probabilistic methods and deterministic methods. Typically, unconventional resources are assessed using deterministic methods. The process presented here is a robust probabilistic approach to determine a risked view of recoverable resources within an entire portfolio including both unconventional and conventional resources.
{"title":"Use of Probabilistic Methods to Assess a Portfolio of Conventional and Unconventional Resources","authors":"Alistair Jones, Chris Mijnssen, Andrew Burton, M. Ewin","doi":"10.2118/192088-MS","DOIUrl":"https://doi.org/10.2118/192088-MS","url":null,"abstract":"\u0000 Recoverable hydrocarbon resource assessments underpin decision making and business planning in the oil and gas industry. Understanding the uncertainty associated with the resource assessments are key to sound decisions that are robust against low or high outcomes. This paper outlines a probabilistic approach to resource assessment in order to characterise resource uncertainty in a portfolio containing primarily Coal Seam Gas resources.\u0000 The Probabilistic Resource Assessment (PRA) process outlined in this paper allows calculation of risked and unrisked probabilistically derived commercially recoverable resources at a field or permit level as well as at a portfolio level. This process incorporates Undiscovered (\"Prospective\") resources and Contingent Resources as well as resources that are producing or are under development. The key steps in this process include: definition of input distributions, probabilistic calculation of technically recoverable resources at a field level, estimation of economic chance of success, probabilistic estimate of commercially recoverable resource and aggregation of resources to a portfolio level.\u0000 This process has been applied within an integrated joint venture supplying Liquefied Natural Gas (LNG) and domestic gas markets. The process has been used primarily to understand the uncertainty range of the total resource as well as the production profile within the upstream portfolio. Sensitivities to product prices or development costs can be investigated to enable a deep understanding of the key drivers and variables of the resource assessment.\u0000 Various methods for determining recoverable hydrocarbon resources have been well documented. Broadly speaking, these methods can be categorised as probabilistic methods and deterministic methods. Typically, unconventional resources are assessed using deterministic methods. The process presented here is a robust probabilistic approach to determine a risked view of recoverable resources within an entire portfolio including both unconventional and conventional resources.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"114 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86244125","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 probability graph was developed to describe height growth potential when performing hydraulic fracture stimulation operations in the Cooper Basin, Central Australia. This graph has led to improvements in setting completion strategies. Multiple data sources were used to define the probability graph, including proppant tracers, microseismic, downhole tiltmeter data as well as pressure interference and production data. Each dataset has known uncertainties, so the empirically derived probability graph has an intrinsic range of uncertainty. The observed data shows instances of fracture propagation across changes in lithology which were previously thought to be highly confining. In other instances, field data closely matched model predictions. Likewise, the observed data indicates that typical levers used to induce or reduce height growth (such as fluid viscosity, pump rate and job size) may have limited influence. These insights led decision makers to question the validity of deterministic fracture models. This study highlights that fracture height growth predictions should carry a range of uncertainty. An appreciation of this range has proven beneficial by fostering ‘what-if’ discussions during the project planning phase. The derived probability graph can be used to run sensitivity analyses to determine the optimal path when several completion methods are available. This graph has proven to be an informative and practical tool for use in the Cooper Basin by promoting deeper thought and collaboration amongst stakeholders. Similar tools could be developed to characterise fracture height growth within other petroleum basins.
{"title":"Fracture Height Growth Study: Cooper Basin Probability Analysis","authors":"J. Griffiths","doi":"10.2118/192060-MS","DOIUrl":"https://doi.org/10.2118/192060-MS","url":null,"abstract":"\u0000 A probability graph was developed to describe height growth potential when performing hydraulic fracture stimulation operations in the Cooper Basin, Central Australia. This graph has led to improvements in setting completion strategies.\u0000 Multiple data sources were used to define the probability graph, including proppant tracers, microseismic, downhole tiltmeter data as well as pressure interference and production data. Each dataset has known uncertainties, so the empirically derived probability graph has an intrinsic range of uncertainty.\u0000 The observed data shows instances of fracture propagation across changes in lithology which were previously thought to be highly confining. In other instances, field data closely matched model predictions. Likewise, the observed data indicates that typical levers used to induce or reduce height growth (such as fluid viscosity, pump rate and job size) may have limited influence. These insights led decision makers to question the validity of deterministic fracture models.\u0000 This study highlights that fracture height growth predictions should carry a range of uncertainty. An appreciation of this range has proven beneficial by fostering ‘what-if’ discussions during the project planning phase. The derived probability graph can be used to run sensitivity analyses to determine the optimal path when several completion methods are available.\u0000 This graph has proven to be an informative and practical tool for use in the Cooper Basin by promoting deeper thought and collaboration amongst stakeholders. Similar tools could be developed to characterise fracture height growth within other petroleum basins.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"17 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74453106","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}
Australia is uniquely positioned globally as a major energy provider, but this comes with multiple challenges that must be overcome to realize its full potential. LNG developments that are nearing fruition are set to make Australia the largest supplier of LNG in the world. The Asian LNG market continues to be the growth market. The development of the world's first coal bed methane (coal seam gas) to LNG projects on the east coast has created a robust east coast LNG export market, which in the near future is expected to coincide with domestic energy shortages arising from low exploration activity, maturing fields, higher costs, the interaction of government policy, commercial decisions and activism. As a result, unique approaches to project management and community relations have been developed that are complementary to the Australian consumer's needs for reliable, affordable and cleaner energy. The east coast demand for gas is likely to trigger new development of onshore Northern Territory gas in the short term, if political opposition can be managed. In Western Australia, new approaches leverage technologies such as floating LNG, and more utilization of existing infrastructure and plant capacity to achieve lower costs. This paper outlines Australia's natural gas supply & demand and the challenges to be faced in the coming years.
{"title":"Australia's World Scale Gas Resources, Its Markets and Why New Approaches Are Required","authors":"B. Towler, Mahshid Firouzi, R. Wilkinson","doi":"10.2118/191895-MS","DOIUrl":"https://doi.org/10.2118/191895-MS","url":null,"abstract":"\u0000 Australia is uniquely positioned globally as a major energy provider, but this comes with multiple challenges that must be overcome to realize its full potential. LNG developments that are nearing fruition are set to make Australia the largest supplier of LNG in the world. The Asian LNG market continues to be the growth market. The development of the world's first coal bed methane (coal seam gas) to LNG projects on the east coast has created a robust east coast LNG export market, which in the near future is expected to coincide with domestic energy shortages arising from low exploration activity, maturing fields, higher costs, the interaction of government policy, commercial decisions and activism. As a result, unique approaches to project management and community relations have been developed that are complementary to the Australian consumer's needs for reliable, affordable and cleaner energy. The east coast demand for gas is likely to trigger new development of onshore Northern Territory gas in the short term, if political opposition can be managed. In Western Australia, new approaches leverage technologies such as floating LNG, and more utilization of existing infrastructure and plant capacity to achieve lower costs. This paper outlines Australia's natural gas supply & demand and the challenges to be faced in the coming years.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"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":"76233443","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}
T. Flottmann, V. Pandey, S. Ganpule, Elliot Kirk-Burnnand, Massoud Zadmehr, N. Simms, J. Jenkinson, Tristan Renwick-Cooke, M. Tarenzi, Ashok Mishra
Walloons Coals of the Surat Basin, Queensland (Australia) contain world class Coal Seam Gas (CSG) plays, where permeability varies from high (>1Darcy), due to Gaussian curvature-related natural fracture connectivity, to low (<1mD) due to unidirectional fracture-systems attributed to regional unidirectional flexure. The low permeability Walloons Coals require stimulation to unlock their gas resources. This contribution describes the design evolution of stimulation concepts in the Surat Basin in context of five key subsurface drivers Coal net to gross: Surat Basin coals contain 30 coal seams with a cumulative thickness of 20-35m in a gross rock column of >300m Permeability of coals requiring stimulation for economic flow rates varies from <1mD - ~30mD Varying stress regimes, both vertically and laterally Ductile rock properties in Walloons coal reservoirs Productivity Index drop (PI drop) can occur when (incompressible) water is replaced by (compressible) gas during coal dewatering Early stimulation treatments in Surat Basin (pre-2010) followed ‘standard’ high rate water/sand designs adapted from the shale industry. However, high treating pressure and rates resulted in several instances of casing shear (Johnson et al. 2003) particularly at depths associated with stress regime transitions. Subsequent designs (2010-12) repeated water fracs albeit including ample diagnostics (Johnson et al 2010; Flottmann et al 2013), showing that water fracs appear to be ineffective in stimulating Walloons Coals. Design optimizations in 2015 (Kirk-Burnnand et al. 2015) based on extensive modeling work (Pandey and Flottmann 2015), identified low rate gel fracs as optimal to stimulate rocks with ‘ductile’ Walloons-specific coal properties. However, treatment rates were limited to optimize height growth, both to connect coals and to avoid height growth into non-reservoir. Initial production data indicated a drop in well productivity in some fracture stimulated coals (Busetti et al. 2017). Consequently, stimulation designs were modified in late 2016 to account for such productivity drops while maximizing the fluid recovery. Early time post stimulation drawdown strategy was also field-tested to mitigate loss of well productivity due to excessive drawdown which could cause partial or full fracture closure (especially near the wellbore region), and lead to loss of communication between reservoir and well. Sub-surface drivers identified in tight Walloons Coals control the effectiveness of any stimulation option deployed. These drivers influence the effectiveness of stimulation in multiple ways. First, these drivers can lead to a sub-optimal connectivity between well and reservoir resulting in poor productivity and marginal recovery. Second, the drivers may influence an operator towards expensive stimulation options which may provide better well to reservoir connectivity but diminish the economic value due to the high costs involved. Hence the inclusion of sub-surface d
澳大利亚昆士兰州Surat盆地的Walloons煤系含有世界级的煤层气(CSG)储层，由于高斯曲率相关的天然裂缝连通性，其渗透率从高(>1达西)到低(300米)，渗透率从<1mD - ~30mD不等。在煤炭脱水过程中，当(不可压缩)水被(可压缩)气取代时，产能指数(PI)会下降。2010年之前，Surat盆地的早期增产措施遵循了页岩行业的“标准”高速率水/砂设计。然而，高处理压力和速率导致了几次套管剪切(Johnson et al. 2003)，特别是在与应力状态变化相关的深度。随后的设计(2010-12)重复出现了水裂缝，尽管包括了大量的诊断(Johnson et al . 2010;Flottmann et al . 2013)，表明水力压裂在开采Walloons煤方面似乎是无效的。2015年的设计优化(Kirk-Burnnand et al. 2015)基于大量的建模工作(Pandey and Flottmann 2015)，确定了低速率凝胶裂缝是开采具有“延展性”walloons特定煤性岩石的最佳选择。然而，为了优化高度增长，既要连接煤，又要避免高度增长进入非储层，处理率受到限制。最初的生产数据表明，一些压裂煤的产能下降(Busetti et al. 2017)。因此，在2016年底对增产设计进行了修改，以解决产能下降的问题，同时最大限度地提高流体采收率。增产后的早期降压策略也进行了现场测试，以减轻由于过度降压可能导致部分或全部裂缝关闭(特别是在井筒附近)，并导致储层与井之间失去联系而造成的井产能损失。致密Walloons煤中确定的地下驱动因素控制着任何增产措施的有效性。这些驱动因素以多种方式影响刺激的有效性。首先，这些驱动因素可能导致井与油藏之间的连通性不佳，从而导致产能低下和边际采收率。其次，驱动因素可能会影响作业者选择昂贵的增产方案，这些方案可能会提供更好的井与油藏连通性，但由于涉及的高成本而降低了经济价值。因此，如本文所述，在选择增产设计时考虑地下驱动因素是至关重要的。
{"title":"Fracture Stimulation Challenges in Tight Walloons Coal Measures: Surat Basin Queensland, Australia","authors":"T. Flottmann, V. Pandey, S. Ganpule, Elliot Kirk-Burnnand, Massoud Zadmehr, N. Simms, J. Jenkinson, Tristan Renwick-Cooke, M. Tarenzi, Ashok Mishra","doi":"10.2118/191958-MS","DOIUrl":"https://doi.org/10.2118/191958-MS","url":null,"abstract":"\u0000 Walloons Coals of the Surat Basin, Queensland (Australia) contain world class Coal Seam Gas (CSG) plays, where permeability varies from high (>1Darcy), due to Gaussian curvature-related natural fracture connectivity, to low (<1mD) due to unidirectional fracture-systems attributed to regional unidirectional flexure. The low permeability Walloons Coals require stimulation to unlock their gas resources.\u0000 This contribution describes the design evolution of stimulation concepts in the Surat Basin in context of five key subsurface drivers\u0000 Coal net to gross: Surat Basin coals contain 30 coal seams with a cumulative thickness of 20-35m in a gross rock column of >300m Permeability of coals requiring stimulation for economic flow rates varies from <1mD - ~30mD Varying stress regimes, both vertically and laterally Ductile rock properties in Walloons coal reservoirs Productivity Index drop (PI drop) can occur when (incompressible) water is replaced by (compressible) gas during coal dewatering\u0000 Early stimulation treatments in Surat Basin (pre-2010) followed ‘standard’ high rate water/sand designs adapted from the shale industry. However, high treating pressure and rates resulted in several instances of casing shear (Johnson et al. 2003) particularly at depths associated with stress regime transitions. Subsequent designs (2010-12) repeated water fracs albeit including ample diagnostics (Johnson et al 2010; Flottmann et al 2013), showing that water fracs appear to be ineffective in stimulating Walloons Coals. Design optimizations in 2015 (Kirk-Burnnand et al. 2015) based on extensive modeling work (Pandey and Flottmann 2015), identified low rate gel fracs as optimal to stimulate rocks with ‘ductile’ Walloons-specific coal properties. However, treatment rates were limited to optimize height growth, both to connect coals and to avoid height growth into non-reservoir. Initial production data indicated a drop in well productivity in some fracture stimulated coals (Busetti et al. 2017). Consequently, stimulation designs were modified in late 2016 to account for such productivity drops while maximizing the fluid recovery. Early time post stimulation drawdown strategy was also field-tested to mitigate loss of well productivity due to excessive drawdown which could cause partial or full fracture closure (especially near the wellbore region), and lead to loss of communication between reservoir and well.\u0000 Sub-surface drivers identified in tight Walloons Coals control the effectiveness of any stimulation option deployed. These drivers influence the effectiveness of stimulation in multiple ways. First, these drivers can lead to a sub-optimal connectivity between well and reservoir resulting in poor productivity and marginal recovery. Second, the drivers may influence an operator towards expensive stimulation options which may provide better well to reservoir connectivity but diminish the economic value due to the high costs involved. Hence the inclusion of sub-surface d","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87663301","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
S. Bui, H. Ngo, Nam Nguyen, G. Blackwell, J. Trethewey
One of the most challenging drilling applications in Vietnam is granitic basement drilling, where the formation is very hard (35-40Kpsi UCS), not drillable with polycrystalline diamond compact (PDC) cutters, and high vibration levels are experienced. There are many common issues and risks, but despite the challenges, Thang Long Joint Operating Company planned to drill a 3217m 3D horizontal granite section hitting all three targets: building inclination from 20 degrees to 85.6 degrees, holding the lateral, and turning from 62°to 14.3°azimuth, total depth (TD) at 6280m measured depth (MD). A scientific approach using torque and drag modelling, relevant offset data, and an axial oscillation tool (AOT) to prove drilling to TD is achievable within the acceptable cost and time frame was proposed. A torque and drag model was built from the longest extended reach drilling (ERD) basement section drilled in 2014 (Well X, a 2D well, TD at 7300m MD, 3035m basement section) to understand drilling conditions and limitations. The results were applied in the torque and drag model of the subject well (Well Y). Bent motor bottom hole assemblies (BHAs) were then designed and optimized to minimize string buckling. The modelling was run again, and axial oscillation tools were placed in appropriate zones of each BHA. The first eight BHAs from the beginning of the granite section at 3063m MD to 5071m MD (completed the horizontal turn at 4313m MD, then held tangent) performed well and stayed close to the planned trajectory. The torque and drag model was continuously updated after each run to predict and prepare the BHA for the next run. From 5071m MD to TD at 6280m MD, optimized bent motor BHAs in combination with two axial oscillation tools were utilized to achieve the directional drilling plan and hit all targets. Two rotary steerable system (RSS) BHAs were used to test an alternative steering solution in granite basement. Both BHAs were unsuccessful in holding the well angle, and repeatedly failed to correct the well path. The use of axial oscillation technology provides a solution to drilling the granitic basement in Vietnam, which has proven to save operators time and reduce costs, as well as facilitate a more complex and longer basement section to connect multiple pay zones to be planned in the future.
越南最具挑战性的钻井应用之一是花岗岩基底钻井，该地层非常坚硬(35-40Kpsi UCS)，不能使用聚晶金刚石(PDC)切齿钻取，并且经历了高振动水平。尽管存在许多共同的问题和风险，但尽管面临挑战，Thang Long Joint Operating Company计划钻出3217米的3D水平花岗岩段，实现所有三个目标:建筑倾角从20度到85.6度，保持横向，方位角从62°到14.3°，总深度(TD)在6280米的测量深度(MD)。提出了一种利用扭矩和阻力建模、相关偏移数据和轴向振荡工具(AOT)的科学方法，以证明在可接受的成本和时间范围内可以实现钻至TD。根据2014年钻出的最长大位移钻井(ERD)基底段(井X，一口2D井，井深7300m，基底段3035m)建立了扭矩和阻力模型，以了解钻井条件和局限性。将结果应用于实验井(井Y)的扭矩和阻力模型中，然后设计和优化弯曲马达底部钻具组合(bha)，以最大限度地减少管柱的屈曲。再次进行建模，并将轴向振荡工具放置在每个BHA的适当区域。从花岗岩段开始的3063米到5071米(在4313米完成水平转弯，然后保持切线)，前8个bha表现良好，并保持在计划轨迹附近。每次下入后，扭矩和阻力模型都会不断更新，以预测和准备下一次下入的BHA。从井深5071米到井深6280米，利用优化后的弯曲马达bha与两个轴向振荡工具相结合，实现了定向钻井计划，并击中了所有目标。使用两个旋转导向系统(RSS) bha在花岗岩基底中测试了一种替代导向方案。两种bha都未能成功保持井角，并且多次未能纠正井眼轨迹。轴向振荡技术的使用为越南花岗岩基底的钻井提供了一种解决方案，该技术已被证明可以节省操作人员的时间和降低成本，并有助于在未来规划的多个产层之间建立更复杂、更长的基底段。
{"title":"Axial Oscillation Tool Combined with Optimized Bent Motor BHA's Successfully Drills Record 3D Horizontal Granitic Basement Section in Vietnam","authors":"S. Bui, H. Ngo, Nam Nguyen, G. Blackwell, J. Trethewey","doi":"10.2118/191872-MS","DOIUrl":"https://doi.org/10.2118/191872-MS","url":null,"abstract":"\u0000 One of the most challenging drilling applications in Vietnam is granitic basement drilling, where the formation is very hard (35-40Kpsi UCS), not drillable with polycrystalline diamond compact (PDC) cutters, and high vibration levels are experienced. There are many common issues and risks, but despite the challenges, Thang Long Joint Operating Company planned to drill a 3217m 3D horizontal granite section hitting all three targets: building inclination from 20 degrees to 85.6 degrees, holding the lateral, and turning from 62°to 14.3°azimuth, total depth (TD) at 6280m measured depth (MD).\u0000 A scientific approach using torque and drag modelling, relevant offset data, and an axial oscillation tool (AOT) to prove drilling to TD is achievable within the acceptable cost and time frame was proposed. A torque and drag model was built from the longest extended reach drilling (ERD) basement section drilled in 2014 (Well X, a 2D well, TD at 7300m MD, 3035m basement section) to understand drilling conditions and limitations. The results were applied in the torque and drag model of the subject well (Well Y). Bent motor bottom hole assemblies (BHAs) were then designed and optimized to minimize string buckling. The modelling was run again, and axial oscillation tools were placed in appropriate zones of each BHA.\u0000 The first eight BHAs from the beginning of the granite section at 3063m MD to 5071m MD (completed the horizontal turn at 4313m MD, then held tangent) performed well and stayed close to the planned trajectory. The torque and drag model was continuously updated after each run to predict and prepare the BHA for the next run. From 5071m MD to TD at 6280m MD, optimized bent motor BHAs in combination with two axial oscillation tools were utilized to achieve the directional drilling plan and hit all targets. Two rotary steerable system (RSS) BHAs were used to test an alternative steering solution in granite basement. Both BHAs were unsuccessful in holding the well angle, and repeatedly failed to correct the well path.\u0000 The use of axial oscillation technology provides a solution to drilling the granitic basement in Vietnam, which has proven to save operators time and reduce costs, as well as facilitate a more complex and longer basement section to connect multiple pay zones to be planned in the future.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 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":"88036860","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 case study highlights the field-trial of a pump-out stage tool, pump-out float collar, and the annular casing packer. These technologies were integral to drilling and completing wells in the Santos coal-seam gas (CSG) development of the Roma field in the Surat Basin of southeast Queensland. Pump-out systems—which allow a primary cementing job to be performed above a slotted casing string using a pump-out stage tool, annular casing packer, and pump-out float equipment—eliminate the need for drill out operations. Once the casing is landed, a ball is deployed from surface to actuate the inflation of an annular casing packer below the stage tool and above the slotted casing. A second ball is deployed to shear and shift a sleeve to open the stage tool and begin the primary cement job. Once complete, a cementing wiper plug is released from surface and pumped behind the cement slurry to shift the stage tool into the closed position. The internal pump-out casing components are displaced to the bottom of the well and require no further intervention. This case history includes results of the initial field-trial runs and technical details on well configurations, slotted liner placement across the coal-bed intervals, pressure charts, cement-job data, shear information on the ball seat, detail on the stage-tool operation, pumping out the float collar, and displacement of the internal equipment downhole. These jobs planned to eliminate the need to run a dedicated drillout trip during initial completion and also the need to change out the pipe rams in the blowout preventer (BOP). Ultimately, the pump-out system provides a full-bore casing geometry with no internal restrictions and is expected to reduce completion costs by 15%.
{"title":"Pump-Out Stage Tool and Pump-Out Float Collar System Enhances Completion Efficiency in Queensland Coal-Seam Gas Project: A Case Study","authors":"Mohammad Zaman, Tim Dunn, Sandeep Tickoo","doi":"10.2118/191954-MS","DOIUrl":"https://doi.org/10.2118/191954-MS","url":null,"abstract":"\u0000 This case study highlights the field-trial of a pump-out stage tool, pump-out float collar, and the annular casing packer. These technologies were integral to drilling and completing wells in the Santos coal-seam gas (CSG) development of the Roma field in the Surat Basin of southeast Queensland.\u0000 Pump-out systems—which allow a primary cementing job to be performed above a slotted casing string using a pump-out stage tool, annular casing packer, and pump-out float equipment—eliminate the need for drill out operations. Once the casing is landed, a ball is deployed from surface to actuate the inflation of an annular casing packer below the stage tool and above the slotted casing. A second ball is deployed to shear and shift a sleeve to open the stage tool and begin the primary cement job. Once complete, a cementing wiper plug is released from surface and pumped behind the cement slurry to shift the stage tool into the closed position. The internal pump-out casing components are displaced to the bottom of the well and require no further intervention.\u0000 This case history includes results of the initial field-trial runs and technical details on well configurations, slotted liner placement across the coal-bed intervals, pressure charts, cement-job data, shear information on the ball seat, detail on the stage-tool operation, pumping out the float collar, and displacement of the internal equipment downhole. These jobs planned to eliminate the need to run a dedicated drillout trip during initial completion and also the need to change out the pipe rams in the blowout preventer (BOP).\u0000 Ultimately, the pump-out system provides a full-bore casing geometry with no internal restrictions and is expected to reduce completion costs by 15%.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"151 ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91451822","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}
Ginger Ren, A. Sanders, Dawn M. Friesen, B. Seymour
Surfactants are used in gas well deliquification to generate foam to lift liquid condensates and brine from a well during gas production. In this paper, the effect of various hydrocarbon components typically found in natural condensates on selected foaming surfactants was studied. The screening methodology used a modified blender test to evaluate foam height and its half-life. The foaming results from the blender tests are reported for a number of alpha olefin sulfonates (AOS), alkyl ether sulfates (AES), and betaines at 25°C and ambient pressure. The surfactants were also evaluated using dynamic foam carry-over apparatus at ambient conditions for further validation. This work helps to elucidate problems associated with choosing the proper gas well deliquification surfactant suitable for a condensate of a specific composition.
{"title":"Understanding the Impact of Condensate Composition on Performance of Gas Well Deliquification Surfactants","authors":"Ginger Ren, A. Sanders, Dawn M. Friesen, B. Seymour","doi":"10.2118/192142-MS","DOIUrl":"https://doi.org/10.2118/192142-MS","url":null,"abstract":"\u0000 Surfactants are used in gas well deliquification to generate foam to lift liquid condensates and brine from a well during gas production. In this paper, the effect of various hydrocarbon components typically found in natural condensates on selected foaming surfactants was studied.\u0000 The screening methodology used a modified blender test to evaluate foam height and its half-life. The foaming results from the blender tests are reported for a number of alpha olefin sulfonates (AOS), alkyl ether sulfates (AES), and betaines at 25°C and ambient pressure. The surfactants were also evaluated using dynamic foam carry-over apparatus at ambient conditions for further validation.\u0000 This work helps to elucidate problems associated with choosing the proper gas well deliquification surfactant suitable for a condensate of a specific composition.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"49 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90381044","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}
In this paper, we present an innovative Rotating Continuous Circulation Tool (RCCT) that allows both limited rotation of a drillstring assembly and uninterrupted circulation of drilling fluid during making up of, or breaking out, a drill pipe, to/from the drillstring assembly. Continuous/nearly continuous drilling has many advantages such as reducing the risk of stuck pipe and wellbore collapse as well as the efficient removal of cuttings resulting in improved borehole cleaning. The RCCT is a sub with a central bore and upper and lower ends that connect to the drillstring assembly. The upper and the lower part of the RCCT are able to rotate independently and in unison through a clutch/sleeve system. A central bore valve that is coupled to the upper part of the RCCT is able to selectively open and close the central bore. There is also a side entry port in the sidewall of the upper part that is controlled by the central bore valve to selectively allow drilling fluid to be injected into the central bore. A preliminary field trial to validate the RCCT was safely and successfully performed in a hydrocarbon well during a cement cleanout operation. The four RCCT subs were successfully tested for rotation with the rotary table and for drilling dynamics while cleaning out cement. Recommendations for improvements from this trial test are planned to be implemented in future field tests.
{"title":"Design, Fabrication and Field Trial Testing of a Novel Rotating Continuous Circulation Tool RCCT","authors":"Mohammed Badran, C. Gooneratne, A. Saqqa","doi":"10.2118/191964-MS","DOIUrl":"https://doi.org/10.2118/191964-MS","url":null,"abstract":"\u0000 In this paper, we present an innovative Rotating Continuous Circulation Tool (RCCT) that allows both limited rotation of a drillstring assembly and uninterrupted circulation of drilling fluid during making up of, or breaking out, a drill pipe, to/from the drillstring assembly. Continuous/nearly continuous drilling has many advantages such as reducing the risk of stuck pipe and wellbore collapse as well as the efficient removal of cuttings resulting in improved borehole cleaning. The RCCT is a sub with a central bore and upper and lower ends that connect to the drillstring assembly. The upper and the lower part of the RCCT are able to rotate independently and in unison through a clutch/sleeve system. A central bore valve that is coupled to the upper part of the RCCT is able to selectively open and close the central bore. There is also a side entry port in the sidewall of the upper part that is controlled by the central bore valve to selectively allow drilling fluid to be injected into the central bore. A preliminary field trial to validate the RCCT was safely and successfully performed in a hydrocarbon well during a cement cleanout operation. The four RCCT subs were successfully tested for rotation with the rotary table and for drilling dynamics while cleaning out cement. Recommendations for improvements from this trial test are planned to be implemented in future field tests.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"131 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81418924","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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