Many stakeholders are concerned about the effects of Coal Seam Gas (CSG) developments on aquifers. Well integrity issues are often mentioned as potential leakage pathways which could lead to aquifer contamination or depletion. This study involved the creation of simple models to represent the behaviour around a producing CSG well with a well integrity failure. A range of realistic scenarios were chosen, representing hypothetical well integrity failures at different stages of CSG production. Dynamic numerical models were built that represent each scenario, and simulations were run to forecast the flux of fluids around the wellbore. These models were parameterized based on data from literature related to well integrity studies, and should represent reasonable worst-case scenarios. The results of simulations using these models are then used to explain key concepts relating to well integrity in CSG wells in a manner which can be understood by interested parties from non-technical backgrounds. The simulation results based on these simple models indicate that well integrity issues in producing (or previously produced) CSG wells are unlikely to have any significant impact on overlying aquifers.
{"title":"Simple Numerical Simulations to Demonstrate Key Concepts Related to Coal Seam Gas Well Integrity","authors":"I. Rodger, A. Garnett, S. Hurter","doi":"10.2118/192106-MS","DOIUrl":"https://doi.org/10.2118/192106-MS","url":null,"abstract":"\u0000 Many stakeholders are concerned about the effects of Coal Seam Gas (CSG) developments on aquifers. Well integrity issues are often mentioned as potential leakage pathways which could lead to aquifer contamination or depletion.\u0000 This study involved the creation of simple models to represent the behaviour around a producing CSG well with a well integrity failure. A range of realistic scenarios were chosen, representing hypothetical well integrity failures at different stages of CSG production. Dynamic numerical models were built that represent each scenario, and simulations were run to forecast the flux of fluids around the wellbore. These models were parameterized based on data from literature related to well integrity studies, and should represent reasonable worst-case scenarios. The results of simulations using these models are then used to explain key concepts relating to well integrity in CSG wells in a manner which can be understood by interested parties from non-technical backgrounds.\u0000 The simulation results based on these simple models indicate that well integrity issues in producing (or previously produced) CSG wells are unlikely to have any significant impact on overlying aquifers.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"46 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86700876","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}
Takaaki Uetani, Jyunichi Kai, Tomoko Hitomi, H. Seino, Kiyomasa Shinbori, H. Yonebayashi
This paper presents the results of a laboratory case study that was initiated to understand the main causes of the crude oil emulsion for an onshore oil field in Japan. The factors investigated on the influence of emulsion stability were oil and brine compositions, content of asphaltene, wax and toluene-insolubles, temperature, shear-stress, and water-cut. The results showed the emulsion was stabilized by multiple factors, indicating that multiple preventative approaches are required to sustain stable production, free of emulsion.
{"title":"Experimental Investigation of Crude Oil Emulsion Stability: Effect of Oil and Brine Compositions, Asphaltene, Wax, Toluene-insolubles, Temperature, Shear-stress, and Water-cut","authors":"Takaaki Uetani, Jyunichi Kai, Tomoko Hitomi, H. Seino, Kiyomasa Shinbori, H. Yonebayashi","doi":"10.2118/192064-MS","DOIUrl":"https://doi.org/10.2118/192064-MS","url":null,"abstract":"\u0000 This paper presents the results of a laboratory case study that was initiated to understand the main causes of the crude oil emulsion for an onshore oil field in Japan. The factors investigated on the influence of emulsion stability were oil and brine compositions, content of asphaltene, wax and toluene-insolubles, temperature, shear-stress, and water-cut. The results showed the emulsion was stabilized by multiple factors, indicating that multiple preventative approaches are required to sustain stable production, free of emulsion.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76298977","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 complex situations production optimisation often differs from plan to reality. Ideally a set of known factors are used to determine the optimal course of action for a production well. However, in reality many factors remain unknown and of those that are, many are only known within a range of uncertainty. Uncertainty is persistent; whether in the form of failed instrumentation, erroneous metering or production reconciliation to multiple reservoirs in commingled completions. Further, well optimisation is always governed by economics and operational constraints. Such constraints limit well surveillance activities and compound uncertainty. These challenges united when a large bore deviated depletion drive gas well on a small unmanned offshore platform in the Otway Basin began to exhibit unexpected production decline. The large bore gas well with commingled reservoir completions was diagnosed as exhibiting liquid loading behavior. The intervention objective was to isolate the probable formation water source and restore water free gas production. A production log was required to confirm water was present and identify the source from three groups of completed intervals, each separated from one another using packers and mechanical sliding side doors. After risk assessments conducted during the intervention an active decision was taken to abort the work and not isolate the water source in favour of continuing cycled production to maximise gas recovery. Introducing an unknown, production logging identified that one of the three completed reservoir intervals was isolated by a closed sliding side door, previously believed to be open, presenting an incremental production opportunity. A follow-up intervention retained an objective of isolating the water source, with the additional objective of accessing the isolated reservoir interval. Detailed planning and uncertainty analysis was conducted ahead of the campaign with a key risk being the range of pressure possibly present within this target interval and the resultant wellbore cross-flow immediately after accessing it. Whilst the second intervention experienced mechanical failure, the ensuing pragmatic decisions that were taken "on the fly" ultimately resulted in a successful production outcome. The water source was isolated and incremental rate and reserves were achieved through perforation of blast joints opposite the target interval. This paper presents the workflows, tools & interventions used to diagnose production decline and optimise production from this challenging well. It is a case study in production surveillance utilising limited data, decision tree analysis and contingency planning for interventions performed with significant operational limitations. It includes the use of slickline production logging, tubing plugs, and electric wireline perforating in a strong cross-flow wellbore environment. This paper will be of interest to operators of unmanned platforms in hostile environments, commin
{"title":"Production Optimisation in the Real World: A Case Study in Gas Production Surveillance, Intervention Planning and Decision Making on an Unmanned Platform","authors":"Antoni Kourakis, A. Nagel","doi":"10.2118/191992-MS","DOIUrl":"https://doi.org/10.2118/191992-MS","url":null,"abstract":"\u0000 In complex situations production optimisation often differs from plan to reality. Ideally a set of known factors are used to determine the optimal course of action for a production well. However, in reality many factors remain unknown and of those that are, many are only known within a range of uncertainty. Uncertainty is persistent; whether in the form of failed instrumentation, erroneous metering or production reconciliation to multiple reservoirs in commingled completions. Further, well optimisation is always governed by economics and operational constraints. Such constraints limit well surveillance activities and compound uncertainty. These challenges united when a large bore deviated depletion drive gas well on a small unmanned offshore platform in the Otway Basin began to exhibit unexpected production decline.\u0000 The large bore gas well with commingled reservoir completions was diagnosed as exhibiting liquid loading behavior. The intervention objective was to isolate the probable formation water source and restore water free gas production. A production log was required to confirm water was present and identify the source from three groups of completed intervals, each separated from one another using packers and mechanical sliding side doors. After risk assessments conducted during the intervention an active decision was taken to abort the work and not isolate the water source in favour of continuing cycled production to maximise gas recovery. Introducing an unknown, production logging identified that one of the three completed reservoir intervals was isolated by a closed sliding side door, previously believed to be open, presenting an incremental production opportunity.\u0000 A follow-up intervention retained an objective of isolating the water source, with the additional objective of accessing the isolated reservoir interval. Detailed planning and uncertainty analysis was conducted ahead of the campaign with a key risk being the range of pressure possibly present within this target interval and the resultant wellbore cross-flow immediately after accessing it. Whilst the second intervention experienced mechanical failure, the ensuing pragmatic decisions that were taken \"on the fly\" ultimately resulted in a successful production outcome. The water source was isolated and incremental rate and reserves were achieved through perforation of blast joints opposite the target interval.\u0000 This paper presents the workflows, tools & interventions used to diagnose production decline and optimise production from this challenging well. It is a case study in production surveillance utilising limited data, decision tree analysis and contingency planning for interventions performed with significant operational limitations. It includes the use of slickline production logging, tubing plugs, and electric wireline perforating in a strong cross-flow wellbore environment. This paper will be of interest to operators of unmanned platforms in hostile environments, commin","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"62 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76993821","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}
Benjamin Wu, Mahshid Firouzi, T. Rufford, B. Towler
Coal seam gas (CSG) well operators typically follow an industry rule of thumb 0.5 ft/s liquid velocity to prevent the onset of gas carryover during CSG dewatering operations. However, there is very little experimental data to validate this rule of thumb with only a publication by Sutton, Christiansen, Skinner and Wilson [1] available in the open literature. A review of more general studies on two-phase gas-water flows in vertical pipes and annuli revealed that experimental conditions, especially pipe and annuli diameters, can have a significant impact on development of two-phase flow phenomena. As such, the limited available data may not be applicable due to differences in experimental conditions. This study experimentally investigates the onset of gas carryover using an experimental setup intended specifically for the study of CSG wells. The University of Queensland Well Simulation Flow Facilities were designed to replicate as closely as possible the production zone of a typical vertical CSG well in Queensland, Australia in transparent acrylic pipes to observe two-phase flow behavior in simulated downhole conditions. The annular test section in the rig was constructed of a 7-in casing and 2¾-in tubing. Modification of the experimental setup to include a vertical separator allowed for the detection of gas carryover. Conceptual demonstrations of gas carryover were captured and have been illustrated. The experiments in this study validate the industry rule of thumb of 0.5 ft/s liquid velocity as an appropriate guideline for onset of gas carryover in a casing-tubing annulus dimension similar to a typical CSG well in Queensland.
煤层气(CSG)井运营商通常遵循行业经验规则，即0.5英尺/秒的液体速度，以防止在CSG脱水过程中发生气体携流。然而，只有Sutton, Christiansen, Skinner和Wilson[1]在公开文献中发表的一篇文章中，很少有实验数据来验证这一经验法则。对垂直管道和环空中气水两相流动的研究表明，实验条件，特别是管道和环空直径，对两相流动现象的发展有重要影响。因此，由于实验条件的差异，有限的可用数据可能不适用。本研究使用专门用于研究CSG井的实验装置，实验研究了气体携带的开始。昆士兰大学(University of Queensland)的井模拟流动设施旨在尽可能地复制澳大利亚昆士兰(Queensland)一口典型的垂直CSG井的生产区域，在透明丙烯酸管中观察模拟井下条件下的两相流动行为。钻机的环空测试部分由7英寸套管和2¾英寸油管组成。修改实验装置，包括一个垂直分离器，允许检测气体携带。捕获并说明了气体携带的概念演示。本研究的实验验证了行业经验法则，即0.5英尺/秒的液体速度是在类似于昆士兰典型的CSG井的套管-油管环空尺寸中气体携带开始的适当指导。
{"title":"Mitigating the Failure of Downhole Pumps Due to Gas Interference in Coal Seam Gas Wells","authors":"Benjamin Wu, Mahshid Firouzi, T. Rufford, B. Towler","doi":"10.2118/191910-MS","DOIUrl":"https://doi.org/10.2118/191910-MS","url":null,"abstract":"\u0000 Coal seam gas (CSG) well operators typically follow an industry rule of thumb 0.5 ft/s liquid velocity to prevent the onset of gas carryover during CSG dewatering operations. However, there is very little experimental data to validate this rule of thumb with only a publication by Sutton, Christiansen, Skinner and Wilson [1] available in the open literature. A review of more general studies on two-phase gas-water flows in vertical pipes and annuli revealed that experimental conditions, especially pipe and annuli diameters, can have a significant impact on development of two-phase flow phenomena. As such, the limited available data may not be applicable due to differences in experimental conditions. This study experimentally investigates the onset of gas carryover using an experimental setup intended specifically for the study of CSG wells.\u0000 The University of Queensland Well Simulation Flow Facilities were designed to replicate as closely as possible the production zone of a typical vertical CSG well in Queensland, Australia in transparent acrylic pipes to observe two-phase flow behavior in simulated downhole conditions. The annular test section in the rig was constructed of a 7-in casing and 2¾-in tubing. Modification of the experimental setup to include a vertical separator allowed for the detection of gas carryover. Conceptual demonstrations of gas carryover were captured and have been illustrated. The experiments in this study validate the industry rule of thumb of 0.5 ft/s liquid velocity as an appropriate guideline for onset of gas carryover in a casing-tubing annulus dimension similar to a typical CSG well in Queensland.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"121 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76204843","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}
Polymer flooding is a mature Enhanced Oil Recovery process which is used worldwide in many large- scale field expansions. Encouraged by these positive results, operators are still looking at applying the process in new fields even in the context of low oil prices and are evaluating its feasibility in more challenging reservoir conditions: high salinity, high hardness and high temperature. Several solutions have been proposed to overcome the limitations of the conventional hydrolyzed polyacrylamide (HPAM) in these types of challenging environments: biopolymers such as xanthan or scleroglucan, associative polymers, or co- or ter-polymers combining acrylamide with monomers such as ATBS or NVP. Each of these solutions has its advantages and disadvantages, which are not always clear for practicing engineers. Moreover, it is always interesting to study past field experience to confront theory with practice. This is what this paper proposes to do. The paper will first review the limits of conventional HPAM and other polymers that have been proposed for more challenging reservoir conditions. But more than that, it will focus on the field experience with each of these products to establish some practical guidelines for the selection of polymers depending on the reservoir and fluid characteristics. One first result of this review is that the limits of conventional HPAM may not be as low as usually expected. Biopolymers appear very sensitive to biodegradation and their success in the field has been limited. Associative polymers appear better suited to near-wellbore conformance control than to displacement processes and some of the new co and ter-polymers are currently being field tested with some measure of success. It appears that the main challenge lies with high temperature rather than high salinity; some field projects are currently ongoing in high salinity (200 g/L) and hardness. The paper will help set the current limits for polymer flooding in terms of temperature, salinity and hardness based on laboratory work and field experience. This will prove a useful guide for practicing engineers looking to pilot polymer injection in challenging reservoir conditions.
{"title":"Polymers and Their Limits in Temperature, Salinity and Hardness: Theory and Practice","authors":"E. Delamaide","doi":"10.2118/192110-MS","DOIUrl":"https://doi.org/10.2118/192110-MS","url":null,"abstract":"\u0000 Polymer flooding is a mature Enhanced Oil Recovery process which is used worldwide in many large- scale field expansions. Encouraged by these positive results, operators are still looking at applying the process in new fields even in the context of low oil prices and are evaluating its feasibility in more challenging reservoir conditions: high salinity, high hardness and high temperature. Several solutions have been proposed to overcome the limitations of the conventional hydrolyzed polyacrylamide (HPAM) in these types of challenging environments: biopolymers such as xanthan or scleroglucan, associative polymers, or co- or ter-polymers combining acrylamide with monomers such as ATBS or NVP. Each of these solutions has its advantages and disadvantages, which are not always clear for practicing engineers. Moreover, it is always interesting to study past field experience to confront theory with practice. This is what this paper proposes to do.\u0000 The paper will first review the limits of conventional HPAM and other polymers that have been proposed for more challenging reservoir conditions. But more than that, it will focus on the field experience with each of these products to establish some practical guidelines for the selection of polymers depending on the reservoir and fluid characteristics.\u0000 One first result of this review is that the limits of conventional HPAM may not be as low as usually expected. Biopolymers appear very sensitive to biodegradation and their success in the field has been limited. Associative polymers appear better suited to near-wellbore conformance control than to displacement processes and some of the new co and ter-polymers are currently being field tested with some measure of success. It appears that the main challenge lies with high temperature rather than high salinity; some field projects are currently ongoing in high salinity (200 g/L) and hardness.\u0000 The paper will help set the current limits for polymer flooding in terms of temperature, salinity and hardness based on laboratory work and field experience. This will prove a useful guide for practicing engineers looking to pilot polymer injection in challenging reservoir conditions.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"25 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88686542","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}
Ian Adrian Kartawijaya, Yoseph Menanti, Dhita Saraswaty, Singgih Suganda, Muhammad Iqbal, F. Anantokusumo, R. Dinata
Managing big gas well requires careful monitoring to ensure optimum wells production within their operating envelopes whilst continuously obtaining production data. Such data improves subsurface understanding over time and become a basis for optimization exercises, wellwork initiation, and quick corrective actions. Tangguh all-inclusive well surveillance integrates various daily data analysis into an efficient well surveillance process. It essentially looks for both early problem signs and improvement opportunities, enabling ahead anticipations. Tangguh real time surveillance allows continuous parameter monitoring: pressures, temperatures, choke opening, multiphase flowrates, sand detection, annuli pressures, and system backpressure. A semi-automatic system then integrates all available data quickly and allow engineers to perform meaningful analysis timely. The integration is a significant upgrade over the past surveillance practice, where typically more time spent on data gathering instead of the analysis; and missing anomalies that happened in unmonitored parameters while concentrating on a specific parameter. Combining with some non-routine data acquisitions, this well surveillance integration enables a quick and thorough well performance review and assists unlocking optimization opportunities. Three examples below demonstrate value creation from the integrated well surveillance. First example: combining real time well data and the non-routine acquisitions enable robust well productivity model construction. This has improved the understanding of each well productivity and operating limits, which upon evaluating lead to deliverability increases by simple well limits upgrade and debottlenecking projects. Other result includes assistance in defining restoration wellwork candidate. Second example: by continuous comparison between real time data and calculated performance model, the surveillance has shown its ability to detect well choke trim damage while flowing. This successfully prevented problem escalation into a more serious safety incident, such as gas release from an eroded choke valve. Third example: despite the challenges in accurate dry-gas-well liquid rate measurement, continuous water source identification is applied honoring the significant reserve it may impact, starting from routine salinity monitoring, theoretical condensed comparison against receiving facility figures, and material balance plots. All positively indicate no aquifer breakthrough yet so far.
{"title":"Value Creations through Tangguh Big Gas Well Daily Surveillance Integration Challenge","authors":"Ian Adrian Kartawijaya, Yoseph Menanti, Dhita Saraswaty, Singgih Suganda, Muhammad Iqbal, F. Anantokusumo, R. Dinata","doi":"10.2118/192008-ms","DOIUrl":"https://doi.org/10.2118/192008-ms","url":null,"abstract":"\u0000 Managing big gas well requires careful monitoring to ensure optimum wells production within their operating envelopes whilst continuously obtaining production data. Such data improves subsurface understanding over time and become a basis for optimization exercises, wellwork initiation, and quick corrective actions. Tangguh all-inclusive well surveillance integrates various daily data analysis into an efficient well surveillance process. It essentially looks for both early problem signs and improvement opportunities, enabling ahead anticipations.\u0000 Tangguh real time surveillance allows continuous parameter monitoring: pressures, temperatures, choke opening, multiphase flowrates, sand detection, annuli pressures, and system backpressure. A semi-automatic system then integrates all available data quickly and allow engineers to perform meaningful analysis timely. The integration is a significant upgrade over the past surveillance practice, where typically more time spent on data gathering instead of the analysis; and missing anomalies that happened in unmonitored parameters while concentrating on a specific parameter.\u0000 Combining with some non-routine data acquisitions, this well surveillance integration enables a quick and thorough well performance review and assists unlocking optimization opportunities. Three examples below demonstrate value creation from the integrated well surveillance.\u0000 First example: combining real time well data and the non-routine acquisitions enable robust well productivity model construction. This has improved the understanding of each well productivity and operating limits, which upon evaluating lead to deliverability increases by simple well limits upgrade and debottlenecking projects. Other result includes assistance in defining restoration wellwork candidate.\u0000 Second example: by continuous comparison between real time data and calculated performance model, the surveillance has shown its ability to detect well choke trim damage while flowing. This successfully prevented problem escalation into a more serious safety incident, such as gas release from an eroded choke valve.\u0000 Third example: despite the challenges in accurate dry-gas-well liquid rate measurement, continuous water source identification is applied honoring the significant reserve it may impact, starting from routine salinity monitoring, theoretical condensed comparison against receiving facility figures, and material balance plots. All positively indicate no aquifer breakthrough yet so far.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 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":"91010192","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}
Anandita Yadav, Animesh Kumar, V. Iyer, Tushar Ganjoo, Devesh Bhaisora
A lightweight cement solution was successfully applied in deepwater wells at depths greater than 1000 m and in production liners terminating in depleted reservoirs. These wells were drilled off the east coast of India. The fracture gradient prognosis for the depleted zones ranged from 11.0 to 11.28 lbm/gal. The measured depth (MD) of these wells was more than 4500 m (MDRT). Mud weights ranged from 10.9 to 11 lbm/gal in the well while drilling the zone. The length of the liner normally ranged from 1400 to 2300 m. The cement slurry was finalized after conducting numerous tests in the laboratory. A lead and tail combination was used for the job to maintain the required equivalent circulating density (ECD). In openhole completions, the casing or liner before the gravel pack should be landed in sand to establish having reached the reservoir top and to help ensure that no shale is present. Challenges for a successful liner job in these wells include landing in a depleted reservoir, which would enable a very low margin between the mud weight and fracture gradient. This margin is further reduced by the minimum horizontal stress mud weight requirement to help ensure that no hole collapse occurs while drilling and before cementing begins. In addition to the depleted zone, to maximize reservoir tapping, the well profiles are highly deviated, often reaching a well deviation of 80+ degrees, resulting in a high ECD during cementing. A long section of the cement column can create problems of cement channeling past the mud and mixing in the annulus. The correct prediction of pore pressure and fracture pressure for different sections is very important. Accurate knowledge of these values is recommended for a correct job design. Some of the lessons learned during the process to help ensure good zonal isolation include the following: An 11-lbm/gal lightweight lead slurry was formulated, keeping ECD and fluid rheology vs. strength development in mind. Solids loading was controlled to help ensure low friction factors (considering rheology) and to achieve a final compressive strength of 2,000 psi because it was a production casing.The length of the tail slurry column was maintained to a minimum to create minimal effect on the ECD, even though the hydrostatic pressure developed was marginal in a highly deviated section.A low-rheology/low-density synthetic oil-based mud (SOBM) (10 lbm/gal) was pumped ahead to reduce the ECD and to maintain the equivalent static density (ESD) above the pore pressure. In addition, the displacement rate was staggered to help maintain the ECDs.A high-viscosity pill was spotted at the 12 1/4-in. section total depth (TD) before the final pullout to act as a base for the cement slurry. This paper highlights the concerns and best practices developed when cementing production liners across depleted formations in deepwater wells.
{"title":"Cementing Production Liners Terminating in Depleted Reservoirs: A Case Study on Deepwater Wells off the East Coast of India","authors":"Anandita Yadav, Animesh Kumar, V. Iyer, Tushar Ganjoo, Devesh Bhaisora","doi":"10.2118/192104-MS","DOIUrl":"https://doi.org/10.2118/192104-MS","url":null,"abstract":"A lightweight cement solution was successfully applied in deepwater wells at depths greater than 1000 m and in production liners terminating in depleted reservoirs. These wells were drilled off the east coast of India. The fracture gradient prognosis for the depleted zones ranged from 11.0 to 11.28 lbm/gal. The measured depth (MD) of these wells was more than 4500 m (MDRT). Mud weights ranged from 10.9 to 11 lbm/gal in the well while drilling the zone. The length of the liner normally ranged from 1400 to 2300 m. The cement slurry was finalized after conducting numerous tests in the laboratory. A lead and tail combination was used for the job to maintain the required equivalent circulating density (ECD).\u0000 In openhole completions, the casing or liner before the gravel pack should be landed in sand to establish having reached the reservoir top and to help ensure that no shale is present. Challenges for a successful liner job in these wells include landing in a depleted reservoir, which would enable a very low margin between the mud weight and fracture gradient. This margin is further reduced by the minimum horizontal stress mud weight requirement to help ensure that no hole collapse occurs while drilling and before cementing begins. In addition to the depleted zone, to maximize reservoir tapping, the well profiles are highly deviated, often reaching a well deviation of 80+ degrees, resulting in a high ECD during cementing. A long section of the cement column can create problems of cement channeling past the mud and mixing in the annulus. The correct prediction of pore pressure and fracture pressure for different sections is very important. Accurate knowledge of these values is recommended for a correct job design.\u0000 Some of the lessons learned during the process to help ensure good zonal isolation include the following: An 11-lbm/gal lightweight lead slurry was formulated, keeping ECD and fluid rheology vs. strength development in mind. Solids loading was controlled to help ensure low friction factors (considering rheology) and to achieve a final compressive strength of 2,000 psi because it was a production casing.The length of the tail slurry column was maintained to a minimum to create minimal effect on the ECD, even though the hydrostatic pressure developed was marginal in a highly deviated section.A low-rheology/low-density synthetic oil-based mud (SOBM) (10 lbm/gal) was pumped ahead to reduce the ECD and to maintain the equivalent static density (ESD) above the pore pressure. In addition, the displacement rate was staggered to help maintain the ECDs.A high-viscosity pill was spotted at the 12 1/4-in. section total depth (TD) before the final pullout to act as a base for the cement slurry.\u0000 This paper highlights the concerns and best practices developed when cementing production liners across depleted formations in deepwater wells.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"164 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76869103","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}
Carbon intensity (CI) of oil and gas production varies widely across global oil plays. Life cycle extraction from certain unconventional plays (e.g., tar sands) have the highest CIs but even many North American shale plays have high CI. Flaring and venting of associated or non-associated natural gas dramatically increases CI. This paper applies peer-reviewed processes across broad averages of shale activity in North America and compares them with CI in countries in the Asia Pacific region. Ways to lower the carbon intensity in both areas are discussed. We perform well-to-refinery calculations of CI for major unconventional oil plays in North America and conventional plays in Asia Pacific. This approach accounts for emissions from exploration, drilling, production, processing, and transportation. The analysis tool is an open-source engineering-based model called Oil Production Greenhouse Gas Emissions Estimator (OPGEE). OPGEE makes estimates of emissions accounting using up to 50 parameters for each modeled field. This model was developed at Stanford University. Data sources include government sources, technical papers, satellite observations, and commercial databases. Applied globally, OPGEE estimates show highest values in areas with extensive flaring of natural gas and very heavy crude oils - heavy oils require large energy inputs (e.g., steam flooding) and/or the use of light hydrocarbon diluents for transportation offset. A few other major areas included for reference. Examples illustrate how OPGEE can be used to evaluate the CI of public policy actions. A sensitivity analysis to flaring volumes illustrates these impacts, and further sensitivity analyses to pad drilling and improving well performance show CI impacts associated with hydraulic fracturing. Unconventional production, especially from light tight oil is the most significant new source of fossil fuels in the last decade. Under a wide variety of carbon constraints, oil usage will continue for many decades and increase in the near term. Operators, governments, and regulators need to be able to avoid "locking in" development of suboptimal resources and instead provide incentives for shale operators to manage resources sustainably. This approach provides quantitative measures of such actions. Oil producers must prepare by eliminating development of marginal projects, elimination of flaring and venting, optimizing hydraulic fracture treatments, using improved recovery methods (e.g., enhanced oil recovery using anthropogenic CO2), reducing energy use, and eliminating unnecessary gas waste.
{"title":"Comparing Carbon Intensity of Unconventional and Asia Pacific Oil Production","authors":"D. Meehan, Hassan M. El-Houjeiri, J. Rutherford","doi":"10.2118/191921-MS","DOIUrl":"https://doi.org/10.2118/191921-MS","url":null,"abstract":"\u0000 Carbon intensity (CI) of oil and gas production varies widely across global oil plays. Life cycle extraction from certain unconventional plays (e.g., tar sands) have the highest CIs but even many North American shale plays have high CI. Flaring and venting of associated or non-associated natural gas dramatically increases CI. This paper applies peer-reviewed processes across broad averages of shale activity in North America and compares them with CI in countries in the Asia Pacific region. Ways to lower the carbon intensity in both areas are discussed.\u0000 We perform well-to-refinery calculations of CI for major unconventional oil plays in North America and conventional plays in Asia Pacific. This approach accounts for emissions from exploration, drilling, production, processing, and transportation. The analysis tool is an open-source engineering-based model called Oil Production Greenhouse Gas Emissions Estimator (OPGEE). OPGEE makes estimates of emissions accounting using up to 50 parameters for each modeled field. This model was developed at Stanford University. Data sources include government sources, technical papers, satellite observations, and commercial databases.\u0000 Applied globally, OPGEE estimates show highest values in areas with extensive flaring of natural gas and very heavy crude oils - heavy oils require large energy inputs (e.g., steam flooding) and/or the use of light hydrocarbon diluents for transportation offset. A few other major areas included for reference. Examples illustrate how OPGEE can be used to evaluate the CI of public policy actions. A sensitivity analysis to flaring volumes illustrates these impacts, and further sensitivity analyses to pad drilling and improving well performance show CI impacts associated with hydraulic fracturing.\u0000 Unconventional production, especially from light tight oil is the most significant new source of fossil fuels in the last decade. Under a wide variety of carbon constraints, oil usage will continue for many decades and increase in the near term. Operators, governments, and regulators need to be able to avoid \"locking in\" development of suboptimal resources and instead provide incentives for shale operators to manage resources sustainably. This approach provides quantitative measures of such actions. Oil producers must prepare by eliminating development of marginal projects, elimination of flaring and venting, optimizing hydraulic fracture treatments, using improved recovery methods (e.g., enhanced oil recovery using anthropogenic CO2), reducing energy use, and eliminating unnecessary gas waste.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"26 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83223875","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. Heikal, Mohamed El Banna, G. Mănescu, Mohammed Al Mulaifi, I. Mohammed
A major Operator in Kuwait have used historically Non-Aqueous Fluid (NAF) to drill the buildup section through the challenging shale formations, mainly due to wellbore stability issues and lubricity requirements. As part of the operator's environmental improvement strategy, the operator and fluids provider team identified potentially fit for purpose High Performance Water Base Mud (HPWBM) as the most suitable, environmentally acceptable alternative to NAF’s. A HPWBM system was designed and proposed based on extensive laboratory testing to overcome drilling challenges. Inhibition characteristics and formation sealing capabilities of conventional KCL polymer mud with sulphonated asphalt were enhanced by using a liquid polyamine based clay hydration suppressant and a co-polymeric nano-sized shale-sealing additive. A customized bridging package based on the pore size distribution was also introduced, using calcium carbonate and resilient graphite particles. The combination of effective bridging and sealing polymer helped in sustaining high overbalance to avoid differential sticking tendency, designed in laboratory conditions during the planning stage. The field trial was a great success compared to the use of conventional fluid systems and methodologies. Using High Performance Water Base Mud, the operator successfully drilled and cased 12.25" and 8.5" sections as per plan with stable wellbore indicated by the smooth trips and no string stalling or sticking tendency. Drilled 1077 feet of 12.25-in hole section crossing Ahmadi shale and 683 ft. of 8.5" section crossing troublesome Wara shale without any well-bore instability issues even at high inclination. Also, while drilling across depleted Mauddud limestone with 1800-psi overbalance, no differential sticking tendency observed. Both sections were completed in record 11 days, fastest comparing to offset wells drilled with NAF. In this paper, the authors will detail this novel approach of using an environmentally acceptable HPWBM system in the North Kuwait Basin, from planning to execution, which can be implemented further on the field and offers significant cost saving and reduces the risk of HSE issues related to Diesel based NAF systems.
{"title":"High-Performance Water-Base Fluid Performs As An Environmentally Friendly Alternative To Oil-Base for Drilling Challenging Intervals In North Kuwait","authors":"A. Heikal, Mohamed El Banna, G. Mănescu, Mohammed Al Mulaifi, I. Mohammed","doi":"10.2118/192050-MS","DOIUrl":"https://doi.org/10.2118/192050-MS","url":null,"abstract":"\u0000 \u0000 \u0000 A major Operator in Kuwait have used historically Non-Aqueous Fluid (NAF) to drill the buildup section through the challenging shale formations, mainly due to wellbore stability issues and lubricity requirements. As part of the operator's environmental improvement strategy, the operator and fluids provider team identified potentially fit for purpose High Performance Water Base Mud (HPWBM) as the most suitable, environmentally acceptable alternative to NAF’s.\u0000 \u0000 \u0000 \u0000 A HPWBM system was designed and proposed based on extensive laboratory testing to overcome drilling challenges. Inhibition characteristics and formation sealing capabilities of conventional KCL polymer mud with sulphonated asphalt were enhanced by using a liquid polyamine based clay hydration suppressant and a co-polymeric nano-sized shale-sealing additive. A customized bridging package based on the pore size distribution was also introduced, using calcium carbonate and resilient graphite particles. The combination of effective bridging and sealing polymer helped in sustaining high overbalance to avoid differential sticking tendency, designed in laboratory conditions during the planning stage.\u0000 \u0000 \u0000 \u0000 The field trial was a great success compared to the use of conventional fluid systems and methodologies. Using High Performance Water Base Mud, the operator successfully drilled and cased 12.25\" and 8.5\" sections as per plan with stable wellbore indicated by the smooth trips and no string stalling or sticking tendency. Drilled 1077 feet of 12.25-in hole section crossing Ahmadi shale and 683 ft. of 8.5\" section crossing troublesome Wara shale without any well-bore instability issues even at high inclination. Also, while drilling across depleted Mauddud limestone with 1800-psi overbalance, no differential sticking tendency observed. Both sections were completed in record 11 days, fastest comparing to offset wells drilled with NAF.\u0000 \u0000 \u0000 \u0000 In this paper, the authors will detail this novel approach of using an environmentally acceptable HPWBM system in the North Kuwait Basin, from planning to execution, which can be implemented further on the field and offers significant cost saving and reduces the risk of HSE issues related to Diesel based NAF systems.\u0000","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":"81170599","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The objective of this study was to examine the feasibility of improving the performance of EOR polymers by adding surface modified silica nanoparticles (NP). The nano-polymer sols were prepared by mixing different types of surface modified silica NP and hydrolyzed polyacrylamide (HPAM) or xanthan gum (XG) solutions. It is well known that the compatibility between organic polymer-inorganic oxide filler increases when the surface of the inorganic filler is chemically modified. To generate different interfacial interactions, the silica NP were treated by chemical grafting with carboxylic acids and silanes. The properties of the modified silica NP were characterized using Fourier transform infrared spectroscopy (FTIR) and the properties of the nano-polymer sols were investigated with viscometry and ζ-potential measurements. The non-Newtonian behavior of the nano-polymer sols was represented by Oswald-de Waele model. Areal sweep efficiency of viscous oil displacements by nano-polymer sols was measured at 25°C in a Hele-Shaw cell representing one-quarter of a five-spot pattern. The fingering patterns of all XG samples were characterized by the formation of branched structures (at earlier growth stage) which by merging and coalescing formed stable interfaces. It was the expected behavior considering the high shear-thinning strength of the XG polymer and nano-polymer sols (n values between 0.17 and 0.27). However, the HPAM solutions and nano-polymer sols exhibited different fingering patterns with tip-splitting or suppressed tip-splitting and side-branching. This difference was attributed to different interactions between the modified NP and the polymeric chains of the two polymers. The areal sweep efficiency of the HPAM polymer solutions did not improve by the addition of any type of NP because of the reduction of the viscosity of the polymer solution and the reduction of the interfacial tension between the injection fluid and oil. However, the XG polymer solutions, modified with the addition of 1.0 and 2.0 wt.% NP provided considerably improved sweep efficiency. The results are promising and show good potential for improving the performance of polymer flooding with Xanthan gum by addition of silica NP.
{"title":"Improving Polymer Flooding by Addition of Surface Modified Nanoparticles","authors":"L. M. Corredor, B. Maini, M. Husein","doi":"10.2118/192141-MS","DOIUrl":"https://doi.org/10.2118/192141-MS","url":null,"abstract":"\u0000 The objective of this study was to examine the feasibility of improving the performance of EOR polymers by adding surface modified silica nanoparticles (NP). The nano-polymer sols were prepared by mixing different types of surface modified silica NP and hydrolyzed polyacrylamide (HPAM) or xanthan gum (XG) solutions. It is well known that the compatibility between organic polymer-inorganic oxide filler increases when the surface of the inorganic filler is chemically modified. To generate different interfacial interactions, the silica NP were treated by chemical grafting with carboxylic acids and silanes. The properties of the modified silica NP were characterized using Fourier transform infrared spectroscopy (FTIR) and the properties of the nano-polymer sols were investigated with viscometry and ζ-potential measurements. The non-Newtonian behavior of the nano-polymer sols was represented by Oswald-de Waele model.\u0000 Areal sweep efficiency of viscous oil displacements by nano-polymer sols was measured at 25°C in a Hele-Shaw cell representing one-quarter of a five-spot pattern. The fingering patterns of all XG samples were characterized by the formation of branched structures (at earlier growth stage) which by merging and coalescing formed stable interfaces. It was the expected behavior considering the high shear-thinning strength of the XG polymer and nano-polymer sols (n values between 0.17 and 0.27). However, the HPAM solutions and nano-polymer sols exhibited different fingering patterns with tip-splitting or suppressed tip-splitting and side-branching. This difference was attributed to different interactions between the modified NP and the polymeric chains of the two polymers.\u0000 The areal sweep efficiency of the HPAM polymer solutions did not improve by the addition of any type of NP because of the reduction of the viscosity of the polymer solution and the reduction of the interfacial tension between the injection fluid and oil. However, the XG polymer solutions, modified with the addition of 1.0 and 2.0 wt.% NP provided considerably improved sweep efficiency. The results are promising and show good potential for improving the performance of polymer flooding with Xanthan gum by addition of silica NP.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81238333","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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