E. Delamaide, G. Batôt, Abdulaziz Alshaqsi, Abdullah Alkindy, Rifaat Al-Mejni
In Naturally Fractured Reservoirs (NFRs), production rate quickly drops once the oil in the fractures is produced. Indeed, high connectivity of the fracture network soon requires the application of IOR/EOR methods to unlock production from the low permeability matrix blocks which bear the major part of the oil in most carbonate-NFRs. This paper is intended as a thorough review of the EOR field tests in such reservoirs and discussion of the physical mechanisms at stakes. To the best of our knowledge there has never been any review dedicated to EOR methods specifically applied to NFRs. After a description of the main mechanisms involved in these processes this paper proposes to revisit the EOR field tests performed in carbonate-NFRs based on the following technologies: Gas injection, thermal- and solvent-assisted production, and finally chemical EOR, the latter being seen as a way to improve the kinetic of oil recovery from the matrix: foam, surfactant-polymer, low-salinity and hybrid processes, including a discussion of the remaining challenges to successfully apply these more recent technologies in the field. Beyond the fact that NFRs are quite interesting because of their complexity, they account for a large part of the world's oil proven reserves, approximatively 20%. Even though this value should be taken with caution, as it depends on the NFRs definitions and their characterizations, there are clearly significant amounts of oil trapped inside these reservoirs. For that reason, they are of great interest, both in terms of understanding and economical consideration for oil companies willing to get the most out of their fractured fields. Even when based on sound static and dynamic characterizations, production optimization of NFRs remains challenging: classical flooding mainly produces the oil contained in the fractures during the early stages of the field development. The high connectivity of the different levels of the fracture network along with the low permeability of the oil-bearing matrix blocks, combined with the often oil-wet nature of carbonate formations, are the three main factors at plays preventing the production of the remaining oil from the matrix blocks. Design of dedicated EOR solutions are needed and learning from past experiences through the review and analyze of the past field trials is of great value to that purpose. This review and discussion will allow engineers to get an extended and up to date understanding of the features and drawbacks of the main EOR methods which could be applied to NFRs, and also provide some guidance in the selection or design of the best suited EOR solution to a specific naturally fracture carbonate field.
{"title":"Enhanced Oil Recovery in Naturally Fractured Reservoirs: State of the Art and Future Perspectives","authors":"E. Delamaide, G. Batôt, Abdulaziz Alshaqsi, Abdullah Alkindy, Rifaat Al-Mejni","doi":"10.2118/200076-ms","DOIUrl":"https://doi.org/10.2118/200076-ms","url":null,"abstract":"\u0000 In Naturally Fractured Reservoirs (NFRs), production rate quickly drops once the oil in the fractures is produced. Indeed, high connectivity of the fracture network soon requires the application of IOR/EOR methods to unlock production from the low permeability matrix blocks which bear the major part of the oil in most carbonate-NFRs. This paper is intended as a thorough review of the EOR field tests in such reservoirs and discussion of the physical mechanisms at stakes.\u0000 To the best of our knowledge there has never been any review dedicated to EOR methods specifically applied to NFRs. After a description of the main mechanisms involved in these processes this paper proposes to revisit the EOR field tests performed in carbonate-NFRs based on the following technologies: Gas injection, thermal- and solvent-assisted production, and finally chemical EOR, the latter being seen as a way to improve the kinetic of oil recovery from the matrix: foam, surfactant-polymer, low-salinity and hybrid processes, including a discussion of the remaining challenges to successfully apply these more recent technologies in the field.\u0000 Beyond the fact that NFRs are quite interesting because of their complexity, they account for a large part of the world's oil proven reserves, approximatively 20%. Even though this value should be taken with caution, as it depends on the NFRs definitions and their characterizations, there are clearly significant amounts of oil trapped inside these reservoirs. For that reason, they are of great interest, both in terms of understanding and economical consideration for oil companies willing to get the most out of their fractured fields. Even when based on sound static and dynamic characterizations, production optimization of NFRs remains challenging: classical flooding mainly produces the oil contained in the fractures during the early stages of the field development. The high connectivity of the different levels of the fracture network along with the low permeability of the oil-bearing matrix blocks, combined with the often oil-wet nature of carbonate formations, are the three main factors at plays preventing the production of the remaining oil from the matrix blocks. Design of dedicated EOR solutions are needed and learning from past experiences through the review and analyze of the past field trials is of great value to that purpose.\u0000 This review and discussion will allow engineers to get an extended and up to date understanding of the features and drawbacks of the main EOR methods which could be applied to NFRs, and also provide some guidance in the selection or design of the best suited EOR solution to a specific naturally fracture carbonate field.","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 2022","volume":"113 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79386384","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}
Iron sulfide scale deposition in sour gas wells is a corrosion induced flow assurance issue. Corrosion inhibitor batch treatment is one of the techniques used to mitigate corrosion and iron sulfide deposition on downhole tubing. The objective of this study is to introduce the newly developed Downhole Corrosion and Scale Monitoring tool (DCSM) to evaluate the performance of batch treatment of corrosion inhibitor under real downhole conditions. An advanced DCSM tool has been designed and developed to monitor and evaluate the performance of the corrosion inhibitor batch treatment in a sour gas well under actual downhole environment and multiphase flow regime. The tool was retrieved after 3-5 months of exposure to the reservoir condition for post-laboratory analysis. The retrieved coupons were thoroughly characterized to assess the performance of corrosion batch treatment and to understand the mechanisms of corrosion and scaling. X-ray diffraction (XRD) was used to analyze the mineraological composition of the surface scale deposition. Scanning electron microscopy (SEM) and energy dispersive x-ray spectroscopy (EDS) analyses were performed to characterize the morphology and elemental analysis of the surface deposition. A surface profilometer was used to quantify the size/depth of the general or localized corrosion, as well as the surface deposition. To evaluate the performance of the corrosion inhibitor batch treatment, two sets of trial tests were conducted in a selected high-temperature sour gas well. One set of the coupons was retrieved after three-month exposure without corrosion inhibitor batch treatment; the other one was retrieved after five-month exposure with corrosion inhibitor batch treatment. The results showed that a very thin layered iron sulfide scale was formed on the surface of test coupons in both cases. General and localized pitting corrosion were found which indicates that corrosion happened first followed by scale layer deposition on metal coupon surface. Less harsh general and localized pitting corrosion were observed in the presence of corrosion inhibitor batch treatment. The corrosion inhibitor treatment did reduce the general corrosion and localized pitting corrosion under scale deposit at a certain level. The newly developed DCSM tool is an advanced design which allows direct corrosion and scaling monitoring for metal coupons under downhole conditions. Combined with post-laboratory analysis, it provides corrosion and scale mechanism, evaluation on the performance of mitigation, and proper corrosion and scale management programs to minimize corrosion and scale. The DSCM tool can also be deployed and applied in sweet gas wells, oil wells, and water supplier wells to monitor the corrosion and scale under real downhole conditions.
{"title":"Evaluation of Corrosion Inhibitor Batch Treatment Using Newly Developed Downhole Monitoring Tool in Sour Gas Wells","authors":"Tao Chen, Feng Liang, F. Chang, Amro Mukhles","doi":"10.2118/200161-ms","DOIUrl":"https://doi.org/10.2118/200161-ms","url":null,"abstract":"\u0000 Iron sulfide scale deposition in sour gas wells is a corrosion induced flow assurance issue. Corrosion inhibitor batch treatment is one of the techniques used to mitigate corrosion and iron sulfide deposition on downhole tubing. The objective of this study is to introduce the newly developed Downhole Corrosion and Scale Monitoring tool (DCSM) to evaluate the performance of batch treatment of corrosion inhibitor under real downhole conditions.\u0000 An advanced DCSM tool has been designed and developed to monitor and evaluate the performance of the corrosion inhibitor batch treatment in a sour gas well under actual downhole environment and multiphase flow regime. The tool was retrieved after 3-5 months of exposure to the reservoir condition for post-laboratory analysis. The retrieved coupons were thoroughly characterized to assess the performance of corrosion batch treatment and to understand the mechanisms of corrosion and scaling. X-ray diffraction (XRD) was used to analyze the mineraological composition of the surface scale deposition. Scanning electron microscopy (SEM) and energy dispersive x-ray spectroscopy (EDS) analyses were performed to characterize the morphology and elemental analysis of the surface deposition. A surface profilometer was used to quantify the size/depth of the general or localized corrosion, as well as the surface deposition.\u0000 To evaluate the performance of the corrosion inhibitor batch treatment, two sets of trial tests were conducted in a selected high-temperature sour gas well. One set of the coupons was retrieved after three-month exposure without corrosion inhibitor batch treatment; the other one was retrieved after five-month exposure with corrosion inhibitor batch treatment. The results showed that a very thin layered iron sulfide scale was formed on the surface of test coupons in both cases. General and localized pitting corrosion were found which indicates that corrosion happened first followed by scale layer deposition on metal coupon surface. Less harsh general and localized pitting corrosion were observed in the presence of corrosion inhibitor batch treatment. The corrosion inhibitor treatment did reduce the general corrosion and localized pitting corrosion under scale deposit at a certain level.\u0000 The newly developed DCSM tool is an advanced design which allows direct corrosion and scaling monitoring for metal coupons under downhole conditions. Combined with post-laboratory analysis, it provides corrosion and scale mechanism, evaluation on the performance of mitigation, and proper corrosion and scale management programs to minimize corrosion and scale. The DSCM tool can also be deployed and applied in sweet gas wells, oil wells, and water supplier wells to monitor the corrosion and scale under real downhole conditions.","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 2022","volume":"45 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79523254","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}
Deep tight gas fields in Northern Oman are often compared to and approached with unconventionals due to their tight matrix properties and the necessity of employing hydraulic fracturing to deliver productivity. Complicated by operational constraints and field histories, hydraulic fracture effectiveness – how fracture stimulation delivers relative to how much matrix flow contributes to production – remains a puzzle and a challenge. This further affects how to optimize existing completion and stimulation strategy in order to improve the value proposition. In this study, we review the fracture and production performance of a mature gas field in Northern Oman. Integrating data of various technical disciplines, we re-examine a wealth of cumulative field data over two decades of operations with an aim to identify the key enablers for fracture placement and production. With integration of reservoir properties, geomechanics, and time-lapse production profiles, we identify that geomechanics plays a key role in controlling reservoir fraccability and the placement of hydraulic fractures. While hydraulic fracture containment within the Barik formation has been well recognized and considered a given in multi-staged fractured vertical wells, the creation of fracture heights is found dependent on the in-situ stress conditions and pumping metrics, which further links to productivity. Such inter-relationship could potentially be utilized to optimize fracture performance by a refined placement strategy. With big data, the common technical opinions that normally arise from a deterministic approach on limited data can be better visualized and addressed. The statistical strength of the analysis leads to improved understanding of the subsurface complexity, interaction of reservoir quality with completion design, and a suite of future optimization opportunities.
{"title":"Conventional Tight Gas Field Through Unconventional Eyes: Data Analytics Help to Optimize Fracture Design and Operations","authors":"R. Yuan, Khalfan Bahri, C. Veeken, S. Shoaibi","doi":"10.2118/200138-ms","DOIUrl":"https://doi.org/10.2118/200138-ms","url":null,"abstract":"\u0000 Deep tight gas fields in Northern Oman are often compared to and approached with unconventionals due to their tight matrix properties and the necessity of employing hydraulic fracturing to deliver productivity. Complicated by operational constraints and field histories, hydraulic fracture effectiveness – how fracture stimulation delivers relative to how much matrix flow contributes to production – remains a puzzle and a challenge. This further affects how to optimize existing completion and stimulation strategy in order to improve the value proposition.\u0000 In this study, we review the fracture and production performance of a mature gas field in Northern Oman. Integrating data of various technical disciplines, we re-examine a wealth of cumulative field data over two decades of operations with an aim to identify the key enablers for fracture placement and production. With integration of reservoir properties, geomechanics, and time-lapse production profiles, we identify that geomechanics plays a key role in controlling reservoir fraccability and the placement of hydraulic fractures. While hydraulic fracture containment within the Barik formation has been well recognized and considered a given in multi-staged fractured vertical wells, the creation of fracture heights is found dependent on the in-situ stress conditions and pumping metrics, which further links to productivity. Such inter-relationship could potentially be utilized to optimize fracture performance by a refined placement strategy.\u0000 With big data, the common technical opinions that normally arise from a deterministic approach on limited data can be better visualized and addressed. The statistical strength of the analysis leads to improved understanding of the subsurface complexity, interaction of reservoir quality with completion design, and a suite of future optimization opportunities.","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 2022","volume":"97 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79027684","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
R. Mjeni, M. Gharbi, S. Lawati, S. Dickson, Abdul Rahman Ismaili, M. Hashmi, Ibrahim Amri, Khalid Belushi, R. Farajzadeh, G. Glasbergen, V. Karpan, A. Anand, Sander de Kruijf, B. Lomans, D. Wever
Efficient production of heavy oil from the reservoirs with strong bottom aquifer has proven to be a challenge. While providing enough energy to produce the field under the primary depletion, the strong bottom aquifer in combination with unfavorable oil/water mobility contrast leads to rapid development of water coning thereby limiting oil recovery. Drilling of long horizontal producing wells in the upper part of the oil column maximizes the distance from the aquifer and allows relatively high production rates. This slows down the water cone development and increases primary recovery. Even with further optimization of the primary production, the recovery factor remains relatively low and consequently application of Enhanced Oil Recovery (EOR) techniques is required to increase the recovery. Сrude oil from Nimr-E field is medium-heavy with the viscosity of 250-700cP under reservoir conditions. The field has been developed with mostly horizontal producing wells with relatively short inter-well distance. Due to strong bottom aquifer the reservoir pressure is maintained at the initial level despite the production under primary depletion. To increase the recovery factor polymer flooding was selected with expectation to increase the recovery by 5-10%. A field trial was conducted to understand the influence of polymer injection on oil recovery and address major uncertainties identified as key enablers for the full-field project. The pilot surveillance program, the surface facilities and the subsurface configurations were specifically designed to meet these objectives. The paper presents field data of polymer injection trial in Nimr field and focuses on the performance results and principal operational challenges. The injection of polymer resulted in the incremental oil production that was assessed using field data and simulations. A significant increase of initial oil production and clear watercut reversal due to polymer injection was observed and incremental recovery reached approximately 7% of the initial oil in place. Injectivity issues encountered in the pilot wells were mitigated by the techniques and chemicals developed to solve the issues. The results prove the subsurface and operational success of polymer field trial that leads the way to a commercial development.
{"title":"Nimr Polymer Project: the Results of Multi-Well Trial in the Medium-Heavy Oil Reservoir with Strong Bottom Aquifer","authors":"R. Mjeni, M. Gharbi, S. Lawati, S. Dickson, Abdul Rahman Ismaili, M. Hashmi, Ibrahim Amri, Khalid Belushi, R. Farajzadeh, G. Glasbergen, V. Karpan, A. Anand, Sander de Kruijf, B. Lomans, D. Wever","doi":"10.2118/200238-ms","DOIUrl":"https://doi.org/10.2118/200238-ms","url":null,"abstract":"\u0000 Efficient production of heavy oil from the reservoirs with strong bottom aquifer has proven to be a challenge. While providing enough energy to produce the field under the primary depletion, the strong bottom aquifer in combination with unfavorable oil/water mobility contrast leads to rapid development of water coning thereby limiting oil recovery. Drilling of long horizontal producing wells in the upper part of the oil column maximizes the distance from the aquifer and allows relatively high production rates. This slows down the water cone development and increases primary recovery. Even with further optimization of the primary production, the recovery factor remains relatively low and consequently application of Enhanced Oil Recovery (EOR) techniques is required to increase the recovery.\u0000 Сrude oil from Nimr-E field is medium-heavy with the viscosity of 250-700cP under reservoir conditions. The field has been developed with mostly horizontal producing wells with relatively short inter-well distance. Due to strong bottom aquifer the reservoir pressure is maintained at the initial level despite the production under primary depletion. To increase the recovery factor polymer flooding was selected with expectation to increase the recovery by 5-10%. A field trial was conducted to understand the influence of polymer injection on oil recovery and address major uncertainties identified as key enablers for the full-field project. The pilot surveillance program, the surface facilities and the subsurface configurations were specifically designed to meet these objectives.\u0000 The paper presents field data of polymer injection trial in Nimr field and focuses on the performance results and principal operational challenges. The injection of polymer resulted in the incremental oil production that was assessed using field data and simulations. A significant increase of initial oil production and clear watercut reversal due to polymer injection was observed and incremental recovery reached approximately 7% of the initial oil in place. Injectivity issues encountered in the pilot wells were mitigated by the techniques and chemicals developed to solve the issues. The results prove the subsurface and operational success of polymer field trial that leads the way to a commercial development.","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 2022","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76189240","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 paper presents the development of new surfactant formulations composed of various low-cost and low-performance surfactants to make them high performance products for high temperature and high salinity carbonate reservoirs. The objective of this study is to optimize the surfactant chemistry by mixing different kinds of surfactants (ionic, nonionic, and amphoteric), which results in significant synergistic effects in interfacial properties to improve oil production at the given harsh conditions. The optimal mixing surfactant ratios were determined according to the brine-surfactant compatibility, microemulsion phase behavior, and the interfacial tension (IFT) between oil and surfactant solutions in high salinity brine and at 90˚C. Comprehensive performance of the surfactants was evaluated, including adsorption of the surfactants onto the carbonate rocks and the long-term stability at 95˚C. The coreflooding displacement experiments were performed using carbonate core plugs at 95˚C to evaluate the potential of the optimal mixing surfactants in improving oil production. Three formulations composed of two types of low-cost surfactants were developed in this study. The mixing surfactants were chosen based on moderate electrostatic interaction among the surfactants. It appeared the synergistic effect between the mixing surfactants was enhanced with increasing temperature. Although the IFT of the individual surfactants with crude oil was in the range of 100mN/m, a significant IFT reduction in the magnitude of 10−2 - 10−3 mN/m was observed by mixing the surfactants. A salinity scan showed that the IFT values maintained a value of 10−2 mN/m in a wide salinity range, which demonstrated the robustness of the surfactants mixtures. In microemulsion phase behavior studies, these mixed surfactant solutions in the presence of crude oil exhibited Winsor Type III emulsions. The static adsorptions of the mixed surfactants were lower than the individual surfactant adsorption. All this indicated the feasibility of these formulations for their applications in the harsh reservoir conditions. The results of coreflooding displacement tests demonstrated significant oil production improvement beyond water flooding. This work provides an efficient way to get surfactant formulations by mixing low-performance and low cost surfactants to obtain high performance in improving oil production under the harsh conditions.
{"title":"New Synergistic Surfactant Mixtures for Improving Oil Production in Carbonate Reservoirs","authors":"Limin Xu, M. Han, D. Cao, A. Fuseni","doi":"10.2118/200182-ms","DOIUrl":"https://doi.org/10.2118/200182-ms","url":null,"abstract":"\u0000 The paper presents the development of new surfactant formulations composed of various low-cost and low-performance surfactants to make them high performance products for high temperature and high salinity carbonate reservoirs. The objective of this study is to optimize the surfactant chemistry by mixing different kinds of surfactants (ionic, nonionic, and amphoteric), which results in significant synergistic effects in interfacial properties to improve oil production at the given harsh conditions.\u0000 The optimal mixing surfactant ratios were determined according to the brine-surfactant compatibility, microemulsion phase behavior, and the interfacial tension (IFT) between oil and surfactant solutions in high salinity brine and at 90˚C. Comprehensive performance of the surfactants was evaluated, including adsorption of the surfactants onto the carbonate rocks and the long-term stability at 95˚C. The coreflooding displacement experiments were performed using carbonate core plugs at 95˚C to evaluate the potential of the optimal mixing surfactants in improving oil production.\u0000 Three formulations composed of two types of low-cost surfactants were developed in this study. The mixing surfactants were chosen based on moderate electrostatic interaction among the surfactants. It appeared the synergistic effect between the mixing surfactants was enhanced with increasing temperature. Although the IFT of the individual surfactants with crude oil was in the range of 100mN/m, a significant IFT reduction in the magnitude of 10−2 - 10−3 mN/m was observed by mixing the surfactants. A salinity scan showed that the IFT values maintained a value of 10−2 mN/m in a wide salinity range, which demonstrated the robustness of the surfactants mixtures. In microemulsion phase behavior studies, these mixed surfactant solutions in the presence of crude oil exhibited Winsor Type III emulsions. The static adsorptions of the mixed surfactants were lower than the individual surfactant adsorption. All this indicated the feasibility of these formulations for their applications in the harsh reservoir conditions. The results of coreflooding displacement tests demonstrated significant oil production improvement beyond water flooding.\u0000 This work provides an efficient way to get surfactant formulations by mixing low-performance and low cost surfactants to obtain high performance in improving oil production under the harsh conditions.","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 2022","volume":"201202 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77686287","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}
Ameera Harrasi, G. Urdaneta, A. Al-Jumah, M. Nasif, Hajir Qassabi
The multidisciplinary Authors summarize the lessons learned from stimulating a long horizontal Polymer Injection well with a Hoisting Unit; the main objective was to reduce the associated cost as compared to a Coiled Conventional Tubing (CCT) Unit, but achieving the same or even improved results. The details procedures for conducting this type of job is summarized in this paper. The well was completed with a smart completion, creating four distinguished zones, Earlier, bullheading approach was carried out, but later on when the smart completion failed, it was necessary to stimulate with a CCT to cover all the different zones in the long well section. This has caused a sharp increase in the price of the job. Hence, a trial has been carried out utilizing a Hoist, with improved acid recipe that is cheaper and better in performance as compared to earlier. The detailed procedure for conducting this type of job is summarized in this paper The tables show the injectivity test result in three stages, in the Hoist and the CCT approach the result shows a good improvement after main treatment and a success of the trial with Hoist as compared to CCT. This has proven to be economically viable and unlocked huge cost savings for all future stimulation jobs. A 50% reduction in the total cost is observed. This work has concluded a successful methodology in the utilization of a hoist in performing multi-stage stimulation in long horizontal wells. Very encouraging results have been observed and the suggested method is highly recommended, further trials will continue to be done with other wells The authors believe the learnings from these trials are of great benefit and will add to the state of knowledge of the industry relating to stimulating long horizontal wells
{"title":"Cheaper and More Effective Stimulation of Horizontal Polymer Injectors in South Sultanate of Oman","authors":"Ameera Harrasi, G. Urdaneta, A. Al-Jumah, M. Nasif, Hajir Qassabi","doi":"10.2118/200203-ms","DOIUrl":"https://doi.org/10.2118/200203-ms","url":null,"abstract":"\u0000 The multidisciplinary Authors summarize the lessons learned from stimulating a long horizontal Polymer Injection well with a Hoisting Unit; the main objective was to reduce the associated cost as compared to a Coiled Conventional Tubing (CCT) Unit, but achieving the same or even improved results. The details procedures for conducting this type of job is summarized in this paper.\u0000 The well was completed with a smart completion, creating four distinguished zones, Earlier, bullheading approach was carried out, but later on when the smart completion failed, it was necessary to stimulate with a CCT to cover all the different zones in the long well section. This has caused a sharp increase in the price of the job. Hence, a trial has been carried out utilizing a Hoist, with improved acid recipe that is cheaper and better in performance as compared to earlier. The detailed procedure for conducting this type of job is summarized in this paper\u0000 The tables show the injectivity test result in three stages, in the Hoist and the CCT approach the result shows a good improvement after main treatment and a success of the trial with Hoist as compared to CCT. This has proven to be economically viable and unlocked huge cost savings for all future stimulation jobs. A 50% reduction in the total cost is observed. This work has concluded a successful methodology in the utilization of a hoist in performing multi-stage stimulation in long horizontal wells. Very encouraging results have been observed and the suggested method is highly recommended, further trials will continue to be done with other wells\u0000 The authors believe the learnings from these trials are of great benefit and will add to the state of knowledge of the industry relating to stimulating long horizontal wells","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 2022","volume":"9 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88769925","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}
C. Marliere, V. Mirallés, C. Morgand, Virginie Rome, Aymerick Le Bris, Chloé Guilloteau, Tiphaine Courtaud, D. Rousseau
The objective of surfactant-polymer (SP) formulation design is to simultaneously achieve ultra-low interfacial tension and good mobility ratio. However, in some cases, the presence of both polymer and surfactant can cause compatibility issues leading to a cloudy or even demixing solution. Until now, those observations were made in bulk conditions but the assessment of this behavior has not been studied in confined and under flow conditions. Three SP compatibility cases were selected using the same SP formulation and playing on the brine salinity (low, medium and high). Bulk and kinetic studies based on solubility, viscosity and cryo-TEM were performed prior to monophasic injections carried out in a transparent micromodel representing a 2D rock porous medium and in a coreflood rig with a 3D outcrop rock. The observation in micromodel was performed using an optical microscope under polarized light to visualize the physical structure of the SP formulations. The pressure drop along the core was monitored during coreflood experiments to measure the mobility reduction entailed by the injected solution. In bulk conditions it is shown that increasing the solution salinity leads, after a few to several days depending on the solution's volume, to a degradation of the SP compatibility or even demixing. This behavior can be attributed to depletion effects. In this case, depletion is due to the formation of surfactant vesicles (hundreds of namometers in size) that tend to aggregate in the presence of polymer molecules. As expected, injection of the compatible SP solution (at low salinity) in the 2D porous medium micromodel and in the outcrop rock led to an easy in-depth transport, namely mobility reduction compatible with the viscosity of the solution. More interestingly, the same formulation at higher salinity exhibited a deposit of SP aggregates having a crystalline structure when injected in the micromodel. However, this formulation at high salinity did not show any issue in terms of mobility reduction when injected in the outcrop rock as the mobility reduction stabilized rapidly at a value close to the relative viscosity of the solution. These results highlight that the presence of a demixing phase does not always induce propagation issues in cores and that some cloudy SP solutions could be injected without causing any pressure increase. The objective of this study was to correlate the bulk behavior of SP formulations showing respectively good and poor compatibilities with their performance in confined and under flow conditions. It has been proved that a poor compatibility in bulk does not always induce transport issues when the solution is injected in porous medium, despite the deposit of structured aggregates in some pores.
{"title":"Surfactant-Polymer Compatibility in Bulk and Static Conditions vs. Confined and Under Flow Conditions","authors":"C. Marliere, V. Mirallés, C. Morgand, Virginie Rome, Aymerick Le Bris, Chloé Guilloteau, Tiphaine Courtaud, D. Rousseau","doi":"10.2118/200074-ms","DOIUrl":"https://doi.org/10.2118/200074-ms","url":null,"abstract":"\u0000 The objective of surfactant-polymer (SP) formulation design is to simultaneously achieve ultra-low interfacial tension and good mobility ratio. However, in some cases, the presence of both polymer and surfactant can cause compatibility issues leading to a cloudy or even demixing solution. Until now, those observations were made in bulk conditions but the assessment of this behavior has not been studied in confined and under flow conditions.\u0000 Three SP compatibility cases were selected using the same SP formulation and playing on the brine salinity (low, medium and high). Bulk and kinetic studies based on solubility, viscosity and cryo-TEM were performed prior to monophasic injections carried out in a transparent micromodel representing a 2D rock porous medium and in a coreflood rig with a 3D outcrop rock. The observation in micromodel was performed using an optical microscope under polarized light to visualize the physical structure of the SP formulations. The pressure drop along the core was monitored during coreflood experiments to measure the mobility reduction entailed by the injected solution.\u0000 In bulk conditions it is shown that increasing the solution salinity leads, after a few to several days depending on the solution's volume, to a degradation of the SP compatibility or even demixing. This behavior can be attributed to depletion effects. In this case, depletion is due to the formation of surfactant vesicles (hundreds of namometers in size) that tend to aggregate in the presence of polymer molecules.\u0000 As expected, injection of the compatible SP solution (at low salinity) in the 2D porous medium micromodel and in the outcrop rock led to an easy in-depth transport, namely mobility reduction compatible with the viscosity of the solution. More interestingly, the same formulation at higher salinity exhibited a deposit of SP aggregates having a crystalline structure when injected in the micromodel. However, this formulation at high salinity did not show any issue in terms of mobility reduction when injected in the outcrop rock as the mobility reduction stabilized rapidly at a value close to the relative viscosity of the solution. These results highlight that the presence of a demixing phase does not always induce propagation issues in cores and that some cloudy SP solutions could be injected without causing any pressure increase.\u0000 The objective of this study was to correlate the bulk behavior of SP formulations showing respectively good and poor compatibilities with their performance in confined and under flow conditions. It has been proved that a poor compatibility in bulk does not always induce transport issues when the solution is injected in porous medium, despite the deposit of structured aggregates in some pores.","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 2022","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82263862","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}
These are exciting times for unconventional resource development across North America. This success has proven to be a driver for the rest of the world to attempt to emulate the game-changing results found in the industry. As a consequence, improved horizontal drilling and hydraulic completion technology are currently being disseminated to the rest of the world, where operators are seeking to replicate the North American success in tight reservoirs and shale plays of interest. This being further fueled by higher gas prices than are awarded in North America. This paper introduces a work-flow process to describe how tight gas-sand potential was discovered in the Mezardere Formation in the southern part of the in Thrace Basin in NW Turkey. The process began with the development of an improved understanding of geology and reservoir characterization followed by the application of North American drilling and completion technologies to commercially extract hydrocarbons from previously uneconomic resources. Design of hydraulic fracturing, including pad volumes, proppant and gel concentrations, stage volumes and typical pressure profiles, production profiles and well design parameters are established. The content also presents how completion designs can be improved in a vertical well application in existing wellbores as a means to mitigate capital risk in a horizontal development plan. The paper concludes by showing how the successful extraction of commercial gas production from heretofore uneconomic portions of the Thrace basin has the potential to change the energy future in Turkey via dramatically improved production results over previous conventional completions. When results were made public, the basin garnered attention from many large E&P Operators. The results proved that improved economic enhancement of deep basin unconventional resources as possible; thereby changing and accelerating development plans for this type of play.
{"title":"An Iterative Approach to Enhance Frac Design and Economics While Developing Tight Gas Reservoirs","authors":"K. Yilmaz, Burc Umul, Moosa Madha","doi":"10.2118/200169-ms","DOIUrl":"https://doi.org/10.2118/200169-ms","url":null,"abstract":"\u0000 These are exciting times for unconventional resource development across North America. This success has proven to be a driver for the rest of the world to attempt to emulate the game-changing results found in the industry. As a consequence, improved horizontal drilling and hydraulic completion technology are currently being disseminated to the rest of the world, where operators are seeking to replicate the North American success in tight reservoirs and shale plays of interest. This being further fueled by higher gas prices than are awarded in North America.\u0000 This paper introduces a work-flow process to describe how tight gas-sand potential was discovered in the Mezardere Formation in the southern part of the in Thrace Basin in NW Turkey. The process began with the development of an improved understanding of geology and reservoir characterization followed by the application of North American drilling and completion technologies to commercially extract hydrocarbons from previously uneconomic resources.\u0000 Design of hydraulic fracturing, including pad volumes, proppant and gel concentrations, stage volumes and typical pressure profiles, production profiles and well design parameters are established. The content also presents how completion designs can be improved in a vertical well application in existing wellbores as a means to mitigate capital risk in a horizontal development plan.\u0000 The paper concludes by showing how the successful extraction of commercial gas production from heretofore uneconomic portions of the Thrace basin has the potential to change the energy future in Turkey via dramatically improved production results over previous conventional completions. When results were made public, the basin garnered attention from many large E&P Operators. The results proved that improved economic enhancement of deep basin unconventional resources as possible; thereby changing and accelerating development plans for this type of play.","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 2022","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74699150","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}
Engineering Asset Management(EAM) is management of engineering assets and it provides guidelines on the effective usage of all the physical engineered assets within the organization. Similarly, Non-Destructive Testing [NDT] is used as a handy tool for integrity assessment of Assets in scheduled maintenance & inspection program. Though Asset Inspection in Oil & Gas Industry were using conventional NDT methods, now ASME, API and others came up with inspection procedures based on fracture mechanics, where each user to ascertain how their tool/regional operating condition deviate from the assumptions herein, then employ their engineering and technical judgment in deciding how and when to employ any part of these standard. Till recent past, there were no regular validation for these procedures being performed as presumed; benchmark for Severity of failure in North Sea offshore and that in MENA Onshore are set as same. Integration of Operations Management System [OMS] based in Asset Inspection with the EAM allows the Asset Owner/Custodian to consistently monitor each Asset, Acquire monitoring / measurement data in common platform using standardized operating procedures, Measure / Analyze Longevity of each Asset and enable the end user to validate their Service Quality Plan and inspection procedures, as per applicable operating limits and risks. The purpose of this paper to emphasize the importance of optimizing the Asset utilization and serviceability to enhance overall efficiency by integrating; (1)EAM software that manages Assets, (2)OMS controlling the process and (3)Asset Inspection Management System[AIMS]. Case study refer our AIMS, a tool to track all Equipment data [Images, OEM/CoC Document, Inspection Reports/Certificates, track analysis of major attributes] through a single channel - Master Asset [Inspection] Register. Uniquely numbered Assets in each category Drilling Tubulars, Hosting &Handling Equipment and/or Lifting Equipment Item is captured in respective Master Asset Inspection Register with all related Equipment data & Inspection records. Inspection records provides all its inspection related history since its commissioning and manufacturing OEM/CoC Documents. Our cloud based AIMS-App's compliance to API Q2, ISO9001:2015 and ISO17020:2012 ensures its certifying requirements to, (1)relevant Industry standard and bench mark (2)Competence of Inspection Personnel and (3)Compliance of Measuring Devices & Equipment. In last two years [2016-2018] by ensuring Acceptance Benchmark only, more than 70% reduction in premature failure [Crack in Thread Connection; where 50% of those are potential NPT cases] in drilling Tools achieved. Our App provide the user to analyze Inspection data. The trend analysis of tools helps in its planning and utilization plus the data can be directly input to modify Service Quality Plan to optimizing the asset utilization & serviceability. The above are some of the immediate befit to Oil Company and Drilling Contra
{"title":"Asset Inspection Management System as a Reliable Inspection / Monitoring Tool to Optimize the Asset Utilization & Serviceability and to Enhance Overall Efficiency of Service Provision","authors":"Shibu John","doi":"10.2118/200288-ms","DOIUrl":"https://doi.org/10.2118/200288-ms","url":null,"abstract":"\u0000 Engineering Asset Management(EAM) is management of engineering assets and it provides guidelines on the effective usage of all the physical engineered assets within the organization. Similarly, Non-Destructive Testing [NDT] is used as a handy tool for integrity assessment of Assets in scheduled maintenance & inspection program. Though Asset Inspection in Oil & Gas Industry were using conventional NDT methods, now ASME, API and others came up with inspection procedures based on fracture mechanics, where each user to ascertain how their tool/regional operating condition deviate from the assumptions herein, then employ their engineering and technical judgment in deciding how and when to employ any part of these standard. Till recent past, there were no regular validation for these procedures being performed as presumed; benchmark for Severity of failure in North Sea offshore and that in MENA Onshore are set as same. Integration of Operations Management System [OMS] based in Asset Inspection with the EAM allows the Asset Owner/Custodian to consistently monitor each Asset, Acquire monitoring / measurement data in common platform using standardized operating procedures, Measure / Analyze Longevity of each Asset and enable the end user to validate their Service Quality Plan and inspection procedures, as per applicable operating limits and risks.\u0000 The purpose of this paper to emphasize the importance of optimizing the Asset utilization and serviceability to enhance overall efficiency by integrating; (1)EAM software that manages Assets, (2)OMS controlling the process and (3)Asset Inspection Management System[AIMS]. Case study refer our AIMS, a tool to track all Equipment data [Images, OEM/CoC Document, Inspection Reports/Certificates, track analysis of major attributes] through a single channel - Master Asset [Inspection] Register. Uniquely numbered Assets in each category Drilling Tubulars, Hosting &Handling Equipment and/or Lifting Equipment Item is captured in respective Master Asset Inspection Register with all related Equipment data & Inspection records. Inspection records provides all its inspection related history since its commissioning and manufacturing OEM/CoC Documents. Our cloud based AIMS-App's compliance to API Q2, ISO9001:2015 and ISO17020:2012 ensures its certifying requirements to, (1)relevant Industry standard and bench mark (2)Competence of Inspection Personnel and (3)Compliance of Measuring Devices & Equipment.\u0000 In last two years [2016-2018] by ensuring Acceptance Benchmark only, more than 70% reduction in premature failure [Crack in Thread Connection; where 50% of those are potential NPT cases] in drilling Tools achieved. Our App provide the user to analyze Inspection data. The trend analysis of tools helps in its planning and utilization plus the data can be directly input to modify Service Quality Plan to optimizing the asset utilization & serviceability. The above are some of the immediate befit to Oil Company and Drilling Contra","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 2022","volume":"28 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75485206","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}
Mohammed Al-Aamri, Ahmed M. AL-Kindi, Y. Terras, H. Ajmi, Saud Khaldi, D. Govind Rao, S. Perumalla, A. Shinde, T. Lhomme, C. Germay
This paper focuses on the case study of the geomechanical evaluation of a tight gas reservoir in Oman. Rock strength was characterized using data inputs/measurements with the objective to reduce uncertainty on predictions of wellbore stability in four deep gas wells. As a primary input for many standard geomechanical models, rock strength parameter is routinely measured on rock samples using triaxial/uniaxial tests. This parameter is traditionally named as Uniaxial Compressive Strength (UCS) measured during the axial loading and crushing of cylindrical "core plugs" extracted from cores. Although considered as a standard for rock strength evaluation, this method has some limitations such as (i) sample destruction, (ii) natural bias in weak formations (iii) natural dispersion, (iv) discretization of the measurement along sampled intervals and (v) sample preparation challenges. The scratch test has been developed as a rapid and cost effective rock strength testing method addressing these limitations. The relative advantages of the scratch test as an alternative to standard rock strength testing are discussed and its added value demonstrated in the context of practical applications for a tight gas reservoir. Geomechanical data was acquired from four different wells with the following measurements: (i) Acoustic wireline log, (ii) Uniaxial compressive strength resulting from laboratory tests on plug samples, (iii) a continuous high-resolution strength profile interpreted from scratch tests performed on whole cores. Then, the data from all these sources has been integrated following a dedicated workflow designed to reduce the uncertainty in the output of strength models from wireline logs, through careful handling of data resolution differences and heterogeneity mapping. Encouraging correlations between core-based measurements and scratch test suggests that the scratch test has emerged as a valid alternative to standard rock mechanical tests in suitable situations. Robust statistics are provided for strength and explanations are proposed for outlier values from tests on plug samples. Furthermore, the continuity and the high resolution of the strength profile enables a much better calibration of strength proxies from acoustic wireline logs. Finally, the scratch test yield values from shale intervals that were traditionally overlooked by plug site selections for rock mechanical testing. The strength assessment protocol from the scratch test handles rock heterogeneity with a much larger data set than conventional rock strength testing methods. This enables more robust core property-log calibration at different length scales. Such continuous high resolution profiles of rock properties leads to a significant reduction in uncertainty in petrophysical and geomechanics models, and better decision making in well design and field management.
{"title":"Using Continuous Core Measurements to Reduce the Uncertainty on Rock Strength vis-à-vis Geomechanical Modeling in a Tight Gas Reservoir in Sultanate of Oman","authors":"Mohammed Al-Aamri, Ahmed M. AL-Kindi, Y. Terras, H. Ajmi, Saud Khaldi, D. Govind Rao, S. Perumalla, A. Shinde, T. Lhomme, C. Germay","doi":"10.2118/200217-ms","DOIUrl":"https://doi.org/10.2118/200217-ms","url":null,"abstract":"\u0000 This paper focuses on the case study of the geomechanical evaluation of a tight gas reservoir in Oman. Rock strength was characterized using data inputs/measurements with the objective to reduce uncertainty on predictions of wellbore stability in four deep gas wells. As a primary input for many standard geomechanical models, rock strength parameter is routinely measured on rock samples using triaxial/uniaxial tests. This parameter is traditionally named as Uniaxial Compressive Strength (UCS) measured during the axial loading and crushing of cylindrical \"core plugs\" extracted from cores. Although considered as a standard for rock strength evaluation, this method has some limitations such as (i) sample destruction, (ii) natural bias in weak formations (iii) natural dispersion, (iv) discretization of the measurement along sampled intervals and (v) sample preparation challenges.\u0000 The scratch test has been developed as a rapid and cost effective rock strength testing method addressing these limitations. The relative advantages of the scratch test as an alternative to standard rock strength testing are discussed and its added value demonstrated in the context of practical applications for a tight gas reservoir. Geomechanical data was acquired from four different wells with the following measurements: (i) Acoustic wireline log, (ii) Uniaxial compressive strength resulting from laboratory tests on plug samples, (iii) a continuous high-resolution strength profile interpreted from scratch tests performed on whole cores. Then, the data from all these sources has been integrated following a dedicated workflow designed to reduce the uncertainty in the output of strength models from wireline logs, through careful handling of data resolution differences and heterogeneity mapping.\u0000 Encouraging correlations between core-based measurements and scratch test suggests that the scratch test has emerged as a valid alternative to standard rock mechanical tests in suitable situations. Robust statistics are provided for strength and explanations are proposed for outlier values from tests on plug samples. Furthermore, the continuity and the high resolution of the strength profile enables a much better calibration of strength proxies from acoustic wireline logs. Finally, the scratch test yield values from shale intervals that were traditionally overlooked by plug site selections for rock mechanical testing.\u0000 The strength assessment protocol from the scratch test handles rock heterogeneity with a much larger data set than conventional rock strength testing methods. This enables more robust core property-log calibration at different length scales. Such continuous high resolution profiles of rock properties leads to a significant reduction in uncertainty in petrophysical and geomechanics models, and better decision making in well design and field management.","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 2022","volume":"26 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75532333","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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