D. Kalinin, D. Choo, Ashley Watling, Hai Liu, L. K. Teng, Gog Soo Hui
A system for reducing solids production in Surat basin coal seam gas (CSG) wells was developed in the laboratory and tested in the laboratory and field trials. Several thousand CSG wells were completed in Surat basin in eastern Australia using what was considered an economic method at a time - an open hole with a predrilled liner. Although the majority of the wells are meeting production expectations, a many wells are producing a substantial amount of solids originating from an interburden rock representing approximately 90% of completed interval length and comprising mudstones, sandstones, and siltstones rich in illite/smectite and other water-sensitive clays. Relatively fresh water, with total dissolved solids (TDS) of approximately 4000 to 7000 mg/l, produced from multiple thin coal seams during dewatering and production phases is causing the interburden rock to swell or disintegrate. Prolific wells with high water rates or high gas velocity are capable of carrying solids to the surface where the solids are deposited in separators, flowlines, and water-treatment settling ponds. Higher solids concentration on lower-rate wells are causing issues with positive cavity pumps (PCP), the artificial lift method of choice in CSG wells. Pump intake plugging with solids, excessive torque and rotation seizure, and wear of tubing/rod strings are frequent causes of workovers and shorter-than-expected pump run-life. Some wells are able to flow freely; however, an extra monitoring program is required to ensure wellheads are not suffering from solids-induced erosion. Recompletion of the wells is not considered practical at this stage because pre-perforated joints form an integral part of the 5 ½-in. or 7-in. casing string, which is cemented above the Walloons subgroup coal seams. An external casing packer (ECP) is often used. Some coal seams were underreamed, thus further complicating recompletion. Plugging existing wells and drilling a pair of wells using same surface location and infrastructure have been considered. A chemical wellbore stabilization solution been developed to alleviate/stop solids production from the interburden rock. The treatment comprises two fluids separated by a spacer that contains clay stabilizer that is typically 3 to 7% KCl, the same as drilling mud base. Proprietary surfactant reduces the possibility of coal damage. Regained permeability testing performed using crushed and sieved coal pack plugs indicated a low level of damage. The wellbore stabilization system could be energized/foamed to reduce hydrostatic pressure and increase compressibility, hence increasing the chance of contacting rock surface in an enlarged wellbore.
{"title":"Alleviating the Solids Issue in Surat Basin CSG Wells","authors":"D. Kalinin, D. Choo, Ashley Watling, Hai Liu, L. K. Teng, Gog Soo Hui","doi":"10.2118/191923-MS","DOIUrl":"https://doi.org/10.2118/191923-MS","url":null,"abstract":"\u0000 A system for reducing solids production in Surat basin coal seam gas (CSG) wells was developed in the laboratory and tested in the laboratory and field trials.\u0000 Several thousand CSG wells were completed in Surat basin in eastern Australia using what was considered an economic method at a time - an open hole with a predrilled liner.\u0000 Although the majority of the wells are meeting production expectations, a many wells are producing a substantial amount of solids originating from an interburden rock representing approximately 90% of completed interval length and comprising mudstones, sandstones, and siltstones rich in illite/smectite and other water-sensitive clays. Relatively fresh water, with total dissolved solids (TDS) of approximately 4000 to 7000 mg/l, produced from multiple thin coal seams during dewatering and production phases is causing the interburden rock to swell or disintegrate. Prolific wells with high water rates or high gas velocity are capable of carrying solids to the surface where the solids are deposited in separators, flowlines, and water-treatment settling ponds. Higher solids concentration on lower-rate wells are causing issues with positive cavity pumps (PCP), the artificial lift method of choice in CSG wells. Pump intake plugging with solids, excessive torque and rotation seizure, and wear of tubing/rod strings are frequent causes of workovers and shorter-than-expected pump run-life. Some wells are able to flow freely; however, an extra monitoring program is required to ensure wellheads are not suffering from solids-induced erosion.\u0000 Recompletion of the wells is not considered practical at this stage because pre-perforated joints form an integral part of the 5 ½-in. or 7-in. casing string, which is cemented above the Walloons subgroup coal seams. An external casing packer (ECP) is often used. Some coal seams were underreamed, thus further complicating recompletion. Plugging existing wells and drilling a pair of wells using same surface location and infrastructure have been considered.\u0000 A chemical wellbore stabilization solution been developed to alleviate/stop solids production from the interburden rock. The treatment comprises two fluids separated by a spacer that contains clay stabilizer that is typically 3 to 7% KCl, the same as drilling mud base. Proprietary surfactant reduces the possibility of coal damage. Regained permeability testing performed using crushed and sieved coal pack plugs indicated a low level of damage. The wellbore stabilization system could be energized/foamed to reduce hydrostatic pressure and increase compressibility, hence increasing the chance of contacting rock surface in an enlarged wellbore.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"132 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88799808","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}
Amirul Adha Bin Amsidom, Elsayed Ouda Ghonim, Euan Alexander, K. Kuswanto, Bakhtiyor Abdullaev, H. Hassan, M. F. Ishak, Benny Rajah, Puvethra Nair Gunasegaran, Kamal Ayad, B. Madon, M. A. Hamzah, Kautsar Zamanuri
About 80% of brownfields in Malaysia use Gas Lift as the artificial lift method. Though it is widely used, the operators are facing numerous challenges which include shortages in gas lift source and compressor reliability issues. Consequently fields’ productivity is impacted and results in higher operating expenditure. A case of change from Gas Lift to ESP was studied however due to high rig costs many of these the projects are uneconomic. Given this is the case PETRONAS had been researching the use of high speed slim, power- cable deployed ESPs for installation inside 2- 7/8" and 3-1/2" tubing (TTESP-CD). The challenge was to develop a deployment method using intervention techniques to comply with process safety requirements and installation over a live well without any workover rig. The associated technologies to enable deployment and operation of the ESP were identified, modified, developed and qualified as required in order to meet API 6A, API 14A and ISO 14310. In order to meet the project objectives and derisk technical uncertainties, an onshore test run and offshore pilot were planned. These ensured the design requirements of the key deployment technologies met relevant API and ISO standards; 1) wellhead adapter for cable exit and load handling 2) the anti-rotation anchor packer and 3) the insert safety valve, 4) wireline unit, 5) pressure control equipment. Each of the technologies developed or modified are key components of the deployment technique. Through the onshore testing, the deployment procedure and running equipment were improvised to fit the offshore pilot installation. The deployment of the TTESP-CD system offshore was a success; the ESP was installed within 3-1/2" 9.2ppf tubing to a depth of 1752ft over a live well using the modified deployment package. The actual ESP deployment took around 5days including rig up/down of the deployment package. Running the ESP to depth only took around 8hrs including setting the insert safety valve. Major time consuming events were assembling the ESP, cable space- out, cable termination/splice, landing hanger and cleaning out the electrical connections. Looking forward; this is a technology PETRONAS see great value in for Malaysian and international assets. Currently there are plans for four more installations in 2018 and a minimum of five installations in 2019. The PETRONAS led team have overcome challenges the industry has faced for many years with regards to this type of ESP deployment by investing in R&D and committing resources. By developing this technology PETRONAS and its technology providers have officially opened up market for low cost ESP deployment which is a significant step change to conventional practice. This will be of great benefit to the upstream oil and gas industry, particularly for offshore assets with little infrastructure.
{"title":"Truly Rigless: A World First Through 3-1/2\" Tubing Cable Deployed Electrical Submersible Pump on a Live Well","authors":"Amirul Adha Bin Amsidom, Elsayed Ouda Ghonim, Euan Alexander, K. Kuswanto, Bakhtiyor Abdullaev, H. Hassan, M. F. Ishak, Benny Rajah, Puvethra Nair Gunasegaran, Kamal Ayad, B. Madon, M. A. Hamzah, Kautsar Zamanuri","doi":"10.2118/192100-MS","DOIUrl":"https://doi.org/10.2118/192100-MS","url":null,"abstract":"\u0000 About 80% of brownfields in Malaysia use Gas Lift as the artificial lift method. Though it is widely used, the operators are facing numerous challenges which include shortages in gas lift source and compressor reliability issues. Consequently fields’ productivity is impacted and results in higher operating expenditure. A case of change from Gas Lift to ESP was studied however due to high rig costs many of these the projects are uneconomic. Given this is the case PETRONAS had been researching the use of high speed slim, power- cable deployed ESPs for installation inside 2- 7/8\" and 3-1/2\" tubing (TTESP-CD). The challenge was to develop a deployment method using intervention techniques to comply with process safety requirements and installation over a live well without any workover rig. The associated technologies to enable deployment and operation of the ESP were identified, modified, developed and qualified as required in order to meet API 6A, API 14A and ISO 14310.\u0000 In order to meet the project objectives and derisk technical uncertainties, an onshore test run and offshore pilot were planned. These ensured the design requirements of the key deployment technologies met relevant API and ISO standards; 1) wellhead adapter for cable exit and load handling 2) the anti-rotation anchor packer and 3) the insert safety valve, 4) wireline unit, 5) pressure control equipment. Each of the technologies developed or modified are key components of the deployment technique. Through the onshore testing, the deployment procedure and running equipment were improvised to fit the offshore pilot installation.\u0000 The deployment of the TTESP-CD system offshore was a success; the ESP was installed within 3-1/2\" 9.2ppf tubing to a depth of 1752ft over a live well using the modified deployment package. The actual ESP deployment took around 5days including rig up/down of the deployment package. Running the ESP to depth only took around 8hrs including setting the insert safety valve. Major time consuming events were assembling the ESP, cable space- out, cable termination/splice, landing hanger and cleaning out the electrical connections. Looking forward; this is a technology PETRONAS see great value in for Malaysian and international assets. Currently there are plans for four more installations in 2018 and a minimum of five installations in 2019.\u0000 The PETRONAS led team have overcome challenges the industry has faced for many years with regards to this type of ESP deployment by investing in R&D and committing resources. By developing this technology PETRONAS and its technology providers have officially opened up market for low cost ESP deployment which is a significant step change to conventional practice. This will be of great benefit to the upstream oil and gas industry, particularly for offshore assets with little infrastructure.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"28 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87598539","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}
Ankesh Nagar, G. Dangwal, N. Pandey, Akanksha Jain, A. Parasher, Mayur Deshpande, Vaibhav Gupta, K. Pande
Increasing water cut in oil-producing zones is a common issue faced by operators, particularly for mature fields. Currently, where most of the decisions are governed by economics, incurring additional expenses with activities such as handling produced water becomes extremely undesirable. Depending upon the nature of the zone, one effective solution to this issue is chemical isolation. This paper undertakes this issue, discussing a case study of a successful zonal isolation operation using an organically crosslinked polymer sealant in a fractured zone with a gravel pack and screen completion for a reservoir with a subhydrostatic nature. This zone was an initial oil producer in FM-01 sand of the Mangala onshore oil field and had been stimulated in 2011 with a fracture-pack completion. The zone was completed with screens and a gravel pack with 16/30-mesh sand and 5.5-in. screens across the producing interval. During a period of time, the zone (FM-01) began to produce a significant amount of water, resulting in excessive water cut. To mitigate the issue, it was decided to completely isolate the zone using an organically crosslinked polymer system as a porosity fill sealant. When prepared in the appropriate concentration, subject to reservoir temperature, this low-viscosity formulation (40 to 80 cp) turns into a permanent rigid gel with time. The particular challenges of this operation were the presence of high permeability streaks because of stimulation by hydraulic fracturing, extra pore space because the perforated interval lay within the gravel-packed screens, and the subhydrostatic nature of the reservoir. Extensive laboratory testing was performed to optimize the formulation at the desired temperature, measuring the time necessary for the viscosity to begin increasing and the minimum total time necessary to form a rigid gel. The case study discussed in this paper features the successful application of the treatment using the spot-and-squeeze method with coiled tubing (CT) for the isolation of the zone. After allowing the setting time, pressure tests were performed, indicating positive isolation of the zone. After the pressure test, a jet pump was installed, and a drawdown was created to flow the zone. It was observed that production post operation was almost 95% less than production before operation at the same pressure drawdown, indicating approximately 100% zone isolation.
{"title":"Zonal Isolation of a Fractured and Gravel Packed Water Producing Zone using an Organically Crosslinked Polymer Sealant: Case Study","authors":"Ankesh Nagar, G. Dangwal, N. Pandey, Akanksha Jain, A. Parasher, Mayur Deshpande, Vaibhav Gupta, K. Pande","doi":"10.2118/191972-MS","DOIUrl":"https://doi.org/10.2118/191972-MS","url":null,"abstract":"\u0000 Increasing water cut in oil-producing zones is a common issue faced by operators, particularly for mature fields. Currently, where most of the decisions are governed by economics, incurring additional expenses with activities such as handling produced water becomes extremely undesirable. Depending upon the nature of the zone, one effective solution to this issue is chemical isolation. This paper undertakes this issue, discussing a case study of a successful zonal isolation operation using an organically crosslinked polymer sealant in a fractured zone with a gravel pack and screen completion for a reservoir with a subhydrostatic nature.\u0000 This zone was an initial oil producer in FM-01 sand of the Mangala onshore oil field and had been stimulated in 2011 with a fracture-pack completion. The zone was completed with screens and a gravel pack with 16/30-mesh sand and 5.5-in. screens across the producing interval. During a period of time, the zone (FM-01) began to produce a significant amount of water, resulting in excessive water cut. To mitigate the issue, it was decided to completely isolate the zone using an organically crosslinked polymer system as a porosity fill sealant. When prepared in the appropriate concentration, subject to reservoir temperature, this low-viscosity formulation (40 to 80 cp) turns into a permanent rigid gel with time. The particular challenges of this operation were the presence of high permeability streaks because of stimulation by hydraulic fracturing, extra pore space because the perforated interval lay within the gravel-packed screens, and the subhydrostatic nature of the reservoir. Extensive laboratory testing was performed to optimize the formulation at the desired temperature, measuring the time necessary for the viscosity to begin increasing and the minimum total time necessary to form a rigid gel.\u0000 The case study discussed in this paper features the successful application of the treatment using the spot-and-squeeze method with coiled tubing (CT) for the isolation of the zone. After allowing the setting time, pressure tests were performed, indicating positive isolation of the zone. After the pressure test, a jet pump was installed, and a drawdown was created to flow the zone. It was observed that production post operation was almost 95% less than production before operation at the same pressure drawdown, indicating approximately 100% zone isolation.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"77 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88114484","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}
Xi Zhang, Bisheng Wu, L. Connell, Yanhui Han, R. Jeffrey
In this paper, a fracture mechanics model that deals with fracture growth in layered low-permeability rocks is presented and applied to hydraulic fracturing stimulation of coal seam gas reservoirs. The model uses the conventional pseudo-3D treatment by which the vertically planar fracture is divided into cells along the horizontal direction. For each cell, the fracture deformation is represented by a 2D plane-strain fracture. To ensure numerical stability, the model uses an optimization method based on the fluid volume increase of each cell and the solutions for each cell can be obtained in parallel when using a computer with multiple CPU cores. The method was verified based on the comparisons with existing solutions and the computational speed can be significantly increased by using parallel computing. Numerical examples are presented to illustrate cases that result in fracture geometrical complexities caused by material properties contrasts between the thin softer coal seams and the adjacent stiffer rocks. The local horizontal stresses in each layer are calculated based on the layer-independent uniform horizontal strain assumption. The overburden stress is given. The fracture length and opening in the coal can be larger than other layers if the coal is subject to a smaller stress. This will promote growth of the fracture plane to include coal seams that do not receive injected fluid at the wellbore. The well developed fracture opening in the coal can be impeded by an increase in the confining stress of the coal. The fracturing produces wide propped channels below the coal seam in the low stress rock that exists there. These conductive channels allow flow of gas and water to the wellbore. The stress uncertainty is considered and interestingly the injection pressure trends are insensitive to the variation of local stresses. There is a process that favors growth in the softer coal seams for all cases, which yields a slight and progressive increase in the injection pressure.
{"title":"Hydraulic Fracturing Treatment of Low-Permeability Coal Seam Gas Reservoirs with Finely Layered Coals","authors":"Xi Zhang, Bisheng Wu, L. Connell, Yanhui Han, R. Jeffrey","doi":"10.2118/192017-MS","DOIUrl":"https://doi.org/10.2118/192017-MS","url":null,"abstract":"\u0000 In this paper, a fracture mechanics model that deals with fracture growth in layered low-permeability rocks is presented and applied to hydraulic fracturing stimulation of coal seam gas reservoirs. The model uses the conventional pseudo-3D treatment by which the vertically planar fracture is divided into cells along the horizontal direction. For each cell, the fracture deformation is represented by a 2D plane-strain fracture. To ensure numerical stability, the model uses an optimization method based on the fluid volume increase of each cell and the solutions for each cell can be obtained in parallel when using a computer with multiple CPU cores. The method was verified based on the comparisons with existing solutions and the computational speed can be significantly increased by using parallel computing. Numerical examples are presented to illustrate cases that result in fracture geometrical complexities caused by material properties contrasts between the thin softer coal seams and the adjacent stiffer rocks. The local horizontal stresses in each layer are calculated based on the layer-independent uniform horizontal strain assumption. The overburden stress is given. The fracture length and opening in the coal can be larger than other layers if the coal is subject to a smaller stress. This will promote growth of the fracture plane to include coal seams that do not receive injected fluid at the wellbore. The well developed fracture opening in the coal can be impeded by an increase in the confining stress of the coal. The fracturing produces wide propped channels below the coal seam in the low stress rock that exists there. These conductive channels allow flow of gas and water to the wellbore. The stress uncertainty is considered and interestingly the injection pressure trends are insensitive to the variation of local stresses. There is a process that favors growth in the softer coal seams for all cases, which yields a slight and progressive increase in the injection pressure.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88133754","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}
Fazeli Tehrani Fatemeh, Langbauer Clemens, H. Herbert
In this paper, a state-of-the-art wire rope is chosen for investigation regarding its applicability as a sucker rod string. Finite element simulation with Abaqus has been used for a detailed analysis of the rope's performance and possible failures along with its length. The sucker rod string is a key component of sucker rod pumps, transferring the reciprocating movement of the surface polished rod to the downhole pump plunger. It is, however, exposed to severe cyclic loads, causing several complications from damaged rods and broken couplings to time-consuming workover procedures. Hence, continuous strings like wire ropes can be a convenient replacement for the conventional design. The mechanical properties of the introduced wire rope demonstrate high tensile strength and great resistance against creep and fatigue while its uniform design eliminates the chances of connection failure. The proposed wire rope was designed to work in tandem with a sucker rod anti-buckling pump (SRABS) to facilitate its motion. The performance of this system was then simulated using a combination of MATLAB and Python codes, visualized in the interface of Abaqus. These simulations confirm that this wire rope can indeed replace the rod string in a sucker rod pumping unit. Detailed stress, load, and movement profiles were also compiled to allow for a comprehensive analysis. The results pointed out that pumping with a wire rope can be just as productive, or surpass the productivity of a system using conventional sucker rods. They indicate that the efficiency of this design highly depends on the geometry and depth of the well, type, and size of the pump, the compressibility of the produced fluid and string material elasticity. The optimization of the wire rope's performance could be achieved by using compatible Pumpjacks and proper downhole equipment, such as string protectors, all operating together under an optimum pumping speed. This paper presents a noteworthy comparison between the performance of a conventional rod string and a wire rope at two reference wells. Laboratory and field tests are being planned to investigate the full capacity of the rope.
{"title":"Behavior Analysis of a Wire Rope Replacing Sucker Rods with Finite Element Simulation","authors":"Fazeli Tehrani Fatemeh, Langbauer Clemens, H. Herbert","doi":"10.2118/191894-MS","DOIUrl":"https://doi.org/10.2118/191894-MS","url":null,"abstract":"\u0000 In this paper, a state-of-the-art wire rope is chosen for investigation regarding its applicability as a sucker rod string. Finite element simulation with Abaqus has been used for a detailed analysis of the rope's performance and possible failures along with its length.\u0000 The sucker rod string is a key component of sucker rod pumps, transferring the reciprocating movement of the surface polished rod to the downhole pump plunger. It is, however, exposed to severe cyclic loads, causing several complications from damaged rods and broken couplings to time-consuming workover procedures. Hence, continuous strings like wire ropes can be a convenient replacement for the conventional design. The mechanical properties of the introduced wire rope demonstrate high tensile strength and great resistance against creep and fatigue while its uniform design eliminates the chances of connection failure.\u0000 The proposed wire rope was designed to work in tandem with a sucker rod anti-buckling pump (SRABS) to facilitate its motion. The performance of this system was then simulated using a combination of MATLAB and Python codes, visualized in the interface of Abaqus. These simulations confirm that this wire rope can indeed replace the rod string in a sucker rod pumping unit. Detailed stress, load, and movement profiles were also compiled to allow for a comprehensive analysis. The results pointed out that pumping with a wire rope can be just as productive, or surpass the productivity of a system using conventional sucker rods. They indicate that the efficiency of this design highly depends on the geometry and depth of the well, type, and size of the pump, the compressibility of the produced fluid and string material elasticity. The optimization of the wire rope's performance could be achieved by using compatible Pumpjacks and proper downhole equipment, such as string protectors, all operating together under an optimum pumping speed.\u0000 This paper presents a noteworthy comparison between the performance of a conventional rod string and a wire rope at two reference wells. Laboratory and field tests are being planned to investigate the full capacity of the rope.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"123 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77571465","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}
Hongyan Yu, Xiaolong Wei, Zhenliang Wang, R. Rezaee, Yihuai Zhang, M. Lebedev, S. Iglauer
The gas content in shale reservoir is of great importance in reservoir evaluation. Shale reservoir has various gas including free gas, adsorpted gas and soluted gas. Free gas take an important part for the total gas content. Hence, we investigated three equations for water saturation calculating and compared and improved them based on theoretical analysis in order to find a siutable one for the shale reservoir characterization. The results indicate that the Archie formula has several limitations applied to complex pore structure, which leads to high water saturation. Since the Archie formula was proposed by experimental data in pure sandstone without enough consideration about the clay of shale reservoir. The Waxman-Smits is suitable to shale gas reservoirs through theoretical analysis, but there are several uncertain parameters. The conductivity of formation water is necessary parameter in calculation of formation water saturation, but calculating the conductivity of formation water is difficult in shale gas reservoir because of its intricate characterization of pore structure and conductivity. Waxman-Smits model take account for the clay conductivity, but there are several uncertain parameters which are hard to obtained, resuting high error. For instance, the equivalent conductivity of exchange cations (B) and the capacitance of exchange anions (Qv) can not be defined accurately relied on experimental calculation, which causes indefinite influence on results. Thus, we concluded that selecting the improved Indonesia equation is a better method to calculate water saturation. This study provided a comprehensive analysis and an accurate way for water satruartion evaluation in shale reservoir.
{"title":"Review of Water Saturation Calculation Methods in Shale Gas Reservoir","authors":"Hongyan Yu, Xiaolong Wei, Zhenliang Wang, R. Rezaee, Yihuai Zhang, M. Lebedev, S. Iglauer","doi":"10.2118/192115-MS","DOIUrl":"https://doi.org/10.2118/192115-MS","url":null,"abstract":"\u0000 The gas content in shale reservoir is of great importance in reservoir evaluation. Shale reservoir has various gas including free gas, adsorpted gas and soluted gas. Free gas take an important part for the total gas content. Hence, we investigated three equations for water saturation calculating and compared and improved them based on theoretical analysis in order to find a siutable one for the shale reservoir characterization. The results indicate that the Archie formula has several limitations applied to complex pore structure, which leads to high water saturation. Since the Archie formula was proposed by experimental data in pure sandstone without enough consideration about the clay of shale reservoir. The Waxman-Smits is suitable to shale gas reservoirs through theoretical analysis, but there are several uncertain parameters. The conductivity of formation water is necessary parameter in calculation of formation water saturation, but calculating the conductivity of formation water is difficult in shale gas reservoir because of its intricate characterization of pore structure and conductivity. Waxman-Smits model take account for the clay conductivity, but there are several uncertain parameters which are hard to obtained, resuting high error. For instance, the equivalent conductivity of exchange cations (B) and the capacitance of exchange anions (Qv) can not be defined accurately relied on experimental calculation, which causes indefinite influence on results. Thus, we concluded that selecting the improved Indonesia equation is a better method to calculate water saturation. This study provided a comprehensive analysis and an accurate way for water satruartion evaluation in shale reservoir.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77655808","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}
Xuejun Lin, G. Sutherland, D. Cumming, B. Thomas, A. Sani
A Coal Seam Gas Field, operated by Origin Energy as upstream operator of the APLNG project in Queensland, Australia has been on commercial production since 2005. From inception to 2012 the development concept used vertical cavitated wells or vertical fracture stimulated wells. Four pilot surface to in-seam well pairs were successfully drilled and commissioned in 2012 and 2013. Based on the performance of these pilots, further development of the coal seam gas field converted from stimulated vertical wells to horizontal wells from 2015 onwards. Surface-in-seam (SIS), high-angle-sump-horizontals (HASH), and multi-laterals wells drilled with coil tubing technologies were implemented in the field. The paper describes horizontal wells drilling, completion and geo-steering technology. The optimal operational strategies of horizontal wells are also described and the production performance of horizontal wells are compared to the vertical well performance. The key factors contributing to the success of horizontal drilling in the field are presented.
{"title":"Increasing Coal Seam Gas Field Productivity with Horizontal Well Technology: A Case Study","authors":"Xuejun Lin, G. Sutherland, D. Cumming, B. Thomas, A. Sani","doi":"10.2118/192114-MS","DOIUrl":"https://doi.org/10.2118/192114-MS","url":null,"abstract":"\u0000 A Coal Seam Gas Field, operated by Origin Energy as upstream operator of the APLNG project in Queensland, Australia has been on commercial production since 2005. From inception to 2012 the development concept used vertical cavitated wells or vertical fracture stimulated wells. Four pilot surface to in-seam well pairs were successfully drilled and commissioned in 2012 and 2013. Based on the performance of these pilots, further development of the coal seam gas field converted from stimulated vertical wells to horizontal wells from 2015 onwards. Surface-in-seam (SIS), high-angle-sump-horizontals (HASH), and multi-laterals wells drilled with coil tubing technologies were implemented in the field. The paper describes horizontal wells drilling, completion and geo-steering technology. The optimal operational strategies of horizontal wells are also described and the production performance of horizontal wells are compared to the vertical well performance. The key factors contributing to the success of horizontal drilling in the field are presented.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75572440","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}
B. Styward, R. Wijaya, D. Manalu, F. Wahyudhi, T. Setiawan, Albert Malvin Richal Dading, M. Rizal, T. Widarena, Geraldie Lukman, I. Primasari, Putu Astari Merati, Rizka Hezmela, M. Fuad, C. Nwafor, Liu Hai, Pratyush Singh
Pertamina Hulu Energi operates numerous wells that produce gas from unconsolidated, tight sands in the Mahakam Delta. The company maintains a zero-sand production policy as its surface facilities are not designed to handle sand. If sand is produced, the wells are choked back, thus impairing the overall field production. To fix sand and fines in place, the primary sand control method used has been multizone single-trip gravel packing, sometimes in conjunction with sand consolidation or ceramic screen for noneconomic zones. However, the current state of the Tunu shallow portfolio renders sand consolidation infeasible, as more than 50% of the remaining reservoirs are either low-stakes (i.e. not economical) or are located in low-permeability zones. Against this backdrop, sand conglomeration is being considered as an alternative solution to produce the remaining reservoirs. A trial has been conducted to assess the feasibility of using sand conglomeration technology as an alternative to sand consolidation in the Mahakam Delta, the results of which will be reviewed in this paper.
Pertamina Hulu Energi公司在Mahakam三角洲运营着许多从松散致密砂岩中开采天然气的井。该公司坚持零出砂政策，因为其地面设施不是为处理砂而设计的。如果出砂，井就会堵塞，从而影响整个油田的产量。为了将砂石和细砂固定到位，主要的防砂方法是多层单趟砾石充填，有时在非经济层使用固砂或陶瓷筛管。然而，目前Tunu浅层组合的现状使得砂体固结不可行，因为超过50%的剩余储层要么是低风险(即不经济)，要么位于低渗透层。在这种背景下，砂团被认为是开采剩余储层的另一种解决方案。已经进行了一项试验，以评估在马哈坎三角洲使用砂团技术作为砂固结的替代方案的可行性，本文将对其结果进行审查。
{"title":"Sand Conglomeration Trial as an Alternative to Sand Control: Case Study from Mahakam Delta, Indonesia","authors":"B. Styward, R. Wijaya, D. Manalu, F. Wahyudhi, T. Setiawan, Albert Malvin Richal Dading, M. Rizal, T. Widarena, Geraldie Lukman, I. Primasari, Putu Astari Merati, Rizka Hezmela, M. Fuad, C. Nwafor, Liu Hai, Pratyush Singh","doi":"10.2118/191987-MS","DOIUrl":"https://doi.org/10.2118/191987-MS","url":null,"abstract":"\u0000 Pertamina Hulu Energi operates numerous wells that produce gas from unconsolidated, tight sands in the Mahakam Delta. The company maintains a zero-sand production policy as its surface facilities are not designed to handle sand. If sand is produced, the wells are choked back, thus impairing the overall field production. To fix sand and fines in place, the primary sand control method used has been multizone single-trip gravel packing, sometimes in conjunction with sand consolidation or ceramic screen for noneconomic zones. However, the current state of the Tunu shallow portfolio renders sand consolidation infeasible, as more than 50% of the remaining reservoirs are either low-stakes (i.e. not economical) or are located in low-permeability zones. Against this backdrop, sand conglomeration is being considered as an alternative solution to produce the remaining reservoirs. A trial has been conducted to assess the feasibility of using sand conglomeration technology as an alternative to sand consolidation in the Mahakam Delta, the results of which will be reviewed in this paper.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"3 3 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78849663","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 Australian coal seam gas (CSG)/coal bed methane (CBM) fields present multiple challenges (i.e., losses, naturally fractured formations, and highly depleted zones) typically addressed using various well design and cementing techniques (i.e., additional casing strings, stage cementers/tools, lost-circulation materials, lightweight designs, and additional cement volume) to manage the potential risk of losses. Foamed cement is a viable option to address these challenges; however, despite the documented benefits, its application within Australia has been minimal at best. The lack of application can be primarily attributed to misconceptions concerning cost, potential risk, excessive equipment footprint, and a limited proven track record, which increases the potential risk of execution. A recent 10-well campaign conducted within the Bowen Basin, Queensland, Australia, demonstrated that foamed cement can be used as an alternative to traditional lightweight and/or elastomeric cement slurries. Further, the benefits of foamed cement make it an economically and technically advantageous solution compared to conventional cementing techniques used to overcome CSG challenges. This case study details the campaign challenges, cement design, and detailed results of the 10 wells with the intention of providing other engineers a road map to better understand foamed cementing with a specific Australian context and how it could be applied to their projects.
{"title":"Foam Cementing in Australian Coal Seam Gas Operations","authors":"T. Saunders, A. Shaban, Mohammad Zaman","doi":"10.2118/191892-MS","DOIUrl":"https://doi.org/10.2118/191892-MS","url":null,"abstract":"\u0000 The Australian coal seam gas (CSG)/coal bed methane (CBM) fields present multiple challenges (i.e., losses, naturally fractured formations, and highly depleted zones) typically addressed using various well design and cementing techniques (i.e., additional casing strings, stage cementers/tools, lost-circulation materials, lightweight designs, and additional cement volume) to manage the potential risk of losses.\u0000 Foamed cement is a viable option to address these challenges; however, despite the documented benefits, its application within Australia has been minimal at best. The lack of application can be primarily attributed to misconceptions concerning cost, potential risk, excessive equipment footprint, and a limited proven track record, which increases the potential risk of execution.\u0000 A recent 10-well campaign conducted within the Bowen Basin, Queensland, Australia, demonstrated that foamed cement can be used as an alternative to traditional lightweight and/or elastomeric cement slurries. Further, the benefits of foamed cement make it an economically and technically advantageous solution compared to conventional cementing techniques used to overcome CSG challenges.\u0000 This case study details the campaign challenges, cement design, and detailed results of the 10 wells with the intention of providing other engineers a road map to better understand foamed cementing with a specific Australian context and how it could be applied to their projects.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 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":"77210947","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}
Qinghua Wang, Liu Yonghui, Junzheng Yang, M. Cui, Dan Qi
For Electrical Submersible Pump (ESP) systems in high-GLR wells, presence of gas inside ESP results in the degradation of hydraulic head. As a remedial tool to improve the ability of handling gas-liquid mixtures, Downhole Gas Separator (DGS) is of crucial importance. However, conventional DGS has limited capability in separating free gas and a maximum separating efficiency of 45%. It can't meet the field applications to a wider range of flow conditions and different pump models. Therefore, the paper proposed a solution to improve gas handling ability of DGS to expand its application. Combining centrifugal separation method and gravity separation method, three-annular design was proposed to address the problem of two-stage separator with fairly long length. In the new design, a device is used to accelerate the fluid for higher velocity flowing into the annular between the spiral outer pipe and the central pipe. Then, the helical blades in the annular separate the gas-liquid mixture, leading gas attaching on the out wall of the central pipe and subsequently discharge into casing through the vent holes. The liquid attached on the inner wall of the spiral outer pipe flows reversal because of gravity. Afterwards, liquid is forced into the central pipe through the drainage holes and then flow into the ESP. In order to improve separating efficiency, the structure of helical blades, including distance and number of thread for centrifugal separator was then optimized by numerical simulation. In addition, an experimental study was conducted in different GLR and deviation. The experimental results show separating efficiency ranges between 88% and 96% while the conventional is under 60%. Furthermore, the separation efficiency decreases with the increasing of deviation, and maximum deviation of the new separator can be applied is 50°[1]. The novel DGS provide an economic solution for ESP application in gassy reservoir with low cost and power; since the new design greatly shorten the length of traditional two-stage separator.
{"title":"A Novel Downhole Gas Separator in ESP Systems","authors":"Qinghua Wang, Liu Yonghui, Junzheng Yang, M. Cui, Dan Qi","doi":"10.2118/192028-MS","DOIUrl":"https://doi.org/10.2118/192028-MS","url":null,"abstract":"\u0000 For Electrical Submersible Pump (ESP) systems in high-GLR wells, presence of gas inside ESP results in the degradation of hydraulic head. As a remedial tool to improve the ability of handling gas-liquid mixtures, Downhole Gas Separator (DGS) is of crucial importance. However, conventional DGS has limited capability in separating free gas and a maximum separating efficiency of 45%. It can't meet the field applications to a wider range of flow conditions and different pump models. Therefore, the paper proposed a solution to improve gas handling ability of DGS to expand its application.\u0000 Combining centrifugal separation method and gravity separation method, three-annular design was proposed to address the problem of two-stage separator with fairly long length. In the new design, a device is used to accelerate the fluid for higher velocity flowing into the annular between the spiral outer pipe and the central pipe. Then, the helical blades in the annular separate the gas-liquid mixture, leading gas attaching on the out wall of the central pipe and subsequently discharge into casing through the vent holes. The liquid attached on the inner wall of the spiral outer pipe flows reversal because of gravity. Afterwards, liquid is forced into the central pipe through the drainage holes and then flow into the ESP. In order to improve separating efficiency, the structure of helical blades, including distance and number of thread for centrifugal separator was then optimized by numerical simulation. In addition, an experimental study was conducted in different GLR and deviation. The experimental results show separating efficiency ranges between 88% and 96% while the conventional is under 60%. Furthermore, the separation efficiency decreases with the increasing of deviation, and maximum deviation of the new separator can be applied is 50°[1].\u0000 The novel DGS provide an economic solution for ESP application in gassy reservoir with low cost and power; since the new design greatly shorten the length of traditional two-stage separator.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88503088","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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