Valsan Vevakanandan, A. Ting, Tingting Zhang, F. Maula, Aqil Ahmad, G. Santoso, K. Alang
K field is a faulted anticline structure lying in a turbidite environmental setting, which consists of two main sand bodies of 50-100ft gross thickness. Two main challenges during development stages were, 1). The narrow thickness of the fault block requiring accurate landing, well placement and characterization. 2). The low vertical permeability inside the sand which requires the straddling and precision of horizontal placement relative to reservoir boundary. Geosteering was proposed to mitigate those challenges, which is then translated into a directional drilling plan. Hybrid LWD combination of Seismic, Reservoir Mapping, RT-Image and Formation Pressure While Drilling technology were used overcome those objectives and challenges. Seismic was used to update target uncertainty in both depth and lateral coordinates, hence accurate landing inside the target fault block was the main driver. Reservoir Mapping Technology and borehole images were used to update the presence of fault and plan for an accurate placement of the horizontal section. Pressure While Drilling was used to update the reservoir pressure and fault/ connectivity between fault/compartments. Post job subsurface modeling was updated using those measurement for accurate interpretation, which was used for future field development plan. The drilling workflow was extensively discussed among the stakeholders to make sure it was fit for purpose and could achieve the objectives. Horizontal well landing procedures using Seismic While Drilling technology helped the well penetrate into fault block A at 100m before fault edge. Reservoir Mapping While Drilling technology enabled successful Geosteering inside the desired target zone. Another important application regarding the Reservoir Mapping Technology is the capability of resolving the internal sedimentary bedding feature (higher dip feature) and the delineating of multiple faults including sub seismic fault block B, which helped the team define well TD at the desired fault block position. An integrated interpretation between Reservoir Mapping While Drilling, High Resolution Images and Formation Pressure While Drilling to detect pressure continuity between one block to the other proved to be very helpful for production management and completion optimization. At the end, two horizontal wells were successfully drilled in the desired fault block. Everything worked, ie the technology, the people and the process, resulting in an accurate and well controlled execution of a complex and high-profile project. The novel approach was successfully demonstrated to ensure well objectives are achieved in an integrated manner. The flawless execution allowed the team to avpid drilling any side tracks which would have been costly.
{"title":"Assesing Well Placement in Multi Faulted Reservoir","authors":"Valsan Vevakanandan, A. Ting, Tingting Zhang, F. Maula, Aqil Ahmad, G. Santoso, K. Alang","doi":"10.2118/191938-MS","DOIUrl":"https://doi.org/10.2118/191938-MS","url":null,"abstract":"\u0000 K field is a faulted anticline structure lying in a turbidite environmental setting, which consists of two main sand bodies of 50-100ft gross thickness. Two main challenges during development stages were, 1). The narrow thickness of the fault block requiring accurate landing, well placement and characterization. 2). The low vertical permeability inside the sand which requires the straddling and precision of horizontal placement relative to reservoir boundary. Geosteering was proposed to mitigate those challenges, which is then translated into a directional drilling plan. Hybrid LWD combination of Seismic, Reservoir Mapping, RT-Image and Formation Pressure While Drilling technology were used overcome those objectives and challenges. Seismic was used to update target uncertainty in both depth and lateral coordinates, hence accurate landing inside the target fault block was the main driver. Reservoir Mapping Technology and borehole images were used to update the presence of fault and plan for an accurate placement of the horizontal section. Pressure While Drilling was used to update the reservoir pressure and fault/ connectivity between fault/compartments. Post job subsurface modeling was updated using those measurement for accurate interpretation, which was used for future field development plan.\u0000 The drilling workflow was extensively discussed among the stakeholders to make sure it was fit for purpose and could achieve the objectives. Horizontal well landing procedures using Seismic While Drilling technology helped the well penetrate into fault block A at 100m before fault edge. Reservoir Mapping While Drilling technology enabled successful Geosteering inside the desired target zone. Another important application regarding the Reservoir Mapping Technology is the capability of resolving the internal sedimentary bedding feature (higher dip feature) and the delineating of multiple faults including sub seismic fault block B, which helped the team define well TD at the desired fault block position. An integrated interpretation between Reservoir Mapping While Drilling, High Resolution Images and Formation Pressure While Drilling to detect pressure continuity between one block to the other proved to be very helpful for production management and completion optimization. At the end, two horizontal wells were successfully drilled in the desired fault block. Everything worked, ie the technology, the people and the process, resulting in an accurate and well controlled execution of a complex and high-profile project.\u0000 The novel approach was successfully demonstrated to ensure well objectives are achieved in an integrated manner. The flawless execution allowed the team to avpid drilling any side tracks which would have been costly.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"35 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79084665","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}
Zheng Tong, Bing Ma, Ran Wei, Chenglong Liao, Shun Liu, Peng Huang, Xinzhong Wang
Operator planned to develop the new low-permeable sandstone gas reservoir below the mature gas layer in Ordos basin. In terms of cost reduction the wellbore was designed to pass through the undeveloped resource locating in the upper mature reservoir to obtain dual-zone commingled production. According to the well logging, there was the indication of hole collapse, enlargement and an unforseen water bearing zone found in the deviated section locating in upper zone. Packers could fail in the irregular deviated wellbore. Upon the modification of completion solution, the 4 1/2in open-hole packer-sleeve (OHPS) completion and fracturing system was deployed to treat the lower target zone. Top cementing operation using novel stage collar with swellable elements was performed to isolate the upper mature zone. "Plug and Perf" (PnP) via compact bridge plugs was carried out to enable efficient fracturing in deviated wellbore. The single-trip OHPS system employed water-swellable packers (WSPs) with corrugated packing element. The WSP and compact bridge plug were successfully evaluated by bench test. In one gas well, the operator performed cementing job and the stage collar was opened by wiper plug once the tripping of the OHPS completion with five packers was made successfully. Three bridge plugs were pumped down to the target depth. Hydraulic fracturing operation was sequentially made with all packers and bridge plugs effectively set. It is shown from the field operation that the hybrid completion is able to meet the requirements of completion and stimulation in irregular wellbore with abnormal conditions for tight reservoirs.
{"title":"The Hybrid Completion and Stimulation Technology Combining Sleeves with Bridge Plugs: A Case History in Ordos Basin, China","authors":"Zheng Tong, Bing Ma, Ran Wei, Chenglong Liao, Shun Liu, Peng Huang, Xinzhong Wang","doi":"10.2118/191945-MS","DOIUrl":"https://doi.org/10.2118/191945-MS","url":null,"abstract":"\u0000 Operator planned to develop the new low-permeable sandstone gas reservoir below the mature gas layer in Ordos basin. In terms of cost reduction the wellbore was designed to pass through the undeveloped resource locating in the upper mature reservoir to obtain dual-zone commingled production. According to the well logging, there was the indication of hole collapse, enlargement and an unforseen water bearing zone found in the deviated section locating in upper zone. Packers could fail in the irregular deviated wellbore.\u0000 Upon the modification of completion solution, the 4 1/2in open-hole packer-sleeve (OHPS) completion and fracturing system was deployed to treat the lower target zone. Top cementing operation using novel stage collar with swellable elements was performed to isolate the upper mature zone. \"Plug and Perf\" (PnP) via compact bridge plugs was carried out to enable efficient fracturing in deviated wellbore. The single-trip OHPS system employed water-swellable packers (WSPs) with corrugated packing element.\u0000 The WSP and compact bridge plug were successfully evaluated by bench test. In one gas well, the operator performed cementing job and the stage collar was opened by wiper plug once the tripping of the OHPS completion with five packers was made successfully. Three bridge plugs were pumped down to the target depth. Hydraulic fracturing operation was sequentially made with all packers and bridge plugs effectively set. It is shown from the field operation that the hybrid completion is able to meet the requirements of completion and stimulation in irregular wellbore with abnormal conditions for tight reservoirs.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"121 19 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83606244","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}
Zhu Shijia, Derong Lei, Liu He, Zhongxian Hao, Lixin Zhang
The development of a new low-carbon operation mode of artificial lift in high-water-cut oilfields, is significant for reducing energy consumption, improving operation efficiency and lowering production costs of oilfields. The annual electric consumption of the oilfield is increasing year by year. In 2016, the total electric consumption exceeded 35 billion kWh, of which the mechanical production system accounts for 57%. The rodless artificial lift eliminates the use of the sucker rod, and reduces the installed motor power over 50%. The electric consumption is greatly decreased, while tremendous gain is seen in the system efficiency. Moreover, the application performance is especially good for low-production wells. Under such circumstances, the operation cost of the oilfield declines. The current rodless artificial lift is basically based on two types of pumps, namely submersible plunger pump and submersible direct-drive screw pump. The submersible plunger pump lifts liquid via vertical reciprocation of the moving body driven by the motor, with daily electric consumption of an individual well decreasing by 46%, from 133.4 kWh to 72.5 kWh. The reduced annual electric cost per well is RMB 14,000, and the annual single-well carbon emission falls by 17.5 tons. As for the submersible direct-drive screw pump, the rotation of the pump is directly motivated by the downhole submersible motor, through which the downhole liquid is elevated to the surface. The daily electric consumption of an individual well decreases by 38.4%, from 224kWh to 138kWh, contributing to the annual electric cost reduction per well of RMB 13,600 and annual carbon emission decline per well of 17.1 tons. The application of the two types of rodless artificial lift has taken initial shape. The submersible plunger pump has been applied to over 200 wells, and the submersible direct-drive screw pump, over 60 wells. The new low-carbon operation mode of artificial lift is critical for the energy saving, efficiency improvement and consequent cost reduction of oilfields, particularly in cases of the industry downturn triggered by low oil prices.
{"title":"Application of Low-Carbon, Rodless Artificial Lift in Low-Production, Low-Permeability Oilfields","authors":"Zhu Shijia, Derong Lei, Liu He, Zhongxian Hao, Lixin Zhang","doi":"10.2118/192071-MS","DOIUrl":"https://doi.org/10.2118/192071-MS","url":null,"abstract":"\u0000 The development of a new low-carbon operation mode of artificial lift in high-water-cut oilfields, is significant for reducing energy consumption, improving operation efficiency and lowering production costs of oilfields. The annual electric consumption of the oilfield is increasing year by year. In 2016, the total electric consumption exceeded 35 billion kWh, of which the mechanical production system accounts for 57%.\u0000 The rodless artificial lift eliminates the use of the sucker rod, and reduces the installed motor power over 50%. The electric consumption is greatly decreased, while tremendous gain is seen in the system efficiency. Moreover, the application performance is especially good for low-production wells. Under such circumstances, the operation cost of the oilfield declines. The current rodless artificial lift is basically based on two types of pumps, namely submersible plunger pump and submersible direct-drive screw pump.\u0000 The submersible plunger pump lifts liquid via vertical reciprocation of the moving body driven by the motor, with daily electric consumption of an individual well decreasing by 46%, from 133.4 kWh to 72.5 kWh. The reduced annual electric cost per well is RMB 14,000, and the annual single-well carbon emission falls by 17.5 tons. As for the submersible direct-drive screw pump, the rotation of the pump is directly motivated by the downhole submersible motor, through which the downhole liquid is elevated to the surface. The daily electric consumption of an individual well decreases by 38.4%, from 224kWh to 138kWh, contributing to the annual electric cost reduction per well of RMB 13,600 and annual carbon emission decline per well of 17.1 tons.\u0000 The application of the two types of rodless artificial lift has taken initial shape. The submersible plunger pump has been applied to over 200 wells, and the submersible direct-drive screw pump, over 60 wells. The new low-carbon operation mode of artificial lift is critical for the energy saving, efficiency improvement and consequent cost reduction of oilfields, particularly in cases of the industry downturn triggered by low oil prices.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"146 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76082874","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}
Baraa Al-Shammari, Nitin L. Rane, Sultan Hasan Al Harbi, S. Mohammad, Abdullah Al-Kinderi, Y. Santin, K. Matar
This paper describes a rigless and cost-effective field implementation of conformance polymer sealant (CPS) and particulate-CPS (P-CPS) systems used successfully in high-permeability and low-pressure reservoirs for zonal isolation intervention. The CPS system is an organically crosslinked polymer that is thermally activated to effectively seal the targeted interval. The P-CPS system combines the CPS system with particulates that provide leakoff control to help ensure shallow matrix penetration of the sealant. The traditional method for zonal isolation consists of rig intervention for cement squeeze, which can be time-consuming and expensive. In high-permeability and low-pressure reservoirs, several unsuccessful attempts can extend the intervention by two or more weeks. CPS and P-CPS systems provide a predictable and controllable right-angle set time that can help to ensure sealing on the first attempt. These systems do not develop compressive strength, simplifying the cleanup stage by quickly and easily jetting it out of the wellbore with coiled tubing (CT), as opposed to cement that must be drilled/milled out. This paper describes laboratory evaluations, treatment design methodologies, and two case histories from Kuwait, including one well that produced 1,600 BOPD after reperforations.
{"title":"Rigless Zonal Isolation in High-Permeability and Low-Pressure Sandstone Formations Using an Organically Crosslinked Polymer Sealant: Successful Field Application","authors":"Baraa Al-Shammari, Nitin L. Rane, Sultan Hasan Al Harbi, S. Mohammad, Abdullah Al-Kinderi, Y. Santin, K. Matar","doi":"10.2118/192099-MS","DOIUrl":"https://doi.org/10.2118/192099-MS","url":null,"abstract":"\u0000 This paper describes a rigless and cost-effective field implementation of conformance polymer sealant (CPS) and particulate-CPS (P-CPS) systems used successfully in high-permeability and low-pressure reservoirs for zonal isolation intervention.\u0000 The CPS system is an organically crosslinked polymer that is thermally activated to effectively seal the targeted interval. The P-CPS system combines the CPS system with particulates that provide leakoff control to help ensure shallow matrix penetration of the sealant.\u0000 The traditional method for zonal isolation consists of rig intervention for cement squeeze, which can be time-consuming and expensive. In high-permeability and low-pressure reservoirs, several unsuccessful attempts can extend the intervention by two or more weeks.\u0000 CPS and P-CPS systems provide a predictable and controllable right-angle set time that can help to ensure sealing on the first attempt. These systems do not develop compressive strength, simplifying the cleanup stage by quickly and easily jetting it out of the wellbore with coiled tubing (CT), as opposed to cement that must be drilled/milled out.\u0000 This paper describes laboratory evaluations, treatment design methodologies, and two case histories from Kuwait, including one well that produced 1,600 BOPD after reperforations.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73222080","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}
Aizuddin Khalid, Nor Baizurah Ahmad Tajuddin, H. Dan, Nik Fazril Ain Sapian, N. A. A. Fadzil, S. N. Hassan
Managing an oil rim type reservoir has constantly been a great challenge and understanding the oil rim movement has remained as one of the main subsurface uncertainties. Prudent reservoir management through an active reservoir, well and facilities management (RWFM) plan is key to realizing the uncertainties, optimizing production and reserves of brownfields. Monitoring the oil rim through cased-hole reservoir saturation logging has been identified as a de-risking method, planned and executed for two consecutive years in the field to minimize the oil rim uncertainty. The field studied is one of the brownfields in offshore Sarawak, Malaysia, which has been on production for more than 40 years. Results acquired from the cased-hole logs have triggered the need to optimize the location of an infill oil producer planned in the Field Development Plan. The cased-hole results indicated that the original oil target in the N reservoir had mostly been swept by water. Through thorough studies and modeling, an opportunity to the western flank in M reservoir, located close to a proposed workover well, was suggested. Furthermore, latest input on the proposed workover well and facilities health check suggested the workover candidate was not favourable due to its location on an aging single well monopod structure with complex well mechanical problems. Thus, the planned infill oil producer was recommended to replace the workover well and recover the reserves. Integrated studies incorporated cased-hole results with reservoir modeling indicated that the new infill location would yield a total of 5.7MMSTB reserves with initial production rate of 1215BOPD. In addition, through integration of a multi-disciplinary team, revision to the infill location was timely and the infill was also accelerated from Phase II to Phase I of the development plan as a rig filler for cost optimization. Well test result successfully validated the reservoir productivity of 1238BOPD with no water production. This paper presents the integrated subsurface and surface solutions and criticality of proactive data acquisition, field monitoring and collaborative team work strategies to maximize the recovery from a brownfield.
{"title":"Successful Infill Realized through Prudent Brownfield Oil Rim Reservoir Management, Offshore Malaysia","authors":"Aizuddin Khalid, Nor Baizurah Ahmad Tajuddin, H. Dan, Nik Fazril Ain Sapian, N. A. A. Fadzil, S. N. Hassan","doi":"10.2118/191949-MS","DOIUrl":"https://doi.org/10.2118/191949-MS","url":null,"abstract":"\u0000 Managing an oil rim type reservoir has constantly been a great challenge and understanding the oil rim movement has remained as one of the main subsurface uncertainties. Prudent reservoir management through an active reservoir, well and facilities management (RWFM) plan is key to realizing the uncertainties, optimizing production and reserves of brownfields. Monitoring the oil rim through cased-hole reservoir saturation logging has been identified as a de-risking method, planned and executed for two consecutive years in the field to minimize the oil rim uncertainty. The field studied is one of the brownfields in offshore Sarawak, Malaysia, which has been on production for more than 40 years.\u0000 Results acquired from the cased-hole logs have triggered the need to optimize the location of an infill oil producer planned in the Field Development Plan. The cased-hole results indicated that the original oil target in the N reservoir had mostly been swept by water. Through thorough studies and modeling, an opportunity to the western flank in M reservoir, located close to a proposed workover well, was suggested. Furthermore, latest input on the proposed workover well and facilities health check suggested the workover candidate was not favourable due to its location on an aging single well monopod structure with complex well mechanical problems. Thus, the planned infill oil producer was recommended to replace the workover well and recover the reserves.\u0000 Integrated studies incorporated cased-hole results with reservoir modeling indicated that the new infill location would yield a total of 5.7MMSTB reserves with initial production rate of 1215BOPD. In addition, through integration of a multi-disciplinary team, revision to the infill location was timely and the infill was also accelerated from Phase II to Phase I of the development plan as a rig filler for cost optimization. Well test result successfully validated the reservoir productivity of 1238BOPD with no water production.\u0000 This paper presents the integrated subsurface and surface solutions and criticality of proactive data acquisition, field monitoring and collaborative team work strategies to maximize the recovery from a brownfield.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"50 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73364378","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}
M. Vatan, Melanie Desplat, A. Giambalvo, Gabriel Amorer
Historically, openhole barefoot completions used in conjunction with cavitation and surging or underreaming techniques, have proven to be an effective way to stimulate coal seam gas wells to increase effective permeability. (Logan et al, 1989). However, despite having a positive impact on production, the unpredictable time required to cavitate and surge the wells can be substantial, sometimes requiring up to 4 weeks to execute required scope. This time consuming technique leaves the operator vulnerable, working in an unstable borehole where fishing operations are common and the outcome of delivering scope is not guaranteed. The main challenges of accurately predicting cost to keep the projects economical, continuing to produce coal fines during cavitating and surging, and continual sloughing are some major drawbacks. The other alternative on the market is underreaming, which has its own limitation in relation to the maximum possible enlargement of the borehole or more specifically, the size of the underreamer that can be utilized. Faced with these limitations, there was a significant need for an innovative way to stimulate wells to increase production while minimizing costs. This paper introduces the ingenious use of a newly designed jetting tool, with specialized nozzles, to enlarge a borehole size using a combination of air and mist. This case study conducts a lookback on design parameters, cost, and safety improvements introduced by this new technology.
从历史上看，裸眼光脚完井与造穴、涌流或扩眼技术相结合，已被证明是提高煤层气井有效渗透率的有效方法。(Logan et al, 1989)。然而，尽管对生产有积极的影响，但空化和井喷所需的不可预测的时间可能很长，有时需要长达4周的时间才能完成所需的范围。这种耗时的技术使作业者容易受到伤害，因为作业在不稳定的井眼中，打捞作业很常见，而且无法保证交付范围的结果。一些主要的缺点是，准确预测成本以保持项目的经济性，在空化和突涌期间继续产生煤粉，以及持续的剥落，这些都是主要的挑战。市场上的另一种选择是扩眼，它在最大可能扩大井眼方面有自己的局限性，更具体地说，是可以使用的扩眼器的尺寸。面对这些限制，迫切需要一种创新的方法来增产，同时最大限度地降低成本。本文介绍了一种新设计的喷射工具的巧妙使用，该工具带有专门的喷嘴，可以利用空气和雾的结合来扩大井眼尺寸。本案例研究回顾了该新技术引入的设计参数、成本和安全性改进。
{"title":"Underbalanced Jetting in CSG play","authors":"M. Vatan, Melanie Desplat, A. Giambalvo, Gabriel Amorer","doi":"10.2118/191944-MS","DOIUrl":"https://doi.org/10.2118/191944-MS","url":null,"abstract":"\u0000 Historically, openhole barefoot completions used in conjunction with cavitation and surging or underreaming techniques, have proven to be an effective way to stimulate coal seam gas wells to increase effective permeability. (Logan et al, 1989). However, despite having a positive impact on production, the unpredictable time required to cavitate and surge the wells can be substantial, sometimes requiring up to 4 weeks to execute required scope. This time consuming technique leaves the operator vulnerable, working in an unstable borehole where fishing operations are common and the outcome of delivering scope is not guaranteed. The main challenges of accurately predicting cost to keep the projects economical, continuing to produce coal fines during cavitating and surging, and continual sloughing are some major drawbacks.\u0000 The other alternative on the market is underreaming, which has its own limitation in relation to the maximum possible enlargement of the borehole or more specifically, the size of the underreamer that can be utilized. Faced with these limitations, there was a significant need for an innovative way to stimulate wells to increase production while minimizing costs.\u0000 This paper introduces the ingenious use of a newly designed jetting tool, with specialized nozzles, to enlarge a borehole size using a combination of air and mist. This case study conducts a lookback on design parameters, cost, and safety improvements introduced by this new technology.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"31 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73085310","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A. Shaban, Mohammad Zaman, T. Dedigama, T. Saunders
The development of Early Permian reservoirs in the Fairview Field is limited by highly depleted shallower Bandanna coal seams and naturally fractured formations that would not allow to reach the original geological goals. Offset wells in the area had been executed as three string well design due to long open hole section across depleted Bandanna and multiple loss zones. Multi-stage cementing was required to ensure there is proper zonal isolation. These resulted in significant incremental cost to achieve 5-1/2″ production casing. Through the depletion of upper coals, fracture pressure in these zones has decreased due to reduction in pore pressure. Drilling in two string design carries higher execution risk due to long open hole section, depleted formations and differential sticking, highly fractured formations, narrow window between fracture gradient and pore pressure, and multiple loss zones which demands special techniques for treatment of loss zones and hole stabilisation while drilling. Considering the downhole conditions, which pore pressure ranging from 2 to 9 ppg in the different formations, the importance of zonal isolation, establishing barriers in aquifers and achieving overall cement coverage is also extremely important. With introduction of various new LCM products, cement plugs, foam cementing, RCD for drilling with no returns (blind drilling), Santos has achieved major success developing Early Permian fields. This Paper describes how two string design was successfully implemented to drill Early Permian wells. This paper serves as an operational guide to ensure challenging depleted and highly fractured zones can be successfully drilled while minimising risks.
{"title":"Planning and Drilling Execution of Early Permian Wells in Two String Design by Implementing New Drilling and Cementing Technologies","authors":"A. Shaban, Mohammad Zaman, T. Dedigama, T. Saunders","doi":"10.2118/192032-MS","DOIUrl":"https://doi.org/10.2118/192032-MS","url":null,"abstract":"\u0000 The development of Early Permian reservoirs in the Fairview Field is limited by highly depleted shallower Bandanna coal seams and naturally fractured formations that would not allow to reach the original geological goals. Offset wells in the area had been executed as three string well design due to long open hole section across depleted Bandanna and multiple loss zones. Multi-stage cementing was required to ensure there is proper zonal isolation. These resulted in significant incremental cost to achieve 5-1/2″ production casing. Through the depletion of upper coals, fracture pressure in these zones has decreased due to reduction in pore pressure.\u0000 Drilling in two string design carries higher execution risk due to long open hole section, depleted formations and differential sticking, highly fractured formations, narrow window between fracture gradient and pore pressure, and multiple loss zones which demands special techniques for treatment of loss zones and hole stabilisation while drilling. Considering the downhole conditions, which pore pressure ranging from 2 to 9 ppg in the different formations, the importance of zonal isolation, establishing barriers in aquifers and achieving overall cement coverage is also extremely important.\u0000 With introduction of various new LCM products, cement plugs, foam cementing, RCD for drilling with no returns (blind drilling), Santos has achieved major success developing Early Permian fields. This Paper describes how two string design was successfully implemented to drill Early Permian wells. This paper serves as an operational guide to ensure challenging depleted and highly fractured zones can be successfully drilled while minimising risks.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"11 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87507976","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}
Muhammad Abdulhadi, Pei Tze Kueh, A. Zamanuri, Wai Cheong Thang, H. Chin, S. Jacobs, Alister Albert Suggust, Ahmad Hafizi Ahmad Zaini, Delwistiel Jamel, Khairul Arifin Dolah, Hasim Munandai, Zainuddin Yusop
In the recent low oil price environment, a cost-effective solution was proposed to use through tubing bridge plugs to perform water-shut-off (WSO) in an offshore field. The solution consisted of using slickline to set a plug with a high expansion ratio followed by a cement dump. After three WSO jobs in different wells, the method has successfully proven itself. Watercut was reduced from 100% to 0% with a minimal cost of only USD100,000. The through tubing bridge plug used is capable of passing through 2-7/8-in. tubing and expanding into 9-5/8-in. casing. After running a Gamma-Ray log, the plug was set across the perforation interval to give the anchor contact with a rough casing surface. The top of the plug, however, was above the perforation interval and became the base for cement. Cement was then continuously dumped on top using a slickline dump bailer in a static condition until the designed cement height was reached. Static conditions ensured no movement of cement during operation. The plug differential pressure limit is directly proportional to the cement height. The first WSO job was a complete success with watercut reduced from 100% to 0%. The second job however, was partially successful as the cement dump was not completed due to unexpected appearance of a hold-up-depth (HUD). The HUD was created by leftover cement which had accumulated at the end of the tubing. Despite the setbacks, the end result was successful in reducing water production from 1000 bwpd to 200 bwpd. The third job faced a completely different problem. The original plug fell off deeper into the well after it was set. To rectify the situation, a second plug was set at the target interval. Despite the successful execution, there was no change in watercut after the well was brought back online. Since the same method was proposed for another upcoming well, Memory-Production log (MPLT) coupled with Temperature-Noise log was performed to assess the effectiveness of the WSO. The log results confirmed that the WSO was successful and the post job water production was caused by channeling behind the casing. The results so far concluded that the through tubing bridge plug WSO method was both reliable and cost-effective. It is exceptionally suitable for zones located at the bottom of a well and can be deployed using slickline. The paper provides valuable insight to a WSO solution which should be a first-choice option due to its relatively inexpensive cost and high reliability. The solution has proven to provide tremendous cost saving for production enhancement activity.
{"title":"Cost Effective Water Shut-Off: Slickline Conveyed High Expansion Ratio Through Tubing Bridge Plug","authors":"Muhammad Abdulhadi, Pei Tze Kueh, A. Zamanuri, Wai Cheong Thang, H. Chin, S. Jacobs, Alister Albert Suggust, Ahmad Hafizi Ahmad Zaini, Delwistiel Jamel, Khairul Arifin Dolah, Hasim Munandai, Zainuddin Yusop","doi":"10.2118/192145-MS","DOIUrl":"https://doi.org/10.2118/192145-MS","url":null,"abstract":"\u0000 In the recent low oil price environment, a cost-effective solution was proposed to use through tubing bridge plugs to perform water-shut-off (WSO) in an offshore field. The solution consisted of using slickline to set a plug with a high expansion ratio followed by a cement dump. After three WSO jobs in different wells, the method has successfully proven itself. Watercut was reduced from 100% to 0% with a minimal cost of only USD100,000.\u0000 The through tubing bridge plug used is capable of passing through 2-7/8-in. tubing and expanding into 9-5/8-in. casing. After running a Gamma-Ray log, the plug was set across the perforation interval to give the anchor contact with a rough casing surface. The top of the plug, however, was above the perforation interval and became the base for cement. Cement was then continuously dumped on top using a slickline dump bailer in a static condition until the designed cement height was reached. Static conditions ensured no movement of cement during operation. The plug differential pressure limit is directly proportional to the cement height.\u0000 The first WSO job was a complete success with watercut reduced from 100% to 0%. The second job however, was partially successful as the cement dump was not completed due to unexpected appearance of a hold-up-depth (HUD). The HUD was created by leftover cement which had accumulated at the end of the tubing. Despite the setbacks, the end result was successful in reducing water production from 1000 bwpd to 200 bwpd. The third job faced a completely different problem. The original plug fell off deeper into the well after it was set. To rectify the situation, a second plug was set at the target interval. Despite the successful execution, there was no change in watercut after the well was brought back online. Since the same method was proposed for another upcoming well, Memory-Production log (MPLT) coupled with Temperature-Noise log was performed to assess the effectiveness of the WSO. The log results confirmed that the WSO was successful and the post job water production was caused by channeling behind the casing. The results so far concluded that the through tubing bridge plug WSO method was both reliable and cost-effective. It is exceptionally suitable for zones located at the bottom of a well and can be deployed using slickline.\u0000 The paper provides valuable insight to a WSO solution which should be a first-choice option due to its relatively inexpensive cost and high reliability. The solution has proven to provide tremendous cost saving for production enhancement activity.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"75 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":"89669633","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}
Y. A. Praditya, A. Satiawarman, Fahmi Nurrahman, Medianestrian Medianestrian, Risnawan Rochaendy
Wells which produce dry gas reservoirs usually have low bottomhole pressure. But in many instance liquid is associated with the produced gas, it can come from the liquid in reservoir or condensed production liquid. When more liquid is introduced into the wellbore, the pressure gradient along the wellbore is higher. The increased liquid fraction creates higher backpressure on the reservoir delivering gas. In high pressure gas reservoir the presence of liquid can occur in several degree of bubble and slug flow; in depleted gas reservoir the liquid can kill the well as the gas does not have enough transport energy to lift the liquid. At the point when the gas velocity is insufficient to carry out liquid, liquid will start to drop and accumulate in the bottomhole creating a restriction on the gas flow path, the phenomena is called liquid loading. This paper presents success case studies from Premier Oil Indonesia in handling and reactivating four liquid loaded gas wells in Natuna Sea offshore operation. Wellbore configuration and facility limitations in offshore operation (e.g. maximum deck load capacity, water handling capacity and crane capacity) create more complexity of the method selection in comparison to onshore operation. There are many gas well deliquification methods available in the industry, but not in instance that each method is appropriate for all conditions. The case studies presented in this paper provide description of how Premier Oil Indonesia screened several available gas well deliquification methods in the industry and came up with the water shut off proposal as the best and most proper method for its wells. The understanding of liquid loading indication, liquid source identification and operational details of gas well deliquification methods are the most important factors to determine the most effective and cost efficient method to handle liquid loaded wells. This paper also presents a general guideline in selecting the best gas well deliquification method for some specific cases under several operational conditions for onshore and offshore operations.
{"title":"Systematic Approach in Extending Liquid Loaded Offshore Gas Wells Production in Natuna Sea with Partial and Full Wellbore Water Shut Off: Case Study and Method Selection","authors":"Y. A. Praditya, A. Satiawarman, Fahmi Nurrahman, Medianestrian Medianestrian, Risnawan Rochaendy","doi":"10.2118/192083-MS","DOIUrl":"https://doi.org/10.2118/192083-MS","url":null,"abstract":"\u0000 Wells which produce dry gas reservoirs usually have low bottomhole pressure. But in many instance liquid is associated with the produced gas, it can come from the liquid in reservoir or condensed production liquid. When more liquid is introduced into the wellbore, the pressure gradient along the wellbore is higher. The increased liquid fraction creates higher backpressure on the reservoir delivering gas. In high pressure gas reservoir the presence of liquid can occur in several degree of bubble and slug flow; in depleted gas reservoir the liquid can kill the well as the gas does not have enough transport energy to lift the liquid. At the point when the gas velocity is insufficient to carry out liquid, liquid will start to drop and accumulate in the bottomhole creating a restriction on the gas flow path, the phenomena is called liquid loading.\u0000 This paper presents success case studies from Premier Oil Indonesia in handling and reactivating four liquid loaded gas wells in Natuna Sea offshore operation. Wellbore configuration and facility limitations in offshore operation (e.g. maximum deck load capacity, water handling capacity and crane capacity) create more complexity of the method selection in comparison to onshore operation. There are many gas well deliquification methods available in the industry, but not in instance that each method is appropriate for all conditions. The case studies presented in this paper provide description of how Premier Oil Indonesia screened several available gas well deliquification methods in the industry and came up with the water shut off proposal as the best and most proper method for its wells. The understanding of liquid loading indication, liquid source identification and operational details of gas well deliquification methods are the most important factors to determine the most effective and cost efficient method to handle liquid loaded wells. This paper also presents a general guideline in selecting the best gas well deliquification method for some specific cases under several operational conditions for onshore and offshore operations.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"49 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85696832","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}
Muhammad Abdulhadi, M. Mansor, N. Amiruddin, T. Tran, S. Jacobs, M. I. Wahid, M. Z. Usop, Mohd Dzulfahmi B Zamzuri, Khairul Arifin Dolah, Hasim Munandai, Zainuddin Yusop
Reservoir X-7, a watered-out reservoir in Field B, was successfully revived by perforating the original gas-cap zone to maximize oil recovery, which increased the recovery factor (RF) from 40% to 46%, resulting in approximately 2,300 BOPD through multiple perforations. Maintaining the oil column sandwiched between gas and water is the standard practice to maximize oil recovery in a strong water-drive reservoir. Despite having a strong aquifer and a thick gas cap, Reservoir X-7 has produced continuously for 30 years without any gas reinjection. The reservoir was producing at 99% watercut, indicating the original oil column was already swept. Subsequent material balance study and saturation log results confirm that oil migrated into the original gas cap. Given the reservoir condition, an unconventional approach was proposed to produce the oil column through the original gas-cap zone. The first gas-cap perforation for Well B-07 successfully produced 500 BOPD, so it was decided to perform three additional perforations (additional perforations) for Wells A-01, B-12, and B-16, which were successful with a total 2,000 BOPD oil gain from the three wells. Subsequent additional perforations was performed in Well B-07 after the original additional perforations watered out. However, the new additional perforations and subsequent ones in Well B-11 resulted in gas rather than oil. Both wells were shut in. Once the new perforations are watered out, the remaining oil potential in Reservoir X-7 will be confirmed by reopening well B-07 and B-11 until either oil or water is produced. The approach has so far provided approximately 2,300 BOPD of incremental oil production, extending well life by more than 24 months and allowing the RF to increase from 40% to 46%. It delivered encouraging results and opened up opportunities for other reservoirs. This paper provides valuable insight into the case study and lessons learned in terms of maximizing oil recovery using original gas-cap perforation. This approach is highly recommended as the production enhancement method for maximizing oil recovery, particularly in mature fields with similar reservoir conditions.
{"title":"Maximizing Oil Recovery through Gas-Cap Perforation in Strong Water-Drive Reservoir","authors":"Muhammad Abdulhadi, M. Mansor, N. Amiruddin, T. Tran, S. Jacobs, M. I. Wahid, M. Z. Usop, Mohd Dzulfahmi B Zamzuri, Khairul Arifin Dolah, Hasim Munandai, Zainuddin Yusop","doi":"10.2118/192058-MS","DOIUrl":"https://doi.org/10.2118/192058-MS","url":null,"abstract":"\u0000 Reservoir X-7, a watered-out reservoir in Field B, was successfully revived by perforating the original gas-cap zone to maximize oil recovery, which increased the recovery factor (RF) from 40% to 46%, resulting in approximately 2,300 BOPD through multiple perforations.\u0000 Maintaining the oil column sandwiched between gas and water is the standard practice to maximize oil recovery in a strong water-drive reservoir. Despite having a strong aquifer and a thick gas cap, Reservoir X-7 has produced continuously for 30 years without any gas reinjection. The reservoir was producing at 99% watercut, indicating the original oil column was already swept. Subsequent material balance study and saturation log results confirm that oil migrated into the original gas cap. Given the reservoir condition, an unconventional approach was proposed to produce the oil column through the original gas-cap zone.\u0000 The first gas-cap perforation for Well B-07 successfully produced 500 BOPD, so it was decided to perform three additional perforations (additional perforations) for Wells A-01, B-12, and B-16, which were successful with a total 2,000 BOPD oil gain from the three wells. Subsequent additional perforations was performed in Well B-07 after the original additional perforations watered out. However, the new additional perforations and subsequent ones in Well B-11 resulted in gas rather than oil. Both wells were shut in. Once the new perforations are watered out, the remaining oil potential in Reservoir X-7 will be confirmed by reopening well B-07 and B-11 until either oil or water is produced. The approach has so far provided approximately 2,300 BOPD of incremental oil production, extending well life by more than 24 months and allowing the RF to increase from 40% to 46%. It delivered encouraging results and opened up opportunities for other reservoirs.\u0000 This paper provides valuable insight into the case study and lessons learned in terms of maximizing oil recovery using original gas-cap perforation. This approach is highly recommended as the production enhancement method for maximizing oil recovery, particularly in mature fields with similar reservoir conditions.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"22 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79105968","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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