Having a good understanding of the offset wells is the key for successful planning and execution of any well, both from the risk management point of view as well as from equipment and operations planning. In both cases of congested or simple fields the amount of the manual work is significant, which further affected by potential human mistakes. The manuscript aims to provide the detailed explanation of the digitalization of the offset well risk analysis (ORA) implemented in several drilling projected, what lead to almost complete elimination of the manual work and allowed to improve the quality and the quantity of the offset data. At the project kick-off the manual work performed by different parties (drilling engineer as well as drilling fluid, directional, bits engineers etc.) was mapped in the different detailed workflows. This allowed to understand the final result of every tasks. As next step the massive database of the end of well reports, post-job reports, daily drilling reports, etc was created with few tens of millions entry points. Further the artificial intelligence in combination with data analytics was used to replicate the previously mapped workflows. As the result entire manual work was replaced by the digital, leading to receive higher number of outputs with superior quality. The direct benefit was a reduction of the time required to get the final result, when previously a detailed analysis was completed in 3 to 4 days, and now it is done within minutes, allowing to dedicate the man-hours to more other valuable tasks. The manuscript provides the novel information on ability to use digital technologies to eliminate manual work and avoid costly human mistakes. The proposed solution can be implemented in any other drilling project worldwide, as well as in any other activity requiring performance of the repetitive tasks.
{"title":"Development and Application of Digital Solutions for Automatic Hazard Identification During Well Planning Stage","authors":"A. Ruzhnikov, Rasesh Saraiya","doi":"10.2118/209870-ms","DOIUrl":"https://doi.org/10.2118/209870-ms","url":null,"abstract":"\u0000 Having a good understanding of the offset wells is the key for successful planning and execution of any well, both from the risk management point of view as well as from equipment and operations planning. In both cases of congested or simple fields the amount of the manual work is significant, which further affected by potential human mistakes. The manuscript aims to provide the detailed explanation of the digitalization of the offset well risk analysis (ORA) implemented in several drilling projected, what lead to almost complete elimination of the manual work and allowed to improve the quality and the quantity of the offset data.\u0000 At the project kick-off the manual work performed by different parties (drilling engineer as well as drilling fluid, directional, bits engineers etc.) was mapped in the different detailed workflows. This allowed to understand the final result of every tasks. As next step the massive database of the end of well reports, post-job reports, daily drilling reports, etc was created with few tens of millions entry points. Further the artificial intelligence in combination with data analytics was used to replicate the previously mapped workflows.\u0000 As the result entire manual work was replaced by the digital, leading to receive higher number of outputs with superior quality. The direct benefit was a reduction of the time required to get the final result, when previously a detailed analysis was completed in 3 to 4 days, and now it is done within minutes, allowing to dedicate the man-hours to more other valuable tasks.\u0000 The manuscript provides the novel information on ability to use digital technologies to eliminate manual work and avoid costly human mistakes. The proposed solution can be implemented in any other drilling project worldwide, as well as in any other activity requiring performance of the repetitive tasks.","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"8 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122661334","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}
H. Bakar, Narindran Ravichandran, Hamidah Hassan, M. Abu Bakar, Khairul Nizam Idris, R. Masoudi
Most of the S oil field producers experienced rapid decline in production and this is suspected due to fine sediment particle migration and plugging. The S field team had carried out external formation damage study as they have no expertise and field experience to determine the damage mechanism and evaluate the best acid treatment recipe for their formation damage. Recently, mixtures of traditional hydrochloric and hydrofluoric acids have been used for the removal of near-wellbore damage in S field sandstone formations. The stimulation campaign in this field which has turbidite reservoir, high clay content predominantly by kaolinite and illite with high siderite mineralogy applied both bullheading and coiled tubing squeezing techniques. The treating fluid selection is highly dependent on mineralogical data and laboratory works. Based on the core flood testing performed, high strength mud acid is chosen as the main treatment fluid and gave superior result in permeability recovery as compared to milder organic acid and HF. Unfortunately, the actual field stimulation turned out to be opposite from the core flood testing outcomes. The situation is worsened in multistage treatments, which traditionally involve many repeat stages of preflush, main treatment, overflush and diverter. The mud acid stimulation prompted more water production and fine migration that is ended up with production curtailment. Only one out of four of the treated candidates resulted significant gain after gas lift valve change took place. This paper also will outline the reviews on results of laboratory testing and field actual performance together with the recommendations for future improvement. Stringent candidate selection, improved treatment fluids cocktail, operational challenges such as unanticipated longer flow back period, post treatment unwanted precipitation, ineffective diverter placement and skin build up post treatment are among of the learning points captured in this paper. From this unfavorable mud acid stimulation campaign which cost USD4million value leakage, our team comes out with best practices for future stimulation and key learning to share with industry colleagues who has no field background to combat with fine migration issue in their sandstone asset. Laboratory works is not the only paramount to any stimulation, success in stimulation is a journey, not a destination. The doing is often more important than the outcome.
{"title":"First Experience Matter: The Valuable and Great Learnings from Unfavorable Mud Acid Stimulation in S Field Gravel Pack Wells, East Malaysia","authors":"H. Bakar, Narindran Ravichandran, Hamidah Hassan, M. Abu Bakar, Khairul Nizam Idris, R. Masoudi","doi":"10.2118/209866-ms","DOIUrl":"https://doi.org/10.2118/209866-ms","url":null,"abstract":"\u0000 Most of the S oil field producers experienced rapid decline in production and this is suspected due to fine sediment particle migration and plugging. The S field team had carried out external formation damage study as they have no expertise and field experience to determine the damage mechanism and evaluate the best acid treatment recipe for their formation damage. Recently, mixtures of traditional hydrochloric and hydrofluoric acids have been used for the removal of near-wellbore damage in S field sandstone formations. The stimulation campaign in this field which has turbidite reservoir, high clay content predominantly by kaolinite and illite with high siderite mineralogy applied both bullheading and coiled tubing squeezing techniques. The treating fluid selection is highly dependent on mineralogical data and laboratory works. Based on the core flood testing performed, high strength mud acid is chosen as the main treatment fluid and gave superior result in permeability recovery as compared to milder organic acid and HF. Unfortunately, the actual field stimulation turned out to be opposite from the core flood testing outcomes. The situation is worsened in multistage treatments, which traditionally involve many repeat stages of preflush, main treatment, overflush and diverter. The mud acid stimulation prompted more water production and fine migration that is ended up with production curtailment. Only one out of four of the treated candidates resulted significant gain after gas lift valve change took place. This paper also will outline the reviews on results of laboratory testing and field actual performance together with the recommendations for future improvement. Stringent candidate selection, improved treatment fluids cocktail, operational challenges such as unanticipated longer flow back period, post treatment unwanted precipitation, ineffective diverter placement and skin build up post treatment are among of the learning points captured in this paper. From this unfavorable mud acid stimulation campaign which cost USD4million value leakage, our team comes out with best practices for future stimulation and key learning to share with industry colleagues who has no field background to combat with fine migration issue in their sandstone asset. Laboratory works is not the only paramount to any stimulation, success in stimulation is a journey, not a destination. The doing is often more important than the outcome.","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"6 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126920008","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}
Granite basement drilling in Vietnam is well-known for challenges such as slow penetration rate, strong drill string vibrations, and multiple bit runs required to finish the section. A 3,217 m length 3D horizontal basement section was successfully drilled in 2017 by applying a new drill string optimization method in combination with using axial oscillation friction reduction tools (AOT), reaching total depth (TD) at 6,280 m measured depth (MD). This run represented the longest 3D lateral well drilled in Vietnam at the time (please reference the SPE-191872-MS). Based on the success of that project, Thang Long Joint Operating Company planned to drill a new well with a longer reach to farther targets as per subsurface objectives to extend the record to a planned 3,543 m 3D horizontal granite section hitting three reservoir targets. The directional plan included building inclination from 19° to 88°, turning from 97° to 57° azimuth, and then turning horizontally from 57° to 16° azimuth, with planned TD at 6,768 m MD. With the field-proven drill string optimization method from the offset well, a torque and drag model was built for the subject well in order to understand the difficulty and feasibility to reach the well TD. This model was used for drill pipe selection and configuration, as well as AOT planning purposes, and it was continuously updated in real-time throughout the well. A newer and more efficient version of the AOT technology was introduced to help increase the effectiveness of the friction reduction to help reach the planned TD. From the modeling results, drilling to the planned TD was considered achievable, even when applying worst-case scenario drilling conditions. In terms of trajectory and timing, the actual drilling operation was well-matched with the planning. The selected drill string designs using single AOT systems and dual AOT systems performed as expected and were instrumental in achieving the planned TD. A total of 15 roller cone insert bits and steerable motor BHA's were used to drill the section. From 5,509m MD, due to the high drag condition, dual AOT systems were utilized to aid in weight transfer to the bit to drill to the well TD at 6,768m MD; the longest 3D horizontal basement section drilled in Vietnam to date. The success of the project once again proves that axial friction reduction technology is a reliable technology for drilling the granitic basement in Vietnam, on time and within budget.
越南花岗岩基底钻井面临着钻进速度慢、钻柱振动强、需要多次下钻头等挑战。2017年，通过采用新的钻柱优化方法结合轴向振荡减摩工具(AOT)，成功钻出了3217米长的3D水平基底段，达到了6280米测量深度(MD)的总深度(TD)。这是当时越南钻出的最长的三维水平井(请参考SPE-191872-MS)。基于该项目的成功，Thang Long Joint Operating Company计划根据地下目标钻一口更长的新井，以达到更远的目标，将记录扩展到计划的3543米3D水平花岗岩段，达到三个储层目标。定向方案包括建立井斜从19°到88°，方位角从97°到57°，然后水平方向从57°到16°，计划井深为6,768 m MD。利用从邻井开始的现场验证的钻柱优化方法，为该井建立了扭矩和阻力模型，以了解达到井深的难度和可行性。该模型用于钻杆选择和配置，以及AOT规划，并在整个井中不断实时更新。引入了一种更新、更高效的AOT技术，以帮助提高减少摩擦的有效性，从而达到计划的钻深。从建模结果来看，即使在最糟糕的钻井条件下，钻到计划的TD也是可以实现的。在轨迹和时间方面，实际钻井作业与计划非常吻合。采用单AOT系统和双AOT系统的钻柱设计达到了预期效果，并有助于实现计划的TD。该段共使用了15个牙轮钻头和可导向电机底部钻具组合。在井深550m处，由于阻力较大，采用双AOT系统将重量转移到钻头上，钻至井深6768 m处;这是越南迄今为止钻出的最长的三维水平基底段。该项目的成功再次证明，轴向减摩技术是越南花岗岩基底钻井的可靠技术，能够按时、在预算内完成。
{"title":"Longest 3D Horizontal Granitic Basement Section Record Drilled in Vietnam Using Friction Reduction Technology and Real-Time Torque & Drag Management","authors":"L. Thai, Nam Nguyen, G. Blackwell, Minh Do","doi":"10.2118/209915-ms","DOIUrl":"https://doi.org/10.2118/209915-ms","url":null,"abstract":"\u0000 Granite basement drilling in Vietnam is well-known for challenges such as slow penetration rate, strong drill string vibrations, and multiple bit runs required to finish the section. A 3,217 m length 3D horizontal basement section was successfully drilled in 2017 by applying a new drill string optimization method in combination with using axial oscillation friction reduction tools (AOT), reaching total depth (TD) at 6,280 m measured depth (MD). This run represented the longest 3D lateral well drilled in Vietnam at the time (please reference the SPE-191872-MS). Based on the success of that project, Thang Long Joint Operating Company planned to drill a new well with a longer reach to farther targets as per subsurface objectives to extend the record to a planned 3,543 m 3D horizontal granite section hitting three reservoir targets. The directional plan included building inclination from 19° to 88°, turning from 97° to 57° azimuth, and then turning horizontally from 57° to 16° azimuth, with planned TD at 6,768 m MD.\u0000 With the field-proven drill string optimization method from the offset well, a torque and drag model was built for the subject well in order to understand the difficulty and feasibility to reach the well TD. This model was used for drill pipe selection and configuration, as well as AOT planning purposes, and it was continuously updated in real-time throughout the well. A newer and more efficient version of the AOT technology was introduced to help increase the effectiveness of the friction reduction to help reach the planned TD. From the modeling results, drilling to the planned TD was considered achievable, even when applying worst-case scenario drilling conditions.\u0000 In terms of trajectory and timing, the actual drilling operation was well-matched with the planning. The selected drill string designs using single AOT systems and dual AOT systems performed as expected and were instrumental in achieving the planned TD. A total of 15 roller cone insert bits and steerable motor BHA's were used to drill the section. From 5,509m MD, due to the high drag condition, dual AOT systems were utilized to aid in weight transfer to the bit to drill to the well TD at 6,768m MD; the longest 3D horizontal basement section drilled in Vietnam to date.\u0000 The success of the project once again proves that axial friction reduction technology is a reliable technology for drilling the granitic basement in Vietnam, on time and within budget.","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"17 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127004806","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}
Ahmad Abdullah Mahmood, Hassaan Rasheed, Usman Ahmed Jan, Anum Yousuf Khan, J. Salazar
As the field of well construction has advanced over the years, one feature that has remained consistent throughout is the use of Cement as a primary well barrier element. The long-lasting, impermeable nature of the cement matrix means no other material has been considered as an effective, widely-available alternate almost a century from the first cement job. What has changed however, with advancement in the the field of well integrity, is how we approach the cement job design and how certain materials can complement the role of the cement in improving hydraulic isolation. The historical cement job design only targeted a pumpable slurry reaching the desired placement interval, then the design moved to improving liquid slurry properties such as rheologies, fluid-loss and free fluid. Later, the short-term performance as the slurry transitioned through a gel phase to a set state also became an important criterion. More recently, after the renewed global focus on well integrity as learning from disasters such as Macondo, the annular cement’s role as a well barrier has become a major focal area for any well construction program. This paper presents a systematic approach in designing cement systems that promise long-term well integrity starting with the root-cause identification, simulating the effect on the cement sheath, required modification of the design, and finally the application and associated results.
{"title":"Well Integrity Under Dynamic Stresses Using Flexible Cement Systems","authors":"Ahmad Abdullah Mahmood, Hassaan Rasheed, Usman Ahmed Jan, Anum Yousuf Khan, J. Salazar","doi":"10.2118/209910-ms","DOIUrl":"https://doi.org/10.2118/209910-ms","url":null,"abstract":"As the field of well construction has advanced over the years, one feature that has remained consistent throughout is the use of Cement as a primary well barrier element. The long-lasting, impermeable nature of the cement matrix means no other material has been considered as an effective, widely-available alternate almost a century from the first cement job. What has changed however, with advancement in the the field of well integrity, is how we approach the cement job design and how certain materials can complement the role of the cement in improving hydraulic isolation. The historical cement job design only targeted a pumpable slurry reaching the desired placement interval, then the design moved to improving liquid slurry properties such as rheologies, fluid-loss and free fluid. Later, the short-term performance as the slurry transitioned through a gel phase to a set state also became an important criterion. More recently, after the renewed global focus on well integrity as learning from disasters such as Macondo, the annular cement’s role as a well barrier has become a major focal area for any well construction program.\u0000 This paper presents a systematic approach in designing cement systems that promise long-term well integrity starting with the root-cause identification, simulating the effect on the cement sheath, required modification of the design, and finally the application and associated results.","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"8 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123457989","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}
Drill cuttings waste was recycled into new use and pilot project to utilize drill cutting waste in road and construction application were carried out. This work describes strategy and best practice to engage regulator in order to unlock regulatory requirements for the pilot on drill cutting waste utilization. Characterization of drill cuttings waste was carried out and its regulatory requirements as indicated in waste management plan and EIA were investigated in parallel to the study on technical feasibility to utilize drill cuttings waste. Equally important is investigation on the rule and regulation relevant to areas and/or industries that the drill cuttings waste will be used for. These regulatory requirements must be clearly identified in an early stage of the pilot project as it will indicate necessary analytical tests to be carried out and will provide information for designing of an environmental impact assessment and monitoring program. Drill cuttings waste is classified into two groups based on type of drilling mud used. Drill cuttings from upper section of well contaminated with water-based mud, called top-hole drill cuttings, is classified as non-hazardous waste while drill cuttings from lower section of well contaminated with synthetic-based mud, called bottom-hole drill cuttings, is classified as hazardous-minor waste. Physical properties of the drill cuttings waste such as pH, conductivity, salinity, chemical properties on chloride contents as well as heavy metal contents must be analyzed and identified to be within the standard limit. These analytical results provide necessary technical information for regulator to make decision based upon in order to support the drill cuttings waste utilization pilot. Based on characteristic of road usage and potential wear and tear of the pilot recycled drill cuttings road, environmental impact assessment and monitoring program on soil, surface water, and subsurface water on areas closed to the pilot site were performed prior and after construction of the pilot road. This environmental impact assessment and monitoring program provides track record of technical analytical data which is essential supporting information for regulator's consideration and endorsement on the future modification of EIA's regulatory requirements. This work demonstrates that good understanding on classification of the drill cuttings waste, its regulatory requirements, characteristic of application the drill cuttings waste will be used for, and its relevant legislations are essential. This information indicates necessary technical analyses required to be performed in order to obtain important technical data to unlock regulatory requirements. Drill cuttings waste utilization not only save waste management cost, but also reduce environmental footprint. This approach can be applied to utilization of other type of waste as well.
{"title":"Unlock Regulatory Requirements for Drill Cuttings Waste Utilisation Pilot","authors":"P. Wattana, Jutharat Wondee, Surasak Chonchirdsin","doi":"10.2118/209930-ms","DOIUrl":"https://doi.org/10.2118/209930-ms","url":null,"abstract":"\u0000 Drill cuttings waste was recycled into new use and pilot project to utilize drill cutting waste in road and construction application were carried out. This work describes strategy and best practice to engage regulator in order to unlock regulatory requirements for the pilot on drill cutting waste utilization.\u0000 Characterization of drill cuttings waste was carried out and its regulatory requirements as indicated in waste management plan and EIA were investigated in parallel to the study on technical feasibility to utilize drill cuttings waste. Equally important is investigation on the rule and regulation relevant to areas and/or industries that the drill cuttings waste will be used for. These regulatory requirements must be clearly identified in an early stage of the pilot project as it will indicate necessary analytical tests to be carried out and will provide information for designing of an environmental impact assessment and monitoring program.\u0000 Drill cuttings waste is classified into two groups based on type of drilling mud used. Drill cuttings from upper section of well contaminated with water-based mud, called top-hole drill cuttings, is classified as non-hazardous waste while drill cuttings from lower section of well contaminated with synthetic-based mud, called bottom-hole drill cuttings, is classified as hazardous-minor waste. Physical properties of the drill cuttings waste such as pH, conductivity, salinity, chemical properties on chloride contents as well as heavy metal contents must be analyzed and identified to be within the standard limit. These analytical results provide necessary technical information for regulator to make decision based upon in order to support the drill cuttings waste utilization pilot. Based on characteristic of road usage and potential wear and tear of the pilot recycled drill cuttings road, environmental impact assessment and monitoring program on soil, surface water, and subsurface water on areas closed to the pilot site were performed prior and after construction of the pilot road. This environmental impact assessment and monitoring program provides track record of technical analytical data which is essential supporting information for regulator's consideration and endorsement on the future modification of EIA's regulatory requirements.\u0000 This work demonstrates that good understanding on classification of the drill cuttings waste, its regulatory requirements, characteristic of application the drill cuttings waste will be used for, and its relevant legislations are essential. This information indicates necessary technical analyses required to be performed in order to obtain important technical data to unlock regulatory requirements. Drill cuttings waste utilization not only save waste management cost, but also reduce environmental footprint. This approach can be applied to utilization of other type of waste as well.","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"49 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124057640","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In order to ensure the national demand for peak shaving and supply guarantee, the project of Xiangguosi underground gas storage capacity expansion for target productivity has been proposed and being carried out. For the purpose of effectively guiding the optimization of the operation upper limit pressure of the gas storage and ensuring its long-term safe operation, it is urgently needed to carry out the assessment of the integrity of the cap rock of the gas storage and the stability of its faults. Based on geological, seismic, logging, dynamic monitoring data and core experimental data, this paper established static and dynamic geomechanical models of the gas storage and analyzed the characteristics of the in-situ stress of different layers of it to simulate and evaluate the stability of the cap rock, underpinning layer and faults of reservoir under different pore pressure. The results showed that 5 reservoir-controlling faults had no risk of fault activation in the early operation of the gas storage and the current stress conditions, with good sealing performance, and when the reservoir pressure was 6MPa higher than the original formation pressure, there was a risk of instability in the integrity of the gas storage. The research results finely and quantitatively evaluated the operation safety of the gas storage under the influence of the dynamic stress field, and had important guiding significance for the optimization of the operation plan of the gas storage.
{"title":"Study on 4D Geomechanical Application in Fault Sealing Capacity Evaluation of Underground Gas Storage","authors":"Yu Luo, Long-xin Li, Yuan Zhou, Limin Li, Yuchao Zhao, Hua Wei, Qiyao Liu, Xiao Liu, Xingning Huang, Thanapol Singjaroen","doi":"10.2118/209853-ms","DOIUrl":"https://doi.org/10.2118/209853-ms","url":null,"abstract":"\u0000 In order to ensure the national demand for peak shaving and supply guarantee, the project of Xiangguosi underground gas storage capacity expansion for target productivity has been proposed and being carried out. For the purpose of effectively guiding the optimization of the operation upper limit pressure of the gas storage and ensuring its long-term safe operation, it is urgently needed to carry out the assessment of the integrity of the cap rock of the gas storage and the stability of its faults. Based on geological, seismic, logging, dynamic monitoring data and core experimental data, this paper established static and dynamic geomechanical models of the gas storage and analyzed the characteristics of the in-situ stress of different layers of it to simulate and evaluate the stability of the cap rock, underpinning layer and faults of reservoir under different pore pressure. The results showed that 5 reservoir-controlling faults had no risk of fault activation in the early operation of the gas storage and the current stress conditions, with good sealing performance, and when the reservoir pressure was 6MPa higher than the original formation pressure, there was a risk of instability in the integrity of the gas storage. The research results finely and quantitatively evaluated the operation safety of the gas storage under the influence of the dynamic stress field, and had important guiding significance for the optimization of the operation plan of the gas storage.","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"23 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133936458","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 permanent tubing patch is a primary method widely used to isolate water production zones, especially in slim-hole wells. As the name implies, the permanent tubing patch is non-retrievable equipment and presents a significant challenge when removal is needed. None of the global records of permanent tubing patches installed in slim-hole wells demonstrate successful removal. This paper will discuss the methods used to achieve the first-ever Coiled Tubing (CT) milling of a permanent tubing patch in a slim-hole well. CT was selected to convey the BHA for milling the tubing patch sealing section. An eccentric pilot milling bit (2.780 in OD) was carefully designed as it needed to pass an ID restriction (2.813 in) in the Downhole Safety Valve (DHSV) while still being able to peel off the tubing patch sealing ID (2.250 in) until reaching the full drift of tubing ID (2.992 in) and ensure that the tubing wall would not be damaged during the milling operation. Once the tubing patch sealing section was removed, a braided-line (WL) operation was run to pull free and retrieve the tubing patch body to surface. The well was then restored to enable further intervention and production. CT performed the milling operation flawlessly, and a carefully designed surface equipment stack-up design provided downhole tool deployment accessibility and convenience for both CT and WL intervention. Nitrified fluid was used with CT to mitigate loss problems in several depleted zones above the milling depth. As a result, the tubing patch seal was successfully milled without jeopardizing the tubing integrity. Once the tubing patch seal element was successfully removed and the patch body became free, the WL was deployed through the CT stack to fish the tubing patch body. This is the first-ever operation to remove and retrieve a permanent tubing patch to the surface in this way without damaging the primary completion. Its success results from a well-thought-out pilot mill bit design and careful execution. This case study can now be shared across the industry to improve intervention efficiency and minimize the chance of early plug and abandonment due to permanent tubing patch removal issues.
{"title":"The First Application of Permanent Tubing Patch Milling With Very Narrow Clearance in a Slimhole well with a Newly Engineered Pilot Mill Bit Design for Coiled Tubing, Offshore Thailand","authors":"Monchai Nimsuk, Treepun Tipapong, Surapong Somjai, Thanawee Kreethapon, Nophadol Jiemsawat, Tuanangkoon Daohmareeyor, Arweephan Kangsadarn, Reawat Wattanasuwankorn, Prapas Phayakrangsee","doi":"10.2118/209881-ms","DOIUrl":"https://doi.org/10.2118/209881-ms","url":null,"abstract":"\u0000 The permanent tubing patch is a primary method widely used to isolate water production zones, especially in slim-hole wells. As the name implies, the permanent tubing patch is non-retrievable equipment and presents a significant challenge when removal is needed. None of the global records of permanent tubing patches installed in slim-hole wells demonstrate successful removal. This paper will discuss the methods used to achieve the first-ever Coiled Tubing (CT) milling of a permanent tubing patch in a slim-hole well.\u0000 CT was selected to convey the BHA for milling the tubing patch sealing section. An eccentric pilot milling bit (2.780 in OD) was carefully designed as it needed to pass an ID restriction (2.813 in) in the Downhole Safety Valve (DHSV) while still being able to peel off the tubing patch sealing ID (2.250 in) until reaching the full drift of tubing ID (2.992 in) and ensure that the tubing wall would not be damaged during the milling operation. Once the tubing patch sealing section was removed, a braided-line (WL) operation was run to pull free and retrieve the tubing patch body to surface. The well was then restored to enable further intervention and production.\u0000 CT performed the milling operation flawlessly, and a carefully designed surface equipment stack-up design provided downhole tool deployment accessibility and convenience for both CT and WL intervention. Nitrified fluid was used with CT to mitigate loss problems in several depleted zones above the milling depth. As a result, the tubing patch seal was successfully milled without jeopardizing the tubing integrity. Once the tubing patch seal element was successfully removed and the patch body became free, the WL was deployed through the CT stack to fish the tubing patch body.\u0000 This is the first-ever operation to remove and retrieve a permanent tubing patch to the surface in this way without damaging the primary completion. Its success results from a well-thought-out pilot mill bit design and careful execution. This case study can now be shared across the industry to improve intervention efficiency and minimize the chance of early plug and abandonment due to permanent tubing patch removal issues.","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"80 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115997102","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}
Olabode Ajibola, J. Sheng, E. Unal, Christopher Armistead, James Rutley, J. Smitherman
The reservoir pressure trend prediction for the potash area of Delaware Basin would enhance its optimum producible depths selection. It is significant for safe drilling, effective, and efficient governmental drilling permits approval in the area. Avoiding kicks, blowouts, fluid loss, pipe differential sticking, and heaving shales prevention improved wellbore control. This also leads to dependable wellbore integrity and better reservoir or well fluids control which are some of the benefits of proper reservoir pressure trend prediction. This study used the reservoir pressures predicted by Multilinear Regression machine learning model to verify the reservoir pressures calculated using drilling data from the potash area. Then, pressure trends are built for the area with Petra using geophysical log cross-sections. The results from these pressure trends are presented in 2-Dimensional and 3-Dimensional forms for the area to connect permitting optimum safely producible depths with hydrocarbon production. The study utilized drilling and well logs data from about 229 wells. All the wells were drilled and completed within the Potash Area to at least the base of Wolfcamp formation. The geophysical log cross-sections were created in 2- and 3-Dimensional forms using Petra, Matlab, and R machine languages. For the Multilinear Regression model over 330,000 data points from model parameters such as Deep & Shallow Laterolog Resistivities, Gamma Ray log, Neutron & Density Porosity Limestone logs, Sonic logs, caliper log, depth, lithology, mud weight, Photoelectric Cross-section, average porosity, water saturation, corrected bulk density log, and bulk density log were used. The datasets were grouped into 70 percent training and 30 percent testing randomly. The Multilinear Regression model predicted the reservoir pressures with high accuracy where the coefficient of determination (R2) is greater than 0.990. The Root Mean Square Error (RMSE) ranges from 0.0086 to 0.034 psi/ft between the predicted and the measured reservoir pressure data. The validation of the Regression model was done using another dataset. The reservoir pressures were predicted by the model with high accuracy using the validation dataset. The coefficient of determination (R2) is 0.99. This study shows that the regression model is reliable and can predict the reservoir pressures for the area accurately using well logs, drilling data, and geophysical data. Furthermore, verified reservoir pressures is used to build reservoir pressure trends for the area. The reservoir pressure trend can then be used to select the optimum producible depths in the area in order to promote safe, cost efficient, and optimum hydrocarbon recovery in the area. This study will also promote concurrent operations in prospecting for, developing, and producing oil and gas and potash deposits owned by the United States within the Designated Potash Area (DPA) (BLM Secretary Order, 2012).
{"title":"Evaluating Reservoir Pressure Gradient Trend for the Delaware Basin’s Potash Area Using Machine Learning & Geophysical Log Cross-Sections Approach","authors":"Olabode Ajibola, J. Sheng, E. Unal, Christopher Armistead, James Rutley, J. Smitherman","doi":"10.2118/209899-ms","DOIUrl":"https://doi.org/10.2118/209899-ms","url":null,"abstract":"\u0000 The reservoir pressure trend prediction for the potash area of Delaware Basin would enhance its optimum producible depths selection. It is significant for safe drilling, effective, and efficient governmental drilling permits approval in the area. Avoiding kicks, blowouts, fluid loss, pipe differential sticking, and heaving shales prevention improved wellbore control. This also leads to dependable wellbore integrity and better reservoir or well fluids control which are some of the benefits of proper reservoir pressure trend prediction.\u0000 This study used the reservoir pressures predicted by Multilinear Regression machine learning model to verify the reservoir pressures calculated using drilling data from the potash area. Then, pressure trends are built for the area with Petra using geophysical log cross-sections. The results from these pressure trends are presented in 2-Dimensional and 3-Dimensional forms for the area to connect permitting optimum safely producible depths with hydrocarbon production. The study utilized drilling and well logs data from about 229 wells. All the wells were drilled and completed within the Potash Area to at least the base of Wolfcamp formation.\u0000 The geophysical log cross-sections were created in 2- and 3-Dimensional forms using Petra, Matlab, and R machine languages. For the Multilinear Regression model over 330,000 data points from model parameters such as Deep & Shallow Laterolog Resistivities, Gamma Ray log, Neutron & Density Porosity Limestone logs, Sonic logs, caliper log, depth, lithology, mud weight, Photoelectric Cross-section, average porosity, water saturation, corrected bulk density log, and bulk density log were used. The datasets were grouped into 70 percent training and 30 percent testing randomly. The Multilinear Regression model predicted the reservoir pressures with high accuracy where the coefficient of determination (R2) is greater than 0.990. The Root Mean Square Error (RMSE) ranges from 0.0086 to 0.034 psi/ft between the predicted and the measured reservoir pressure data. The validation of the Regression model was done using another dataset. The reservoir pressures were predicted by the model with high accuracy using the validation dataset. The coefficient of determination (R2) is 0.99. This study shows that the regression model is reliable and can predict the reservoir pressures for the area accurately using well logs, drilling data, and geophysical data. Furthermore, verified reservoir pressures is used to build reservoir pressure trends for the area.\u0000 The reservoir pressure trend can then be used to select the optimum producible depths in the area in order to promote safe, cost efficient, and optimum hydrocarbon recovery in the area. This study will also promote concurrent operations in prospecting for, developing, and producing oil and gas and potash deposits owned by the United States within the Designated Potash Area (DPA) (BLM Secretary Order, 2012).","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"32 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116324961","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 well-planning process involves many parties collaborating and optimizing various design aspects to deliver the best well construction. There are still many challenges for a well-planning team to manage the process and formulate the best drilling program. Many tasks are cumbersome and time-consuming; ensuring coherency within various parts of the drilling program is also difficult. Digital transformation integrates digital technology to create new or modify existing workflows that can fundamentally change how we operate and deliver value. The oil and gas industry is expecting to redefine its boundaries through digitalization. Leveraging digital technology can act as an enabler to tackle various challenges, improve efficiency, and provide greater value in all aspects of the oil and gas industry, including a well-planning process. In this paper, the author discusses various examples of how digital technology is used in well planning and how it changes our way of working, improves working efficiency, and delivers better results. Cloud technologies provide a new platform for collaboration and break the working culture in silos. It also provides a new way to communicate, share information, and eliminate multiple data transfers and manual inputs. Cloud computations can scale the computing resource elastically, enabling simple to complex modeling. Engineers can simulate various scenarios more quickly to decide the best plan. Various automation, from smart input to auto engineering analysis, are used to minimize mistakes, provide real-time feedback while designing, and improve working efficiency. The use of big data and machine learning can improve the accuracy of engineering analysis and provide an advisory model that can minimize the risk and uncertainty during execution. All these digital technologies are implemented in a cloud-based well construction planning solution. Many other digital capabilities learned from other industry applications are also implemented to improve user experiences. Examples are a notification system, open architecture to connect to other databases and cross domain information, a digital review-and-approve system, traffic light validation system, multidimensional visualization, and automated report generation for the coherent drilling program. Leveraging the digital transformation in the well construction planning process through a cloud-based application enables the planning team to maximize the results by giving them access to all the data and science they need in a single, common system. The solution increases planning efficiency and enhances well designs through automated end-to-end workflows, cross-company and cross-domain collaboration, auto-validation, and integrated offset knowledge; this accelerates continuous improvement of well construction activities.
{"title":"Leveraging Digital Transformation in the Well Construction Planning Process","authors":"H. Suryadi","doi":"10.2118/209893-ms","DOIUrl":"https://doi.org/10.2118/209893-ms","url":null,"abstract":"\u0000 The well-planning process involves many parties collaborating and optimizing various design aspects to deliver the best well construction. There are still many challenges for a well-planning team to manage the process and formulate the best drilling program. Many tasks are cumbersome and time-consuming; ensuring coherency within various parts of the drilling program is also difficult.\u0000 Digital transformation integrates digital technology to create new or modify existing workflows that can fundamentally change how we operate and deliver value. The oil and gas industry is expecting to redefine its boundaries through digitalization. Leveraging digital technology can act as an enabler to tackle various challenges, improve efficiency, and provide greater value in all aspects of the oil and gas industry, including a well-planning process.\u0000 In this paper, the author discusses various examples of how digital technology is used in well planning and how it changes our way of working, improves working efficiency, and delivers better results. Cloud technologies provide a new platform for collaboration and break the working culture in silos. It also provides a new way to communicate, share information, and eliminate multiple data transfers and manual inputs. Cloud computations can scale the computing resource elastically, enabling simple to complex modeling. Engineers can simulate various scenarios more quickly to decide the best plan. Various automation, from smart input to auto engineering analysis, are used to minimize mistakes, provide real-time feedback while designing, and improve working efficiency. The use of big data and machine learning can improve the accuracy of engineering analysis and provide an advisory model that can minimize the risk and uncertainty during execution. All these digital technologies are implemented in a cloud-based well construction planning solution.\u0000 Many other digital capabilities learned from other industry applications are also implemented to improve user experiences. Examples are a notification system, open architecture to connect to other databases and cross domain information, a digital review-and-approve system, traffic light validation system, multidimensional visualization, and automated report generation for the coherent drilling program.\u0000 Leveraging the digital transformation in the well construction planning process through a cloud-based application enables the planning team to maximize the results by giving them access to all the data and science they need in a single, common system. The solution increases planning efficiency and enhances well designs through automated end-to-end workflows, cross-company and cross-domain collaboration, auto-validation, and integrated offset knowledge; this accelerates continuous improvement of well construction activities.","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130883960","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}
Coiled Tubing (CT) is a commonly used well intervention technique for sand/debris cleanout, milling, fishing, cementing, and gas lifting applications. Performing cement plug operations with CT in high-pressure live wells can present a relatively high level of risk of getting stuck, improper placement of cement plugs, and poor quality cement plugs. In this scenario, an offshore well in Vietnam was left with CT held only on the surface by the Blow Out Preventers (BOP) after getting stuck downhole more than a year previously. Retrieval of the CT was required without any downhole barrier in place and circumstances that made the conventional killing of the well difficult. This paper will discuss the equipment necessary, factors to consider in the job design, sealant design with lab testing, and describe the technique used to safely retrieve the fish from the well. During the design phase of the solution, risk assessments were carried out to cover various scenarios such as: Poor condition of one or more of the CT string, BOP, dual ball kelly cock valve, double flapper check valve. Inability of the Organic Crosslinked Polymer sealant to hold well pressure. Difficulty in latching the surface CT stump, and the potential requirement for freezing to establish a surface barrier. Along with the specially designed sealant treatment, multiple yard tests for dressing the sheared CT and latching were performed to represent actual conditions during the operation and allow risk mitigation plans to be put in place. Firstly, the barrier verification process was performed to monitor any well pressure build-up from the downhole/surface pressure reading to confirm a barrier was in place, allowing surface equipment to be rigged up. After this was confirmed, the equipment was rigged up, and a fluid circulation test followed by the inflow test of the double flapper check valve in the bottom hole assembly was performed to verify CT integrity. The first of the organic crosslinked polymer was then pumped to plug inside the CT before electric line (E-line) was run into the CT to cut at the free-point above the stuck location. The second organic crosslinked polymer was then placed to plug between the CT and annulus, forming a barrier allowing the makeup of the spoolable connector. Finally, retrieval of the 1,700 meters of CT string took place without any loss of well control. Retrieving the CT from this high pressure well presented a lot of challenges. Achieving a safe and successful operation showed that with proper planning, design, and risk mitigation plans, a potential well control situation can be prevented with the well being secured and successfully returned to production. This paper can now serve as a guideline for future operations with similar circumstances requiring retrieval of stuck CT from high-pressure wells where it has been held on surface for an extended period of time.
{"title":"The Use of an Organic Crosslinked Polymer Sealant as a Barrier to Retrieve Stuck Coiled Tubing from a Live High Pressure Well After Over a Year: Case Study from Offshore Vietnam","authors":"Tuanangkoon Daohmareeyor, Deric Leong Wei Lock, Reawat Wattanasuwan","doi":"10.2118/209856-ms","DOIUrl":"https://doi.org/10.2118/209856-ms","url":null,"abstract":"\u0000 Coiled Tubing (CT) is a commonly used well intervention technique for sand/debris cleanout, milling, fishing, cementing, and gas lifting applications. Performing cement plug operations with CT in high-pressure live wells can present a relatively high level of risk of getting stuck, improper placement of cement plugs, and poor quality cement plugs. In this scenario, an offshore well in Vietnam was left with CT held only on the surface by the Blow Out Preventers (BOP) after getting stuck downhole more than a year previously. Retrieval of the CT was required without any downhole barrier in place and circumstances that made the conventional killing of the well difficult. This paper will discuss the equipment necessary, factors to consider in the job design, sealant design with lab testing, and describe the technique used to safely retrieve the fish from the well.\u0000 During the design phase of the solution, risk assessments were carried out to cover various scenarios such as:\u0000 Poor condition of one or more of the CT string, BOP, dual ball kelly cock valve, double flapper check valve. Inability of the Organic Crosslinked Polymer sealant to hold well pressure. Difficulty in latching the surface CT stump, and the potential requirement for freezing to establish a surface barrier.\u0000 Along with the specially designed sealant treatment, multiple yard tests for dressing the sheared CT and latching were performed to represent actual conditions during the operation and allow risk mitigation plans to be put in place.\u0000 Firstly, the barrier verification process was performed to monitor any well pressure build-up from the downhole/surface pressure reading to confirm a barrier was in place, allowing surface equipment to be rigged up. After this was confirmed, the equipment was rigged up, and a fluid circulation test followed by the inflow test of the double flapper check valve in the bottom hole assembly was performed to verify CT integrity. The first of the organic crosslinked polymer was then pumped to plug inside the CT before electric line (E-line) was run into the CT to cut at the free-point above the stuck location. The second organic crosslinked polymer was then placed to plug between the CT and annulus, forming a barrier allowing the makeup of the spoolable connector. Finally, retrieval of the 1,700 meters of CT string took place without any loss of well control.\u0000 Retrieving the CT from this high pressure well presented a lot of challenges. Achieving a safe and successful operation showed that with proper planning, design, and risk mitigation plans, a potential well control situation can be prevented with the well being secured and successfully returned to production. This paper can now serve as a guideline for future operations with similar circumstances requiring retrieval of stuck CT from high-pressure wells where it has been held on surface for an extended period of time.","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"55 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"117277753","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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