Although polymer flooding technology has been widely applied and achieved remarkable effect of increasing oil. Yet the "entry profile inversion" phenomenon occurs inevitably in its later stage, which seriously affects the development effect. The dispersion system is a novel flooding system developed in recent years. Due to its excellent performance and advanced mechanism, it can slow down the process of profile inversion, and achieve the goal of deep fluid diversion and expanding swept volume. The dispersion system consists of dispersion particles and its carrier fluid. After coming into porous media, it shows the properties of "plugging large pore and leave the small one open" and the motion feature of "trapping, deformation, migration". In this paper, the reservoir adaptability evaluation, plugging and deformation characteristics of dispersion system in pore throat is explored. On this basis, by adopting the microfluidic technology and CT tomography technology, the research on its oil displacement mechanism is further carried out. Furthermore, the typical field application case is analyzed. Results show that, particles have good performance and transport ability in porous media. The reservoir adaptability evaluation results can provide basis for field application scheme design. Through microfluidic experiments, the temporary plugging and deformation characteristics of particles in the pore throat are explored. Also, the particle phase separation occurs during the injection process of dispersion system into the core, which makes the particles enter and plug the large pore in the high permeability layer. Therefore, their carrier fluid displace oil in the small pore, which works in cooperation and causes no porous media and the distribution law of remaining oil during displacement process are analyzed. It shows that, particles presents the motion feature of "migration, trapping, and deformation" in the porous media, which can realize deep fluid diversion and expand swept volume. 3D macro physical simulation experiment shows that, particles can achieve the goal of enhance oil recovery. Finally, the dispersion flooding technology has been applied in different oilfields, which all obtained great success. Through interdisciplinary innovative research methods, the oil displacement mechanism and field application of dispersion system is researched, which proves its progressiveness and superiority. The research results provide theoretical basis and technical support for the enhancing oil recovery significantly.
{"title":"The Latest Research Progress of Micro-Nano Dispersion System Conformance Control Technology–From Theoretical Research in Laboratory to Field Trail","authors":"Zhe Sun, Xiujun Wang","doi":"10.2523/iptc-22726-ms","DOIUrl":"https://doi.org/10.2523/iptc-22726-ms","url":null,"abstract":"\u0000 Although polymer flooding technology has been widely applied and achieved remarkable effect of increasing oil. Yet the \"entry profile inversion\" phenomenon occurs inevitably in its later stage, which seriously affects the development effect. The dispersion system is a novel flooding system developed in recent years. Due to its excellent performance and advanced mechanism, it can slow down the process of profile inversion, and achieve the goal of deep fluid diversion and expanding swept volume.\u0000 The dispersion system consists of dispersion particles and its carrier fluid. After coming into porous media, it shows the properties of \"plugging large pore and leave the small one open\" and the motion feature of \"trapping, deformation, migration\". In this paper, the reservoir adaptability evaluation, plugging and deformation characteristics of dispersion system in pore throat is explored. On this basis, by adopting the microfluidic technology and CT tomography technology, the research on its oil displacement mechanism is further carried out. Furthermore, the typical field application case is analyzed.\u0000 Results show that, particles have good performance and transport ability in porous media. The reservoir adaptability evaluation results can provide basis for field application scheme design. Through microfluidic experiments, the temporary plugging and deformation characteristics of particles in the pore throat are explored. Also, the particle phase separation occurs during the injection process of dispersion system into the core, which makes the particles enter and plug the large pore in the high permeability layer. Therefore, their carrier fluid displace oil in the small pore, which works in cooperation and causes no porous media and the distribution law of remaining oil during displacement process are analyzed. It shows that, particles presents the motion feature of \"migration, trapping, and deformation\" in the porous media, which can realize deep fluid diversion and expand swept volume. 3D macro physical simulation experiment shows that, particles can achieve the goal of enhance oil recovery. Finally, the dispersion flooding technology has been applied in different oilfields, which all obtained great success.\u0000 Through interdisciplinary innovative research methods, the oil displacement mechanism and field application of dispersion system is researched, which proves its progressiveness and superiority. The research results provide theoretical basis and technical support for the enhancing oil recovery significantly.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"117224670","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}
Oil reserves with oil viscosity above 150 mPa·s account for a large proportion of the Bohai Oilfield. However, due to the low mobility of heavy oil, and low sweep efficiency of injected fluid, the recovery factor of heavy oil is always low. A new amphiphilic polymer (activator), which can effectively disassemble the accumulation of asphaltene molecular layer of heavy oil, thus reducing oil viscosity has been developed in the lab and applied for two injection wells in Bohai Oilfield for a pilot trial. In this paper, the pilot trial of heavy-oil activator flooding (HAF) is comprehensively evaluated in both injectivity, production, and interwell connectivity analyses. The apparent injectivity index, Hall plot analysis, injection profile measurement for different layers, and PI test methods are applied to study the seepage resistance build-up effect at injection wells. Waterflooding characteristic curve method is implemented for history matching and oil incremental analysis. The interwell connectivity between wells is characterized by the Capacitance Resistance model (CRM). The injection trials showed great seepage resistance build-up effects at two activator injectors. There are apparent deviations in Hall plots after the activator injection. Activator flooding enables uniform water injection profiles for different layers. The PI tests show that the pressure drop speeds get lowered during the injection period. As for the oil incremental effect evaluation, the theoretical waterflooding characteristic curve function gives an estimation of the incremental oil production to be 1.77×104 m3 during the evaluation period. CRM analysis indicates that the connectivity between injector I2 and producer P4 is higher than that of other wells, and the time lag of getting a response by the activator fluid is smaller than other wells, which is an indication of potential fluid channeling in the flow path. It is validated by the high concentration of produced agent from P4 during HAF. The successful implementation of the activator flooding pilot trial proves that the lab results of amphiphilic polymers can be scaled up to field scale and it plays an important role in the de-risking of full-field implementation. Besides, it shed light upon the effective displacement of heavy oil with a viscosity greater than 150 mPa·s in offshore reservoirs by amphiphilic polymers.
{"title":"A Successful Activator Flooding Pilot Test in Offshore Oilfield: A Comprehensive Evaluation and Interpretation","authors":"Yi Jin, Jian Zhang, Engao Tang, Xudong Wang, Yuyang Liu, Wensheng Zhou, Zhijie Wei","doi":"10.2523/iptc-22880-ms","DOIUrl":"https://doi.org/10.2523/iptc-22880-ms","url":null,"abstract":"\u0000 Oil reserves with oil viscosity above 150 mPa·s account for a large proportion of the Bohai Oilfield. However, due to the low mobility of heavy oil, and low sweep efficiency of injected fluid, the recovery factor of heavy oil is always low. A new amphiphilic polymer (activator), which can effectively disassemble the accumulation of asphaltene molecular layer of heavy oil, thus reducing oil viscosity has been developed in the lab and applied for two injection wells in Bohai Oilfield for a pilot trial.\u0000 In this paper, the pilot trial of heavy-oil activator flooding (HAF) is comprehensively evaluated in both injectivity, production, and interwell connectivity analyses. The apparent injectivity index, Hall plot analysis, injection profile measurement for different layers, and PI test methods are applied to study the seepage resistance build-up effect at injection wells. Waterflooding characteristic curve method is implemented for history matching and oil incremental analysis. The interwell connectivity between wells is characterized by the Capacitance Resistance model (CRM).\u0000 The injection trials showed great seepage resistance build-up effects at two activator injectors. There are apparent deviations in Hall plots after the activator injection. Activator flooding enables uniform water injection profiles for different layers. The PI tests show that the pressure drop speeds get lowered during the injection period. As for the oil incremental effect evaluation, the theoretical waterflooding characteristic curve function gives an estimation of the incremental oil production to be 1.77×104 m3 during the evaluation period. CRM analysis indicates that the connectivity between injector I2 and producer P4 is higher than that of other wells, and the time lag of getting a response by the activator fluid is smaller than other wells, which is an indication of potential fluid channeling in the flow path. It is validated by the high concentration of produced agent from P4 during HAF.\u0000 The successful implementation of the activator flooding pilot trial proves that the lab results of amphiphilic polymers can be scaled up to field scale and it plays an important role in the de-risking of full-field implementation. Besides, it shed light upon the effective displacement of heavy oil with a viscosity greater than 150 mPa·s in offshore reservoirs by amphiphilic polymers.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"28 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123969096","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 the Gulf of Thailand, PTT Exploration and Production are operating 231 platforms. And with facility ages up to 40 years, inspection programs are required to be more rigorous. Conventional inspection concepts, mainly requiring human direct assessment and data manipulation, are labor-intensive and requires facility shutdown for safe access. Therefore, company have been developing and deploying advanced NDE and digitalization to assure integrity with optimum inspection strategies, while keeping operational cost reasonable and avoiding work backlogs. The initiatives of advanced NDE (Non-Destructive Examination) and digitalization started in 2016, throughout the process of technical survey, feasibility study, proof-of-concept testing and field testing. Specific tools, parameters, demonstration pieces, procedures and interpretation have been chosen, analyzed and developed for specific inspection tasks for acceptable sensitivity and accuracy of NDE. At the same time, under the concept of total inspection and integrity management, company have implemented digitalization. The digitalization has been developed to supplement, aid and even replace conventional inspection data manipulation methods, which are based mainly on personnel. In this paper, sample cases of the applications of LRUT (Long Range Ultrasonic Testing) to detect and monitor corrosion under riser clamps, PAUT (Phase Arrayed Ultrasonic Testing) to monitor thermal fatigue cracking of vessels, and home-made Drones to monitor flares (while operating) and inspect tank internals are discussed. It has been found that, with proven, specific tool parameters and procedures, target damages and defects can be identified and monitored. 62% reduction in downtime per year required for safe access and assessment are attained. From the sample cases, cost saving at 17.83MMUSD per year is realized. Also, sample cases of digitalization are discussed. The paper describes cases of ML (Machine Learning) for image processing to detect and identify cracking, for characterization and prediction of metal loss. cases of RPA (Robot Processing Automation) for manipulating inspection results are described too. It has been found that ML provides 80% improvement in terms of accuracy and of interpretation time. RPA 71% reduces the time of manipulating inspection/NDE data, anomalies and metal loss calculation, apart from eliminating human errors. Finally, integrity management platform 21% saves direct inspection cost, by improving inspection strategies. As on-stream inspection concept is more important for increasing numbers of aging Oil and Gas facilities, advanced NDE methods play more vital roles. And with increasingly powerful computer-processing, digitalization is proven to provide higher accuracy and efficiency, with minimal errors. Concepts and sample cases explained in this paper reinforce these ideas with realized benefits of both cost saving and integrity assurance.
{"title":"Plant Integrity Assurance by the Development and Deployment of Advanced NDE and Digitalization","authors":"Thirut Loertthiraporn, Passaworn Silakorn, Kunachat Witoonsoontorn, Athipkiat Lertthanasart, Suthisak Thepsriha, Chatchai Laemkhowthong","doi":"10.2523/iptc-22869-ms","DOIUrl":"https://doi.org/10.2523/iptc-22869-ms","url":null,"abstract":"\u0000 In the Gulf of Thailand, PTT Exploration and Production are operating 231 platforms. And with facility ages up to 40 years, inspection programs are required to be more rigorous. Conventional inspection concepts, mainly requiring human direct assessment and data manipulation, are labor-intensive and requires facility shutdown for safe access. Therefore, company have been developing and deploying advanced NDE and digitalization to assure integrity with optimum inspection strategies, while keeping operational cost reasonable and avoiding work backlogs.\u0000 The initiatives of advanced NDE (Non-Destructive Examination) and digitalization started in 2016, throughout the process of technical survey, feasibility study, proof-of-concept testing and field testing. Specific tools, parameters, demonstration pieces, procedures and interpretation have been chosen, analyzed and developed for specific inspection tasks for acceptable sensitivity and accuracy of NDE. At the same time, under the concept of total inspection and integrity management, company have implemented digitalization. The digitalization has been developed to supplement, aid and even replace conventional inspection data manipulation methods, which are based mainly on personnel.\u0000 In this paper, sample cases of the applications of LRUT (Long Range Ultrasonic Testing) to detect and monitor corrosion under riser clamps, PAUT (Phase Arrayed Ultrasonic Testing) to monitor thermal fatigue cracking of vessels, and home-made Drones to monitor flares (while operating) and inspect tank internals are discussed. It has been found that, with proven, specific tool parameters and procedures, target damages and defects can be identified and monitored. 62% reduction in downtime per year required for safe access and assessment are attained. From the sample cases, cost saving at 17.83MMUSD per year is realized.\u0000 Also, sample cases of digitalization are discussed. The paper describes cases of ML (Machine Learning) for image processing to detect and identify cracking, for characterization and prediction of metal loss. cases of RPA (Robot Processing Automation) for manipulating inspection results are described too. It has been found that ML provides 80% improvement in terms of accuracy and of interpretation time. RPA 71% reduces the time of manipulating inspection/NDE data, anomalies and metal loss calculation, apart from eliminating human errors. Finally, integrity management platform 21% saves direct inspection cost, by improving inspection strategies.\u0000 As on-stream inspection concept is more important for increasing numbers of aging Oil and Gas facilities, advanced NDE methods play more vital roles. And with increasingly powerful computer-processing, digitalization is proven to provide higher accuracy and efficiency, with minimal errors. Concepts and sample cases explained in this paper reinforce these ideas with realized benefits of both cost saving and integrity assurance.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"24 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125836761","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}
Rahma Wisnu Suryantoro, Yusuf Oktoviyanto, Dionisius Dewanata, Luqman Arif, Despredi Akbar
Rantau is a mature oil field located in Aceh, Indonesia, which has been producing oil since 1928 and reached the peak production in 1970s. The reservoir in Rantau field is already depleted so it needs artificial lift to produce the oil. About 71% of artificial used in Rantau are sucker rod pump (SRP), 26% are electric submersible pump (ESP), and others remaining are gas lift. To maintain production with a high decline rate efficiently gets more challenging with the downhole problem, especially gas interference dan sand problem. In 2020, 78% of well services came from artificial lift wells with sucker rod pumps. The data said that sand problem with gas interference became dominant causes in 74% of the cases. To solve those issues with the limitation of cost and maximizing the effect, modification of tubing pump accessories was chosen. Multiple Preventive Downhole Pump (MPDT) is a modified tubing pump accessory that has seven stages to minimize sand production and separate the associate gas while the fluid was pumping into the surface. The sand separation was effective enough to prevent a huge amount of sand and gas from the reservoir infiltrating the pump assembly, so the sand could not produce to the surface or blocking the standing or traveling valve and gas pound could not occur. The four wells installed with MPDT could exceed their previous run life more than five times. This brings impact on the less well service activity in those wells and for Rantau field in general. During the observation, the fluid sample taken from the wellhead showed no sand to a small amount of sand produced, as the wells produced a small amount to no sand at all we could optimize its parameter to achieve more oil, while when the well produced a huge amount of sand, its parameter could not be optimized or increased which could lead to more sand produced to the surface. In conclusion, well that installed with MPDT become more efficient contributed by longer run life which led to less well service work and increased oil production where its parameter could be optimized. MPDT could prevent reservoir sand getting into the tubing pump, as well as the gas. It is a practical solution for mature oil fields that encounter sand problems as a common challenge in producing oil.
{"title":"Increasing Run Life by Using Multiple Preventive Downhole Pump (MPDT) to Overcome Gas Interference and Sand Problem on Sucker Rod Pump Well","authors":"Rahma Wisnu Suryantoro, Yusuf Oktoviyanto, Dionisius Dewanata, Luqman Arif, Despredi Akbar","doi":"10.2523/iptc-23058-ea","DOIUrl":"https://doi.org/10.2523/iptc-23058-ea","url":null,"abstract":"\u0000 Rantau is a mature oil field located in Aceh, Indonesia, which has been producing oil since 1928 and reached the peak production in 1970s. The reservoir in Rantau field is already depleted so it needs artificial lift to produce the oil. About 71% of artificial used in Rantau are sucker rod pump (SRP), 26% are electric submersible pump (ESP), and others remaining are gas lift. To maintain production with a high decline rate efficiently gets more challenging with the downhole problem, especially gas interference dan sand problem.\u0000 In 2020, 78% of well services came from artificial lift wells with sucker rod pumps. The data said that sand problem with gas interference became dominant causes in 74% of the cases. To solve those issues with the limitation of cost and maximizing the effect, modification of tubing pump accessories was chosen. Multiple Preventive Downhole Pump (MPDT) is a modified tubing pump accessory that has seven stages to minimize sand production and separate the associate gas while the fluid was pumping into the surface.\u0000 The sand separation was effective enough to prevent a huge amount of sand and gas from the reservoir infiltrating the pump assembly, so the sand could not produce to the surface or blocking the standing or traveling valve and gas pound could not occur. The four wells installed with MPDT could exceed their previous run life more than five times. This brings impact on the less well service activity in those wells and for Rantau field in general. During the observation, the fluid sample taken from the wellhead showed no sand to a small amount of sand produced, as the wells produced a small amount to no sand at all we could optimize its parameter to achieve more oil, while when the well produced a huge amount of sand, its parameter could not be optimized or increased which could lead to more sand produced to the surface. In conclusion, well that installed with MPDT become more efficient contributed by longer run life which led to less well service work and increased oil production where its parameter could be optimized.\u0000 MPDT could prevent reservoir sand getting into the tubing pump, as well as the gas. It is a practical solution for mature oil fields that encounter sand problems as a common challenge in producing oil.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"47 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124596952","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}
N. Varma, Avdesh Negi, Manish Kumar, Shailesh Chauhan, A. Bohra, M. Kothiyal
Aishwariya Barmer Hill (ABH) field area consists of a laminated high porosity (25-35%), low permeability (~1 mD) unit of 50-250 meters thick hydrocarbon bearing payzone. With the success of the first 6 pilot wells, it was decided to extend to the whole field with more than 44 horizontal wells. The horizontal wells are ~2300-2600 mMD long, lateral average length of 1000m and multistage hydraulic fracturing (10-17). These wells face numerous complications due to high gas-oil ratio, sand production, and corrosion tendencies because of high CO2 mole percent concentration (40-60%) in fluid. Further complications include downhole pumps setting at very high deviation (60-65 deg), rod failures-wear in high deviation wells, rod rotation due to deviation and gradual productivity declines due to sand deposition at lower side of downhole completion. Due to low permeability and low mobility fluid nature, it was necessary to find efficient ways to enhance the overall hydrocarbon recovery factor of the field. Several sensitivities were performed, on the number of wells, number of hydraulic fractures, well design, artificial lift options, water, and gas injection. According to the sensitivities results, the best developed scenario envisages high number of multiple frac wells to increase the recovery factor. Based on the detailed evaluation of available artificial lift options, SRP was selected over Jet pumps as the most suitable artificial lift considering the requirement of large drawdowns & operating costs of lifts. The risk of gas issues was mitigated by keeping the tubing-production casing annulus vented and further alleviated by running suitable downhole gas separators. Other problems were analyzed, and multiple attempts of solution implementation were done. This paper addresses an inhouse ways to tackle sand, high gas rate issues, along with rectifications &learning of other problems faced during the last 3 years of field operations, including digitalization projects for visualization of well behavior. This paper also addresses a few remarkable calculated parameters which are - actual production loss calculations whenever well is shut-in (considering wellbore column storage effects), calculated gas free liquid level pump submergence and pump intake pressure from pump load live data. The purpose of this paper is to describe technical & operational challenges along with lessons learnt/solutions implemented in last 3 years.
Aishwariya Barmer Hill (ABH)油田由一个50-250米厚的含油气层状高孔隙度(25-35%)、低渗透率(~1 mD)单元组成。随着前6口试验井的成功，决定将整个油田扩展到44口以上的水平井。水平井长2300 ~ 2600mmd，横向平均长度1000m，多级水力压裂(10 ~ 17)。由于高气油比、出砂和高CO2摩尔浓度(40-60%)导致的腐蚀趋势，这些井面临着许多复杂问题。进一步的复杂问题包括:井下泵安装在非常大的斜度(60-65度)，大斜度井中的抽油杆失效磨损，由于斜度导致抽油杆旋转，以及由于井下完井下部积砂导致产能逐渐下降。由于低渗透、低流动性的流体性质，有必要寻找有效的方法来提高油田的整体油气采收率。对井数、水力裂缝数、井设计、人工举升方案、注水和注气等几个敏感性因素进行了分析。根据敏感性结果，最佳开发方案设想了大量多口压裂井以提高采收率。基于对现有人工举升方案的详细评估，考虑到大降压和操作成本的要求，SRP被选为最合适的人工举升方案，而不是喷射泵。通过保持油管-生产套管环空通风，降低了气体问题的风险，并通过安装合适的井下气体分离器进一步降低了风险。对其他问题进行了分析，并进行了多次方案实施尝试。本文介绍了一种解决出砂、高含气量问题的内部方法，以及对过去3年现场作业中遇到的其他问题的纠正和学习，包括用于可视化井动态的数字化项目。本文还讨论了几个值得注意的计算参数，即关井时的实际产量损失计算(考虑井筒柱存储效应)，根据泵负载实时数据计算的无气液位，泵浸入和泵吸入压力。本文的目的是描述技术和运营挑战以及过去3年的经验教训/实施的解决方案。
{"title":"Tight Oil Field Development Challenges, Lessons Learnt and Successful Implementation of Selected Artificial Lift (SRP) Along with Operational & Digital Solutions: ABH Field, Rajasthan, India","authors":"N. Varma, Avdesh Negi, Manish Kumar, Shailesh Chauhan, A. Bohra, M. Kothiyal","doi":"10.2523/iptc-23079-ms","DOIUrl":"https://doi.org/10.2523/iptc-23079-ms","url":null,"abstract":"\u0000 Aishwariya Barmer Hill (ABH) field area consists of a laminated high porosity (25-35%), low permeability (~1 mD) unit of 50-250 meters thick hydrocarbon bearing payzone. With the success of the first 6 pilot wells, it was decided to extend to the whole field with more than 44 horizontal wells. The horizontal wells are ~2300-2600 mMD long, lateral average length of 1000m and multistage hydraulic fracturing (10-17). These wells face numerous complications due to high gas-oil ratio, sand production, and corrosion tendencies because of high CO2 mole percent concentration (40-60%) in fluid. Further complications include downhole pumps setting at very high deviation (60-65 deg), rod failures-wear in high deviation wells, rod rotation due to deviation and gradual productivity declines due to sand deposition at lower side of downhole completion.\u0000 Due to low permeability and low mobility fluid nature, it was necessary to find efficient ways to enhance the overall hydrocarbon recovery factor of the field. Several sensitivities were performed, on the number of wells, number of hydraulic fractures, well design, artificial lift options, water, and gas injection. According to the sensitivities results, the best developed scenario envisages high number of multiple frac wells to increase the recovery factor. Based on the detailed evaluation of available artificial lift options, SRP was selected over Jet pumps as the most suitable artificial lift considering the requirement of large drawdowns & operating costs of lifts. The risk of gas issues was mitigated by keeping the tubing-production casing annulus vented and further alleviated by running suitable downhole gas separators. Other problems were analyzed, and multiple attempts of solution implementation were done.\u0000 This paper addresses an inhouse ways to tackle sand, high gas rate issues, along with rectifications &learning of other problems faced during the last 3 years of field operations, including digitalization projects for visualization of well behavior. This paper also addresses a few remarkable calculated parameters which are - actual production loss calculations whenever well is shut-in (considering wellbore column storage effects), calculated gas free liquid level pump submergence and pump intake pressure from pump load live data. The purpose of this paper is to describe technical & operational challenges along with lessons learnt/solutions implemented in last 3 years.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"13 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128231316","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
R. Maheshwari, Duncan Ure, Cynthia Sing Yueh Cheong
Unloading wells post drilling and completion is critical in ensuring risk of well productivity impairment due to extended residence of drilling and completion fluids in the well is minimized. In addition, unloading high pressure (HHP) gas wells can be quite complex since it includes rapid changes in operating conditions (pressure, temperatures and rates), which if not planned properly, can lead to exceeding design operating envelopes and in the worst-case result in process safety incidents. The objective of this paper is to present a case study, which demonstrates the application of transient flow modelling for analysis of complex high pressure (HHP) gas well unloading. Traditional well and surface network modelling tools and softwares use steady state flow models. However, well unloading is a transient phenomenon with rapid changes in pressure, temperature, flowrate and hold-up and ideally requires multiphase transient flow modelling software to predict the conditions accurately. This paper describes how transient flow simulation, using the software package OLGA, was applied to model well unloading with the objective to keep the flow within the operating envelope of the well and surface equipment. The execution was carried out safely and successfully aided by the modelling work carried out in OLGA. A comparison of the modelled and actual measured parameters is presented showcasing the utility of transient flow modelling in planning, decision making and smooth execution. The model was used to optimize the choke positions within the constraints of low temperature limit, while avoiding the requirement of heat exchangers, steam generators and flare stack and avoid a long learning curve during execution. This also ensured that flaring was not required which means no Greenhouse Gas (GHG) emissions and the produced hydrocarbons were monetized.
钻井和完井后的卸载对于确保最大限度地降低因钻井液和完井液在井内停留时间过长而导致油井生产率下降的风险至关重要。此外，高压（HHP）气井的卸载可能相当复杂，因为它包括操作条件（压力、温度和速率）的快速变化，如果计划不当，可能会导致超出设计操作范围，最坏的情况下会导致工艺安全事故。本文旨在介绍一个案例研究，展示瞬态流动建模在复杂高压（HHP）气井卸载分析中的应用。传统的油井和地面网络建模工具和软件使用稳态流动模型。然而，气井卸载是一种瞬态现象，压力、温度、流速和滞留都会发生快速变化，因此需要使用多相瞬态流动建模软件来准确预测卸载条件。本文介绍了如何使用 OLGA 软件包进行瞬态流动模拟，模拟油井卸载，目的是将流动控制在油井和地面设备的工作范围内。在 OLGA 建模工作的帮助下，执行工作安全顺利地进行。对建模参数和实际测量参数进行了比较，展示了瞬态流动建模在规划、决策和顺利执行中的作用。该模型用于在低温限制条件下优化扼流圈位置，同时避免了对热交换器、蒸汽发生器和火炬烟囱的要求，并避免了执行过程中漫长的学习曲线。这也确保了无需燃烧，这意味着没有温室气体（GHG）排放，并且生产的碳氢化合物可以货币化。
{"title":"Innovative Use of Transient Flow Modelling for Successful Planning and Execution of Complex High Pressure (HHP) Well Unloading: Plan and Results","authors":"R. Maheshwari, Duncan Ure, Cynthia Sing Yueh Cheong","doi":"10.2523/iptc-22771-ms","DOIUrl":"https://doi.org/10.2523/iptc-22771-ms","url":null,"abstract":"\u0000 Unloading wells post drilling and completion is critical in ensuring risk of well productivity impairment due to extended residence of drilling and completion fluids in the well is minimized. In addition, unloading high pressure (HHP) gas wells can be quite complex since it includes rapid changes in operating conditions (pressure, temperatures and rates), which if not planned properly, can lead to exceeding design operating envelopes and in the worst-case result in process safety incidents. The objective of this paper is to present a case study, which demonstrates the application of transient flow modelling for analysis of complex high pressure (HHP) gas well unloading.\u0000 Traditional well and surface network modelling tools and softwares use steady state flow models. However, well unloading is a transient phenomenon with rapid changes in pressure, temperature, flowrate and hold-up and ideally requires multiphase transient flow modelling software to predict the conditions accurately. This paper describes how transient flow simulation, using the software package OLGA, was applied to model well unloading with the objective to keep the flow within the operating envelope of the well and surface equipment.\u0000 The execution was carried out safely and successfully aided by the modelling work carried out in OLGA. A comparison of the modelled and actual measured parameters is presented showcasing the utility of transient flow modelling in planning, decision making and smooth execution. The model was used to optimize the choke positions within the constraints of low temperature limit, while avoiding the requirement of heat exchangers, steam generators and flare stack and avoid a long learning curve during execution. This also ensured that flaring was not required which means no Greenhouse Gas (GHG) emissions and the produced hydrocarbons were monetized.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"55 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127042642","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}
Jianguo Zhang, Zhenjia Wang, Yi-fei Lan, Chenyang Zhao, Jinhua Liu
A low-permeability lithological reservoir was successfully put into operation in 2015 as a gas storage system. The field S2 Underground Gas Storage (UGS) is located in the Ordos Basin and is primarily alithological trap, with low permeability, high heterogeneity, and no obvious seal boundaries. Based on low permeability, low abundance, low vertical wells productivity, low pressure coefficient, serious skin damage in the bottomhole during drilling and completion, strong heterogeneity and unclear lithological boundaries, low control of injection-withdrawal well patterns, the working gas volume and operating efficiency of S2 UGS underperformed relative to modeled expectations. The technical solutions to improve the working gas volume of S2 USG focused upon: well pattern optimization, well placement, stimulation treatment, infillings, and increasing of operating maximum pressure. The results demonstrate that if reasonable technical solutions are adopted, even poor and low-quality storage reservoirs with low permeability, and strong heterogeneity, can be utilized as natural gas storage targets. This discussion provides an overview of approaches used in the Ordos Basin to make operation of S2 UGS more efficient. The development of this project, particularly regarding the operation processes and the resulting adjustments, are noteworthy. The development of such UGS reservoirs require new insights into the performance criteria which can be applied to other reservoirs in the future.
{"title":"Increasing Working Gas Volume of UGS Based on Low Permeability Lithological Gas Reservoirs","authors":"Jianguo Zhang, Zhenjia Wang, Yi-fei Lan, Chenyang Zhao, Jinhua Liu","doi":"10.2523/iptc-22885-ea","DOIUrl":"https://doi.org/10.2523/iptc-22885-ea","url":null,"abstract":"\u0000 \u0000 \u0000 A low-permeability lithological reservoir was successfully put into operation in 2015 as a gas storage system. The field S2 Underground Gas Storage (UGS) is located in the Ordos Basin and is primarily alithological trap, with low permeability, high heterogeneity, and no obvious seal boundaries. Based on low permeability, low abundance, low vertical wells productivity, low pressure coefficient, serious skin damage in the bottomhole during drilling and completion, strong heterogeneity and unclear lithological boundaries, low control of injection-withdrawal well patterns, the working gas volume and operating efficiency of S2 UGS underperformed relative to modeled expectations. The technical solutions to improve the working gas volume of S2 USG focused upon: well pattern optimization, well placement, stimulation treatment, infillings, and increasing of operating maximum pressure. The results demonstrate that if reasonable technical solutions are adopted, even poor and low-quality storage reservoirs with low permeability, and strong heterogeneity, can be utilized as natural gas storage targets.\u0000 This discussion provides an overview of approaches used in the Ordos Basin to make operation of S2 UGS more efficient. The development of this project, particularly regarding the operation processes and the resulting adjustments, are noteworthy. The development of such UGS reservoirs require new insights into the performance criteria which can be applied to other reservoirs in the future.\u0000","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"32 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132506489","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 Ocean Data Platform project was initiated initiated since 2020 to support our aspiration to become the guardian of the Ocean. PTTEP (‘the Company’) aspires to take part in providing of marine science data around our offshore operation to the general public, as there is currently no offshore information available from Thailand. The data will be beneficial to ocean scientists, authorities, and could lead to the development of various ocean conservation programs and prediction model. This Ocean Data Platform is designed to collect the up-to-date and real-time offshore ocean health and biodiversity data in Gulf of Thailand (GoT) by leveraging our offshore location strengths, knowledge, and innovative technologies. To establish the real-time offshore data in our operation, met-ocean monitoring station and underwater camera are installed to automatically perform oceanographic measurements to identify biodiversity, species, and aquatic life. This platform will connect our offshore data with other nearshore and midshore data from other entities. They also have alert function to detect abnormal activity so they can investigate and notify relevant parties to take action if necessary. The Ocean Data Platform will be published to stakeholders and interested parties for further research through the websie (reference 4). This platform comprises of 3 main parts of oceanographic monitoring, Ocean for life initiatives and Corporate Social Responsibility (CSR) events such as offshore microplastic monitoring, underwater biodiversity around offshore platform, coral bleaching baseline, the His Thai Majesty's Ship (H.T.M.S) underwater learning site. This information allows us to mornitor the state of the ocean health in various aspects and analyze the causes of various phenomena such as, impact of greenhouse gases on the ocean, change in ocean water temperature, wave height in monsoon season, ocean acidity, and base of ocean water, etc. We could also use this information to design offshore facilities to optimize CAPEX costs in the future. In addition, this platform is also regarded as the starting point for consolidating all marine-related information into one platform to support Thailand ocean conservation program. This is the first development in Thailand that integrates offshore data with others to complete ocean data in a holistic manner and allows researchers interested in the ocean to effectively use this type of data in their research.
{"title":"First Time in Thailand: Ocean Data Platform Through the Use of Offshore Facilities","authors":"Witthaya Channarong","doi":"10.2523/iptc-23096-ea","DOIUrl":"https://doi.org/10.2523/iptc-23096-ea","url":null,"abstract":"\u0000 The Ocean Data Platform project was initiated initiated since 2020 to support our aspiration to become the guardian of the Ocean. PTTEP (‘the Company’) aspires to take part in providing of marine science data around our offshore operation to the general public, as there is currently no offshore information available from Thailand. The data will be beneficial to ocean scientists, authorities, and could lead to the development of various ocean conservation programs and prediction model.\u0000 This Ocean Data Platform is designed to collect the up-to-date and real-time offshore ocean health and biodiversity data in Gulf of Thailand (GoT) by leveraging our offshore location strengths, knowledge, and innovative technologies. To establish the real-time offshore data in our operation, met-ocean monitoring station and underwater camera are installed to automatically perform oceanographic measurements to identify biodiversity, species, and aquatic life. This platform will connect our offshore data with other nearshore and midshore data from other entities. They also have alert function to detect abnormal activity so they can investigate and notify relevant parties to take action if necessary.\u0000 The Ocean Data Platform will be published to stakeholders and interested parties for further research through the websie (reference 4). This platform comprises of 3 main parts of oceanographic monitoring, Ocean for life initiatives and Corporate Social Responsibility (CSR) events such as offshore microplastic monitoring, underwater biodiversity around offshore platform, coral bleaching baseline, the His Thai Majesty's Ship (H.T.M.S) underwater learning site. This information allows us to mornitor the state of the ocean health in various aspects and analyze the causes of various phenomena such as, impact of greenhouse gases on the ocean, change in ocean water temperature, wave height in monsoon season, ocean acidity, and base of ocean water, etc. We could also use this information to design offshore facilities to optimize CAPEX costs in the future. In addition, this platform is also regarded as the starting point for consolidating all marine-related information into one platform to support Thailand ocean conservation program.\u0000 This is the first development in Thailand that integrates offshore data with others to complete ocean data in a holistic manner and allows researchers interested in the ocean to effectively use this type of data in their research.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"70 3 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130800981","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}
Regarding the Direct Current (DC) power generation for the offshore gas wellhead platform, the hybrid power generator Thermoelectric generator (TEG) and Solar Panel is used in the COMPANY design to supply power for DC loads such as a PLC and Telecom system of the offshore gas wellhead platform in past 10 years. To effectively achieve Capital Expenditures (CAPEX), and Operating Expenditures (OPEX) and green environment, now 100% solar panel power generator with battery backup is considered. The challenge of a single power generation which is a solar power system is reliability. There are a few key factors that effect to the reliability of 100% solar power system design. The shadow on solar panel, solar radiation and battery backup duration during the low insolation and nighttime would be key factors in engineering design. Approximately 20 gas wellhead platforms in the gulf of Thailand are designed with 100% solar power generation with battery backup during the past 3 years, they have been operating without power generation issue. When designing solar panel locations, the software Sun-Path software is used to confirm there is no significant shadow on solar panel in all seasons. For the sun solar radiation, we use weather statistic solar insolation data provided by NASA. And battery backup time, we use weather statistic data as a factor for battery backup time. During the low insolation days and nighttime, the DC load shall be power supplied by backup battery. Battery duration shall be referred to solar insolation and Equivalent Number of NO-SUN Or BLACK Days data provided by NASA. As per a study prior deciding to select 100% solar power system gas wellhead platform, 100% solar power system CAPEX can totally save about 30% when compared to Hybrid Thermal Electric Generation (TEG) &Solar power generation. In addition, there is no concern about fuel gas properties such as high CO2 on wellhead platform. There is no fuel gas consumption in solar panel power generation which support a green environment.
{"title":"Evolution of Power Generation of Offshore Wellhead Platform to 100% Solar Power System Design","authors":"Wiwat Kurustien, Taweepong Maneeanekcoon, Pisit Chaiwiboonpol","doi":"10.2523/iptc-23107-ea","DOIUrl":"https://doi.org/10.2523/iptc-23107-ea","url":null,"abstract":"\u0000 Regarding the Direct Current (DC) power generation for the offshore gas wellhead platform, the hybrid power generator Thermoelectric generator (TEG) and Solar Panel is used in the COMPANY design to supply power for DC loads such as a PLC and Telecom system of the offshore gas wellhead platform in past 10 years.\u0000 To effectively achieve Capital Expenditures (CAPEX), and Operating Expenditures (OPEX) and green environment, now 100% solar panel power generator with battery backup is considered. The challenge of a single power generation which is a solar power system is reliability. There are a few key factors that effect to the reliability of 100% solar power system design. The shadow on solar panel, solar radiation and battery backup duration during the low insolation and nighttime would be key factors in engineering design.\u0000 Approximately 20 gas wellhead platforms in the gulf of Thailand are designed with 100% solar power generation with battery backup during the past 3 years, they have been operating without power generation issue. When designing solar panel locations, the software Sun-Path software is used to confirm there is no significant shadow on solar panel in all seasons. For the sun solar radiation, we use weather statistic solar insolation data provided by NASA. And battery backup time, we use weather statistic data as a factor for battery backup time. During the low insolation days and nighttime, the DC load shall be power supplied by backup battery. Battery duration shall be referred to solar insolation and Equivalent Number of NO-SUN Or BLACK Days data provided by NASA.\u0000 As per a study prior deciding to select 100% solar power system gas wellhead platform, 100% solar power system CAPEX can totally save about 30% when compared to Hybrid Thermal Electric Generation (TEG) &Solar power generation. In addition, there is no concern about fuel gas properties such as high CO2 on wellhead platform. There is no fuel gas consumption in solar panel power generation which support a green environment.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"305 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121404955","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}
Well metering is an important part of daily oilfield management. For wells in a block, production metering can help reservoir managers fully understand the changes in the reservoir and provide a basis for reservoir dynamics analysis and scientific field development planning. For single-well metering, accurate producing rate can help oil well operators optimize the well production system, improve the efficiency of oil wells, and even discover abnormal conditions in oil wells based on changes in production. In order to obtain accurate well production, over 300 SRP wells in an experimental area of an oil field in northeastern China are tracked and measured in this paper. Easily available continuous electrical parameter data (including electrical power, current and voltage) and real-time output of the wells were selected as training parameters. We separated the SRP well electrical curves and corresponding real-time production data into a set of samples by one-stroke time, and obtained a total of 200,000 valid samples. The production status of the pumping wells was classified by deep learning, and the electric curves were Fourier transformed to extract statistical features. Then, we performed deep learning on these samples, using production parameters as input vectors and well fluid production as output results. Finally, good results were obtained by training and a model for calculating SRP well production based on big data was developed. The model was used to calculate the production of SRP wells in an experimental area of an oil field in northeastern China and compared with the actual production data. For low-producing wells with daily production less than 6 m3, the error of the model was less than 0.5 m3 /d, and for wells with daily production greater than 6 m3, the relative error of the wells was less than 10%, which met the expectation of managers. Compared with the methods mentioned in this paper, the currently used measurement methods, such as flowmeter measurement and volumetric measurement, have limitations in terms of instrumental measurement range and real-time measurement, respectively. In addition, both of these methods increase the construction cost of flow measurement systems. The big data production measurement model provides operators with a method for optimizing the production system of oil wells and also provides signals for early warning of oil well failures. This method can help managers achieve cost reduction and efficiency increase. The processing and application methods of electrical parameters in this paper can also provide ideas for production prediction of PCP o ESP wells.
{"title":"Research and Application of Big Data Production Measurement Method for SRP Wells Based on Electrical Parameters","authors":"Shiwen Chen, Feng Deng, Guanhong Chen, Ruidong Zhao, Junfeng Shi, Weidong Jiang","doi":"10.2523/iptc-23013-ea","DOIUrl":"https://doi.org/10.2523/iptc-23013-ea","url":null,"abstract":"\u0000 Well metering is an important part of daily oilfield management. For wells in a block, production metering can help reservoir managers fully understand the changes in the reservoir and provide a basis for reservoir dynamics analysis and scientific field development planning. For single-well metering, accurate producing rate can help oil well operators optimize the well production system, improve the efficiency of oil wells, and even discover abnormal conditions in oil wells based on changes in production.\u0000 In order to obtain accurate well production, over 300 SRP wells in an experimental area of an oil field in northeastern China are tracked and measured in this paper. Easily available continuous electrical parameter data (including electrical power, current and voltage) and real-time output of the wells were selected as training parameters. We separated the SRP well electrical curves and corresponding real-time production data into a set of samples by one-stroke time, and obtained a total of 200,000 valid samples. The production status of the pumping wells was classified by deep learning, and the electric curves were Fourier transformed to extract statistical features.\u0000 Then, we performed deep learning on these samples, using production parameters as input vectors and well fluid production as output results. Finally, good results were obtained by training and a model for calculating SRP well production based on big data was developed. The model was used to calculate the production of SRP wells in an experimental area of an oil field in northeastern China and compared with the actual production data. For low-producing wells with daily production less than 6 m3, the error of the model was less than 0.5 m3 /d, and for wells with daily production greater than 6 m3, the relative error of the wells was less than 10%, which met the expectation of managers. Compared with the methods mentioned in this paper, the currently used measurement methods, such as flowmeter measurement and volumetric measurement, have limitations in terms of instrumental measurement range and real-time measurement, respectively. In addition, both of these methods increase the construction cost of flow measurement systems.\u0000 The big data production measurement model provides operators with a method for optimizing the production system of oil wells and also provides signals for early warning of oil well failures. This method can help managers achieve cost reduction and efficiency increase. The processing and application methods of electrical parameters in this paper can also provide ideas for production prediction of PCP o ESP wells.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"128 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123251997","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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