In the Tarim Basin, the wellbore blockage problem of HTHP oil wells was very severe, especially in Fuman, Donghe 1 and Yudong 7 oil fields. The total number of blocked Wells is 95, Over 24% oil wells have organic solid phase plugging problem. More than 64% of the Wells in Donghe 1 oilfield were blocked, resulting in difficulties in testing, wellbore blockage and surface pipeline burst, affecting annual production of 8,500 tons. In this paper, a fast analysis method of blockage was established, and an organic solid phase deposition test device was innovated. The law of solid phase blocking under different reservoir conditions, development modes and crude oil properties was systematically analyzed. The dynamic prediction model of organic solid phase blocking was established to realize the visualization prediction of blocking position, and the unblocking measures technology of organic solid phase blocking was formed to comprehensively solve the organic solid phase blocking problem in oil Wells. It was shown that the blockages in the Fuman carbonate reservoirs were dominated by wax-asphalt organic compound and sand burial, and t he gas injection development in Donghe 1 Oilfield is dominated by asphalt deposition, while that in Yudong 7 Oilfield is dominated by asphalt and wax plugging. Gas injection extraction, crude oil composition change, pressure drop and sand production are the main factors of solid phase blockage, and organic solid phase blockage exists in "wellbore + reservoir near the wellbore "; The dynamic prediction model of composite plug deposition is established to realize the "visualization"of plug location and degree, and the prediction accuracy is ≥ 80 %. The efficient unblocking agent have been developed based on the understanding of the blockage composition, to achieve high-efficiency dissolution of the blockage (the dissolving rate 90%) and the effective inhibition (85.84%). Based on the understanding of the blockage law, 4 sets of unblocking processes had been developed with "plugging degree" and "whether there was a squeeze channel" as the main considerations, For the first time, the "system blockage unblocking "design method based on the composite plugging mode of "wellbore + reservoir near the wellbore " is proposed, which realizes the efficient plugging removal. The field application of 477 wells improves the success rate of reproduction from 53 % to 100 %, and effectively reduces the risk of plugging. This successful experience could provide guidance for blockage treatment in other oil fields with asphalt deposition and organic solid plugging such as wax.
{"title":"Organic Solid Blocking Mechanism and Unblocking Technology for Ultra-Deep and High Pressure Oil Wells from Tarim Basin","authors":"Haixia Xu, Shifeng Wang, Chunjie Cheng, Qiang Li, Yishi Liu, Junsheng Qi, Junyi Wu","doi":"10.2523/iptc-23092-ea","DOIUrl":"https://doi.org/10.2523/iptc-23092-ea","url":null,"abstract":"\u0000 In the Tarim Basin, the wellbore blockage problem of HTHP oil wells was very severe, especially in Fuman, Donghe 1 and Yudong 7 oil fields. The total number of blocked Wells is 95, Over 24% oil wells have organic solid phase plugging problem. More than 64% of the Wells in Donghe 1 oilfield were blocked, resulting in difficulties in testing, wellbore blockage and surface pipeline burst, affecting annual production of 8,500 tons.\u0000 In this paper, a fast analysis method of blockage was established, and an organic solid phase deposition test device was innovated. The law of solid phase blocking under different reservoir conditions, development modes and crude oil properties was systematically analyzed. The dynamic prediction model of organic solid phase blocking was established to realize the visualization prediction of blocking position, and the unblocking measures technology of organic solid phase blocking was formed to comprehensively solve the organic solid phase blocking problem in oil Wells.\u0000 It was shown that the blockages in the Fuman carbonate reservoirs were dominated by wax-asphalt organic compound and sand burial, and t he gas injection development in Donghe 1 Oilfield is dominated by asphalt deposition, while that in Yudong 7 Oilfield is dominated by asphalt and wax plugging. Gas injection extraction, crude oil composition change, pressure drop and sand production are the main factors of solid phase blockage, and organic solid phase blockage exists in \"wellbore + reservoir near the wellbore \"; The dynamic prediction model of composite plug deposition is established to realize the \"visualization\"of plug location and degree, and the prediction accuracy is ≥ 80 %. The efficient unblocking agent have been developed based on the understanding of the blockage composition, to achieve high-efficiency dissolution of the blockage (the dissolving rate 90%) and the effective inhibition (85.84%). Based on the understanding of the blockage law, 4 sets of unblocking processes had been developed with \"plugging degree\" and \"whether there was a squeeze channel\" as the main considerations, For the first time, the \"system blockage unblocking \"design method based on the composite plugging mode of \"wellbore + reservoir near the wellbore \" is proposed, which realizes the efficient plugging removal. The field application of 477 wells improves the success rate of reproduction from 53 % to 100 %, and effectively reduces the risk of plugging.\u0000 This successful experience could provide guidance for blockage treatment in other oil fields with asphalt deposition and organic solid plugging such as wax.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"18 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":"124799084","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}
Sustaining hydrocarbon production using artificial lifting technology could be daunting to say the least. Over time, both surface and subsurface challenges associated to artificial lift applications and electric submersible pumping systems in particular, that impact hydrocarbon production make the system unappealing and uneconomical for field development. This paper attempts to review the challenges impacting ESP system optimization for sustainable hydrocarbon production in both brown and green fields during the current big data era. The producing environment as well as the ESP components used in field development and production require continuous optimization across the ESP system spectrum. Analysis and diagnosis of the producing well completion is essential to achieving a better optimization and sustainability of the desired production target. A two-approach system optimization is preferred to address the challenges impacting sustainable hydrocarbon production in an ESP completed well. The approach enumerated in the paper relies on the innovative technological advancement of data capturing, segmentation, and integration brought about by the fourth industrial revolution. The approach involves a top-to-bottom optimization in addition to real-time data integration. The increasing sophistication in ESP system platforms’, mobility, surveillance, connectivity, and storage technologies, joined with the ability to process and rapidly analyze data, improve agility, and support real-time on the spot automated decision making. These enhancements allow action execution to overcome the numerous challenges impacting production sustainability in ESP completed wells. This brings about increased and timely engagement between the equipment manufacturer, operator and the well. In addition, there is reduction in well downtime, increased uptime with overall resultant of sustained hydrocarbon production. A comprehensive approach to artificial lift hydrocarbon production optimization in an ESP completed well using data interwoven connectivity is preferred as the best approach to reactivate, boost, and sustain hydrocarbon production in this era of digitalization.
{"title":"Sustainable Hydrocarbon Production Through ESP System Optimization in the Digital Era","authors":"T. C. Kalu-Ulu, Saud A. Khamees, Cleavant Flippin","doi":"10.2523/iptc-23085-ms","DOIUrl":"https://doi.org/10.2523/iptc-23085-ms","url":null,"abstract":"\u0000 Sustaining hydrocarbon production using artificial lifting technology could be daunting to say the least. Over time, both surface and subsurface challenges associated to artificial lift applications and electric submersible pumping systems in particular, that impact hydrocarbon production make the system unappealing and uneconomical for field development. This paper attempts to review the challenges impacting ESP system optimization for sustainable hydrocarbon production in both brown and green fields during the current big data era.\u0000 The producing environment as well as the ESP components used in field development and production require continuous optimization across the ESP system spectrum. Analysis and diagnosis of the producing well completion is essential to achieving a better optimization and sustainability of the desired production target. A two-approach system optimization is preferred to address the challenges impacting sustainable hydrocarbon production in an ESP completed well. The approach enumerated in the paper relies on the innovative technological advancement of data capturing, segmentation, and integration brought about by the fourth industrial revolution.\u0000 The approach involves a top-to-bottom optimization in addition to real-time data integration. The increasing sophistication in ESP system platforms’, mobility, surveillance, connectivity, and storage technologies, joined with the ability to process and rapidly analyze data, improve agility, and support real-time on the spot automated decision making. These enhancements allow action execution to overcome the numerous challenges impacting production sustainability in ESP completed wells. This brings about increased and timely engagement between the equipment manufacturer, operator and the well. In addition, there is reduction in well downtime, increased uptime with overall resultant of sustained hydrocarbon production.\u0000 A comprehensive approach to artificial lift hydrocarbon production optimization in an ESP completed well using data interwoven connectivity is preferred as the best approach to reactivate, boost, and sustain hydrocarbon production in this era of digitalization.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"29 6 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":"133919879","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}
Takonporn Kunpitaktakun, P. Boonyasatphan, S. Utitsan, Khuananong Wongpaet, H. Primadi
To prolong the field life of The Suphanburi oil field, an additional enhanced oil recovery (EOR) process is required. Dynamic reservoir modeling will need to be performed to maximize the EOR strategy. However, achieving the right result is a challenge as the field has a complex depositional environment and high heterogeneity, resulting in a high uncertainty of the dynamic reservoir model. A new reservoir model is proposed and created. The new model has been purposely built to capture the heterogeneity of the field by incorporating the newly interpreted geological concept of the field, together with quantitative seismic interpretation results. First, the new geological concept is interpreted from well data into "depofacies". The depofacies describe both depositional environment and lithofacies. Next, quantitative seismic interpretation is performed to capture the spatial variation of the reservoir and the predefined facies. Lastly, the reservoir model is built by first generating the depofacies. The reservoir or sandstone is then modeled specifically into each pre-modeled depofacies. As a result, the new reservoir model can better capture reservoir heterogeneity, resulting in a better EOR strategy.
{"title":"Integrated Subsurface Reservoir Characterization to Enhance Geomodeling in the Suphanburi Oil Field, Onshore Thailand","authors":"Takonporn Kunpitaktakun, P. Boonyasatphan, S. Utitsan, Khuananong Wongpaet, H. Primadi","doi":"10.2523/iptc-22830-ea","DOIUrl":"https://doi.org/10.2523/iptc-22830-ea","url":null,"abstract":"\u0000 To prolong the field life of The Suphanburi oil field, an additional enhanced oil recovery (EOR) process is required. Dynamic reservoir modeling will need to be performed to maximize the EOR strategy. However, achieving the right result is a challenge as the field has a complex depositional environment and high heterogeneity, resulting in a high uncertainty of the dynamic reservoir model. A new reservoir model is proposed and created. The new model has been purposely built to capture the heterogeneity of the field by incorporating the newly interpreted geological concept of the field, together with quantitative seismic interpretation results. First, the new geological concept is interpreted from well data into \"depofacies\". The depofacies describe both depositional environment and lithofacies. Next, quantitative seismic interpretation is performed to capture the spatial variation of the reservoir and the predefined facies. Lastly, the reservoir model is built by first generating the depofacies. The reservoir or sandstone is then modeled specifically into each pre-modeled depofacies. As a result, the new reservoir model can better capture reservoir heterogeneity, resulting in a better EOR strategy.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"23 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":"121995033","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}
Kinetic hydrate inhibitors (KHIs) and anti-agglomerants (AAs) – known as low dosage hydrate inhibitors (LDHIs) – have been used widely for gas hydrate prevention in oil and gas operations. They offer significant advantages over thermodynamic inhibitors (e.g., methanol and glycols). While significant works have been done on KHIs evaluation, AAs suffer from their evaluation in terms of hydrate structural effect, gas composition, water cut, and hydrate amount, which are the main objectives of this work. A Shut-in-Restart procedure was carried out to experimentally evaluate (using a visual rocking cell) various commercial AAs in different gas compositions (from a simple methane system to multicomponent natural gas systems). The kinetics of hydrate growth rate and the amount of hydrate formation in the presence of AAs were also analysed using the recorded pressure-temperature data. The amount of hydrate formation (WCH: percentage of water converted to hydrate) was also calculated by pressure drop and establishing the pressure-temperature hydrate flash. The experimental results from the step heating equilibrium point measurement suggest the formation of multiple hydrate structures or phases in order of thermodynamic stability rather than the formation of simple structure II hydrate in the multicomponent natural gas system. The initial findings of experimental studies show that the performance of AAs is not identical for different gas compositions. This is potentially due to the hydrate structural effect on AAs performance. For example, while a commercially available AA (as tested here) could not prevent hydrate agglomeration/blockage in the methane system (plugging occurred after 2% hydrate formed in the system), it showed a much better performance in the natural gas systems. In addition, while hydrate plugging was not observed in the visual rocking cell in the rich natural gas system with AA (at a high subcooling temperature of ∼15°C), some hydrate agglomeration and hydrate plugging were observed for the lean natural gas system at the same subcooling temperature. It is speculated that methane hydrate structure I is potentially the main reason for hydrate plugging and failure of AAs. Finally, the results indicate that water cut%, gas composition, and AAs concentration have a significant effect on hydrate growth rate and hydrate plugging. In addition to increasing confidence in AAs field use, findings potentially have novel applications with respect to hydrate structural effect on plugging and hydrate plug calculation. A robust pressure-temperature hydrate flash calculation is required to calculate the percent of water converted to hydrate during hydrate growth in the presence of AAs.
{"title":"Anti-Agglomerants: Study of Hydrate Structural, Gas Composition, Hydrate Amount, and Water Cut Effect","authors":"Morteza Aminnaji, A. Hase, L. Crombie","doi":"10.2523/iptc-22765-ms","DOIUrl":"https://doi.org/10.2523/iptc-22765-ms","url":null,"abstract":"\u0000 Kinetic hydrate inhibitors (KHIs) and anti-agglomerants (AAs) – known as low dosage hydrate inhibitors (LDHIs) – have been used widely for gas hydrate prevention in oil and gas operations. They offer significant advantages over thermodynamic inhibitors (e.g., methanol and glycols). While significant works have been done on KHIs evaluation, AAs suffer from their evaluation in terms of hydrate structural effect, gas composition, water cut, and hydrate amount, which are the main objectives of this work.\u0000 A Shut-in-Restart procedure was carried out to experimentally evaluate (using a visual rocking cell) various commercial AAs in different gas compositions (from a simple methane system to multicomponent natural gas systems). The kinetics of hydrate growth rate and the amount of hydrate formation in the presence of AAs were also analysed using the recorded pressure-temperature data. The amount of hydrate formation (WCH: percentage of water converted to hydrate) was also calculated by pressure drop and establishing the pressure-temperature hydrate flash.\u0000 The experimental results from the step heating equilibrium point measurement suggest the formation of multiple hydrate structures or phases in order of thermodynamic stability rather than the formation of simple structure II hydrate in the multicomponent natural gas system. The initial findings of experimental studies show that the performance of AAs is not identical for different gas compositions. This is potentially due to the hydrate structural effect on AAs performance. For example, while a commercially available AA (as tested here) could not prevent hydrate agglomeration/blockage in the methane system (plugging occurred after 2% hydrate formed in the system), it showed a much better performance in the natural gas systems. In addition, while hydrate plugging was not observed in the visual rocking cell in the rich natural gas system with AA (at a high subcooling temperature of ∼15°C), some hydrate agglomeration and hydrate plugging were observed for the lean natural gas system at the same subcooling temperature. It is speculated that methane hydrate structure I is potentially the main reason for hydrate plugging and failure of AAs. Finally, the results indicate that water cut%, gas composition, and AAs concentration have a significant effect on hydrate growth rate and hydrate plugging.\u0000 In addition to increasing confidence in AAs field use, findings potentially have novel applications with respect to hydrate structural effect on plugging and hydrate plug calculation. A robust pressure-temperature hydrate flash calculation is required to calculate the percent of water converted to hydrate during hydrate growth in the presence of AAs.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"44 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":"129243593","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}
Andrés Isaac Merchan Nájera, Orlando José Urribarri Romero, Hector Hugo Jimenez Rangel, Luis Daniel Gonzalez Mendoza, Erik Alberto Ramírez Fuentes, Efrain Jose Rodriguez, Marco Antonio Zarate Vergara
Today drilling wells is one of the biggest capital expenditures and is employed starting from exploration, delineation, initial wells for production, and fresh production incorporation when existing wells production have declined. The estimated cost for drilling new wells in Ayatsil field is around 20 to 25 MM $, which requires a high level of decision to achieve production goals without exceeding the budget assigned to the Ayatsil field. Therefore, to make the right decision requires an integration of multidisciplinary group of specialists (geologists, geomechanics, reservoir engineers, production engineers and drilling engineers) from well design to execution phases. This paper will illustrate the methodology and process applied by the operator to optimize the drilling stages and accelerate field production, as a result the operator developed the operational excellence project, that consist of five phases and being executed by a multidisciplinary project team. The drilling team has been successful in reducing the depth versus days curves from an average of 130 days in 2017 to an average of less than 58 days in 2022. The best performance achieved till now in terms of total meterage is 4,200 meters drilled in 51 days from the surface. The continuous improvement of the Ayatsil project has resulted in world class drilling performance. The success factors include standardized well design, performance improvement processes that was made possible by the multidisciplinary well decision team like, flat times efficiency. In addition, the outcome of this approach has resulted that 30 to 33 million dollars have been saved from the original budget in reduction of well costs and impulse the productivity of Ayatsil field.
{"title":"Application of New Technologies and Best Operational Practices to Accelerate the Learning Curve in Wells Drilled in the Ayatsil Field, Mexico","authors":"Andrés Isaac Merchan Nájera, Orlando José Urribarri Romero, Hector Hugo Jimenez Rangel, Luis Daniel Gonzalez Mendoza, Erik Alberto Ramírez Fuentes, Efrain Jose Rodriguez, Marco Antonio Zarate Vergara","doi":"10.2523/iptc-22778-ea","DOIUrl":"https://doi.org/10.2523/iptc-22778-ea","url":null,"abstract":"\u0000 Today drilling wells is one of the biggest capital expenditures and is employed starting from exploration, delineation, initial wells for production, and fresh production incorporation when existing wells production have declined. The estimated cost for drilling new wells in Ayatsil field is around 20 to 25 MM $, which requires a high level of decision to achieve production goals without exceeding the budget assigned to the Ayatsil field. Therefore, to make the right decision requires an integration of multidisciplinary group of specialists (geologists, geomechanics, reservoir engineers, production engineers and drilling engineers) from well design to execution phases.\u0000 This paper will illustrate the methodology and process applied by the operator to optimize the drilling stages and accelerate field production, as a result the operator developed the operational excellence project, that consist of five phases and being executed by a multidisciplinary project team.\u0000 The drilling team has been successful in reducing the depth versus days curves from an average of 130 days in 2017 to an average of less than 58 days in 2022. The best performance achieved till now in terms of total meterage is 4,200 meters drilled in 51 days from the surface. The continuous improvement of the Ayatsil project has resulted in world class drilling performance.\u0000 The success factors include standardized well design, performance improvement processes that was made possible by the multidisciplinary well decision team like, flat times efficiency. In addition, the outcome of this approach has resulted that 30 to 33 million dollars have been saved from the original budget in reduction of well costs and impulse the productivity of Ayatsil field.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"44 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":"130887402","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}
Ivy Chai Ching Hsia, Mohd Firdaus Abdul Wahab, Nur Kamilah Abdul Jalil, A.H. Goodman, H. M. Lahuri, S. S. Md Shah
Methanogenesis is the conversion of carbon dioxide (CO2) to methane (CH4) using microbes. In the context CO2 utilization, methanogenesis process in the utilizing native microbes from a particular reservoir can be a very slow process without any external intervention. To accelerate the conversion rate and methane yield, this study investigates the use of agriculture by-product such as palm oil mill effluent (POME) as substrates as well as potential microbial isolates that can produce biohydrogen at high temperatures. This paper covers the three laboratory assessments of microbes from anaerobic sludge from a local palm oil mill, use of POME to augment the microbial growth, and physicochemical manipulation to identify key parameters that increases CH4 yield and rate: i) biohydrogen production ii) biomethane production, and iii) syntrophic reactions. All experiments are conducted at 70°C which is considered a hyperthermophilic condition for many microbes. Biohydrogen production achieved with highest H2 production of 66.00 (mL/Lmedium). For biomethane production, the highest production rate achieved was 0.0768 CH4 µmol/mL/day which 10,000X higher than 19.6 pmol/mL/day used as a benchmark. Syntrophic reaction with both types of hydrogen-producing and methanogen in the same reactor, and pure H2 and CO2 supplemented externally was able to achieve the highest methane production of 10.095 µmol/mL and 2.524 µmol/ml/day. Methane production rate is 2.5 times faster than without external gasses being introduced. Introduction of external CO2 to the syntrophic reaction is to mimic actual carbon injection and storage in the reservoir. Our paper shows that stimulation of microbes using POME as substrates and H2/CO2 supplementation are important in accelerating the rate of methane production and yield. Future work will focus on optimizing the gas ratio, pH of growth media, and performing syntrophic reaction in porous media to emulate conditions of a reservoir.
{"title":"Accelerated Methanogenesis for the Conversion of Biomethane from Carbon Dioxide and Biohydrogen at Hyperthermophilic Condition","authors":"Ivy Chai Ching Hsia, Mohd Firdaus Abdul Wahab, Nur Kamilah Abdul Jalil, A.H. Goodman, H. M. Lahuri, S. S. Md Shah","doi":"10.2523/iptc-22744-ea","DOIUrl":"https://doi.org/10.2523/iptc-22744-ea","url":null,"abstract":"\u0000 Methanogenesis is the conversion of carbon dioxide (CO2) to methane (CH4) using microbes. In the context CO2 utilization, methanogenesis process in the utilizing native microbes from a particular reservoir can be a very slow process without any external intervention. To accelerate the conversion rate and methane yield, this study investigates the use of agriculture by-product such as palm oil mill effluent (POME) as substrates as well as potential microbial isolates that can produce biohydrogen at high temperatures. This paper covers the three laboratory assessments of microbes from anaerobic sludge from a local palm oil mill, use of POME to augment the microbial growth, and physicochemical manipulation to identify key parameters that increases CH4 yield and rate: i) biohydrogen production ii) biomethane production, and iii) syntrophic reactions. All experiments are conducted at 70°C which is considered a hyperthermophilic condition for many microbes. Biohydrogen production achieved with highest H2 production of 66.00 (mL/Lmedium). For biomethane production, the highest production rate achieved was 0.0768 CH4 µmol/mL/day which 10,000X higher than 19.6 pmol/mL/day used as a benchmark. Syntrophic reaction with both types of hydrogen-producing and methanogen in the same reactor, and pure H2 and CO2 supplemented externally was able to achieve the highest methane production of 10.095 µmol/mL and 2.524 µmol/ml/day. Methane production rate is 2.5 times faster than without external gasses being introduced. Introduction of external CO2 to the syntrophic reaction is to mimic actual carbon injection and storage in the reservoir. Our paper shows that stimulation of microbes using POME as substrates and H2/CO2 supplementation are important in accelerating the rate of methane production and yield. Future work will focus on optimizing the gas ratio, pH of growth media, and performing syntrophic reaction in porous media to emulate conditions of a reservoir.","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":"128468758","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A. Sanea, Omar Alzahrani, K. Divine, Nawaf Alrajeh
Measuring HSE performance is vital when dealing with the implementation and execution of multiple Drilling Contractor HSE programs to ensure expectations are achieved throughout each rig contract life cycle. The HSE rig ranking program works as an HSE measuring tool by effectively consolidating eleven (11) leading and lagging key performance indicators (KPIs). KPI's such as total recordable incident injury rate (TRI-IR) and the Lost time Incident Injury rate (LTI-IR) as well as incident potential and inspection performance and compliance are all amalgamated into an all-inclusive scoring system with unprecedented results. Measuring, monitoring and benchmarking the health, safety and environmental performance of drilling contractors and their contracted rig fleet through this structured and comprehensive rig ranking program has organically spawned not only growth in behavioral based safety but also promoted a more robust HSE culture. The rig ranking methodology applied has facilitated greater contractor HSE oversight, resulting in not only healthy contractor competition but also substantial HSE performance improvements among the various drilling contractors and their respective rig fleets due to reductions in injuries, near misses as well as the severity of incident occurrences and improved adherence to established HSE requirements. Combining both lagging and leading indicators into a single Rig HSE performance score requires the efficient exploitation of both current and historical data and the HSE trends of each individual contracted rig and accurately weighting the impact of each of the 11 leading and lagging KPIs to arrive at a single representative score for each rig on contract. Each drilling contractors’ fleet of rigs is scored and benchmarked monthly and shared discreetly to contractor management team in an effort to provide a better understanding of their fleets HSE performance among their competitors and within their organizations. This rig ranking methodology identifies both high and low performance rigs, resulting in targeted intervention of low performance rigs and allowing for best practices of high-performance rigs to be cascaded downward to the lower echelons of the rig ranking scale. HSE practitioners engaged in site visits are equipped with a greater understanding of a rigs specific HSE improvement needs. As a result, the HSE rig ranking system facilitates a tailored site specific HSE message as opposed to broad, general safety improvement engagement. Since the inception and deployment of the HSE rig ranking program in 2018 a 240% increase in rigs performing in the Excellent range was achieved by October 2021 and behavioral based safety reporting increased over 255%. Recognition is also a key component of the rig ranking process and is incorporated communicate the achievements demonstrated and improvements made as well as sustained performance. The HSE Rig Ranking Program has contributed to fewer incidents, safer operations
{"title":"HSE Rig Ranking Measuring What Matters","authors":"A. Sanea, Omar Alzahrani, K. Divine, Nawaf Alrajeh","doi":"10.2523/iptc-22722-ms","DOIUrl":"https://doi.org/10.2523/iptc-22722-ms","url":null,"abstract":"\u0000 Measuring HSE performance is vital when dealing with the implementation and execution of multiple Drilling Contractor HSE programs to ensure expectations are achieved throughout each rig contract life cycle. The HSE rig ranking program works as an HSE measuring tool by effectively consolidating eleven (11) leading and lagging key performance indicators (KPIs). KPI's such as total recordable incident injury rate (TRI-IR) and the Lost time Incident Injury rate (LTI-IR) as well as incident potential and inspection performance and compliance are all amalgamated into an all-inclusive scoring system with unprecedented results.\u0000 Measuring, monitoring and benchmarking the health, safety and environmental performance of drilling contractors and their contracted rig fleet through this structured and comprehensive rig ranking program has organically spawned not only growth in behavioral based safety but also promoted a more robust HSE culture.\u0000 The rig ranking methodology applied has facilitated greater contractor HSE oversight, resulting in not only healthy contractor competition but also substantial HSE performance improvements among the various drilling contractors and their respective rig fleets due to reductions in injuries, near misses as well as the severity of incident occurrences and improved adherence to established HSE requirements. Combining both lagging and leading indicators into a single Rig HSE performance score requires the efficient exploitation of both current and historical data and the HSE trends of each individual contracted rig and accurately weighting the impact of each of the 11 leading and lagging KPIs to arrive at a single representative score for each rig on contract.\u0000 Each drilling contractors’ fleet of rigs is scored and benchmarked monthly and shared discreetly to contractor management team in an effort to provide a better understanding of their fleets HSE performance among their competitors and within their organizations. This rig ranking methodology identifies both high and low performance rigs, resulting in targeted intervention of low performance rigs and allowing for best practices of high-performance rigs to be cascaded downward to the lower echelons of the rig ranking scale. HSE practitioners engaged in site visits are equipped with a greater understanding of a rigs specific HSE improvement needs. As a result, the HSE rig ranking system facilitates a tailored site specific HSE message as opposed to broad, general safety improvement engagement.\u0000 Since the inception and deployment of the HSE rig ranking program in 2018 a 240% increase in rigs performing in the Excellent range was achieved by October 2021 and behavioral based safety reporting increased over 255%. Recognition is also a key component of the rig ranking process and is incorporated communicate the achievements demonstrated and improvements made as well as sustained performance. The HSE Rig Ranking Program has contributed to fewer incidents, safer operations ","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"46 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":"126066433","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A. A. Abu Bakar, Amir Badzly M Nazri, P. Shankar, Nor Arina M Azam, Aida Nor Hidayah Abu Bakar, Nor Azman Che Mahmood, Zairi A. Kadir, Zayful Hasrin Kamarudzaman, Mior Yusni Ahmad, Ibrahim B. Subari, A. Ridzuan, Norhayati M Sahid, Chee Seong Tan, Nicholas Moses, Zhen-Xuan Yew, Agnes Tan, G. Goh
In Q4 2017, the first extended-reach horizontal oil producer was completed in S-Field, with the horizontal section designed with nine isolation compartments with swellable packers. Each compartment was configured with an inflow control device (ICD) and an integral sleeve (on/off function) attached to the ICD’s joint. This paper discusses the effectiveness of the ICD technology in terms of sustaining incremental cumulative oil production by delaying water-breakthrough and subsequently reducing undesired water cut after water-breakthrough. An extensive post-job evaluation on production performance was conducted to evaluate the performance of the installed ICDs. The workflow was divided into three stages: history matching, forecasting, and post-job ICD evaluation. During history matching, the horizontal well with the ICDs was modeled using a high-resolution numerical simulator, and the reservoir model was calibrated with production data from a well test. Actual production rates and the water-breakthrough time were matched by revisiting key subsurface uncertainties from the sector model, such as aquifer strength, oil/water-contact, and relative permeability using the Corey correlation. The history-matched model was then used for the forecasting stage to predict cumulative production on a longer-term basis. Lastly, the performance of the ICDs was quantified after 4 years of production by comparing the oil increment from the ICD completion to the non-ICD case as baseline that would have been a miss of additional oil cumulative. Over the past 4 years, this horizontal well produced more than expected, with approximately 2–4 times more oil production than the estimated rate provided in the field development plan (FDP), whereby the lower completion is design optimally based on real-time ICD modeling updates. There were few uncertainties in the subsurface parameters such as fluid contact, fluid characterization, and the nature of an aquifer, were incorporated in the history-matching stage using sensitivity analysis and uncertainty range estimation. On the basis of actual and history-matched production performance, the well with the installed ICDs is projected to produce more than the non-ICD OH case with an improved cumulative oil production gain of as much as 6% and an 8% water reduction over 12 years of production. In addition, the ICD enables downhole influx balancing to delay the water breakthrough by 4 months compared to the OH case. The reduction or delay of water production is beneficial to the field to enhance oil recovery from the well. This case study demonstrates a successful ICD deployment under uncertainties, where during a real-time study in 2017, similar uncertainties were incorporated in high-resolution ICD modeling conditioned with real-time petrophysical data from logging while drilling (LWD) measurements. The use of ICD technology in this well demonstrated that zonal control efficiency could be achieved across the horizontal section
{"title":"Extended-Reach Horizontal Well with Excellent Inflow Control Device Completion Production and Sand-Free Gravel-Packing Integrated Solution Performance: A Case Study from S-Field, Offshore Malaysia","authors":"A. A. Abu Bakar, Amir Badzly M Nazri, P. Shankar, Nor Arina M Azam, Aida Nor Hidayah Abu Bakar, Nor Azman Che Mahmood, Zairi A. Kadir, Zayful Hasrin Kamarudzaman, Mior Yusni Ahmad, Ibrahim B. Subari, A. Ridzuan, Norhayati M Sahid, Chee Seong Tan, Nicholas Moses, Zhen-Xuan Yew, Agnes Tan, G. Goh","doi":"10.2523/iptc-23007-ms","DOIUrl":"https://doi.org/10.2523/iptc-23007-ms","url":null,"abstract":"\u0000 In Q4 2017, the first extended-reach horizontal oil producer was completed in S-Field, with the horizontal section designed with nine isolation compartments with swellable packers. Each compartment was configured with an inflow control device (ICD) and an integral sleeve (on/off function) attached to the ICD’s joint. This paper discusses the effectiveness of the ICD technology in terms of sustaining incremental cumulative oil production by delaying water-breakthrough and subsequently reducing undesired water cut after water-breakthrough.\u0000 An extensive post-job evaluation on production performance was conducted to evaluate the performance of the installed ICDs. The workflow was divided into three stages: history matching, forecasting, and post-job ICD evaluation. During history matching, the horizontal well with the ICDs was modeled using a high-resolution numerical simulator, and the reservoir model was calibrated with production data from a well test. Actual production rates and the water-breakthrough time were matched by revisiting key subsurface uncertainties from the sector model, such as aquifer strength, oil/water-contact, and relative permeability using the Corey correlation. The history-matched model was then used for the forecasting stage to predict cumulative production on a longer-term basis. Lastly, the performance of the ICDs was quantified after 4 years of production by comparing the oil increment from the ICD completion to the non-ICD case as baseline that would have been a miss of additional oil cumulative.\u0000 Over the past 4 years, this horizontal well produced more than expected, with approximately 2–4 times more oil production than the estimated rate provided in the field development plan (FDP), whereby the lower completion is design optimally based on real-time ICD modeling updates. There were few uncertainties in the subsurface parameters such as fluid contact, fluid characterization, and the nature of an aquifer, were incorporated in the history-matching stage using sensitivity analysis and uncertainty range estimation. On the basis of actual and history-matched production performance, the well with the installed ICDs is projected to produce more than the non-ICD OH case with an improved cumulative oil production gain of as much as 6% and an 8% water reduction over 12 years of production. In addition, the ICD enables downhole influx balancing to delay the water breakthrough by 4 months compared to the OH case. The reduction or delay of water production is beneficial to the field to enhance oil recovery from the well. This case study demonstrates a successful ICD deployment under uncertainties, where during a real-time study in 2017, similar uncertainties were incorporated in high-resolution ICD modeling conditioned with real-time petrophysical data from logging while drilling (LWD) measurements.\u0000 The use of ICD technology in this well demonstrated that zonal control efficiency could be achieved across the horizontal section ","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"36 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":"122432649","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}
Yuanzhao Li, Yue Ming, Chi Zhang, Rong Han, Luhao Guo, Y. Zeng
The Fuling shale gas field in China is one of the largest shale gas fields outside of North America. After a long period of production, some gas wells showed significant production decline and an effective refracturing treatment is designed to rejuvenate production. This Casing-in-Casing (CiC) refracturing method with customized design was successfully implemented with production increase beyond expectation. It was the first successful trial of a CiC refracturing treatment on a horizontal shale gas well in China. Bullheading (BH) refracturing with diverting balls was attempted in this field in past years, with high initial production observed. However, the production was inconsistent and declined quickly. The operator investigated and decided to attempt a CiC refracturing method in an under-stimulated candidate well. The CiC refracturing method is to cement a 3.5-in. liner in the legacy 5.5-in. casing to isolate the perforations, and new plugging and perforating (P-n-P) operations can be performed in the reconstructed wellbore. A refracturing design was customized integrating the production profile, residual recoverable reserves, and the specific 5.5- × 3.5-in. reconstructed wellbore limitation. During the BH refracturing, the treating pressure gradually increased with the drops of diverting balls, but the proppant placement became more and more difficult accordingly. The BH refracturing was finally completed with five cycles which was less than the design. High initial production after the BH treatment was observed but it declined quickly. In the CiC refracturing, a new 5.5-in × 3.5-in wellbore was constructed successfully, and it passed pressure test for stage frac. New clusters were added between the original clusters and stimulated with more intensive fracturing treatment in the new wellbore. Dissolvable particulate diverting agent was used for even cluster initiation and fracture geometry. The pressure response of the diverting agent was obvious indicating good diversion result and new reservoir contact. The initial production recovery rate was 88.1% compared to that of the original fracturing and the production increased 819% compared to the production before the CiC refracturing, which was much higher than BH refracturing. This case study illustrates that the CiC refracturing method is an effective method for refracturing. It overcomes the uncertainty and difficulty of proppant placement, achieves a higher intensity of fracturing treatment, and enables stimulation of the previously bypassed reservoir to improve the recovery of the well. The method has provided the industry with a new and reliable option to rejuvenate the aging wells.
{"title":"Innovative and Tailored Refracturing to Rejuvenate the Largest Shale Gas Field of China: Case Study","authors":"Yuanzhao Li, Yue Ming, Chi Zhang, Rong Han, Luhao Guo, Y. Zeng","doi":"10.2523/iptc-23040-ms","DOIUrl":"https://doi.org/10.2523/iptc-23040-ms","url":null,"abstract":"\u0000 The Fuling shale gas field in China is one of the largest shale gas fields outside of North America. After a long period of production, some gas wells showed significant production decline and an effective refracturing treatment is designed to rejuvenate production. This Casing-in-Casing (CiC) refracturing method with customized design was successfully implemented with production increase beyond expectation. It was the first successful trial of a CiC refracturing treatment on a horizontal shale gas well in China.\u0000 Bullheading (BH) refracturing with diverting balls was attempted in this field in past years, with high initial production observed. However, the production was inconsistent and declined quickly. The operator investigated and decided to attempt a CiC refracturing method in an under-stimulated candidate well. The CiC refracturing method is to cement a 3.5-in. liner in the legacy 5.5-in. casing to isolate the perforations, and new plugging and perforating (P-n-P) operations can be performed in the reconstructed wellbore. A refracturing design was customized integrating the production profile, residual recoverable reserves, and the specific 5.5- × 3.5-in. reconstructed wellbore limitation.\u0000 During the BH refracturing, the treating pressure gradually increased with the drops of diverting balls, but the proppant placement became more and more difficult accordingly. The BH refracturing was finally completed with five cycles which was less than the design. High initial production after the BH treatment was observed but it declined quickly. In the CiC refracturing, a new 5.5-in × 3.5-in wellbore was constructed successfully, and it passed pressure test for stage frac. New clusters were added between the original clusters and stimulated with more intensive fracturing treatment in the new wellbore. Dissolvable particulate diverting agent was used for even cluster initiation and fracture geometry. The pressure response of the diverting agent was obvious indicating good diversion result and new reservoir contact. The initial production recovery rate was 88.1% compared to that of the original fracturing and the production increased 819% compared to the production before the CiC refracturing, which was much higher than BH refracturing.\u0000 This case study illustrates that the CiC refracturing method is an effective method for refracturing. It overcomes the uncertainty and difficulty of proppant placement, achieves a higher intensity of fracturing treatment, and enables stimulation of the previously bypassed reservoir to improve the recovery of the well. The method has provided the industry with a new and reliable option to rejuvenate the aging wells.","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":"130215325","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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