The inspection of the steel legs that hold up gas storage spheres has been difficult because of the thickness of cement that is applied to the legs to make them "fireproof". The cement contains steel studs that are welded to the legs and wire mesh that may vary in mesh size, all of which complicate the inspection possibilities. A new, low frequency AC scanning technique has been developed which can detect corrosion under fireproofing (CUF). The technique and its industry-supported development is described.
{"title":"Asset Integrity of Gas Storage Sphere Legs Using Advanced Technologies","authors":"Ankit Vajpayee","doi":"10.2118/207747-ms","DOIUrl":"https://doi.org/10.2118/207747-ms","url":null,"abstract":"\u0000 The inspection of the steel legs that hold up gas storage spheres has been difficult because of the thickness of cement that is applied to the legs to make them \"fireproof\". The cement contains steel studs that are welded to the legs and wire mesh that may vary in mesh size, all of which complicate the inspection possibilities. A new, low frequency AC scanning technique has been developed which can detect corrosion under fireproofing (CUF). The technique and its industry-supported development is described.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"17 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82616676","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}
J. Tsau, Qinwen Fu, R. Barati, J. Zaghloul, A. Baldwin, K. Bradford, B. Nicoud, J. D. Mohrbacher
The hydrocarbon gas huff and puff (HnP) technique has been used to improve oil production in unconventional oil reservoirs where excess capacity of produced gas is available and hydrocarbon prices are in a range to result in an economically viable case. Eagle Ford (EF) is one of the largest unconventional oil plays in the United State where HnP has been applied for enhanced oil recovery (EOR) at reservoirs within various oil windows. Our previously published Huff-n-puff results on dead oil with produced gas from Eagle Ford (EF) showed the recovery factor of hydrocarbon varying from 40 to 58%. The objective of this paper is to extend the experiments to live oil with EF core plugs to investigate the mechanisms of HnP which are affected by the composition of injected gas and resident oil, injection and soaking time as well as injection/depletion pressure gradient. Eagle Ford live oil and natural gas produced from the target area were used for HnP tests. Four representative core plugs were used with the tests conducted at reservoir conditions (125 °C and 3,500 psi). The live oil experiments with four reservoir core plugs showed an improvement in oil recovery with recovery factor (RF) varying from 19.5 to 33 % in six cycles of HnP, whereas the primary depletion on the same core plug showed RF below 11 %. A lower recovery factor of HnP from live oil saturated core in this study was observed as compared to dead oil saturated core reported in a previous publication. It is attributed to a lesser diffusion effect on mass transfer between injected gas and resident oil when the core is saturated with live oil. This behavior is displayed by the pressure decline curve during the first soaking period. A sharper diffusion pressure decline occurred in the dead oil saturated core plug where a higher concentration gradient between injected gas and resident oil drives a faster gas transport into the oil due to the molecular diffusion during the soaking period.
烃类气吞吐(HnP)技术已被用于提高非常规油藏的产量，这些油藏的产出气产能过剩，且烃类价格在经济上可行的范围内。Eagle Ford (EF)是美国最大的非常规油区之一，HnP已应用于不同油窗的储层提高采收率(EOR)。我们之前发表的针对Eagle Ford (EF)采出气的死油的huffn -puff结果显示，油气的采收率从40%到58%不等。本文的目的是将实验扩展到使用EF岩心塞的活油，以研究注入气和常住油的组成、注入和浸泡时间以及注入/耗尽压力梯度对HnP的影响机制。从目标区域产出的Eagle Ford活油和天然气用于HnP测试。在油藏条件下(125°C和3500 psi)，使用了四个具有代表性的岩心桥塞进行了测试。4个储层岩心桥塞的油井实验表明，在6个HnP循环中，采收率提高，采收率系数(RF)从19.5%到33%不等，而同一岩心桥塞的初始枯竭显示RF低于11%。与之前发表的报告相比，本研究中从活油饱和岩心中提取的HnP采收率较低。这是由于当岩心被活油饱和时，注入气体和驻留油之间的传质扩散效应较小。这一特性在第一次浸泡期间的压力下降曲线中得到了体现。在死油饱和岩心塞中，由于浸渍期分子扩散作用，注入气和滞留油之间的浓度梯度较高，导致气体运移到油中速度更快，扩散压力下降幅度更大。
{"title":"Experimental Investigation of Hydrocarbon Gas Huff-N-Puff Injection into the Live-Oil Window of Eagle Ford","authors":"J. Tsau, Qinwen Fu, R. Barati, J. Zaghloul, A. Baldwin, K. Bradford, B. Nicoud, J. D. Mohrbacher","doi":"10.2118/207224-ms","DOIUrl":"https://doi.org/10.2118/207224-ms","url":null,"abstract":"\u0000 The hydrocarbon gas huff and puff (HnP) technique has been used to improve oil production in unconventional oil reservoirs where excess capacity of produced gas is available and hydrocarbon prices are in a range to result in an economically viable case. Eagle Ford (EF) is one of the largest unconventional oil plays in the United State where HnP has been applied for enhanced oil recovery (EOR) at reservoirs within various oil windows. Our previously published Huff-n-puff results on dead oil with produced gas from Eagle Ford (EF) showed the recovery factor of hydrocarbon varying from 40 to 58%. The objective of this paper is to extend the experiments to live oil with EF core plugs to investigate the mechanisms of HnP which are affected by the composition of injected gas and resident oil, injection and soaking time as well as injection/depletion pressure gradient.\u0000 Eagle Ford live oil and natural gas produced from the target area were used for HnP tests. Four representative core plugs were used with the tests conducted at reservoir conditions (125 °C and 3,500 psi).\u0000 The live oil experiments with four reservoir core plugs showed an improvement in oil recovery with recovery factor (RF) varying from 19.5 to 33 % in six cycles of HnP, whereas the primary depletion on the same core plug showed RF below 11 %. A lower recovery factor of HnP from live oil saturated core in this study was observed as compared to dead oil saturated core reported in a previous publication. It is attributed to a lesser diffusion effect on mass transfer between injected gas and resident oil when the core is saturated with live oil. This behavior is displayed by the pressure decline curve during the first soaking period. A sharper diffusion pressure decline occurred in the dead oil saturated core plug where a higher concentration gradient between injected gas and resident oil drives a faster gas transport into the oil due to the molecular diffusion during the soaking period.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"20 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88209626","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}
Pawan Agrawal, S. Yousif, A. Shokry, T. Saqib, O. Keshtta, Y. Bigno, Abdullah Al Ghailani
In a giant offshore UAE carbonate oil field, challenges related to advanced maturity, presence of a huge gas-cap and reservoir heterogeneities have impacted production performance. More than 30% of oil producers are closed due to gas front advance and this percentage is increasing with time. The viability of future developments is highly impacted by lower completion design and ways to limit gas breakthrough. Autonomous inflow-control devices (AICD's) are seen as a viable lower completion method to mitigate gas production while allowing oil production, but their effect on pressure drawdown must be carefully accounted for, in a context of particularly high export pressure. A first AICD completion was tested in 2020, after a careful selection amongst high-GOR wells and a diagnosis of underlying gas production mechanisms. The selected pilot is an open-hole horizontal drain closed due to high GOR. Its production profile was investigated through a baseline production log. Several AICD designs were simulated using a nodal analysis model to account for the export pressure. Reservoir simulation was used to evaluate the long-term performance of short-listed scenarios. The integrated process involved all disciplines, from geology, reservoir engineering, petrophysics, to petroleum and completion engineering. In the finally selected design, only the high-permeability heel part of the horizontal drain was covered by AICDs, whereas the rest was completed with pre-perforated liner intervals, separated with swell packers. It was considered that a balance between gas isolation and pressure draw-down reduction had to be found to ensure production viability for such pilot evaluation. Subsequent to the re-completion, the well could be produced at low GOR, and a second production log confirmed the effectiveness of AICDs in isolating free gas production, while enhancing healthy oil production from the deeper part of the drain. Continuous production monitoring, and other flow profile surveys, will complete the evaluation of AICD effectiveness and its adaptability to evolving pressure and fluid distribution within the reservoir. Several lessons will be learnt from this first AICD pilot, particularly related to the criticality of fully integrated subsurface understanding, evaluation, and completion design studies. The use of AICD technology appears promising for retrofit solutions in high-GOR inactive strings, prolonging well life and increasing reserves. Regarding newly drilled wells, dedicated efforts are underway to associate this technology with enhanced reservoir evaluation methods, allowing to directly design the lower completion based on diagnosed reservoir heterogeneities. Reduced export pressure and artificial lift will feature in future field development phases, and offer the flexibility to extend the use of AICD's. The current technology evaluation phases are however crucial in the definition of such technology deployments and the confirmation of their lon
{"title":"Unlocking By-Passed Oil with Autonomous Inflow Control Devices Through an Integrated Approach","authors":"Pawan Agrawal, S. Yousif, A. Shokry, T. Saqib, O. Keshtta, Y. Bigno, Abdullah Al Ghailani","doi":"10.2118/207569-ms","DOIUrl":"https://doi.org/10.2118/207569-ms","url":null,"abstract":"\u0000 In a giant offshore UAE carbonate oil field, challenges related to advanced maturity, presence of a huge gas-cap and reservoir heterogeneities have impacted production performance. More than 30% of oil producers are closed due to gas front advance and this percentage is increasing with time. The viability of future developments is highly impacted by lower completion design and ways to limit gas breakthrough.\u0000 Autonomous inflow-control devices (AICD's) are seen as a viable lower completion method to mitigate gas production while allowing oil production, but their effect on pressure drawdown must be carefully accounted for, in a context of particularly high export pressure. A first AICD completion was tested in 2020, after a careful selection amongst high-GOR wells and a diagnosis of underlying gas production mechanisms. The selected pilot is an open-hole horizontal drain closed due to high GOR. Its production profile was investigated through a baseline production log. Several AICD designs were simulated using a nodal analysis model to account for the export pressure. Reservoir simulation was used to evaluate the long-term performance of short-listed scenarios.\u0000 The integrated process involved all disciplines, from geology, reservoir engineering, petrophysics, to petroleum and completion engineering. In the finally selected design, only the high-permeability heel part of the horizontal drain was covered by AICDs, whereas the rest was completed with pre-perforated liner intervals, separated with swell packers. It was considered that a balance between gas isolation and pressure draw-down reduction had to be found to ensure production viability for such pilot evaluation. Subsequent to the re-completion, the well could be produced at low GOR, and a second production log confirmed the effectiveness of AICDs in isolating free gas production, while enhancing healthy oil production from the deeper part of the drain. Continuous production monitoring, and other flow profile surveys, will complete the evaluation of AICD effectiveness and its adaptability to evolving pressure and fluid distribution within the reservoir.\u0000 Several lessons will be learnt from this first AICD pilot, particularly related to the criticality of fully integrated subsurface understanding, evaluation, and completion design studies. The use of AICD technology appears promising for retrofit solutions in high-GOR inactive strings, prolonging well life and increasing reserves. Regarding newly drilled wells, dedicated efforts are underway to associate this technology with enhanced reservoir evaluation methods, allowing to directly design the lower completion based on diagnosed reservoir heterogeneities. Reduced export pressure and artificial lift will feature in future field development phases, and offer the flexibility to extend the use of AICD's. The current technology evaluation phases are however crucial in the definition of such technology deployments and the confirmation of their lon","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"73 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75985414","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
B. Bernadi, I. Mohamed, Ahmed Mohamed Al Bairaq, M. A. Hosani, A. Abdullayev, Allen Roopal
A comprehensive study of a giant onshore Abu Dhabi gas field using a next-generation commercial numerical simulator has been conducted. The objective was to identify the distribution and track the movement of the gas condensate in the reservoir, and to develop strategies to minimize the condensate drop-out and improve condensate recovery from the field. The field contains a large gas cap and an oil rim. We have identified the distribution of the gas condensate throughout the reservoir and were able to track its movement using the advanced fluid tracking option in the simulator. Once the gas condensate drop-out regions in the reservoir are identified, sensitivity runs with localized changes are carried out to improve the recovery from the reservoir. The strategies to mitigate drop-out include adding infill wells, drilling multi-lateral wells, reinjecting CO2 and dry gas into the reservoir, and hydraulic fracturing near the well bore. We were able to track the distribution of the condensate throughout the reservoir and identified key condensate drop-out regions. Adding infill wells improved the recovery of the condensate. Implementing multi-lateral wells also showed improved condensate recovery in the field. Hydraulic fracturing near the wellbore reduced condensate banking near the wellbore. Injecting dry gas improved the condensate recovery by a re-vaporization process where the liquid condensate is absorbed by dry gas. This paper discusses a comprehensive study on tracking the condensate distribution in a giant onshore field using a commercial simulator. The authors have performed a thorough investigation to identify an optimal condensate recovery strategy for the field, by comparing various recovery strategies using the full field reservoir simulation model.
{"title":"A Comprehensive Study Developing and Maximizing the Recovery of Gas Condensate from a Giant Onshore Abu Dhabi Gas Field Utilizing Advanced Condensate Tracking, Gas Injection and Drilling Strategies in Next-generation Commercial Numerical Simulator","authors":"B. Bernadi, I. Mohamed, Ahmed Mohamed Al Bairaq, M. A. Hosani, A. Abdullayev, Allen Roopal","doi":"10.2118/207765-ms","DOIUrl":"https://doi.org/10.2118/207765-ms","url":null,"abstract":"\u0000 A comprehensive study of a giant onshore Abu Dhabi gas field using a next-generation commercial numerical simulator has been conducted. The objective was to identify the distribution and track the movement of the gas condensate in the reservoir, and to develop strategies to minimize the condensate drop-out and improve condensate recovery from the field.\u0000 The field contains a large gas cap and an oil rim. We have identified the distribution of the gas condensate throughout the reservoir and were able to track its movement using the advanced fluid tracking option in the simulator. Once the gas condensate drop-out regions in the reservoir are identified, sensitivity runs with localized changes are carried out to improve the recovery from the reservoir. The strategies to mitigate drop-out include adding infill wells, drilling multi-lateral wells, reinjecting CO2 and dry gas into the reservoir, and hydraulic fracturing near the well bore.\u0000 We were able to track the distribution of the condensate throughout the reservoir and identified key condensate drop-out regions. Adding infill wells improved the recovery of the condensate. Implementing multi-lateral wells also showed improved condensate recovery in the field. Hydraulic fracturing near the wellbore reduced condensate banking near the wellbore. Injecting dry gas improved the condensate recovery by a re-vaporization process where the liquid condensate is absorbed by dry gas.\u0000 This paper discusses a comprehensive study on tracking the condensate distribution in a giant onshore field using a commercial simulator. The authors have performed a thorough investigation to identify an optimal condensate recovery strategy for the field, by comparing various recovery strategies using the full field reservoir simulation model.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75933717","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}
Khaled Al Khoujah, Antonio Medina, J. A. Al Qaydi, Jawwad Kaleem, Fatima Hassan Al Mansoori, M. Nisar, Markus Lentz
An innovative design was implemented as a solution for the repetitive failure of a plate heat exchanger installed at Gas Processing Facilitates due to weld cracking, the new design was introduced for the first time in the facility, demonstrating the novelty of utilizing new technologies and enhanced designs in Heat Exchangers used for gas processing. The main challenges were in accommodating various operating modes and ensure the prevention of reoccurrence of the failures. The success was achieved through the collaboration between the operating company and Industry experts in heat transfer equipment to replace the existing design at the gas processing Facilitates with no change in piping layouts, hence, performing the replacement at optimal cost and maximum benefit.
{"title":"Upgrade of Plate Heat Exchanger at Optimal Cost Through Core Pack Plate Welding Modification","authors":"Khaled Al Khoujah, Antonio Medina, J. A. Al Qaydi, Jawwad Kaleem, Fatima Hassan Al Mansoori, M. Nisar, Markus Lentz","doi":"10.2118/207461-ms","DOIUrl":"https://doi.org/10.2118/207461-ms","url":null,"abstract":"\u0000 An innovative design was implemented as a solution for the repetitive failure of a plate heat exchanger installed at Gas Processing Facilitates due to weld cracking, the new design was introduced for the first time in the facility, demonstrating the novelty of utilizing new technologies and enhanced designs in Heat Exchangers used for gas processing. The main challenges were in accommodating various operating modes and ensure the prevention of reoccurrence of the failures. The success was achieved through the collaboration between the operating company and Industry experts in heat transfer equipment to replace the existing design at the gas processing Facilitates with no change in piping layouts, hence, performing the replacement at optimal cost and maximum benefit.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"122 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76841330","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Y. Samarkin, M. Aljawad, A. Amao, T. Sølling, K. Al-Ramadan, M. AlTammar, K. Alruwaili
Hydraulic fracturing is applied in tight formations to create conductive paths within the reservoir. However, the conductivity of the created fractures declines with time due to the closure stresses. The decline is sharp in soft formations because of proppant embedment and fracture surface asperities failure. The improvement in fracture surface hardness can mitigate the abovementioned challenges and sustain the fracture conductivity. This research targeted enhancing carbonate rock's hardness by forming minerals harder than calcite. Carbonate rocks, namely dolomite, limestone, and chalk, were treated at ambient temperature conditions by immersion into the aqueous solutions of NaF and ZnSO4 with a concentration of 0.1M. During treatment, the solution was sampled to monitor the changes in ion concentration and estimate the reaction kinetics by ICP - OES and IC devices. The hardness of rock samples was measured by impulse hammering technique before and after the treatment. The changes in rock's mineralogy and elemental content were studied by XRD and SEM imaging. The permeability of rocks was estimated by the steady-state gas injection method. The formation of smithsonite (ZnCO3, Mohs scale hardness - 4.5) and fluorite (CaF2, Mohs scale hardness - 4) was achieved in the reaction of calcite (CaCO3, Mohs scale hardness – 3) with ZnSO4 and NaF, respectively. Chalk and limestone reacted efficiently with both solutions; however, the dolomite reaction with solutions was feeble. XRD detected the newly formed smithsonite minerals, and it was observed in SEM images that minerals formed an interconnected net in chalk and limestone specimens. In dolomite samples, the minerals formed isolated gatherings that were sparsely located on the grains. The treatments caused the improvement of the rock specimen's hardness. 0.1M solution of NaF was not effective in strengthening the rock samples (only chalk sample experienced 6.7% improvement in hardness) because of low concentration of the solutions used; however, treatment resulted in negligible changes in permeability of the samples. In contrast, Young's modulus of limestone and chalk treated by ZnSO4 increased by 17% and 21%. Permeability of rocks treated by ZnSO4 reduced drastically, most likely due to the formation of gypsum as a byproduct of the reaction. This research presents a method for carbonate rock hardening via the transformation of parent calcite into harder minerals. It explains its possible application in the petroleum industry to sustain the conductivity of propped/acid fractures. The proposed technique will help to mitigate fracture conductivity decline due to proppant embedment and asperities failure issues that are especially severe in soft formations.
{"title":"Improving Long-Term Hydraulic Fracture Conductivity in Carbonate Formations by Substitution of Harder Minerals","authors":"Y. Samarkin, M. Aljawad, A. Amao, T. Sølling, K. Al-Ramadan, M. AlTammar, K. Alruwaili","doi":"10.2118/208118-ms","DOIUrl":"https://doi.org/10.2118/208118-ms","url":null,"abstract":"\u0000 Hydraulic fracturing is applied in tight formations to create conductive paths within the reservoir. However, the conductivity of the created fractures declines with time due to the closure stresses. The decline is sharp in soft formations because of proppant embedment and fracture surface asperities failure. The improvement in fracture surface hardness can mitigate the abovementioned challenges and sustain the fracture conductivity. This research targeted enhancing carbonate rock's hardness by forming minerals harder than calcite.\u0000 Carbonate rocks, namely dolomite, limestone, and chalk, were treated at ambient temperature conditions by immersion into the aqueous solutions of NaF and ZnSO4 with a concentration of 0.1M. During treatment, the solution was sampled to monitor the changes in ion concentration and estimate the reaction kinetics by ICP - OES and IC devices. The hardness of rock samples was measured by impulse hammering technique before and after the treatment. The changes in rock's mineralogy and elemental content were studied by XRD and SEM imaging. The permeability of rocks was estimated by the steady-state gas injection method.\u0000 The formation of smithsonite (ZnCO3, Mohs scale hardness - 4.5) and fluorite (CaF2, Mohs scale hardness - 4) was achieved in the reaction of calcite (CaCO3, Mohs scale hardness – 3) with ZnSO4 and NaF, respectively. Chalk and limestone reacted efficiently with both solutions; however, the dolomite reaction with solutions was feeble. XRD detected the newly formed smithsonite minerals, and it was observed in SEM images that minerals formed an interconnected net in chalk and limestone specimens. In dolomite samples, the minerals formed isolated gatherings that were sparsely located on the grains. The treatments caused the improvement of the rock specimen's hardness. 0.1M solution of NaF was not effective in strengthening the rock samples (only chalk sample experienced 6.7% improvement in hardness) because of low concentration of the solutions used; however, treatment resulted in negligible changes in permeability of the samples. In contrast, Young's modulus of limestone and chalk treated by ZnSO4 increased by 17% and 21%. Permeability of rocks treated by ZnSO4 reduced drastically, most likely due to the formation of gypsum as a byproduct of the reaction.\u0000 This research presents a method for carbonate rock hardening via the transformation of parent calcite into harder minerals. It explains its possible application in the petroleum industry to sustain the conductivity of propped/acid fractures. The proposed technique will help to mitigate fracture conductivity decline due to proppant embedment and asperities failure issues that are especially severe in soft formations.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"95 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79241352","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}
Operational Excellence and Automation Excellence go hand in hand when it comes to enabling process optimization and cost-reduction opportunities in Upstream Oil & Gas Operations. As part of our Digital Journey in the Upstream Business, multiple streams and workflows have been created to successfully identify and explore the use of new technologies to foster collaboration, achieve higher levels of efficiency, lower operating costs, maximize production and asset integrity, improve decision making, and lower the carbon footprint of all of our exploration and production activities. While our Digital Journey has been highly successful in identifying, assessing and implementing new technologies and novel solutions, it has also made very clear, during the development of business-cases’, that a rather big number of existing and older facilities were not going to be good cost-effective candidates for the deployment of many of the identified solutions and technologies. As an established and rooted operator with a large number of aging facilities, these presented an additional challenge to dig deeper and look further for solutions to cover all of these remaining assets, no matter how old or small they could be.
{"title":"Capex-Free Production Facilities Optimization Opportunities by Exploiting Installed Automation Infrastructure and Unused Functionalities","authors":"Jose David De Sousa Drumond","doi":"10.2118/207699-ms","DOIUrl":"https://doi.org/10.2118/207699-ms","url":null,"abstract":"\u0000 Operational Excellence and Automation Excellence go hand in hand when it comes to enabling process optimization and cost-reduction opportunities in Upstream Oil & Gas Operations.\u0000 As part of our Digital Journey in the Upstream Business, multiple streams and workflows have been created to successfully identify and explore the use of new technologies to foster collaboration, achieve higher levels of efficiency, lower operating costs, maximize production and asset integrity, improve decision making, and lower the carbon footprint of all of our exploration and production activities.\u0000 While our Digital Journey has been highly successful in identifying, assessing and implementing new technologies and novel solutions, it has also made very clear, during the development of business-cases’, that a rather big number of existing and older facilities were not going to be good cost-effective candidates for the deployment of many of the identified solutions and technologies. As an established and rooted operator with a large number of aging facilities, these presented an additional challenge to dig deeper and look further for solutions to cover all of these remaining assets, no matter how old or small they could be.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"19 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74442393","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. I. Mohamed, Ahmed Mahmoud El-Menoufi, Eman Abed Ezz El-Regal, Ahmed M. S. Ali, K. Mansour, Mohamed Nagy Negm, Hatem Mohamed Hussein
Field development planning of gas condensate fields using numerical simulation has many aspects to consider that may lead to a significant impact on production optimization. An important aspect is to account for the effects of network constraints and process plant operating conditions through an integrated asset model. This model should honor proper representation of the fluid within the reservoir, through the wells and up to the network and facility. Obaiyed is one of the biggest onshore gas field in Egypt, it is a highly heterogeneous gas condensate field located in the western desert of Egypt with more than 100 wells. Three initial condensate gas ratios are existing based on early PVT samples and production testing. The initial CGR values are as following;160, 115 and 42 STB/MMSCF. With continuous pressure depletion, the produced hydrocarbon composition stream changes, causing a deviation between the design parameters and the operating parameters of the equipment within the process plant, resulting in a decrease in the recovery of liquid condensate. Therefore, the facility engineers demand a dynamic update of a detailed composition stream to optimize the system and achieve greater economic value. The best way to obtain this compositional stream is by using a fully compositional integrated asset model. Utilizing a fully compositional model in Obaiyed is challenging, computationally expensive, and impractical, especially during the history match of the reservoir numerical model. In this paper, a case study for Obaiyed field is presented in which we used an alternative integrated asset modeling approach comprising a modified black-oil (MBO) that results in significant timesaving in the full-field reservoir simulation model. We then used a proper de-lumping scheme to convert the modified black oil tables into as many components as required by the surface network and process plant facility. The results of proposed approach are compared with a fully compositional approach for validity check. The results clearly identified the system bottlenecks. The model enables the facility engineers to keep the conditions of the surface facility within the optimized operating envelope throughout the field's lifetime and will be used to propose new locations and optimize the tie-in location of future wells in addition to providing flow assurance indications throughout the field's life and under different network configurations.
{"title":"A Case History for an Integrated Asset Model with Fluid Delumping for a Complex Gas Condensate Field","authors":"M. I. Mohamed, Ahmed Mahmoud El-Menoufi, Eman Abed Ezz El-Regal, Ahmed M. S. Ali, K. Mansour, Mohamed Nagy Negm, Hatem Mohamed Hussein","doi":"10.2118/207718-ms","DOIUrl":"https://doi.org/10.2118/207718-ms","url":null,"abstract":"\u0000 Field development planning of gas condensate fields using numerical simulation has many aspects to consider that may lead to a significant impact on production optimization. An important aspect is to account for the effects of network constraints and process plant operating conditions through an integrated asset model. This model should honor proper representation of the fluid within the reservoir, through the wells and up to the network and facility.\u0000 Obaiyed is one of the biggest onshore gas field in Egypt, it is a highly heterogeneous gas condensate field located in the western desert of Egypt with more than 100 wells. Three initial condensate gas ratios are existing based on early PVT samples and production testing. The initial CGR values are as following;160, 115 and 42 STB/MMSCF. With continuous pressure depletion, the produced hydrocarbon composition stream changes, causing a deviation between the design parameters and the operating parameters of the equipment within the process plant, resulting in a decrease in the recovery of liquid condensate. Therefore, the facility engineers demand a dynamic update of a detailed composition stream to optimize the system and achieve greater economic value. The best way to obtain this compositional stream is by using a fully compositional integrated asset model.\u0000 Utilizing a fully compositional model in Obaiyed is challenging, computationally expensive, and impractical, especially during the history match of the reservoir numerical model.\u0000 In this paper, a case study for Obaiyed field is presented in which we used an alternative integrated asset modeling approach comprising a modified black-oil (MBO) that results in significant timesaving in the full-field reservoir simulation model. We then used a proper de-lumping scheme to convert the modified black oil tables into as many components as required by the surface network and process plant facility. The results of proposed approach are compared with a fully compositional approach for validity check. The results clearly identified the system bottlenecks. The model enables the facility engineers to keep the conditions of the surface facility within the optimized operating envelope throughout the field's lifetime and will be used to propose new locations and optimize the tie-in location of future wells in addition to providing flow assurance indications throughout the field's life and under different network configurations.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84670027","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}
Keeping track of the oil and gas supply chain is challenging task as the route and transportation requires sophisticated security environment - both physical systems’ and IT systems’ security. Thanks to the recent advancement in IoT, specialized sensors can keep track of the required supply chain environment. With the help of blockchain, the supply chain data can be immutably saved for further sharing with stakeholders. Due to the introduction of AI as an embedded element within 6G networks, the end-to-end supply chain process can now be automated for safety, security, and efficiency purposes. By leveraging 6G, AI, blockchain, and IoT, the supply chain data during the transportation or at rest can be monitored for any changed environment during the movement of the ship through national or international routes. In this paper, we study the requirements of such intelligent and secure supply chain management system conducive to the oil and gas industry. We also show our proof-of-concept implementation and initial test results. Our obtained results show promising prospect of the current system to be deployed to safeguard the oil and gas supply chain.
{"title":"Blockchain and 6G-Based Supply Chain Management Framework for Oil and Gas Shipment","authors":"Md. Abdur Rahman, Syed M. Belal","doi":"10.2118/207328-ms","DOIUrl":"https://doi.org/10.2118/207328-ms","url":null,"abstract":"\u0000 Keeping track of the oil and gas supply chain is challenging task as the route and transportation requires sophisticated security environment - both physical systems’ and IT systems’ security. Thanks to the recent advancement in IoT, specialized sensors can keep track of the required supply chain environment. With the help of blockchain, the supply chain data can be immutably saved for further sharing with stakeholders. Due to the introduction of AI as an embedded element within 6G networks, the end-to-end supply chain process can now be automated for safety, security, and efficiency purposes. By leveraging 6G, AI, blockchain, and IoT, the supply chain data during the transportation or at rest can be monitored for any changed environment during the movement of the ship through national or international routes. In this paper, we study the requirements of such intelligent and secure supply chain management system conducive to the oil and gas industry. We also show our proof-of-concept implementation and initial test results. Our obtained results show promising prospect of the current system to be deployed to safeguard the oil and gas supply chain.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89959822","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}
Passive fire protection (PFP) is applied to steel structures in process plants to delay temperature rise and maintain structural integrity until active firefighting methods are deployed and fire is contained. Our largest gas plant was developed in several phases spanning over 25years with fireproofing designed and applied as per existing philosophy during respective execution phases. During recent Risk Management Survey, potential gaps in fireproofing were observed and survey recommended a campaign to review and identify similar gaps across entire Plant. This paper highlights the approach for gap identification, assessment and optimal recommendations which ensure safety and asset integrity while avoiding high OPEX. Fire hazard evaluation is carried out based on risk assessment of fire and hydrocarbon leakage scenarios in process plant, and recommendations for fire prevention, protection and firefighting measures are provided. Requirement of fire protection is dependent on fire source and resulting fire influence zone (fireproofing zone drawings, FPZ). Structures which are located within the FPZ are then evaluated as per identified criteria in a sequential approach (e.g. whether sudden collapse will cause significant damage, structure supports equipment containing toxic material etc.). Further detailed assessment of structural members and their impact on overall structural stability and integrity is carried out for identified structures to determine fireproofing needs. Based on the outcome, fireproofing is applied for identified members. The scope involved assessment of structural steel fireproofing in the entire complex comprising of over 40 numbers process units and 12 numbers utility units. Several teams conducted physical site survey to identify the actual fireproofing based on zone drawings across the entire plant. Desktop assessment and identification of gaps were carried out primarily based on Project fireproofing specifications, fireproofing zone drawings, fireproofing location drawings, fireproofing schedule, structural design calculations and 3-D models wherever available for respective areas. Study revealed that actual fireproofing at site in each phase of plant is consistent within all process units installed as part of that particular project, however inconsistencies were observed when compared across the different phases, probably due to different interpretation of requirements. To ensure consistency a common criteria was established considering fire source, equipment supported by structure, criticality of member and industry standards. Optimized solutions was recommended to avoid high OPEX while ensuring asset integrity and safety. Fireproofing criteria are general guidelines susceptible to various interpretations by respective users. Establishment of common criteria and elimination of ambiguities in specifications enables consistent application of fireproofing, resulting in optimization while ensuring asset safety and integri
{"title":"Managing Safety and Ensuring Asset Integrity Through Judicious PFP Application","authors":"T. Subramanian, Ibrahim Al Awadhi","doi":"10.2118/207745-ms","DOIUrl":"https://doi.org/10.2118/207745-ms","url":null,"abstract":"\u0000 Passive fire protection (PFP) is applied to steel structures in process plants to delay temperature rise and maintain structural integrity until active firefighting methods are deployed and fire is contained. Our largest gas plant was developed in several phases spanning over 25years with fireproofing designed and applied as per existing philosophy during respective execution phases. During recent Risk Management Survey, potential gaps in fireproofing were observed and survey recommended a campaign to review and identify similar gaps across entire Plant. This paper highlights the approach for gap identification, assessment and optimal recommendations which ensure safety and asset integrity while avoiding high OPEX.\u0000 Fire hazard evaluation is carried out based on risk assessment of fire and hydrocarbon leakage scenarios in process plant, and recommendations for fire prevention, protection and firefighting measures are provided. Requirement of fire protection is dependent on fire source and resulting fire influence zone (fireproofing zone drawings, FPZ).\u0000 Structures which are located within the FPZ are then evaluated as per identified criteria in a sequential approach (e.g. whether sudden collapse will cause significant damage, structure supports equipment containing toxic material etc.). Further detailed assessment of structural members and their impact on overall structural stability and integrity is carried out for identified structures to determine fireproofing needs. Based on the outcome, fireproofing is applied for identified members.\u0000 The scope involved assessment of structural steel fireproofing in the entire complex comprising of over 40 numbers process units and 12 numbers utility units. Several teams conducted physical site survey to identify the actual fireproofing based on zone drawings across the entire plant. Desktop assessment and identification of gaps were carried out primarily based on Project fireproofing specifications, fireproofing zone drawings, fireproofing location drawings, fireproofing schedule, structural design calculations and 3-D models wherever available for respective areas. Study revealed that actual fireproofing at site in each phase of plant is consistent within all process units installed as part of that particular project, however inconsistencies were observed when compared across the different phases, probably due to different interpretation of requirements. To ensure consistency a common criteria was established considering fire source, equipment supported by structure, criticality of member and industry standards. Optimized solutions was recommended to avoid high OPEX while ensuring asset integrity and safety.\u0000 Fireproofing criteria are general guidelines susceptible to various interpretations by respective users. Establishment of common criteria and elimination of ambiguities in specifications enables consistent application of fireproofing, resulting in optimization while ensuring asset safety and integri","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"587 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77991037","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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