A series of explosions destroyed several houses at Al-Ahmadi Town in southeast Kuwait during 2010 and 2011; they were initially attributed to gas leakages from discarded old domestic gas supply system. The incidents led Kuwait Oil Company (KOC) to commission a surface geochemical survey of one of KOC's Al-Ahmadi housing blocks which was affected by the explosions. A serious gas explosion in Al-Ahmadi on the 18th of May 2015 prompted an evacuation of a number of Al-Ahmadi houses, followed by a prolonged investigation of the source(s) of the recurrent gas leakages. This paper is a review of the published surface geology, subsurface stratigraphy, seismic structural motives and consequences of prolonged production operations of Greater Burgan Oil Field (with special focus on the surface and subsurface stratigraphy and structure of the Al-Ahmadi Ridge of Greater Burgan Oil Field, which is situated beneath the afflicted Al-Ahmadi Town) in search of natural seepage(s) rather than man-made leakage(s) of the exploding gas. The review revealed that the gas explosions were not likely caused by trapped gas in the discarded domestic gas supply network, and argue for an imperfect Greater Burgan oil trap, with inherent ancient oil and gas seepages propagated by environmental side effects of prolonged oil production operations, which attained recurrent cycles in response to climatic seasons, and probably amplified by the occasional regional earthquake seismic waves. The review concludes that under current environments and production practices, the historic trend projects an increase in the volume and number of gas seepages sites over and beyond the footprint of Greater Burgan Oil Field. Furthermore, the review recommends some habitat gas seepage mitigation measures and the deployment of mobile technologies for regular surveying and monitoring of Methane and H2S build-up in the air, and in the shallow subsurface reservoirs below the Ahmadi Town as routine risk management procedures.
{"title":"Geologic, Seismic, Climatic and Oil Production Controls on Hydrocarbon Seepages at Al-Ahmadi Town, South-Eastern Kuwait","authors":"M. Ibrahim","doi":"10.2118/198151-ms","DOIUrl":"https://doi.org/10.2118/198151-ms","url":null,"abstract":"\u0000 A series of explosions destroyed several houses at Al-Ahmadi Town in southeast Kuwait during 2010 and 2011; they were initially attributed to gas leakages from discarded old domestic gas supply system. The incidents led Kuwait Oil Company (KOC) to commission a surface geochemical survey of one of KOC's Al-Ahmadi housing blocks which was affected by the explosions. A serious gas explosion in Al-Ahmadi on the 18th of May 2015 prompted an evacuation of a number of Al-Ahmadi houses, followed by a prolonged investigation of the source(s) of the recurrent gas leakages. This paper is a review of the published surface geology, subsurface stratigraphy, seismic structural motives and consequences of prolonged production operations of Greater Burgan Oil Field (with special focus on the surface and subsurface stratigraphy and structure of the Al-Ahmadi Ridge of Greater Burgan Oil Field, which is situated beneath the afflicted Al-Ahmadi Town) in search of natural seepage(s) rather than man-made leakage(s) of the exploding gas. The review revealed that the gas explosions were not likely caused by trapped gas in the discarded domestic gas supply network, and argue for an imperfect Greater Burgan oil trap, with inherent ancient oil and gas seepages propagated by environmental side effects of prolonged oil production operations, which attained recurrent cycles in response to climatic seasons, and probably amplified by the occasional regional earthquake seismic waves. The review concludes that under current environments and production practices, the historic trend projects an increase in the volume and number of gas seepages sites over and beyond the footprint of Greater Burgan Oil Field. Furthermore, the review recommends some habitat gas seepage mitigation measures and the deployment of mobile technologies for regular surveying and monitoring of Methane and H2S build-up in the air, and in the shallow subsurface reservoirs below the Ahmadi Town as routine risk management procedures.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"111 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124761842","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}
Hassan Z. Haddad, M. Al-Khaja, A. Saffar, S. Raturi, B. Aleem, Mohamed Samak, ElSayed Ibrahim ElSeheemy, Victor Barsoum, R. Abdelaziz, Jené Rockwood
To reach many of the world's petroleum-rich formations, drilling must first penetrate challenging shale formations where wellbore instability frequently results in costly stuck pipe, lost circulation, non-productive time, and expensive sidetracks. One technology gaining traction through successful field usage is a wellbore stabilizing agent (WSA) to limit the invasion of drilling fluid and wellbore pressure into the formation. Using a WSA can assist in stabilizing shales, delivering trouble-free drilling, and reduce losses and non-productive time. The drilling team was assigned a challenging well involving the Mutriba Formation, a shale-limestone formation notorious for stuck pipe and lost circulation. Focusing on wellbore stability and minimizing of the destabilizing nature of invasive drilling fluid and wellbore pressure, the team utilized a wellbore stabilizing agent to stop fluid invasion at the borehole wall. This barrier, or "shield", minimizes formation damage and mitigates fracture growth which can lead to destabilization of the wellbore Constant monitoring and additions of the wellbore stabilizing agent resulted in a thin, tight, flexible HTHP filtercake and wellbore stability while drilling this challenging formation. The entire section through the Mutriba Formation was drilled with 100% returns and later casing was run without problems. No adverse wellbore conditions were encountered while tripping or drilling, and no non-productive time was lost in stuck pipe or lost circulation events. When compared to the offset well, the successful well using the wellbore stabilizing agent came in 7 days ahead of schedule and with a cost savings of more than 21% for the Mutriba section. Controlling wellbore instability, especially in shale and shale-composite formations, is a key element of successful drilling in many fields across the globe. Information on field-proven technologies, such as this wellbore stabilizing agent, are important to the continual improvement of drilling fluid to safely drill similar fields around the world.
{"title":"Conquering Wellbore Instability in Kuwait","authors":"Hassan Z. Haddad, M. Al-Khaja, A. Saffar, S. Raturi, B. Aleem, Mohamed Samak, ElSayed Ibrahim ElSeheemy, Victor Barsoum, R. Abdelaziz, Jené Rockwood","doi":"10.2118/198177-ms","DOIUrl":"https://doi.org/10.2118/198177-ms","url":null,"abstract":"\u0000 To reach many of the world's petroleum-rich formations, drilling must first penetrate challenging shale formations where wellbore instability frequently results in costly stuck pipe, lost circulation, non-productive time, and expensive sidetracks. One technology gaining traction through successful field usage is a wellbore stabilizing agent (WSA) to limit the invasion of drilling fluid and wellbore pressure into the formation. Using a WSA can assist in stabilizing shales, delivering trouble-free drilling, and reduce losses and non-productive time.\u0000 The drilling team was assigned a challenging well involving the Mutriba Formation, a shale-limestone formation notorious for stuck pipe and lost circulation. Focusing on wellbore stability and minimizing of the destabilizing nature of invasive drilling fluid and wellbore pressure, the team utilized a wellbore stabilizing agent to stop fluid invasion at the borehole wall. This barrier, or \"shield\", minimizes formation damage and mitigates fracture growth which can lead to destabilization of the wellbore\u0000 Constant monitoring and additions of the wellbore stabilizing agent resulted in a thin, tight, flexible HTHP filtercake and wellbore stability while drilling this challenging formation. The entire section through the Mutriba Formation was drilled with 100% returns and later casing was run without problems. No adverse wellbore conditions were encountered while tripping or drilling, and no non-productive time was lost in stuck pipe or lost circulation events. When compared to the offset well, the successful well using the wellbore stabilizing agent came in 7 days ahead of schedule and with a cost savings of more than 21% for the Mutriba section.\u0000 Controlling wellbore instability, especially in shale and shale-composite formations, is a key element of successful drilling in many fields across the globe. Information on field-proven technologies, such as this wellbore stabilizing agent, are important to the continual improvement of drilling fluid to safely drill similar fields around the world.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"165 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124628150","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}
Hawraa A N A M Alkhalifah, T. Al-Twaitan, H. Chetri
Sabiriyah Mauddud is a giant carbonate reservoir in North Kuwait under active development with water flooding by treated seawater. Reservoir souring occurring at multiple producers has added one more dimension of complexity to be tracked; evaluated & managed. The paper proposal aims to elaborate the challenges and associated mitigations conceived & implemented. Comprehensive evaluation of all data available pertaining to reservoir souring has been done, based on which a field-wise sampling program has been embarked. The sampling program has been executed in phases in a rationalized manner to provide necessary data & inputs to the overall evaluation using analytical as well as simulation approach. Workflow process has been developed so that the tracking, evaluation & management of reservoir souring continues as a live project during the water flood development for Sabiriyah Mauddud. A clear linkage has been observed between the injected volumes of seawater and the level of souring. A review of chemicals being used for inhibition of souring indicated that the bacteria becomes insensitive to the dosage used in the past and requires re formulation of the package of chemical dosage. The impact on flowlines and production facilities has been found to be nominal so far but likely to aggravate with time. The possibility of using sour competent metallurgy in future has been flagged for future budgeting, to be first implemented in the facilities with most of Mauddud producers flowing. Any new facility has been recommended with NACE specifications. A continuous tracking & monitoring of the Reservoir souring lead to opportunistic solutions & mitigations for short-term production & long-term reservoir management requirements with HSE adherence.
{"title":"Reservoir Souring Tracking; Evaluation & Management to De-Eisk the Development Activities in a Giant Carbonate Reservoir in North Kuwait","authors":"Hawraa A N A M Alkhalifah, T. Al-Twaitan, H. Chetri","doi":"10.2118/198059-ms","DOIUrl":"https://doi.org/10.2118/198059-ms","url":null,"abstract":"\u0000 Sabiriyah Mauddud is a giant carbonate reservoir in North Kuwait under active development with water flooding by treated seawater. Reservoir souring occurring at multiple producers has added one more dimension of complexity to be tracked; evaluated & managed. The paper proposal aims to elaborate the challenges and associated mitigations conceived & implemented.\u0000 Comprehensive evaluation of all data available pertaining to reservoir souring has been done, based on which a field-wise sampling program has been embarked. The sampling program has been executed in phases in a rationalized manner to provide necessary data & inputs to the overall evaluation using analytical as well as simulation approach. Workflow process has been developed so that the tracking, evaluation & management of reservoir souring continues as a live project during the water flood development for Sabiriyah Mauddud.\u0000 A clear linkage has been observed between the injected volumes of seawater and the level of souring. A review of chemicals being used for inhibition of souring indicated that the bacteria becomes insensitive to the dosage used in the past and requires re formulation of the package of chemical dosage. The impact on flowlines and production facilities has been found to be nominal so far but likely to aggravate with time. The possibility of using sour competent metallurgy in future has been flagged for future budgeting, to be first implemented in the facilities with most of Mauddud producers flowing. Any new facility has been recommended with NACE specifications.\u0000 A continuous tracking & monitoring of the Reservoir souring lead to opportunistic solutions & mitigations for short-term production & long-term reservoir management requirements with HSE adherence.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"80 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126369564","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}
Iron sulphide (FeS), zinc sulphide (ZnS) and lead sulphide (PbS) scales have been observed in many sour oil and gas wells. Sulphide scales often form alongside other scales such as calcium carbonate and barium sulphate and such scales can be removed using chemicals like hydrochloric acid (HCl) and chelating agents. However, there are several drawbacks associated with the removal of sulphide scales, for example, HCl acid, which outperforms other dissolvers has a high corrosion rate and generates hydrogen sulphide (H2S) gas as a byproduct. Other dissolvers, including chelating agents, have very low dissolution rates. Therefore, FeS inhibition is much preferred to its removal, if this can be achieved efficiently and economically. The objective of this paper is to investigate the inhibition efficiency of inhibitors/dispersants for preventing FeS, ZnS and PbS scales. Different scale inhibitor chemistries have been examined over a wide range of parameters, including temperature, salinity, pH and concentrations of Fe, Zn, Pb and sulphide. Static formation and inhibition experiments were conducted and the progress of the reaction was monitored by ion tracking using inductively coupled plasma (ICP) analysis and pH monitoring. Also, filter-blocking inhibition tests were carried out to examine the impact of scale inhibitor concentration on the scaling time. Polymeric scale inhibitors showed a high inhibition efficiency for ZnS while no inhibition was observed for phosophonate based scale inhibitors. Unlike ZnS, none of the tested scale inhibitors inhibited FeS. High molecular weight scale inhibitors performed well even at high temperature and salinity and maintained the particles suspended in solution for several days. However, high scale inhibitor concentrations were required to prevent the deposition of FeS, particularly when the iron concentration was raised to 100 ppm and above. In SI-1 solutions, it was easier to inhibit PbS and ZnS when they formed concurrently rather than forming PbS followed by ZnS. These results are in line with the difference in the MIC (Minimum Inhibitor Concentration) observed in SI-2 solutions. Based on these results, the tested polymeric scale inhibitors managed to inhibit ZnS and PbS but failed against FeS under the same conditions despite the fact that the solubility of ZnS and PbS is less than FeS. It was also found that, cation displacement and the sequence of the scale formation had a significant impact on the inhibition efficiency. The size of scale particles was dependent on the type of scale inhibitor and concentration and this was reflected in the scaling time in the dynamic inhibition tests.
{"title":"Inhibition and Interaction between Iron Sulphide, Zinc Sulphide and Lead Sulphide","authors":"B. Alharbi, N. Aljeaban, A. Graham, K. Sorbie","doi":"10.2118/198175-ms","DOIUrl":"https://doi.org/10.2118/198175-ms","url":null,"abstract":"\u0000 Iron sulphide (FeS), zinc sulphide (ZnS) and lead sulphide (PbS) scales have been observed in many sour oil and gas wells. Sulphide scales often form alongside other scales such as calcium carbonate and barium sulphate and such scales can be removed using chemicals like hydrochloric acid (HCl) and chelating agents. However, there are several drawbacks associated with the removal of sulphide scales, for example, HCl acid, which outperforms other dissolvers has a high corrosion rate and generates hydrogen sulphide (H2S) gas as a byproduct. Other dissolvers, including chelating agents, have very low dissolution rates. Therefore, FeS inhibition is much preferred to its removal, if this can be achieved efficiently and economically.\u0000 The objective of this paper is to investigate the inhibition efficiency of inhibitors/dispersants for preventing FeS, ZnS and PbS scales. Different scale inhibitor chemistries have been examined over a wide range of parameters, including temperature, salinity, pH and concentrations of Fe, Zn, Pb and sulphide. Static formation and inhibition experiments were conducted and the progress of the reaction was monitored by ion tracking using inductively coupled plasma (ICP) analysis and pH monitoring. Also, filter-blocking inhibition tests were carried out to examine the impact of scale inhibitor concentration on the scaling time.\u0000 Polymeric scale inhibitors showed a high inhibition efficiency for ZnS while no inhibition was observed for phosophonate based scale inhibitors. Unlike ZnS, none of the tested scale inhibitors inhibited FeS. High molecular weight scale inhibitors performed well even at high temperature and salinity and maintained the particles suspended in solution for several days. However, high scale inhibitor concentrations were required to prevent the deposition of FeS, particularly when the iron concentration was raised to 100 ppm and above. In SI-1 solutions, it was easier to inhibit PbS and ZnS when they formed concurrently rather than forming PbS followed by ZnS. These results are in line with the difference in the MIC (Minimum Inhibitor Concentration) observed in SI-2 solutions.\u0000 Based on these results, the tested polymeric scale inhibitors managed to inhibit ZnS and PbS but failed against FeS under the same conditions despite the fact that the solubility of ZnS and PbS is less than FeS. It was also found that, cation displacement and the sequence of the scale formation had a significant impact on the inhibition efficiency. The size of scale particles was dependent on the type of scale inhibitor and concentration and this was reflected in the scaling time in the dynamic inhibition tests.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"19 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128182048","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}
This paper presents a fast embedded discrete fracture model (EDFM) based on POD method to improve the computational efficiency. Firstly, this paper gives a brief review of EDFM and derive the form of functional equations of pressure vector or saturation vector for global equations, and this form indicates the dimension of the discrete dynamic system is about the number of cells. Then, the time costs of EDFM are analyzed in detail, and the analysis shows that reducing the order of global equations is critical to decrease the time cost. Finally, this paper derives the POD basis function expansion of the pressure or saturation vector and gives the new global equations with a low order. The accuracy and efficiency of the fast model is compared in case of different sample numbers and mode numbers, and the results show that the POD-based EDFM can significantly improve the computational efficiency while ensuring enough accuracy.
{"title":"A Fast Embedded Discrete Fracture Model Based on Proper Orthogonal Decomposition POD Method","authors":"X. Rao, Linsong Cheng, R. Cao, P. Jia, Xulin Du","doi":"10.2118/198139-ms","DOIUrl":"https://doi.org/10.2118/198139-ms","url":null,"abstract":"\u0000 This paper presents a fast embedded discrete fracture model (EDFM) based on POD method to improve the computational efficiency. Firstly, this paper gives a brief review of EDFM and derive the form of functional equations of pressure vector or saturation vector for global equations, and this form indicates the dimension of the discrete dynamic system is about the number of cells. Then, the time costs of EDFM are analyzed in detail, and the analysis shows that reducing the order of global equations is critical to decrease the time cost. Finally, this paper derives the POD basis function expansion of the pressure or saturation vector and gives the new global equations with a low order. The accuracy and efficiency of the fast model is compared in case of different sample numbers and mode numbers, and the results show that the POD-based EDFM can significantly improve the computational efficiency while ensuring enough accuracy.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"106 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122621035","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}
Fabio Gonzalez, Doris L. González, B. Altemeemi, A. Al-Nasheet, F. Snasiri, Sara Jassim, S. Sinha, P. Shaw, E. Ghloum, Bader Al-Kandari, Sohabi Kholosy, A. Emadi
Asphaltene deposition in reservoir rock is very difficult to remediate. If precipitated, asphaltenes could be trapped in the formation pores, the particles can deposit and plug the porous media reducing permeability. However, it has been hypothesized that precipitated asphaltene could entrain back into the liquid phase if the shear rate is high enough before it is deposited, adsorbed and anchored to the rock. This work intends to evaluate the role of rate in the asphaltene deposition tendency for the asphaltenic Magwa-Marrat reservoir fluid. Precisely, the purpose of this work is to study the effect of production rates and operating pressures on asphaltene deposition in the production tubing and reservoir rock at lab level running Coreflooding tests and at field level producing a well at different rates. This work provides insights into field observations of a trial well producing at a bottom hole flowing pressure below AOP. Several multi rate tests and pressure transient analysis were performed to understand asphaltene deposition in the reservoir near wellbore region and away from the well. Asphaltene deposition in the production tubing was also assessed by means of friction coefficient calculations to better understand the deposition mechanism, especially the roles played by shear rate and pressure. Coreflooding experiments at different flow rates below and above AOP were run after proper characterization of the cores and reservoir fluids. As expected, the laboratory Coreflooding results demonstrated that there were no changes in the cores’ flow capacity whether at low or at high velocities when the pore pressure was kept above AOP. However, when the pore pressure was brought below AOP, Coreflooding tests showed that the higher the velocity, the lower the permeability impairment. This concludes that fluid velocity is an important factor in the asphaltene deposition mechanism. Field tests were also conducted, and the field observations were fully consistent with laboratory results. In the case of asphaltenic crude oils, industry standards recommend depleting the reservoir to pressures no lower than AOP. Based on results of this study, and alternative approach is proposed; basically, depending on the rock-fluid properties and their interaction, it is possible to deplete the reservoir pressure significantly below AOP. Asphaltene deposition is nowadays an area of research and this study has brought some uniqueness to this subject. 1) The laboratory tests were designed together with field tests to confirm the validity of conclusions; 2) It demonstrates that a reservoir can be operated at pressures below AOP and wells produced at higher production rates as a result of operating at higher drawdowns. Altogether, the proposed approach in this paper to mitigate asphaltene deposition maximizes production offtake to the full potential of the wells while optimizing ultimate recovery; 3) Results from these field and laboratory tests have been used for f
{"title":"Understanding of Asphaltene Deposition in the Production Tubing and Reservoir Rock While Flowing at Bottom-Hole Pressure Below Asphaltene Onset Pressure, AOP in the Magwa-Marrat Field","authors":"Fabio Gonzalez, Doris L. González, B. Altemeemi, A. Al-Nasheet, F. Snasiri, Sara Jassim, S. Sinha, P. Shaw, E. Ghloum, Bader Al-Kandari, Sohabi Kholosy, A. Emadi","doi":"10.2118/198121-ms","DOIUrl":"https://doi.org/10.2118/198121-ms","url":null,"abstract":"\u0000 Asphaltene deposition in reservoir rock is very difficult to remediate. If precipitated, asphaltenes could be trapped in the formation pores, the particles can deposit and plug the porous media reducing permeability. However, it has been hypothesized that precipitated asphaltene could entrain back into the liquid phase if the shear rate is high enough before it is deposited, adsorbed and anchored to the rock. This work intends to evaluate the role of rate in the asphaltene deposition tendency for the asphaltenic Magwa-Marrat reservoir fluid. Precisely, the purpose of this work is to study the effect of production rates and operating pressures on asphaltene deposition in the production tubing and reservoir rock at lab level running Coreflooding tests and at field level producing a well at different rates.\u0000 This work provides insights into field observations of a trial well producing at a bottom hole flowing pressure below AOP. Several multi rate tests and pressure transient analysis were performed to understand asphaltene deposition in the reservoir near wellbore region and away from the well. Asphaltene deposition in the production tubing was also assessed by means of friction coefficient calculations to better understand the deposition mechanism, especially the roles played by shear rate and pressure. Coreflooding experiments at different flow rates below and above AOP were run after proper characterization of the cores and reservoir fluids.\u0000 As expected, the laboratory Coreflooding results demonstrated that there were no changes in the cores’ flow capacity whether at low or at high velocities when the pore pressure was kept above AOP. However, when the pore pressure was brought below AOP, Coreflooding tests showed that the higher the velocity, the lower the permeability impairment. This concludes that fluid velocity is an important factor in the asphaltene deposition mechanism. Field tests were also conducted, and the field observations were fully consistent with laboratory results. In the case of asphaltenic crude oils, industry standards recommend depleting the reservoir to pressures no lower than AOP. Based on results of this study, and alternative approach is proposed; basically, depending on the rock-fluid properties and their interaction, it is possible to deplete the reservoir pressure significantly below AOP.\u0000 Asphaltene deposition is nowadays an area of research and this study has brought some uniqueness to this subject. 1) The laboratory tests were designed together with field tests to confirm the validity of conclusions; 2) It demonstrates that a reservoir can be operated at pressures below AOP and wells produced at higher production rates as a result of operating at higher drawdowns. Altogether, the proposed approach in this paper to mitigate asphaltene deposition maximizes production offtake to the full potential of the wells while optimizing ultimate recovery; 3) Results from these field and laboratory tests have been used for f","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"24 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128983361","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}
Field development of mature fields in Kuwait Oil Company have seen a paradigm shift over the past couple of years, to adopt the latest field proven technology to exploit the remaining reserves. The Mauddad formation in the Bahrah field is a low permeability with high viscosity oil which was previously developed with vertical cased and perforated wells with electrical submersible pumps (ESP). Inflow monitoring also posed a challenge to conduct production logs due to challenges with the Y-tool of the ESP. In light of these challenges, it was decided to drill horizontal wells, installed with multi-stage frac completions with acid being the stimulant. The described solution was considered a recent success because of the 300% increased production compared to offset vertical wells over the same producing period. However, ESPs are still required to lift fluids to surface in these horizontal wells and the understanding of inflow performance of each stage remained a monitoring challenge. A solution was identified to utilise intelligent inflow tracers after the successful pilot in another field development in Kuwait, using passive inflow control devices (ICD) with ESPs. Therefore, it was decided to pilot the same technology which provided intervention free, permanent downhole monitoring. However, the additional challenge was to prove that inflow tracers could survive the harsh acid operation and continue to function as a reliable downhole sensor thereafter. The wells installed with intelligent chemical inflow tracers are used to provide a trend assessment of the clean-up phase of production, productivity assessment information for each stage and to event monitoring such as identifying the location of water breakthrough. Fluid samples collected from the surface flow lines were analyzed for unique chemical tracer signatures and interpreted the corresponding tracer signals. The monitoring campaigns have provided an improved understanding of fracture efficiency which has translated to frac design optimsation and also reduced subsurface uncertainty. This paper discusses the chemical sensor design, integration of the sensors, run in hole procedure, sampling, analysis and interpretations of multi-stage acid frac wells, penetrating the Mauddud reservoir. Several wells were installed with chemical sensors adjacent to the sliding sleeves compartmentalized with swell packers in horizontal producing sections of up to 3,000-ft. The post operation interpretation revealed that chemical sensors functioned after the acid jobs and revealed how each stage performed from the frac clean up operation and how productivity changed over the life of the well.
{"title":"The Application of Chemical Tracer Monitoring in Multi Stage Acid Frac Wells in the Mature Bahrah Field, North Kuwait","authors":"A. Qamber, Mohammad Hassan, A. Ali","doi":"10.2118/198037-ms","DOIUrl":"https://doi.org/10.2118/198037-ms","url":null,"abstract":"\u0000 Field development of mature fields in Kuwait Oil Company have seen a paradigm shift over the past couple of years, to adopt the latest field proven technology to exploit the remaining reserves. The Mauddad formation in the Bahrah field is a low permeability with high viscosity oil which was previously developed with vertical cased and perforated wells with electrical submersible pumps (ESP). Inflow monitoring also posed a challenge to conduct production logs due to challenges with the Y-tool of the ESP.\u0000 In light of these challenges, it was decided to drill horizontal wells, installed with multi-stage frac completions with acid being the stimulant. The described solution was considered a recent success because of the 300% increased production compared to offset vertical wells over the same producing period. However, ESPs are still required to lift fluids to surface in these horizontal wells and the understanding of inflow performance of each stage remained a monitoring challenge. A solution was identified to utilise intelligent inflow tracers after the successful pilot in another field development in Kuwait, using passive inflow control devices (ICD) with ESPs. Therefore, it was decided to pilot the same technology which provided intervention free, permanent downhole monitoring. However, the additional challenge was to prove that inflow tracers could survive the harsh acid operation and continue to function as a reliable downhole sensor thereafter.\u0000 The wells installed with intelligent chemical inflow tracers are used to provide a trend assessment of the clean-up phase of production, productivity assessment information for each stage and to event monitoring such as identifying the location of water breakthrough. Fluid samples collected from the surface flow lines were analyzed for unique chemical tracer signatures and interpreted the corresponding tracer signals. The monitoring campaigns have provided an improved understanding of fracture efficiency which has translated to frac design optimsation and also reduced subsurface uncertainty.\u0000 This paper discusses the chemical sensor design, integration of the sensors, run in hole procedure, sampling, analysis and interpretations of multi-stage acid frac wells, penetrating the Mauddud reservoir. Several wells were installed with chemical sensors adjacent to the sliding sleeves compartmentalized with swell packers in horizontal producing sections of up to 3,000-ft. The post operation interpretation revealed that chemical sensors functioned after the acid jobs and revealed how each stage performed from the frac clean up operation and how productivity changed over the life of the well.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"12 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129070854","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The Burgan sands Formation is one of the main reservoirs of Greater Burgan field in Kuwait, producing under primary depletion since the late 1940s. Massive sands reservoirs (Lower Burgan BGSL2 and Middle Burgan BGSM) interpreted as deposited in fluvio-tidal depositional environments, alternate with lower quality and muddy interbedded sandstones (Lower Burgan BGSL1 and Upper Burgan BGSU), deposited in tidal-influenced delta settings. The complex reservoir architecture of these sand reservoirs is dependent of the sinuosity and complexity of the channel system but also on the lateral extend and distribution of the muddy deposits that will create heterogeneities and barrier to flow. In the context of future development plans of the Burgan reservoirs, the Burgan Subsurface Team implemented a workflow to identify the main barriers to flow at the interface between the massive and the lower net-to-gross reservoirs. This workflow combines geological (cores), petrophysical (Rock-Types, conventional logs) and dynamic data (pressures), to characterize the main barriers to flow between the different reservoirs. Shale barrier types and thicknesses of shales are picked and defined from logs using wireline conventional log data, and the huge database of pressures available was used to visualize and check the impact of the shale barriers on the connectivity of the reservoir and the pressure drop or continuity between the sandy units. This multiple approach allows to capture the main geological heterogeneities (shale barriers) by their type and thicknesses and combining the information with dynamic data (pressures within the reservoir zones) gave a direct link to the connectivity (pressure communication or not) between the main reservoirs. The data generated by these two approaches were used to produce maps of connectivity as well as maps of pressure differences between the main reservoirs. Modeling complex reservoir heterogeneities in clastic environments is a challenge in the oil industry. An accurate sand body distribution is crucial for a good understanding and representation of the reservoir behavior but a good representation and image of the barrier to flow is fundamental to complete the picture. In the context of the future development of Burgan reservoirs, such workflow and products will be very useful to take some decisions about the strategy to develop efficiently such type of reservoirs.
{"title":"Characterization of Barriers to Flow in Burgan Reservoirs Using Geological and Dynamic Pressure Data, Burgan Field, Kuwait.","authors":"J. Filak, Laila Alawadh, Bashayer Alrefaei","doi":"10.2118/198057-ms","DOIUrl":"https://doi.org/10.2118/198057-ms","url":null,"abstract":"\u0000 The Burgan sands Formation is one of the main reservoirs of Greater Burgan field in Kuwait, producing under primary depletion since the late 1940s. Massive sands reservoirs (Lower Burgan BGSL2 and Middle Burgan BGSM) interpreted as deposited in fluvio-tidal depositional environments, alternate with lower quality and muddy interbedded sandstones (Lower Burgan BGSL1 and Upper Burgan BGSU), deposited in tidal-influenced delta settings. The complex reservoir architecture of these sand reservoirs is dependent of the sinuosity and complexity of the channel system but also on the lateral extend and distribution of the muddy deposits that will create heterogeneities and barrier to flow.\u0000 In the context of future development plans of the Burgan reservoirs, the Burgan Subsurface Team implemented a workflow to identify the main barriers to flow at the interface between the massive and the lower net-to-gross reservoirs. This workflow combines geological (cores), petrophysical (Rock-Types, conventional logs) and dynamic data (pressures), to characterize the main barriers to flow between the different reservoirs. Shale barrier types and thicknesses of shales are picked and defined from logs using wireline conventional log data, and the huge database of pressures available was used to visualize and check the impact of the shale barriers on the connectivity of the reservoir and the pressure drop or continuity between the sandy units.\u0000 This multiple approach allows to capture the main geological heterogeneities (shale barriers) by their type and thicknesses and combining the information with dynamic data (pressures within the reservoir zones) gave a direct link to the connectivity (pressure communication or not) between the main reservoirs. The data generated by these two approaches were used to produce maps of connectivity as well as maps of pressure differences between the main reservoirs.\u0000 Modeling complex reservoir heterogeneities in clastic environments is a challenge in the oil industry. An accurate sand body distribution is crucial for a good understanding and representation of the reservoir behavior but a good representation and image of the barrier to flow is fundamental to complete the picture. In the context of the future development of Burgan reservoirs, such workflow and products will be very useful to take some decisions about the strategy to develop efficiently such type of reservoirs.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"24 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115791392","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}
Mohamed El Shahati, Haidar Khadadeh, Fajer Al-Aradah
This paper analyses the role of LNG in balancing the natural gas demand in the MENA region. Natural gas is increasingly becoming a main energy source in the region due to several factors. The global LNG pricing mechanism is changing towards flexible market related methods that might encourage some countries in MENA to switch to LNG supplies. The growing requirements for natural gas as a fuel for electricity generation is estimated to be the driving force behind the growth in consumption of the hydrocarbon. Contrary to wide held belief several countries in the region could fall into deficit regarding their self-supply of gas which would require them to import it. The options of supply are either through pipeline networks or LNG. The study estimates the future demand of natural gas by country using multivariate regression and then compares it to the availability of gas as estimated by GEFC. Deficit is derived for each country and the study indicate how the deficit could be filled through pipeline or LNG.
{"title":"The Global LNG Price Trend and the Role of LNG in Balancing the Gas Demand in MENA Region","authors":"Mohamed El Shahati, Haidar Khadadeh, Fajer Al-Aradah","doi":"10.2118/198054-ms","DOIUrl":"https://doi.org/10.2118/198054-ms","url":null,"abstract":"\u0000 This paper analyses the role of LNG in balancing the natural gas demand in the MENA region. Natural gas is increasingly becoming a main energy source in the region due to several factors. The global LNG pricing mechanism is changing towards flexible market related methods that might encourage some countries in MENA to switch to LNG supplies. The growing requirements for natural gas as a fuel for electricity generation is estimated to be the driving force behind the growth in consumption of the hydrocarbon. Contrary to wide held belief several countries in the region could fall into deficit regarding their self-supply of gas which would require them to import it. The options of supply are either through pipeline networks or LNG. The study estimates the future demand of natural gas by country using multivariate regression and then compares it to the availability of gas as estimated by GEFC. Deficit is derived for each country and the study indicate how the deficit could be filled through pipeline or LNG.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"14 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126859772","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The unconventional Shale and Tight play concept has grown to dominate the North American energy landscape, now accounting for the vast majority of onshore activity levels. However, not all Shale or Tight reservoir plays are created equal and what works for one play/Formation may not work for another. How should you design your stimulation, where to begin, what parameters are most impactful and what are some of the large economic leavers that can either make your project successful, or potentially cause it to fail. The Duvernay is an Upper Devonian mudrock, with significant quartz, carbonate and total organic carbon content, making it an attractive Shale gas target. Total Organic Carbon (TOC) varies from 2-17 wt.% and porosity ranges from 3-8% (averaging approximately 5%). The Formation is approximately 2,800 – 3,800 meters deep in the project area and is approximately 35-60m thick. Importantly, the target is significantly overpressured, with nearly double normal hydrostatic reservoir pressure (15-21 Kpa/m gradient). The native permeability of the Duvernay Formation is extremely tight, measuring in the 70-150 nano Darcy range, thus the formation requires horizontal wells with multi stage hydraulic fracturing, to be economically productive. The natural fracture density of the formation partially explains how a rock with such low matrix permeability can be so prolific, background tectonic fracturing is significantly greater than most other low permeability reservoirs being exploited in North America. Fracture densities have been measured in core and image logs at up to 8 fractures per meter, with average open fracture density's approximating 1-2 per meter. These fractures are steeply dipping (75-85 degrees) and created during tectonic events, both open and healed/calcite filled fractures are present. While the presence of natural fractures aid in the productive stage of the well's life, it can complicate the stimulation design and challenge the placement of a wellbore treatment. During the initial planning stages of an unconventional hydraulic stimulation program, the first step is to examine what other operators in the play are already utilizing. Early due diligence into what design elements are successful and almost as important, not successful, can save significant amounts of capital early in the evolution of a project. An example of this within the Duvernay project were uncemented ball drop liner completion systems. Due to the high-pressure pumping requirements of the Duvernay (up to 90 Mpa), these systems were not able to adequately stimulate the reservoir and were prone to install and isolation challenges. Limited entry Plug and Perf design dominates the Canadian unconventional energy landscape, this is where Chevron Canada Limited and KUFPEC Canada ("The JV") began its journey. The next critical stimulation parameters to decide on are proppant and water intensities, these will govern the duration of the stimulation and are key economic dr
非常规页岩和致密储层的概念已经主导了北美的能源格局，目前占陆上活动水平的绝大部分。然而，并不是所有的页岩或致密储层都是一样的，适用于一个储层/储层的方法可能并不适用于另一个储层。你应该如何设计刺激措施，从哪里开始，哪些参数最具影响力，哪些是可能使项目成功或可能导致项目失败的重大经济因素。Duvernay为上泥盆统泥岩，具有丰富的石英、碳酸盐和总有机碳含量，是极具吸引力的页岩气靶区。总有机碳(TOC)在2-17 wt.%之间变化，孔隙度在3-8%之间变化(平均约为5%)。该地层在项目区深度约为2800 - 3800米，厚度约为35-60米。重要的是，目标区明显超压，其压力几乎是正常静水油藏压力(15-21 Kpa/m梯度)的两倍。Duvernay地层的天然渗透率非常致密，在70-150纳米达西范围内，因此该地层需要水平井进行多级水力压裂，以获得经济效益。地层的天然裂缝密度部分解释了为何如此低基质渗透率的岩石可以如此多产，背景构造压裂明显大于北美正在开发的大多数其他低渗透储层。岩心和图像测井测量的裂缝密度为每米8条裂缝，平均张开裂缝密度约为每米1-2条。这些裂缝呈陡峭倾斜(75-85度)，形成于构造活动期间，既有开放裂缝，也有愈合裂缝/方解石充填裂缝。虽然天然裂缝的存在有助于油井的生产阶段，但它会使增产设计复杂化，并给井筒处理的布置带来挑战。在非常规水力增产方案的初始规划阶段，第一步是检查该区块的其他作业者已经在使用什么。早期尽职调查哪些设计元素是成功的，哪些同样重要，哪些不成功，可以在项目发展的早期节省大量资金。Duvernay项目中的一个例子是无胶结投球尾管完井系统。由于Duvernay的高压泵送要求(高达90mpa)，这些系统无法充分刺激储层，并且容易在安装和隔离方面遇到挑战。有限的Plug and Perf设计在加拿大非常规能源领域占据主导地位，这是雪佛龙加拿大有限公司和KUFPEC加拿大公司(“合资公司”)开始的旅程。下一个需要确定的关键增产参数是支撑剂和水的强度，这将决定增产的持续时间，也是关键的经济驱动因素(支撑剂强度通常是成本和油井产能方面最重要的变量)。压裂项目的其他主要投入围绕着簇设计;作为单压裂段一部分的压裂簇的数量、压裂簇之间的间距以及射孔簇/压裂段内射孔的数量和方向是关键参数。处理压力通常由储层固有的破裂压力和裂缝扩展压力决定，其中目标处理速率由作业者选择(对于大多数非常规储层通常为10-15 m3/min)。增产液的设计也因储层类型的不同而不同，滑溜水设计是当今最流行的混合、反向混合和高粘度减摩剂(VFR)设计，在不同的储层类型中也有不同的使用数量。与增产设计相关的是井间距，通常井间距越宽，支撑剂强度越高。有限进入设计的关键前提是，假设同一压裂段内的所有压裂簇吸收的流体和砂量相等，因此裂缝半长相等，但事实并非如此(称为压裂簇效率的概念)，关于该主题的更多讨论将在后面的文章中进行。
{"title":"The Duvernay Shale Completion Journey","authors":"Sean Kleiner, O. Aniekwe","doi":"10.2118/198070-ms","DOIUrl":"https://doi.org/10.2118/198070-ms","url":null,"abstract":"\u0000 The unconventional Shale and Tight play concept has grown to dominate the North American energy landscape, now accounting for the vast majority of onshore activity levels. However, not all Shale or Tight reservoir plays are created equal and what works for one play/Formation may not work for another. How should you design your stimulation, where to begin, what parameters are most impactful and what are some of the large economic leavers that can either make your project successful, or potentially cause it to fail.\u0000 The Duvernay is an Upper Devonian mudrock, with significant quartz, carbonate and total organic carbon content, making it an attractive Shale gas target. Total Organic Carbon (TOC) varies from 2-17 wt.% and porosity ranges from 3-8% (averaging approximately 5%). The Formation is approximately 2,800 – 3,800 meters deep in the project area and is approximately 35-60m thick. Importantly, the target is significantly overpressured, with nearly double normal hydrostatic reservoir pressure (15-21 Kpa/m gradient). The native permeability of the Duvernay Formation is extremely tight, measuring in the 70-150 nano Darcy range, thus the formation requires horizontal wells with multi stage hydraulic fracturing, to be economically productive. The natural fracture density of the formation partially explains how a rock with such low matrix permeability can be so prolific, background tectonic fracturing is significantly greater than most other low permeability reservoirs being exploited in North America. Fracture densities have been measured in core and image logs at up to 8 fractures per meter, with average open fracture density's approximating 1-2 per meter. These fractures are steeply dipping (75-85 degrees) and created during tectonic events, both open and healed/calcite filled fractures are present. While the presence of natural fractures aid in the productive stage of the well's life, it can complicate the stimulation design and challenge the placement of a wellbore treatment.\u0000 During the initial planning stages of an unconventional hydraulic stimulation program, the first step is to examine what other operators in the play are already utilizing. Early due diligence into what design elements are successful and almost as important, not successful, can save significant amounts of capital early in the evolution of a project. An example of this within the Duvernay project were uncemented ball drop liner completion systems. Due to the high-pressure pumping requirements of the Duvernay (up to 90 Mpa), these systems were not able to adequately stimulate the reservoir and were prone to install and isolation challenges. Limited entry Plug and Perf design dominates the Canadian unconventional energy landscape, this is where Chevron Canada Limited and KUFPEC Canada (\"The JV\") began its journey. The next critical stimulation parameters to decide on are proppant and water intensities, these will govern the duration of the stimulation and are key economic dr","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"20 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124700971","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}
京公网安备 11010802042870号
京ICP备2023020795号-1
扫码关注我们
求助内容：
应助结果提醒方式：