In line with our quest to improve performance, optimize efficiency, and increase profitability, ADNOC Gas Processing is committed to ensure process design optimization by following best practices that add significant value to its gas business and industry. This report will outline how we were able to increase our C3+ recovery and thus the NGL production of BuHasa Train 2 by safely utilizing the existing design envelope and available design margins. Although, operating a plant beyond its design capacity is not a new concept, process and HSE assessments are a must before proceeding. These efficiency enhancements can be implemented without any capital investment and also strengthen a plant's readiness to deal with any future challenges in plant performance. In gas processing plant such as NGL extraction, process fluid pressure is an important factor which can affect the plant characteristics. The influence of different values of pressure drop in various equipment needs to be realized as it can affect the quality and quantity of the process outputs. An in-house feasibility study has been conducted to evaluate the possibility of increasing the HP compressor discharge pressure by 1 bar over its current operating pressure. The study indicated that it was possible to enhance the train's efficiency by increasing C3+ recovery, leading to an increase in NGL production and therefore a profitability increase. The study was completed after the plant facilities were comprehensively evaluated for process safety and operability, as well as analyzed improvements in terms of C3+ recovery and NGL production. A successful "Field Test Run" for 10 days were conducted to validate the predictions of the study to operate the HP compressors at 1 bar higher. The product specification, quantity and plant operating costs are important parameters and balancing them will determine the optimum pressure distribution in the process and consequently realize our benefits. Hence, during the test run, the revised operating conditions were implemented and achieved safely without any major modification or upset to the facilities. As a result, the following cost benefits were realized: C3 + Recovery increased by around ≈ 0.2 wt.%NGL production increased by around ≈ 35 Ton/dayRevenues increased by around ≈ 2.8 MM US$/YearOperating cost increased by around≈ 220000 US$/Year
{"title":"Enhancing NGL Recovery Through Utilized Design Margins","authors":"Mariam Al Ali, Mohamed Salem Al Matroushi","doi":"10.2118/193340-ms","DOIUrl":"https://doi.org/10.2118/193340-ms","url":null,"abstract":"\u0000 In line with our quest to improve performance, optimize efficiency, and increase profitability, ADNOC Gas Processing is committed to ensure process design optimization by following best practices that add significant value to its gas business and industry. This report will outline how we were able to increase our C3+ recovery and thus the NGL production of BuHasa Train 2 by safely utilizing the existing design envelope and available design margins.\u0000 Although, operating a plant beyond its design capacity is not a new concept, process and HSE assessments are a must before proceeding. These efficiency enhancements can be implemented without any capital investment and also strengthen a plant's readiness to deal with any future challenges in plant performance. In gas processing plant such as NGL extraction, process fluid pressure is an important factor which can affect the plant characteristics. The influence of different values of pressure drop in various equipment needs to be realized as it can affect the quality and quantity of the process outputs.\u0000 An in-house feasibility study has been conducted to evaluate the possibility of increasing the HP compressor discharge pressure by 1 bar over its current operating pressure. The study indicated that it was possible to enhance the train's efficiency by increasing C3+ recovery, leading to an increase in NGL production and therefore a profitability increase.\u0000 The study was completed after the plant facilities were comprehensively evaluated for process safety and operability, as well as analyzed improvements in terms of C3+ recovery and NGL production.\u0000 A successful \"Field Test Run\" for 10 days were conducted to validate the predictions of the study to operate the HP compressors at 1 bar higher.\u0000 The product specification, quantity and plant operating costs are important parameters and balancing them will determine the optimum pressure distribution in the process and consequently realize our benefits. Hence, during the test run, the revised operating conditions were implemented and achieved safely without any major modification or upset to the facilities. As a result, the following cost benefits were realized: C3 + Recovery increased by around ≈ 0.2 wt.%NGL production increased by around ≈ 35 Ton/dayRevenues increased by around ≈ 2.8 MM US$/YearOperating cost increased by around≈ 220000 US$/Year","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87242977","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. Al-Enezi, B. Kostic, Nicola Foote, J. Filak, F. Al-Mahmeed, O. Al-Shammari, M. Bertouche
Resistivity image logs are high-resolution tools that can help to unravel the depositional and structural organisation in a wellbore. They provide a particularly powerful dataset when calibrated against core, maximising their benefit for reservoir characterisation. This paper shows examples how very detailed image assessment from selected wells in the Greater Burgan Field has helped to constrain the stratigraphic model and depositional interpretations of the Cretaceous Burgan and Wara reservoirs. A multidisciplinary study of 123 cored wells, integrating core sedimentology, petrography, bio- and chemostratigraphy, wireline well and resistivity image logs, has delivered a robust stratigraphic and depositional framework for one of the most important reservoirs in the world's largest siliciclastic oil field. A descriptive image facies scheme that has been calibrated against core and conventional well logs captures the lithological variation, sedimentary features and surfaces of the reservoir, providing a detailed proxy for the sedimentological evaluation of uncored intervals and wells. The sand-rich lower Burgan (4S) comprises fine to very coarse-grained fluvial channel sandbodies that are locally separated by laterally restricted mudrock baffles. Image and core analyses suggest that the majority of the sandstones are high-angle cross-stratified and form stacked barforms within amalgamated channel sandbodies. Their consistent orientation towards the NE-E supports a low-sinuosity (braided) fluvial system resulting in a relatively simple, sheet-like depositional architecture across the field. Although slightly finer grained, the cored middle Burgan channel sandbodies (3SM) are similar to those in the lower Burgan. However, palaeoflow data from the imaged wells show a higher directional spread in the order of c.60-90° with a dominantly N to E orientation of the sandy barforms. Careful analysis of the orientation of the bounding surfaces between the sandstone packages indicates nearly equal proportions of obliquely and roughly parallel dip orientations in some wells. This suggests the formation of at least some lateral (point) bars and possibly the presence of higher sinuosity channels implying that sandbody architecture and fluid flow pathways could be more complex in the middle Burgan relative to the lower Burgan. The examples from the Burgan and Wara Formations highlight the value of integrated image analysis for reservoir characterisation by delivering a consistent descriptive framework, embedding different datasets.
{"title":"The Value of Integrated Borehole Image Analysis to Refine Geological Models: An Example From the Greater Burgan Field, Kuwait","authors":"B. Al-Enezi, B. Kostic, Nicola Foote, J. Filak, F. Al-Mahmeed, O. Al-Shammari, M. Bertouche","doi":"10.2118/193222-MS","DOIUrl":"https://doi.org/10.2118/193222-MS","url":null,"abstract":"\u0000 Resistivity image logs are high-resolution tools that can help to unravel the depositional and structural organisation in a wellbore. They provide a particularly powerful dataset when calibrated against core, maximising their benefit for reservoir characterisation. This paper shows examples how very detailed image assessment from selected wells in the Greater Burgan Field has helped to constrain the stratigraphic model and depositional interpretations of the Cretaceous Burgan and Wara reservoirs.\u0000 A multidisciplinary study of 123 cored wells, integrating core sedimentology, petrography, bio- and chemostratigraphy, wireline well and resistivity image logs, has delivered a robust stratigraphic and depositional framework for one of the most important reservoirs in the world's largest siliciclastic oil field. A descriptive image facies scheme that has been calibrated against core and conventional well logs captures the lithological variation, sedimentary features and surfaces of the reservoir, providing a detailed proxy for the sedimentological evaluation of uncored intervals and wells.\u0000 The sand-rich lower Burgan (4S) comprises fine to very coarse-grained fluvial channel sandbodies that are locally separated by laterally restricted mudrock baffles. Image and core analyses suggest that the majority of the sandstones are high-angle cross-stratified and form stacked barforms within amalgamated channel sandbodies. Their consistent orientation towards the NE-E supports a low-sinuosity (braided) fluvial system resulting in a relatively simple, sheet-like depositional architecture across the field. Although slightly finer grained, the cored middle Burgan channel sandbodies (3SM) are similar to those in the lower Burgan. However, palaeoflow data from the imaged wells show a higher directional spread in the order of c.60-90° with a dominantly N to E orientation of the sandy barforms. Careful analysis of the orientation of the bounding surfaces between the sandstone packages indicates nearly equal proportions of obliquely and roughly parallel dip orientations in some wells. This suggests the formation of at least some lateral (point) bars and possibly the presence of higher sinuosity channels implying that sandbody architecture and fluid flow pathways could be more complex in the middle Burgan relative to the lower Burgan.\u0000 The examples from the Burgan and Wara Formations highlight the value of integrated image analysis for reservoir characterisation by delivering a consistent descriptive framework, embedding different datasets.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"28 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86692315","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}
G. Pimenta, D. Abdullah, Mohamed Awadh Alhammami, A. ElBarbary, T. Waheed, M. Q. Hussain, F. Abdulsallam
Completion fluids, typically chloride or bromide brines, based on density requirements are used to control the well during some operations and remain either in the tubing until well is put on production or in the annulus above the packer for the duration of well life. Under normal conditions, the well casing is a closed system where the brine is protected from ingress of H2S/CO2 and oxygen. However, brines may be exposed to oxygen ingress from the surface through a leak at the wellhead, and /or to H2S / CO2 ingress through a potential leak through the packer, their dissolution in the brine, affecting significantly the corrosion resistance of the steel. In spite of its proven efficiency with martensitic stainless steels, sodium bromide based completion brines are quite expensive. To explore possible less expensive alternatives, without compromising corrosion resistance of the tubing, ADNOC Onshore conducted a comprehensive testing program to identify suitable, less expensive alternative brine systems with the same or improved corrosion behavior in well conditions. In the study, the general and pitting corrosion, and the Sulphide Stress Cracking (SSC) resistance of 13Cr and S13Cr samples in NaCl, NaBr and CaCl2 brines were assessed. Samples were tested for a period of 30 days in three brine systems, under inert conditions, under 1.6psi (6.5psi) H2S / 165psi CO2, at 120°C and under oxygen ingress conditions at 49°C, in an autoclave. Pitting and general corrosion were assessed using weight loss coupons, whereas the susceptibility to SSC was tested using C-ring specimens in accordance with NACE TM0177 - Method C, at stress levels of 0,2% of the material proof stresses. Relative pitting susceptibility of the steels under oxygen contamination of the different brine systems was also assessed by electrochemical polarisation tests, at 49°C. The most significant results obtained is that none of the steels presented SSC under all conditions and brine systems. For both alloys, in all test conditions, the general corrosion rates decreased in the order CaCl2 > NaBr > NaCl brines, the exposure to H2S/CO2 presenting 2 to 5 times higher corrosion rates as compared to the inert gas conditions, with the 13Cr alloy presenting higher rates in all conditions, as expected. Pitting was inexistent / negligible in all testing conditions for S13Cr. In sour environment and in oxygen ingress conditions, 13Cr showed relevant pitting in all brines. Under oxygen contamination, deeper and broader pits were observed in the NaCl as compared to the CaCl2 brine, while no pitting was found on NaBr brine specimens. Electrochemical polarisation tests showed that the pitting onset and the repassivation potentials were shifting towards the cathodic direction in the order NaCl, NaBr and CaCl2. The conclusions of the study is that chloride brine systems are a technically viable option for application with S13Cr, without introducing additional corrosion or HSE risks, leading to cos
{"title":"Optimizing the Drilling Completion Brine Design in the Presence of Martensitic Stainless Steel Equipment","authors":"G. Pimenta, D. Abdullah, Mohamed Awadh Alhammami, A. ElBarbary, T. Waheed, M. Q. Hussain, F. Abdulsallam","doi":"10.2118/192941-MS","DOIUrl":"https://doi.org/10.2118/192941-MS","url":null,"abstract":"\u0000 Completion fluids, typically chloride or bromide brines, based on density requirements are used to control the well during some operations and remain either in the tubing until well is put on production or in the annulus above the packer for the duration of well life.\u0000 Under normal conditions, the well casing is a closed system where the brine is protected from ingress of H2S/CO2 and oxygen. However, brines may be exposed to oxygen ingress from the surface through a leak at the wellhead, and /or to H2S / CO2 ingress through a potential leak through the packer, their dissolution in the brine, affecting significantly the corrosion resistance of the steel.\u0000 In spite of its proven efficiency with martensitic stainless steels, sodium bromide based completion brines are quite expensive. To explore possible less expensive alternatives, without compromising corrosion resistance of the tubing, ADNOC Onshore conducted a comprehensive testing program to identify suitable, less expensive alternative brine systems with the same or improved corrosion behavior in well conditions.\u0000 In the study, the general and pitting corrosion, and the Sulphide Stress Cracking (SSC) resistance of 13Cr and S13Cr samples in NaCl, NaBr and CaCl2 brines were assessed.\u0000 Samples were tested for a period of 30 days in three brine systems, under inert conditions, under 1.6psi (6.5psi) H2S / 165psi CO2, at 120°C and under oxygen ingress conditions at 49°C, in an autoclave. Pitting and general corrosion were assessed using weight loss coupons, whereas the susceptibility to SSC was tested using C-ring specimens in accordance with NACE TM0177 - Method C, at stress levels of 0,2% of the material proof stresses.\u0000 Relative pitting susceptibility of the steels under oxygen contamination of the different brine systems was also assessed by electrochemical polarisation tests, at 49°C.\u0000 The most significant results obtained is that none of the steels presented SSC under all conditions and brine systems. For both alloys, in all test conditions, the general corrosion rates decreased in the order CaCl2 > NaBr > NaCl brines, the exposure to H2S/CO2 presenting 2 to 5 times higher corrosion rates as compared to the inert gas conditions, with the 13Cr alloy presenting higher rates in all conditions, as expected.\u0000 Pitting was inexistent / negligible in all testing conditions for S13Cr. In sour environment and in oxygen ingress conditions, 13Cr showed relevant pitting in all brines. Under oxygen contamination, deeper and broader pits were observed in the NaCl as compared to the CaCl2 brine, while no pitting was found on NaBr brine specimens. Electrochemical polarisation tests showed that the pitting onset and the repassivation potentials were shifting towards the cathodic direction in the order NaCl, NaBr and CaCl2.\u0000 The conclusions of the study is that chloride brine systems are a technically viable option for application with S13Cr, without introducing additional corrosion or HSE risks, leading to cos","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"19 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89462216","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}
Rang Dong field in offshore Vietnam has been producing oil since 1998 from a Lower Miocene sandstone reservoir. Upon the achievement of peak oil production in 2002, gaslift and water injection have been applied to maintain oil production. With primary and secondary oil recovery applications underway, a tertiary recovery technique by immiscible hydrocarbon gas enhanced oil recovery ("HCG-EOR") had been studied since 2009. Subsequent to a successful Pilot Test in 2011, a full field scale HCG-EOR with water-alternating-gas ("WAG") scheme has been implemented since 2014. This HCG-EOR application was the first commercial EOR project in offshore Vietnam and attracted attentions in the region. The project has been successfully executed to effectively minimize the decline and contribute approximately 30 percent of oil production rate as of the date of this paper. Numerous efforts for WAG pattern optimization and accurate incremental oil evaluation were attempted. This paper introduces coupled approach of well performance analysis and reservoir simulation study applied to the WAG optimization and incremental oil evaluation. In line with the theoretical reservoir responses of immiscible gas flooding, all the producers were classified into 3 groups by different types of performances following the WAG injection. By coloring the different groups on the well location map, reservoir engineers were able to understand the regional characteristics of response and managed to optimize WAG by allocating more gas to the regions where incremental production were dominated by tertiary recovery mechanism. For incremental oil evaluation, either decline curve analysis ("DCA") or compositional reservoir simulation is common practice, however, both techniques have its strengths and weaknesses. In this study, reservoir simulations for "past" incremental oil evaluation are always double-checked by DCA, and then prediction runs are performed. Such exercise could deliver the incremental oil evaluation of high confidence. In addition to discussion related to such subsurface evaluations, this paper also introduces lessons leant and mitigations on actual field operation with focus on intensified sand production, injectivity deterioration and back pressure surge after gas breakthrough.
{"title":"Full Field Scale Hydrocarbon Gas Enhanced Oil Recovery Project in Offshore Vietnam -Response Analysis and Optimization Practice in Early Stage","authors":"Yohei Kawahara, Yukiya Sako, Zhenjie Chai, Chuyen Nguyen Chu, Takahiro Murakami, Aiko Nishizaki, Thien Dao Cong","doi":"10.2118/193214-ms","DOIUrl":"https://doi.org/10.2118/193214-ms","url":null,"abstract":"\u0000 Rang Dong field in offshore Vietnam has been producing oil since 1998 from a Lower Miocene sandstone reservoir. Upon the achievement of peak oil production in 2002, gaslift and water injection have been applied to maintain oil production. With primary and secondary oil recovery applications underway, a tertiary recovery technique by immiscible hydrocarbon gas enhanced oil recovery (\"HCG-EOR\") had been studied since 2009. Subsequent to a successful Pilot Test in 2011, a full field scale HCG-EOR with water-alternating-gas (\"WAG\") scheme has been implemented since 2014. This HCG-EOR application was the first commercial EOR project in offshore Vietnam and attracted attentions in the region. The project has been successfully executed to effectively minimize the decline and contribute approximately 30 percent of oil production rate as of the date of this paper. Numerous efforts for WAG pattern optimization and accurate incremental oil evaluation were attempted.\u0000 This paper introduces coupled approach of well performance analysis and reservoir simulation study applied to the WAG optimization and incremental oil evaluation. In line with the theoretical reservoir responses of immiscible gas flooding, all the producers were classified into 3 groups by different types of performances following the WAG injection. By coloring the different groups on the well location map, reservoir engineers were able to understand the regional characteristics of response and managed to optimize WAG by allocating more gas to the regions where incremental production were dominated by tertiary recovery mechanism. For incremental oil evaluation, either decline curve analysis (\"DCA\") or compositional reservoir simulation is common practice, however, both techniques have its strengths and weaknesses. In this study, reservoir simulations for \"past\" incremental oil evaluation are always double-checked by DCA, and then prediction runs are performed. Such exercise could deliver the incremental oil evaluation of high confidence.\u0000 In addition to discussion related to such subsurface evaluations, this paper also introduces lessons leant and mitigations on actual field operation with focus on intensified sand production, injectivity deterioration and back pressure surge after gas breakthrough.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"68 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89817839","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}
Research indicate that 80% of all failures in fluid transfer systems are caused by contamination. Contamination causes huge gaps in both safety and reliability and shortening the lifespan of, systems. Subsea systems are often controlled by very long umbilical's/control-lines (>6 km) with no efficient cleaning option. It is necessary to clean these lines with turbulent flow, which can be difficult to obtain with conventional cleaning fluids With the Super Critical CO2 (SCCO2) technology, it is now possible to clean very long narrow pipes with turbulent flow, not possible with conventional flushing methods. Due to the very low viscosity, diffusivity, and no surface tension of the CO2, it possible to reach a level of cleanness never seen before. Using the pressure & temperature it is possible to manipulate the density needed to carry the particles. When the particles are carried out of the system, the liquid CO2 is converted into gas in the separator, and the contamination suspended in the CO2 drops out. This technology has been proven on a proof of concept test (onshore) with two 3rd party participance, flushing a 6,5km ¼" dual control-line. This line was cleaned with laminar flow (Reynolds No. under 3000) and had a certificate that said it was cleaned to NAS1638 grade 6. It was proved, using SCCO2 with a Reynolds No. of 42.000, that the line was not clean, [and was NAS1638 grade 12]. It was then cleaned to NAS1638 grade 3, best we have ever seen. Also, the SCCO2 technology was proved offshore, by cleaning a 38km ½"ID Umbilical for Wintershall Noordzee, from NAS1638 grade 12 to Grade 3 with a Reynolds No. of over 30.000. This umbilical had the same issue as in the proof of concept test. The line was claimed to be clean, but the operator experienced that the chemical injection line was blocked by contamination. This caused a lot of shutdowns and was very costly. After the umbilical was cleaned with the SCCO2 technology, the operator has not had any shutdowns due to contamination or blockages for over 9 months now. With the SCCO2 technology, it is possible to clean or unblock very long tubes/lines, to a cleanness never seen before. The cleanliness and unblocking possibilities are a result of the unique characteristics of the CO2, and the high Reynolds No. possible by using CO2. This opens more possibilities that previously was not possible and lacking in the industry. It will make the systems more safe, reliable and reduce cost and increase the production up-time.
研究表明，80%的流体输送系统故障是由污染引起的。污染在安全性和可靠性方面造成了巨大的差距，并缩短了系统的寿命。海底系统通常由非常长的脐带/控制线(>6公里)控制，没有有效的清洁选择。有必要用紊流清洗这些管道，而用常规清洗液很难获得紊流。使用超临界二氧化碳(SCCO2)技术，现在可以用紊流清洗非常长的窄管，而用常规冲洗方法是不可能的。由于非常低的粘度，扩散性，并且没有二氧化碳的表面张力，它可能达到前所未有的清洁水平。利用压力和温度，可以控制携带颗粒所需的密度。当颗粒被带出系统时，液态CO2在分离器中转化为气体，悬浮在CO2中的污染物脱落。该技术已经在两家第三方参与的陆上概念验证测试中得到验证，冲洗了一条6.5 km / 4英寸的双控制线。这条线是用层流清洗的。3000以下)，并有一个证书，说它被清洗到NAS1638 6级。用雷诺数为0的SCCO2进行了验证。在42000中，线不干净，[并且是NAS1638等级12]。然后它被清洗到NAS1638 3级，这是我们见过的最好的。此外，SCCO2技术在海上也得到了验证，在Wintershall Noordzee钻井平台上，使用Reynolds No.清洗了一条38km / 2”ID的脐带缆，从NAS1638等级12级到3级。3万多人。这条脐带与概念验证测试中存在同样的问题。该管线声称是清洁的，但操作人员发现化学注入管线被污染堵塞了。这导致了大量的停工，成本非常高。在使用SCCO2技术对脐带缆进行清洁后，作业公司已经有9个多月没有因污染或堵塞而停工。使用SCCO2技术，可以清洁或疏通非常长的管道/管线，达到前所未有的清洁度。清洁和易堵塞的可能性是二氧化碳的独特特性和高雷诺数的结果。通过使用二氧化碳来实现。这开启了更多的可能性，而这在以前的行业中是不可能的。它将使系统更加安全，可靠，降低成本，增加生产正常运行时间。
{"title":"SCCO2 Flushing Technology: The Supercritical Revolution","authors":"E. Amundsen, M. Juul","doi":"10.2118/192830-MS","DOIUrl":"https://doi.org/10.2118/192830-MS","url":null,"abstract":"\u0000 \u0000 \u0000 Research indicate that 80% of all failures in fluid transfer systems are caused by contamination.\u0000 Contamination causes huge gaps in both safety and reliability and shortening the lifespan of, systems. Subsea systems are often controlled by very long umbilical's/control-lines (>6 km) with no efficient cleaning option. It is necessary to clean these lines with turbulent flow, which can be difficult to obtain with conventional cleaning fluids\u0000 \u0000 \u0000 \u0000 With the Super Critical CO2 (SCCO2) technology, it is now possible to clean very long narrow pipes with turbulent flow, not possible with conventional flushing methods. Due to the very low viscosity, diffusivity, and no surface tension of the CO2, it possible to reach a level of cleanness never seen before. Using the pressure & temperature it is possible to manipulate the density needed to carry the particles. When the particles are carried out of the system, the liquid CO2 is converted into gas in the separator, and the contamination suspended in the CO2 drops out.\u0000 \u0000 \u0000 \u0000 This technology has been proven on a proof of concept test (onshore) with two 3rd party participance, flushing a 6,5km ¼\" dual control-line. This line was cleaned with laminar flow (Reynolds No. under 3000) and had a certificate that said it was cleaned to NAS1638 grade 6. It was proved, using SCCO2 with a Reynolds No. of 42.000, that the line was not clean, [and was NAS1638 grade 12]. It was then cleaned to NAS1638 grade 3, best we have ever seen. Also, the SCCO2 technology was proved offshore, by cleaning a 38km ½\"ID Umbilical for Wintershall Noordzee, from NAS1638 grade 12 to Grade 3 with a Reynolds No. of over 30.000. This umbilical had the same issue as in the proof of concept test. The line was claimed to be clean, but the operator experienced that the chemical injection line was blocked by contamination. This caused a lot of shutdowns and was very costly. After the umbilical was cleaned with the SCCO2 technology, the operator has not had any shutdowns due to contamination or blockages for over 9 months now.\u0000 \u0000 \u0000 \u0000 With the SCCO2 technology, it is possible to clean or unblock very long tubes/lines, to a cleanness never seen before. The cleanliness and unblocking possibilities are a result of the unique characteristics of the CO2, and the high Reynolds No. possible by using CO2. This opens more possibilities that previously was not possible and lacking in the industry. It will make the systems more safe, reliable and reduce cost and increase the production up-time.\u0000","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"42 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89517191","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}
Lost circulation is a recurring and costly challenge for the oil and gas industry. Losses range from seepage to total and financial effects, including nonproductive time and remedial operational expenses, which can increase potential risks to the operator. To address this issue, a tunable cement-based lost circulation treatment solution has been developed that is most suitable for partial to total losses, particularly when particulate-based solutions are not effective; the solution is primarily intended to cure losses while drilling. Unlike conventional lost circulation materials (LCMs) that cure losses by mechanical bridging of particles, the thixotropic cement solution's effectiveness arises from its unique chemical composition, which is ideal when flow paths are too large to be plugged by particles. The new lost circulation treatment solution is thixotropic with a density range of 10 to 15 lbm/gal working in temperatures up to 250°F. The formulation can be mixed with fresh water, seawater, or seawater with up to 14% NaCl. It is designed and tested in accordance with API RP 10B2 (2013) procedures for thickening time (TT), compressive strength, static gel strength, fluid loss, and rheology. During the TT on-off-on test, the formulation builds gel strength when shear is reduced and regains fluidity when shear is reapplied. The formulation developed rapid static gel strength and an early compressive strength up to 500 psi. The reversible gelation behavior is demonstrated through multiple shear on-off cycles. This solution is operationally convenient to apply because it can be pumped through the bottomhole assembly (BHA), thus reducing trip times. Because of its acid solubility, it can be used across production zones. The unique properties of gaining rapid gel strength reversibly and a good compressive strength render this solution effective for treating a wide range of lost circulation events during drilling. A wider density window might minimize the potential risk of inflow when treating losses.
对于油气行业来说，漏失是一个反复出现且成本高昂的挑战。损失范围从渗漏到总体和财务影响，包括非生产时间和补救操作费用，这些都可能增加作业者的潜在风险。为了解决这个问题，开发了一种可调的水泥基漏失处理方案，最适合部分或全部漏失，特别是当颗粒基方案无效时;该解决方案主要用于解决钻井过程中的漏失问题。与通过机械桥接颗粒来修复漏失的传统漏失材料(lcm)不同，触变性水泥溶液的有效性源于其独特的化学成分，在流动路径太大而无法被颗粒堵塞时非常理想。新型漏失处理液具有触变性，密度范围为10 ~ 15磅/加仑，可在高达250°F的温度下工作。该配方可与淡水、海水或含14% NaCl的海水混合。根据API RP 10B2(2013)程序对增稠时间(TT)、抗压强度、静态凝胶强度、失液量和流变性进行设计和测试。在TT开关测试中，当剪切减少时，该配方建立凝胶强度，当再次施加剪切时，该配方恢复流动性。该配方具有快速的静态凝胶强度和高达500psi的早期抗压强度。通过多次剪切开关循环证明了可逆凝胶行为。该解决方案操作方便，因为它可以通过底部钻具组合(BHA)泵入，从而减少了起下钻时间。由于其酸溶性，它可以跨生产区域使用。该溶液具有快速可逆凝胶强度和良好抗压强度的独特特性，可有效处理钻井过程中的各种漏失。在处理损失时，更宽的密度窗口可以将流入的潜在风险降至最低。
{"title":"Acid-Soluble Thixotropic Cement System for Lost Circulation Challenges","authors":"Rahul Jadhav, Sandip P Patil","doi":"10.2118/193168-MS","DOIUrl":"https://doi.org/10.2118/193168-MS","url":null,"abstract":"\u0000 Lost circulation is a recurring and costly challenge for the oil and gas industry. Losses range from seepage to total and financial effects, including nonproductive time and remedial operational expenses, which can increase potential risks to the operator. To address this issue, a tunable cement-based lost circulation treatment solution has been developed that is most suitable for partial to total losses, particularly when particulate-based solutions are not effective; the solution is primarily intended to cure losses while drilling. Unlike conventional lost circulation materials (LCMs) that cure losses by mechanical bridging of particles, the thixotropic cement solution's effectiveness arises from its unique chemical composition, which is ideal when flow paths are too large to be plugged by particles.\u0000 The new lost circulation treatment solution is thixotropic with a density range of 10 to 15 lbm/gal working in temperatures up to 250°F. The formulation can be mixed with fresh water, seawater, or seawater with up to 14% NaCl. It is designed and tested in accordance with API RP 10B2 (2013) procedures for thickening time (TT), compressive strength, static gel strength, fluid loss, and rheology. During the TT on-off-on test, the formulation builds gel strength when shear is reduced and regains fluidity when shear is reapplied.\u0000 The formulation developed rapid static gel strength and an early compressive strength up to 500 psi. The reversible gelation behavior is demonstrated through multiple shear on-off cycles. This solution is operationally convenient to apply because it can be pumped through the bottomhole assembly (BHA), thus reducing trip times. Because of its acid solubility, it can be used across production zones.\u0000 The unique properties of gaining rapid gel strength reversibly and a good compressive strength render this solution effective for treating a wide range of lost circulation events during drilling. A wider density window might minimize the potential risk of inflow when treating losses.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"36 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78398957","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}
Arctic's huge reserves potential development was blocked for many years by the lack of accessible and all-year open for navigation transport routes. In spite of the fact that the Northern Sea Route is the shortest way from Europe to Asia, currently about 75% of the total cargo turnover delivers through the south corridor via the Suez Canal and the Mediterrenian sea, but the turnover via the Northern Sea Route is growing rapidly over the past years. Due to the strategic allocation of the Northern Sea Route it attracts enormous attention of the international companies now. This paper highlights challenges with the development of the Northern Sea Route nowadays along with the opportunities for international cooperation.
{"title":"Northern Sea Route as the Main Driver for the Arctic Development: Challenges with Infrastructure and Opportunities for International Cooperation","authors":"I. Akimova","doi":"10.2118/192980-MS","DOIUrl":"https://doi.org/10.2118/192980-MS","url":null,"abstract":"\u0000 Arctic's huge reserves potential development was blocked for many years by the lack of accessible and all-year open for navigation transport routes. In spite of the fact that the Northern Sea Route is the shortest way from Europe to Asia, currently about 75% of the total cargo turnover delivers through the south corridor via the Suez Canal and the Mediterrenian sea, but the turnover via the Northern Sea Route is growing rapidly over the past years. Due to the strategic allocation of the Northern Sea Route it attracts enormous attention of the international companies now. This paper highlights challenges with the development of the Northern Sea Route nowadays along with the opportunities for international cooperation.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"20 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75765567","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}
Arvind D. Patel, Sakshi Indulkar, Vikas Chavan, Pradeep Maddheshiya, Megha Asrani, S. Thakur, Ashutosh Kumar Singh, V. Gupta
Exploration and Production Operators prefer a non-damaging non-aqueous fluid (NAF) for drilling Reservoir. One of the requirements of non-damaging system is a clay free system and it should perform as good as any NAF Fluid. For drilling in deep water environment, it is necessary to have flat rheology of NAF over a wide range of temperatures. An innovative polymeric rheology modifier was used to develop Clay Free Invert Drilling Fluid (CFIDF) which provides dual function to achieve a clay free system as well as flat rheology when measured over a wide range of temperatures from 40 to 150 °F. The flat rheology is required in offshore deep water drilling due to varying temperature profile from 4 °C at the bottom of sea to as high as 100 °C or even higher at bottom of hole. Lower temperatures increase the rheology leading to higher ECD and at higher temperatures the rheology is lowered leading to hole cleaning issues. Flat rheology profile minimizes or eliminates such adverse effects on ECD or hole cleaning activity. The newly developed clay free system utilizes a single rheology modifier component to provide dual functions of providing true clay free system and offers flat rheological profile without sacrificing the vital mud parameters such as emulsion stability, fluid loss control and rheology. In addition, the system uses a new rheology modifier that provides a temperature-independent rheology profile for hole cleaning, barite suspension, ECD management. The system can be formulated for deep-water applications with mud weights up to 18.0 lb/gal and bottom hole temperatures up to 350°F. Recent successful field trials as a clay free system for drilling reservoir indicated that the new system is easy to maintain and provides good fluid performance in terms of drilling rate, ECD management, lost circulation control and hole cleaning. The product provides an excellent rheological profile and was used in the field at a low dosage of 1 ppb. Even at this low dosage LSRV was above 10 in 8 ½″ Hole with yield point of greater than 15 lbs/100 sq.ft. When the system was contaminated with a severe saltwater flow, there were no fluid-related problems before the synthetic/water ratio was restored. The new fluid system exhibits flat rheology profiles and non-progressive gel structures. The system showed excellent hole cleaning with excellent thixotropic properties. This resulted in a noticeable reduction of lost circulation potential in lost circulation prone areas due to manageable ECD. An innovative rheology modifier which provides clay free system and offering flat rheology profile has been developed and successfully used in field. The rheology modifier can minimize or totally eliminate the organophilic clay to improve the quality of non-damaging reservoir drilling fluid.
{"title":"Clay Free Invert Emulsion Drilling Fluid System- An Innovative Rheology Modifier Which Provides Flat Rheology for Deep Water Drilling and Viscosifier for Clay Free System","authors":"Arvind D. Patel, Sakshi Indulkar, Vikas Chavan, Pradeep Maddheshiya, Megha Asrani, S. Thakur, Ashutosh Kumar Singh, V. Gupta","doi":"10.2118/192618-MS","DOIUrl":"https://doi.org/10.2118/192618-MS","url":null,"abstract":"\u0000 Exploration and Production Operators prefer a non-damaging non-aqueous fluid (NAF) for drilling Reservoir. One of the requirements of non-damaging system is a clay free system and it should perform as good as any NAF Fluid. For drilling in deep water environment, it is necessary to have flat rheology of NAF over a wide range of temperatures. An innovative polymeric rheology modifier was used to develop Clay Free Invert Drilling Fluid (CFIDF) which provides dual function to achieve a clay free system as well as flat rheology when measured over a wide range of temperatures from 40 to 150 °F.\u0000 The flat rheology is required in offshore deep water drilling due to varying temperature profile from 4 °C at the bottom of sea to as high as 100 °C or even higher at bottom of hole. Lower temperatures increase the rheology leading to higher ECD and at higher temperatures the rheology is lowered leading to hole cleaning issues. Flat rheology profile minimizes or eliminates such adverse effects on ECD or hole cleaning activity.\u0000 The newly developed clay free system utilizes a single rheology modifier component to provide dual functions of providing true clay free system and offers flat rheological profile without sacrificing the vital mud parameters such as emulsion stability, fluid loss control and rheology. In addition, the system uses a new rheology modifier that provides a temperature-independent rheology profile for hole cleaning, barite suspension, ECD management. The system can be formulated for deep-water applications with mud weights up to 18.0 lb/gal and bottom hole temperatures up to 350°F.\u0000 Recent successful field trials as a clay free system for drilling reservoir indicated that the new system is easy to maintain and provides good fluid performance in terms of drilling rate, ECD management, lost circulation control and hole cleaning. The product provides an excellent rheological profile and was used in the field at a low dosage of 1 ppb. Even at this low dosage LSRV was above 10 in 8 ½″ Hole with yield point of greater than 15 lbs/100 sq.ft. When the system was contaminated with a severe saltwater flow, there were no fluid-related problems before the synthetic/water ratio was restored. The new fluid system exhibits flat rheology profiles and non-progressive gel structures. The system showed excellent hole cleaning with excellent thixotropic properties. This resulted in a noticeable reduction of lost circulation potential in lost circulation prone areas due to manageable ECD.\u0000 An innovative rheology modifier which provides clay free system and offering flat rheology profile has been developed and successfully used in field. The rheology modifier can minimize or totally eliminate the organophilic clay to improve the quality of non-damaging reservoir drilling fluid.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"49 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72870172","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In this paper, we considered the effect of water chemistry on water-rock interactions during seawater and smart water flooding of reservoir sandstone cores containing heavy oil. Oil recovery, surface reactivity tests, and multicomponent reactive transport simulation using CrunchFlow were conducted to better understand smart water flooding. Secondary water flooding with FW at 25°C resulted in an ultimate oil recovery (UOR) of ~50% OOIP for all reservoir cores in this study. Formation water salinity was 104,550 ppm. FW was diluted twice to obtain SMW1. SMW2 was similar to SMW1 but depleted in divalent cations (Ca2+ and Mg2+). SMW3 was also similar to SMW1 but depleted in Mg2+ and SO42-, while SMW4 was the same as SMW1 but Ca2+ was diluted 100 times. Seawater salinity was 48300 ppm, which is close to the smart waters salinity (52275 ppm). No oil recovery was observed during SMW1 flooding, while softening SMW1 (SMW2) resulted in a significant additional oil recovery OOIP. Depleting Mg2+ and SO42- resulted in additional oil recovery but smaller than in SMW2. Diluting Ca2+ 100 times was the second best scenario coming after depleted Ca2+ in SMW2. The results of this study showed that the more diluted Ca2+ is in the injected brine, the more additional oil recovery that can be obtained, even though the other divalent/monovalent cations/anions were increased or decreased or even depleted. Other reservoir cores were allocated for surface reactivity test. The absence of an oil phase allows us to isolate the important water-rock reactions. The Ca2+, Mg2+, and SO42- effluents for all cores were matched using CrunchFlow, and then further investigations of the water-rock interactions were conducted. The reactive transport model showed that decreasing the Mg2+ concentration will decrease the number of the most effective kaolinite edges Si-O- and Al-O-, but was not as pronounced as that in present of Ca2+, which explains why lowering Mg2+ concentration gives lower additional oil recovery, and why lowering Ca2+ concentration gives higher additional oil recovery.
{"title":"Investigation of Smart Water Flooding in Sandstone Reservoirs: Experimental and Simulation Study Part2","authors":"Hasan N. Al-Saedi, R. Flori, Alsaba Mortadha","doi":"10.2118/193238-MS","DOIUrl":"https://doi.org/10.2118/193238-MS","url":null,"abstract":"\u0000 In this paper, we considered the effect of water chemistry on water-rock interactions during seawater and smart water flooding of reservoir sandstone cores containing heavy oil. Oil recovery, surface reactivity tests, and multicomponent reactive transport simulation using CrunchFlow were conducted to better understand smart water flooding.\u0000 Secondary water flooding with FW at 25°C resulted in an ultimate oil recovery (UOR) of ~50% OOIP for all reservoir cores in this study. Formation water salinity was 104,550 ppm. FW was diluted twice to obtain SMW1. SMW2 was similar to SMW1 but depleted in divalent cations (Ca2+ and Mg2+). SMW3 was also similar to SMW1 but depleted in Mg2+ and SO42-, while SMW4 was the same as SMW1 but Ca2+ was diluted 100 times. Seawater salinity was 48300 ppm, which is close to the smart waters salinity (52275 ppm). No oil recovery was observed during SMW1 flooding, while softening SMW1 (SMW2) resulted in a significant additional oil recovery OOIP. Depleting Mg2+ and SO42- resulted in additional oil recovery but smaller than in SMW2. Diluting Ca2+ 100 times was the second best scenario coming after depleted Ca2+ in SMW2. The results of this study showed that the more diluted Ca2+ is in the injected brine, the more additional oil recovery that can be obtained, even though the other divalent/monovalent cations/anions were increased or decreased or even depleted.\u0000 Other reservoir cores were allocated for surface reactivity test. The absence of an oil phase allows us to isolate the important water-rock reactions. The Ca2+, Mg2+, and SO42- effluents for all cores were matched using CrunchFlow, and then further investigations of the water-rock interactions were conducted. The reactive transport model showed that decreasing the Mg2+ concentration will decrease the number of the most effective kaolinite edges Si-O- and Al-O-, but was not as pronounced as that in present of Ca2+, which explains why lowering Mg2+ concentration gives lower additional oil recovery, and why lowering Ca2+ concentration gives higher additional oil recovery.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"3 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73228189","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}
Kamran Awan, Mohammed Al Aufi, Hilal Al Salti, Hussain Al Noumani, Bijan Nabavi, Ali Al Ghaithy, K. Busaidi, Ali Al Harrasi, Ali Al Lamki, Rahima Al Mujaini, Mohammed Al Salhi, Seif Al Nadabi, A. Abri, Yousef Al Zaabi, S. Busaidi
'Sweating the Asset’ is an integrated change management approach for maximizing cheap oil production from existing fields and facilities, without capital expenditure. ‘Sweating the Asset’ utilizes a Theory of Constraints approach to identify and focus on a production system's limiting factor on a daily, mid-term and long term basis. The ‘Sweating the Asset’ goal was introduced as an organisational initiative in Q1 2017 with the aim of helping producing assets close their ‘gap to potential’ and operate as closely as possible to technical limit. The approach enables team leaders managing different components of the integrated production system to focus on a common goal and make aligned decisions. The structured ‘Sweat the Asset’ process integrates components of the company's Lean Management System (LMS), including:Goal deployment: a process used to identify a SMART top-level goal, establish ‘line of sight’ to & from front-line teams within an asset, and align all involved to close their specific performance gaps via improvement metrics, visual management, Leader Standard Work (ensuring continuous engagement and support), and the use of Continuous Improvement tools (Lean projects, Kaizen events etc as appropriate).Horizon 1: the ‘Daily Production Huddle’ is an efficient process which brings together key stakeholders in the integrated production system, identifies the daily production constraint using relevant tools (incl. live limit diagrams & creaming curves) and helps them make decisions which optimise daily production and minimise deferment.Production System Optimisation (Horizon 2): is a process used to identify mid-term improvement opportunities via an integrated team approach using Lean, allowing it to be led by asset teams on a monthly and quarterly basis. 'Sweating the Asset’ has been deployed in 13 production systems within the organisation and currently at different levels of maturity. As an example of goal deployment, an EOR polymer injection facility with suboptimal performance, poor compliance with injection and viscosity requirements had resulted in a severe decline in oil production. In order to safeguard production and close an estimated production gap of 4000 barrels/day, a goal was set to improve polymer flood compliance from 40 % to 95 %. The goal was deployed via a ‘catch-ball’ exercise with field (operations) and office-based (subsurface) teams to agree gaps, metrics and commitment at the front line. The goal is owned jointly by the subsurface and operations asset leaders, who provide focused support for gap closure via regular, dedicated engagements built into their Leader Standard Work routines. The plan for 2018 is to ensure that ‘Sweating the Asset’ is fully embedded and sustainable in all assets across the organisation. This may be seen as step change in, and the next level of Wells, Reservoir and Facilities Management (WRFM) maturity. This paper will primarily focus on the Goal Deployment process and strategy.
{"title":"Maximising Production of Lowest-Cost Oil and Gas from Existing Integrated Production Systems Using the Sweating the Asset Change Management Process","authors":"Kamran Awan, Mohammed Al Aufi, Hilal Al Salti, Hussain Al Noumani, Bijan Nabavi, Ali Al Ghaithy, K. Busaidi, Ali Al Harrasi, Ali Al Lamki, Rahima Al Mujaini, Mohammed Al Salhi, Seif Al Nadabi, A. Abri, Yousef Al Zaabi, S. Busaidi","doi":"10.2118/192848-MS","DOIUrl":"https://doi.org/10.2118/192848-MS","url":null,"abstract":"\u0000 'Sweating the Asset’ is an integrated change management approach for maximizing cheap oil production from existing fields and facilities, without capital expenditure. ‘Sweating the Asset’ utilizes a Theory of Constraints approach to identify and focus on a production system's limiting factor on a daily, mid-term and long term basis.\u0000 The ‘Sweating the Asset’ goal was introduced as an organisational initiative in Q1 2017 with the aim of helping producing assets close their ‘gap to potential’ and operate as closely as possible to technical limit. The approach enables team leaders managing different components of the integrated production system to focus on a common goal and make aligned decisions.\u0000 The structured ‘Sweat the Asset’ process integrates components of the company's Lean Management System (LMS), including:Goal deployment: a process used to identify a SMART top-level goal, establish ‘line of sight’ to & from front-line teams within an asset, and align all involved to close their specific performance gaps via improvement metrics, visual management, Leader Standard Work (ensuring continuous engagement and support), and the use of Continuous Improvement tools (Lean projects, Kaizen events etc as appropriate).Horizon 1: the ‘Daily Production Huddle’ is an efficient process which brings together key stakeholders in the integrated production system, identifies the daily production constraint using relevant tools (incl. live limit diagrams & creaming curves) and helps them make decisions which optimise daily production and minimise deferment.Production System Optimisation (Horizon 2): is a process used to identify mid-term improvement opportunities via an integrated team approach using Lean, allowing it to be led by asset teams on a monthly and quarterly basis.\u0000 'Sweating the Asset’ has been deployed in 13 production systems within the organisation and currently at different levels of maturity. As an example of goal deployment, an EOR polymer injection facility with suboptimal performance, poor compliance with injection and viscosity requirements had resulted in a severe decline in oil production. In order to safeguard production and close an estimated production gap of 4000 barrels/day, a goal was set to improve polymer flood compliance from 40 % to 95 %. The goal was deployed via a ‘catch-ball’ exercise with field (operations) and office-based (subsurface) teams to agree gaps, metrics and commitment at the front line. The goal is owned jointly by the subsurface and operations asset leaders, who provide focused support for gap closure via regular, dedicated engagements built into their Leader Standard Work routines.\u0000 The plan for 2018 is to ensure that ‘Sweating the Asset’ is fully embedded and sustainable in all assets across the organisation. This may be seen as step change in, and the next level of Wells, Reservoir and Facilities Management (WRFM) maturity. This paper will primarily focus on the Goal Deployment process and strategy.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"17 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73660593","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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