M. Bondar, Andrey B. Osipov, A. Groman, I. Koltsov, G. Shcherbakov, S. Milchakov
EOR technologies in general and surfactant-polymer flooding (SP) in particular is considered as a tertiary method for redevelopment of mature oil fields in Western Siberia, with potential to increase oil recovery to 60-70% OOIP. The selection of effective surfactant blend and a polymer for SP flooding a complex and multi-stage process. The selected SP compositions were tested at Kholmogorskoye oilfield in September-December 2020. Two single well tests with partitioning chemical tracers (SWCTT) and the injectivity test were performed. The surfactant and the polymer for chemical EOR were selecting during laboratory studies. Thermal stability, phase behavior, interfacial tension and rheology of SP formulation were investigated, then a prospective chemical design was developed. Filtration experiments were carried out for optimization of slugs and concentrations. Then SWCTT was used to evaluated residual oil saturation after water flooding and after implementation of chemical EOR in the near wellbore areas. The difference between the obtained values is a measure of the efficiency of surfactant-polymer flooding. Pandemic restriction shifted SWCTT to the period when temperature dropped below zero and suitable for winter conditions equipment was required. Two SWCTT were conducted with same surfactant, but different design of slugs in order to prove technical and economic models of SP-flooding. Long-term polymer injectivity was accessed at the third well. Oil saturation of sandstone reservoir after the injection of a surfactant-polymer solution was reduced about 10% points which is around one third of the residual oil after water flooding. Results were compared with other available data such as well logging, lab core flooding experiments, and hydrodynamic simulation. Modeling of SWCTT is ongoing, current interpretation confirms the increase the oil recovery factor after SP-flooding up to 20-25%, which is a promising result. Temperature model of the bottom hole zone was created and verified. The model predicts that temperature of those zones essentially below that average in the reservoir, which is important for interpretation of tracer test and surfactant efficiency. The tested surfactant showed an acceptable efficiency at under-optimum conditions, which is favorable for application of the SP formulation for neighboring field and layers with different reservoir temperatures, but similar water composition. In general, the results of the conducted field tests correlate with the results of the core experiments for the selected surfactant
{"title":"Evaluating Efficiency of Surfactant-Polymer Flooding with Single Well Chemical Tracer Tests at Kholmogorskoye Field","authors":"M. Bondar, Andrey B. Osipov, A. Groman, I. Koltsov, G. Shcherbakov, S. Milchakov","doi":"10.2118/207314-ms","DOIUrl":"https://doi.org/10.2118/207314-ms","url":null,"abstract":"\u0000 EOR technologies in general and surfactant-polymer flooding (SP) in particular is considered as a tertiary method for redevelopment of mature oil fields in Western Siberia, with potential to increase oil recovery to 60-70% OOIP. The selection of effective surfactant blend and a polymer for SP flooding a complex and multi-stage process. The selected SP compositions were tested at Kholmogorskoye oilfield in September-December 2020. Two single well tests with partitioning chemical tracers (SWCTT) and the injectivity test were performed.\u0000 The surfactant and the polymer for chemical EOR were selecting during laboratory studies. Thermal stability, phase behavior, interfacial tension and rheology of SP formulation were investigated, then a prospective chemical design was developed. Filtration experiments were carried out for optimization of slugs and concentrations. Then SWCTT was used to evaluated residual oil saturation after water flooding and after implementation of chemical EOR in the near wellbore areas. The difference between the obtained values is a measure of the efficiency of surfactant-polymer flooding. Pandemic restriction shifted SWCTT to the period when temperature dropped below zero and suitable for winter conditions equipment was required.\u0000 Two SWCTT were conducted with same surfactant, but different design of slugs in order to prove technical and economic models of SP-flooding. Long-term polymer injectivity was accessed at the third well. Oil saturation of sandstone reservoir after the injection of a surfactant-polymer solution was reduced about 10% points which is around one third of the residual oil after water flooding. Results were compared with other available data such as well logging, lab core flooding experiments, and hydrodynamic simulation. Modeling of SWCTT is ongoing, current interpretation confirms the increase the oil recovery factor after SP-flooding up to 20-25%, which is a promising result.\u0000 Temperature model of the bottom hole zone was created and verified. The model predicts that temperature of those zones essentially below that average in the reservoir, which is important for interpretation of tracer test and surfactant efficiency. The tested surfactant showed an acceptable efficiency at under-optimum conditions, which is favorable for application of the SP formulation for neighboring field and layers with different reservoir temperatures, but similar water composition. In general, the results of the conducted field tests correlate with the results of the core experiments for the selected surfactant","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84621840","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}
Abu Dhabi subsurface fault populations triggered basin system in diverse directions, because of their significant role as fluid pathways. Studying fault infill materials, fault geometries, zone architecture and sealing properties from outcrops as analogues to the subsurface of Abu Dhabi, and combining these with well data and cores are the main objectives of this paper. The fault core around the fault plane and in areas of overlap between fault segments and around the fault tip include slip surfaces and deformed rocks such as fault gouge, breccia, and lenses of host rock, shale smear, salt flux and diagenetic features. Structural geometry of the fault zone architecture and fault plane infill is mainly based on the competency contrast of the materials, that are behaving in ductile or in a brittle manner, which are distributed in the subsurface of Abu Dhabi sedimentary sequences with variable thicknesses. Brittleness is producing lenses, breccia and gouge, while, ductile intervals (principally shales and salt), evolved in smear and flux. The fault and fractures are behaving in a sealy or leaky ways is mainly dependent on the percentage of these materials in the fault deformation zone. The reservoir sections distancing from shale and salt layers are affected by diagenetic impact of the carbonates filling fault zones by recrystallized calcite and dolomite. Musandam area, Ras Al Khaima (RAK), and Jabal Hafit (JH) on the northeast- and eastern-side of the UAE represents good surface analogues for studying fault materials infill characteristics. To approach this, several samples, picked from fault planes, were analysed. NW-trending faults system show more dominant calcite, dolomite, anhydrites and those closer to salt and shale intervals are showing smearing of the ductile infill. The other linked segments and transfer faults of other directions are represented by a lesser percentage of infill. In areas of gravitational tectonics, the decollement ductile interval is intruded in differently oriented open fractures. The studied outcrops of the offshore salt islands and onshore Jabal Al Dhanna (JD) showing salt flux in the surrounding layers that intruded by the salt. The fractures and faults of the surrounding layers and the embedment insoluble layers are highly deformed and showing nearly total seal. As the salt behaving in an isotropic manner, the deformation can be measured clearly by its impact on the surrounding and embedment's insoluble rocks. The faults/fractures behaviour is vicious in migrating hydrocarbons, production enhancement and hydraulic fracturing propagation.
阿布扎比地下断裂群作为流体通道的重要作用，在不同方向上触发了盆地体系。研究从露头到阿布扎比地下的断层充填物、断层几何形状、带构型和密封特性，并将其与井数据和岩心相结合，是本文的主要目标。断面周围、断段重叠区域和断尖周围的断核包括滑动面和断层泥、角砾岩等变形岩，以及寄主岩透镜体、页岩涂抹、盐通量和成岩特征。阿布扎比变厚度沉积层序地下分布的韧性和脆性材料的能力对比，是确定断裂带构造和断面充填的主要依据。脆性产生透镜体、角砾岩和泥岩，而韧性层(主要是页岩和盐层)则在涂片和通量中演化。断层和裂缝的封闭性或漏性主要取决于这些物质在断层变形带中的百分比。远离页岩和盐层的储层段受到碳酸盐岩充填断裂带的方解石和白云岩重结晶成岩作用的影响。阿联酋东北部和东侧的Musandam地区、Ras Al Khaima (RAK)和Jabal Hafit (JH)是研究断层物质充填特征的良好地表模拟物。为了解决这个问题，研究人员分析了从断层面上采集的几个样本。北西向断裂体系中方解石、白云岩、硬石膏占主导地位，靠近盐层和页岩层段的断裂体系中韧性充填物呈模糊化。其他连接段和其他方向的传递断层的充填比例较小。在重力构造地区，滑脱韧性段侵入于不同取向的开放裂缝中。研究了近海盐岛和岸上贾巴尔•阿尔•丹纳(JD)的露头，显示了盐侵入周围层的盐通量。围岩和埋置不溶层的裂缝断裂高度变形，几乎完全封闭。由于盐具有各向同性，因此可以通过其对周围和嵌入的不溶性岩石的影响来清楚地测量变形。断层/裂缝行为在油气运移、增产和水力压裂扩展方面是恶性的。
{"title":"Fault Planes Materials Fill Characteristics, UAE","authors":"A. Noufal","doi":"10.2118/207217-ms","DOIUrl":"https://doi.org/10.2118/207217-ms","url":null,"abstract":"\u0000 Abu Dhabi subsurface fault populations triggered basin system in diverse directions, because of their significant role as fluid pathways. Studying fault infill materials, fault geometries, zone architecture and sealing properties from outcrops as analogues to the subsurface of Abu Dhabi, and combining these with well data and cores are the main objectives of this paper. The fault core around the fault plane and in areas of overlap between fault segments and around the fault tip include slip surfaces and deformed rocks such as fault gouge, breccia, and lenses of host rock, shale smear, salt flux and diagenetic features.\u0000 Structural geometry of the fault zone architecture and fault plane infill is mainly based on the competency contrast of the materials, that are behaving in ductile or in a brittle manner, which are distributed in the subsurface of Abu Dhabi sedimentary sequences with variable thicknesses. Brittleness is producing lenses, breccia and gouge, while, ductile intervals (principally shales and salt), evolved in smear and flux. The fault and fractures are behaving in a sealy or leaky ways is mainly dependent on the percentage of these materials in the fault deformation zone. The reservoir sections distancing from shale and salt layers are affected by diagenetic impact of the carbonates filling fault zones by recrystallized calcite and dolomite.\u0000 Musandam area, Ras Al Khaima (RAK), and Jabal Hafit (JH) on the northeast- and eastern-side of the UAE represents good surface analogues for studying fault materials infill characteristics. To approach this, several samples, picked from fault planes, were analysed. NW-trending faults system show more dominant calcite, dolomite, anhydrites and those closer to salt and shale intervals are showing smearing of the ductile infill. The other linked segments and transfer faults of other directions are represented by a lesser percentage of infill. In areas of gravitational tectonics, the decollement ductile interval is intruded in differently oriented open fractures.\u0000 The studied outcrops of the offshore salt islands and onshore Jabal Al Dhanna (JD) showing salt flux in the surrounding layers that intruded by the salt. The fractures and faults of the surrounding layers and the embedment insoluble layers are highly deformed and showing nearly total seal. As the salt behaving in an isotropic manner, the deformation can be measured clearly by its impact on the surrounding and embedment's insoluble rocks.\u0000 The faults/fractures behaviour is vicious in migrating hydrocarbons, production enhancement and hydraulic fracturing propagation.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"58 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83266957","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
R. Bethancourt, M. Sarhan, Felix Leonardo Castillo, Imad Al Hamlawi, L. Baptista, Sultan Saeed Al Mansoori, Ali Mubarak Al Braiki, Gennadys Ferrer, A. Cortes, M. Husien, Nader Jouzy, D. Herrera, P. Benny, Jeremy Paul Halma, Joey Roberie, R. Aubakirov
Loss of circulation while drilling the surface holes has become the main challenge in the Abu Dhabi Onshore developed fields. Typical consequences of losses are blind drilling and high instability of the wellbore that eventually led to hole collapse, drill string pack-offs and other associated well-integrity risks. Expensive operations including implementing aerated drilling technique, high water consumption and logistical constraints lead to difficulties reaching planned depth and running casing with added complexities of well integrity due to poor cement quality and bonding in the required isolation zones. Casing while drilling (CWD) is becoming a powerful method in mitigating both lost circulation as well as wellbore stability issues. This paper details the first 13 3/8″ × 16″ successful non-directional CWD trial accomplished in Abu Dhabi and the various advantages of the process. The Non-Directional CWD technology is used to drill vertical or tangent profiles with no directional drilling or logging (formation evaluation) requirements. The casing string is run with drillable body polycrystalline diamond cutters (PDC) bit and solid body centralizers are installed into the casing to achieve the required stand-off for cementing purpose. Some of the best practices applied to conventional drilling operations are not valid for CWD. The paper presents the methodology followed by the drilling engineers during the planning and preparation phases and presents a detailed description of the execution at the rig and the results of the evaluation including time savings, cement quality, rate of penetration, bottomhole assembly (BHA) directional tendency and losses comparison among others.The implementation of CWD saved the operator five days. The bit selection and fit-for-purpose bit design were critical factors for the success of the application. The interval was drilled (as planned) in one run through interbedded formations with a competitive rate of penetration (ROP). In this trial the interval consisted of 2,470ft with an average on-bottom ROP of 63.7 ft/hr, zero quality, health, safety and environmental (QHSE) incidents with enhanced safety for the rig crew.The technology eliminated the non-productive time (NPT) associated with tight spots, BHA pack-off, vibrations or stalls which it is an indication of good hole cleaning and optimum drilling parameters.Medium losses (10-15 BBL/hr) were cured due to the plastering and wellbore strengthening effect of CWD allowing drilling to resume with full returns.Well Verticality maintained with 0.3 degrees Inclination at section final depth.The drillable CWD bit was drilled out with a standard 12.25-in PDC bit in 1 hour as per the plan.
{"title":"First Non-Directional Casing While Drilling CWD Run in ADNOC Onshore Saves Five Days Rig Time and Improves the Well Construction Process Minimizing Associated Risks with Circulation Losses and Wellbore Instability","authors":"R. Bethancourt, M. Sarhan, Felix Leonardo Castillo, Imad Al Hamlawi, L. Baptista, Sultan Saeed Al Mansoori, Ali Mubarak Al Braiki, Gennadys Ferrer, A. Cortes, M. Husien, Nader Jouzy, D. Herrera, P. Benny, Jeremy Paul Halma, Joey Roberie, R. Aubakirov","doi":"10.2118/208024-ms","DOIUrl":"https://doi.org/10.2118/208024-ms","url":null,"abstract":"\u0000 Loss of circulation while drilling the surface holes has become the main challenge in the Abu Dhabi Onshore developed fields. Typical consequences of losses are blind drilling and high instability of the wellbore that eventually led to hole collapse, drill string pack-offs and other associated well-integrity risks. Expensive operations including implementing aerated drilling technique, high water consumption and logistical constraints lead to difficulties reaching planned depth and running casing with added complexities of well integrity due to poor cement quality and bonding in the required isolation zones.\u0000 Casing while drilling (CWD) is becoming a powerful method in mitigating both lost circulation as well as wellbore stability issues. This paper details the first 13 3/8″ × 16″ successful non-directional CWD trial accomplished in Abu Dhabi and the various advantages of the process.\u0000 The Non-Directional CWD technology is used to drill vertical or tangent profiles with no directional drilling or logging (formation evaluation) requirements. The casing string is run with drillable body polycrystalline diamond cutters (PDC) bit and solid body centralizers are installed into the casing to achieve the required stand-off for cementing purpose. Some of the best practices applied to conventional drilling operations are not valid for CWD. The paper presents the methodology followed by the drilling engineers during the planning and preparation phases and presents a detailed description of the execution at the rig and the results of the evaluation including time savings, cement quality, rate of penetration, bottomhole assembly (BHA) directional tendency and losses comparison among others.The implementation of CWD saved the operator five days. The bit selection and fit-for-purpose bit design were critical factors for the success of the application. The interval was drilled (as planned) in one run through interbedded formations with a competitive rate of penetration (ROP). In this trial the interval consisted of 2,470ft with an average on-bottom ROP of 63.7 ft/hr, zero quality, health, safety and environmental (QHSE) incidents with enhanced safety for the rig crew.The technology eliminated the non-productive time (NPT) associated with tight spots, BHA pack-off, vibrations or stalls which it is an indication of good hole cleaning and optimum drilling parameters.Medium losses (10-15 BBL/hr) were cured due to the plastering and wellbore strengthening effect of CWD allowing drilling to resume with full returns.Well Verticality maintained with 0.3 degrees Inclination at section final depth.The drillable CWD bit was drilled out with a standard 12.25-in PDC bit in 1 hour as per the plan.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"74 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73240622","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}
Arlen Sarsekov, Salem Ali Al Kindi, Manal I. Albeshr, Yi Luo, Bulat Kamaletdinov, Vaishak Basavraj Arali
The United Arab Emirates oil and gas reservoirs are continuously intersected with a growing number of horizontal wells and longer drains at varying bottomhole static temperatures. This results in a variety of naturally flowing and more challenging wells where stimulation is required for sustainable flow. Hence it became important to not only rely on plain acid systems for production gain, but to also include more sophisticated acid stimulation systems that can provide improved results in more challenging environments where plain acid may be found lacking. These results were recently achieved via the introduction of single-phase retarded acid (SPRA) as well as viscoelastic diverting acid (VEDA) in inactive wells offshore. The application of SPRA and VEDA was subsequent to extensive laboratory testing including core flow tests, solubility tests, and emulsion tendency testing to the performance of these blends against existing acid recipes such as plain HCl and polymer-based diverting acid. These tests proved that a combination of SPRA and VEDA would allow maximizing lateral coverage in heterogenous reservoirs due to the chemical diversion capabilities from thief zones without imposing further damage that polymer-based diverted acids may cause. The combined SPRA and VEDA would also enhance acid wormhole penetration due to the reduced rate of reaction caused by acid retardation. Such tests were supported with software simulations that provided acid dosage, pumping rate, and pumping method sensitives. Proposing SPRA and VEDA at higher pumping rates enabled the delivery of previously unattainable production influx at sustainable wellhead pressures. In addition, 28% acid content typically used for dolomitic reservoirs was considered unnecessary as 20% retarded acid proved sufficient in such environments. This allowed bullheading treatments, which was previously not possible due to the restriction on pumping 28% acid content across wellheads to avoid causing corrosive damage. Other treatment parameters such as volumes, rates, and acid/diverter sequence and ratio were also adjusted for optimal wormhole penetration across all zones using a fit-for-purpose carbonate matrix acidizing modeling software. The success of SPRA and VEDA was clear in post-treatment evaluation for the cases of previously shut-in wells. These wells were able to produce sustainably at the required tubinghead pressure (production line pressure) after unsuccessful attempts to flow prior to stimulation. The novelty of this paper is the assessment between legacy carbonate stimulation results in UAE using plain HCl acid and polymer-based diverting acid (PDA) and using SPRA and VEDA in shut-in or inactive wells. It also highlights the game-changing solutions that suit the increasing challenges observed in offshore inactive wells including well placement, lithology, bottomhole static temperature, and permeability contrast.
{"title":"Changing the Status Quo: Cases of Production Restoration in Inactive Offshore Oil Wells","authors":"Arlen Sarsekov, Salem Ali Al Kindi, Manal I. Albeshr, Yi Luo, Bulat Kamaletdinov, Vaishak Basavraj Arali","doi":"10.2118/207524-ms","DOIUrl":"https://doi.org/10.2118/207524-ms","url":null,"abstract":"\u0000 The United Arab Emirates oil and gas reservoirs are continuously intersected with a growing number of horizontal wells and longer drains at varying bottomhole static temperatures. This results in a variety of naturally flowing and more challenging wells where stimulation is required for sustainable flow. Hence it became important to not only rely on plain acid systems for production gain, but to also include more sophisticated acid stimulation systems that can provide improved results in more challenging environments where plain acid may be found lacking. These results were recently achieved via the introduction of single-phase retarded acid (SPRA) as well as viscoelastic diverting acid (VEDA) in inactive wells offshore.\u0000 The application of SPRA and VEDA was subsequent to extensive laboratory testing including core flow tests, solubility tests, and emulsion tendency testing to the performance of these blends against existing acid recipes such as plain HCl and polymer-based diverting acid. These tests proved that a combination of SPRA and VEDA would allow maximizing lateral coverage in heterogenous reservoirs due to the chemical diversion capabilities from thief zones without imposing further damage that polymer-based diverted acids may cause. The combined SPRA and VEDA would also enhance acid wormhole penetration due to the reduced rate of reaction caused by acid retardation. Such tests were supported with software simulations that provided acid dosage, pumping rate, and pumping method sensitives.\u0000 Proposing SPRA and VEDA at higher pumping rates enabled the delivery of previously unattainable production influx at sustainable wellhead pressures. In addition, 28% acid content typically used for dolomitic reservoirs was considered unnecessary as 20% retarded acid proved sufficient in such environments. This allowed bullheading treatments, which was previously not possible due to the restriction on pumping 28% acid content across wellheads to avoid causing corrosive damage. Other treatment parameters such as volumes, rates, and acid/diverter sequence and ratio were also adjusted for optimal wormhole penetration across all zones using a fit-for-purpose carbonate matrix acidizing modeling software.\u0000 The success of SPRA and VEDA was clear in post-treatment evaluation for the cases of previously shut-in wells. These wells were able to produce sustainably at the required tubinghead pressure (production line pressure) after unsuccessful attempts to flow prior to stimulation.\u0000 The novelty of this paper is the assessment between legacy carbonate stimulation results in UAE using plain HCl acid and polymer-based diverting acid (PDA) and using SPRA and VEDA in shut-in or inactive wells. It also highlights the game-changing solutions that suit the increasing challenges observed in offshore inactive wells including well placement, lithology, bottomhole static temperature, and permeability contrast.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"14 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88810329","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 2017, a blowout and explosion occurred in a drilling oilwell in the Middle East. After drilling to the depth of 2,610 m, tripping was decided in order to change the bit. When the crew were pulling the drill string out of the hole with the drill-string being at the depth of 1332 m, blowout and explosion occurred. The well was a development well drilling almost horizontally (82 degrees inclination angle) into a highly-pressured gas-cap and oil pay-zone of the oilfield. In this work, following a brief explanation of the root causal factors of the incident, we give an account of the blowout control methods applied to put an end to the blowout. Both the top-kill method and the bottom-kill method by relief well drilling, were simultaneously implemented to control the blowout. Finally, the blowout was successfully controlled by the bottom-kill after 58 days. During top-kill operations, all equipment was cleared away and this contributed to proceeding to permanent abandonment immediately after the relief well success. Finally, the adverse effect of the blowout on the environment (HSE) was qualitatively discussed.
{"title":"The Root Cause Analysis and Successful Control of an Oilwell Blowout in the Middle East","authors":"Rahman Ashena, Farzad Ghorbani, Muhammad Mubashir, Mahdi Nazari Sarem, Amin Iravani","doi":"10.2118/207834-ms","DOIUrl":"https://doi.org/10.2118/207834-ms","url":null,"abstract":"\u0000 In 2017, a blowout and explosion occurred in a drilling oilwell in the Middle East. After drilling to the depth of 2,610 m, tripping was decided in order to change the bit. When the crew were pulling the drill string out of the hole with the drill-string being at the depth of 1332 m, blowout and explosion occurred. The well was a development well drilling almost horizontally (82 degrees inclination angle) into a highly-pressured gas-cap and oil pay-zone of the oilfield. In this work, following a brief explanation of the root causal factors of the incident, we give an account of the blowout control methods applied to put an end to the blowout. Both the top-kill method and the bottom-kill method by relief well drilling, were simultaneously implemented to control the blowout. Finally, the blowout was successfully controlled by the bottom-kill after 58 days. During top-kill operations, all equipment was cleared away and this contributed to proceeding to permanent abandonment immediately after the relief well success. Finally, the adverse effect of the blowout on the environment (HSE) was qualitatively discussed.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"40 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82407964","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}
S. Baloch, J. Leon, S. Masalmeh, D. Chappell, J. Brodie, C. Romero, S. Al Mazrouei, A. Al Tenaiji, M. Al Balooshi, Arit Igogo, M. Azam, Y.K Maheshwar, G. Dupuis
Over the last few years, ADNOC has systematically investigated a new polymer-based EOR scheme to improve sweep efficiency in high temperature and high salinity (HTHS) carbonate reservoirs in Abu Dhabi (Masalmeh et al., 2014). Consequently, ADNOC has developed a thorough de-risking program for the new EOR concept in these carbonate reservoirs. The de-risking program includes extensive laboratory experimental studies and field injectivity tests to ensure that the selected polymer can be propagated in the target reservoirs. A new polymer with high 2-acrylamido-tertiary-butyl sulfonic acid (ATBS) content was identified, based on extensive laboratory studies (Masalmeh, et al., 2019, Dupuis, et al., 2017, Jouenne 2020), and an initial polymer injectivity test (PIT) was conducted in 2019 at 250°F and salinity >200,000 ppm, with low H2S content (Rachapudi, et al., 2020, Leon and Masalmeh, 2021). The next step for ADNOC was to extend polymer application to harsher field conditions, including higher H2S content. Accordingly, a PIT was designed in preparation for a multi-well pilot This paper presents ADNOC's follow-up PIT, which expands the envelope of polymer flooding to dissolve H2S concentrations of 20 - 40 ppm to confirm injectivity at representative field conditions and in situ polymer performance. The PIT was executed over five months, from February 2021 to July 2021, followed by a chase water flood that will run until December 2021. A total of 108,392 barrels of polymer solution were successfully injected during the PIT. The extensive dataset acquired was used to assess injectivity and in-depth mobility reduction associated with the new polymer. Preliminary results from the PIT suggest that all key performance indicators have been achieved, with a predictable viscosity yield and good injectivity at target rates, consistent with the laboratory data. The use of a down-hole shut-in tool (DHSIT) to acquire pressure fall-off (PFO) data clarified the near-wellbore behaviour of the polymer and allowed optimisation of the PIT programme. This paper assesses the importance of water quality on polymer solution preparation and injection performance and reviews operational data acquired during the testing period. Polymer properties determined during the PIT will be used to optimise field and sector models and will facilitate the evaluation of polymer EOR in other giant, heterogeneous carbonate reservoirs, leading to improved recovery in ADNOC and Middle East reservoirs.
{"title":"Expanding Polymer Injectivity Tests on a Second Giant Carbonate UAE Oil Reservoir at High Salinity & High Temperature Conditions.","authors":"S. Baloch, J. Leon, S. Masalmeh, D. Chappell, J. Brodie, C. Romero, S. Al Mazrouei, A. Al Tenaiji, M. Al Balooshi, Arit Igogo, M. Azam, Y.K Maheshwar, G. Dupuis","doi":"10.2118/207498-ms","DOIUrl":"https://doi.org/10.2118/207498-ms","url":null,"abstract":"\u0000 Over the last few years, ADNOC has systematically investigated a new polymer-based EOR scheme to improve sweep efficiency in high temperature and high salinity (HTHS) carbonate reservoirs in Abu Dhabi (Masalmeh et al., 2014). Consequently, ADNOC has developed a thorough de-risking program for the new EOR concept in these carbonate reservoirs. The de-risking program includes extensive laboratory experimental studies and field injectivity tests to ensure that the selected polymer can be propagated in the target reservoirs.\u0000 A new polymer with high 2-acrylamido-tertiary-butyl sulfonic acid (ATBS) content was identified, based on extensive laboratory studies (Masalmeh, et al., 2019, Dupuis, et al., 2017, Jouenne 2020), and an initial polymer injectivity test (PIT) was conducted in 2019 at 250°F and salinity >200,000 ppm, with low H2S content (Rachapudi, et al., 2020, Leon and Masalmeh, 2021). The next step for ADNOC was to extend polymer application to harsher field conditions, including higher H2S content. Accordingly, a PIT was designed in preparation for a multi-well pilot\u0000 This paper presents ADNOC's follow-up PIT, which expands the envelope of polymer flooding to dissolve H2S concentrations of 20 - 40 ppm to confirm injectivity at representative field conditions and in situ polymer performance. The PIT was executed over five months, from February 2021 to July 2021, followed by a chase water flood that will run until December 2021. A total of 108,392 barrels of polymer solution were successfully injected during the PIT. The extensive dataset acquired was used to assess injectivity and in-depth mobility reduction associated with the new polymer.\u0000 Preliminary results from the PIT suggest that all key performance indicators have been achieved, with a predictable viscosity yield and good injectivity at target rates, consistent with the laboratory data. The use of a down-hole shut-in tool (DHSIT) to acquire pressure fall-off (PFO) data clarified the near-wellbore behaviour of the polymer and allowed optimisation of the PIT programme.\u0000 This paper assesses the importance of water quality on polymer solution preparation and injection performance and reviews operational data acquired during the testing period.\u0000 Polymer properties determined during the PIT will be used to optimise field and sector models and will facilitate the evaluation of polymer EOR in other giant, heterogeneous carbonate reservoirs, leading to improved recovery in ADNOC and Middle East reservoirs.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"399 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76441612","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}
Some wells are either producing intermittently or ceasing against the trunk line pressure due to low flowing wellhead pressure. OLS with MPP provides the flexibility such as boosting pressure from low flowing wellhead pressure well to the existing trunk lines. The MPP has a wider pressure operating envelope to accommodate the less flowing wellhead pressure well in long run. Incremental Oil & gas production will be realized by lowering the FWHP on this well using the OLS. Multi-Phase Pumps solutions have sustained production from marginal and restarted non-producing wells. Production gains are highly dependent on the reservoir and well parameters.
{"title":"Enhanced Production with Self-Driven Multi-Phase Pumps","authors":"Maamoun Abdul Halim, Emiliano Maianti","doi":"10.2118/207355-ms","DOIUrl":"https://doi.org/10.2118/207355-ms","url":null,"abstract":"\u0000 Some wells are either producing intermittently or ceasing against the trunk line pressure due to low flowing wellhead pressure. OLS with MPP provides the flexibility such as boosting pressure from low flowing wellhead pressure well to the existing trunk lines. The MPP has a wider pressure operating envelope to accommodate the less flowing wellhead pressure well in long run. Incremental Oil & gas production will be realized by lowering the FWHP on this well using the OLS.\u0000 Multi-Phase Pumps solutions have sustained production from marginal and restarted non-producing wells.\u0000 Production gains are highly dependent on the reservoir and well parameters.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"269 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77720079","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}
C. Sanasi, Luca Dal Forno, Giorgio Ricci Maccarini, Luigi Mutidieri, P. Tempone, D. Mezzapesa, Matilde Dalla Rosa, Alessandro Bucci, F. Rinaldi, C. Andreoletti
The evolution of the energy market requires companies to increase their operating efficiency, leveraging on collaborative environment and existing assets, including Data. A new focus on data governance and integration is needed to maximize the value of data and ensure "real-time" efficient response. The decoupling of data from applications enables organization by domain and data type in one cross-functional data hub. This scheme is independent from the scope of the activity and will therefore maintain its validity when dealing with new business requiring subsurface data utilization. The integrated data platform will feed advanced digital tools capable to control the risks, optimize performance and reduce emissions associated with the operations. Eni is putting this idea into practice with a new data infrastructure which is integrated across all the subsurface disciplines (G&G, Exploration, Upstream Laboratories, Reservoir and Well Operations departments). In this paper, the example of real time data exploitation will be discussed. Real time data workflow was first established in well operations for operational supervision and later developed for real time performance optimization, through the introduction of predictive analytics. Its latest evolution in the broader subsurface domain encompasses the application of AI to operations geology processes and the extension to all operated activities. This approach will equally support new company goals, such as decarbonization, increasing performance of subsurface activities related to underground storage of CO2 in depleted reservoirs.
{"title":"Company Data Governance Transformation to Support the Business Evolution","authors":"C. Sanasi, Luca Dal Forno, Giorgio Ricci Maccarini, Luigi Mutidieri, P. Tempone, D. Mezzapesa, Matilde Dalla Rosa, Alessandro Bucci, F. Rinaldi, C. Andreoletti","doi":"10.2118/207525-ms","DOIUrl":"https://doi.org/10.2118/207525-ms","url":null,"abstract":"\u0000 The evolution of the energy market requires companies to increase their operating efficiency, leveraging on collaborative environment and existing assets, including Data. A new focus on data governance and integration is needed to maximize the value of data and ensure \"real-time\" efficient response.\u0000 The decoupling of data from applications enables organization by domain and data type in one cross-functional data hub. This scheme is independent from the scope of the activity and will therefore maintain its validity when dealing with new business requiring subsurface data utilization. The integrated data platform will feed advanced digital tools capable to control the risks, optimize performance and reduce emissions associated with the operations.\u0000 Eni is putting this idea into practice with a new data infrastructure which is integrated across all the subsurface disciplines (G&G, Exploration, Upstream Laboratories, Reservoir and Well Operations departments). In this paper, the example of real time data exploitation will be discussed.\u0000 Real time data workflow was first established in well operations for operational supervision and later developed for real time performance optimization, through the introduction of predictive analytics. Its latest evolution in the broader subsurface domain encompasses the application of AI to operations geology processes and the extension to all operated activities. This approach will equally support new company goals, such as decarbonization, increasing performance of subsurface activities related to underground storage of CO2 in depleted reservoirs.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"17 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74261913","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}
Narayana Swamy Nallamothu, G. Anghel, H. Singh, F. Kamal
In order to develop an effective inspection program for the early operational phase, Risk Based Inspection (RBI) study is included as a standard requirement in recent EPC Oil & Gas Projects. Conventionally, RBI study was managed by Operators, however nowadays EPC contractors are mandated to execute the same. This paper discusses the challenges faced by EPC Contractor during the execution of RBI study and provides an approach for timely completion of study. RBI study involves enormous data gathering and risk assessment to identify critical equipment, piping systems to optimize inspection programs and recommends inspection frequencies, locations and techniques. In addition, RBI study covers potential damage mechanisms identification, risk ranking and identification of potential hot spots for development of inspection program. RBI is normally performed based on risk assessment methodologies derived from International Standards such as API 580/581, DNV RP G101and applicable Operator guidelines. Specialized software is widely used for carrying out integrated activities involving failure probability, consequence assessment and inspection details. Finally, RBI inspection programs are integrated with Computerized Maintenance Management System. In order to execute RBI study successfully, a specialized third-party Consultant is normally engaged., Further alignment of all stakeholders including RBI study specialist is essential to address the following: - Timely availability of "As-built" data for study such as baseline inspection survey reports Agreement on design data versus baseline inspection data for RBI analysis Agreement on appropriate RBI approach: quantitative vs. semi-quantitative/qualitative Acceptance of RBI software Agreement on inspection program recommendations including hot spots, inspection intervals RBI study activities can be effectively initiated once the equipment fabrication records, piping isometrics, baseline reports and hydro-test data are available. In case of pipelines, inline inspection data should be the initial basis for the pipeline RBI assessment. EPC contractors normally face following challenges during RBI study execution: Delay in finalizing the study due to lack of "As-built" data Inconsistency between the outcomes of Corrosion Risk Assessment Study and RBI study performed by third party due to different corrosion modeling software Implications on selected material of construction as a result of RBI Study findings Ensuring compatibility of RBI templates with Operators CMMS. NPCC, as a large EPC company, has extensive experience in various Oil & Gas projects where RBI studies are developed in recent EPC projects and ensuring the integrity of the newly constructed assets. This paper attempts to address the challenges faced by EPC Contractor during execution of RBI studies; emphasizing the strategic considerations to be adopted for successful and timely completion of the study, providing benefits to the End user
为了在早期作业阶段制定有效的检查计划，基于风险的检查(RBI)研究已成为最近EPC油气项目的标准要求。传统上，RBI研究是由运营商管理的，但现在EPC承包商被授权执行同样的工作。本文讨论了EPC承包商在实施RBI研究过程中所面临的挑战，并提出了及时完成研究的方法。RBI研究涉及大量数据收集和风险评估，以确定关键设备和管道系统，以优化检查计划，并建议检查频率、地点和技术。此外，RBI研究还包括潜在损伤机制识别、风险排序和潜在热点识别，为检测方案的制定提供依据。RBI通常根据国际标准(如API 580/581、DNV RP g101和适用的运营商指南)衍生的风险评估方法进行。专门的软件被广泛用于开展涉及故障概率、后果评估和检查细节的综合活动。最后，将RBI检查程序与计算机维护管理系统相结合。为了成功实施RBI研究，通常会聘请专门的第三方顾问。包括印度储备银行研究专家在内的所有利益相关者的进一步协调对于解决以下问题至关重要:-及时提供用于研究的“建成”数据，如基线检查调查报告，就设计数据与印度储备银行分析的基线检查数据达成一致，就适当的印度储备银行方法达成一致;一旦有了设备制造记录、管道等距图、基线报告和水力测试数据，就可以有效地启动RBI研究活动。对于管道，在线检测数据应作为管道RBI评估的初始依据。EPC承包商在RBI研究执行过程中通常面临以下挑战:由于缺乏“建成”数据而导致研究最终完成的延迟;由于腐蚀建模软件不同，腐蚀风险评估研究的结果与第三方进行的RBI研究的结果不一致;由于RBI研究结果对选择的建筑材料的影响;确保RBI模板与运营商CMMS的兼容性。NPCC作为一家大型EPC公司，在各种石油和天然气项目中拥有丰富的经验，在最近的EPC项目中开发了RBI研究，并确保了新建资产的完整性。本文试图解决EPC承包商在实施RBI研究过程中面临的挑战;强调为成功及适时完成研究而采取的策略考虑，为最终用户提供好处。
{"title":"Risk Based Inspection Study Challenges - An EPC Contractor's Perspective","authors":"Narayana Swamy Nallamothu, G. Anghel, H. Singh, F. Kamal","doi":"10.2118/207421-ms","DOIUrl":"https://doi.org/10.2118/207421-ms","url":null,"abstract":"\u0000 In order to develop an effective inspection program for the early operational phase, Risk Based Inspection (RBI) study is included as a standard requirement in recent EPC Oil & Gas Projects. Conventionally, RBI study was managed by Operators, however nowadays EPC contractors are mandated to execute the same. This paper discusses the challenges faced by EPC Contractor during the execution of RBI study and provides an approach for timely completion of study.\u0000 RBI study involves enormous data gathering and risk assessment to identify critical equipment, piping systems to optimize inspection programs and recommends inspection frequencies, locations and techniques. In addition, RBI study covers potential damage mechanisms identification, risk ranking and identification of potential hot spots for development of inspection program.\u0000 RBI is normally performed based on risk assessment methodologies derived from International Standards such as API 580/581, DNV RP G101and applicable Operator guidelines. Specialized software is widely used for carrying out integrated activities involving failure probability, consequence assessment and inspection details.\u0000 Finally, RBI inspection programs are integrated with Computerized Maintenance Management System.\u0000 In order to execute RBI study successfully, a specialized third-party Consultant is normally engaged., Further alignment of all stakeholders including RBI study specialist is essential to address the following: -\u0000 Timely availability of \"As-built\" data for study such as baseline inspection survey reports Agreement on design data versus baseline inspection data for RBI analysis Agreement on appropriate RBI approach: quantitative vs. semi-quantitative/qualitative Acceptance of RBI software Agreement on inspection program recommendations including hot spots, inspection intervals\u0000 RBI study activities can be effectively initiated once the equipment fabrication records, piping isometrics, baseline reports and hydro-test data are available. In case of pipelines, inline inspection data should be the initial basis for the pipeline RBI assessment.\u0000 EPC contractors normally face following challenges during RBI study execution:\u0000 Delay in finalizing the study due to lack of \"As-built\" data Inconsistency between the outcomes of Corrosion Risk Assessment Study and RBI study performed by third party due to different corrosion modeling software Implications on selected material of construction as a result of RBI Study findings\u0000 Ensuring compatibility of RBI templates with Operators CMMS.\u0000 NPCC, as a large EPC company, has extensive experience in various Oil & Gas projects where RBI studies are developed in recent EPC projects and ensuring the integrity of the newly constructed assets.\u0000 This paper attempts to address the challenges faced by EPC Contractor during execution of RBI studies; emphasizing the strategic considerations to be adopted for successful and timely completion of the study, providing benefits to the End user","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"70 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73363936","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 Middle East contains some of the most fascinating and prolific oil provinces in the world. The combination of excellent source rocks of different geologic ages, the presence of outstanding reservoirs and ubiquitous seals, optimal thermal history, and structural evolution provides an ideal recipe to produce the largest oilfields in the world. The UAE is currently estimated to hold 6% of global oil reserves, 96% of which are within Abu Dhabi. However, exploration for additional recoverable reserves is becoming more challenging. Finding hydrocarbons for the future is dependent upon a detailed understanding of the petroleum systems and subtle play types. For southeastern Abu Dhabi, several petroleum systems have been proposed to explain the oil and gas accumulations in Lower Cretaceous reservoirs. This study presents the practical application of a geochemical inversion workflow to a set of oil samples from Lower Cretaceous reservoirs collected in two exploration wells recently drilled in southeastern Abu Dhabi. The geochemical inversion workflow is based on stable isotope, biomarker, and oil composition data. Preliminary results and comparisons with previously identified oil families in the UAE suggest that the oils were generated from a carbonate-rich source rock deposited during Jurassic time. Compositional data and detailed stratigraphic and structural analyses support the possibility of multiple episodes of lateral and vertical migrations. The implications and risk associated with the timing of oil generation and trap formation are presented here to define a path forward and guide the prospecting efforts within this exciting region.
{"title":"Geochemical Inversion Applied to Oil Samples from Lower Cretaceous Reservoirs, Southeast Abu Dhabi: Implications for Hydrocarbon Exploration","authors":"Lozano Mario Jorge, H. Camacho, José O. Guevara","doi":"10.2118/207558-ms","DOIUrl":"https://doi.org/10.2118/207558-ms","url":null,"abstract":"\u0000 The Middle East contains some of the most fascinating and prolific oil provinces in the world. The combination of excellent source rocks of different geologic ages, the presence of outstanding reservoirs and ubiquitous seals, optimal thermal history, and structural evolution provides an ideal recipe to produce the largest oilfields in the world. The UAE is currently estimated to hold 6% of global oil reserves, 96% of which are within Abu Dhabi. However, exploration for additional recoverable reserves is becoming more challenging. Finding hydrocarbons for the future is dependent upon a detailed understanding of the petroleum systems and subtle play types. For southeastern Abu Dhabi, several petroleum systems have been proposed to explain the oil and gas accumulations in Lower Cretaceous reservoirs. This study presents the practical application of a geochemical inversion workflow to a set of oil samples from Lower Cretaceous reservoirs collected in two exploration wells recently drilled in southeastern Abu Dhabi. The geochemical inversion workflow is based on stable isotope, biomarker, and oil composition data. Preliminary results and comparisons with previously identified oil families in the UAE suggest that the oils were generated from a carbonate-rich source rock deposited during Jurassic time. Compositional data and detailed stratigraphic and structural analyses support the possibility of multiple episodes of lateral and vertical migrations. The implications and risk associated with the timing of oil generation and trap formation are presented here to define a path forward and guide the prospecting efforts within this exciting region.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74930037","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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