Sand management has become in one of the most vital factors in today's upstream oil and gas industry, more and more are the cases where the sand control systems play an important factor to determine the economic viability of each project. This paper will focus in a solution for sand problems in ESP systems applying to sand slug breakdown using a 10 V-Mesh Sand Screen to homogenize the solid inflow in the system so it would be easier to handle the solids through the ESP's stages. The implementation of the screen intake for the homogenization of solids in an ESP well allowed to efficiently manage sand slugs, improving the pump efficiency and avoiding blocking problems in the pump caused by sand. Furthermore, the system allows increasing the frequency of operation of the ESP motor to have a greater drawdown, increasing the production of the fluid from 1600 BFPD to 1800 BFPD. The behavior of the sensor data such as vibration, current, and voltage remained stable throughout the period evaluated, extending the run life of the system.
{"title":"Successful Application of Homogenization Principle in ESPs: Case Study in South America","authors":"G. González, L. Guanacas, D. Pinto, C. Montufar","doi":"10.2118/196070-ms","DOIUrl":"https://doi.org/10.2118/196070-ms","url":null,"abstract":"\u0000 Sand management has become in one of the most vital factors in today's upstream oil and gas industry, more and more are the cases where the sand control systems play an important factor to determine the economic viability of each project. This paper will focus in a solution for sand problems in ESP systems applying to sand slug breakdown using a 10 V-Mesh Sand Screen to homogenize the solid inflow in the system so it would be easier to handle the solids through the ESP's stages. The implementation of the screen intake for the homogenization of solids in an ESP well allowed to efficiently manage sand slugs, improving the pump efficiency and avoiding blocking problems in the pump caused by sand. Furthermore, the system allows increasing the frequency of operation of the ESP motor to have a greater drawdown, increasing the production of the fluid from 1600 BFPD to 1800 BFPD. The behavior of the sensor data such as vibration, current, and voltage remained stable throughout the period evaluated, extending the run life of the system.","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75587369","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}
With the industry shifting gears toward pad development there has been a significant increase in operator press releases to stockholders expressing concern about fracture driven interactions (formerly called "frac hits") within a drilling spacing unit (DSU) (Triepke 2018). Primary wells (formerly called "parents") (Daneshy 2019) are the initial wells on the pad and infill wells (formerly called "children") are all those that follow on the pad or an adjacent pad. Failure to protect the primary well from infill well fracture driven interactions can result in up to 40% EUR losses in infill wells from asymmetric fractures (Elliott 2019)(Ajisafe et al 2017). Adverse frac interactions between wells in a DSU can be largely eliminated with a combination of primary well refracs and infill well zipper fracs. In the primary well protection process there is a movement away from "preloads" as the overall results from the preloads to date suggest they are not effective in preventing infill well frac asymmetry unless the primary well can be restored to its original stress conditions. A number of operators have announced plans in press releases to increase well spacing in the DSUs to reduce well to well interference. A number of of organic shale operators have also announced performance related reserve write downs according to a March 13, 2019 Simmons Energy report (Harrison and Todd 2019). While in some cases the writedowns were due to changes in pricing expectations, the combination of a known reserve bashing situation and numerous operators still relying on preloads for parent protection raises a red flag. It is highly likely that there is a relationship between DSUs that use preloads instead of refracs for primary well protection and poor overall performance from the DSU. It was proposed in the keynote address at a recent primary-infll frac interaction conference that refraccing primary wells is significantly more effective than preloading them in preventing large infill EUR losses (Elliott 2019) (Figures 1 and 2). Figure (3) has a microseismic interpretation of an infill well assymetric frac offsetting a primary well with no refrac. The stranded hydrocarbons are clearly where there is no microseismic activity. For a DSU with 600,000 BO wells the combination of the 40% infill well EUR loss and the loss of up to two PUDs per DSU can be in the $29 million range so this is hardly an academic exercise. Figure 1 Depletion Mitigation Opportunities Figure 2 Depletion Mitigation Results Figure 3 Infill Well Asymmetric Frac in Toe Stage with Depleted Primary Well Overlap Historically, refrac operations in horizontal organic shale wells have had unpredictable production results, with the industry moving toward mechanical isolation following an often painful history that included single stage "pump and really pray" treatments with no diversion to "pump and pray" with chemical or ball sealer diversion. While results from mechanical isolation have been more consisten
随着行业转向区块开发，运营商向股东发布的新闻稿大幅增加，表达了对钻井间距单元(DSU)内裂缝驱动相互作用(以前称为“裂缝撞击”)的担忧(Triepke 2018)。主井(以前称为“父井”)(Daneshy 2019)是区块上的初始井，而填充井(以前称为“子井”)是区块上或邻近区块上的所有井。如果不能保护主井免受填充井裂缝驱动的相互作用的影响，可能会导致不对称裂缝造成的填充井高达40%的损失(Elliott 2019)(Ajisafe et al 2017)。DSU中井间的不良压裂相互作用可以通过主井压裂和填充井拉链压裂的组合来很大程度上消除。在主井保护过程中，“预压”逐渐消失，因为到目前为止，预压的总体结果表明，除非主井能够恢复到原始应力条件，否则它们不能有效防止填充井裂缝不对称。许多运营商已经在新闻稿中宣布了增加dsu井距的计划，以减少井间干扰。根据2019年3月13日Simmons Energy的报告(Harrison and Todd 2019)，许多有机页岩油运营商也宣布了与业绩相关的储备减记。虽然在某些情况下，减记是由于价格预期的变化，但已知的储量冲击情况和许多运营商仍然依赖预加载来保护母公司，这都是一个危险的信号。DSU使用预压而不是压裂进行初级井保护，很可能与DSU整体性能不佳有关。在最近的一次主-充填压裂相互作用会议上，在主题演讲中提出，在防止大量的充填EUR损失方面，重复压裂主井比预压主井更有效(Elliott 2019)(图1和2)。图(3)是对充填井的微地震解释，不对称压裂抵消了没有重复压裂的主井。搁浅的碳氢化合物显然是在没有微地震活动的地方。对于拥有60万口BO井的DSU来说，40%的钻井损失和每个DSU最多两个pud的损失加起来可能在2900万美元的范围内，因此这几乎不是一个学术研究。图1缓解枯竭的机会图2缓解枯竭的结果图3充填井趾段非对称压裂与主井重叠历史上，水平有机页岩井的重复压裂作业具有不可预测的生产结果。在经历了一段痛苦的历史之后，行业开始转向机械隔离，其中包括单级“泵和祈祷”处理，没有转向“泵和祈祷”，使用化学或球密封剂进行转移。虽然机械隔离的结果比前两种方法更一致(Cadotte et al, 2018)，但现在有很多关于最佳机械隔离方法的讨论。最常用的两种隔离技术是常规固井套管和可膨胀衬管。固井套管的主要优点是降低了初始成本，在开始5000英尺的压裂尾管作业之前，成本相差12.3万美元。膨胀尾管的主要优点是直径更大，可将泵送速率提高20%至25%。将极限限入(XLE)完井技术与可膨胀尾管相结合，更高的处理率直接转化为更长的段长，同时仍保持较高的簇效率。由此产生的较低的压裂级数降低了总体增产成本，远远低于可膨胀尾管的初始增量成本，在5000英尺的分支段，与固井尾管相比，每次压裂可节省44.6万美元。随着段数差异的增加，较长的分支段节省的成本会更高。
{"title":"Maximizing Refrac Treatment Recovery Factors in Organic Shales Using Expandable Liners and the Extreme Limited Entry Process","authors":"R. Barba, M. Villareal","doi":"10.2118/195962-ms","DOIUrl":"https://doi.org/10.2118/195962-ms","url":null,"abstract":"\u0000 With the industry shifting gears toward pad development there has been a significant increase in operator press releases to stockholders expressing concern about fracture driven interactions (formerly called \"frac hits\") within a drilling spacing unit (DSU) (Triepke 2018). Primary wells (formerly called \"parents\") (Daneshy 2019) are the initial wells on the pad and infill wells (formerly called \"children\") are all those that follow on the pad or an adjacent pad. Failure to protect the primary well from infill well fracture driven interactions can result in up to 40% EUR losses in infill wells from asymmetric fractures (Elliott 2019)(Ajisafe et al 2017). Adverse frac interactions between wells in a DSU can be largely eliminated with a combination of primary well refracs and infill well zipper fracs. In the primary well protection process there is a movement away from \"preloads\" as the overall results from the preloads to date suggest they are not effective in preventing infill well frac asymmetry unless the primary well can be restored to its original stress conditions. A number of operators have announced plans in press releases to increase well spacing in the DSUs to reduce well to well interference. A number of of organic shale operators have also announced performance related reserve write downs according to a March 13, 2019 Simmons Energy report (Harrison and Todd 2019). While in some cases the writedowns were due to changes in pricing expectations, the combination of a known reserve bashing situation and numerous operators still relying on preloads for parent protection raises a red flag. It is highly likely that there is a relationship between DSUs that use preloads instead of refracs for primary well protection and poor overall performance from the DSU. It was proposed in the keynote address at a recent primary-infll frac interaction conference that refraccing primary wells is significantly more effective than preloading them in preventing large infill EUR losses (Elliott 2019) (Figures 1 and 2). Figure (3) has a microseismic interpretation of an infill well assymetric frac offsetting a primary well with no refrac. The stranded hydrocarbons are clearly where there is no microseismic activity. For a DSU with 600,000 BO wells the combination of the 40% infill well EUR loss and the loss of up to two PUDs per DSU can be in the $29 million range so this is hardly an academic exercise.\u0000 Figure 1 Depletion Mitigation Opportunities Figure 2 Depletion Mitigation Results Figure 3 Infill Well Asymmetric Frac in Toe Stage with Depleted Primary Well Overlap\u0000 Historically, refrac operations in horizontal organic shale wells have had unpredictable production results, with the industry moving toward mechanical isolation following an often painful history that included single stage \"pump and really pray\" treatments with no diversion to \"pump and pray\" with chemical or ball sealer diversion. While results from mechanical isolation have been more consisten","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"183 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77462546","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}
Polymer enhanced oil recovery (EOR) has been successful in onshore and offshore reservoirs, and is especially promising for heavy oil or heterogeneous reservoirs. Polymer retention, mainly due to adsorption, results in the removal of polymer from the solution, leading to the formation of a polymer-free bank. Thus, determining the retention is a key factor in evaluating the feasibility of polymer flooding. This work investigates a method to reduce polymer adsorption and improve the economics of polymer EOR. This is done through laboratory experiments and reservoir simulation. The experimental investigations consisted of five dynamic retention core floodings in fresh and non-fresh high permeability sandstones. Five concentrations of a HPAM-AMPS in high salinity brine were tested. Two types of experiments were performed: fresh-adsorption, and re-adsorption. Injection of the polymer solution in porous media that had never been in contact with polymer composed the fresh-adsorption experiments. Differently, the re-adsorption experiments were performed in media that had been flushed with the same polymer previously. The experiments indicated a type IV isotherm for fresh-adsorption, while the re-adsorption isotherm was of type I. For a polymer concentration of 1250ppm, the fresh-adsorption was 166.7μg/g while the cumulative re-adsorption was 64.8μg/g. Therefore, reduction of ∼61% may be achieved by pre-flushing the medium with a low polymer concentration solution before the injection of the mobility control bank. Other properties of the polymeric system were measured in the core floodings to serve as inputs to the reservoir simulation model. The field-scale simulation studies evaluated the economic impact of the injection of a low concentration polymer slug to reduce polymer loss during EOR, such as observed in the re-adsorption experiments. The production strategy optimization was composed of eight steps, and targeted net present value (NPV) maximization. The case studied was a heavy oil offshore sandstone field, based on a benchmark. The strategy to reduce polymer retention represented a 4% increase in the final NPV over the conventional polymer flooding. Additionally, risk curve analysis demonstrated the advantage of this reduced-retention strategy over waterflooding and conventional polymer flooding. This work shows experimental evidence that polymer overall retention may be reduced through injection of a low polymer concentration bank prior to the mobility control one. Additionally, through numerical simulation and economic analysis, it indicates that the reduced retention allows for an economic advantage in polymer EOR, which may improve the feasibility of polymer flooding projects.
{"title":"Injection Scheme to Reduce Retention and Improve Economics of Polymer Enhanced Oil Recovery","authors":"V. H. Ferreira","doi":"10.2118/199771-stu","DOIUrl":"https://doi.org/10.2118/199771-stu","url":null,"abstract":"\u0000 Polymer enhanced oil recovery (EOR) has been successful in onshore and offshore reservoirs, and is especially promising for heavy oil or heterogeneous reservoirs. Polymer retention, mainly due to adsorption, results in the removal of polymer from the solution, leading to the formation of a polymer-free bank. Thus, determining the retention is a key factor in evaluating the feasibility of polymer flooding. This work investigates a method to reduce polymer adsorption and improve the economics of polymer EOR. This is done through laboratory experiments and reservoir simulation. The experimental investigations consisted of five dynamic retention core floodings in fresh and non-fresh high permeability sandstones. Five concentrations of a HPAM-AMPS in high salinity brine were tested. Two types of experiments were performed: fresh-adsorption, and re-adsorption. Injection of the polymer solution in porous media that had never been in contact with polymer composed the fresh-adsorption experiments. Differently, the re-adsorption experiments were performed in media that had been flushed with the same polymer previously. The experiments indicated a type IV isotherm for fresh-adsorption, while the re-adsorption isotherm was of type I. For a polymer concentration of 1250ppm, the fresh-adsorption was 166.7μg/g while the cumulative re-adsorption was 64.8μg/g. Therefore, reduction of ∼61% may be achieved by pre-flushing the medium with a low polymer concentration solution before the injection of the mobility control bank. Other properties of the polymeric system were measured in the core floodings to serve as inputs to the reservoir simulation model. The field-scale simulation studies evaluated the economic impact of the injection of a low concentration polymer slug to reduce polymer loss during EOR, such as observed in the re-adsorption experiments. The production strategy optimization was composed of eight steps, and targeted net present value (NPV) maximization. The case studied was a heavy oil offshore sandstone field, based on a benchmark. The strategy to reduce polymer retention represented a 4% increase in the final NPV over the conventional polymer flooding. Additionally, risk curve analysis demonstrated the advantage of this reduced-retention strategy over waterflooding and conventional polymer flooding. This work shows experimental evidence that polymer overall retention may be reduced through injection of a low polymer concentration bank prior to the mobility control one. Additionally, through numerical simulation and economic analysis, it indicates that the reduced retention allows for an economic advantage in polymer EOR, which may improve the feasibility of polymer flooding projects.","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"32 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80017771","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}
Reservoir characterisation for modelling and flow simulation is done assuming the homogenous nature of the rock. Heterogeneity is overlooked to prevent occurrences of reserve management complexities. Bioturbated sandstone reservoirs are heterogeneous and prominently found in many petroleum producing basins. Studying the fluid characteristics of these heterogeneous systems is essential, as with changing characters will affect the resulting wettability behaviour. Thus, in a bioturbated heterogeneous reservoir, estimation of the wettability will help in estimating the flow behaviour and possible outcomes of hydrocarbon oil and gas recovery from such formations. With this background, a collective approach has been designed to understand the reservoir behaviour of bioturbated sandstones from Kachchh Basin. The samples are from outcrop, and the analysis includes established standard experimental procedures of core/rock analysis for estimating wettability. The paper explores the experimental analysis of the measuring contract angle in various bioturbated samples. Contact angles of both oil-wet and water-wet cores were measured considering time and gradient factors. Capillary pressure of the various grades of bioturbated sandstones was calculated combining obtained data on contact angle values along with the pore size (radius) and interfacial tension data. The results suggest that the final model can be designed and proposed for the characterisation of bioturbated heterogeneous sandstones using the Capillary pressure behaviour of rocks along with hysteresis trend of imbibition and drainage flows.
{"title":"Wettability Studies and Estimation of Capillary Pressure on Heterogeneous Bioturbated Sandstones from Kachchh Basin, India","authors":"Adityam Dutta","doi":"10.2118/199763-stu","DOIUrl":"https://doi.org/10.2118/199763-stu","url":null,"abstract":"\u0000 Reservoir characterisation for modelling and flow simulation is done assuming the homogenous nature of the rock. Heterogeneity is overlooked to prevent occurrences of reserve management complexities. Bioturbated sandstone reservoirs are heterogeneous and prominently found in many petroleum producing basins. Studying the fluid characteristics of these heterogeneous systems is essential, as with changing characters will affect the resulting wettability behaviour. Thus, in a bioturbated heterogeneous reservoir, estimation of the wettability will help in estimating the flow behaviour and possible outcomes of hydrocarbon oil and gas recovery from such formations. With this background, a collective approach has been designed to understand the reservoir behaviour of bioturbated sandstones from Kachchh Basin. The samples are from outcrop, and the analysis includes established standard experimental procedures of core/rock analysis for estimating wettability. The paper explores the experimental analysis of the measuring contract angle in various bioturbated samples. Contact angles of both oil-wet and water-wet cores were measured considering time and gradient factors. Capillary pressure of the various grades of bioturbated sandstones was calculated combining obtained data on contact angle values along with the pore size (radius) and interfacial tension data. The results suggest that the final model can be designed and proposed for the characterisation of bioturbated heterogeneous sandstones using the Capillary pressure behaviour of rocks along with hysteresis trend of imbibition and drainage flows.","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"19 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81891204","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}
Mahmoud Atef El Gharbawi, A. Elgibaly, A. Salem, Mohamed Abbas
This paper describes the implementation of a performance analysis (PA) review and a comprehensive root cause failure analysis (RCFA) for the artificial lift system (ALS) failures in heavy oil wells. The subject wells, located in Egyptian Eastern Desert (EED), have been operated by Canadian-Egyptian joint venture. Progressive cavity pump (PCP) and beam pump (BP) have been selected as the preferred ALS methods. With the objective of improving ALS performance, RCFA identifies the main causes of ALS failures and proposes guidelines and recommendations with a new open source service for the current and future development for EED Oil companies. PA has been applied using some Key Performance Indicators (KPI), such as: failure index, recurrence index, and average run life in order to track all failed and crucial issues. RCFA has been applied to different ALS, such as: BP and PCP. Therefore, the definition or limitation of the boundaries of each system and the classification of failures were performed. RCFA covered failures between 2012 and 2018 for average 150 active wells and 622 failures. Finally, the new open source service applied as a trial to evolve the failure tracking and decision making methodology. PA review showed a high failure and recurrence index that reached 3.0 and 3.7, respectively, in 2014 then declined to 1.0 and 1.7, respectively, in 2017 as a result of comprehensive corrective actions implemented. RCFA showed that rod string failure in BP was and still is a dominant failure with 200 failures over the last six years. Moreover, Down-hole pump failure in PCP was the major PCP failure system although its failures declined from 80 failures in 2014 to 14 failures in 2018. Several field cases were presented to cover the dominant cause of failures for both BP and PCP wells. Most wells had a significant improvement in their mean time to failure (MTTF) after reviewing design, installation and operation procedures. The procedure for carrying out this methodology and implementing lessons learned has been presented in this paper. In addition, the new open source integration service provides an increased visibility about individual well performance issues and more broadly, about field performance and ALS failures.
{"title":"Performance Analysis of the Artificial Lift Systems for Heavy Oil Wells in the Egyptian Eastern Desert","authors":"Mahmoud Atef El Gharbawi, A. Elgibaly, A. Salem, Mohamed Abbas","doi":"10.2118/196173-ms","DOIUrl":"https://doi.org/10.2118/196173-ms","url":null,"abstract":"\u0000 This paper describes the implementation of a performance analysis (PA) review and a comprehensive root cause failure analysis (RCFA) for the artificial lift system (ALS) failures in heavy oil wells. The subject wells, located in Egyptian Eastern Desert (EED), have been operated by Canadian-Egyptian joint venture. Progressive cavity pump (PCP) and beam pump (BP) have been selected as the preferred ALS methods. With the objective of improving ALS performance, RCFA identifies the main causes of ALS failures and proposes guidelines and recommendations with a new open source service for the current and future development for EED Oil companies.\u0000 PA has been applied using some Key Performance Indicators (KPI), such as: failure index, recurrence index, and average run life in order to track all failed and crucial issues. RCFA has been applied to different ALS, such as: BP and PCP. Therefore, the definition or limitation of the boundaries of each system and the classification of failures were performed. RCFA covered failures between 2012 and 2018 for average 150 active wells and 622 failures. Finally, the new open source service applied as a trial to evolve the failure tracking and decision making methodology.\u0000 PA review showed a high failure and recurrence index that reached 3.0 and 3.7, respectively, in 2014 then declined to 1.0 and 1.7, respectively, in 2017 as a result of comprehensive corrective actions implemented. RCFA showed that rod string failure in BP was and still is a dominant failure with 200 failures over the last six years. Moreover, Down-hole pump failure in PCP was the major PCP failure system although its failures declined from 80 failures in 2014 to 14 failures in 2018. Several field cases were presented to cover the dominant cause of failures for both BP and PCP wells. Most wells had a significant improvement in their mean time to failure (MTTF) after reviewing design, installation and operation procedures.\u0000 The procedure for carrying out this methodology and implementing lessons learned has been presented in this paper. In addition, the new open source integration service provides an increased visibility about individual well performance issues and more broadly, about field performance and ALS failures.","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86001731","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 orientation of hydraulic fractures controls the productivity from hydrocarbon reservoirs. Productivity from low permeability formations is greatly improved having multiple fractures oriented transversely rather than longitudinally, relative to a horizontal wellbore. Analytical approximations from the literature for the longitudinal and transverse fracturing stresses are modified to incorporate pore pressure effects and then used to develop a criterion for the orientation of fractures initiating from perforated wells. The validity of this criterion is assessed numerically and is found to overestimate transverse fracture initiation, which occurs under a narrow range of conditions; when the formation tensile strength is below a critical value and the breakdown pressure within a "window." In horizontal wells, it is easier to achieve longitudinal fracture initiation, as transverse fracture initiation only occurs over a narrow wellbore pressure-at-breakdown window, while longitudinal fracture initiation occurs at comparatively higher wellbore pressures. The numerical study shows that in contradiction with existing analytical approximations, the tangential stress which induces transverse fracture initiation, is a stronger function of wellbore pressure just as the stress inducing longitudinal fracture initiation is. This reduces the breakdown pressure window for transverse fracture initiation compared to what the derived analytical approximations predict. Furthermore, this creates an additional constraint for transverse fracture initiation; the critical tensile strength value, which determines the maximum tensile strength for which transverse fracture initiation is possible for a given stress state. The range of the in-situ stress states where transverse fracture initiation is promoted can be visualized in dimensionless plots for perforated wells. This is useful for completion engineers; when targeting low permeability formations, wells must be made to induce multiple transverse fractures. A numerical simulation scheme performed on several stress states demonstrates frequent occurrence of longitudinal fracture initiation, implying that the propagating fracture re-orients in the near-wellbore region to become aligned perpendicular to the least compressive in-situ principal stress. This is the cause of near-wellbore tortuosity, which in turn is a cause completions and production-related problems, such as early screenouts and post-stimulation well underperformance.
{"title":"Orientation of Hydraulic Fracture Initiation from Perforated Horizontal Wellbores","authors":"Andreas Michael","doi":"10.2118/199766-stu","DOIUrl":"https://doi.org/10.2118/199766-stu","url":null,"abstract":"\u0000 The orientation of hydraulic fractures controls the productivity from hydrocarbon reservoirs. Productivity from low permeability formations is greatly improved having multiple fractures oriented transversely rather than longitudinally, relative to a horizontal wellbore. Analytical approximations from the literature for the longitudinal and transverse fracturing stresses are modified to incorporate pore pressure effects and then used to develop a criterion for the orientation of fractures initiating from perforated wells. The validity of this criterion is assessed numerically and is found to overestimate transverse fracture initiation, which occurs under a narrow range of conditions; when the formation tensile strength is below a critical value and the breakdown pressure within a \"window.\"\u0000 In horizontal wells, it is easier to achieve longitudinal fracture initiation, as transverse fracture initiation only occurs over a narrow wellbore pressure-at-breakdown window, while longitudinal fracture initiation occurs at comparatively higher wellbore pressures. The numerical study shows that in contradiction with existing analytical approximations, the tangential stress which induces transverse fracture initiation, is a stronger function of wellbore pressure just as the stress inducing longitudinal fracture initiation is. This reduces the breakdown pressure window for transverse fracture initiation compared to what the derived analytical approximations predict. Furthermore, this creates an additional constraint for transverse fracture initiation; the critical tensile strength value, which determines the maximum tensile strength for which transverse fracture initiation is possible for a given stress state.\u0000 The range of the in-situ stress states where transverse fracture initiation is promoted can be visualized in dimensionless plots for perforated wells. This is useful for completion engineers; when targeting low permeability formations, wells must be made to induce multiple transverse fractures. A numerical simulation scheme performed on several stress states demonstrates frequent occurrence of longitudinal fracture initiation, implying that the propagating fracture re-orients in the near-wellbore region to become aligned perpendicular to the least compressive in-situ principal stress. This is the cause of near-wellbore tortuosity, which in turn is a cause completions and production-related problems, such as early screenouts and post-stimulation well underperformance.","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"27 16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81013922","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}
Oil and gas businesses are often characterised as operating in volatile, uncertain, complex and ambiguous (‘VUCA’) environments, whilst also expected to meet ever more demanding operational challenges and stakeholder expectations. Within this setting the historically prevalent directive, ‘command and control’ leadership style has become increasingly ineffective at creating a workplace culture which fully enables and engages staff, especially millennials, to deliver outstanding results sustainably. This paper looks at what it takes for an organisation to shift towards a ‘coaching culture’, one in which exceptional performance is gained by a significantly higher quality of conversation between all involved in the business. The paper discusses the business context for a modern oil and gas business which necessitates a shift towards a ‘coaching culture’ for many in the sector; it sheds light on the critical elements of such a change programme and the key steps that are required for such a change to be successful; it examines the theoretical basis for development of a coaching leadership style in the sector; and it shares the authors’ practical learning from the field gained through implementation of such programmes in the sector, with examples and composite case studies.
{"title":"Culture Eats Strategy for Breakfast: Developing Coaching Cultures in the Oil and Gas Sector","authors":"R. Hamp, D. Webster","doi":"10.2118/195997-ms","DOIUrl":"https://doi.org/10.2118/195997-ms","url":null,"abstract":"\u0000 Oil and gas businesses are often characterised as operating in volatile, uncertain, complex and ambiguous (‘VUCA’) environments, whilst also expected to meet ever more demanding operational challenges and stakeholder expectations. Within this setting the historically prevalent directive, ‘command and control’ leadership style has become increasingly ineffective at creating a workplace culture which fully enables and engages staff, especially millennials, to deliver outstanding results sustainably. This paper looks at what it takes for an organisation to shift towards a ‘coaching culture’, one in which exceptional performance is gained by a significantly higher quality of conversation between all involved in the business. The paper discusses the business context for a modern oil and gas business which necessitates a shift towards a ‘coaching culture’ for many in the sector; it sheds light on the critical elements of such a change programme and the key steps that are required for such a change to be successful; it examines the theoretical basis for development of a coaching leadership style in the sector; and it shares the authors’ practical learning from the field gained through implementation of such programmes in the sector, with examples and composite case studies.","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"50 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82987953","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}
An experimental study was conducted to measure the settling velocity of spherical particles in viscoplastic fluids. Using a mechanistic model based on the balance of the forces acting on the settling particle and detailed statistical analyses of the experimental results, a generalized model for predicting settling velocity of spherical particles in viscoplastic fluids was developed. The main objectives of the study were: i.) To measure the terminal settling velocity of particles in various viscoplastic fluids intending to expand the present database of experimental data ii.) To develop a new Drag coefficient-particle Reynolds number (CD-Rep) correlation that is applicable to both Newtonian and non-Newtonian viscoplastic fluids iii.) To present a general non-iterative approach for predicting settling velocities of particles in Newtonian and non-Newtonian viscoplastic fluids irrespective of their rheological models (Casson Model, Herschel Bulkley Model, and Bingham Model etc.). The settling velocities of the spherical particles (Specific gravity ranging from 2.5 - 7.7; Diameters: ranging from 1.09 - 4.00 mm) in various Carbopol solutions were measured using Particle Image Shadowgraphy (PIS). The experimental results were combined with experimental data published in the literature to broaden the range and applicability of empirical analysis. Advanced statistical analysis programs (OriginPro 9.0 and MATLAB r2018b) were utilized together with extensive experimental data to develop a new CD-Rep correlation. In this study, a new modified shear Reynolds number (ReT*) was introduced, which physically quantifies the effects of non-Newtonian fluid rheological properties on the settling velocity. The newly developed CD-Rep correlation and the modified shear Reynolds number were incorporated into the Wilson et al. (2003) model to develop a generalized model that can be used for predicting particle settling velocity in viscoplastic fluids. We have shown that presented new model predicts settling velocity better and yielded relatively more accurate results than existing models with the lowest approximate Mean Absolute Error (MAE) of 0.1 m/s for all data points. In addition to enhanced prediction accuracy, this new model occludes application constraints and offers prediction versatility that is lacking in current existing models by being valid for diverse rheological models of non-Newtonian viscoplastic fluids. The paper is concluded by presenting an illustrative and pragmatic example to calculate the terminal velocity of a spherical particle in a non-Newtonian viscoplastic fluid using the presented generalized model. The knowledge of particle settling velocity in viscoplastic fluids is indispensable for the design, analysis, and optimization of a wide spectrum of industrial processes such as cuttings transport in oil and gas well drilling and proppant transport in hydraulic fracturing operations. By augmenting the current corpus of experimental data; we ha
{"title":"A New Generalized Model for Predicting Particle Settling Velocity in Viscoplastic Fluids","authors":"T. Okesanya, E. Kuru","doi":"10.2118/196104-ms","DOIUrl":"https://doi.org/10.2118/196104-ms","url":null,"abstract":"\u0000 An experimental study was conducted to measure the settling velocity of spherical particles in viscoplastic fluids. Using a mechanistic model based on the balance of the forces acting on the settling particle and detailed statistical analyses of the experimental results, a generalized model for predicting settling velocity of spherical particles in viscoplastic fluids was developed. The main objectives of the study were: i.) To measure the terminal settling velocity of particles in various viscoplastic fluids intending to expand the present database of experimental data ii.) To develop a new Drag coefficient-particle Reynolds number (CD-Rep) correlation that is applicable to both Newtonian and non-Newtonian viscoplastic fluids iii.) To present a general non-iterative approach for predicting settling velocities of particles in Newtonian and non-Newtonian viscoplastic fluids irrespective of their rheological models (Casson Model, Herschel Bulkley Model, and Bingham Model etc.).\u0000 The settling velocities of the spherical particles (Specific gravity ranging from 2.5 - 7.7; Diameters: ranging from 1.09 - 4.00 mm) in various Carbopol solutions were measured using Particle Image Shadowgraphy (PIS). The experimental results were combined with experimental data published in the literature to broaden the range and applicability of empirical analysis. Advanced statistical analysis programs (OriginPro 9.0 and MATLAB r2018b) were utilized together with extensive experimental data to develop a new CD-Rep correlation. In this study, a new modified shear Reynolds number (ReT*) was introduced, which physically quantifies the effects of non-Newtonian fluid rheological properties on the settling velocity. The newly developed CD-Rep correlation and the modified shear Reynolds number were incorporated into the Wilson et al. (2003) model to develop a generalized model that can be used for predicting particle settling velocity in viscoplastic fluids.\u0000 We have shown that presented new model predicts settling velocity better and yielded relatively more accurate results than existing models with the lowest approximate Mean Absolute Error (MAE) of 0.1 m/s for all data points. In addition to enhanced prediction accuracy, this new model occludes application constraints and offers prediction versatility that is lacking in current existing models by being valid for diverse rheological models of non-Newtonian viscoplastic fluids. The paper is concluded by presenting an illustrative and pragmatic example to calculate the terminal velocity of a spherical particle in a non-Newtonian viscoplastic fluid using the presented generalized model.\u0000 The knowledge of particle settling velocity in viscoplastic fluids is indispensable for the design, analysis, and optimization of a wide spectrum of industrial processes such as cuttings transport in oil and gas well drilling and proppant transport in hydraulic fracturing operations. By augmenting the current corpus of experimental data; we ha","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82426695","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}
Implementation of a drift-flux (DF) multiphase flow model within a fully-coupled wellbore-reservoir simulator is non-trivial and must adhere to a number of strict requirements in order to ensure numerical robustness and convergence. The existing DF model that can meet these requirements is only fully posed for upward flow from 2 degrees (from the horizontal) to vertical. The work attempts to extend the current DF model to a unified and numerically robust model that is applicable to all well inclinations. In order to achieve this objective, some 5805 experimentally measured data points from 22 sources as well as 13440 data points from the OLGA-S library are utilized to parameterize a new DF model – one that makes use of the accepted upward flow DF model and a new formulation extending this to horizontal and downward flow. The proposed model is compared against 2 existing DF models (also applicable to all inclinations) and is shown to have better, or equivalent, performance. More significantly, the model is also shown to be numerically smooth, continuous and stable for co-current flow when implemented in a fully implicitly coupled wellbore-reservoir simulator.
{"title":"A Unified Gas-Liquid Drift-Flux Model for Coupled Wellbore-Reservoir Simulation","authors":"Hewei Tang, W. Bailey, T. Stone, J. Killough","doi":"10.2118/195885-ms","DOIUrl":"https://doi.org/10.2118/195885-ms","url":null,"abstract":"\u0000 Implementation of a drift-flux (DF) multiphase flow model within a fully-coupled wellbore-reservoir simulator is non-trivial and must adhere to a number of strict requirements in order to ensure numerical robustness and convergence. The existing DF model that can meet these requirements is only fully posed for upward flow from 2 degrees (from the horizontal) to vertical. The work attempts to extend the current DF model to a unified and numerically robust model that is applicable to all well inclinations. In order to achieve this objective, some 5805 experimentally measured data points from 22 sources as well as 13440 data points from the OLGA-S library are utilized to parameterize a new DF model – one that makes use of the accepted upward flow DF model and a new formulation extending this to horizontal and downward flow. The proposed model is compared against 2 existing DF models (also applicable to all inclinations) and is shown to have better, or equivalent, performance. More significantly, the model is also shown to be numerically smooth, continuous and stable for co-current flow when implemented in a fully implicitly coupled wellbore-reservoir simulator.","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78938262","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 traditional advantage of petroleum-based transport fuels of unmatched energy-density and affordability is diluted with the requirement to lower atmospheric carbon. However, despite a significant R&D effort and investment over the last three decades, humanity is still looking for carbon neutral alternatives to petroleum that can be commercially viable. This paper presents meaningful novel approaches to deal with carbon abatement utilizing petroleum that have a better chance to succeed in fulfilling the underlying techno-economic desirables. While the multi-directional work performed in the past on the subject has informed us on a variety of related topics, going forward the society can benefit from a systematic approach to solving atmospheric CO2 problem building on the petroleum advantage. A framework formulating the challenge in terms of techno-economic and environmental requirements is presented that narrows down further work to only meaningful and promising leads. With this framework in mind a few specific pathways are proposed that naturally hold the desired traits if certain conditions are met. These conditions in turn define specific objectives of the subsequent developmental work. While it is premature to suggest any of these will develop into a commercially viable pragmatic method, due to the underlying criteria they hold a better chance to be successful. The presented pathways using advances in electro-chemistry, nanoscience, rational design, and other areas range from (a) mimicking natural fixation of CO2 as in plants to produce tailored polysaccharides or food, to (b) converting CO2 to substances such as carboxylic acids for easy and cost effective sequestration, to (c) changing the way petroleum fuel is used in internal combustion engines to alter the exit state of oxidation of carbon so that the waste product is easily and economically captured compared to the conventional waste product - CO2. One outcome from the framework results in collapse of the economic models and associated technical approaches that aim to convert CO2 to sellable products, owing mainly to the volume of the global GHG challenge. On the other hand, a common element in the proposed promising leads is to deal with the problem of carbon abatement as an added step with an associated cost. The lower this cost, the less diluted the petroleum-advantage. In this context the framework also points to a range of relative costs that the carbon abatement approaches have to work within to retain the petroleum advantage. The outlined technical approaches of carbon abatement are not previously discussed in the literature and hold the promise to help combat the global GHG challenge in a more practical and significant way.
{"title":"Promising Pathways to Lower Atmospheric Carbon Without Sacrificing the Petroleum Advantage","authors":"S. Gupta","doi":"10.2118/196109-ms","DOIUrl":"https://doi.org/10.2118/196109-ms","url":null,"abstract":"\u0000 The traditional advantage of petroleum-based transport fuels of unmatched energy-density and affordability is diluted with the requirement to lower atmospheric carbon. However, despite a significant R&D effort and investment over the last three decades, humanity is still looking for carbon neutral alternatives to petroleum that can be commercially viable. This paper presents meaningful novel approaches to deal with carbon abatement utilizing petroleum that have a better chance to succeed in fulfilling the underlying techno-economic desirables.\u0000 While the multi-directional work performed in the past on the subject has informed us on a variety of related topics, going forward the society can benefit from a systematic approach to solving atmospheric CO2 problem building on the petroleum advantage. A framework formulating the challenge in terms of techno-economic and environmental requirements is presented that narrows down further work to only meaningful and promising leads. With this framework in mind a few specific pathways are proposed that naturally hold the desired traits if certain conditions are met. These conditions in turn define specific objectives of the subsequent developmental work. While it is premature to suggest any of these will develop into a commercially viable pragmatic method, due to the underlying criteria they hold a better chance to be successful. The presented pathways using advances in electro-chemistry, nanoscience, rational design, and other areas range from (a) mimicking natural fixation of CO2 as in plants to produce tailored polysaccharides or food, to (b) converting CO2 to substances such as carboxylic acids for easy and cost effective sequestration, to (c) changing the way petroleum fuel is used in internal combustion engines to alter the exit state of oxidation of carbon so that the waste product is easily and economically captured compared to the conventional waste product - CO2.\u0000 One outcome from the framework results in collapse of the economic models and associated technical approaches that aim to convert CO2 to sellable products, owing mainly to the volume of the global GHG challenge. On the other hand, a common element in the proposed promising leads is to deal with the problem of carbon abatement as an added step with an associated cost. The lower this cost, the less diluted the petroleum-advantage. In this context the framework also points to a range of relative costs that the carbon abatement approaches have to work within to retain the petroleum advantage.\u0000 The outlined technical approaches of carbon abatement are not previously discussed in the literature and hold the promise to help combat the global GHG challenge in a more practical and significant way.","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"26 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82863238","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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