The stimulation design of hydraulically fractured wells has always pitted the engineer's capability to maximize the fracture extent (or fracture half-length within the formation) versus the conductivity of the fracture pack generated by the deposited proppant material. In essence, the area of productive reservoir rock contacted by the hydraulic fracture treatment needs to be appropriately engineered to remain connected to the wellbore over the life of the well to maximize reservoir recovery. The completion design of multi-stage hydraulically fractured horizontal wells has been driven by their application to unconventional oil and gas reservoirs. This has primarily occurred in North America where most of the wells drilled and completed were operated by small, private, or upstream-only independent public companies. Metrics used to evaluate performance and completion design changes were short-term in nature and typically focused on parameters such as peak-month production, 90- or 180-day cumulative production; or at longest, the first year or two of cumulative production. Capital efficiency, and capital return or well payout were drivers of value creation in an environment where the well inventory was viewed as extensive if not unlimited and the quick recycling of invested capital created the illusion of value creation. Short-term performance metrics give credence to fracture designs that value most the early-time production that is dominated by rate acceleration. The work presented in this paper shows a comparison of fracture designs in deep unconventional formations looking to minimize cost by pumping all sand proppants versus a focus on ultimate recovery from the reservoir with designs that are more applicable to the stress regime. The work shows the importance of maintaining the wellbore connectivity to the reservoir by designing fracture treatments using proppant conductivity decline data measured over an extended-time period of months or years to maximize ultimate recovery from the reservoir. This approach will be critical to those E&P companies who view their well inventory or resource base as finite and consequently place a priority on maximizing recovery from the reservoir.
{"title":"The Impact of Extended-Time Proppant Conductivity Impairment on the Ultimate Recovery from Unconventional Horizontal Well Completions","authors":"C. Pearson, G. Fowler","doi":"10.2118/205294-ms","DOIUrl":"https://doi.org/10.2118/205294-ms","url":null,"abstract":"\u0000 The stimulation design of hydraulically fractured wells has always pitted the engineer's capability to maximize the fracture extent (or fracture half-length within the formation) versus the conductivity of the fracture pack generated by the deposited proppant material. In essence, the area of productive reservoir rock contacted by the hydraulic fracture treatment needs to be appropriately engineered to remain connected to the wellbore over the life of the well to maximize reservoir recovery.\u0000 The completion design of multi-stage hydraulically fractured horizontal wells has been driven by their application to unconventional oil and gas reservoirs. This has primarily occurred in North America where most of the wells drilled and completed were operated by small, private, or upstream-only independent public companies. Metrics used to evaluate performance and completion design changes were short-term in nature and typically focused on parameters such as peak-month production, 90- or 180-day cumulative production; or at longest, the first year or two of cumulative production. Capital efficiency, and capital return or well payout were drivers of value creation in an environment where the well inventory was viewed as extensive if not unlimited and the quick recycling of invested capital created the illusion of value creation.\u0000 Short-term performance metrics give credence to fracture designs that value most the early-time production that is dominated by rate acceleration. The work presented in this paper shows a comparison of fracture designs in deep unconventional formations looking to minimize cost by pumping all sand proppants versus a focus on ultimate recovery from the reservoir with designs that are more applicable to the stress regime. The work shows the importance of maintaining the wellbore connectivity to the reservoir by designing fracture treatments using proppant conductivity decline data measured over an extended-time period of months or years to maximize ultimate recovery from the reservoir. This approach will be critical to those E&P companies who view their well inventory or resource base as finite and consequently place a priority on maximizing recovery from the reservoir.","PeriodicalId":10917,"journal":{"name":"Day 2 Wed, January 12, 2022","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-01-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90835254","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}
Nadir Husein, Vishwajit Upadhye, A. Drobot, V. Bolshakov, A. Buyanov
Reliable information about the inflow composition and distribution in a multilateral well is of great importance and an existing challenge in the oil and gas industry. In this paper, we present an innovative method for dynamic monitoring of inflow profile based on quantum marker technology in a multi-lateral well located in West Siberia. Marker systems were placed in the well during the well reconstruction by horizontal side tracking with the parent borehole remaining in production. This way of reconstruction allows development of the reservoir drainage area with a lateral hole and bringing the oil reserves from the parent borehole into production, which results in an increased flow rate and improved oil recovery rate. Placement of marker systems into parent borehole and side-track for fluid distribution monitoring allows to evaluate the flow rate from every borehole and estimate the effectiveness of performed well reconstruction. Marker systems are placed into the parent borehole as a downhole sub installed into the well completion string. For the side-track polymer-coated marked proppant was injected during hydraulic fracturing to place markers. The developed method was reliably used for an accurate and fast determination of the inflow distribution in a multi-lateral well which allows more efficient field development and also enabled us to provide effective solutions for following challenges: Providing tools for timely water cut diagnostics in multilateral wells and information for water shut-off method selection; Selecting the optimal well operating mode for effective field development and premature flooding prevention in one or both boreholes; Evaluating whether well construction was performed efficiently, and an increased production rate was achieved; Leading to a considerable economic savings in capital expenditure.
{"title":"Production Monitoring of Multilateral Wells by Quantum Marker Systems","authors":"Nadir Husein, Vishwajit Upadhye, A. Drobot, V. Bolshakov, A. Buyanov","doi":"10.2118/205290-ms","DOIUrl":"https://doi.org/10.2118/205290-ms","url":null,"abstract":"\u0000 Reliable information about the inflow composition and distribution in a multilateral well is of great importance and an existing challenge in the oil and gas industry. In this paper, we present an innovative method for dynamic monitoring of inflow profile based on quantum marker technology in a multi-lateral well located in West Siberia.\u0000 Marker systems were placed in the well during the well reconstruction by horizontal side tracking with the parent borehole remaining in production. This way of reconstruction allows development of the reservoir drainage area with a lateral hole and bringing the oil reserves from the parent borehole into production, which results in an increased flow rate and improved oil recovery rate. Placement of marker systems into parent borehole and side-track for fluid distribution monitoring allows to evaluate the flow rate from every borehole and estimate the effectiveness of performed well reconstruction.\u0000 Marker systems are placed into the parent borehole as a downhole sub installed into the well completion string. For the side-track polymer-coated marked proppant was injected during hydraulic fracturing to place markers.\u0000 The developed method was reliably used for an accurate and fast determination of the inflow distribution in a multi-lateral well which allows more efficient field development and also enabled us to provide effective solutions for following challenges:\u0000 Providing tools for timely water cut diagnostics in multilateral wells and information for water shut-off method selection; Selecting the optimal well operating mode for effective field development and premature flooding prevention in one or both boreholes; Evaluating whether well construction was performed efficiently, and an increased production rate was achieved; Leading to a considerable economic savings in capital expenditure.","PeriodicalId":10917,"journal":{"name":"Day 2 Wed, January 12, 2022","volume":"77 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-01-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90531102","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. Kayumov, A. Al Shueili, M. Jaboob, Hussain Al Salmi, R. Trejo, R.. Al Shidhani
Development of the tight gas Khazzan Field in Sultanate of Oman has progressed through an extensive learning curve over many years. Thereby, the hydraulic fracturing design was fine-tuned and optimized to properly fit the requirements of the challenging Barik reservoir in this area. In 2018, BP Oman started developing the Barik reservoir in the Ghazeer Field, which naturally extends the reservoir boundary south of Khazzan Field. However, the Barik reservoir in the Ghazeer area is thicker and more permeable than in the Khazzan Field; therefore, the hydraulic fracturing design required adjustment to be optimized to directly reflect the reservoir needs of the Ghazeer Field. A comprehensive hydraulic fracturing design software was used for this optimization study and sensitivity analysis. This software is a plug-in to a benchmark exploration and production software platform and provides a complete fracturing optimization loop from hydraulic fracturing design sensitivity modelled with a calibrated mechanical earth model to detailed production prediction using the incorporated reservoir simulator. One of the stimulated wells from Ghazeer Field was used as the reference for this study. The reservoir sector model was created and adjusted to match actual data from this well. The data include fracturing treatment execution response, surveillance data such as radioactive tracers, bottomhole pressure gauge, and pressure transient analysis. Reservoir properties were also adjusted to match long-term production data obtained for this reference well. After the reservoir model was fully validated against actual data, multiple completion and fracturing scenarios were simulated to estimate potential production gain and thus find an optimal hydraulic fracturing design for Ghazeer Field. Many valuable outcomes can be concluded from this study. The optimal treatment design was identified. The value of fracture half-length versus conductivity was clarified for this area. The comparison between single-stage fracturing versus multistage treatment across the thick laminated Barik reservoir in a conventional vertical well was derived. The drainage of different layers with variable reservoir properties was compared for a range of different scenarios.
{"title":"Finding the Best of the Best: Hydraulic Fracturing Design Optimization Study in Oman","authors":"R. Kayumov, A. Al Shueili, M. Jaboob, Hussain Al Salmi, R. Trejo, R.. Al Shidhani","doi":"10.2118/205249-ms","DOIUrl":"https://doi.org/10.2118/205249-ms","url":null,"abstract":"\u0000 Development of the tight gas Khazzan Field in Sultanate of Oman has progressed through an extensive learning curve over many years. Thereby, the hydraulic fracturing design was fine-tuned and optimized to properly fit the requirements of the challenging Barik reservoir in this area. In 2018, BP Oman started developing the Barik reservoir in the Ghazeer Field, which naturally extends the reservoir boundary south of Khazzan Field. However, the Barik reservoir in the Ghazeer area is thicker and more permeable than in the Khazzan Field; therefore, the hydraulic fracturing design required adjustment to be optimized to directly reflect the reservoir needs of the Ghazeer Field.\u0000 A comprehensive hydraulic fracturing design software was used for this optimization study and sensitivity analysis. This software is a plug-in to a benchmark exploration and production software platform and provides a complete fracturing optimization loop from hydraulic fracturing design sensitivity modelled with a calibrated mechanical earth model to detailed production prediction using the incorporated reservoir simulator. One of the stimulated wells from Ghazeer Field was used as the reference for this study. The reservoir sector model was created and adjusted to match actual data from this well. The data include fracturing treatment execution response, surveillance data such as radioactive tracers, bottomhole pressure gauge, and pressure transient analysis. Reservoir properties were also adjusted to match long-term production data obtained for this reference well. After the reservoir model was fully validated against actual data, multiple completion and fracturing scenarios were simulated to estimate potential production gain and thus find an optimal hydraulic fracturing design for Ghazeer Field.\u0000 Many valuable outcomes can be concluded from this study. The optimal treatment design was identified. The value of fracture half-length versus conductivity was clarified for this area. The comparison between single-stage fracturing versus multistage treatment across the thick laminated Barik reservoir in a conventional vertical well was derived. The drainage of different layers with variable reservoir properties was compared for a range of different scenarios.","PeriodicalId":10917,"journal":{"name":"Day 2 Wed, January 12, 2022","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-01-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83130205","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
J. Franquet, V. Telang, Hayat Abdi Ibrahim Jibar, K. Khan
The scope of this work is to measure downhole fracture-initiation pressures in multiple carbonate reservoirs located onshore about 50 km from Abu Dhabi city. The objective of characterizing formation breakdown across several reservoirs is to quantify the maximum gas and CO2 injection capacity on each reservoir layer for pressure maintenance and enhance oil recovery operations. This study also acquires pore pressure and fracture closure pressure measurements for calibrating the geomechanical in-situ stress model and far-field lateral strain boundary conditions. Several single-probe pressure drawdown and straddle packer microfrac injection tests provide accurate downhole measurements of reservoir pore pressure, fracture initiation, reopening and fracture closure pressures. These tests are achieved using a wireline or pipe-conveyed straddle packer logging tool capable to isolate 3 feet of openhole formation in a vertical pilot hole across five Lower Cretaceous carbonate reservoirs zones. The fracture closure pressures are obtained from three decline methods during the pressure fall-off after fracture propagation injection cycle. The three methods are: (1) square-root of the shut-in time, (2) G-Function pressure derivative, and (3) Log-Log pressure derivative. The far-field strain values are estimated by multi-variable regression from the microfrac test data and the core-calibrated static elastic properties of the formations where the stress tests are done. The reservoir pressure across these carbonate formations are between 0.48 to 0.5 psi/ft with a value repeatability of 0.05 psi among build-up tests and 0.05 psi/min of pressure stability. The formation breakdown pressures are obtained between 0.97 and 1.12 psi/ft over 5,500 psi above hydrostatic pressure. The in-situ fracture closure measurements provide the magnitude of the minimum horizontal stress 0.74 - 0.83 psi/ft which is used to back-calculate the lateral strain values (0.15 and 0.72 mStrain) as far-field boundary condition for subsequent geomechanical modeling. These measurements provide critical subsurface information to accurately predict wellbore stability, hydraulic fracture containment and CO2 injection capacity for effective enhance oil recovery within these reservoirs. This in-situ stress wellbore data represents the first of its kind in the field allowing petroleum and reservoir engineers to optimize the subsurface injection plans for efficient field developing.
{"title":"Multiple In-Situ Stress Measurements in Carbonate Reservoirs for CO2 Injection Capability Assessment and Far-Field Strain Calibrations","authors":"J. Franquet, V. Telang, Hayat Abdi Ibrahim Jibar, K. Khan","doi":"10.2118/205261-ms","DOIUrl":"https://doi.org/10.2118/205261-ms","url":null,"abstract":"\u0000 The scope of this work is to measure downhole fracture-initiation pressures in multiple carbonate reservoirs located onshore about 50 km from Abu Dhabi city. The objective of characterizing formation breakdown across several reservoirs is to quantify the maximum gas and CO2 injection capacity on each reservoir layer for pressure maintenance and enhance oil recovery operations. This study also acquires pore pressure and fracture closure pressure measurements for calibrating the geomechanical in-situ stress model and far-field lateral strain boundary conditions.\u0000 Several single-probe pressure drawdown and straddle packer microfrac injection tests provide accurate downhole measurements of reservoir pore pressure, fracture initiation, reopening and fracture closure pressures. These tests are achieved using a wireline or pipe-conveyed straddle packer logging tool capable to isolate 3 feet of openhole formation in a vertical pilot hole across five Lower Cretaceous carbonate reservoirs zones. The fracture closure pressures are obtained from three decline methods during the pressure fall-off after fracture propagation injection cycle. The three methods are: (1) square-root of the shut-in time, (2) G-Function pressure derivative, and (3) Log-Log pressure derivative. The far-field strain values are estimated by multi-variable regression from the microfrac test data and the core-calibrated static elastic properties of the formations where the stress tests are done.\u0000 The reservoir pressure across these carbonate formations are between 0.48 to 0.5 psi/ft with a value repeatability of 0.05 psi among build-up tests and 0.05 psi/min of pressure stability. The formation breakdown pressures are obtained between 0.97 and 1.12 psi/ft over 5,500 psi above hydrostatic pressure. The in-situ fracture closure measurements provide the magnitude of the minimum horizontal stress 0.74 - 0.83 psi/ft which is used to back-calculate the lateral strain values (0.15 and 0.72 mStrain) as far-field boundary condition for subsequent geomechanical modeling.\u0000 These measurements provide critical subsurface information to accurately predict wellbore stability, hydraulic fracture containment and CO2 injection capacity for effective enhance oil recovery within these reservoirs. This in-situ stress wellbore data represents the first of its kind in the field allowing petroleum and reservoir engineers to optimize the subsurface injection plans for efficient field developing.","PeriodicalId":10917,"journal":{"name":"Day 2 Wed, January 12, 2022","volume":"38 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-01-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82047210","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. Thomson, Baglan Kiyabayev, Barry Ritchie, Jakob Monberg, Maurits De Heer, Soren Skov List
The Valdemar field, located in the Danish sector of the North Sea, targets a Lower Cretaceous, "dirty chalk" reservoir characterized by low permeabilities of <0.5mD, high porosities of >20% and contains up to 25% insoluble fines. To produce economically the reservoir must be stimulated. Typically, this is by means of hydraulic fracturing. A traditional propped fracture consists of 500,000 to 1,000,000 lbs of 20/40 sand, placed using a crosslinked seawater-based borate fluid. The existing wells in the field are completed using the PSI (perforate, isolate, stimulate)1 system. This system was developed in the late 1980s as a way of improving completion times allowing each interval to be perforated, stimulated and isolated in a single trip and has been used extensively in the Danish North Sea in a variety of fields. The system consists of multiset packers with sliding sleeves and typically takes 2-3 days between the start of one fracture to the next. Future developments in this area now require a new, novel and more efficient approach owing to new target reservoir being of a thinner and poorer quality. In order for these new developments to be economical an approach was required to allow for longer wells to be drilled and completed allowing better reservoir connectivity whilst at the same time reducing the completion time, and therefore rig time and overall cost. A project team was put together to develop a system that could be used in an offshore environment that would satisfy the above criteria, allowing wells to be drilled out to 21,000ft and beyond in excess of coiled tubing reach. The technology developed consists of cemented frac sleeves, operated with jointed pipe, allowing multiple zones to be stimulated in one trip, as well as utilizing a modified BHA that allows for the treatments to take place through the tubing, bringing numerous benefits. The following paper details the reasons for developing the new technology, the development process itself, the challenges that had to be overcome and a case history on the execution of the first job of its kind in the North Sea, in which over 7MM lbs of sand was pumped successfully, as well as the post treatment operations which included a proof of concept in utilizing a tractor to manipulate the sleeves. Finally, the production performance will be discussed supported by the use of tracer subs at each of the zones.
{"title":"Worlds First Offshore Horizontal Well Using Jointed Pipe Cemented Frac Sleeve Technology","authors":"S. Thomson, Baglan Kiyabayev, Barry Ritchie, Jakob Monberg, Maurits De Heer, Soren Skov List","doi":"10.2118/205331-ms","DOIUrl":"https://doi.org/10.2118/205331-ms","url":null,"abstract":"\u0000 The Valdemar field, located in the Danish sector of the North Sea, targets a Lower Cretaceous, \"dirty chalk\" reservoir characterized by low permeabilities of <0.5mD, high porosities of >20% and contains up to 25% insoluble fines. To produce economically the reservoir must be stimulated. Typically, this is by means of hydraulic fracturing. A traditional propped fracture consists of 500,000 to 1,000,000 lbs of 20/40 sand, placed using a crosslinked seawater-based borate fluid. The existing wells in the field are completed using the PSI (perforate, isolate, stimulate)1 system. This system was developed in the late 1980s as a way of improving completion times allowing each interval to be perforated, stimulated and isolated in a single trip and has been used extensively in the Danish North Sea in a variety of fields. The system consists of multiset packers with sliding sleeves and typically takes 2-3 days between the start of one fracture to the next.\u0000 Future developments in this area now require a new, novel and more efficient approach owing to new target reservoir being of a thinner and poorer quality. In order for these new developments to be economical an approach was required to allow for longer wells to be drilled and completed allowing better reservoir connectivity whilst at the same time reducing the completion time, and therefore rig time and overall cost.\u0000 A project team was put together to develop a system that could be used in an offshore environment that would satisfy the above criteria, allowing wells to be drilled out to 21,000ft and beyond in excess of coiled tubing reach. The technology developed consists of cemented frac sleeves, operated with jointed pipe, allowing multiple zones to be stimulated in one trip, as well as utilizing a modified BHA that allows for the treatments to take place through the tubing, bringing numerous benefits.\u0000 The following paper details the reasons for developing the new technology, the development process itself, the challenges that had to be overcome and a case history on the execution of the first job of its kind in the North Sea, in which over 7MM lbs of sand was pumped successfully, as well as the post treatment operations which included a proof of concept in utilizing a tractor to manipulate the sleeves. Finally, the production performance will be discussed supported by the use of tracer subs at each of the zones.","PeriodicalId":10917,"journal":{"name":"Day 2 Wed, January 12, 2022","volume":"37 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-01-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90116642","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}
Erfan M. Al Lawe, Adnan Humaidan, A. Amodu, M. Parker, Oscar Alvarado, Amine Abdenbi
Zubair formation in West Qurna field, is one of the largest prolific reservoirs comprising of oil bearing sandstone layers interbedded with shale sequences. An average productivity index of 6 STB/D/psi is observed without any types of stimulation treatment. As the reservoir pressure declines from production, a peripheral water injection strategy was planned in both flanks of the reservoir to enhance the existing wells production deliverability. The peripheral injection program was initiated by drilling several injectors in the west flank. Well A1 was the first injector drilled and its reservoir pressure indicated good communication with the up-dip production wells. An injection test was conducted, revealing an estimated injectivity index of 0.06 STB//D/psi. Candidate well was then re-perforated and stimulated with HF/HCl mud acid, however no significant improvement in injectivity was observed due to the complex reservoir mineralogy and heterogeneity associated to the different targeted layers. An extended high-pressure injection test was performed achieving an injectivity index of 0.29 STB/D/psi at 4500 psi. As this performance was sub-optimal, a proppant fracture was proposed to achieve an optimal injection rate. A reservoir-centric fracture model was built, using the petrophysical and geo-mechanical properties from the Zubair formation, with the objective of optimizing the perforation cluster, fracture placement and injectivity performance. A wellhead isolation tool was utilized as wellhead rating was not able to withstand the fracture model surface pressure; downhole gauges were also installed to provide an accurate analysis of the pressure trends. The job commenced with a brine injection test to determine the base-line injectivity profile. The tubing volume was then displaced with a linear gel to perform a step-rate / step-down test. The analysis of the step-rate test revealed the fracture extension pressure, which was set as the maximum allowable injection pressure when the well is put on continuous injection. The step-down test showed significant near wellbore tortuosity with negligible perforation friction. A fracture fluid calibration test was then performed to validate the integrated model leak-off profile, fracture gradient and young’s modulus; via a coupled pressure fall-off and temperature log analysis. Based on the fluid efficiency, the pad volume was adjusted to achieve a tip screen-out. The job was successfully pumped and tip screen-out was achieved after pumping over ~90% of the planned proppant volume. A 7 days post-frac extended injection test was then conducted, achieving an injection rate of 12.5 KBWD at 1300 psi with an injectivity index of 4.2 STB/D/psi. These results proved that the implementation of a reservoir-centric Proppant Fracture treatment, can drastically improve the water injection strategy and field deliverability performance even in good quality rock formations. This first integrated fracture model and wate
West Qurna油田的Zubair组是最大的多产油藏之一，由含油砂岩层与页岩层序互层组成。在不进行任何增产处理的情况下，平均产能指数为6 STB/D/psi。随着油藏生产压力的下降，为了提高现有油井的产能，在油藏两侧规划了外围注水策略。外围注入计划是通过在西侧钻几个注入器来启动的。A1井是第一口注入井，其储层压力与上倾生产井具有良好的沟通。进行了注入测试，估计注入指数为0.06 STB//D/psi。然后，对候选井进行重新射孔并使用HF/HCl泥浆酸进行增产，但由于不同目标层的油藏矿物学和非均质性的复杂性，没有观察到注入能力的显著改善。进行了扩展的高压注入测试，在4500psi下，注入指数达到0.29 STB/D/psi。由于该性能不是最优的，因此建议进行支撑剂压裂以获得最佳注入速率。利用Zubair地层的岩石物理和地球力学特性，建立了以储层为中心的裂缝模型，目的是优化射孔簇、裂缝布置和注入性能。由于井口等级无法承受裂缝模型的地面压力，因此使用了井口隔离工具;还安装了井下仪表，以提供准确的压力趋势分析。作业开始时进行了盐水注入测试，以确定基线注入能力剖面。然后用线性凝胶置换油管体积，进行阶梯速率/降压测试。通过对步进速率试验的分析，确定了连续注入时的最大允许注入压力为裂缝扩展压力。降压测试显示了显著的近井弯曲，射孔摩擦可以忽略不计。然后进行压裂液校准测试，以验证综合模型的泄漏剖面、裂缝梯度和杨氏模量;通过耦合压力下降和温度测井分析。根据流体效率，调整垫的体积，以实现尖端筛出。该作业成功泵送，在泵送超过计划支撑剂体积的90%后，实现了尖端筛出。然后进行了压裂后7天的延长注入测试，在1300 psi下实现了12.5 KBWD的注入速率，注入能力指数为4.2 STB/D/psi。这些结果证明，即使在质量良好的岩层中，实施以储层为中心的支撑剂压裂处理也可以大大改善注水策略和现场产能性能。这是第一个综合裂缝模型和注水油田策略，为伊拉克南部进一步的油田开发优化计划提供了一个平台。
{"title":"First Successful Proppant Frac in a Water Injection Field Strategy, West Qurna-1, South Iraq","authors":"Erfan M. Al Lawe, Adnan Humaidan, A. Amodu, M. Parker, Oscar Alvarado, Amine Abdenbi","doi":"10.2118/205240-ms","DOIUrl":"https://doi.org/10.2118/205240-ms","url":null,"abstract":"\u0000 Zubair formation in West Qurna field, is one of the largest prolific reservoirs comprising of oil bearing sandstone layers interbedded with shale sequences. An average productivity index of 6 STB/D/psi is observed without any types of stimulation treatment. As the reservoir pressure declines from production, a peripheral water injection strategy was planned in both flanks of the reservoir to enhance the existing wells production deliverability.\u0000 The peripheral injection program was initiated by drilling several injectors in the west flank. Well A1 was the first injector drilled and its reservoir pressure indicated good communication with the up-dip production wells. An injection test was conducted, revealing an estimated injectivity index of 0.06 STB//D/psi. Candidate well was then re-perforated and stimulated with HF/HCl mud acid, however no significant improvement in injectivity was observed due to the complex reservoir mineralogy and heterogeneity associated to the different targeted layers. An extended high-pressure injection test was performed achieving an injectivity index of 0.29 STB/D/psi at 4500 psi. As this performance was sub-optimal, a proppant fracture was proposed to achieve an optimal injection rate.\u0000 A reservoir-centric fracture model was built, using the petrophysical and geo-mechanical properties from the Zubair formation, with the objective of optimizing the perforation cluster, fracture placement and injectivity performance. A wellhead isolation tool was utilized as wellhead rating was not able to withstand the fracture model surface pressure; downhole gauges were also installed to provide an accurate analysis of the pressure trends. The job commenced with a brine injection test to determine the base-line injectivity profile. The tubing volume was then displaced with a linear gel to perform a step-rate / step-down test. The analysis of the step-rate test revealed the fracture extension pressure, which was set as the maximum allowable injection pressure when the well is put on continuous injection. The step-down test showed significant near wellbore tortuosity with negligible perforation friction. A fracture fluid calibration test was then performed to validate the integrated model leak-off profile, fracture gradient and young’s modulus; via a coupled pressure fall-off and temperature log analysis. Based on the fluid efficiency, the pad volume was adjusted to achieve a tip screen-out. The job was successfully pumped and tip screen-out was achieved after pumping over ~90% of the planned proppant volume.\u0000 A 7 days post-frac extended injection test was then conducted, achieving an injection rate of 12.5 KBWD at 1300 psi with an injectivity index of 4.2 STB/D/psi. These results proved that the implementation of a reservoir-centric Proppant Fracture treatment, can drastically improve the water injection strategy and field deliverability performance even in good quality rock formations. This first integrated fracture model and wate","PeriodicalId":10917,"journal":{"name":"Day 2 Wed, January 12, 2022","volume":"102 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-01-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82690030","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. Veeken, Yousuf Busaidi, A. Hajri, Ahmed Mohammed Hegazy, Hamyar Riyami, M. Rashdi, Mohammed Zarafi, M. Zadjali, Kumaresh Darga, Mazen Mamari
PDO operates about 200 deep gas wells in the X field in the Sultanate of Oman, producing commingled from the Barik gas-condensate and Miqrat lean gas reservoir completed by multiple hydraulic fracturing. Their inflow performance relation (IPR) is tracked to diagnose condensate damage, hydraulic fracture cleanup and differential reservoir pressure depletion. The best IPR data is collected through multi-rate production logging but surface production data serves as an alternative. This paper describes the process of deriving IPR's from production logging and surface production data, and then evaluates 20 years of historic IPR data to quantify the impact of condensate damage and condensate cleanup with progressive reservoir pressure depletion, to demonstrate the massive damage and slow cleanup of hydraulic fractures placed in depleted reservoirs, to show how hydraulic fractures facilitate the vertical cross-flow between isolated reservoir intervals, and to highlight that stress-dependent permeability does not play a major role in this field.
{"title":"Track Fractured Well Inflow Performance Using Historic Production Logging and Surface Well Performance Data in Sultanate of Oman","authors":"C. Veeken, Yousuf Busaidi, A. Hajri, Ahmed Mohammed Hegazy, Hamyar Riyami, M. Rashdi, Mohammed Zarafi, M. Zadjali, Kumaresh Darga, Mazen Mamari","doi":"10.2118/205279-ms","DOIUrl":"https://doi.org/10.2118/205279-ms","url":null,"abstract":"\u0000 PDO operates about 200 deep gas wells in the X field in the Sultanate of Oman, producing commingled from the Barik gas-condensate and Miqrat lean gas reservoir completed by multiple hydraulic fracturing. Their inflow performance relation (IPR) is tracked to diagnose condensate damage, hydraulic fracture cleanup and differential reservoir pressure depletion. The best IPR data is collected through multi-rate production logging but surface production data serves as an alternative. This paper describes the process of deriving IPR's from production logging and surface production data, and then evaluates 20 years of historic IPR data to quantify the impact of condensate damage and condensate cleanup with progressive reservoir pressure depletion, to demonstrate the massive damage and slow cleanup of hydraulic fractures placed in depleted reservoirs, to show how hydraulic fractures facilitate the vertical cross-flow between isolated reservoir intervals, and to highlight that stress-dependent permeability does not play a major role in this field.","PeriodicalId":10917,"journal":{"name":"Day 2 Wed, January 12, 2022","volume":"29 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-01-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74551650","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}
A. Gandomkar, D. Katz, Ricardo Gomez, Anders H. Gundersen, Parvez Khan
Casing Deformation has plagued numerous unconventional basins globally, in particular with plug-and-perforation (also known as plug-and-perf) operations. This infamous issue can greatly influence 20-30% of field productivity of horizontal wells in shale and tight oil fields (Jacobs, 2020). When a wellbore lies in a target zone and intersects many natural fractures, these fractures are perturbed by hydraulic stimulation. Therefore, rock or bedding slippage may occur, resulting in casing deformation. This phenomenon is escalated by active tectonics, high anisotropic in-situ stresses, and poor cement design. This paper evaluates the mechanisms of casing deformation. It reviews how these conditions can be evaluated in the target zone. The mitigation procedures to reduce casing deformation through either well planning or completions design are discussed. Finally, an alternative completion method to plug-and-perf allowing limited entry completion technique in restricted casing with a field case study will be discussed.
{"title":"Casing Deformation Mitigation Achieved Through Ball Activated Sliding Fracturing Sleeves – An Alternative to Plug and Perf Fracturing Operations","authors":"A. Gandomkar, D. Katz, Ricardo Gomez, Anders H. Gundersen, Parvez Khan","doi":"10.2118/205264-ms","DOIUrl":"https://doi.org/10.2118/205264-ms","url":null,"abstract":"\u0000 Casing Deformation has plagued numerous unconventional basins globally, in particular with plug-and-perforation (also known as plug-and-perf) operations. This infamous issue can greatly influence 20-30% of field productivity of horizontal wells in shale and tight oil fields (Jacobs, 2020). When a wellbore lies in a target zone and intersects many natural fractures, these fractures are perturbed by hydraulic stimulation. Therefore, rock or bedding slippage may occur, resulting in casing deformation. This phenomenon is escalated by active tectonics, high anisotropic in-situ stresses, and poor cement design.\u0000 This paper evaluates the mechanisms of casing deformation. It reviews how these conditions can be evaluated in the target zone. The mitigation procedures to reduce casing deformation through either well planning or completions design are discussed. Finally, an alternative completion method to plug-and-perf allowing limited entry completion technique in restricted casing with a field case study will be discussed.","PeriodicalId":10917,"journal":{"name":"Day 2 Wed, January 12, 2022","volume":"68 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-01-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89312693","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}
Due to the increases in completion costs demand for production improvements, fracturing through double casing in upper reservoirs for mature wells and refracturing early stimulated wells to change the completion design, has become more and more popular. One of the most common technologies used to re-stimulate previously fracked wells, is to run a second, smaller casing or tubular inside of the existing and already perforated pipes of the completed well. The new inner and old outer casing are isolated from each other by a cement layer, which prevents any hydraulic communication between the pre-existing and new perforations, as well as between adjacent new perforations. For these smaller inner casing diameters, specially tailored and designed re-fracturing perforation systems are deployed, which can shoot casing entrance holes of very similar size through both casings, nearly independent of the phasing and still capable of creating tunnels reaching beyond the cement layer into the natural rock formation. Although discussing on the API RP-19B section VII test format has recently been initiated and many companies have started to test multiple casing scenarios and charge performance, not much is known about the complex flow through two radially aligned holes in dual casings. In the paper we will look in detail at the parameters which influence the flow, especially the Coefficient of Discharge of such a dual casing setup. We will evaluate how much the near wellbore pressure drop is affected by the hole's sizes in the first and second casing, respectively the difference between them and investigate how the cement layer is influenced by turbulences, which might build up in the annulus. The results will enhance the design and provide a better understanding of fracturing or refracturing through double casings for hydraulic fracturing specialists and both operation and services companies.
{"title":"Determination of the Near-Wellbore Pressure Drop for Dual Casing in Hydraulic Fracturing and Refracturing Applications","authors":"J. Loehken, D. Yosefnejad, L. Mcnelis, B. Fricke","doi":"10.2118/205234-ms","DOIUrl":"https://doi.org/10.2118/205234-ms","url":null,"abstract":"\u0000 Due to the increases in completion costs demand for production improvements, fracturing through double casing in upper reservoirs for mature wells and refracturing early stimulated wells to change the completion design, has become more and more popular. One of the most common technologies used to re-stimulate previously fracked wells, is to run a second, smaller casing or tubular inside of the existing and already perforated pipes of the completed well. The new inner and old outer casing are isolated from each other by a cement layer, which prevents any hydraulic communication between the pre-existing and new perforations, as well as between adjacent new perforations.\u0000 For these smaller inner casing diameters, specially tailored and designed re-fracturing perforation systems are deployed, which can shoot casing entrance holes of very similar size through both casings, nearly independent of the phasing and still capable of creating tunnels reaching beyond the cement layer into the natural rock formation.\u0000 Although discussing on the API RP-19B section VII test format has recently been initiated and many companies have started to test multiple casing scenarios and charge performance, not much is known about the complex flow through two radially aligned holes in dual casings.\u0000 In the paper we will look in detail at the parameters which influence the flow, especially the Coefficient of Discharge of such a dual casing setup. We will evaluate how much the near wellbore pressure drop is affected by the hole's sizes in the first and second casing, respectively the difference between them and investigate how the cement layer is influenced by turbulences, which might build up in the annulus.\u0000 The results will enhance the design and provide a better understanding of fracturing or refracturing through double casings for hydraulic fracturing specialists and both operation and services companies.","PeriodicalId":10917,"journal":{"name":"Day 2 Wed, January 12, 2022","volume":"32 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-01-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81243799","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This paper focuses on optimizing future well landing zones and their corresponding hydraulic fracture treatments in the Eagle Ford shale play. The optimum landing zone and stimulation treatment were determined by analyzing multiple landing zone options, including the lower Austin Chalk, Eagle Ford, and Pepper Shale, with several hydraulic fracturing treatment possibilities. Fracturing fluids and their volume, proppant size, and cluster spacing were investigated to determine the optimum hydraulic fracturing treatment for the subject geologic area. Ranges of 75,000 to 300,000 gallons of pure gel, pure slickwater, and hybrid fracturing fluids along with 20/40, 30/50, 40/70, and 100 mesh proppant were tested. Cluster spacing of twenty feet to eighty feet were also sensitized in this study. A fully three-dimensional hydraulic fracture modeling software was used to develop a geological and geomechanical model of the studied area. The generated model was calibrated with available field data to ensure that the model reflects the area's geological and geomechanical characteristics. The developed model was used to create fracture results for each sensitized parameter. Production analysis was performed for all fracture models to determine the optimum landing zone and fracturing treatment implications. The study shows that the Eagle Ford had better production than the lower Austin Chalk in the subject area. The Pepper Shale had the highest potential hydrocarbon production, around 326 Mbbl cumulative, when fractured with a pure gel treatment. The analyses showed that a hybrid treatment with 70% gel and 30% slickwater yielded the optimum production due to the treatment economics even though the highest production was obtained using the pure gel. Treating the formation with larger proppant provided better production than smaller proppant due to conductivity concerns associated with damaging mechanisms in the studied area. Since increasing the volume above 175,000 gallons caused a negligible increase in the production, 175,000 gallons of fracturing fluid per stage appeared to be the optimum fracturing fluid volume. Thirty-foot cluster spacing was the optimum spacing in the study area. Overall, the study suggests that oil production can be improved in the Eagle Ford study area through a detailed workflow development and optimization process. The hydraulic fracture treatment and landing zone optimization workflow ensures optimum hydrocarbon extraction from the study area. The developed workflow can be applied to new unconventional plays instead of using trial and error methods.
{"title":"Hydraulic Fracture Treatment and Landing Zone Interval Optimization: An Eagle Ford Case Study","authors":"Abdulrahim K. Al Mulhim, J. Miskimins, A. Tura","doi":"10.2118/205257-ms","DOIUrl":"https://doi.org/10.2118/205257-ms","url":null,"abstract":"\u0000 This paper focuses on optimizing future well landing zones and their corresponding hydraulic fracture treatments in the Eagle Ford shale play. The optimum landing zone and stimulation treatment were determined by analyzing multiple landing zone options, including the lower Austin Chalk, Eagle Ford, and Pepper Shale, with several hydraulic fracturing treatment possibilities. Fracturing fluids and their volume, proppant size, and cluster spacing were investigated to determine the optimum hydraulic fracturing treatment for the subject geologic area. Ranges of 75,000 to 300,000 gallons of pure gel, pure slickwater, and hybrid fracturing fluids along with 20/40, 30/50, 40/70, and 100 mesh proppant were tested. Cluster spacing of twenty feet to eighty feet were also sensitized in this study.\u0000 A fully three-dimensional hydraulic fracture modeling software was used to develop a geological and geomechanical model of the studied area. The generated model was calibrated with available field data to ensure that the model reflects the area's geological and geomechanical characteristics. The developed model was used to create fracture results for each sensitized parameter. Production analysis was performed for all fracture models to determine the optimum landing zone and fracturing treatment implications.\u0000 The study shows that the Eagle Ford had better production than the lower Austin Chalk in the subject area. The Pepper Shale had the highest potential hydrocarbon production, around 326 Mbbl cumulative, when fractured with a pure gel treatment. The analyses showed that a hybrid treatment with 70% gel and 30% slickwater yielded the optimum production due to the treatment economics even though the highest production was obtained using the pure gel. Treating the formation with larger proppant provided better production than smaller proppant due to conductivity concerns associated with damaging mechanisms in the studied area. Since increasing the volume above 175,000 gallons caused a negligible increase in the production, 175,000 gallons of fracturing fluid per stage appeared to be the optimum fracturing fluid volume. Thirty-foot cluster spacing was the optimum spacing in the study area. Overall, the study suggests that oil production can be improved in the Eagle Ford study area through a detailed workflow development and optimization process.\u0000 The hydraulic fracture treatment and landing zone optimization workflow ensures optimum hydrocarbon extraction from the study area. The developed workflow can be applied to new unconventional plays instead of using trial and error methods.","PeriodicalId":10917,"journal":{"name":"Day 2 Wed, January 12, 2022","volume":"56 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-01-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81867853","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
京公网安备 11010802042870号
京ICP备2023020795号-1
扫码关注我们
求助内容：
应助结果提醒方式：