Day 3 Thu, October 18, 2018最新文献

{"title":"Development Strategy Optimization of Ning201 Block Longmaxi Shale Gas","authors":"Rui Yong, Jian-fa Wu, Xuewen Shi, Xiangqi Zhuang, Heng Wen, Yin Luo","doi":"10.2118/191452-18IHFT-MS","DOIUrl":"https://doi.org/10.2118/191452-18IHFT-MS","url":null,"abstract":"Changning National Shale Gas Demonstration Area was established in 2012. Field Development of its Ning201 shale gas fields was geared up in 2014. By 2015, Changning area accomplished the construction of 15×108 m3/a production capacity. During early appraisal phase before 2014, average testing results of wells were 10~15×104 m3/d. In the end of 2016 and early 2017, average testing results of large numbers of wells across multiple pads achieved over 25×104 m3/d. Overall testing results of some pads have exceeded 180×104 m3/d per pad, and some of them may exceed 180×104 m3/d per pad in soon future. Through implementing geo-engineering integration, efficiency and effectiveness of field development have been steadily enhanced. This paper reviews our practices to establish and rapidly evolve the learning curve in this national demonstration area through geoengineering integration. Benefiting from geo-engineering integrated study, development options were systematically, proactively and effectively supported throughout the process of field development. Per the evolving understanding of reservoir and engineering challenges, adaptive technology and engineering solutions were exploited and optimized. A new geo-engineering model has been proposed which covers engineering applications of drilling, completion, production and development. Based on our gathered knowledge and experience, key contributing factors for marine shale gas development in Sichuan basin were thoroughly studied and summarized. They may include controlling factors of productivity, optimum production scheme, optimized well spacing, and so on. This paper also points out key areas for further improvement and enhancement in future.","PeriodicalId":397259,"journal":{"name":"Day 3 Thu, October 18, 2018","volume":"37 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-10-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131627202","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}

{"title":"An Integrated Analytics Platform for Completion Optimization and Reservoir Characterization","authors":"Junjie Yang, S. Stolyarov, E. Cazeneuve, Jason D Simmons, S. Kotov, David Gadzhimizaev","doi":"10.2118/191459-18ihft-ms","DOIUrl":"https://doi.org/10.2118/191459-18ihft-ms","url":null,"abstract":"\u0000 As laterals become longer with more stages, large datasets make evaluation of the information complicated and time consuming. Variations in the obtained data adds more uncertainty to the main industry challenges and questions, such as optimal well spacing, optimal completion (e.g., type of completion, stage and cluster spacing), optimal stimulation treatment (e.g., proppant type, mass and concentration, fluid type, volume and composition).\u0000 This paper describes a novel automated framework for completion optimization and post-fracture analysis. For pre-fracture analysis, this framework utilizes an integrated dataset from drilling and wireline logs, and automatically places clusters based on heterogeneity along the lateral. This information is then coupled with post-fracture data to examine fracture treating information (breakdown pressure, instantaneous shut in pressure, etc.) and correlate it to rock properties from each fracture stage. The newly identified correlation is looped back into the framework as a guideline for future frac design.\u0000 The strong correlation between subsurface rock properties and hydraulic fracture treatment parameters suggests that the previous captured heterogeneity reveals the fracture design efficiency, and the multivariable evaluation process can be accelerated by the machine learning platform. A statistical model was built on geomechanical and petrophysical properties used to design fracture treatments. Meanwhile, the platform automatically evaluates fracture treating signatures (surface treating pressure, pumping rate, ISIP, etc.) and links them with subsurface information for each stage. When the model is trained with a sufficient amount of data, it can be used as a real-time advisor that suggests a fracture treatment schedule (pump rate, sand concentration, fluid volume). The fracture geometry as well as the treatment efficiency can be optimized with the enhanced design. The model can eliminate or reduce the need for expensive subsurface characterization logging tools and provide quick recommendations for changes to the treatment.\u0000 This paper introduces an integrated solution to optimize fracture treatment design assisted by data analytics that can be further improved to solve other multivariable problems in the oil and gas industry.","PeriodicalId":397259,"journal":{"name":"Day 3 Thu, October 18, 2018","volume":"40 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-10-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130267911","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}

{"title":"Investigation of Multiple Hydraulic Fracture Propagation for Low-Pressure Tight Sandstone Reservoirs in Northern Ordos Basin of Changqing Oilfield, China","authors":"Jizhou Tang, C. Ehlig-Economides, Jiawei Li, Xuyang Guo, Kan Wu, L. Mu, M. Tang, Xianfei Du","doi":"10.2118/191454-18IHFT-MS","DOIUrl":"https://doi.org/10.2118/191454-18IHFT-MS","url":null,"abstract":"\u0000 Giant Ordos basin, located in the northern China, consists of Palaeozoic lacustrine stacked sandstone and shale deposits characterized by low-pressure, low-porosity, low permeability matrix rock and a poorly developed natural fractures (NFs) system. Recognizing the successful exploration of shale gas reservoirs in United States, Changqing oilfield primarily uses three fracturing technologies, hydraulic sandblasting technology, open-hole packer technology and drillable bridge plugging technology, to create multiple straight hydraulic fractures (HFs) in tight sandstone zones with large differential horizontal stress. For this study we consider multiple perforation clusters per stage using the drillable bridge plugging technology, which offers benefits of large injection rate and high treatment efficiency. This paper describes a hydraulic fracture propagation model (HFPM) that couples fracture deformation and fluid flow to simulate the growth of multiple HFs in the horizontal wellbore. We then integrated an embedded discrete fracture model (EDFM) and commercial reservoir simulator to analyze production prediction based on the provided data from Changqing oilfield. We calibrated the fracture propagation model with the reservoir performance data and demonstrated how to optimize the fracture treatment. The low formation pressure gradient in the Changqing oilfield impairs the production performance. To reduce the rapid decline rate in reservoir pressure, the fracturing fluid is not only used for creating fractures, but also enhancing the pore pressure by leaking off into the formation. Adjusting the pumping rate and fluid volume enables our model to increase the formation pressure gradient. Moreover, the tight sandstone deposits in the Changqing oilfield have a relatively high brittleness index (BI) and large differential horizontal stress. This is the reason why reservoir with sparse NFs in the Ordos basin has less opportunity of generating complex fracture networks. Large-scale physical simulation experiments were also conducted to validate the possibility of fracture networks generation. Our model accouts for the stress heterogeneity and offers the capability to address HF propagation in the presence of sparsely distributed NFs and adjusts the dimensions and spacing of the NFs to achieve a history match with production data. This paper emphasizes the extensive application of a fracture propagation model for lacustrine tight sandstone deposits. Considering features of Ordos basin, such as low-pressure gradient and relatively high BI, our model can provide a guideline for HF treatment design and optimization of well performance.","PeriodicalId":397259,"journal":{"name":"Day 3 Thu, October 18, 2018","volume":"25 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-10-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126999179","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}

{"title":"Optimizing Drawdown Strategies in Wells Producing from Complex Fracture Networks","authors":"Ashish Kumar, P. Seth, Kaustubh Shrivastava, M. Sharma","doi":"10.2118/191419-18IHFT-MS","DOIUrl":"https://doi.org/10.2118/191419-18IHFT-MS","url":null,"abstract":"\u0000 In unconventional reservoirs, the presence of natural fractures coupled with high pore pressures leads to the creation of complex fracture networks. During drawdown, the fracture network experiences large changes in the stresses which can affect the fracture conductivity, and hence the production rate. We present a workflow to find an optimum drawdown strategy in which the fractures can remain conductive while maintaining a high enough drawdown to maximize production.\u0000 A fully coupled geomechanical reservoir simulator is developed to simulate production from complex fracture networks. Flow in the fracture and reservoir domains is solved in two separate conforming meshes which are coupled through matrix-fracture transfer indices. The complex fracture network is represented as an explicit discontinuity in the reservoir domain which is essential to capture the stress variations in the vicinity of the fractures due to reservoir depletion and fracture closure. The fracture closure process is modeled dynamically using the Barton-Bandis contact relationship, and the fracture conductivity is determined using the fracture width and proppant concentration. This model is used to study the impact of drawdown strategy on fracture conductivity and well productivity.\u0000 It is observed that the estimated ultimate recovery (EUR) from complex fracture networks depends upon the connected fracture conductivity and the applied drawdown. A conservative drawdown strategy maintains the fracture conductivity for a longer period but results in a lower initial production rate. As the drawdown is increased, the unpropped fractures close and can cause a large portion of the fracture network (the part behind the closed segment) to get disconnected from the wellbore. This reduces the available fracture area for production. Although an aggressive drawdown strategy results in higher initial production rates, it can lead to faster fracture closure, in turn resulting in a lower EUR. Impact of drawdown strategy on productivity is analyzed at different fracture closure rates.\u0000 We show that the optimum choke management strategy depends on the sensitivity of the fracture conductivity to stress. A coupled geomechanical reservoir model is presented that can simulate production with dynamic fracture closure in complex fracture networks to quantify this effect.","PeriodicalId":397259,"journal":{"name":"Day 3 Thu, October 18, 2018","volume":"25 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-10-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121296292","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}

{"title":"Mapping Stress Profile and Rock Quality Variation in Tight Gas Sandstone Across a Geological Setting","authors":"M. Molenaar, Sonia Lai, R. Kumar, Surej Kumar Subbaih, A. Ghafri, R. Talreja, R. Lawatia, S. Busaidi","doi":"10.2118/191387-18IHFT-MS","DOIUrl":"https://doi.org/10.2118/191387-18IHFT-MS","url":null,"abstract":"\u0000 In an unconventional reservoir exploration process, the horizontal stress profile across different rock types plays a critical role for drilling and frac design optimization. Present study provides insight about the challenge of estimating stress profile and breakdown pressure in tight sandstone gas reservoirs at 4900m-5500m TVD with varying petrophysical parameters across a complex geological setting. A geomechanical model is prepared prior to a hydraulic fracturing job based on open hole geophysical logs and history match borehole images features like breakouts and drilling induced fractures. Advanced sonic shear fast & slow radial profiles are inverted to directly estimate horizontal stress profile in applicable formations to constrain strain at different well locations. This helps to map changes in stress magnitude, contrast and direction in reservoir across different exploration areas. Algorithm has been successfully implemented earlier worldwide in deep water and has been tested successfully in tight shallow sandstone where dispersion data shows crossover of fast & slow shear near wellbore due to hoop stress. 3D anisotropic data from advanced sonic measurement has been utilized to predict true rock fabric based rock mechanical, elastic and stress profile in silty layers. It helps to understand containment of frac across different reservoirs and optimize stages. Rock types based on petrophysical results, image features and estimated breakdown pressure were used as reference for choosing frac stages. Post-frac closure and breakdown pressure values came close to estimated values using geomechanical results and provided confidence in strain values at different fields. Breakdown pressure seems to vary in range of 12500 psi to 19000 psi depending on stress and rock quality for same reservoir. Stress barrier at top of one reservoir vary at various locations as confirmed with tracer and pressure history match which was predicted using geomechanical model. This integrated petrophysical-geomechanics workflow has been utilized in two vertical wells for two reservoirs successfully to understand field level variation in closure and breakdown pressure and map degree of anisotropy with geological variation. Cost effective optimization of Frac design have been achieved through proper integrated approach saving rig time in decision making and avoiding extra stage as confirmed through Tracer logs.","PeriodicalId":397259,"journal":{"name":"Day 3 Thu, October 18, 2018","volume":"45 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-10-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124830584","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}

{"title":"Rock Fabric Analysis Based on Borehole Image Logs: Applications to Modeling Fracture Height Growth","authors":"H. Diaz, J. Desroches, Ryan Williams, Cyrille Defeu, J. Martin, D. Cannon","doi":"10.2118/191389-18IHFT-MS","DOIUrl":"https://doi.org/10.2118/191389-18IHFT-MS","url":null,"abstract":"\u0000 Completion and production stimulation engineers use isotropic or transversely isotropicwith a vertical axis of symmetry (TIV) mechanical earth models (MEM) as an input to predict hydraulic fracture (HF) height growth. Occasionally the MEM results in models that predict fracture heights at odds with the observed fracture height in the field (e.g., fracture hits, microseismic monitoring). A potential solution to this discrepancyis to add rock fabric into the HF modeling process to better match the containment boundaries observed in the field. Laboratory large-block experiments have shown the importance of rock fabric for HF height growth and containment. Rock fabric in organic-rich mudstones (e.g., Barnett) andhybrid sequences (e.g., Wolfcamp, Eagle Ford), results from the depositional and diagenetic history of the basin andcomprises different elements relevant to HF modeling. Key rock fabric elements include: a) thin, hard layers (named stringers); b) weak beds (e.g., ash beds); and c) weak interfaces (e.g., mineralized fractures, lithology contacts).\u0000 The firstchallenge in usingrock fabric elements is identifying them with wireline logs (e.g., sonic logs). Because these features are thin, often only a few inches thick or less, they are less than the vertical resolution of most sonic logs. For thatreason, they are generally not considered in the creation of a MEM, which is the key input for modeling HF height growth. A novel rock fabric analysis workflow specifically targeted to HF height growth has been developed. It is based on high-resolution borehole images and the interpretation of the interaction of tensile drilling induced fractures with rock fabric. Qualitative flags (thickness and density of occurrence) are generated for all rock fabric elements found relevant to HF height containment, for subsequent integration into HF modeling. This offers a data-driven workflow to solve discrepancies between the hydraulic fracture heights predicted by models and those observed in the field. For weak interfaces, these flags are integrated into hydraulic fracture models as boundaries where the rock will undergo shear displacement and the fluid flow will experience complexity in its vertical path that will lead to effective containment. It is important to note that a single boundary might not stop fracture propagation, but rather a succession of boundaries is typically required to sufficiently contain a hydraulic fracture.","PeriodicalId":397259,"journal":{"name":"Day 3 Thu, October 18, 2018","volume":"57 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-10-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128049892","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}

{"title":"Hydraulic Fracture Experience in an Omani Oil Field","authors":"A. Dobroskok, Sietse de Vries, Ruqaiya Al Zadjali","doi":"10.2118/191443-18IHFT-MS","DOIUrl":"https://doi.org/10.2118/191443-18IHFT-MS","url":null,"abstract":"\u0000 The objective of this paper is to review the hydrofracturing experience in one of the Omani oil fields and to provide better understanding of geological and operational controls on the productivity of the fractured wells.\u0000 The methodology adopted in the study relied on the geomechanical evaluation for understanding the hydrofracture geometry. In particular a geomechanical model was built and calibrated by history matching the simulated and field data. Further, the implications of the created hydrofracture geometry in productivity have been studied based on the conceptual understanding and actual production histories. Last but not least, the influence of operational parameters on the hydrofracture success has also been studied.\u0000 The geomechanical evaluation concluded that it is likely that the hydraulic fracture’s growth is unconfined and downwards. Because of the combination of the unconstrained growth with relatively high reservoir permeability, the created fractures potentially are of limited length and of relatively good conductivity. According to a semi-analytical bi-linear production model, these parameters are nearly optimal for the particular reservoir. Preference for highly conductive and short fracture is due to reazonably high fluid mobility in the reservoir, high viscosity of hydrocarbons, and a relatively close well spacing. Horizontal well technology is an alternative to the hydraulic fracturing in the considered settings. Meanwhile the preference may be given to hydraulic fracturing if the commingling of the targeted unit with the overlying or underlying reservoirs is sought after. On the other hand, in the areas of structural deep, the unconfined downward growth poses a risk of connecting to the water zone. Production histories of the wells indicate that water inflow has a very pronounced negative effect on hydrocarbon production and thus must be avoided. The calibrated geomechanical model helps in choosing operational parameters that allow for proper hydrofracture design in the areas of structural deep. Nevertheless, horizontal wells will be beneficial in the areas where fracture connectivity to the water zone is likely.\u0000 Finally, a review of the fracturing operations has been carried out to understand the potential for improving the success rate. Because of the overall limited number of hydrofracturing jobs in the field, the results are far from being definitive. Meanwhile it is possible to hypothesize on the range of optimal operational parameters. In particular, this study recommends using limited volumes of fracturing fluids and coarser proppant mesh. The choice is based on the necessity to avoid communication with the water zone and the requirement of a highly conductive fracture for the efficient drainage. The recommendation is supported by limited trials. A viable alternative is combining deviated drilling technology with hydraulic fracturing. In such combination longitudinal small volume fractures should be targeted. The","PeriodicalId":397259,"journal":{"name":"Day 3 Thu, October 18, 2018","volume":"280 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-10-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133847646","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}

{"title":"Influence of Regional Tectonics and Pore-Pressure Depletion on Tight-Gas Recovery in the Sanga Sanga PSC","authors":"M. Rylance","doi":"10.2118/191469-18ihft-ms","DOIUrl":"https://doi.org/10.2118/191469-18ihft-ms","url":null,"abstract":"\u0000 The Sanga-Sanga PSC fields are located onshore Mahakam delta, East Kalimantan, Indonesia. Since the 1970s, they have produced over 80% of originally estimated gas in place with the remaining gas locked up in low permeability sands. A prize of at least 0.75 Tcf would be achievable, if these sub milli-Darcy resources could be developed. However, previous attempts at hydraulic fracturing, over three decades, have been spectacularly ineffective and rarely enjoyed any improvement or uplift at all.\u0000 During late 2006, a detailed review of the regional stress-state and prior unsuccessful frac operations was performed. This review unearthed significant evidence of a reverse stress-ordering in the deep low permeability sands, resulting in horizontal fractures being created. While this provided some logic behind the widespread failure rate, it did not in itself offer a direct solution. However, there was also sufficient evidence from previous frac history, to indicate that the solution may lie with a pore-pressure reduction. A pilot program, with meticulous candidate selection was planned to investigate this.\u0000 Further investigation determined the presence of a strong poro-elastic relationship and it was assessed that when combined with longevity of production (30 years), that the stress-state would be substantially affected. During 2008, a suite of well candidates were carefully selected with a range of reduced pore- pressures, aligned with the poro-elastic understanding, hydraulic frac treatments were performed and the wells flowed and produced for two years to confirm productivity. The subsequent production behaviour, confirmed a very positive response and the treated wells netted substantial gas/condensate sales. Production behaviour confirmed the poro-elastic relationships and a set of absolute guidelines on candidate selection and fracture execution were created. Subsequent operations that have adhered to these strict guidelines have been extremely successful. The ability of the new approach to reverse a 30- year trend of hydraulic fracturing failure will now lead to the development of the remaining resource within the fields. An extensive treatment campaign will now be possible to perform with between 50 - 100 candidates well opportunities likely to be available in the field.\u0000 A careful assessment of the regional stress-state indicated a reverse ordering of the principal stresses as being the root cause of the poor hydraulic fracturing behaviour. However, careful consideration of the rock mechanics and a coherent pilot programme demonstrated the ability, under effective depletion conditions, to place economic and successful hydraulic fracturing treatments.","PeriodicalId":397259,"journal":{"name":"Day 3 Thu, October 18, 2018","volume":"732 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-10-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116071589","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}

{"title":"Successful Application of TSE-Based Fracturing Fluids in Proppant Fracturing for Unconventional Carbonate Source Rock","authors":"A. Al-Taq, M. Al-Khaldi, Basil M. Alfakher, Karim Mechkak","doi":"10.2118/191432-18IHFT-MS","DOIUrl":"https://doi.org/10.2118/191432-18IHFT-MS","url":null,"abstract":"\u0000 Fracturing operations consume relatively large amounts of fresh or groundwater, especially in the area of unconventional resources where multi-stage fracturing is required to obtain an economical production rate and improve recovery. In an attempt to conserve groundwater, treated sewage effluent (TSE) has been evaluated and optimized for fracturing treatments to provide the required transport property for the proppant and not induce formation damage by maintaining compatibility with formation brine. Extensive laboratory work has been conducted including viscosity measurements, compatibility testing, and a microbial study to optimize an TSE-based fracturing fluid for unconventional operations. Based on laboratory recommendations, the TSE-based fracturing fluid has been applied successfully on well-A.\u0000 Twenty stages of unconventional proppant fracture stimulation utilizing the Plug and Perf (P-n-P) technique across the carbonate source rock have been applied successfully. Two base fluids, freshwater and TSE, were used to evaluate the effectiveness of TSE as a substitute for the freshwater in unconventional fracturing operations. Each water was used in 10 stages. The post-fracturing production results of well-A showed comparable results with the offset wells treated only with freshwater-based fracturing fluids. The pressure logging tests (PLT) conducted on this well confirmed that contribution of intervals treated with TSE-based fracturing fluid was comparable with those treated with fresh water-based fracturing fluid. There was no evidence of scaling issues during the flowback period for both fluid systems. Microbial evaluation of water samples collected during the flowback of well-A showed no presence of bacteria in these samples. This paper will discuss the laboratory work and the field application of TSE-based fracturing fluid.","PeriodicalId":397259,"journal":{"name":"Day 3 Thu, October 18, 2018","volume":"14 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-10-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129713880","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}

{"title":"First Successful Proppant Fracturing Treatment in Cretaceous Carbonate formation in Kuwait – Part II Tuba Reservoir","authors":"S. Pooniwala, Malvika Nagarkoti, A. Alam, B. Al-Enezi, S. Aloun, M. Al-Haddad, Sultan Al-Harbi, A. Mubarak, A. Al-Ibrahim","doi":"10.2118/191416-18IHFT-MS","DOIUrl":"https://doi.org/10.2118/191416-18IHFT-MS","url":null,"abstract":"\u0000 Proppant fracturing treatments in sandstone formations are routinely executed in Kuwait, however when carbonate formations are the target, acid fracturing is the preferred treatment method. It has been observed that acid fracturing delivers a high initial production however maintaining a sustainable production rate is a challenge in the tight cretaceous carbonate formations in Kuwait. A production enhancement technique needed to be identified in order to deliver more sustainable production and maximize recovery from these carbonate formations. The first stage of the project focused on ascertaining the operational feasibility of proppant fracturing in a single layered Mauddud reservoir. This paper will focus on the operational implementation of multi-stage proppant fracturing in the multi-layered Tuba reservoir. (Nagarkoti, M., et al., 2018)\u0000 Based on global experience it was proposed that proppant fracturing can deliver more sustainable production rate as compared to acid fracturing. A predominant issue in previous acid fracturing treatments done in the Tuba reservoir has been fracture containment between layers. Proppant fracturing was also identified as a solution to mitigate this challenge.\u0000 Proppant fracturing had been previously attempted in Kuwait, however the attempts were evaluated as not being operationally successful. The steps that lead to the recent first successfully executed proppant fracturing treatment in carbonates in Kuwait has been documented in Part I of this paper series.\u0000 The cretaceous carbonate formations in North Kuwait are relatively shallow and are known to be tight and highly ductile. Due to the ductility of these formations, proppant placement and reduction of the fracture conductivity due proppant embedment were thought to be significant risks. During the course of the project, detailed core analysis and testing was conducted using formation core samples to ascertain the severity of this risk.\u0000 Lessons learnt in the first stage of this project were implemented prior execution to ensure that the planned proppant fracturing treatment would meet or exceed operational expectations.\u0000 Successful execution of this hydraulic fracturing treatment was pivotal in order to plan the future production strategies for the Tuba formation. A cautious approach needed to be followed as proppant placement was of paramount importance. Different strategies were incorporated in the fracturing workflow to ensure the success of the treatment and to maximize data collection in order to optimize future treatments and well placement. Multiple mini-fracs, temperature logs and pumping of novel non-radioactive tracer proppant were some of the techniques utilized.\u0000 During execution various decisions were taken real-time to ensure success of the treatment. It was observed that all parameters were consistent with the results of the core and laboratory testing conducted during the initial phase of the project which lead to optimizing the proppant pla","PeriodicalId":397259,"journal":{"name":"Day 3 Thu, October 18, 2018","volume":"14 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-10-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125339840","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}