Day 2 Wed, February 07, 2024最新文献

{"title":"Minimizing Parent-Child Effect in the Anadarko Basin Through Parent Recharges","authors":"K. D. Wilson, M. Tabatabaei","doi":"10.2118/217818-ms","DOIUrl":"https://doi.org/10.2118/217818-ms","url":null,"abstract":"\u0000 Recharging parents has been used as a technique in the Anadarko Basin to mitigate the parent-child effect since 2018. Usually, parent wells either don't return to their pre-infill rate or recover slowly after frac hits. On the other hand, the performance of the child directly adjacent to the parent can be negatively impacted by the presence of the parent and underperform other infills. Recharging a parent prior to completing the children not only can help the parent well recover to its pre-infill rate faster but also can help minimize the parent-child effect and improve the performance of the children, specifically direct offsets. Over time our recharge operations and design parameters have evolved significantly to increase the effectiveness and improve economics of the program. Many trials were performed to identify key design parameters that impact parent recovery post frac-hit. In addition, a robust analysis was done to quantify the effect of recharges on direct offsets. This paper presents several case studies of successful and unsuccessful parent recharges in the Anadarko Basin. We will review candidate selection criterion and discuss key parameters that optimize the recharge program to maximize the effectiveness on parent recovery and minimize the parent effect on the parent adjacent child wells. The key parameters that will be discussed are recharge volume, pump rate, magnitude of pressure depletion, distance between the parent and the direct offset, and completion design.","PeriodicalId":518084,"journal":{"name":"Day 2 Wed, February 07, 2024","volume":"192 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-01-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140529448","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":"Quantifying the Effects of Parent-Child Communication Using Dynamic Fluid-In-Place Calculations","authors":"C. R. Clarkson, A. -. L. Benson, H. Hamdi","doi":"10.2118/217760-ms","DOIUrl":"https://doi.org/10.2118/217760-ms","url":null,"abstract":"\u0000 Multi-fractured horizontal wells completed in the same reservoir layer, or different reservoir layers, commonly experience inter-well communication through hydraulic fractures. For example, after a parent well is placed on production, its production performance can be impacted by communication with an offsetting child well placed on production after the parent well. The degree of communication between parent-child wells is important to quantify for the purposes of well production forecasting, reserves estimation, and completions and well spacing design optimization. In this study, dynamic fluid-in-place calculations performed using parent well production rates and flowing pressures are used to quantify the impact of child well communication on parent well contacted fluid-in-place estimates.\u0000 Agarwal (2010) demonstrated that pressure transient analysis theory can be used to derive the volume of fluid in place contacted by a well (CFIP) over time during constant rate, transient production. The method was later extended to variable-rate/pressure scenarios. However, all previous applications of Agarwal’s method were for single, isolated wells. In order to evaluate the usefulness of the method for quantifying parent-child communication, for this study, multiple numerical simulation cases are generated to simulate different degrees of communication. This is achieved by simulating light oil and gas production scenarios, where the parent and child wells are communicating through a hydraulic fracture with a specified transmissibility multiplier (Tmult) used to adjust the amount of inter-well communication. The CFIP diagnostic plot (i.e., log-log plot of CFIP versus material balance time) is applied to the parent well to evaluate the CFIP trend before and after child well production, and the magnitude of CFIP change. Practical application of the method is demonstrated with field cases.\u0000 From the simulation cases, it is observed that, after the child well is put on production, a reduction of CFIP for the parent well occurs (rapidly decreasing at first, then stabilizing after a transition period) proportional to productivity index reduction. The loss in CFIP for the parent well can be determined simply by estimating the parent well CFIP immediately before and after child well production. The loss in CFIP is verified using drainage volume estimates in the simulator. For the Tmult=0.25, 0.5, and 1 cases (where Tmult=1 yields the greatest degree of communication), the slope of the CFIP trend for the parent well = 0.5 (pure transient linear flow) before and after child-well communication/transition, and the CFIP change is estimated to be about 40% for oil and 47% for gas. For the case of Tmult =0.001, the CFIP change for the parent well is smaller (28% for oil, 39% for gas) than for Tmult > 0.25. The slope of the CFIP plot for the parent well in this case, prior to child-well production, is > 0.5, but stabilizes at 0.5 after interference. For the case of Tmult","PeriodicalId":518084,"journal":{"name":"Day 2 Wed, February 07, 2024","volume":"68 2","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-01-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140529992","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":"Protecting Parent-Well Production Using Far-Field Diverters in Unconventional Wells","authors":"F. O. Ajisafe, H. Porter, S. Kothare, E. Colson, R. Ellis, N. Heaton, B. Demars, M. Mayerhofer","doi":"10.2118/217813-ms","DOIUrl":"https://doi.org/10.2118/217813-ms","url":null,"abstract":"\u0000 The impact of fracture driven interaction (FDI) is an increasing concern in mature developed unconventional plays in the US. In this study, parent well production performance after infill well stimulation is evaluated to understand the effectiveness of far-field diverter in mitigating FDI's. Studies to determine if FDI's result in a negative or positive impact, have concluded that it varies from basin-to-basin (Miller et al 2016). In this project, the purpose of pumping far-field diverter is to mitigate wellbore sanding and production loss in existing parent wells.\u0000 The far-field diverter pill includes a blend of multimodal particles to bridge the fracture tip, preventing excessive fracture length and height growth. Fracture modeling with a unique particle transport model is typically used to design the far-field diverter pill impact on fracture geometry. The pill design and contingency designs are executed in the infill well stimulation job, right after the pad step, in the beginning of the pump schedule. Optimization of the far-field diverter can be complemented with real-time pressure monitoring or cross-well fiber strain data on the parent well.\u0000 Over the years, far-field diverter has, in one form or the other, been used for various applications in stimulation design. However, since mid-2010's, far-field diverter has been used to address growing concerns of FDI's observed in most mature plays in the US. In this study, since 2018, far-field diverters have been pumped in several wells for the purpose of mitigating the negative impact of FDI's between parent and child wells. While these jobs were operational successes, the next crucial step was to evaluate and quantify the effectiveness of the far-field diverter in mitigating production loss in the parent wells. It is important to note that the operator whose wells utilized far-field diverters, had experienced negative impact of FDI's in their parent wells in the form of production loss and sand in the wellbore which required clean outs at a significant cost. In this study, production data was evaluated comparing pre-stimulation production before shut-in and post-stimulation production after the parent wells were brought back online. Overall, about 75% of the parent wells protected show positive uplift in oil production. And about 80% of the child wells show superior or comparable production decline after about a year of production when compared with offset parent wells It is evident that far-field diverters for fracture geometry control in child wells can be extremely helpful in mitigating negative impact of FDI's.\u0000 In unconventional reservoirs, where infill (child) well drilling is prevalent, the impact of far-field diverter in controlling fracture geometry has the potential to be a value added FDI mitigation technology to mitigate wellbore sanding and subsequent clean outs as well as optimize production performance of both child and parent wells. The early part of the project resulted in ~$","PeriodicalId":518084,"journal":{"name":"Day 2 Wed, February 07, 2024","volume":"92 2","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-01-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140529261","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":"Real Time Calculation of Bottomhole Injection Temperature Using Surface and Downhole Temperature Gauge Data","authors":"V. Pandey","doi":"10.2118/217798-ms","DOIUrl":"https://doi.org/10.2118/217798-ms","url":null,"abstract":"\u0000 During hydraulic fracturing or acid fracturing treatments, the efficacy and performance of the stimulation fluid largely depends on the bottomhole injection temperatures to which the fluid is exposed as it enters the fracture. This study focuses on calculation of injection temperatures from available measurements to aid in the fluid selection and design for well stimulation operations.\u0000 Injection temperatures at the perforations during well stimulation treatment, is one of the starting points in fluid selection processes, be it acid or propped fracturing stimulation. In acid fracturing, inaccurate estimation can lead to incorrect selection of acid which can result in either an under-stimulated well, or in worst case, damage to the tubular goods resulting in expensive workover operations. In case of propped fracturing treatments, inaccurate estimation of wellbore temperatures can result in (a) an early or delayed cross-linking of fluid which can lead to shear-degradation of fluid or even a premature screen out, (b) higher than expected treatment pressures if cross-linking is delayed excessively leading to increased horsepower requirements and, (c) screen out or inferior stimulation due to overly conservative treatment designs. Accurate temperature estimates are thus a necessity.\u0000 The temperature distribution and prediction of temperature profile in the wellbore during injection process has been well studied and documented (Ramey, 1962; Wu and Pruess, 1990; Hagoort, 2004; Hassan et al. 2005) with original contributions by Carslaw and Jager (1959) on transient heat conduction in an infinite radial system. The current study uses temperature measurements, recorded by gauges that are typically located far away from the perforations, as inputs for the calibration of overall system heat transfer coefficient. Subsequently, based on well construction details and injection schedule, temperatures at perforations are predicted. The calculation can be carried out in a live mode if the treatment data is available in real time.\u0000 The paper discusses the pertinent theory and development of a calculation engine that can predict temperatures in the wellbore after calibration of the input data. Though predictions can be made for any depth in the wellbore, the focus is on the temperatures that exist at the perforation depths. The calculated injection temperatures were found to be different than measured values at shallower depths indicating that gauge temperature does not accurately represent injection temperatures at the perforations. Correct estimation is thus critical to the success of the treatment so that fluid properties can be adjusted and tailored to meet the requirements, and even possibly assist in optimizing the stimulation program.\u0000 Prediction of bottomhole temperatures at the injection point obtained with the help of temperatures measured at shallower depths is a unique approach and produces more accurate results than mere predictions based on generic a","PeriodicalId":518084,"journal":{"name":"Day 2 Wed, February 07, 2024","volume":"212 ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-01-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140529847","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":"Performance Redefined: A Business-Centric Approach to Assessing Hydraulic Fracturing Execution","authors":"D. Mogck, J. Doucette","doi":"10.2118/217803-ms","DOIUrl":"https://doi.org/10.2118/217803-ms","url":null,"abstract":"\u0000 The hydraulic fracturing of an unconventional well is typically the single most significant component of the expenditure for that well; however, there is no industry standard for assessing the efficiency of that operation.\u0000 This work will present an approach for evaluating hydraulic fracturing performance that transcends commonly used key performance indicators (KPIs). Historically, the industry has focused on various metrics, such as pumping hours per day, to quantify a frac crew's efficiency. However, many commonly used KPIs may provide incomplete and sometimes misleading indicators of the actual performance of a given completions spread.\u0000 This paper will present examples of traditionally used KPIs, instances where they have gone wrong, and offer an alternative means of consolidating and visualizing data from various commonly available sources. The intent is to better diagnose drivers affecting the performance of a given hydraulic fracturing spread.\u0000 Commonly collected data from a hydraulic fracturing job, including rates, volumes, design parameters, and job logs, are transformed into consistent and easily understandable metrics. These data have been collected for hundreds of jobs and stages over the last few years and integrated into a dashboard to get a high-level understanding of performance. The authors of this paper have mined these data sets for examples to share lessons learned from experience and present some of the critical factors that can substantially impact performance.\u0000 A review of historically used KPIs (stages, hours, feet per day, transition times, etc.) will reveal that none are ideal, and many suffer significant flaws. For example, a typical ‘stage’ design can vary wildly between areas. Pumping hours per day do not account for actual output during those hours. Case studies will illustrate the potential pitfalls of traditional KPI tracking and introduce the value of a more comprehensive approach.\u0000 The methodology presented will divide the efficiency of a frac crew into a few broad buckets. The first encompasses surface efficiency - how physical operations on the well site affect the ability to pump. The second is hydraulic efficiency - quantifying how effectively the spread can attain and maintain the target pumping rate.\u0000 The final bucket focuses on capturing overall crew performance in a single metric – slurry volume pumped. The volume pumped per day captures daily performance, while cumulative volume pumped over time reveals macro efficiency trends.\u0000 Hydraulic fracturing KPIs have not been standardized. Additionally, they are often only evaluated and reviewed monthly or quarterly, not daily. Subsurface drivers of efficiency are also commonly neglected. To the authors' knowledge, this is the first work to present a methodology for holistically assessing a hydraulic fracturing operation's effectiveness and efficiency using a combination of surface and subsurface metrics trackable on a daily basis.","PeriodicalId":518084,"journal":{"name":"Day 2 Wed, February 07, 2024","volume":"256 ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-01-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140529843","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":"Application of Machine Learning to Create a Discrete Fracture Network Model for Utah FORGE Fracture Injections","authors":"Jeffrey R. Bailey, Yanrui Daisy Ning, Jeff Bourdier, Israel Momoh, Prathik Prasad","doi":"10.2118/217809-ms","DOIUrl":"https://doi.org/10.2118/217809-ms","url":null,"abstract":"\u0000 A method to process microseismic event locations from three injections into the Utah FORGE 16A(78)-32 geothermal well has been developed as part of the 2023 SPE Geothermal Datathon. One objective of the datathon was to develop methods using a few tunable parameters that are capable of multiple realizations of the Discrete Fracture Network (DFN).\u0000 The method uses open-source software tools and comprises seven steps. The first step is to calculate the square-root of elapsed time from the first event of each stage. The next step is to use DBSCAN (Density Based Spatial Clustering of Applications with Noise) on this RootTime variable, followed by the application of DBSCAN to the spatial variables in each time slice. Each of the resulting clusters is analyzed by principal component analysis to generate fracture planes. DBSCAN leaves multiple outliers that are then harvested using two methods. Criteria are provided to fuse fractures together that are close spatially. The final step is to consider if connective fractures are required to ensure communication of the fracture network with the perforated interval.\u0000 The Utah FORGE dataset comprises 2798 event locations from three injections. The analysis in time yielded 54 clusters of data, and the spatial analysis then provided 73 distinct fractures, with a residue of 25% outliers. Outliers were harvested in two steps: first, capturing outliers that were adjacent to mapped fractures, and then evaluating the remaining outliers for individual fracture planes using relaxed DBSCAN parameters. After these two steps, the outlier population was reduced to less than 4%, and the total number of mapped fractures grew to 87.\u0000 It was recognized that fractures can propagate across time slices, so a fracture fusion step was conceived to combine subparallel fractures that were indistinguishable from each other based on error analysis. This was particularly necessary for Stage 3 that had mostly vertical fractures. In this step, 24 fractures were combined, resulting in a total of 63 fractures in the DFN. In the final step, it was recognized that there were no fracture intersections with the perforated interval for Stage 2, and thus an aseismic flow path was inferred. A vertical and a horizontal fracture were inserted to represent this flow.\u0000 Each DBSCAN application has two input parameters, resulting in possibly many clusters and multiple outliers. The development of steps to harvest outliers and fuse adjacent fractures were conceived to utilize as much data as possible and to recognize the relative errors in event locations. With regards to the Datathon goal of achieving an automated processing sequence, the algorithm runs without manual intervention once the user has chosen four parameters for each stage: the minimum number of points in a cluster and the accepted percentage of outliers for each of the time and spatial clustering steps. The calculated dominant fracture azimuth of N-20-E compares favorably with data from t","PeriodicalId":518084,"journal":{"name":"Day 2 Wed, February 07, 2024","volume":"176 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-01-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140529450","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":"Getting Granular with Proppant Logistics","authors":"C. Wagner, B. Poppel, G. McKee","doi":"10.2118/217831-ms","DOIUrl":"https://doi.org/10.2118/217831-ms","url":null,"abstract":"\u0000 Delivery of the proppant required for a hydraulic fracturing job can quickly become a weak link in operational excellence. New technology in the oil and gas industry has been hyper focused on well site efficiency but has missed out on the synergies that can be leveraged between proppant delivery and hydraulic fracturing operations. A new logistics solution was developed to take advantage of these synergies and support higher operational efficiency.\u0000 The new proppant logistics solution was built on an established hydraulic fracturing field data collection platform. Driver and proppant load information was ingested into the new solution with a software program used to order the proppant loads to be delivered to the job. The combination of these two systems synergized the new solution and ensured the supply chain of products needed for a hydraulic fracturing job would not create a weak link in the chain of operational excellence.\u0000 With the world still feeling impacts from the 2020 pandemic, worldwide shipping and logistics markets sank into a supply imbalance. This supply-demand disparity combined with the consistency of over-the-road trucking as compared with the historically volatile nature of proppant delivery, over-the-road trucking became very desirable for existing proppant delivery drivers. This paper will present a case study reviewing how a new software solution was built and implemented to facilitate rapid field data delivery and will also discuss how this solution was utilized to build out differential visual and predictive analysis tools to promote timely delivery of proppant needed at each fracturing location. After implementing the new solution, success was measured through the following observations. 90% decrease in proppant delivery downtime.35% decrease in drivers needed for a job, lowering the footprint of drivers on the road.Individual drivers delivered 20% more loads per day.33% decrease in total time required to deliver a load of proppant.Enhanced competitiveness among drivers lowering the cost to produce a barrel of oil.\u0000 With this new solution, proppant logistics teams are now able to leverage intelligent solutions to help dispatch proppant so that operational excellence is maintained to the highest standard.","PeriodicalId":518084,"journal":{"name":"Day 2 Wed, February 07, 2024","volume":"93 9","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-01-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140529703","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 Fracturing Design Considerations for Carbon Capture, Utilization, and Storage (CCUS)","authors":"Leopoldo Sierra, Connor Lovingfoss","doi":"10.2118/217816-ms","DOIUrl":"https://doi.org/10.2118/217816-ms","url":null,"abstract":"\u0000 Hydraulic fracturing, a well-established technique in the oil and gas industry, has gained significant attention as a potential method to improve the short- and long-term efficiency of the Carbon Capture, Utilization, and Storage (CCUS) process. Most of the scoping studies on CCUS have centered on the reservoir aspects, such as storage and CO2 movement. Very little has been done evaluating what the fracture designs might look like in this process.\u0000 This paper presents a review of the application of hydraulic fracturing in CCUS projects, examining its technical feasibility, fluids, sustaining agents, wellbore orientation, and fracture orientation considerations required to assure its technical and economic success. It will consider rock properties, depleted oil or gas reservoirs conditions, or deep saline aquifers horizons and compressed CO2 supply at the storage site; simulations have been performed using primarily super critical CO2 (scCO2) and conventional fluids to perform the hydraulic fracturing. In addition to the sCO2 usage and proppants required to tail the generated fractures; the wellbore orientation effect in reference to the stress plane is also considered in the paper.\u0000 Finally the short- and long-term benefit of the hydraulic fracturing will be evaluated by simulating the CO2 injection behavior.\u0000 The review encompasses an analysis of the various key stages involved in CCUS hydraulic fracturing process, starting from the review of rock properties, wellbore orientation, perforation strategy, selection of suitable fluid and propping agents for efficient and safe stimulation of a well candidate. The potential benefits of the proper hydraulic fracturing process implementation will be translated in an enhanced storage capacity and improved injectivity.\u0000 The extensive simulations considering the sCO2 as the primary fluid system for fracturing purposes, combined with the wellbore orientation and other parameters will show the direct benefit of the combinations of the hydraulic fracturing and the CCUS processes, including: The use of sCO2 and proppants for hydraulic fracturing purposes in CCUSThe influence of the wellbore and hydraulic fracture orientation in the success of the CCUS process\u0000 The paper aims to explore the potential of CCUS in conjunction with hydraulic fracturing to increase the efficiency of CO2 disposal and analyze methods to maximize its effectiveness. It will be beneficial for those contemplating CCUS, complementing other CCUS evaluations to provide a more complete picture of the feasibility as well as technical hurdles that must be overcome to implement this concept.","PeriodicalId":518084,"journal":{"name":"Day 2 Wed, February 07, 2024","volume":"44 20","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-01-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140529138","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":"Managing Friction Pressures to Reduce Fuel Consumption and Emissions for a Fracturing Fleet","authors":"Zacary Beveridge, Nathan McLaughlin, S. Kakadjian","doi":"10.2118/217783-ms","DOIUrl":"https://doi.org/10.2118/217783-ms","url":null,"abstract":"\u0000 Friction pressure has always been a limiting factor for placing water and proppant during a hydraulic fracture treatment. Mitigating friction pressure has relied heavily upon using chemicals to reduce the friction and ultimately the hydraulic horsepower required to complete the job. Costs to reduce friction pressure have always been associated with the type and amount of friction reducer (FR) used. Best practices being associated with using as little as necessary to achieve the treatment. On the contrary, utilizing the minimum amount of FR can increase overall costs for treatment due to increased fuel usage which leads to increased emissions. As the industry strengthens focus surrounding Environmental, Social, and Governance (ESG) and optimizing costs for well completions, this paper discusses a unique approach to decrease friction pressures, reduce fuel usage, and ultimately optimize the completions treatment and associated cost.\u0000 Using friction models based on laboratory data and fuel consumption models built from flowmeter measurement during treatment, various pumping scenarios can be combined to estimate fuel consumption for diesel and dual fuel engines at varying FR set points. Incorporating a friction pressure model allows for treating pressure to be estimated and used within the fuel consumption model. Providing commodity costs and emissions factors allows for understanding of total cost and emissions changes with increased FR usage. Varying FR usage, treatment rate, and number of pumps gives room for optimization and understanding of the variables that demonstrate the greatest effect on total costs and emissions.\u0000 Increasing FR leads to decreased treating pressure and required hydraulic horsepower which reduces fuel consumption and generated emissions. The cost reductions depend on commodity prices as well as the types of fuel used (diesel or a blend of diesel and natural gas). Utilizing current market pricing, an increase in FR concentration from 0.4 gal per thousand to 0.6 gal per thousand resulted in a decrease in overall costs of nearly 5% per pumping hour and emissions reductions of up to 15.9%. By changing the conventional wisdom of lowering costs by reducing chemical concentrations to optimizing based on the bigger picture, emissions, treatment costs, and equipment utilized are reduced. Additional horsepower can be utilized for backup and further reduce non-productive time and increase efficiency. With proper planning and understanding, this solution will provide a more efficient environment for completions.","PeriodicalId":518084,"journal":{"name":"Day 2 Wed, February 07, 2024","volume":"196 ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-01-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140529412","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":"Managing the Challenges of Casing Deformation in Multi-Fractured Horizontal Wells","authors":"W. Arshad, R. Alidi","doi":"10.2118/217766-ms","DOIUrl":"https://doi.org/10.2118/217766-ms","url":null,"abstract":"\u0000 One of the challenges encountered in hydraulic fracturing of unconventional resources is casing deformation. Casing deformation statistics vary across different regions of the world, but it is estimated to affect 20-30% of horizontal wells in some areas of operations. The consequences of casing failures can be varied but, in many cases, it affects the well production, wellbore accessibility and in some rare instances presents a situation of well control and its associated risks.\u0000 Incidentally, most literature on casing deformation pertains to \"plug & perf\" fracturing operations in cemented completions though pipe deformation is known to occur in multi-stage fracturing (MSF) sleeves type of openhole completions as well. Intuitively, the two failure mechanisms may appear similar instead they represent very diverse well conditions that lead to pipe deformation.\u0000 Tubular damage during fracturing is not caused by a single, consistent reason. Multiple mechanisms may be responsible for casing deformation; formation rock properties, wellbore configuration, cyclic loads acting on the tubulars, tubular quality, cement bond, or simply some operational aspects during drilling and completion conducive to pipe deformation. Tubing stresses analysis of the lower completion and especially of the individual components of the openhole MSF completion is seldom done. A comprehensive study was initiated by first validating the key data and parameters, multi-arm caliper data in conjunction with downhole camera imaging, and review of the physical mill-out patterns of frac plugs (in cased hole completions) and ball-seats used in MSFs to understand the damage pattern. This work was supported by detailed geo-mechanical properties profiles, diagnostic injection tests analysis, and evaluation of casing integrity under anticipated fracture loads.\u0000 One of the primary learnings from this study was that wellbore quality had a significant bearing on the post-frac wellbore integrity for both types of well completions. The study indicated that well profile, design, and tool placement in the well also had a strong influence on axial load distribution in open-hole multistage completions. The mode of failure in openhole multistage wells was different than those seen in cemented liners. These differences do not necessarily fall under the domain of formation movement experienced in geomechanically complex and tectonically active areas.\u0000 Since reservoir uncertainties are a reality, a good wellbore quality cannot always be guaranteed. It becomes necessary to manage pipe deformation with mitigating practices. This paper provides practical solutions to pipe deformation in cemented and openhole completions. The operational workflows allow upfront assessment with analytical tools to model the stress loads. By understanding the primary factors that affect well integrity, the likelihood of casing failure can be predicted and avoided ahead of time, save fracturing costs across high-risk areas,","PeriodicalId":518084,"journal":{"name":"Day 2 Wed, February 07, 2024","volume":"249 ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-01-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140529984","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}