Day 1 Mon, November 15, 2021最新文献

{"title":"Individual Fracture Efficiency Monitoring in Horizontal Wells by Using a New 3d Fine-Grid Temperature Modelling","authors":"Vitaly Virt, V. Kosolapov, V. Nagimov, A. Salamatin, Y. Fesina, A. Alekseeva, Yu.I. Yakhina, E. Skutina","doi":"10.2118/207237-ms","DOIUrl":"https://doi.org/10.2118/207237-ms","url":null,"abstract":"\u0000 Profitable development of hard-to-recover reserves often involves drilling of horizontal wells with multistage hydraulic fracturing to increase the oil recovery factor. Usually to monitor the fracture sweep efficiency, pressure transient analysis is used. However, in case of several fractures this method delivers only average hydrodynamic parameters of the well-fracture system. This paper illustrates the value of temperature logging data and demonstrates possibilities of the 3-D thermo-mechanical modelling in evaluating the differential efficiency of multi-stage hydraulic fracturing.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"37 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81558350","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":"Digitally Distanced Inspection & Maintenance at Drilling Rigs : Applied Augmented Reality","authors":"D. Dash, Dileep Chandran Nair, Srinivas Potluri","doi":"10.2118/207284-ms","DOIUrl":"https://doi.org/10.2118/207284-ms","url":null,"abstract":"\u0000 For drilling contractors, the moment of truth is the operations at the site. If the technician at the site encounters a problem he can't solve, then everything stops. The team has to wait for a subject matter expert (SME) to arrive at the site to diagnose rectify the problem. Such process of SME mobilization and till that time Non-Productive Time (NPT) results in loss of hundreds of thousands of dollars. Hence the key challenge is converting the Sparse to Adequate availability of Right Knowledge at Right Time at Right Place, for the support of technicians.\u0000 This paper is focused on the approach of moving from Hand Held devices to Hands-Free environment at sites and connecting local/global support to site support systems, to reduce cost, improve HSE and enhance operational performance. The augmented reality technology-enabled, smart glass laced headsets are rugged, zone 1 certified, and are voice-operated which are better than smart tablets which were considered during Technology Qualification Process. Evaluation criteria were: 1. Availability and follow up of the digital work instruction while operating. Moreover, not missing a single step of work instruction while inspection or maintenance continues was noted carefully. 2. Reduced travel/accommodation cost : Normally at the time of shutdown, the rig crew contacts subject matter experts (SME) and (at times) in turn the SME contacts the OEM support team to mobilize service engineers globally. 3. Response time improvement-Availability of support by SME right at the time of need results from better response time to diagnose and fix the issue at hand. Call logging till final resolution process improvement is considered an important metric. Travel restrictions imposed by Covid-19, are also being addressed through the distanced inspection. A hands-free environment is compared vis a vis handheld device. Better training and knowledge transfer are achieved through better communication methods and this goes better with learning by doing. Subsequent text (NLP-speech to text) analysis is planned through deep learning models to derive related predictions. Sparse to Adequate availability of support to rig staff with Right Knowledge at Right Place at Right Time is the key outcome of this Proof of Value project.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"26 10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82698105","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":"Insights into Oil Recovery Mechanism by Nothing-Alternating-Polymer NAP Concept","authors":"M. Battashi, R. Farajzadeh, A. Bimani, M. Abri, R. Mjeni, V. Karpan, A. Fadili, J. van Wunnik","doi":"10.2118/207743-ms","DOIUrl":"https://doi.org/10.2118/207743-ms","url":null,"abstract":"\u0000 This paper discusses the application of polymer injection in a heavy oil reservoir in the South of the Sultanate of Oman containing oil with a viscosity of 300-800cP underlain by a strong bottom-up aquifer. Due to unfavorable mobility ratio between aquifer water and oil and the development of the sharp cones significant amount of oil remains unswept. To overcome these issues, a polymer injection pilot started in 2013 with three horizontal injectors, located a few meters above the oil/water contact. Initially a polymer solution with a viscosity of 100 cP was continuously injected at high injection rates. However, it was challenging to sustain the injectivity mainly due to surface facilities, water, and polymer quality issues. This resulted in frequent shutdowns of the injectors. Interestingly, the water cut reversal and oil gain continued during the shut-in periods. This observation has led to the development of a new cyclic polymer injection strategy, in which the injection of polymer is alternated with shut-ins. The strategy is referred to as Nothing-Alternating-Polymer (NAP). This paper discusses the oil recovery mechanism from the NAP strategy. A 3D model was constructed to match the actual pilot results and capture the observed behavior. The injected polymer squeezes the cones and partly restores the barrier between the aquifer and the oil column, suppressing the aquifer flux and hence the negative affect of the cones.\u0000 It was found that during polymer injection, the oil is recovered by conventional mobility and sweep enhancement mechanisms ahead of the polymer front. Additionally, during this stage the injected polymer creates a barrier between the aquifer and the oil column, suppressing the aquifer flux and hence the negative effect of the cones or water channels (blanketing mechanism). Moreover, injection of polymer pushes the oil to the depleted water cones, which is then is produced by the water coming from the aquifer during shut-in period (recharge mechanism). During the shut-in or NAP period, the aquifer water also pushes the existing polymer bank and hence leads to extra oil production. The NAP strategy reduces polymer loss into aquifer and improves the polymer utilization factor expressed in kg-polymer/bbl of oil, resulting in a favorable economic outcome.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"30 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87053165","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":"The Optimization of Infill Well Fracturing Using an Integrated Numerical Simulation Method of Fracturing and Production Processes","authors":"S. Wei, Yan Jin, Xing-gang Liu, Yang Xia","doi":"10.2118/207978-ms","DOIUrl":"https://doi.org/10.2118/207978-ms","url":null,"abstract":"\u0000 New wells are continuously drilled to improve the recovery of shale gas reservoirs. Production processes of parent wells will induce stress changes in the reservoir and then affect infill wells’ fracturing design. In this paper, we employed an integrated numerical method to simulate the hydraulic fracturing and production processes with single one method, thus the fracturing scheme of the infill well can be optimized. The integrated numerical method is based on the finite element method (FEM), which is named as the discontinuous discrete fracture method (DDFM). The DDFM can be used with conventional finite element mesh, which is perfectly compatible with the discrete fracture model (DFM). The fully coupled solution of DDFM is validated by two problems, including Mandel problem's analytical solution and the numerical solutions of the single fracture propagation. When predict the shale gas production, a new diffusion equation is modified to describe the shale gas flow, and the simulation results showed a good agreement with the field data. At last, this paper takes an infill well construction in a shale gas reservoir in south China as an example. The hydraulic fractures of parent wells are interpreted from micro-seismic data and described with DFM to reduce the computational cost. Then the infill well's hydraulic fractures are described using DDFM. After simulating the production process of two parent wells, we get the current formation pressure and stress state. Aims at obtaining the maximum profit of the whole well region, by comparing the gas production of different fracturing schemes, we can choose the optimal fracturing scheme of the infill well.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86296344","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":"Numerical Optimization of WAG Injection in a Sandstone Field using a Coupled Surface and Subsurface Model","authors":"Thaer I. Ismail, E. Al-Shalabi, M. Bedewi, W. Alameri","doi":"10.2118/207449-ms","DOIUrl":"https://doi.org/10.2118/207449-ms","url":null,"abstract":"\u0000 Gas injection is one of the most commonly used enhanced oil recovery (EOR) methods. However, there are multiple problems associated with gas injection including gravity override, viscous fingering, and channeling. These problems are due to an adverse mobility ratio and cause early breakthrough of the gas resulting, in poor recovery efficiency. A Water Alternating Gas (WAG) injection process is recommended to resolve these problems through better mobility control of gas, leading to better project economics. However, poor WAG design and lack of understanding of the different factors that control its performance might result in unfavorable oil recovery. Therefore, this study provides more insight into improving WAG oil recovery by optimizing different surface and subsurface WAG parameters using a coupled surface and subsurface simulator. Moreover, the work investigates the effects of hysteresis on WAG performance.\u0000 This case study investigates a field named Volve, which is a decommissioned sandstone field in the North Sea. Experimental design of factors influencing WAG performance on this base case was studied. Sensitivity analysis was performed on different surface and subsurface WAG parameters including WAG ratio, time to start WAG, total gas slug size, cycle slug size, and tubing diameter. A full two-level factorial design was used for the sensitivity study. The significant parameters of interest were further optimized numerically to maximize oil recovery.\u0000 The results showed that the total slug size is the most important parameter, followed by time to start WAG, and then cycle slug size. WAG ratio appeared in some of the interaction terms while tubing diameter effect was found to be negligible. The study also showed that phase hysteresis has little to no effect on oil recovery. Based on the optimization, it is recommended to perform waterflooding followed by tertiary WAG injection for maximizing oil recovery from the Volve field. Furthermore, miscible WAG injection resulted in an incremental oil recovery between 5 to 11% OOIP compared to conventional waterflooding. WAG optimization is case-dependent and hence, the findings of this study hold only for the studied case, but the workflow should be applicable to any reservoir. Unlike most previous work, this study investigates WAG optimization considering both surface and subsurface parameters using a coupled model.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"11 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84213789","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":"Geochemical Techniques to Detect Sources of Fluids in Highly Pressured Casing-Casing Annuli CCA","authors":"Dr. Peter Birkle, Hamdi A. AlRamadan","doi":"10.2118/208146-ms","DOIUrl":"https://doi.org/10.2118/208146-ms","url":null,"abstract":"\u0000 The buildup of high casing-casing annulus (CCA) pressure compromises the well integrity and can lead to serious incidents if left untreated. Potential sources of water causing the elevated CCA pressure are either trapped water in the cement column or water from a constant feeding source. This study utilizes inorganic geochemical techniques to determine the provenance of CCA produced water as trigger for high pressure in newly drilled wells. Affinities in the hydrochemical (major, minor and trace elements) and stable isotopic (δ2H, δ18O) composition are monitored to identify single fluid types, multi-component mixing and secondary fluid alteration processes. As a proof-of-concept, geochemical fingerprints of CCA produced water from three wells were correlated with potential source candidates, i.e., utilized drilling fluids (mud filtrate, supply water) from the target well site, Early - Late Cretaceous aquifers and Late Jurassic - Late Triassic formation waters from adjacent wells and fields. Geochemical affinities of CCA water with groundwater from an Early Cretaceous aquifer postulate the presence one single horizon for active water inflow. Non-reactive elements (Na, Cl) and environmental isotopes (δ2H, δ18O) were found to be most suited tools for fluid identification. 2H/1H and 18O/16O ratios of supply water and mud filtrate are close to global meteoric water composition, whereas formation waters are enriched in 18O. Elevated SO4 and K concentrations and extreme alkaline conditions for CCA water indicates the occurrence of minor secondary alteration processes, such the contact of inflowing groundwater with cement or fluid mixing with minor portions of KCl additives. The presented technology in this study enables the detection of high CCA pressure and fluid leakages sources, thereby allowing workover engineers to plan for potential remedial actions prior to moving the rig to the affected well; hence significantly reducing operational costs. Appropriate remedial solutions can be prompted for safe well abandonment as well as to resume operation at the earliest time.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"19 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81946582","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":"Covid Best Practices for Cyber Risk Management","authors":"Syed M. Belal, Md. Abdur Rahman","doi":"10.2118/208113-ms","DOIUrl":"https://doi.org/10.2118/208113-ms","url":null,"abstract":"\u0000 If we learned anything from the year 2020, it is that we need to be more prepared for the unexpected. We need to be working to enable our business to be more resilient in the face of unexpected challenges. We strongly believe that for the industrial sector, the most effective way to enable resiliency is to ensure you have integrity in your operational technology (OT).\u0000 The objective of this paper is to identify and manage the risk that arose from managing plants remotely. As a result of COVID-19, people started working and managing from home. While this needed to be done to keep businesses running, many risks were introduced as well. How to manage them effectively to reduce cyber risk to an acceptable level will be discussed.\u0000 Industrial frameworks to identify security gaps, and thus risk, were considered, such as ISA-99/IEC-62443, NIST, ISO-27001, and Top CIS controls. New practices critical infrastructure followed to reduce infection rates were identified from interviews and surveys conducted by PAS, part of Hexagon, of our customers who work with critical infrastructure. These new practices were then compared to the industrial risk management framework to identify the severity of the threats. Once these were identified, mitigation plans were recommended to reduce the risk to an acceptable level.\u0000 Because of this rapid shift to run the plant remotely, there was an over-provisioning of access in the early stages of the pandemic – i.e., giving more direct access to the industrial control system environment. This was not wise from a security standpoint, but the priority was to keep businesses up and running, so they were ready to take that risk.\u0000 Now that some organizations have decided to continue with remote work, it is imperative to verify all remote access considers the least privileged access concept.\u0000 Remote access is like a bridge that bypasses all the controls implemented. Having a remote access vulnerability will help bad actors break into the network and cause catastrophic damage. Though this paper focuses on remote access risk introduced by the COVID-19 pandemic, you can apply the findings to all remote access into critical infrastructure.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"87 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84266448","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":"Downhole Steam Generation for Green Heavy Oil Recovery","authors":"Abdulsallam Al-Mashrafi, M. Fani, F. Asfand, M. Amani, M. Assadi, Nader Mosavat","doi":"10.2118/207597-ms","DOIUrl":"https://doi.org/10.2118/207597-ms","url":null,"abstract":"\u0000 The ultimate target of heavy oil recovery is to enhance oil mobility by transferring steam's thermal energy to the oil phase, incrementing its temperature, and reducing heavy oil's viscosity. While the various types of steam floods such as Cyclic Steam Injection (CSI) and Steam-Assisted Gravity Drainage (SAGD) are widely used worldwide, they have certain limitations that need further improvements. Notably, in surface steam generation systems, downhole steam quality is around 70% which means that 30% of latent heat is lost while steam travels from the surface to the pre-determined downhole location.\u0000 Downhole steam generation (DHSG) can be a viable alternative for the surface steam injection in which steam will be generated downhole instead of on the surface. The asserted method presents significant benefits such as preventing steam quality loss, decreasing the environmental effects, and enhancing the heavy oil recovery by co-injecting the flue gas products such as CO2, and consequently, the economic outcomes will be increased.\u0000 In this research, a comprehensive techno-economic case study has been conducted on a heavy oil reservoir to evaluate the economic and technical advantages of DHSG compared to surface steam generation. Various technical expenses and revenues such as investment costs, operating costs, royalties, and taxes have been considered in a simulation model in MATLAB. This DHSG feasibility assessment has been performed using data of a heavy oil reserve currently under steam flood. Results showed that DHSG could increase up to 50% economic and technical interest than conventional steam injection projects. One of the outstanding benefits of DHSG is the reduction of heat loss. Since steam is produced in-situ, either downhole or in the reservoir, no waste of heat occurs. Typically, most heat losses happen on surface lines and wellbore during steam injection from the surface, which accounts for approximately 32%. Thus, this issue is excluded using the DHSG method.\u0000 The results of the recent effort fit well into the current industry's requirements. DHSG can (1) increase the rate of heavy oil production, (2) decrease the extra expenses, and (3) dwindle the environmental side effects of CO2 emission of surface steam generation. Compared with conventional thermal methods, in DHSG, the steam to oil ratio remains constant with depth change while the desired steam quality can be achieved at any location. The asserted benefits can ultimately optimize the steam injection with a significant reduction in UTC, hence, improved profitability.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"43 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90699857","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":"Transformation Management Office as a Vehicle to Accelerate Digital Transformation","authors":"Khaled Al Blooshi, H. Mohammed, Khalid Yousef Al Awadhi, Pedro Carreiras, Maitha Al Mansoori, Waad Saeed Al Ameri, Mouza Sulaiman Al Houqani, Amal ALwedami, Rasha Humaid Saleh, A. Alsaeedi, Ayesha Al Hemeiri","doi":"10.2118/207222-ms","DOIUrl":"https://doi.org/10.2118/207222-ms","url":null,"abstract":"\u0000 ADNOC has identified digital technology as a key enabler of sustainable value creation as it delivers its 2030 smart growth strategy. The Transformation Management Office (TMO) has been established to accelerate delivery of ADNOC's digital transformation, actively manage its digital portfolio, build digital capabilities, lead the digital empowerment of local talent and institute a ‘new way to operate’. By doing so, it supports ADNOC's ambition to be a data-driven organization, adopting new ways of working, and delivering greater value, while adapting swiftly to competitive threats to its core business.\u0000 ADNOC's digital transformation is changing the way the organization operates. The adoption of digital technologies, including big data, Artificial Intelligence and Machine Learning and robotics will optimize production, improve efficiency, reduce risk and de-risk multibillion dollar projects. To achieve this requires a change of company culture across the full value chain. The decision to establish the Transformation Management Office was a recognition that ADNOC must evolve to meet the realities of the new energy era by adopting advanced digital technologies to ensure we remain resilient and agile, by making the most of our resources, enhancing our performance, empowering our people and delivering greater value for our shareholders, Abu Dhabi and the UAE.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"25 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73447594","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":"Realtime Wellbore Digitalization for Stimulations Using Multi-Well Fiber Optics","authors":"Xinyang Li, A. Chavarria, Y. Oukaci","doi":"10.2118/207710-ms","DOIUrl":"https://doi.org/10.2118/207710-ms","url":null,"abstract":"\u0000 Distributed Fiber-optic Sensing (DFOS) provides real-time data acquisition, monitoring and diagnostics for well stimulation and well spacing assessment. These include measurements of Distributed Acoustic Sensing (DAS) with high frequency acoustics in treatment wells, and low frequency strain/temperature sensing in offset monitor ones. The goal of this integrated study is to show the value of multi-well fiber sensing for real time fracturing diagnostics and stimulation optimization. By integrating near field injection to far field strain responses we assess overall reservoir development.\u0000 The availability of fibers on both the treatment well and a nearby observation well allows us to investigate the near-wellbore injection profile and the far-field strain fracture propagation. Quantitative strain levels clearly respond to the effects of well distance, location and treatment well stimulation design. Monitoring well strain measurements of fracture density and triggered stimulated span were logged and compared to acoustic signals in the nearfield stage by stage. DAS interpretation was conducted during the treatment of each stage indicating the effectiveness and efficiency of the completion design. Results show that this is a very effective tool to better understand the performance of the fracturing treatment by digital transformation using DAS data. In addition, acoustic and strain measurements also validated its diagnostic capability for real-time operation monitoring.\u0000 In this presentation we show how the near-field acoustic and far-field strain measurements allow for better understanding of the completion efficiency. This is by assessing the far field response to quantified DAS injected signals in the treatment. This analysis takes advantage of fiber installation on both the treatment and nearby monitor well. The fluid and proppant allocations in the near field were performed on the treatment well using relative acoustic intensities. Meanwhile, the fracture propagation induced strain change is recorded by the offset fiber well. Using this fiber data reveals dominant clusters and stage bias from near-field injection profile. Simultaneously the far-field identified fracture counts from strain further enable a geomechanical assessment of the stimulated reservoir and assess the effectiveness of the completion design.\u0000 Multiple DAS fiber equipped wells not only provide single diagnostic tool for each of the fiber well, but also demonstrate significant integrated assessment of the stimulation effectiveness, completion efficiency, well interaction, and reservoir description. Availability of near and far field measurements constitutes an important tool to assess properties of the reservoir. Here we show how different vantage points can help illuminate a fracturing program in unconventional reservoirs.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90146267","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}