|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Summary Working in the oil industry comes with unique challenges and risks, and so extra precautions and safety measures coupled with strict environmental compliance must be applied. Contrary to the common belief that strict safety enforcement could hinder smooth operations, the deployment of new technologies and enhanced solutions of processes has enabled operational excellence (OE) and improved safety performance. In this paper, we demonstrate health, safety, and environment performance improvement through implementing two main initiatives: The first category has initiatives that require less intervention or personnel; for example, the deployment of cableless pressure sensors or permanent monitoring systems in key wells to ensure continuous real-time pressure data to monitor reservoir pressure. The second category has initiatives that mitigate traditional health, safety, and environment risks; for example, through use of multiphase flow meters (MPFMs) to collect accurate and continuous flow measurements instead of traditional well testing. Optimizing operations costs while maintaining a high-level of safety is achieved through a dedicated team working in a state-of-the-art Production Operations Surveillance Hub (POSH), which enables the monitoring of wells in real time, making production optimization decisions, and ensuring a high level of well integrity via close monitoring of wells and assets.
Geoscience technology company CGG has launched SeaScope, a pollution monitoring service, as part of its growing portfolio of environmental products. SeaScope combines remote-sensing science, Earth-observation data, machine-learning, and high-performance computing to provide information on sea-surface slicks for industries to strengthen situational awareness of the interaction between offshore assets, coastal facilities, local vessel activity, and the natural marine environment. For energy companies with offshore assets, SeaScope's proactive monitoring enables the establishment of production-water baselines and provides early detection of anomalous events and third-party pollution incidents, as well as surveillance of natural seeps. It also supports the creation of a growing evidence base of responsible operations for stakeholders such as operators, regulators, investors, and insurers. SeaScope was developed with the support of the European Space Agency and a group of energy companies and emergency-response organizations.
Abstract Distributed Fiber Optics (DFO) technology has been the new face for unconventional well diagnostics. This technology focuses on measuring Distributed Acoustic Sensing (DAS) and Distrusted Temperature Sensing (DTS) to give an in-depth understanding of well productivity pre and post stimulation. Many different completion design strategies, both on surface and downhole, are used to obtain the best fracture network outcome; however, with complex geological features, different fracture designs, and fracture driven interactions (FDIs) effecting nearby wells, it is difficult to grasp a full understanding on completion design performance for each well. Validating completion designs and improving on the learnings found in each data set should be the foundation in developing each field. Capturing a data set with strong evidence of what works and what doesn't, can help the operator make better engineering decisions to make more efficient wells as well as help gauge the spacing between each well. The focus of this paper will be on a few case studies in the Bakken which vividly show how infill wells greatly interfered with production output. A DFO deployed with a 0.6" OD, 23,000-foot-long carbon fiber rod to acquire DAS and DTS for post frac flow, completion, and interference evaluation. This paper will dive into the DFO measurements taken post frac to further explain what effects are seen on completion designs caused by interferences with infill wells; the learnings taken from the DFO post frac were applied to further escalate the understanding and awareness of how infill wells will preform on future pad sites. A showcase of three separate data sets from the Bakken will identify how effective DFO technology can be in evaluating and making informed decisions on future frac completions. In this paper we will also show and discuss how DFO can measure real time FDI events and what measures can be taken to lessen the impact on negative interference caused by infill wells.
Abstract Uniformity of proppant distribution among multiple perforation clusters affects treatment efficiency in multistage fractured wells stimulated using the plug-and-perf technique. Multiple physical phenomena taking place in the well and perforation tunnels can cause uneven proppant distribution among multiple clusters. The problem has been studied in the recent years with experimental and computational fluid dynamics (CFD) methods, which provide useful insights but are impractical for routine designs. Simplified models that incorporated the proppant transport efficiency (PTE) correlation derived from the CFD results in a hydraulic fracture model have been also presented in literature. In this paper, we present a numerical model that simulates the transient proppant slurry flow in the wellbore, considering proppant transport and settling including bed formation, rate- and concentration-dependent pressure drop, PTE, and dynamic pressure coupling with the hydraulic fractures. The model is efficient and is designed to be an independent wellbore transport model so it can be integrated with any fracture models, including fully 3D and/or complex fracture network models, for practical design optimization. The model predictions are compared and found to agree with previously published studies. Parametric studies demonstrate sensitivity of proppant distribution to grain size, fluid viscosity, and pumping rate for fixed perforation designs. Analysis of the simulation results shows that the dominant cause of uneven proppant distribution is proppant inertia. Possible slurry stratification is less important, except for the cases with relatively low flow rates and near toe clusters. Accordingly, proppant distribution is less sensitive to perforation phasing than to the number of perforations in clusters. Alterations of the number of perforations per cluster within a stage enable achieving more even proppant distribution.
Wu, Yinghui (Silixa LLC) | Hull, Robert (Silixa LLC) | Tucker, Andrew (Apache Corp.) | Rice, Craig (Apache Corp.) | Richter, Peter (Silixa LLC) | Wygal, Ben (Silixa LLC) | Farhadiroushan, Mahmoud (Silixa Ltd.) | Trujillo, Kirk (Silixa LLC) | Woerpel, Craig (Silixa LLC)
Abstract Distributed fiber-optic sensing (DFOS) has been utilized in unconventional reservoirs for hydraulic fracture efficiency diagnostics for many years. Downhole fiber cables can be permanently installed external to the casing to monitor and measure the uniformity and efficiency of individual clusters and stages during the completion in the near-field wellbore environment. Ideally, a second fiber or multiple fibers can be deployed in offset well(s) to monitor and characterize fracture geometries recorded by fracture-driven interactions or frac-hits in the far-field. Fracture opening and closing, stress shadow creation and relaxation, along with stage isolation can be clearly identified. Most importantly, fracture propagation from the near to far-field can be better understood and correlated. With our current technology, we can deploy cost effective retrievable fibers to record these far-field data. Our objective here is to highlight key data that can be gathered with multiple fibers in a carefully planned well-spacing study and to evaluate and understand the correspondence between far-field and near-field Distributed Acoustic Sensing (DAS) data. In this paper, we present a case study of three adjacent horizontal wells equipped with fiber in the Permian basin. We can correlate the near-field fluid allocation across a stage down to the cluster level to far-field fracture driven interactions (FDIs) with their frac-hit strain intensity. With multiple fibers we can evaluate fracture geometry, the propagation of the hydraulic fractures, changes in the deformation related to completion designs, fracture complexity characterization and then integrate the results with other data to better understand the geomechanical processes between wells. Novel frac-hit corridor (FHC) is introduced to evaluate stage isolation, azimuth, and frac-hit intensity (FHI), which is measured in far-field. Frac design can be evaluated with the correlation from near-field allocation to far-field FHC and FHI. By analyzing multiple treatment and monitor wells, the correspondence can be further calibrated and examined. We observe the far-field FHC and FHI are directly related to the activities of near-field clusters and stages. A leaking plug may directly result in FHC overlapping, gaps and variations in FHI, which also can be correlated to cluster uniformity. A near-far field correspondence can be established to evaluate FHC and FHI behaviors. By utilizing various completion designs and related measurements (e.g. Distributed Temperature Sensing (DTS), gauges, microseismic etc.), optimization can be performed to change the frac design based on far-field and near-field DFOS data based on the Decision Tree Method (DTM). In summary, hydraulic fracture propagation can be better characterized, measured, and understood by deploying multiple fibers across a lease. The correspondence between the far-field measured FHC and FHI can be utilized for completion evaluation and diagnostics. As the observed strain is directly measured, completion engineering and geoscience teams can confidently optimize their understanding of the fracture designs in real-time.
Abstract Low-frequency distributed acoustic sensing (LF-DAS) has been used for hydraulic fracture monitoring and characterization. Large amounts of DAS data have been acquired across different formations. The low-frequency components of DAS data are highly sensitive to mechanical strain changes. Forward geomechanical modeling has been the focus of current research efforts to better understand the LF-DAS signals. Moreover, LF-DAS provides the opportunity to quantify fracture geometry. Recently, Liu et al. (2020a;2020b) proposed an inversion algorithm to estimate hydraulic fracture width using LF-DAS data measured during multifracture propagation. The LF-DAS strain data is linked to the fracture widths through a forward model developed based on the Displacement Discontinuity Method (DDM). In this study, we firstly investigated the impacts of fracture height on the inversion results through a numerical case with a four-cluster completion design. Then we discussed how to estimate the fracture height based on the inversion results. Finally, we applied the inversion algorithm to two field examples. The inverted widths are not sensitive to the fracture height. In the synthetic case, the maximum relative error is less than 10% even when the fracture height is two times of the true value. After obtaining the fracture width, the fracture height can be estimated by matching the true strain data under various heights with a strong smooth weight. The error between the calculated strain and true strain decreases as the height is getting close to the true value. In the two field examples, the temporal evolutions of both width summation of all fractures and the width of each fracture show consistent behaviors with the field LF-DAS measurements. The calculated strain data from the forward model matches well with the field LF-DAS strain data. The results demonstrate the robustness and accuracy of the proposed inversion algorithm.
Huckabee, Paul (Shell Exploration & Production Co.) | Ledet, Chris (Shell Exploration & Production Co.) | Ugueto, Gustavo (Shell Exploration & Production Co.) | Tolle, John (Shell Exploration & Production Co.) | Mondal, Somnath (Shell Exploration & Production Co.)
Abstract This paper presents design considerations and field trial applications for determining practical dimensions and limits for interdependencies associated with stage length, perforation clusters and limited entry pressures. Recent applications by multiple authors and companies have begun to reverse the decade-long trend of reducing stage length and perforation spacing, in favor of extending stage lengths, to capture free cash flow value for unconventional resource development. Aggressive limited entry has been an enabler for successful extended stage length applications. Multiple authors have advocated "eXtreme Limited Entry" (XLE) applications. We present diagnostics data and applications that challenges the need for XLE and better constrains the necessary amount of limited entry pressures for effective stimulation distribution for resource development across multiple North American Basins. Data is presented from integrated application of field trials, stimulation distribution diagnostics, and well performance analysis. Field trials and well performance analysis are from the Permian Delaware Basin Wolfcamp. The field trials include both: greater perforation cluster intensities for base design stage lengths; and extended stage lengths of 50% greater than the base designs. Diagnostics are from multiple North American Basins and include discrete treatment pressure diagnostics and optic fiber distributed sensing. Data is presented to quantify the magnitude and variability for components necessary for maintaining active fracture extension for multiple perforation clusters. Components include: fracture breakdown pressures; in-situ stress, net fracture extension pressure, and near wellbore complexity pressure drop. Data and examples are presented from multiple wells, and resource development areas, to show the variability in measured treatment pressures for different length scale dimensions. This variability is used to determine the amount of limited entry pressure required to maintain fracture extension, dependent on the stage length dimension. Although Aggressive Limited Entry (ALE) is generally required to enable effective stimulation distribution and extended stage lengths in multiple cluster stages, examples are presented that demonstrate XLE is generally not required. We also discuss some of the considerations and observations that limit perforation cluster spacing intensities. Well performance data from the field trials is presented to validate the applications. This work demonstrates the value of integrated application of field trials, stimulation distribution diagnostics, and well performance analysis to capture free cash flow value from improved completions and stimulation designs. The discussion will include an assessment of future opportunities for further extension of stage length dimensions.
Abstract In the present cost-constrained environment, it is critical that operators effectively complete their wells while minimizing capital expenditure. Optimization efforts focus on increasing recovery factor by managing landing zone, increasing the number of effective fractures, increasing the size of the fractures, and increasing the length of the lateral, while reducing the total number of stages and job size, without sacrificing efficient proppant and fluid delivery. The same pressure to reduce expenditure also impacts decision making on diagnostic evaluation, reducing operators to ‘free’ or low-cost feedback, like surface production rates and decline curves. Operators are responding to these challenges by utilizing a combination of lower cost, post-completion diagnostics like deployed fiber optics, downhole camera evaluation of perforations and radioactive tracers. These less expensive options allow for a broader scope and number of diagnostic inquiries, whereas a permanent fiber may prove to be cost-prohibitive, reducing diagnostic focus to one well, in one part of a play. Combining differing diagnostic technologies enhances the overall description of the well and reservoir behaviors and improves confidence in their interpretation of stimulation and production efficiency; furthermore, where a single diagnostic measurement may be unlikely to justify dramatic change in a completion strategy, a combination of data points from different domains can and does support design change that leads to rapid, real world performance improvements. Care is needed in the conclusions drawn when utilizing complimentary diagnostics due to the differences in depth of investigation and the non-unique interpretation of some data types. This paper discusses three post-completion diagnostic technologies, perforation evaluation by downhole camera, radioactive tracers, and distributed acoustic and temperature sensing (DAS+DTS) data and their respective physical measurements, strengths and weaknesses and how they can be combined to better understand well and reservoir behavior. It concludes with a review of completion optimization efforts from the Rockies area, where these post-completion diagnostic technologies were applied in the evaluation of eXtreme Limited Entry (XLE) trials. A statistical analysis of the RA tracer, downhole camera measurement of perforation area and deployed fiber optic acquisition of DAS+DTS reveals no correlation between diagnostic answers, indicating no one diagnostic measurement can accurately predict the other, such that it could substitute for that diagnostic and provide the same answer. Asking the right question can often enhance the value of diagnostic descriptions of the system in question. Those answers often lead to the next question and clear the path forward in advancing completion optimization. Complimentary diagnostics facilitate a more complete understanding of stimulation and production performance when compared, increasing confidence when they agree. When one or more appear to disagree, the different respective physical measurements and depths of investigation often reveal a more complete and complex understanding of stimulation and production efficiency. As an aggregate they provide clarity on the effect of efforts to create conductive pathways into the reservoir, allowing operators increased control over the resulting production.
Abstract In this paper, the authors examine the impacts of natural fractures on the distribution of slurry in a well with a permanent fiber installation and drill bit geomechanics data. Additionally, they propose a framework for further investigation of natural fractures on slurry distribution. As part of the Marcellus Shale Energy and Environmental Laboratory (MSEEL), the operator monitored the drilling of a horizontal Marcellus Formation well with drill bit geomechanics, and subsequent stimulation phase with a DAS/DTS permanent fiber installation. Prior to the completion, the authors used an analytical model to examine the theoretical distribution of slurry between perforation clusters from a geomechanics framework. A perforation placement scheme was then developed to minimize the stress difference between clusters and to segment stages by the intensity of natural fractures while conforming to standard operating procedures for the operator's other completions. The operator initially began completing the well with the geomechanics-informed perforation placement plan while monitoring the treatment distribution with DAS/DTS in real time. The operator observed several anomalous stages with treating pressures high enough to cause operational concerns. The operator, fiber provider, and drill bit geomechanics provider reviewed the anomalous stages’ treatment data, DAS/DTS data, and geomechanics data and developed a working hypothesis. They believed that perforation clusters placed in naturally fractured rock were preferentially taking the treatment slurry. This phenomenon appeared to cause other clusters within the stage to sand-off or become dormant prematurely, resulting in elevated friction pressure. This working hypothesis was used to predict upcoming stages within the well that would be difficult to treat. Another perforation placement plan was developed for the second half of the well to avoid perforating natural fractures as an attempt to mitigate operational issues due to natural fracture dominated distribution. Over the past several years, the industry's growing understanding of geomechanical and well construction variability has created new limited-entry design considerations to optimize completion economics and reduce the variability in cluster slurry volumes. Completion engineers working in naturally fractured fields, such as the Marcellus, should consider the impact the natural fractures have on slurry distribution when optimizing their limited-entry designs and stage plan.