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Suarez-Rivera, Roberto (W. D. Von Gonten Laboratories) | Panse, Rohit (W. D. Von Gonten Laboratories) | Sovizi, Javad (Baker Hughes) | Dontsov, Egor (ResFrac Corporation) | LaReau, Heather (BP America Production Company, BPx Energy Inc.) | Suter, Kirke (BP America Production Company, BPx Energy Inc.) | Blose, Matthew (BP America Production Company, BPx Energy Inc.) | Hailu, Thomas (BP America Production Company, BPx Energy Inc.) | Koontz, Kyle (BP America Production Company, BPx Energy Inc.)
Abstract Predicting fracture behavior is important for well placement design and for optimizing multi-well development production. This requires the use of fracturing models that are calibrated to represent field measurements. However, because hydraulic fracture models include complex physics and uncertainties and have many variables defining these, the problem of calibrating modeling results with field responses is ill-posed. There are more model variables than can be changed than field observations to constrain these. It is always possible to find a calibrated model that reproduces the field data. However, the model is not unique and multiple matching solutions exist. The objective and scope of this work is to define a workflow for constraining these solutions and obtaining a more representative model for forecasting and optimization. We used field data from a multi-pad project in the Delaware play, with actual pump schedules, frac sequence, and time delays as used in the field, for all stages and all wells. We constructed a hydraulic fracturing model using high-confidence rock properties data and calibrated the model to field stimulation treatment data varying the two model variables with highest uncertainty: tectonic strain and average leak-off coefficient, while keeping all other model variables fixed. By reducing the number of adjusting model variables for calibration, we significantly lower the potential for over-fitting. Using an ultra-fast hydraulic fracturing simulator, we solved a global optimization problem to minimize the mismatch between the ISIPs and treatment pressures measured in the field and simulated by the model, for all the stages and all wells. This workflow helps us match the dominant ISIP trends in the field data and delivers higher confidence predictions in the regional stress. However, the uncertainty in the fracture geometry is still large. We also compared these results with traditional workflows that rely on selecting representative stages for calibration to field data. Results show that our workflow defines a better global optimum that best represents the behavior of all stages on all wells, and allows us to provide higher-confidence predictions of fracturing results for subsequent pads. We then used this higher confidence model to conduct sensitivity analysis for improving the well placement in subsequent pads and compared the results of the model predictions with the actual pad results.
Abstract Well spacing and stimulation design are amongst the highest impact design variables which can dictate the economics of an unconventional development. The objective of this paper is to showcase a numerical simulation workflow, with emphasis on the hydraulic fracture simulation methodology, which optimizes well spacing and completion design simultaneously. The workflow is deployed using Cloud Computing functionality, a step-change over past simulation methods. Workflow showcased in this paper covers the whole cycle of 1) petrophysical and geomechanical modeling, 2) hydraulic fracture simulations and 3) reservoir simulation modeling, followed by 4) design optimization using advanced non-linear methods. The focus of this paper is to discuss the hydraulic fracture simulation methods which are an integral part of this workflow. The workflow is deployed on a dataset from a multi-well pad completed in late 2018 targeting two landing zones in the Vaca Muerta shale play. On calibrated petrophysical and geomechanical model, hydraulic fracture simulations are conducted to map the stimulated rock around the wellbores. Finely gridded base model is utilized to capture the property variation between layers to estimate fracture height. The 3d discrete fracture network (DFN) built for the acreage is utilized to pick the natural fracture characteristics of the layers intersected by the wellbores. The methodology highlights advances over the past modeling approaches by including the variation of discrete fracture network between layers. The hydraulic fracture model in conjunction with reservoir flow simulation is used for history matching the production data. On the history matched model, a design of experiments (DOE) simulation study is conducted to quantify the impact of a wide range of well spacing and stimulation design variables. These simulations are facilitated by the recent deployments of cloud computing. Cloud computing allows parallel running of hundreds of hydraulic fracturing and reservoir simulations, thereby allowing testing of many combinations of stimulation deigns and well spacing and reducing the effective run time from 3 months on a local machine to 1 week on the cloud. Output from the parallel simulations are fitted with a proxy model to finally select the well spacing and stimulation design variables that offer the minimum unit development cost i.e. capital cost-$ per EUR-bbl. The workflow illustrates that stimulation design and well spacing are interlinked to each other and need to be optimized simultaneously to maximize the economics of an unconventional asset. Using the workflow, the team identified development designs which increase EUR of a development area by 50-100% and reduce the unit development cost ($/bbl-EUR) by 10-30%.
Abstract Early hydraulic fracturing completions in the Vaca Muerta Formation in central Argentina have incorporated the use of conventional fluid systems, such as linear and crosslinked guar-based polymers. Within the past few years, however, the benefits of viscosifying friction reducers (VFR) have been demonstrated in the industry, predominantly within the United States. The objective of this project was to trial the VFR fluid technology in fracturing operations in this area for potential use for full field development. After studying the potential advantages of the VFR technology including cost savings, simplified operations and enhanced well production, a project was initiated to determine if those same benefits could be obtained. To accomplish this, studies were performed to ensure economic and technical justification through a stepwise process of laboratory testing, logistical and operational considerations, a single well field trial, and a five well development phase evaluation project. The pilot project was performed on a horizontal, 27 stage lateral in the Aguada Pichana Oeste field in the Neuquen Basin of Argentina. The five well development phase evaluation project was performed in the Lindero Atravesado field. Positive laboratory test results led to a field trial using this technology, during which several benefits of the VFR fluid system began to emerge. Operational efficiency was an early success, including a reduction in the quantity of chemicals on location, more simplified pumping schedules, and low pumping pressures. Secondly, significant cost savings were realized compared to previous fluid system packages. Finally, positive production results were observed, leading to the decision to incorporate this technology into full field development operations. This paper will review the results of the stepwise evaluation process along with a focus on the economic benefits and well production from the development phase evaluation project. This paper describes the transition by Pan American Energy (PAE) from conventional fracturing fluids to viscosifying friction reducer (VFR) technology in the Vaca Muerta Formation. The paper highlights the performance of a relatively new treatment fluid which delivered positive results in a strategic international asset. The project has led to full field development using this technology. The same efficiencies provided by this system can potentially be realized through applications in other basins.
Abstract Losses, wellbore instability, and influxes during drillings operations in unconventional fields result from continuous reactivity to the drilling fluid causing instability in the microfractured limestone of the Quintuco Formation in Argentina. This volatile situation becomes more critical when drilling operations are navigating horizontally through the Vaca Muerta Formation, a bituminous marlstone with a higher density than the Quintuco Formation. Controlling drilling fluids invasion between the communicating microfractures and connecting pores helps to minimize seepage losses, total losses, wellbore fluid influxes, and instabilities, reducing the non-productive time (NPT) caused by these problems during drilling operations. The use of conventional sealants – like calcium carbonate, graphite, asphalt, and other bridging materials – does not guarantee problem-free drilling operations. Also, lost circulation material (LCM) is restricted because the MWD-LWD tools clearances are very narrow in these slim holes. The challenge is to generate a strong and resistant seal separating the drilling fluid and the formation. Using an ultra-low-invasion technology will increase the operative fracture gradient window, avoid fluid invasion to the formation, minimize losses, and stop the cycle of fluid invasion and instability, allowing operations to maintain the designed drilling parameters and objectives safely. The ultra-low-invasion wellbore shielding technology has been applied in various fields, resulting in significantly improved drilling efficiencies compared to offset wells. The operator has benefited from the minimization of drilling fluids costs and optimization in drilling operations, including reducing the volume of oil-based drilling fluids used per well, fewer casing sections, and fewer requirements for cementing intervals to solve lost circulation problems. This paper will discuss the design of the ultra-low-invasion technology in an oil-based drilling fluid, the strategy for determining the technical limits for application, the evaluation of the operative window with an increase in the fracture gradient, the optimized drilling performance, and reduction in costs, including the elimination of NPT caused by wellbore instability.
Kazak, Andrey (Center for Hydrocarbon Recovery, Skolkovo Institute of Science and Technology) | Simonov, Kirill (Center for Hydrocarbon Recovery, Skolkovo Institute of Science and Technology) | Kulikov, Victor (PicsArt Inc. and Skolkovo Institute of Science and Technology)
Summary The modern focused ion beam-scanning electron microscopy (FIB-SEM) allows imaging of nanoporous tight reservoir-rock samples in 3D at a resolution up to 3 nm/voxel. Correct porosity determination from FIB-SEM images requires fast and robust segmentation. However, the quality and efficient segmentation of FIB-SEM images is still a complicated and challenging task. Typically, a trained operator spends days or weeks in subjective and semimanual labeling of a single FIB-SEM data set. The presence of FIB-SEM artifacts, such as porebacks, requires developing a new methodology for efficient image segmentation. We have developed a method for simplification of multimodal segmentation of FIB-SEM data sets using machine-learning (ML)-based techniques. We study a collection of rock samples formed according to the petrophysical interpretation of well logs from a complex tight gas reservoir rock of the Berezov Formation (West Siberia, Russia). The core samples were passed through a multiscale imaging workflow for pore-space-structure upscaling from nanometer to log scale. FIB-SEM imaging resolved the finest scale using a dual-beam analytical system. Image segmentation used an architecture derived from a convolutional neural network (CNN) in the DeepUNet (Ronneberger et al. 2015) configuration. We implemented the solution in the Pytorch® (Facebook, Inc., Menlo Park, California, USA) framework in a Linux environment. Computation exploited a high-performance computing system. The acquired data included three 3D FIB-SEM data sets with a physical size of approximately 20 × 15 × 25 µm with a voxel size of 5 nm. A professional geologist manually segmented (labeled) a fraction of slices. We split the labeled slices into training, validation, and test data. We then augmented the training data to increase its size. The developed CNN delivered promising results. The model performed automatic segmentation with the following average quality indicators according to test data: accuracy of 86.66%, precision of 54.93%, recall of 83.76%, and F1 score of 55.10%. We achieved a significant boost in segmentation speed of 14.5 megapixel (MP)/min. Compared with 0.18 to 1.45 MP/min for manual labeling, this yielded an efficiency increase of at least 10 times. The presented research work improves the quality of quantitative petrophysical characterization of complex reservoir rocks using digital rock imaging. The development allows the multiphase segmentation of 3D FIB-SEM data complicated with artifacts. It delivers correct and precise pore-space segmentation, resulting in little turn-around-time saving and increased porosity-data quality. Although image segmentation using CNNs is mainstream in the modern ML world, it is an emerging novel approach for reservoir-characterizationtasks.
Olusola, Bukola Korede (Schulich School of Engineering, University of Calgary) | Orozco, Daniel (Schulich School of Engineering, University of Calgary) | Aguilera, Roberto (Schulich School of Engineering, University of Calgary)
Summary Recent improved‐oil‐recovery and enhanced‐oil‐recovery (EOR) methods in shale reservoirs use huff ‘n’ puff gas injection (H&P). Investigating the technical and economic impact of this technology for one well is challenging and time consuming, and even more so when the petroleum company is planning H&P and refracturing (RF) jobs in multiple wells. Thus, in this paper we present an original methodology to learn how to perform these tasks faster and at lower cost to improve oil recovery. The procedure is explained with the use of an actual H&P gas‐injection pilot horizontal well in the Eagle Ford Shale, the performance of which is matched using the methodology developed in this paper. The methodology includes use of an original climbing‐swarm (CS) derivative‐free algorithm that drives, without human intervention, desktop computer or laptop material‐balance (MatBal) and net‐present‐value (NPV) calculations. The code was written in open-source Python programming language. Following history match, the methodology demonstrates that significant improvements in oil recovery can be obtained by injecting gas at larger rates during shorter periods of time (as opposed to injecting gas at lower rates during longer periods of time). Once oil‐recovery improvement in a pilot horizontal well is demonstrated, the methodology is extended to the analysis of H&P gas injection and RF in horizontal wells and shale reservoirs that have not yet been developed or are in initial stages of development; this provides a preliminary assessment of H&P and RF potential. Results indicate that oil recovery and NPV from multiple wells can be improved significantly by a strategic combination of H&P gas injection and RF. A combination of derivative‐free optimization algorithms, MatBal calculations, and NPVs permits optimizing when to start the H&P gas‐injection project, the optimum gas‐injection rates (GIRs) and time span of injection, the reservoir pressure at which gas injection should be started in each cycle, and the time span during which the well should produce oil, before starting a new cycle of gas injection. The development strategy of shale‐oil reservoirs could be improved significantly if the possibility of H&P gas injection is considered before field development. This could be the case of the Eagle Ford Shale in Mexico, La Luna Shale in Colombia and Venezuela, Vaca Muerta Shale in Argentina, and other shale‐oil reservoirs worldwide. The paper contributes the development of an original methodology, which includes use of a derivative‐free algorithm we call CS. CS drives the desktop computer or laptop to perform MatBal and NPV calculations, without human intervention, once the optimization process is started. The methodology improves oil recovery and NPV from a single horizontal well or from multiple horizontal wells operating under H&P gas injection.
Oil production from the Vaca Muerta Shale has surpassed the record level prior to the crash nearly a year ago, as operators in the Argentine formation belatedly move toward full development mode. Rystad reported production hit 124,000 B/D in December as drilling and completions work came back in the oil window at the eastern edge of the formation. Farther west in the gas window, they are still waiting for a comeback. "Oil wells put on production rebounded sharply in November and December, pushing the new oil well count to an average of about 11 wells per month," said Artem Abramov, head of shale research at Rystad Energy. The sources of the growth were international companies, led by an independent, Vista, producing 15,000 B/D, and Shell at 13,000 B/D.
PowerChina is planning to build a railway in Argentina to transport crude oil and natural gas from the Vaca Muerta region to the port city of Bahia Blanca. The state-owned company is engaged in discussions with Argentina's state-owned rail ADIF, which would connect the Vaca Muerta shale region and the petrochemical and refinery hub. The railway could also ship sand for fracturing operations. "There is a concrete plan that we have been working on for almost two years," PowerChina's Argentina President Tu Shuiping told Reuters. "We were talking with people from ADIF to see how the project can be presented and then seek joint financing," Shuiping noted plans for the rail line stalled under Argentina's previous administration due to a lack of financing options, but the project is moving forward under the current administration and China could provide the financing for the $1.2–1.5 billion project.
Summary Wells are sometimes deformed due to geomechanical shear slip, which occurs on a localized slip surface, such as a bedding plane, fault, or natural fracture. This can occur in the overburden above a conventional reservoir (during production) or within an unconventional reservoir (during completion operations). Shear slip will usually deform the casing into a recognizable shape, with lateral offset and two opposite-trending bends, and ovalized cross sections. Multifinger casing caliper tools have a recognizable response to this shape and are especially useful for diagnosing well shear. Certain other tools can also provide evidence for shear deformation. Shear deformations above a depleting, compacting reservoir are usually due to slip on bedding planes. They usually occur at multiple depths and are driven by overburden bending in response to reservoir differential compaction. Shear deformations in unconventional reservoirs, for the examples studied, have been found to be caused by slip on bedding planes and natural fractures. In both cases, models, field data, and physical reasoning suggest that slip occurs primarily due to fluid pressurization of the interface. In the case of bedding plane slip, fracturing pressure greater than the vertical stress (in regions where the vertical stress is the intermediate stress) could lead to propagation of a horizontal fracture, which then slips in shear. Introduction Well shear is defined as deformation of the well (usually observed as casing deformation) due to localized geomechanical shear slip that intersects the well. Typical slipping surfaces are bedding planes, faults, and natural fractures. Shear deformations in the overburden above compacting (or inflating) conventional reservoirs, and also at the reservoir/caprock interface, have been recognized for decades. Excellent overviews of these issues can be found in Dusseault et al. (2001) and Bruno (2002). Well shear associated with conventional reservoirs typically occurs only after production operations begin, and in the case of a depleting reservoir, it is often not until many years later. Unconventional reservoirs also experience casing deformations. These deformations can occur anywhere along the lateral, although many are observed near the heel. Importantly, they occur while completion operations are underway. While there are nongeomechanical causes for some of these observed deformations, there is a growing awareness that many of these deformations are due to geomechanical shear slip (Casero and Rylance 2020).
To collect, disseminate, and exchange technical knowledge--are the first seven words of SPE's mission statement. These are the three fundamental objectives of our Society. We proactively seek out the technical knowledge that not only our members need, but that the industry requires to meet the world's demand for oil and gas. Collecting this information can be challenging, especially if those who have it are not willing or able to share it. This proved especially challenging in the area of unconventional shales when SPE began to hold conferences on the subject nearly a decade ago.