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Abstract Continuing from the previous publication (Navaiz et al. 2023) detailing the hydraulic fracturing energy system and energy transfer as fluid and proppant are pumped from the surface into formation. this paper focuses on the validating the importance of effective energy delivered to formation and its correlation to total productivity. Combining extensive in-house pumping data and well-production data available from the public domain, a two-dimensional approach cross-plotting total effective energy injected per unit area against production output shows a highly correlative positive relationship (R2>0.75) across several basins in North America. This strong relationship not only reinforces the value of this energy analysis concept in hydraulic fracturing established by the authors previously. It also validates the conservation of energy principle highlighting the usefulness of relating effective energy injected into formation to a direct increase in reservoir energy potential and therefore a greater potential for total productivity. With the unconventional oil and gas industry highly focused on capital efficiency, the effective energy metric enables near-instantaneous optimization of development costs rather than iterating on 6-month or 1-year production performance. Time and capital can then be invested in technologies and processes that maximize effective energy and resultant productivity or minimize energy losses in the system.
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (36 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- (5 more...)
On the Path to Least Principal Stress Prediction: Quantifying the Impact of Borehole Logs on the Prediction Model
Dvory, N. Z. (Civil & Environmental Engineering & Energy and Geoscience Institute) | Smith, P. J. (Chemical Engineering) | McCormack, K. L. (Energy and Geoscience Institute) | Esser, R. (Energy and Geoscience Institute) | McPherson, B. J. (Civil & Environmental Engineering & Energy and Geoscience Institute)
ABSTRACT Knowledge of the minimum horizontal principal stress (Shmin) is essential for geo-energy utilization. Shmin direct measurements are costly, involve high-risk operations, and provide only discrete values of the required quantity. Other methods were developed to interpret a continuous stress sequence from sonic logs. These methods usually require some ‘horizontal tectonic stress’ correction for calibration and rarely match sections characterized by stress profiling due to viscoelastic stress relaxation. Recently, several studies have tried to predict the stress profile by an empirical correlation corresponding to an average strain rate through geologic time or by using machine learning technologies. Here, we used the Bayesian Physics-Based Machine Learning framework to identify the relationships among the viscoelastic parameter distributions and to quantify statistical uncertainty. More specifically, we used well logs data and ISIP measurements to quantify the uncertainty of the viscoelastic-dependent stress profile model. Our results show that the linear regression approach suffers from higher uncertainty, and the Gaussian process regression Shmin prediction shows a relatively smaller uncertainty distribution. Extracting the lithology logs from the prediction model improves each method's uncertainty distribution. We show that the density and the porosity logs have a superior correlation to the viscoplastic stress relaxation behavior. INTRODUCTION Comprehensive recognition of the least principal stress is essential for economic multistage hydraulic fracturing stimulation design. It is well established that hydraulic fractures propagate perpendicular to the least principal stress and that the stress profile prominent the hydraulic fractures generation in both the lateral and horizontal direction (Fisher et al., 2012; Hubbert and Willis, 1957; Kohli et al., 2022; Valkó and Economides, 1995; Zoback et al., 2022)c. In other words, the stress layering could act as a ‘frac barrier’ that limits fracture development in discrete directions and promotes progress in different directions (Singh et al., 2019). Detailed knowledge of the least principal stress profile is significant for hydraulic fracture growth assessment, proppants technology optimization, and efficient landing zone detection (Pudugramam et al., 2022). Traditionally, these considerations were aligned with the oil and gas industry. Still, today, they have substantial implications for enhanced geothermal system development, carbon storage integrity, and in a broader sense, a safe path for a carbon neutrality economy.
- Geology > Rock Type (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- North America > United States > Texas > Permian Basin > Midland Basin (0.99)
- (13 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
A Geomechanics and Pore Pressure Informed Stage Level Optimization Case Study for Unconventional, Infill Development in the Powder River Basin
Mazza, Joel (Fracture ID) | Kegel, Justin (Ballard Petroleum Holdings) | Van Delinder, Steve (Ballard Petroleum Holdings) | Hewett, Tom (Ballard Petroleum Holdings) | Emborsky, Beth (Fracture ID) | Patrick, Scott (Fracture ID)
Abstract A two-mile lateral infill well was drilled roughly 2000 ft from an offset producer in the same formation. The offset producer was a one-mile lateral and ran parallel to the heel portion of the child. The objective was to maximize productivity and completion efficiency by completing the infill well in a geo-informed manner. This would be accomplished by isolating depleted regions, maximizing cluster efficiency, decreasing the required stage count, and utilizing a practical treatment approach to maximize stimulation in the depleted and non-depleted sections of the wellbore. The authors utilized the geomechanics of the infill well, a depletion analysis, limited entry modeling, and hydraulic fracture modeling to optimize the child well’s completion approach. The optimization workflow applied to the infill lateral was as follows: 1. Derive a high resolution geomechanical and pore pressure profile from at-the-drill bit vibration data 2. Evaluate the min. horizontal stress (Shmin) changes along the lateral to optimize stage placement, stage length, and limited entry strategy 3. Utilize a hydraulic fracture model to simulate practical "what-if" scenarios to optimize hydraulic fracture flowing area in the depleted and non-depleted stages 4. Apply the optimal stage and treatment design in the field After the well was completed, the treatment data were evaluated against the geomechanics and pore pressure predictions using analytics software. After 12 months of production, the production data of the child well was evaluated against a nearby legacy producer. Compared to a base geometric design, the stage count was reduced by 8 (19%), total entry points and cluster efficiency remained the same, and the average stage Shmin variability was reduced by over 80%. Based on modeling results and practicality, treatment volume was reduced in depleted stages by 25% and increased in non-depleted stages by 25%. The design was successfully implemented in the field. After completion, the stage pressure data recorded during stimulation were analyzed against the stage-aggregated geomechanics and pore pressure data with good results. The subject well is a strong producer when compared to its peers. Its oil and gas production has outperformed a nearby legacy two-mile lateral well by 36% after 12 months. As infill development becomes the norm, subsurface data should at a minimum be considered and at best be integrated in optimization workflows to address challenges. The geomechanical data included in this study are economically obtained and operationally non-intrusive. In addition, the derived pore pressure profile uniquely identifies discrete regions of depletion along the near-wellbore allowing for stage and cluster level changes. Finally, the authors successfully implemented a pre-completion optimization workflow that can be explored in other unconventional reservoirs where fracture-driven interaction causes and reservoir drainage mechanisms vary widely.
- North America > United States > Texas (1.00)
- North America > United States > Wyoming (0.82)
- North America > United States > Colorado (0.68)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
Recent Advances and New Insights of Fiber Optic Techniques in Fracture Diagnostics Used for Unconventional Reservoirs
Nath, Fatick (School of Engineering, Texas A&M International University, Laredo) | Hoque, S. M. Shamsul (School of Geosciences, University of Louisiana at Lafayette) | Mahmood, Md. Nahin (Petroleum Engineering, University of Louisiana at Lafayette)
Abstract Technological advancements in well completion and stimulation have resulted in record production and considerable growth in global unconventional markets. However, the connection of the wellbore to hydrocarbon resource volumes by effective fracture stimulation is a critical factor in unconventional reservoir completions. Fiber optic (FO) techniques are gaining confidence among researchers for a better understanding of fracture diagnostics, visualization of the created hydraulic fractures, and identifying the proppant placement in the deep formation. Several notable outcomes have been observed recently in this emerging field. This paper investigates the recent advances and future opportunities in FO measurements for evaluating the stimulation performance in unconventional reservoirs. FO technique - Distributed Temperature Sensing (DTS) and Distributed Acoustic Sensing (DAS) cover the way to overcome the lack of knowledge in fracture diagnosis. Advances in this technique address challenges of fracture diagnostic between new cracks and reactivation of existing cracks, understanding fracture geometry, strain field, accurate inflow profile, and the far-field response of hydraulic fracturing treatment. A comprehensive discussion is made with their application in different shale formations (Eagle Ford, Bakken, Permian Basin, and Marcellus) of the United States. The advantages and limitations of each technique were highlighted. Finally, the paper evaluates what are the completion evaluation strategies to employ in unconventional moving forward. The result illustrates the observations obtained from the deployment of FO techniques in the Bakken, Eagle Ford, Marcellus, and Permian shale formations. The comparative outcomes of those methods have been analyzed to develop a pragmatic guideline for factors impacting fracture diagnostics. The review finds that modeling and interpreting DAS strain rate responses can help quantitatively to map fracture propagation and stimulated reservoir volume. The relationship between injection rate and strain rate responses is investigated to show the potential of using DAS measurements to diagnose multistage fracturing. FO diagnostics indicate that interactions between the well, the fracture, and the rock are complex, hence the need to integrate the results with other diagnostics and reservoir information. Rapidly growing FO implementation in fracture diagnostics needs direction based on recent developments made in this field. This work discusses and summarizes important outcomes that will benefit future researchers to integrate ideas and generate breakthroughs in FO implementation for fracture evaluation and monitoring. Extensive insight is a need for the industry given that there are growing developments and opportunities in unconventional plays, as operators are finding more economic ways to enhance production through stimulation. However, a critical review of FO implementation by analyzing the public domain has not been done before with the breadth and depth that this paper provides.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.96)
- Geology > Petroleum Play Type > Unconventional Play (0.89)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- (41 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Well Completion > Completion Monitoring Systems/Intelligent Wells > Downhole sensors & control equipment (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
A Back-Of-The-Envelope Model to Estimate Dimensions for Every Shale Frac
Weijers, Leen (Liberty Energy) | Agarwal, Karn (Liberty Energy) | Lolon, Ely (Liberty Energy) | Fontana, DK (Liberty Energy) | Mayerhofer, Mike (Liberty Energy) | Defeu, Cyrille (Liberty Energy) | Haustveit, Kyle (Liberty Energy) | Haffener, Jackson (Liberty Energy)
Abstract Creating a reliable, calibrated frac model used to be a long and expensive task in frac optimization. Today, with the proliferation of fracture diagnostics to calibrate models, simple frac dimensions can be calculated from indirect measurements on most North American shale fracs. Through the US Shale Revolution, fracturing operations have increasingly focused on pumping efficiencies. "Factory mode" operations today often allow little time for what used to be a lengthy optimization process of estimating fracture dimension sensitivity to job design changes for well placement selection and optimization of production economics. While some new fracture diagnostics have been designed to do measurements without interfering with frac operations, the calibrated models that harness these measurements remain cumbersome. We have developed a practical engineering tool that can extend the use of direct measurements to all shale horizontal well frac jobs. Unlike complex models that require lots of inputs and that are only routinely run on a few stages in a limited fraction of all North American shale wells, this Back-of-the-Envelope (BoE) model can be run effectively on every horizontal well stage. To date, it has been run on almost a quarter million stages. The BoE model provides two main advantages: (1) utilization of average basin diagnostic feedback and model calibration for more realistic results, and (2) augmenting more complex models on a much larger scale through a simpler workflow. The BoE model incorporates key fundamental processes in elliptical-shaped hydraulic fracture growth, including conservation of mass; limited entry-driven cluster distribution into simultaneously growing equal-sized multiple fractures; and Sneddon width profile with calibrated coupling over the fracture height. The physical model is further constrained by assuming a fixed half-length-to-height ratio from direct observation of hydraulic fracture growth. The BoE fracture model can be described with a few different rock mechanical fracture design and treatment parameters and ISIP measurements at the end of each fracture treatment stage. A key feature of the BoE model is that direct measurements are directly incorporated as an inherent calibration step. The model is anchored to basin closure stress measurements from DFITs and calibrated with past fracture geometry measurements, for example from Volume-to-First-Response data provided through Sealed Wellbore Pressure Monitoring (SWPM), or from other direct fracture diagnostics. In our paper, we present the results of this simple model and compare it with more complex fracture modeling efforts and fracture diagnostic results in a few major US shale basins.
- North America > United States > Texas (0.71)
- North America > United States > North Dakota (0.47)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (33 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Management > Energy Economics > Unconventional resource economics (1.00)
Abstract Objectives/Scope In the Permian Basin frac locations, azimuths and intensities recorded by single-use distributed fiber optics in two wells are integrated and compared to post-flow back production allocation and interference testing acquired with intervention fiber optics to identify areas of hydraulically conductive fracs and communication between offset wells. Methods, Procedures, Process Two wells on an 8 well pad were monitored with single-use pump down fiber. Strain events are recorded, identifying magnitude, azimuth, frac dimensions and velocity of the frac'd stages in purview of the monitor wells. 60 days post flowback, two of the frac'd laterals are sensed using intervention fiber optics to evaluate production allocation at the cluster level. Offset wells are then shut-in and production changes in the sensed well indicate the location and magnitude of interconnection between the sensed well and offsets. Strain data is compared to interference data to determine if strain could be associated with future productivity. Results, Observations, Conclusions Areas where cross-well strain indicated connective fractures also showed increases in production via interference testing. Areas with poor or no strain activity indicated reduced production and little, if any offset interference. Novel/Additive Information Extrapolating observed strain events identified areas where frac tips overlapped and appear to have created conductive pathways between offset wells, where interference is noted, despite an absence of strain data (as the farther fracs did not reach the monitor well but did overlap the offset that was sensed for flow allocation). This indicates that the production allocation interference testing method appears to reveal hydraulically connected fractures, even in the absence of strain data.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (24 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations (1.00)
Application of Fracture Injection Test, Rate Transient Analysis, and Pearson Correlation in Niobrara and Codell Formations to Evaluate Reservoir Performance in a Northern DJ Basin
Mindygaliyeva, B. (Colorado School of Mines) | Bekbossinov, N. (Colorado School of Mines) | Kazemi, H. (Colorado School of Mines)
ABSTRACT: This paper presents an assessment of well drilling strategy and the associated hydraulic fracture stimulation for a field in the Northern DJ Basin, Colorado. The paper is rich in data related to well orientation, completion, and production over a ten-year period from an unconventional field. Shale formations have very low permeabilities; however, multistage hydraulic fracturing stimulates the rock matrix by inducing micro- and macro-cracks; thus, improving formation drainage. Subsequently, rate transient analysis (RTA) of production data determines the quality of well stimulation. RTA emanates from single-phase linear-flow theory using rate-normalized-pressure versus (Equation) of the production data; however, RTA also extends to multiphase flow. RTA yields the effective formation permeability (EFP) and, occasionally, hydraulic fracture conductivity (HFC). Additionally, we used an iterative Perkins-Kern-Nordgren (PKN) model to interpret diagnostic fracture injection tests (DFIT) for the unstimulated formation permeability. Finally, we used 21 variables to generate a ‘correlation map’ of various reservoir performance measures: well s pacing, lateral length, number of perforations, total stimulation fluid injected, amount of sand placed, sand mesh size, quantity of p roduced oil, gas, and water. The variables that yielded the strongest positive correlation coefficients were well spacing, produced oil and gas volumes, 20/40 sand, acid additives, EFP, and HFC. 1. INTRODUCTION The Shale formations are denoted as ‘tight’ reservoir plays with low, nano-Darcy, matrix permeabilities where pore-size distribution is in the nanometer higher frequencies (Luo, 2018). Because of low matrix permeability, the maturation of the organic matter takes place in the source rock and the resultant distribution of hydrocarbon components also remains within the source rock with little outward migration. Formations with such characteristics are designated ‘unconventional reservoir’. There is a continued demand for hydrocarbon production due to the global energy demand and population growth. Fortunately, innovations in the technological sector of the oil and gas industry has provided effective means of oil and gas recovery from such tight formations (Kazemi et al., 2015). Contribution of unconventional reservoirs is significant in maintaining the balance in the energy market (Cui, 2015).
- North America > United States > Wyoming (1.00)
- North America > United States > Colorado (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.94)
- North America > United States > Wyoming > Niobrara Formation (0.99)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- (11 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- (2 more...)
Lithologically-Controlled Variations of the Least Principal Stress with Depth and Resultant Frac Fingerprints During Multi-Stage Hydraulic Fracturing
Zoback, Mark (Stanford University) | Ruths, Troy (Petro.ai) | McClure, Mark (ResFrac) | Singh, Ankush (ResFrac) | Kohli, Arjun (Stanford University) | Hall, Brendon (Petro.ai) | Irvin, Rohan (ResFrac) | Kintzing, Malcolm (Henry Resources)
Abstract We present observational data and modeling results which support the hypothesis that the degree of vertical to horizontal hydraulic fracture propagation during multi-stage hydraulic fracturing is largely controlled by variations of the least principal stress with depth. It is obvious that monotonic variations of the least principal stress with depth imply either upward or downward hydraulic fracture growth. More interestingly, we present several case studies in which direct measurements show layer-to-layer stress variations of the least principal stress as large as ~10 MPa (~1500 psi) which are lithologically controlled. Using two different types of analysis approaches, we investigate complex patterns of vertical and horizontal hydraulic fracture growth from the Midland Basin. In each case, we show that pattern of hydraulic fracture propagation (and resultant drainage volumes) are largely governed by the detailed variation of the magnitude of the least horizontal stress with depth and exact position of a given stage. In gun barrel view, this complex pattern we refer to as a frac fingerprint for convenience. The frac fingerprint depends on the exact vertical position of a frac stage with respect to the variations of the least principal stress in the layers both above and below the stage depth. We show how frac fingerprints can vary along the length of a well because of the way its trajectory encounters lithofacies along its length. We briefly discuss the implication of these concepts for choosing optimal well spacings and landing depths and the relationships between hydraulic fracture geometry and drainage volumes. Introduction It was established 65 years ago that hydraulic fractures should propagate perpendicular to the minimum horizontal principal stress, Shmin (Hubbert and Willis, 1957). While there have been abundant observations consistent with this concept, recent experiments in the Eagleford Formation (Raterman et al., 2017) and the Permian Basin at HFTS-1 and HFTS-2 (Gale et al., 2018: 2021) have added appreciable new data confirming this concept. Hubbert and Willis (1957) also argued that the magnitude of the least principal stress governs the pressure required for propagation of hydraulic fractures. In most areas, of interest to development of unconventional oil and gas reservoirs, the least principal stress is the least principal horizontal stress, Shmin (see recent review by Lund Snee and Zoback (2022) of stress orientations and magnitudes in unconventional sedimentary basins in North America). Thus, knowledge of Shmin and its variations with depth is especially important in unconventional oil and gas reservoirs exploited with multi-stage hydraulic fracturing in horizontal wells. Of specific interest in this paper is the variation of Shmin with depth. The least principal stress governs the degree to which hydraulic fractures propagate vertically, either upward or downward, depending on Shmin magnitudes above, within and below the horizontal section of well commonly referred to as the lateral. Significant vertical propagation can limit successful exploitation of the targeted formation and defines the number of laterals required to exploit productive zones at multiple depth intervals or stacked pay. Hence, optimizing the depths and number of laterals needed to exploit stacked pay as well as the optimal well spacing at different depths will be closely related to how the magnitude of Shmin varies with depth.
- North America > United States > Texas (1.00)
- North America > United States > Gulf of Mexico > Central GOM (0.25)
- Geology > Rock Type (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.68)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (45 more...)
- Well Completion > Hydraulic Fracturing > Multistage fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- (3 more...)
Abstract Multiple transverse fractures initiated in a horizontal wellbore are the most effective method to maximize formation contact and access reserves in unconventional reservoirs. Most horizontal well operations in unconventional reservoirs utilize multi-stage/multi-cluster plug and perforation completions. Optimization of unconventional resources requires improvements in the number of effective clusters within the designed stage length and sizing fracture treatments that are appropriate for the lateral and vertical spacing between wellbores. However, it can be challenging for operators to routinely and inexpensively 1) evaluate cluster performance within each stage, 2) analyze fracture propagation and complexity pressures and 3) determine fracture geometry resulting from the treatment design. Fracture treatment stage data is under-utilized and provides an opportunity for completion and stimulation optimization. This work focuses on a novel methodology to assess tubular and near well perforation pressure loss and limited entry success, determine cluster effectiveness, evaluate diverter performance, analyze fracturing pressures, and provide as-placed fracture geometry using stage treatment data. No changes to routine fracturing operations are required and stepdown tests are not necessary. After evaluating these key performance indicators, future completions can be optimized to achieve specific objectives including 1) improved cluster efficiency, 2) efficient fluid and mass placement per cluster, 3) stress and fracture shadowing component pressure management and 4) achieving fit-for-purpose created and propped fracture half-lengths. This work has been applied to multiple unconventional basins in North America. The methodology honors first-order principles and has been calibrated with multiple diagnostic technologies including optic-fiber, stepdown testing, RA and CFT tracing, fracture modeling and production data analysis methods. Results will illustrate varying stimulation and completion design variables, including the effects of perforation size and number, cluster spacing, application of diverters and mechanical stress shadowing. The effects of cluster performance on fracture length will be shown. The methodology is useful for stand alone, single well applications, however, increased value is gained with multiple well and multiple pad assessments. Using readily available hydraulic fracturing treatment data, completion and reservoir engineers and geoscience teams obtain meaningful results accelerating the learning curve and are provided a large parametric population for multivariant analysis and machine learning applications. The methodology presented provides a low-cost, scalable diagnostic solution for each completion stage within the horizontal well. Application of this methodology provides the fracture design engineer with new tools to optimize well performance using existing data.
- North America > United States > Texas (1.00)
- North America > United States > Colorado (1.00)
- North America > Canada (0.93)
- (3 more...)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (0.46)
- North America > United States > West Virginia > Appalachian Basin > Utica Shale Formation (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- (46 more...)
- Well Completion > Hydraulic Fracturing > Multistage fracturing (1.00)
- Well Completion > Completion Installation and Operations > Perforating (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
Paying it Forward: How an Emerging Unconventional Play can Hit the Ground Running
Koperna, George J (Advanced Resources International, Inc.) | Murray, Brett L (Advanced Resources International, Inc.) | Riestenberg, David E (Advanced Resources International, Inc.) | Carpenter, Steven M (Enhanced Oil Recovery Institute)
Abstract While every tight oil play is unique, there are lessons that can be transferred from one play to another to improve the efficiency and pace of production operations and development. These improvements may not fit precisely in every basin or play but generally hold to themes that can be tested against and built upon. Themes such as the quantity of proppant, longer lateral length, or the number of stages can be directly tied to increased productivity. However, there are diminishing returns on these investment activities for which each operator, within a given play, will be required to identify and mitigate against. This is especially true as the industry steps in and begins developing new tight oil plays. In their nascent stages, these plays may have limited well penetrations and, as a result, limited geological and performance data from which to extrapolate. Pulling together an understanding of where the industry currently resides in terms of how to exploit these resources can provide a boost in terms of working towards greatly improved well completions. In 2019, the US EIA estimated that nearly 8 million barrels of oil per day were produced from tight oil reservoirs in the United States (US EIA, 2020). This represents over 60% of the domestic crude production, originating from multiple reservoirs in the Permian Basin (TX) as well as the Bakken (MT, ND), Eagle Ford (TX), Niobrara (CO, WY), and Anadarko Basin (OK) formations, among others. As such, there are 1,000s of wells across these numerous tight oil plays that can relate an informative story. To build this story, the interplay of geology, well spacing, lateral length, and stimulation, all critical to economic success, will be explored. This paper proposes to look back at these mature tight oil (and gas) basins and bring forth an understanding of what lessons can be applied to the emerging Powder River Basin tight oil reservoirs (Mowry and the Turner/Frontier). The authors will delve into the four broad topics of geology, well spacing, lateral length, and stimulation, highlighting case studies to demonstrate those lessons from established tight oil plays that will underpin planned activities at a Field Laboratory Test Site in the southern Powder River Basin.
- North America > United States > Texas (1.00)
- North America > United States > Montana (0.89)
- North America > United States > Wyoming > Niobrara County (0.24)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.32)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- (7 more...)