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Far from the Siberian gas fields that it is best known for producing, Gazprom Neft--the oil-focused subsidiary of Gazprom--is taking steps toward a larger footprint in the Middle East. The Russian oil company said it wants to open doors in the region by opening up its portfolio of advanced technologies to national oil companies (NOCs) there. To that end, Gazprom Neft chose this year's SPE Annual Technical Conference and Exhibition (ATCE) held in Dubai to showcase half a dozen proprietary developments, some of which remain in the R&D phase while others are being used companywide. They included an in-house-developed hydraulic fracturing simulator, drilling advisory and automation software, a new material for drill bits, and digital twins for its facilities. Each represents a major investment of time and resources, but the majority state-owned Gazprom Neft said it doesn't necessarily want cash from those who might use the fruits of its labor; it wants relationships.
Abstract This study explains how production performance of the multi-fractured horizontal wells can be divided into two key contributing components: (1) geographical location and (2) completion strategy. Furthermore, we show how to quantify the contribution of these two independent components to production, and to understand the variations in key performance drivers across the evaluated field. Being able to differentiate these contributions allows us to compare well performance in a consistent manner and identify potential upside opportunities such as re-frac candidates, infill well development, and operator benchmarking. Further analysis uses multiple benchmarks to evaluate operator performance and assess how underperforming operators can optimize their completion strategies. We use a novel machine learning approach – a combination of XGBoost and Factor Contribution Analysis (FCA) - that not only allows for field-wide well evaluations, but also provides a quantifiable contribution of each feature to production. Our approach generates a production prediction model and takes into account the completion parameters and geological information for each well. The final model can be used to either predict future performance of a field/well, or to understand reservoir and completion characteristics. This study focuses on the latter and provides an approach to understand the main influencing factors behind well performance as a result of location and completion strategies. Our study is conducted on three major unconventional plays, Haynesville, Eagle Ford and Bakken, where we demonstrate how different completion features (e.g., lateral length, proppant volume, fluid volume) affect production data, and what we could expect in terms of production should the well have been completed differently. We show how to combine the effect of individual controlling factors (e.g., location, depth, lateral length, proppant volume, fluid volume and well spacing) to appropriately characterize the performance of each well in terms of two key components, location and completion. This enables us to quantify what portion of the production is a result of rock quality and how much is due to its completion strategy. This technique also allows us to quantify and relate each of these features, and highlight areas with desirable geological features, as well as good candidates for re-frac jobs. Moreover, we benchmark different operators’ performance as it relates to changing rock quality and completion strategies. The proposed procedure allows us to answer a series of important questions that are asked quite often. These include questions such as, is a well's production performance a factor of its location or the way it was completed? How to quantify, separately, the contribution of completion and location to production? Can sweet spots be identified in an area using production data? Does completion effectiveness vary with location, or operator, or year?
Haq, Izhar Ul (Department of Geoscience, Universiti Teknologi Petronas, Malaysia) | Padmanabhan, Eswaran (Department of Geoscience, Universiti Teknologi Petronas, Malaysia) | Khan, Javed Akbar (Shale Gas Research Group, Universiti Teknologi Petronas, Malaysia) | Sajid, Zulqarnain (Department of Geoscience, Universiti Teknologi Petronas, Malaysia)
Abstract Shale gas as energy resource play a significant role in the energy interdependence of any region and further research is needed to overcome the challenges by evaluating the factors that affects the methane storage capacity in shale reservoirs. This research evaluates the methane storage capacity of a potential unconventional reservoir, Semantan Formation, in the Peninsular Malaysia as well as factors responsible for the variation in the gas storage on the basis of mineralogy, maturity, and kerogen type by measuring methane adsorption isotherms on black shales from Semantan Formation as well as Oatka Creek Formation, Appalachian Basin, USA. X-ray Diffraction analysis were carried out to characterize the mineralogy of shales from both the Formations. TOC analysis and Rock-eval pyrolysis were utilized to determine the organic richness, maturity, and kerogen type, whereas pore structure and pore types were analyzed using Field-Emission Scanning Electron Microscopy. Black shales from both the Formations have shown a considerable storage potential due to the presence macro and meso-pores associated with mineral matter in the matrix. Increasing the pressure gradually from 1 MPa to 13 MPa, at a constant temperature, has shown a significant increase in the sorption capacity of shales from both the Formations. Results shows that organic richness and kerogen type has a significant impact on the methane sorption capacity of shales. The black shales hosting type-III kerogen provided more sites for gas adsorption than shale hosting type-II kerogen. The organic richness i.e., TOC > 5 % of the shale hosting type-III kerogen has shown higher methane adsorption compared to shale of low TOC type-III kerogen. Microscopic analysis revealed that the pore structure and mineral matter is similar in both the shales where the dominant inter-mineral pores are hosted by clay minerals, however, pores abundance vary in both shales due to visible mechanical compaction effects in Semantan shales. Black shales of Semantan Formation holding type-III kerogen has shown considerable gas sorption capacity and can act as a potential gas shale resource in Peninsular Malaysia.
Abstract This study used production data and a novel machine learning approach utilizing Factor Contribution Analysis (FCA) to highlight geologic sweet spots for multiple US on-shore basins. Each model result was validated against key geologic parameters to establish if the geologic conditions exist for the modeled sweet spots. Further analysis shows how geologic production drivers can change across each play. Geologic assessments rely primarily on parameters related to tectonic/depositional settings, reservoir storage, saturations, hydrocarbon phase, and wellbore deliverability to define resource play outlines. These same parameters are often used to identify geologic sweet spots and help explain production drivers. Available data resolution varies widely across plays depending on maturity of the play and/or complexity of subsurface relationships. Using only publicly available production and well completion data, XGBoost and SHAP machine learning approaches were used to identify play sweet spots and prepare reservoir quality maps. The focus of this study was on validating the results obtained from machine learning of production variables by using geological information. These geological data were derived from multiple sources including regional interpretations and incorporating geologic parameter cutoffs traditionally used for highlighting geologically favorable areas. Regional play data was provided through public data sources, technical publications, and investor presentations. Parameter cutoffs were overlayed with model results to validate the process. The machine learning methodology utilizing FCA was used to highlight production sweet spots across multiple US on-shore basins. This study has validated the production-based machine learning results through geologic analysis. The result was a strong correlation between key geologic parameters and model results. Specific relationships are established between the geology and model results that allow for deeper insights to be uncovered regarding changing geologic production drivers across the play. This analysis has corroborated independently that machine learning of production variables does result in a reliable characterization of reservoir rock quality. This type of analysis has been applied successfully to several unconventional resource plays, and provides significant impetus for intelligent use of explainable machine learning modeling. Moving forward, application of similar approaches can not only validate model results, but also highlight key geologic production drivers. Validation of the machine learning methodology allows users to better answer questions related to completion effectiveness, well evaluations, and development strategies.
Bilak, Roman (Terralog Teknologi Indonesia) | Kristiansen, Kerry (Terralog Technologies Inc.) | Xia, Guowei (Terralog Technologies Inc.) | Latif, Maiy (Terralog Technologies Inc.) | Marika, Eduard (Terralog Technologies Inc.)
Abstract This paper presents an innovative alternative stimulation approach for unconventional resource development called the Slow & Easy (S&E) stimulation process. This new generation geo-stimulation technology enables the convergence of environmental sustainability, enhancement of production performance, and well & field revitalization. The S&E process is designed to induce subsurface complex fracturing networks resulting in the progressive development of an Optimized Stimulated Rock Volume (O-SRV) in tight, stiff formations such as shales, tight sands, and carbonates. The process utilizes a cyclic injection approach with produced fluids at lower rates and pressures to enhance conductivity of the O-SRV. The extensive development of O-SRV is critical for effective, prolonged reservoir stimulation, leading to more sustained production rates and increased Estimated Ultimate Recovery (EUR) from wells. The lower injection rates and pressures, in addition to the cyclic injection approach, mitigate the risk of induced seismicity and inter-well ‘frac hits’. During its operation, freshwater and chemicals are not used, reducing the environmental impact of the S&E process. Also, as the S&E process requires lower proppant load and horsepower for production, it is a more cost-effective simulation method than conventional fracturing methods. The S&E process has been successfully implemented in over 60 wells worldwide. Typical unconventional reservoirs where the S&E process is applied include conglomeratic sands, dolomitic siltstone, and tuff formations; and typical petrophysical properties are porosity less than 9%, permeability less than 3 mD, and bulk stiffness of 14-30 GPa. Post-stimulation data shows an improvement in well oil productivity by a factor of 8 on average over a 6-month period. Field case histories and post-stimulation production performance are presented in this paper. The S&E process provides improved sustained hydrocarbon production, reduced stimulation costs, and significantly reduced environmental impact. The S&E method offers an innovative and specialized technology solution for more effective stimulation of unconventional resources to meet current industry demands.
Abstract Shale plays continue to push the demand for OCTG connections that can achieve higher torque, tension, compression, and pressure ratings while remaining economical as the drive for lower well costs intensifies. These unconventional wells require new connection technologies and adapted testing protocols to ensure no downhole issues occur. The work presented in this paper focuses on a new locking-thread connection developed specifically to address the shale performance need. The connection testing program has been based on the API TR 5SF June 2019 ballot draft. This new standard is being drafted by API Working Group 3081 specifically for shale applications and divides the testing into a sequence typical of operation including connection make-up, installation and running, stimulation, and production. In addition, the connection needed to address an issue that Shale operations are commonly facing, i.e. inner diameter (ID) restriction. This phenomenon was investigated with torque and drag simulations and utilizing finite element analysis (FEA). Various conditions and locations in a typical well were analyzed. By utilizing locking-thread connections, the new connection resulted in a significant increase in operational torque. The use of a thread seal allowed for a more economical design better suited for the application. This paper explains in detail which test conditions have been defined and successfully performed on the connection, aimed at being representative of all Shale play load sequences and usage. ID restrictions are a result of unique combined loading in shale developments – high torque being applied in combination with tension and compression. This connection exhibits low risk of ID restrictions thanks to its high torque capacity and design features. The high torque capacity in turn, allows operators to push their laterals further as they move to torque to mitigate friction factors. Additionally, a torque-tension relationship was investigated which is currently sparsely reported in any OCTG literature. This relationship suggests that the new connection could obtain higher torques under most conditions but would experience a reduction of torque capacity if high torque and tension loads were applied. This will help the operator to mitigate the ID restriction risk. The testing protocol presented in this work sets an interesting reference for Shale connection testing as it is the most advanced testing seen in the industry for shale products, combining API 5SF guidelines with the API RP 5C5 2017 standard. This paper also provides the details of torque capacity evolution vs. tension and compression, allowing the user to have a more accurate model for connection suitability when combining with torque and drag simulations.
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.
Abstract With the increase in shale oil and gas activity and complexity, companies deploy new solutions to safely and efficiently drill, complete, and produce wells in unconventional plays. These include Oil Country Tubular Goods (OCTG) connections, which must withstand installation, stimulation, and production loads specific to this application. Industry available standards provide manufacturers and operators a framework for quality founded on best practices and testing. In some instances, existing testing protocols may not be adequate (e.g. insufficient or overconservative) to assess connections’ performance for this application. For this reason, the American Petroleum Institute established an expert working group to develop Technical Report 5SF (TR 5SF) intended to evaluate casing connections performance in multi-fractured horizontal wells. The objective of this paper is to present a set of verified testing protocols applicable to casing connections used in the most common shale plays, complementing the existing body of knowledge. We discuss testing elements and parameters tailored to the conditions of various shale plays. Based on the operations planned for the life of a well, the testing procedure is adjusted to resemble the expected conditions and loads in the correct order. This includes make-up, high-cycle fatigue associated with the casing string installation, thread compound degradation under temperature and time, and mechanical load cycles generated by stimulation. Specimen sealability is confirmed under production loads, after which failure testing is performed. Some of the inputs to build the testing protocol are: maximum internal pressure, axial load, dogleg severity, number of cycles, temperature, and fluid type. Since connections play a crucial role in the integrity of a well, a testing procedure to ensure their performance is shown. Testing protocols for Multi-fractured Horizontal Wells (MFHW) applied to two connection types are presented, highlighting how tailored testing protocols and robust engineering improve product reliability and well integrity assurance. We compile a set of testing inputs for the most relevant shale plays worldwide, together with the testing elements, sequence, and acceptance criteria. This should help end users validate and benchmark products’ performance while improving industry knowledge of connections capabilities.
The direction of unconventional developments has been a roller-coaster ride, not only in the realms of financing and profitability, but very much in the technical execution of the well construction and the completion phases, too. This is particularly the case for those aspects relating to the completion and hydraulic fracturing operations. There are few parties, I believe, that would disagree that the drilling community rapidly delivered an extremely coherent and efficient learning curve, something that the completion/fracturing discipline has unfortunately been much slower to achieve. This is not in the least surprising. Effectively extending conventional technologies and focusing on key requirements (i.e., getting from point A to point B) worked well for drilling teams.
When trying to understand the well-to-well events known as frac hits and fracture-driven interactions (FDIs), the first idea to embrace is this: they are not all the same. "And the key physical mechanisms are not the same," said Mark McClure, who added that, "Until you've really dialed in on what those are, you're really in the dark." McClure is the cofounder and CEO of ResFrac Corp. In March, the modeling firm began a multiclient study to diagnose the relationships between parent and child wells--or what many consider to be the ultimate subsurface challenge facing the shale sector. Participating operators are Marathon Oil, Hess Corp., Pioneer Resources, Arc Resources, Birchcliff Energy, SM Energy, and Ovintiv Inc.