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Abstract Casing Deformation has presented itself in numerous unconventional basins. Severe deformation interferes with multistage fracturing, in particular with plug-and-perforation (also known as plug-and-perf) operations, the most common stage isolation method in unconventional development. Casing Deformation can greatly impact 20-30% of field productivity of horizontal wells in certain US shale and tight oil fields (Jacobs, 2020). Reservoir accessibility and well integrity are the two separate issues when considering casing deformation. In this paper, the impact of geomechanically driven casing deformation on reservoir accessibility that in turn affects production and economics, will be discussed. Origin of casing deformation within a target zone lies in natural fractures placed in highly anisotropic stress regimes. When these fractures are perturbed by hydraulic stimulation, slow slip or dynamic failure of the rock may occur. This phenomenon is intensified by active tectonics, high anisotropic in-situ stresses, and poor completion practices, i.e., poor cement. This paper evaluates these processes by demonstrating failure conditions of wellbores in different stress states and well orientations representative of unconventional basins. It reviews how these conditions can be evaluated in the reservoir, so risk can be estimated. The mitigation procedures to reduce casing deformation impact to operations through either well planning or completions design are discussed. Finally, this paper will also review an alternative completion method to plug-and-perf that allows limited entry completion technique in restricted ID casing due to casing deformation with a field case study.
Wang, Meng (Research Institute of Petroleum Exploration and Development, PetroChina) | Che, Mingguang (Research Institute of Petroleum Exploration and Development, PetroChina) | Wang, Guangyao (Research Institute of Shale Gas, Southwest Oil and Gasfield Company, PetroChina) | Wang, Yonghui (Research Institute of Petroleum Exploration and Development, PetroChina) | Zhu, Guangyou (Research Institute of Petroleum Exploration and Development, PetroChina)
Abstract Application of diversion agents in temporarily plugging fracturing of horizontal wells of shale has becoming more and more popular. Nevertheless, the studies on determining the diverter dosage are below adequacy. A novel approach based on laboratory experiments, logging data, rock mechanics tests and fracture simulation was proposed to optimizing the dosage of diversion agents. The optimization model is based on the classic Darcy Law. A pair of 3D-printed rock plates with rugged faces was combined to simulate the coarse hydraulic fractures with the width of 2.0 ~ 7.0 mm. The mixture of the diversion agents and slickwater was dynamically injected to the simulated fracture in Temco fracture conductivity system to mimic the practical treatment of temporarily plugging fracturing. The permeability of the temporary plugging zone in the 3D-printed fractures was measured in order to optimize the dosage of the selected diversion agents. The value of Pnet (also the value of ΔP in Darcy Formula) required for creation of new branched fractures was determined using the Warpinski-Teufel Failure Rules. The hydraulic fractures of target stages were simulated to obtain the widths and heights. The experimental results proved that the selected suite of the diversion agents can temporarily plug the 3D-printed fractures of 2.0 ~ 7.0 mm with blocking pressure up to 15 MPa. The measured permeability of the resulting plugging zones was 0.724 ~ 0.933 D (averaging 0.837 D). The value of Pnet required for creation of branched fractures in shale of WY area (main shale gas payzone of China) was determined as 0.4 ~ 15.6 MPa (averaging 7.9 MPa) which means the natural fractures and/or weak planes with approaching angle less than 70o could be opened to increase the SRV. The typical dosage of the diversion agents used for one stage of the horizontal wells was calculated as 232 ~ 310 kg. The optimization method was applied to the design job of temporarily plugging fracturing of two shale gas wells. The observed surface pressure rise after injection of diversion agents was 0.6 ~ 11.7 MPa (averaging 4.7 MPa) and the monitored microseismic events of the test stages were 37% more than those of the offset stages.
Haynesville Shale operator Aethon Energy and Halliburton have inked a multiyear contract to use the oilfield service company's new all-electric fracturing spread, or an e-fleet. The companies said in a joint announcement that the e-fleet will use Halliburton's "Zeus" electric pumping unit and a power-generation unit supplied by VoltaGrid. "All-electric fracturing represents an exciting approach to our overall strategy to reduce emissions in our operations," Paul Sandler, Aethon's chief operating officer, said in the announcement. Aethon said it is the largest privately-owned natural gas producer in the Haynesville Shale where production this year rose to nearly 13.2 Bcf/D, according to S&P Global Platts Analytics. Halliburton announced the first deployment of the Zeus electric pumping unit in August with Chesapeake Energy. This deployment also included the power system developed by the startup VoltaGrid.
The energy market is changing, according to consulting firm Deloitte. In their 2021 Oil and Gas Industry Outlook, Deloitte refers to the latest trend as "the great compression." Mass layoffs, changing public perception and governmental policies towards clean energy, and long-term decline of oil demand in the US are just some of the headwinds shale operators face today. Companies must be agile and be able to generate superior financial performance with minimal resources in order to survive. Deloitte predicts that the U.S. shale industry will look very different in the coming years, perhaps dominated by a high-graded or integrated portfolio of data-driven operators.
This year has been rife with announcements of new electric-powered fracturing fleet (e-fleet) operations in North American shale plays. Were these the latest barrage in a swift takeover of the North American hydraulic fracturing market by e-fleets? No, but they are evidence of the growing interest among operators, fracturing companies, and service and technology companies in developing and implementing solutions to sustainable shale development that satisfy the "three e's"--economics, environment, and efficiency. The rise of e-fleets is being driven by the US shale sector's growing concerns over greenhouse-gas (GHG) emissions, noise levels, fuel and maintenance costs, and carbon footprints, all of which impact environmental, social, and corporate governance (ESG) compliance scores and thus, funding for the major operators who now dominate North American shale development. E-fleets are increasingly seen as an environmentally and socially responsible fracturing option that minimizes sound, fire risk, fueling costs, and GHG emissions, offers clean and simple rigup, and significantly increases power density vs. conventional diesel-powered fleets while maintaining the redundancy that efficient frac operations require.
Friction reducers are expected to play critical roles in fracturing, some better than others. Shale producers are belatedly realizing that there are many variables that can alter the performance of these chemicals used to reduce the power needed to hydraulically fracture a reservoir, and in higher doses, to thicken fluid, making it possible to deliver proppant more efficiently. There are wells that can justify paying more for a friction reducer formulated to stand up to difficult chemical challenges, and others that cannot. But there is no guide that describes how these key additives perform. Those who do evaluations will realize that a lot of details about friction reducers are proprietary and no industry standard provides guidance about the information needed to thoroughly assess their compatibility with reservoir conditions.
Gordin, Yair (Department of Earth and Environmental Sciences, Ben-Gurion University of the Negev, Beer Sheva 8410501, Israel) | Bradley, Thomas (Baker Hughes) | Rosenberg, Yoav O. (Geological Survey of Israel) | Canning, Anat (Emerson, Paradigm Geophysical Ltd., Herzliya, Israel) | Hatzor, Yossef H. (Department of Earth and Environmental Sciences, Ben-Gurion University of the Negev, Beer Sheva 8410501, Israel) | Vinegar, Harold J. (Department of Earth and Environmental Sciences, Ben-Gurion University of the Negev, Beer Sheva 8410501, Israel and Vinegar Technologies, LLC, Bellaire, TX)
Abstract The mechanical and petrophysical behavior of organic-rich carbonates (ORC) is affected significantly by burial diagenesis and the thermal maturation of their organic matter. Therefore, establishing Rock Physics (RP) relations and appropriate models can be valuable in delineating the spatial distribution of key rock properties such as the total organic carbon (TOC), porosity, water saturation, and thermal maturity in the petroleum system. These key rock properties are of most importance to evaluate during hydrocarbon exploration and production operations when establishing a detailed subsurface model is critical. High-resolution reservoir models are typically based on the inversion of seismic data to calculate the seismic layer properties such as P- and S-wave impedances (or velocities), density, Poisson's ratio, Vp/Vs ratio, etc. If velocity anisotropy data are also available, then another layer of data can be used as input for the subsurface model leading to a better understanding of the geological section. The challenge is to establish reliable geostatistical relations between these seismic layer measurements and petrophysical/geomechanical properties using well logs and laboratory measurements. In this study, we developed RP models to predict the organic richness (TOC of 1-15 wt%), porosity (7-35 %), water saturation, and thermal maturity (Tmax of 420-435⁰C) of the organic-rich carbonate sections using well logs and laboratory core measurements derived from the Ness 5 well drilled in the Golan Basin (950-1350 m). The RP models are based primarily on the modified lower Hashin-Shtrikman bounds (MLHS) and Gassmann's fluid substitution equations. These organic-rich carbonate sections are unique in their relatively low burial diagenetic stage characterized by a wide range of porosity which decreases with depth, and thermal maturation which increases with depth (from immature up to the oil window). As confirmation of the method, the levels of organic content and maturity were confirmed using Rock-Eval pyrolysis data. Following the RP analysis, horizontal (HTI) and vertical (VTI) S-wave velocity anisotropy were analyzed using cross-dipole shear well logs (based on Stoneley waves response). It was found that anisotropy, in addition to the RP analysis, can assist in delineating the organic-rich sections, microfractures, and changes in gas saturation due to thermal maturation. Specifically, increasing thermal maturation enhances VTI and azimuthal HTI S-wave velocity anisotropies, in the ductile and brittle sections, respectively. The observed relationships are quite robust based on the high-quality laboratory and log data. However, our conclusions may be limited to the early stages of maturation and burial diagenesis, as at higher maturation and diagenesis the changes in physical properties can vary significantly.
Abstract A significant amount of research for gridding of complex reservoirs, including models with fractures, has focused on use of unstructured grids. While models with unstructured grids can be extremely flexible, they can also be expensive, both in configuring, computationally, and visual display. Even with this focus on unstructured grids, most reservoir simulation models are still built on structured grids. Current methods for creating reservoir simulation models with structured grids often involve defining a base grid upfront and then "somehow" inserting one or more Features of Interest (FOI's) into the model. Applied to fractured horizontal wells with many stages it can be extremely difficult to accurately align wells and completions within a pre-existing simulation grid. This work describes and demonstrates a methodology to resolve such issues. This approach changes the order of model design and creation steps. This paper describes the process where FOI's are identified, a base grid is designed around the FOI's, then local grid refinements (LGR's) are defined as desired. Applied to a horizontal well with fractures, the well and completion locations are defined before the detailed grid definition is created. This process is illustrated for generalized FOI's, and then applied to fractured horizontal wells. Formulas for creation of models for wells with evenly space homogeneous completions are presented. Numerical testing and analyses are presented that show the impact of the gridding parameters and various design parameters on performance of reservoir simulations.
Abstract This paper presents a continuum-scale diffusion-based model informed by pore-scale data for gas transport in organic nanoporous media. A mass transfer and adsorption model is developed by considering multiple transport and storage mechanisms, including bulk diffusion and Knudsen diffusion for free phase, surface diffusion for sorbed phase, and multilayer adsorption. The continuum-scale diffusion-based governing equation is developed solely based on free phase concentration for the overall mass conservation of free and sorbed phases, carrying a newly-defined effective diffusion coefficient and a capacity factor to account for multilayer adsorption. Diffusion of free and sorbed phases is coupled through the pore-scale simplified local density method based on the modified Peng-Robinson equation of state for confinement effects. The model is first utilized to analyze pore-scale adsorption data from the krypton (Kr) gas adsorption experiment on graphite. Then we implement the model to conduct sensitivity analysis for the effects of pore size on gas transport for Kr-graphite and methane-coal systems. The model is finally used to study Kr diffusion profiles through a coal matrix obtained through X-ray micro-CT imaging. The results show that the sorbed phase occupies most of the pore space in organic nanoporous media due to multilayer adsorption, and surface diffusion contributes significantly to the total mass flux. Therefore, neglecting the volume of sorbed phase and surface diffusion in organic nanoporous rocks may result in considerable errors. Furthermore, the results reveal that implementing a Langmuir-based model may be erroneous for an organic-rich reservoir with nanopores during the early depletion period when the reservoir pressure is high.
Abstract Hydraulic fracture/reservoir properties and fluid-in-place can be quantified by using rate-transient analysis (RTA) techniques applied to flow rates/pressures gathered from multi-fractured horizontal wells (MFHWs) completed in unconventional reservoirs. These methods are commonly developed for the analysis of production data from single wells without considering communication with nearby wells. However, in practice, wells drilled from the same pad can be in strong hydraulic communication with each other. This study aims to develop the theoretical basis for analyzing production data from communicating MFHWs completed in single-phase shale gas reservoirs. A simple and practical semi-analytical method is developed to quantify the communication between wells drilled from the same pad by analyzing online production data from the individual wells. This method is based on the communicating tanks model and employs the concepts of macroscopic material balance and the succession of pseudo-steady states. A set of nonlinear ordinary differential equations (ODEs) are generated and solved simultaneously using the efficient Adams-Bashforth-Moulton algorithm. The accuracy of the solutions is verified against robust numerical simulation. In the first example provided, a MFHW well-pair is presented where the wells are communicating through primary hydraulic fractures with different communication strengths. In the subsequent examples, the method is extended to consider production data from a three-well and a six-well pad with wine-rack-style completions. The developed model is flexible enough to account for asynchronous wells that are producing from distinct reservoir blocks with different fracture/rock properties. For all the studied cases, the semi-analytical method closely reproduces the results of fully numerical simulation. The results demonstrate that, in some cases, when new wells start to produce, the production rates of existing wells can drop significantly. The amount of productivity loss is a direct function of the communication strengths between the wells. The new method can accurately quantify the communication strength between wells through transmissibility multipliers between the hydraulic fractures that are adjusted to match individual well production data. In this study, a new simple and efficient semi-analytical method is presented that can be used to analyze online production data from multiple wells drilled from a pad simultaneously with minimal computation time. The main advantage of the developed method is its scalability, where additional wells can be added to the system very easily.