The Hydraulic Fracturing Test Site 1 (HFTS-1) was a field study performed in the Wolfcamp Formation in the West Texas Permian (Midland) Basin, USA, with a focus on improving the efficiency of hydraulic fracturing. Investigating site-specific rock-fluid geochemical interactions during hydraulic fracturing is an important step to understanding the impact on formation shale porosity, permeability, and long-term shale gas production. During field operations in this region, hydraulic fracturing fluid (HFF) injection usually starts with a concentrated acid spearhead for rapid rock dissolution, followed by the injection of near-neutral pH slickwater containing chemicals and proppants. A multistep sequential injection approach was used to investigate different stages of rock-fluid interactions. The carbonate content in the host rock is important when acid spearhead is considered, as carbonate mineral dissolution is rapid and can result in porosity and permeability changes in the shale matrix. In this study, we designed flow-through experiments using fractured carbonate-rich and clay-rich Wolfcamp shale cores with (1) a short-time acid soaking step and (2) a long-term slickwater flow-through step to simulate the injection method used at HFTS-1. The fluid chemistry was analyzed. A thorough mineralogical progression [e.g., Calcium (Ca) dissolution and iron (Fe) redox progression] in the cores during HFF injection was also characterized and imaged by synchrotron microprobe. Reactive transport modeling was performed based on the experimental setup. The results showed that the acid spearhead is a crucial step in creating a reaction front by mineral dissolution, especially in carbonate-rich shales. A slight layer of ferrihydrite precipitated during the slickwater flow-through period. This study provides insights into potential geochemical impact due to hydraulic fracturing operations in the Permian Basin.

The efficacy of geological carbon sequestration is reliant on the integrity of the caprock and its resistance to physical and chemical alteration. Caprocks with high abundance of reactive carbonates like calcite are susceptible to acid-promoted dissolution and can result in structural weakening. This work investigates the effect of acidified brine flow through an artificially fractured, high-carbonate (30 % by XRD) shale under differential compressive stress. Cylindrical samples were cut in half vertically and milled to create an artificial fracture with interlocking asperities and open channels. Samples were sheared with a single applied stress in a custom flow cell housed within an industrial CT scanner. Either acidic (pH 4) or reservoir-simulated (pH 9.5) brine was flowed through the artificial fracture for 7–8 days under reservoir pressure and room temperature. Model simulations indicate flow mainly occurred in open channels, with limited flow between overlapping asperities. Analysis of fracture surfaces by optical and scanning electron microscopy show increased surface alteration and roughness after exposure to pH 4 versus pH 9.5 brine indicating mineral dissolution/loss, and this effect is greater in areas that receive the highest brine flows. Similarly, surface analysis by scratch testing shows fracture toughness decreases more after exposure to acidic versus reservoir-simulated brine, with the greatest alteration in areas of highest acidic brine flows. Despite weakening, no shear slip occurred. Overall, the results indicate that acidified brine can result in significant physical and geomechanical alteration of irregular fracture surfaces in shale caprock, with greatest effects in preferential flow regions.

The computed tomography (CT) facilities and the Multi-Sensor Core Logger (MSCL) at the National Energy Technology Laboratory (NETL) in Morgantown, West Virginia were used to characterize core material from three Ohio wells. These wells are listed below along with their American Petroleum Institute (API) and Ohio Geological Survey (OGS) identification numbers: - New York Central System 1 well (API 34085200170000, OGS Core 855) - Herren Well (API 34099201650000, OGS Core 2914) - Garvin-King Well (API 34121215610000, OGS Core 2939) The primary impetus of this work was to capture a detailed digital representation of the available core from all three wells. The collaboration between the U.S. Department of Energy's (DOE) NETL and the Ohio Department of Natural Resources, Division of Geological Survey enables other research entities to access information about this potential carbon storage location and its surrounding formations.

Technical report describing non-destructive core scanning on the One Earth Energy Well #1. Data is available on EDX (https://edx.netl.doe.gov/dataset/illinois-storage-corridor-one-earth-energy-1-core). Includes multi-scale computed tomography scanning and x-ray fluorescence measurements.

The poromechanical properties of unconventional reservoir materials are in large part dictated by their mineralogy. Since these properties govern the response to stress experienced during hydraulic fracturing, fluid production, and fluid injection, they play a central role in the formation of microcracks or bedding delaminations which ultimately dominate mass transport. In this work we study access to the porosity of end member unconventional reservoir materials, where the end members are predominantly dictated by carbonate content. Access to the porosity is quantified using state of the art 3D x-ray computed tomography coupled with physics informed data analytics. Xenon gas, which attenuates x-rays, provides a spatiotemporal map of access to the porosity. The accessible porosity is quantified over a range of net confining stress relevant to the manmade disturbances listed above. These experiments demonstrate that heavily carbonated mudstones are nearly impermeable at the core (~ cm) scale, while carbonate free analogues afford better access to the microstructure. Consistent with previous qualitative 2D radiographs, access to the interior of the clastic mudstones is first observed along planar microcracks, followed by slow penetration into the surrounding matrix. Physics informed data analytics of the 3D tomography measurements presented here show that these microcracks do not permit uniform access to the adjacent rock matrix. In addition, variation of the effective pressure elucidates the mechanisms that govern fracture/matrix fluid exchange. Under conditions consistent with hydrocarbon production fluid accumulates in the immediate vicinity of the nearest microcrack. While there is clear evidence that, as intended, part of this accumulation is from the more distant matrix, fluid is also squeezed out of the microcrack. The fluid build-up at the microcrack indicates that migration out of the rock is hindered by the coupled poroelastic response of the microcrack and adjacent rock matrix. We show that these mechanisms ultimately account for the meager oil recovery factors realized in practice. These insights have implications for making reservoir scale predictions based on core scale observations, and provide a basis for devising new asset development techniques to access more porosity, and enhance fluid extraction. Finally, these findings shed light on key features and mechanisms that govern shale storage capacity, with relevance to other important industrial processes, such as geologic CO 2 storage.

Experiments showed that 5% KI carbonated brine injection into fractured Marcellus and Utica Shale cores at room temperature (similar to 20 degrees C) and at 1700 psi (MPa) confining pressure resulted in dissolution along fractures, together with an increase in the total core permeability of the fractured cores. Dissolution in the more calcium-rich Utica Shale concentrated along larger aperture zones that likely channeled the bulk of the flow through the core. In contrast, dissolution in the Marcellus Shale sample was more uniform across the fracture plane and accompanied by the development of a porous, permeable zone of partial dissolution within the shale matrix that developed throughout the sample and decreased in volume along core length. X-ray fluorescence measurements in both cores revealed depletion in calcium, and in the Marcellus core the composition of the porous reaction rind was non-reactive and silica rich. The partial dissolution of the Marcellus Shale matrix adjacent to the fracture resulted in a permeable zone that contributed to the sample's increased transmissivity, as shown by fracture aperture mapping, high-resolution microtomography, and numerical simulations of flow through the fracture. Shale lithology and mineralogy were combined with the initial fracture morphology to determine where, how, and to what degree reactive fluids caused changes to fractured shales. Although the experimentally determined macroscopic permeability of both cores increased approximately one order of magnitude, the different compositions of the rocks resulted in distinct microscopic dissolution patterns. The umbrella term of "shale" encompasses a variety of lithological compositions with variable reactive potential. Our analysis demonstrates that even small lithological variations in carbonate and silicate mineral content and distribution can have an outsized impact on shale fracture behavior during reactive flow. Any field-scale assessment of the utility of shales as sealing formations or reservoirs in the presence of reactive brines must entail a thorough description of the given lithological unit and its susceptibility to reactive flow.

The computed tomography facilities and the Multi-Sensor Core Logger at the National Energy Technology Laboratory in Morgantown, West Virginia were used to characterize core from the Lively Grove #1 Well (API 121892494700), drilled near Marissa, Washington County, Illinois. Core from the well was obtained as part of the Illinois Storage Corridor CarbonSAFE project (DE-FE0031892).

The U.S. Department of Energy’s National Energy Technology Laboratory (DOE-NETL) has been developing methods and tools (the online Carbon Dioxide Storage prospeCtive Resource Estimation Excel aNalysis (CO2-SCREEN) tool) to estimate carbon dioxide (CO2) storage potential in subsurface reservoirs. The CO2 storage efficiency terms are input in the tool to calculate storage potential in targeted reservoirs. In this effort, two CO2 storage efficiency terms were evaluated: volumetric displacement (EV) and microscopic displacement (Ed). The first term deals with efficiency of CO2 propagation into an accessible reservoir volume, while the second term evaluates effectiveness of native fluid displacement with CO2. The interpreted well logs and core sample measurements were applied to create the heterogeneous reservoir models including geostatistical realizations of porosity and intrinsic permeability fields. Supercritical CO2 was injected over the course of 30 years into brine-saturated reservoir models for clastics, limestone, and dolomite lithologies and deltaic fluvial, aeolian, shallow marine, and reef depositional environments by means of varying reservoir parameters and injection scenarios. The reservoir models providing vertically heterogeneous petrophysical properties and designated as “layered reservoir models” (with homogeneous parameters along each layer of the model) were not determined to be a transition between the homogeneous and heterogeneous models in respect to storage efficiency. Another finding shows that high-efficiency factors do not necessarily mean increased CO2 storage; they rather indicate that the available volume and pore space are more fully utilized. The CO2 storage efficiency factors were evaluated dynamically at the select time points using P10‐P50‐P90 percentiles. The results of this study show that the P10‐P90 distribution for volumetric efficiency is wider when compared to the microscopic efficiency. It was found that where dominant buoyancy forces drive the plume to the top of a target formation, the volumetric efficiency is low. Tighter sandstone and carbonate formations show prevalence of capillary forces and better utilization of reservoir volume.

The integrity of wellbore cement is vital for the long-term success of applications such as enhanced oil recovery and carbon storage. Intact cemented well casings are crucial to preventing leakage and fluid migration, as well as maintaining safety of operations. To investigate the changes to fractures in foamed wellbore cement in a carbon storage scenario, four cores were fractured lengthwise and injected with deionized water at equilibrium with CO2. The experiment duration was five days for the first core and was increased for each successive test, with the final test lasting 20 days. The fractured cores were periodically imaged with a NorthStar M5000 Industrial Computed Tomography (CT) scanner, documenting the changes to the fracture during dissolution, as well as the reaction zone in the surrounding cement matrix. For two cores with the most robust reactions, the fracture and two reaction zones (proximal and distal to the fracture) were segmented from the raw CT data. They were quantified volumetrically and in the form of fracture aperture maps. A Local Cubic Law (LCL) modeling suite was used to map out localization of flow within the open portions of the fractures.

Polyfluoroacrylate (PFA) is a hydrophobic and oleophobic polymer that is soluble in high pressure carbon dioxide (CO2). In this study, the ability of PFA-CO2 solutions to greatly reduce the apparent permeability of split or cracked Portland cement cylindrical samples is assessed. The apparent permeability values of confined samples were determined before and after treatment with PFA-CO2 solutions. In four tests, PFA-CO2 solutions were continuously displacing pure CO2 from the cracked cement and the decrease in apparent permeability due to PFA adsorption and wettability alteration was monitored. The lowest apparent permeability cracked cement sample (81 nD) was completely sealed with a very small amount of solution. Samples with initial apparent permeabilities of 89 & mu;D and 29.4 mD exhibited 92% and 99% reductions in permeability, respectively, before the experiments had to be stopped because of the excessively large increase in pressure drop. A 50% reduction in apparent permeability was observed with a 3.80 mD sample. Four other split cement samples (bound together with tape) with an initial apparent permeability in the 9.0-70 mD range were removed from the core holder and immersed in a PFA-CO2 solution for 24 h to allow for PFA adsorption. Then the PFA-CO2 solution was depressurized, allowing for the deposition of additional PFA from the solution within the crack as the pressure fell below the cloud point pressure of the PFA-CO2 solution. These four samples were then confined again in a core holder and apparent permeability reductions of 29-93% were observed. Results from these eight experiments indicates that the more substantial reductions in the nD - mD apparent permeability of the cracked cement correlated to lower initial crack permeability, higher PFA concentration, and slower injection rate of the PFA-CO2 solution into the crack.

Multi-stage stimulation using alternative injection has been successfully applied in low mobility hydrocarbon production. However, fracture initiation and growth induced by different injection schemes have been inadequately studied for hot dry rock (HDR) geothermal reservoirs. Here, the impact of injection schemes on hydraulic fracture (HF) propagation regimes was determined with PFC2D software. The results show that the propagation of natural fractures (NFs) created by cyclic injection are dominated by the mode of shear activation and direct penetration. However, cyclic injection with frequent starting and stopping can produce non-uniform stress and fatigue, resulting in crack initiation and more branched fractures growth. The stepped injection can activate NFs effectively, and the HF propagation are featured by a style of turning at the tip of NFs. However, the stepped injection often produces a single main fracture with few branches. Different injection methods can lead to different propagation regimes and ultimately result in variation of the fracture network. A numerical model of the FORGE site that contains relevant geological structure and a fracture network was established with 3DEC software, and the impact of NFs on the HF network formation was investigated systematically. Compared with cyclic injection, the fracture network formed by stepped injection is more susceptible to the distribution of the NFs. The value of stepped injection is about 1.31 times in surface area and 1.17 times in aperture than the cyclic injection. Cyclic injection is conducive to creating fractures in the matrix, while stepped injection is more inclined to activate the preexisting NFs. The method presented here can be adopted to other geologic settings to optimize the fracture growth regime and provide a scientific basis for Enhanced Geothermal System (EGS) multi-stage fracturing design.

The computed tomography (CT) facilities and the Multi-Sensor Core Logger (MSCL) at the U.S. Department of Energy’s (DOE) National Energy Technology Laboratory (NETL) site in Morgantown, West Virginia, were used to characterize the Upper Jurassic (Oxfordian) Smackover limestone in the Roberson 18-19 1-15H core retrieved from the Atlanta Field, Columbia County, Arkansas. The 365.68-ft long Roberson core came from a vertical well at depths 8,802 ft to 9,169.60 ft, drilled by Southwestern Energy targeting the Smackover Formation as a potential unconventional oil reservoir. The primary impetus of this work was to non-destructively characterize core from the Smackover Formation that was acquired through a core exchange with Southwestern Energy. The Smackover Formation is an unconventional limestone play in southern Arkansas. This report and the associated scans provide detailed datasets not typically made publicly available from unconventional limestone for analysis. The resultant datasets are presented in this report and can be accessed from NETL’s Energy Data eXchange (EDX) online system using the following link: https://edx.netl.doe.gov/dataset/roberson-smackover.

The computed tomography (CT) facilities and the Multi-Sensor Core Logger (MSCL) at the National Energy Technology Laboratory (NETL) in Morgantown, West Virginia were used to characterize the Marcellus Shale and underlying formations. The core is from a vertical pilot well (Boggess 17H) drilled in western Monongalia County near Core, West Virginia by Northeast Natural Energy for the second Marcellus Shale Energy and Environmental Laboratory (MSEEL). MSEEL is a joint venture between NETL, Northeast Natural Energy, and West Virginia University. The primary impetus for this report is to characterize the core to better understand the structure and variation of the Marcellus Shale and surrounding formations. This report, and the associated scans, provide detailed datasets not typically available from unconventional shales for analysis.