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Search indexed NASA NTRS and DOE OSTI research on propulsion, heat transfer, battery materials and energy systems. Follow report and document links to the original sources.

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At least 19 records
All sourcesNASA NTRSDOE OSTI
DOE OSTI2021

Nanoscale Interfacial Smoothing and Dissolution during Unconventional Reservoir Stimulation Implications for Hydrocarbon Mobilization and Transport

Hydraulic fracturing of low-permeability rocks significantly enhances hydrocarbon production from unconventional reservoirs. However, fluid transport through low-permeability rocks, and the influence of geochemical transformations on pore networks, are poorly constrained. Mineral reactivity during interactions with injected water may alter the physical nature of the rock, which may affect hydrocarbon mobility. To assess alteration to the rock, we previously conducted a hydrothermal experiment that reacted cubed rock samples (1 cm3) with synthetic hydraulic fracturing fluid to simulate physicochemical reactivity during hydraulic fracturing. We analyzed unreacted and reacted rocks by small-angle neutron scattering and high-pressure mercury intrusion to determine how nanoscale (~1-1400 nm) pore networks of unconventional reservoir rocks are influenced by reaction with hydraulic fracturing injectates. We show that fluid-rock interactions have a two-fold influence on hydrocarbon recovery, promoting both hydrocarbon mobilization and transport. Pore-matrix interfaces smooth via removal of clay mineral surface asperities, reducing available surface area for hydrocarbon adsorption by ca. 12-75%. Additionally, hydraulic fracturing fluid-induced dissolution creates new pores with diameters ranging in size from 800-1400 nm, increasing the permeability of the rocks by a factor of 5-10. These two consequences of mineral dissolution act in concert to release hydrocarbons from the host rock and facilitate transport through the rock during unconventional reservoir production.

Herz-Thyhsen, Ryan↗
DOE OSTI2021

Factors Determining Commercially Optimal Development Strategies for CO 2 Storage With and Without CO 2 -EOR

This report is a draft white paper on the factors determining commercially optimal development strategies for CO 2 storage with and without CO 2 -EOR. The draft report provides a summary of accomplishments during the first budget period of the Southeast Offshore Storage Resource Assessment for the Gulf of Mexico (SECARB Offshore GOM) project. It also identifies “Next Steps” to be undertaken during Budget Period II. A final white paper will be prepared at the end of Budget Period II. The goal of this draft white paper is to expand the knowledge base required for commercially viable, secure, longterm, large-scale carbon dioxide (CO 2 ) subsea storage in the U.S. Gulf of Mexico (GOM), both with and without enhanced hydrocarbon recovery. This effort supports the U.S. Department of Energy’s (DOE) long-term objective of ensuring a comprehensive assessment of the potential for offshore CO 2 subsea storage in the GOM. The groundwork that has been completed in the draft white paper advanced by expanding the membership of the Southern States Energy Board’s (SSEB) existing Southeast Offshore Storage Resource Assessment (DE-FE0026082) GOM government-industry partnership during the next budget period. Further, the team plans to consult with U.S. federal and state agencies to develop recommendations to remove barriers and streamline the regulatory process to encourage subsea CO 2 storage with or without enhanced hydrocarbon recovery.

02 PETROLEUM↗
DOE OSTI2022

Probing oil recovery in shale nanopores with small-angle and ultra-small-angle neutron scattering

Increasing oil production from unconventional shale reservoirs is crucial to meet growing energy demands while achieving lower carbon emission than conventional crude oil. Enhanced oil recovery (EOR) has been proposed to improve hydrocarbon recovery rates through the injection of a fluid into the reservoir to facilitate residual oil release from the shale formation. However, economical and sustainable implementation of EOR requires advanced knowledge of fluid behavior in nano-sized pore spaces in shale. In this study, we utilize small-angle neutron scattering (SANS) and ultra-small-angle neutron scattering (USANS) as experimental probes to examine decane removal from a shale nano- to micro-porous matrix, utilizing methane as the injectant. The extent of decane saturation and recovery post-methane pressurization is quantified for clay-rich and carbonate-rich shale samples. A key finding is that extraction of decane by methane on depressurization is related to the methane-decane critical point. Furthermore, we found that although clay-rich shale had a much higher porosity of 5.6%, compared with 1.2% for carbonate-rich shale, decane was more easily removed from the carbonate-rich matrix, leading to similar hydrocarbon yields. These promising results demonstrate the ability of SANS and USANS to provide key insights into oil recovery from nano- to micron-sized pores in shale matrices. Combined with effects of various fractures on fluid behavior in shale, this experimental technique can be used to assess the viability of EOR injectants.

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2026

Improving Production in the Emerging Paradox Oil Play (Final Technical Report)

This report documents the results of the DOE-funded project Improving Production in the Emerging Paradox Oil Play, focused on integrating geological characterization, petrophysical analysis, reservoir simulation, and field development planning to improve hydrocarbon recovery from the Paradox Basin. Project activities included core and log analysis, assessment of reservoir heterogeneity and compartmentalization, evaluation of completion and stimulation strategies, and development of an uncertainty-aware field development framework. Findings highlight the importance of selective completions, geology-driven well placement, and targeted stimulation in vertically heterogeneous carbonate reservoirs.

02 PETROLEUM↗
DOE OSTI2024

Understanding Water Controls on Shale Gas/Oil Mobilization into Fractures (FY 2019-2021(FY2022, No Cost Extension), Final Report)

The large volumes of injected and produced water, and costs associated with both hydraulic fracturing fluids and produced water treatment motivate development of hydraulic fracturing strategies that use water more efficiently. The overall objective of this project is to improve understanding on how water is distributed within unconventional shales during and after hydraulic fracturing in order to provide a more rational basis for reservoir stimulation strategies that increase hydrocarbon recovery per unit of water used. The strong capillary imbibition of water into shale matrix pores and immiscibility with hydrocarbons makes it highly desirable to reduce water use during reservoir development. Given the importance, and competing influences of capillarity and gravity in controlling water in fractured porous media, this project also seeks to understand how these factors interact to obstruct or allow gas flow.

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2021

A comprehensive techno-eco-assessment of CO 2 enhanced oil recovery projects using a machine-learning assisted workflow

Carbon dioxide enhanced oil recovery (CO 2 -EOR) projects not only extract residual oil but also sequestrate CO 2 in the depleted reservoirs. Here, this study develops a machine-learning-based workflow to co-optimize the hydrocarbon recovery, CO 2 sequestration volume and project net present value (NPV) simultaneously. Considering the trade-off relationships among the objective functions, support vector regression with Gaussian kernel (Gaussian- SVR) proxies are coupled with multi-objective particle swarm optimization (PSO) protocol and generate Pareto optimal solutions. Taking advantage of the high computational efficacy of the proxy model, economic uncertainties introduced by tax credits, capital costs and oil price are investigated by this study. The results indicate that the tax incentive policy (Section 45Q) plays a vital role in enhancing the economic returns of CO 2 -EOR projects, especially under the depression of crude oil market. The proposed workflow has been successfully implemented to optimize a water alternative CO 2 (CO 2 -WAG) injection project in a depleted oil sand in the US. The optimization results yield an incremental oil production of 15.8 MM STB and 1.37 MM metric tons of CO 2 storage in a 20-year development strategy, with the highest project NPV to be 205.6 MM US dollars.

03 NATURAL GAS↗
DOE OSTI2020

Optimal pumping schedule with high-viscosity gel for uniform distribution of proppant in unconventional reservoirs

Hydrocarbon recovery from a hydraulic-fractured unconventional reservoir can be enhanced by replacing slickwater with non-Newtonian high-viscosity gel as a fracturing fluid. However, in the literature, the role of gel rheology on hydrocarbon production from a fractured reservoir is not very well understood. This lack of understanding makes it difficult for the industry to choose appropriate viscosity parameters of fracturing gels. Motivated by these limitations, first, we have developed a high-fidelity model of non-Newtonian fluid flow to simulate fracture propagation, fluid leak-off, and gel flowback processes to predict the oil production from a hydraulic fractured reservoir. Simulation results of the high-fidelity model show how fracture geometry, formation damage, and gel cleanup process varies with the fracturing fluid rheology. Therefore, the developed model is used to understand the effect of gel rheology on hydrocarbon production via a sensitivity analysis, which provides a set of rheological parameters that maximize the cumulative amount of oil production. Finally, utilizing this optimal high-viscosity gel, a model predictive controller is designed to obtain an optimal pumping schedule necessary for producing a target fracture geometry and proppant concentration. The closed-loop simulation results demonstrate that the obtained pumping schedule successfully achieved the desired fracture geometry and proppant concentration at the end of pumping, leading to the maximum oil production from an unconventional reservoir.

13 HYDRO ENERGY↗
DOE OSTI2024

Risk Considerations of Transitioning CO2-EOR Field to CO2 storage Field: Case Study

In the United States (U.S.), carbon dioxide (CO2) injection wells at EOR sites are currently regulated as Class II wells under the U.S. Environmental Protection Agency’s (EPA) Underground Injection Control (UIC) program while dedicated geological CO2 storage (GCS) wells are considered Class VI wells. A CO2-EOR facility considering a transitioning from tertiary oil recovery to injecting CO2 for the primary purpose of long-term storage is required to obtain a Class VI permit where this transition poses an increased risk to underground sources of drinking water. This study considers how transitioning operations from CO2-EOR to storage can impact reservoir plume and pressure transient in the storage envelope, and how these changes could impact area of review and potential unwanted fluid migration. We developed a case study to assess subsurface response and leakage risks associated with a representative, hypothetical operation in a carbonate reservoir. This reservoir transitions from tertiary hydrocarbon recovery to dedicated GCS. Reservoir simulations were run for a set of credible CO2-EOR scenarios to estimate distributions of fluids phases and pressures throughout the model domain after CO2 flooding as well as forecasting the behavior of the reservoir after the transition to a dedicated storage phase. The evolutions from all simulated scenarios were used as the basis for leakage risk quantification using the National Risk Assessment Partnership’s Open-Source Integrated Assessment Model (NRAP-Open-IAM) with a novel reduced-order model to estimate time-dependent leakage of CO2, brine, and hydrocarbon fluids through potentially leaky wells. Results include a description of reservoir response, an estimate of the areal extent that could potentially be impacted by leakage to underground sources of drinking water, and estimates of the magnitude of potential leakage. Considerations for dedicated storage injection well selection, injectivity, and injection scheme performance and potential leakage risk are presented, with implications for risk assessment of well transition discussed. This study presents a risk-based workflow for the Class II to Class VI well transition. Integrating credible numerical simulation of viable CO2-EOR to dedicated CO2 storage with quantitative risk assessment tools, such as the NRAP-Open-IAM, will provide a valuable means to devise operational scenarios and inform decision-making related to storage benefit, leakage risk, and liability. Presented at the SPE/AAPG/SEG Carbon Capture Utilization and Storage Conference in Houston, TX, March 11-13, 2024.

Liu, Guoxiang↗
DOE OSTI2020

Characterizing Pore-Scale Geochemical Alterations in Eagle Ford and Barnett Shale from Exposure to Hydraulic Fracturing Fluid and CO 2 /H 2 O

As demand increases for an affordable energy source that is tied to an environmental obligation to reduce greenhouse gas emissions and water usage, there is a growing consideration in shale production utilizing processes such as 1) enhancing hydrocarbon recovery via carbon dioxide (CO 2 ) flooding, 2) using CO 2 as a fracturing agent to minimize water use, and 3) storing CO 2 in depleted shale formations to mitigate emissions to the atmosphere. Understanding the geochemical reactions and alterations that occur as shale is exposed to fluids and CO 2 is necessary to develop and optimize each of these processes for field applications. While the majority of shale formations are stimulated using traditional fracturing fluid, some may be fractured using CO 2 or other non-traditional means. We examine the effect fracturing fluid has on shale and how it behaves with secondary exposure to dry CO 2 or CO 2 -saturated water using in situ Fourier Transform infrared spectroscopy (FTIR), feature relocation scanning electron microscopy (SEM), and surface area and pore size analysis using volumetric gas sorption. These techniques were performed on Eagle Ford and Barnett shale samples that were exposed to fracturing fluid and unexposed (as received). Shales that have been exposed to traditional fracturing fluid experienced two reaction fronts. The first reaction front was formed during exposure to the fracturing fluid (pH of ~1.4). A secondary reaction front was formed as a result of CO 2 -saturated fluid exposure in the form of carbonic acid (pH ~5.6). These two different reaction mechanisms drove multiple dissolution and precipitation cycles which altered petrophysical properties of the shale and could lead to a significant impact on flow pathways. FTIR showed that equilibration of carbonate dissolution and precipitation cycles could take as long as 35 days. Samples exposed to fracturing fluid showed significantly less carbonate reactivity compared to those exposed to water. Pore size analysis results indicate exposure to fracturing fluid blocked small nanopores (10-15 nm) reducing BET surface area and total pore volume. SEM results show barite precipitated heavily during exposure to fracturing fluid. It appeared that carbonic acid was able to extract sulfur from organic matter to form gypsum evaporites. The mineralogical (barite precipitation and calcite dissolution/precipitation) and pore-scale alterations observed in these samples may lead to enhancement of flow pathways for injected CO 2 or produced hydrocarbons.

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2021

Synergistic foam stabilization and transport improvement in simulated fractures with polyelectrolyte complex nanoparticles: Microscale observation using laser etched glass micromodels

Inaccessibility to direct pore scale observation in hydrocarbon recovery of tight shale formations poses a great challenge to water-energy nexus initiatives and necessitates the use of high throughput technologies to emulate environmentally friendly processes. Herein, we employ a precise glass micromodel fabrication and visualization method to isolate the supercritical CO 2 bubbles surrounded by CO 2 -water lamella prepared in saline produced water stabilized with molecular complexation of zwitterionic surfactants (ZS) and polyelectrolyte complex nanoparticles (PECNP). The Selective Laser Enhanced Etching (SLE) technique was selected for micromodel simulation of high-pressure flow. Two representative designs, (1) fracture/micro-crack network 28 and (2) fracture/matrix were etched on fused silica glass with a laser printing machine and scCO 2 foam was injected to study the foamability, propagation, stability, and fluid loss properties. The highly monodispersed and uniformly distributed array of scCO 2 bubbles were detected in flow of scCO 2 foam in highly saline brine containing ionic complexes of positively charged PECNPs and ZS, whereas foam flow with the lamella containing ZS in fractures offered a noticeably large and polydisperse array of scCO 2 bubbles. scCO 2 bubble motion and deformation were traced, and local description of foam flow was visually examined. The confined array of scCO 2 bubbles stabilized by ZS in microcracks was affected by bubble growth and coalescence, whereas the super-populated array of monodispersed scC O2 bubbles with lamella containing complexes of PECNP and ZS were able to fill the channels with stable configurations within the timeframe of comparative stability measurements. The ability of complex fluid to prevent the formation damage was evaluated through fluid loss visualization in micromodels. Probing scCO 2 foam transport in homogenous porous media revealed smaller volume leak-off for scCO 2 foam containing PECNP-ZS ionic complexes.

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2021

A Physics-Constrained Deep Learning Model for Simulating Multiphase Flow in 3D Heterogeneous Porous Media

Physics-based simulators for multiphase flow in porous media emulate nonlinear processes with coupled physics, and usually require extensive computational resources for software development, maintenance and simulation execution. As a result, a huge demand exists for fast modeling of coupled processes in a wide range of subsurface applications including geological sequestration, hydrocarbon recovery and geothermal energy extraction. In this work, an efficient physics-constrained deep learning model is developed for solving multiphase flow in 3-Dimensional (3D) heterogeneous porous media. The model fully leverages the spatial topology predictive capability of convolutional neural networks, specifically U-Net with successive contracting and expansive steps, and is coupled with an efficient continuity-based smoother to predict flow responses that need spatial continuity. Furthermore, the transient regions are penalized to steer the training process such that the model can accurately capture flow in these regions. The model takes inputs including properties of porous media, fluid properties and well controls, and predicts the temporal-spatial evolution of the state variables (pressure and saturation). While maintaining the continuity of fluid flow, the 3D spatial domain is decomposed into 2D images for reducing training cost, and the decomposition results in an increased number of training data samples and better training efficiency. Additionally, a surrogate model is separately constructed as a postprocessor to calculate well flow rate based on the predictions of state variables from the deep learning model. We use the example of CO 2 injection into saline aquifers, and apply the physics-constrained deep learning model that is trained from physics-based simulation data and emulates the physics process. The model performs prediction with a speedup of ~ 1400 times compared to physics-based simulations, and the average temporal errors of predicted pressure and saturation plumes are 0.27% and 0.099% respectively. Furthermore, water production rate is efficiently predicted by a surrogate model for well flow rate, with a mean error less than 5%. Therefore, with its unique scheme to cope with the fidelity in fluid flow in porous media, the physics-constrained deep learning model can become an efficient predictive model for computationally demanding inverse problems or other coupled processes.

58 GEOSCIENCES↗
DOE OSTI2025

Unravelling the origins of shale nanoporosity using small-angle neutron scattering (SANS)

Hydrocarbon production from tight rocks is constrained by slow diffusion within the shale matrix, limited by small pore sizes and low permeability. The nanopore proportion and size distribution significantly influence matrix permeability, a key property for optimizing hydrocarbon recovery and supporting hydrogen production while minimizing environmental impacts. Small-angle neutron scattering (SANS) has been an important tool for exploring the characteristics and structure of shale nanopores. This study used SANS to analyze nanoporosity and pore size distribution (<100 nm) in tight rocks with varying compositions to determine the influence of rock heterogeneity on SANS measurements. Results showed that nanoporosity correlates with clay content, with the highest clay-rich shale (52.48 wt% clay) exhibiting 8.8 % nanoporosity. SANS also revealed more nanopores than traditional nitrogen adsorption measurements, affirming its ability to reflect bulk mineralogy and upholding the relevance of experimental findings using this technique to optimize field operational approaches.

03 NATURAL GAS↗
DOE OSTI2021

Challenges of designing, operating, and managing brine extraction at a carbon dioxide storage site

Developing and deploying commercial-scale carbon dioxide (CO 2 ) storage at a site requires operational strategies to manage pressure and CO 2 plume distribution. In the natural gas storage and oil and gas industries, fluid extraction has been successfully implemented as a strategy to manage pressure and control fluid distribution (i.e., hydrocarbon recovery and natural gas storage efficiency, respectively). The technical challenges of integrating brine extraction at CO 2 storage sites are expected to be similar, if not identical, to those in the natural gas storage and petroleum industries. Major technical challenges of using brine extraction to manage storage in a storage unit include (1) designing and completing the brine extraction wells, (2) locating the brine extraction well, (3) assessing the efficacy of brine extraction, and (4) handling the extracted brine. The design and completion of the brine extraction well include the well type (i.e., vertical or horizontal) and perforated interval. The location of the well is influenced by the timing of extraction operations (i.e., prior or after CO 2 injection starts) and project objectives (i.e., desired directional movement of the CO 2 plume and avoid or minimize CO 2 extraction). The efficacy of brine extraction requires a baseline projection of the pressure and CO 2 plume distribution. Options for handling extracted brine include subsurface disposal, surface disposal, and industrial use. Here this paper addresses means of overcoming technical challenges that may likely be encountered before or after CO 2 injection starts.

25 ENERGY STORAGE↗
DOE OSTI2022

Preparation of illite coated geomaterial microfluidic surfaces: Effect of salinity and heat treatment

Unique characteristics of clay (e.g., high surface area, deficiency in positive charges) make any clay abundant shales a good source of adsorbed gas. However, the presence of clay in porous media can also affect shale rock's producibility. The clay-water interaction can cause significant swelling and fines migration in the formation and impair the overall hydrocarbon recovery from shale. Geomaterial micromodels, developed by functionalizing traditional glass or PDMS surfaces with geomaterials (e.g., calcite, Quartz, clay), can represent the physicochemical properties of the natural porous media and have been used during the last few years to understand and evaluate the solid-fluid physicochemical interactions. Here, this study focuses on developing a clay-coated geomaterial surface and investigates the effect of base fluid's salinity on clay adsorption to the glass surface. Glass capillary tubes and straight channel borosilicate glass micromodels are coated with Illite clay to represent the pore-scale clay chemistry of Caney Shale, a Mississippian unconventional play in Southern Oklahoma, USA. 10 wt% of Illite clay slurries made with brines of four different salinities are used to coat the glass-capillary tubes to understand the effect of salinity in clay adsorption on the glass surface and overall coating quality. To achieve a stable coating and evaluate the impact of heat treatment on coating's stability, straight channel glass flow cells coated with Illite clay are heat-treated at low (25 °C) and high temperature (125 °C), and the results are compared with an untreated coated surface. Flooding tests were carried out with brines of different salinities on the coated surface to evaluate the stability of the coating. The experimental results indicated a strong relationship between the brine's salinity and the adsorption of clay particles on the glass surface. An increase in brine concentration resulted in improved adsorption of clay particles on the glass surface. Experiments involving heat treating the glass surface following the coating demonstrated significant improvement in the stability of the coating.

02 PETROLEUM↗
DOE OSTI2025

A Multiscale Approach to Simulate Non‐Isothermal Multiphase Flow in Deformable Porous Materials

Coupled thermal, hydraulic, and mechanical processes in porous materials play important roles in several energy and environmental technologies. The Darcy-Brinkman-Biot (DBB) framework has proven effective in modeling multiphase fluid flow in deformable porous solids across both pore and Darcy scales, including in systems where fractures coexist with a porous matrix. In this study, we extend the DBB framework, originally designed for isothermal conditions, to address non-isothermal problems by incorporating an energy conservation equation. The resulting solver, hybridBiotThermalInterFoam, enables simulations of coupled multiphase fluid flow, heat transfer, and solid deformation in hybrid-scale systems containing both solid-free regions and ductile porous domains. The new solver is validated through comparisons with analytical solutions and, also, against established heat transfer solvers chtMultiRegionFoam and compressibleInterFoam. Further, a series of 2D and 3D case studies, including two-phase heat transfer in solid-free, static, or deformable porous media, highlights the solver's capacity to simulate complex flow dynamics and heat transport in systems involving high mobility ratios, viscous fingering, and fracture propagation. Our results establish the feasibility of incorporating thermal effects in simulations of a wide variety of energy geotechnics and environmental applications, including enhanced hydrocarbon recovery, soil remediation, and enhanced geothermal energy systems.

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2021

Core-flood Effluent and Shale Surface Chemistries in Predicting Interaction between Shale, Brine, and Reactive Fluid

We report field and laboratory observations to date indicate that the efficiency of hydraulic fracturing, as it relates to hydrocarbon recovery, depends significantly on geochemical alterations to rock surfaces that diminish accessibility by partial or total plugging of the pore and fracture networks. This is caused by mineral scale deposition such as coating of fracture surfaces with precipitates, particle migration, and/or crack closure due to dissolution under stress. In reactive flow-through experiments, mineral reactions in response to acidic fluid injection significantly reduced system porosity and core permeability. The present study focuses on changes to fluid chemistry and shale surfaces (inlet and fracture walls) resulting from shale-fluid interactions and integrating these findings for an improved estimate of transport-related consequences. The reacted shale surfaces were examined by spatially-resolved scanning electron microscopy - energy dispersive spectroscopy (SEM-EDS) analysis. Importantly, inductively coupled plasma - mass spectrometry/optical emission spectroscopy (ICP-MS/OES) was utilized to probe the chemical evolution of the core-flood effluents. The three study cores selected from the Marcellus formation represent different mineralogies and structural features. In flow-through experiments, lab-generated brine and HCl-based fracture fluid (pH=2) were injected sequentially under effective stress (up to 500 psi) at reservoir temperature (80°C). SEM-EDS results confirmed by the ICP concentration trends showed significant Fe hydroxide precipitates in clay- and pyrite-rich outcrop samples due to partial oxidation of Fe-bearing phases in the case of intrusion of low salinity water-based fluids. Porosity reduction in the MSEEL (Marcellus Shale Energy and Environmental Laboratory) carbonate-rich sample is related to compaction of cores under stress due to matrix softening with substantial dissolution, and pore-filling by hydroxides, as well as barite and salts. Despite the same fluid compositions and experimental conditions used for both MSEEL samples, barite precipitation was much more intense in the MSEEL clay-rich sample due to its greater sorption capacity and additional sulfate source as well as fissile nature with multiple lengthwise cracks. ICP tests revealed time-resolved concentration trends in produced brine and reactive fluids that in turn complemented the pre-/post-reaction SEM-EDS observations.

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗
DOE OSTI2021

Newly acquired core enhances geologic understanding of the northern Paradox Basin Cane Creek play, southeastern Utah

The Cane Creek interval is an emerging unconventional heterolithic play within the Pennsylvanian Paradox Formation of the northern Paradox Basin, southeastern Utah. Structural controls (basement uplifts, salt movement, faults, fractures) likely control production from the Cane Creek, where total oil production of ~10 MMBO is just a fraction of current estimates of the undiscovered resource (up to 1.2 BBOE). Oil production has been most successful from unstimulated horizontal wells in the Cane Creek Unit in the central play area, whereas areas to the north (Greentown and Gunnison Valley) have to date proven to be largely unproductive from vertical and horizontal wells drilled without the benefit of 3D seismic or the deployment of modern hydraulic fracturing techniques. However, the limited historical drilling has shown significant promise (e.g., significant shows). The lack of core data in the northern part of the play has impeded thorough assessment of reservoir quality, character, and lithological facies heterogeneity. The Cane Creek is informally divided into three distinct zones. The upper A and basal C zones are composed of fabric destructive and wavy bedded anhydrite, dolomitic mudstone, and organic-rich algal laminated mudstones (source rock). The middle B zone is generally wave rippled and burrowed, low-permeability sandstone-siltstone (reservoir) with subordinate displacive anhydrite. Recent potash cores collected from the Salt Valley anticline near Crescent Junction, Utah (but east of the main play area), show thicker reservoir sandstone/siltstone packages (~40 ft) in the B zone, and parts of the C zone, in the northern part of the Paradox Basin in comparison to the central (~35 ft) and southern (~30 ft) areas. Source rock analyses from northern core/cuttings also indicate that it is well positioned within the oil window (VRo ~0.8), with thin organic-rich mudstone beds containing up to 20 wt% TOC. Because the siliciclastic reservoir rocks have low permeabilities (0.009–0.202 mD) and variable porosities (6–17%) due to dolomite-anhydrite cement, naturally occurring and possibly stimulated fractures may be essential for hydrocarbon recovery. To better understand the northern part of the Cane Creek play, a new core was obtained from the research stratigraphic well State 16-2 (January 2021). Details from this new core will help characterize reservoir quality via core analyses, petrography, fracture orientations, geomechanics, and correlation of facies and depositional trends. Additionally, an evaluation of matrix porosity/permeability will be conducted to determine its contribution to productivity.

02 PETROLEUM↗
DOE OSTI2024

Dynamic Binary Complexes (DBC) as Super-Adjustable Viscosity Modifiers for Hydraulic Fracturing Fluids

In the preceding project year two, we refined three DBC formulations from a selection of over 50 different chemistries. The optimization study primarily encompassed testing for (i) reversibility extent, (ii) performance in the presence of chemical additives, (iii) adhesion and friction behavior during displacement in wellbores and pipelines, (iv) corrosion protection performance, and (v) injection performance with model fracture systems at the laboratory scale. Highly promising results obtained from all these tests signify the significant potential of DBCs in enhancing hydrocarbon recovery from unconventional reservoirs. The primary activities in the third project year included publishing experimental findings across multiple articles and conducting outreach initiatives. Throughout the year, we undertook tasks such as replicating experimental results, further optimizing various formulations and their associated experimental sets, and conducting additional tests to address missing components based on reviewer feedback and suggestions. We also explored the surfactant and friction-reduction aspects of selected formulations through drag reduction tests. In addition, we constructed an improved fracturing performance setup and performed flow injection tests. The specific DBC formulations focused on during this project period were A8/B1, A12/B5, and A10/B12. We also obtained results for additional DBC formulations and a select few commercial fracturing fluids for the purpose of comparison. Within the project's scope, we aim to enhance the experimental findings with the development of various models. The first two years focused on two key aspects: (i) the creation of a high-fidelity hydraulic fracturing model for non-Newtonian fluids to gain insights into the implementation of DBC fluids in fracking environments, and (ii) the development of a multiphase flow simulator for estimating total production, fluid saturation in the reservoir, and the creation of a fracture propagation model and kinetic Monte Carlo (kMC) models for diverse applications. In the third year, we delved into the fundamental nanostructural properties of DBCs, exploring aspects such as material chemistry, pH tunability, and control of DBC formation and stability. Subsequently, in the extension year, we conducted a systematic investigation of various building blocks containing primary, secondary, and tertiary amine functional groups to understand their impact on rheological and viscoelastic properties. Furthermore, we explored a Dissipative Particle Dynamics (DPD) model to simulate self-assembly processes with precision, creating a high-fidelity representation of relevant nanostructures. The tasks performed this year with the significant results obtained have been discussed in Section 2.

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗