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At least 55 records · Page 3
All sourcesNASA NTRSDOE OSTI
DOE OSTI2021

Maximizing oil production from water alternating gas (CO 2 ) injection into residual oil zones: The impact of oil saturation and heterogeneity

Residual oil zones (ROZs) are widespread reservoirs, characterized by oil at residual saturation, either underlying oil fields (brownfield) or lateral (greenfield) to such fields. These reservoirs have the potential to produce volumes of oil sufficiently significant to make appreciable impacts on the US’s oil reserves and associated incidental CO 2 sequestration. The objective of this study is to improve our understanding the impact of heterogeneous and low oil saturations, in brownfield ROZs, on the effectiveness of water alternating gas (WAG) injection strategies. ROZs occur in the Permian Basin and elsewhere, and operators are using CO 2 injection for enhanced oil recovery (EOR) in these zones. The consensus model for the formation of ROZs is that they were formed by the effect of faster regional aquifer flow, acting over millions of years. Both the magnitude of oil saturation and the spatial distribution of oil differ from water-flooded main pay zones (MPZs). To explore the most effective injection strategies, we conducted simulations of CO 2 injection into synthetic geologic reservoirs. These simulations focused on injection into reservoirs subject to either man-made waterflooding or long-term natural waterflooding. By exploring the impact of varying: oil saturation; well patterns; reservoir heterogeneity; and permeability anisotropy, we attempt to quantify the factors that most influence the effectiveness of WAG injection. WAG ratios (the ratio of injected water and CO 2 , in reservoir volumes) of interest are those that either minimize the net CO 2 utilization ratios or maximize oil production rates. In general, the most effective WAG ratios for ROZs, are consistently less than those observed undergoing CO 2 injection in the same geologic reservoir models after traditional (man-made) waterflooding. This work demonstrates that most favorable WAG ratios for oil production in ROZs are different from those in traditional MPZs because of oil saturation differences. Therefore, CO 2 injection into both zones or directly copying WAG injection designs from MPZs to ROZs might not maximize oil production.

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2021

Public data from three US states provide new insights into well integrity

Significance There are over 900,000 active oil and gas wells in the United States. Estimates of the percentage of these wells that leak during their lifetime have been limited by data availability. We mined publicly available records from state regulatory databases and synthesized the results of various well testing methods into a uniform dataset that describes the integrity of 105,031 wells. Our analysis of the dataset provides insight into regional well leakage frequencies in three US states (Colorado, New Mexico, and Pennsylvania), spatial and temporal leakage trends among vertical and directional wells, and the characteristics of leaked fluids. Our findings demonstrate the value of statewide well testing programs and highlight the challenges of interpreting disparate interjurisdictional well testing data.

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2022

Exploring the benefits of utilizing small modular device for sustainable and flexible shale gas water management

Growing shale gas extraction in recent years has triggered wide discussions on the associated freshwater requirement and wastewater management. Many optimization approaches have been developed for shale gas water management; however, most of the studies assumed permanent utilization of wastewater treatment facilities with fixed capacities. Considering the rapidly declining characteristics of shale gas wastewater production, these treatment facilities could remain largely underutilized after the first few months/years of production, making them less economically attractive. To maximize the capacity utilization of treatment facilities and further improve the economic performance of shale gas development, this study develops a systematic optimization framework, where the capacity strategy of conventional treatment facilities and utilization of the recent concept of modular manufacturing are both considered for flexible shale gas water management. The proposed mixed-integer linear programming (MILP) model simultaneously optimizes the design and planning of integrated shale gas and water supply chain, with a focus on capacity planning for both large-scale conventional treatment facilities and small-scale modular devices. A series of Marcellus-based case studies are performed to illustrate the applicability of the proposed model and provide general insights into the trade-offs between the multiple types of treatment facilities. The optimization results reveal that the combinatorial utilization of conventional facilities and modular devices for wastewater treatment (66% by conventional facilities and 34% by modular devices) brings 9.3% more reused water for other well development and 6.2% savings in water-related costs, compared to flexible management of only conventional facilities. Furthermore, this work suggests that taking modular device as auxiliary equipment for shale gas water management is most beneficial to increase the capacity utilization of treatment facilities and achieve a more economic and sustainable shale gas production system.

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2022

Technology, technology, technology: An integrated assessment of deep decarbonization pathways for the Canadian oil sands

As a party to the Paris Agreement, Canada has an ambitious climate target of net-zero emissions by 2050. The country also holds the world's third largest oil reserves in the Alberta oil sands. Given increasing emissions from the oil sands sector, achieving Canada's net-zero target requires significant oil sands decarbonization. If, while phasing out fossil fuels, there is still a demand for Canadian oil sands, then the decarbonization of the resource production process becomes crucial. In this study, we use an enhanced version of the Global Change Analysis Model (GCAM) with a detailed unconventional oil sector for Canada, including mining and in situ resources. We ask, what is the future of the oil sands sector in deeply decarbonized global and Canadian economies? We address this question under four mitigation scenarios with varying global net-zero GHG emissions constraints, three additional representative lower carbon extraction technologies available for the oil sands sector, as well as global direct air capture (DAC) deployment. We find that lower carbon technology deployment allows a 20%–44% increase in oil sands production by 2050 for scenarios with net-zero GHG emissions in 2100 or 2075. DAC helps maintain oil sands production in the most ambitious global decarbonization scenario (net-zero GHG by 2050), without which low international oil demand makes Canadian oil sands production uncompetitive. Canadian oil sands production thus depends highly on the availability of lower carbon extraction technologies and international oil demand, which to a certain extent relies on the availability and global deployment of negative emissions technologies.

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2021

Pore-Scale Oil Connectivity and Displacement by Controlled-Ionic-Composition Waterflooding Using Synchrotron X-Ray Microtomography

Controlled-ionic-composition waterflooding is an economic and effective method to improve oil recovery in carbonate oil reservoirs. Recent studies show controlling the salinity and ionic composition of injection water can alter the wettability of carbonate mineral surfaces. The pore-scale oil connectivity and displacement by controlled-ionic-composition waterflooding in heterogeneous carbonate reservoirs, especially at the early stage, is still unclear. The goal of this study is to examine the role of ion concentrations and types in the oil displacement efficiency and investigate the impact of the waterflooding on the pore-scale oil displacement using the national synchrotron facility. A carbonate rock sample was flooded with synthetic high-salinity water and other water solutions with different sulfate concentrations. The waterflooding processes were visualized with synchrotron X-ray microtomography to follow the evolution of pore-scale oil/brine interactions at typical field flow rates. Experimental results show that the water with lower sulfate concentration and higher salinity did not change the wettability of the pore surfaces. Higher sulfate ion concentrations in the water, in contrast, altered the wettability of carbonate pore surfaces from oil-wet to neutral-wet within the first few minutes of waterflooding. Finally, novel insight was gained on the ability of water with high-sulfate concentration to displace oil in the small pores and through abundant oil channels, which could consequently lead to higher oil recovery from the carbonate rock.

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2020

SIMS Analysis of d18O and d13C of Carbonate Cements in Shale & Mudstone. Final report

This project has had two primary goals: 1) improving new technology for in situ microanalysis of stable isotope ratios by SIMS (secondary ion mass spectrometry) and 2) evaluating the importance of in situ analysis for studies of carbonate cements within shales of the Bakken Petroleum System. The systematic relations of stable isotope ratios provide an important tool to help resolve critical questions in geology. Stable isotope analysis of carbonate cements in shale constrain many topics of interest to DOE including: CO2 sequestration, climate change, and the genesis and quality of rock reservoirs for petroleum, natural gas, and water. However, this evidence is often preserved as fine-scale zonation, which is homogenized by conventional bulk analysis of powders. Recently, analysis of ultra-small spots in polished samples at the University of Wisconsin WiscSIMS Lab. has documented stable isotope zoning in carbonates and other diagenetic cements at smaller scales than previously possible. We have made detailed studies of oxygen and carbon isotope ratios in diagenetic cements from shales of the Bakken Formation from the Williston basin and elsewhere. The Bakken contains both reservoir and source rocks for petroleum. Hydrofracturing has greatly enhanced production of oil in these tight reservoirs. The sediments contain zoned carbonate cements with growth textures that record multiple events. The growth of carbonate (dolomite) cements has been proposed to control reservoir quality, but previous stable isotope studies of homogenized powders could not resolve individual generations of cement and this proposal remains untested. Our better characterization of the multiple growth zones in these carbonates will aid in understanding the genesis of these tight reservoirs and the production of unconventional oil and gas. This study has also developed SIMS standards for analysis of all compositions of Ca-Mg-Fe carbonate and selected Mn-carbonates and hydromagnesite. We have refined techniques for improved accuracy of SIMS stable isotope analysis, and for sub-1-micron spot sizes. We have established protocols for mapping and correlating sample analyses at micron-scale using QGIS software.

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2020

Small-angle Neutron Scattering (SANS) Characterization of Clay- and Carbonate-rich Shale at Elevated Pressures

Unconventional oil and gas from shale formations have emerged as some of the fastest growing energy resources in the United States, providing both cleaner energy to consumers and reducing the nation’s reliance on energy imports. To properly harness these important natural resources, the nanopore structure of associated shales must be fully understood, particularly under hydraulic fracturing conditions, where they are exposed to both overburden compressive and hydrostatic fluid pressures. The current study uses small-angle neutron scattering (SANS) to characterize pore structure, including porosity, pore accessibility, and pore size distribution, in the 1–100 nm regime at elevated pressures for mineralogically distinct clay- and carbonate-rich shales from the Permian Basin. Unlike typical porosity measurement techniques, SANS is uniquely capable of characterizing both open and closed porosity, allowing measurement of how pore accessibility changes with pressure and determination of the size range of accessible versus inaccessible pores. The porosity of the clay-rich shale was 7.7%, compared to 0.51% for the carbonate-rich shale. However, only 2.6% of the nanopores in the carbonate-rich shale were inaccessible to water at 8 kPSI (55.1 MPa) compared to 7.8% for the clay-rich shale. Furthermore, our analyses indicated that the closed pores fall within distinct size ranges, likely corresponding with the chemical nature of the pore host material. These results provide valuable insight into the effects of shale petrophysical properties on hydrocarbon extraction from unconventional reservoirs.

36 MATERIALS SCIENCE↗
DOE OSTI2024

Active Seismoelectric Monitoring of CO 2 Injection

Conference presentation at Carbon Capture, Utilization, and Storage (CCUS) Conference 2024, Houston, Texas, March 11–13, 2024. We investigated the use of active seismoelectric monitoring (ASE) to determine its effectiveness in detecting CO 2 injected deep underground and as an additional monitoring option for carbon storage projects. The EERC performed an ASE survey in February of 2023 at Pennel oil field near Baker, Montana, as part of the U.S. Department of Energy-sponsored Williston Basin CO 2 Field Laboratory in conjunction with operating partner Denbury Inc. The field site is part of the Cedar Creek Anticline geologic structure, with CO 2 planned for injection into a stacked storage complex (SSC) in the Interlake Formation containing both a residual oil zone and a conventional reservoir. The objective was to test the ASE method’s ability to characterize baseline fluid distribution in both the near surface and the SSC prior to CO 2 injection.

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2021

Characterization of shale using Helium and Argon at high pressures

In order to estimate the shale gas in place and the eventual recovery during shale gas operations, one of the key requirements is to accurately characterize the shale’s petrophysical and transport properties such as porosity, permeability, diffusivity, and storage capacity. Despite the many efforts reported in the technical literature aiming to provide an improved understanding of the complex pore structures and the associated fluid flow in gas shales, complete characterization of organic-rich shale samples still poses a big challenge. Here, we have characterized mass transfer and sorption in shale at different length scales using Helium (He) and Argon (Ar) as probe gases. Thermogravimetric analysis (TGA) with a shale cube of ~1 cm 3 in size and gas expansion experiments with a full-diameter core (3.5” in diameter) were used to measure sorption kinetics/isotherms and mass transfer, respectively. Both samples are from the same depth/location in the Marcellus shale formation. The TGA steady-state technique was initially used to generate excess sorption isotherms for Ar, while dynamic TGA experiments were used to study its sorption kinetics. The TGA experiments demonstrate that Ar, which has a similar sorption potential as Methane, but is generally assumed to be inert, adsorbs onto the surfaces of the mesoporous and microporous regions of the shale samples according to a Langmuir-type behavior. Helium expansion experiments, on the full-diameter core, were used to measure the overall porosity, on the basis that He is a non-sorbing and inert gas as compared to Ar. The He expansion experiments, furthermore, allow us to delineate the mass transfer of gas across the inherent hierarchy of pore sizes, including macropores (macro- and microcracks), mesopores and micropores. Similar expansion experiments were also performed with Ar to study the combined impact of mass transfer and sorption. A triple-porosity model (TPM) was utilized to interpret the He expansion experiments with the shale core and to extract (estimate) relevant transport parameters. We report and compare here the diffusivities and permeabilities of the whole core for both He and Ar, as calculated from the modeling and fitting of the experimental data. On the premise that the shale cube is representative of the matrix region of the core, the Ar sorption kinetics from the cube experiments were subsequently combined with the transport parameters extracted from the He experiments to predict the behavior of the Ar expansion test with the full-diameter core. An excellent agreement is observed between the model predictions and the experimental data. The experimental observations and their interpretation indicate that one must be cautious when using Ar to estimate the true porosity and permeability of shales. In addition, we demonstrate that He and Ar probe gases, when used in tandem, can be employed effectively as a tool to characterize shales in terms of mass transfer and sorption dynamics across scales.

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2021

Conasauga Shale Research Consortium (CSRC) (Final Report)

The objective of the Conasauga Shale Research Consortium (CSRC) project was to establish a field laboratory and utilize a horizontal well of opportunity to conduct a scientific study designed to advance the understanding of the petrophysical and geomechanical properties of the emerging Rogersville Shale unconventional oil and gas play. Unfortunately, just as the research program was beginning, our industry partner lost a primary investor in the horizontal well which was intended to be the ‘well of opportunity’ for the project. In a negotiated restructuring of the project by DOE-NETL and the Awardee consortium, additional time for Budget Period 1 was granted in the hopes that the industry partner could acquire additional investments to allow for the drilling of the horizontal well. This search was ultimately unsuccessful, and the consortium was unable to pass the negotiated Go/No-go Decision Point #1, which resulted in the termination of the project on July 31, 2021.

02 PETROLEUM↗
DOE OSTI2021

Evaluation of Technically-Recoverable Resources in the Marcellus and Utica Shale Gas Plays of the Appalachian Basin

Well production estimates are evaluated to provide estimates of total and remaining technically-recoverable gas resources in the Marcellus and Utica shale gas plays of the Appalachian basin. Domestic gas resources are critical contributors to the United States (U.S.) economy and will be key to enabling the sustainable and carbon-neutral fuel systems of the future. Recent assessments by the Energy Information Administration (EIA) continue to identify resources of the Appalachian region as critical to meeting energy demand, with the Marcellus and Utica- Point Pleasant (“Utica”) shale plays combining for more than 30 percent of projected U.S. domestic natural gas production through 2050.

03 NATURAL GAS↗
DOE OSTI2022

Supplementary Data for "Evaluation of the Economic Implications of Varied Pressure Drawdown Strategies Generated Using a Real-time, Rapid Predictive, Multi-fidelity Model for Unconventional Oil and Gas Wells" by Bello, K., Vikara, D., Sheriff, A., Viswanathan, H., Carr, T., Sweeney, M., O'Malley, D., Marquis, M., Vactor, R.T., and Cunha, L.

The Bello et al. study evaluates the impact of contrasting pressure drawdown on gas productivity and the resulting economics of a well in the Marcellus Shale of the Appalachian Basin. This research applies a techno-economic analysis approach to help identify potential ways pressure management strategies can be used to improve cumulative recovery of hydraulically fractured horizontal wells while maintaining project profitability. Gas production forecast outlook scenarios of the Marcellus Shale Energy and Environment Laboratory Laboratory's MIP-3H well were generated under varying pressure drawdowns using two approaches: 1) a novel physics-informed machine learning (PIML) workflow and 2) via traditional reservoir simulation in Computer Modeling Group’s (CMG) GEM Compositional & Unconventional Simulator. Cash flow and other economic metrics of interest were compiled on the production outlook using the U.S. Department of Energy's (DOE) National Energy Technology Laboratory (NETL) Unconventional Shale Well Economic Model (UShWEM).The sheets within this Microsoft ExcelTM workbook provide the economic metric outputs for the baseline condition and the one-at-a-time (OAT) sensitivity analysis of UShWEM's input parameters for each of the production scenarios evaluated.

Fracture Network Model↗
DOE OSTI2023

Pore Structure and Wettability of Bossier Shale, East Texas, United States: Insights from Integrated Porosimetry, Scattering, and Imbibition Approaches

In this study, ascertaining the pore geometry and wettability characteristics of tight shales is of great significance for revealing the mechanisms of occurrence, migration, and production of shale resources. Taking the Bossier Shale collected from Well A, East Texas, USA, as an example, the pore geometry and wettability behavior in a broad nm-& μm scale pore spectrum were quantified based on integrated techniques, including water immersion porosimetry (WIP), mercury intrusion porosimetry(MIP), (ultra)small-angle X-ray scattering [(U)SAXS], contact angle, and liquid spontaneous imbibition (SI). Mainly owing to differences in the sample sizes used, data interpretation, as well as the detectable pore type (e.g., connected or not) and pore diameter ranges among different methods, sample porosities derived from WIP, MIP, and (U)SAXS were quite different, which range from 7.70 to 13.34%, 5.12 to 9.52%, and 2.48 to 6.44%, respectively. Therefore, a comparison of the porosities derived from different methods must be handled with utmost care. Additionally, although (U)SAXS is an effective technique for detecting both connected and non-connected pores, the fraction of non-connected pores could be underestimated by directly comparing the pore size distribution derived from (U)SAXS and MIP tests. This is because the sample sizes used for and pore information reflected by these two methods are different. Furthermore, the studied Bossier Shales exhibited various contact angle values and imbibition behaviors when using differently polarized liquids, revealing their mixed-wet characteristics. Comprehensively considering the differences in contact angle, imbibition slope, and imbibed liquid volume, three sub-categories of wettability behavior, with respect to more oil-wet, more water-wet, and intermediate mixed-wet, were qualitatively identified.

(U)SAXS↗
DOE OSTI2022

Tuscaloosa Marine Shale: Seal or Source? Petrophysical Comparative Study of Wells in SE Louisiana and SW Mississippi

The Tuscaloosa Marine Shale (TMS) is a versatile Late Cretaceous shale formation present in central and SE Louisiana and SW Mississippi, which drew attention because of the various roles played within the Tuscaloosa Group. In this paper, it is debated whether the Tuscaloosa Marine Shale can act as a source, reservoir, or seal all throughout the shale play or only in certain areas. Well log and core data from Adams County, Mississippi, are compared to data from East Feliciana Parish in Louisiana. Conclusions were drawn based on the results of well log analysis, X-ray Diffraction (XRD), porosity–permeability measurements, programmed pyrolysis, and fracture analysis. It was shown that the Tuscaloosa Marine Shale interval in SE Louisiana consists of important amounts of calcite, exhibits multiple natural fractures, has porosity values as high as 9.3%, and shows a TOC content of up to 2.8 wt%. On the other hand, samples from a well at the Cranfield field, MS, are characterized by considerably lower TOC values of around 0.88 wt%, porosities between 0.33% and 4%, and no serious fracturing. The formation demonstrates better reservoir and source potential in SE Louisiana and reliable CO2 sealing capacity in SW Mississippi. The analysis presented in this paper represents a holistic approach to the characterization of shale formations, is applicable to other plays around the world, and can be used as an integral part of CO2 sequestration or hydraulic fracturing programs.

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2024

Aromatic amino acid metabolism and active transport regulation are implicated in microbial persistence in fractured shale reservoirs

Abstract Hydraulic fracturing has unlocked vast amounts of hydrocarbons trapped within unconventional shale formations. This large-scale engineering approach inadvertently introduces microorganisms into the hydrocarbon reservoir, allowing them to inhabit a new physical space and thrive in the unique biogeochemical resources present in the environment. Advancing our fundamental understanding of microbial growth and physiology in this extreme subsurface environment is critical to improving biofouling control efficacy and maximizing opportunities for beneficial natural resource exploitation. Here, we used metaproteomics and exometabolomics to investigate the biochemical mechanisms underpinning the adaptation of model bacterium Halanaerobium congolense WG10 and mixed microbial consortia enriched from shale-produced fluids to hypersalinity and very low reservoir flow rates (metabolic stress). We also queried the metabolic foundation for biofilm formation in this system, a major impediment to subsurface energy exploration. For the first time, we report that H. congolense WG10 accumulates tyrosine for osmoprotection, an indication of the flexible robustness of stress tolerance that enables its long-term persistence in fractured shale environments. We also identified aromatic amino acid synthesis and cell wall maintenance as critical to biofilm formation. Finally, regulation of transmembrane transport is key to metabolic stress adaptation in shale bacteria under very low well flow rates. These results provide unique insights that enable better management of hydraulically fractured shale systems, for more efficient and sustainable energy extraction.

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2020

Fundamental Understanding of Methane-Carbon Dioxide-Water (CH 4 -CO 2 - H 2 O) Interactions in Shale Nanopores under Reservoir Conditions (Quarterly Report)

Shale is characterized by the predominant presence of nanometer-scale (1-100 nm) pores. The behavior of fluids in those pores directly controls shale gas storage and release in shale matrix and ultimately the wellbore production in unconventional reservoirs. Recently, it has been recognized that a fluid confined in nanopores can behave dramatically differently from the corresponding bulk phase due to nanopore confinement. CO 2 and H 2 O, either preexisting or introduced, are two major components that coexist with shale gas (predominately CH 4 ) during hydrofracturing and gas extraction. Note that liquid or supercritical CO 2 has been suggested as an alternative fluid for subsurface fracturing such that CO 2 enhanced gas recovery can also serve as a CO 2 sequestration process. Limited data indicate that CO 2 may preferentially adsorb in nanopores (particularly those in kerogen) and therefore displace CH 4 in shale. Similarly, the presence of water moisture seems able to displace or trap CH 4 in shale matrix. Therefore, fundamental understanding of CH 4 -CO 2 -H 2 O behavior and their interactions in shale nanopores is of great importance for gas production and the related CO 2 sequestration. This project focuses on the systematic study of CH 4 -CO 2 -H 2 O interactions in shale nanopores under high-pressure and high temperature reservoir conditions. The proposed work will help develop new stimulation strategies to enable efficient resource recovery from fewer and less environmentally impactful wells.

04 OIL SHALES AND TAR SANDS↗