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At least 19 records
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 OSTI2019

Carbon Storage and Enhanced Oil Recovery in Pennsylvanian Morrow Formation Clastic Reservoirs: Controls on Oil–Brine and Oil–CO2 Relative Permeability from Diagenetic Heterogeneity and Evolving Wettability

The efficiency of carbon utilization and storage within the Pennsylvanian Morrow B sandstone, Farnsworth Unit, Texas, is dependent on three-phase oil, brine, and CO2 flow behavior, as well as spatial distributions of reservoir properties and wettability. We show that end member two-phase flow properties, with binary pairs of oil–brine and oil–CO2, are directly dependent on heterogeneity derived from diagenetic processes, and evolve progressively with exposure to CO2 and changing wettability. Morrow B sandstone lithofacies exhibit a range of diagenetic processes, which produce variations in pore types and structures, quantified at the core plug scale using X-ray micro computed tomography imaging and optical petrography. Permeability and porosity relationships in the reservoir permit the classification of sedimentologic and diagenetic heterogeneity into five distinct hydraulic flow units, with characteristic pore types including: macroporosity with little to no clay filling intergranular pores; microporous authigenic clay-dominated regions in which intergranular porosity is filled with clay; and carbonate–cement dominated regions with little intergranular porosity. Steady-state oil–brine and oil–CO2 co-injection experiments using reservoir-extracted oil and brine show that differences in relative permeability persist between flow unit core plugs with near-constant porosity, attributable to contrasts in and the spatial arrangement of diagenetic pore types. Core plugs “aged” by exposure to reservoir oil over time exhibit wettability closer to suspected in situ reservoir conditions, compared to “cleaned” core plugs. Together with contact angle measurements, these results suggest that reservoir wettability is transient and modified quickly by oil recovery and carbon storage operations. Reservoir simulation results for enhanced oil recovery, using a five-spot pattern and water-alternating-with-gas injection history at Farnsworth, compare models for cumulative oil and water production using both a single relative permeability determined from history matching, and flow unit-dependent relative permeability determined from experiments herein. Both match cumulative oil production of the field to a satisfactory degree but underestimate historical cumulative water production. Differences in modeled versus observed water production are interpreted in terms of evolving wettability, which we argue is due to the increasing presence of fast paths (flow pathways with connected higher permeability) as the reservoir becomes increasingly water-wet. The control of such fast-paths is thus critical for efficient carbon storage and sweep efficiency for CO2-enhanced oil recovery in heterogeneous reservoirs.

Rasmussen, Lindsey↗
DOE OSTI2024

Repurposing Inactive Oil and Gas Wells for Energy Storage: Maximizing the Potential Via Optimal Drivetrain Control: Preprint

In recent years, there has been a growing emphasis on utilizing energy storage to enhance grid resilience against disruptive events. While renewable energy supply continues to expand, gravity-based solutions like pumped hydro remain dominant in the commercial space. However, their geographical limitations constrain availability, scalability, and increase costs for co-locating solar and wind energy. An alternative approach proposes repurposing idle oil and gas wells located closer to existing grid infrastructure, offering a promising and cost-effective solution. This paper addresses the optimization and control of a regenerative drive system coupled to an interior permanent magnet synchronous machine in a 300-meter well with a 100-Newton weight. The study employs a dynamic MATLAB/Simulink model to simulate the operation of the electric drivetrain system during storage and discharge operations. The results demonstrate an initial round-trip efficiency of 85.9% for the electrical system alone and identify crucial factors for maximizing efficiency. The optimized operation and control of the electromechanical drivetrain system hold great potential for minimizing the levelized cost of storage while maximizing efficiency and revenue generation.

ENERGY STORAGE,ENGINEERING↗
DOE OSTI2017

Use of Biosurfactants in Oil Recovery

Biosurfactant-mediated oil recovery has the potential to recover large amounts of crude oil that remain entrapped in oil reservoirs after current oil recovery technologies reach their economic limit. Lipopeptides (surfactins and lichenysins), rhamnolipids, and other glycolipids generate the low interfacial tensions and the appropriate rock wettabilities needed to mobilize entrapped oil. Biosurfactants are active over a wide range of temperatures, pH values, and salinities found in many oil reservoirs and are effective at low concentrations. A number of laboratory experiments show that biosurfactant-mediated oil recovery is effective in recovering large amounts of entrapped oil. Several field trials show that in situ biosurfactant production is possible and recovers additional oil. Biosurfactant-mediated oil recovery has been difficult to scale-up to a reservoir-wide technology due to the lack of understanding of how best to stimulate biosurfactant production in the reservoir. In addition, the relationship between biosurfactant concentration and oil recovery is still unclear. Ex-situ biosurfactant-mediated oil recovery where the biosurfactant is added to the injection fluids has not been implemented on a large scale, most likely due to the high production costs of biosurfactants. Multidisciplinary approaches are needed to move biosurfactant-mediated oil recovery from the laboratory to the reservoir.

02 PETROLEUM↗
DOE OSTI2019

Hydrotreatment of pyrolysis bio-oil: A review

Fast pyrolysis is an effective process to convert more than 60 wt. % of lignocellulosic materials into a bio-oil that can be further hydrotreated for transportation fuel production. However, bio-oil is acidic, viscous, and chemically unstable due to its high oxygen content. Therefore, increasing attention has being paid to deoxygenation of bio-oil through catalytic hydrotreatment into a “drop-in” fuel has been gaining attention from researchers. The first section of this review is devoted to summarize our current understanding of bio-oil composition. Bio-oil hydrotreatment is typically conducted in two-steps. In the first step, known as stabilization, the reactive carbonyl and carboxyl functional groups are transformed into alcohols at a temperature between 373 and 573 K. In the second step, between 623 and 673 K, cracking and hydro-deoxygenation (HDO) occurs. The most common catalysts used in the stabilization step are noble metals (Pt, Ru, Pd) supported on carbon and metal oxides (TiO2, Al2O3, SiO2, Fe2O3, ZrO2). The most common catalysts for deoxygenation and hydrocracking are sulfided CoMo or NiMo. More recently transition metal phosphides and carbides have been shown to be active. The effect of hydrotreatment parameters and the main global reaction mechanisms are discussed. In the first section, we update the progresses made on bio-oil composition, followed by a detailed discussion on the role of heterogeneous catalysts. Many of the bio-oil hydrotreament studies in the literature are based on model compound results. The reactions revealed by such approach are summarized and discussed. Although these studies provide valuable information for developing upgrading strategies, bio-oil chemistry is difficult to describe by model compounds. Thus, we also reviewed a smaller number of hydrotreatment studies of pyrolysis oil fractions. The presence of several oxygenated functional groups (phenols, carboxylic acids, carbonyls, alcohols) in monomeric and oligomeric molecules is a major challenge to study hydrotreatment reactions. Under realistic industrial operational conditions undesirable polymerization and crosslinking reactions leading to catalyst deactivation are very important. In spite of the extensive work on bio-oil hydrotreatment, the nature of the reactions happening in these complex oils is still poorly known. Pyrolytic lignin and sugars have been identified as important contributors to coke formation. Both fractions can then undergo successful hydrogenation or hydrogenolysis over the catalysts. The review ends with a discussion on future prospects and challenges to hydrotreat pyrolysis oils. Because bio-oil is a liquid formed by hundreds of molecules covering a wide range of molecular weights and functionalities, it is very unlikely that a single hydrotreatment technology that makes a good use of each of its molecules could be found. In fact, current hydrotreatment schemes sacrifice some fractions (convert them into low value products) to maximize the conversion of others into fuel. Separation of bio-oil in fractions and processing of each of them via hydrotreatment or by other suitable technology at optimized conditions with well suited catalysts to obtain high value products seems to be the most promising path to reduce hydrogen consumption, coke formation and enhance the economic viability of bio-oil refineries.

Han, Yinglei↗
DOE OSTI2015

Clean and Secure Energy from Domestic Oil Shale and Oil Sands Resources

This report summarizes the significant findings from the Clean and Secure Energy from Domestic Oil Shale and Oil Sands Resources program sponsored by the Department of Energy through the National Energy Technology Laboratory. There were four principle areas of research; Environmental, legal, and policy issues related to development of oil shale and oil sands resources; Economic and environmental assessment of domestic unconventional fuels industry; Basin-scale assessment of conventional and unconventional fuel development impacts; and Liquid fuel production by in situ thermal processing of oil shale Multiple research projects were conducted in each area and the results have been communicated via sponsored conferences, conference presentations, invited talks, interviews with the media, numerous topical reports, journal publications, and a book that summarizes much of the oil shale research relating to Utah’s Uinta Basin. In addition, a repository of materials related to oil shale and oil sands has been created within the University of Utah’s Institutional Repository, including the materials generated during this research program. Below is a listing of all topical and progress reports generated by this project and submitted to the Office of Science and Technical Information (OSTI). A listing of all peer-reviewed publications generated as a result of this project is included at the end of this report; Geomechanical and Fluid Transport Properties 1 (December, 2015); Validation Results for Core-Scale Oil Shale Pyrolysis (February, 2015); and Rates and Mechanisms of Oil Shale Pyrolysis: A Chemical Structure Approach (November, 2014); Policy Issues Associated With Using Simulation to Assess Environmental Impacts (November, 2014); Policy Analysis of the Canadian Oil Sands Experience (September, 2013); V-UQ of Generation 1 Simulator with AMSO Experimental Data (August, 2013); Lands with Wilderness Characteristics, Resource Management Plan Constraints, and Land Exchanges (March, 2012); Conjunctive Surface and Groundwater Management in Utah: Implications for Oil Shale and Oil Sands Development (May, 2012); Development of CFD-Based Simulation Tools for In Situ Thermal Processing of Oil Shale/Sands (February, 2012); Core-Based Integrated Sedimentologic, Stratigraphic, and Geochemical Analysis of the Oil Shale Bearing Green River Formation, Uinta Basin, Utah (April, 2011); Atomistic Modeling of Oil Shale Kerogens and Asphaltenes Along with their Interactions with the Inorganic Mineral Matrix (April, 2011); Pore Scale Analysis of Oil Shale/Sands Pyrolysis (March, 2011); Land and Resource Management Issues Relevant to Deploying In-Situ Thermal Technologies (January, 2011); Policy Analysis of Produced Water Issues Associated with In-Situ Thermal Technologies (January, 2011); and Policy Analysis of Water Availability and Use Issues for Domestic Oil Shale and Oil Sands Development (March, 2010)

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2021

Heavy Oil Polymer EOR in the Challenging Alaskan Arctic - It Works!

Under co-sponsorship of the US Department of Energy and Hilcorp Alaska LLC the first ever polymer field pilot commenced on 8/28/2018 in the Schrader Bluff heavy oil reservoir at the Milne Point Field on Alaska North Slope (ANS). The primary objective of the pilot is to prove the efficacy of polymer Enhanced Oil Recovery (EOR) to unlock the vast heavy oil resources on ANS. More than two and half years after startup, the polymer injection, supporting laboratory experiments and simulation studies steadily continue. The pilot started injecting hydrolyzed polyacrylamide (HPAM), at a concentration of 1,750 ppm to achieve a target viscosity of 45 cP, into the two horizontal injectors in the flood pattern. Production is monitored in the two horizontal producers. Based on laboratory measurements of polymer viscosity at reservoir conditions, the team decided to reduce polymer concentration to 1,200 ppm since July 2020 in an effort to control injection pressure and optimize polymer utilization. Quality control (QC) on the field ensures uniform polymer solution properties. Representative rock and fluid systems and test conditions are utilized in the corefloods on polymer retention, effect of injection water salinity, polymer loading, and their combinations on oil recovery. A history matched reservoir simulation model for forecasting oil recovery was developed on the basis of all the available field data. Field concerns related to the post-polymer breakthrough impact on flow assurance is addressed via specialized laboratory tests. Notwithstanding early operational disruptions and hydration issues, continuous polymer injection in both injectors has been achieved. To date, 950,000 lbs of polymer or 2 million barrels of polymer solution, equating to 13% of total pore volume (PV), has been placed in the flood pattern, serving as an effective indicator of adequate polymer injectivity. So far, the success of polymer EOR is evident from drastically reduced water cut in the producers, an estimated incremental 1,000 bopd over waterflood, and a favorable polymer utilization of 1.7 lbs/barrel of incremental oil. Polymer breakthrough was observed 26 months after the start of polymer injection. Main observations from corefloods are unusually high polymer retention values in some cases and a positive response to low salinity water. Although the heterogeneity in the flood pattern and exceptionally low water cut pose some challenges, persistent novel and justifiable simulation approaches have resulted in a robust history matched model. Experimental results on produced fluids treatment provide operational guidance for improved oil-water separation and mitigation of heater tube fouling. The ongoing success of the pilot is a key indicator of bringing the team ever closer to meeting the project’s primary objective. The encouraging results of the pilot is one of the drivers that has provided the impetus to apply polymer EOR throughout the Milne Point Field, which would increase oil recovery and extend the economic life of the Trans Alaska Pipeline System. The scientific knowledge, including the many lessons learned from this pilot also has referential value for other potential heavy oil EOR projects throughout the world. The collected data, operational lessons learned, and the overall success of the pilot are summarized in the paper.

None, None↗
DOE OSTI2017

Characterization of upgraded fast pyrolysis oak oil distillate fractions from sulfided and non-sulfided catalytic hydrotreating

Catalytic hydroprocessing of pyrolysis oils from biomass produces hydrocarbons that can be considered for liquid fuel production. This process requires removal of oxygen and cracking of the heavier molecular weight bio-oil constituents into smaller fragments at high temperatures and pressures under hydrogen. A comprehensive understanding of product oils is useful to optimize cost versus degree of deoxygenation. Additionally, a better understanding of the chemical composition of the distillate fractions can open up other uses of upgraded oils for potentially higher-value chemical streams. We present in this paper the characterization data for five well-defined distillate fractions of two hydroprocessed oils with different oxygen levels: a low oxygen content (LOC, 1.8% O, wet basis) oil and a medium oxygen content (MOC, 6.4% O, wet basis) oil. Elemental analysis and 13C NMR results suggest that the distillate fractions become more aromatic/unsaturated as they become heavier. Our results also show that the use of sulfided catalysts directly affects the S content of the lightest distillate fraction. Carbonyl and carboxylic groups were found in the MOC light fractions, while phenols were present in the heavier fractions for both MOC and LOC. PIONA analysis of the light LOC fraction shows a predominance of paraffins with a minor amount of olefins. These results can be used to direct future research on refinery integration and production of value-added product from specific upgraded oil streams.

biofuel↗
DOE OSTI2018

Global carbon intensity of crude oil production

Producing, transporting, and refining crude oil into fuels such as gasoline and diesel accounts for ~15 to 40% of the “well-to-wheels” life-cycle greenhouse gas (GHG) emissions of transport fuels. Reducing emissions from petroleum production is of particular importance, as current transport fleets are almost entirely dependent on liquid petroleum products, and many uses of petroleum have limited prospects for near-term substitution (e.g., air travel). Better understanding of crude oil GHG emissions can help to quantify the benefits of alternative fuels and identify the most cost-effective opportunities for oil-sector emissions reductions. Yet, while regulations are beginning to address petroleum sector GHG emissions, and private investors are beginning to consider climate-related risk in oil investments, such efforts have generally struggled with methodological and data challenges. First, no single method exists for measuring the carbon intensity (CI) of oils. Second, there is a lack of comprehensive geographically rich datasets that would allow evaluation and monitoring of life-cycle emissions from oils. We have previously worked to address the first challenge by developing open-source oil-sector CI modeling tools [OPGEE, supplementary materials (SM) 1.1]. Furthermore, we address the second challenge by using these tools to model well-to-refinery CI of all major active oil fields globally—and to identify major drivers of these emissions.

02 PETROLEUM↗
DOE OSTI2024

Co-hydrotreatment of Bio-oil and Waste Cooking Oil to Produce Transportation Fuels

This paper reports the co-hydrotreatment of the heavy bio-oil fraction with waste cooking oil (WCO) using NiMo/γ-Al 2 O 3 catalyst, followed by the distillation of resulting deoxygenated oil and the characterization of resulting fuel cuts. The heavy BTG bio-oil fraction was obtained by removing the very reactive light-oxygenated compounds via rotary evaporation, subsequently mixed with 1-butanol. The resulting oil was blended with WCO and subjected to a two-step co-hydrotreatment process. The first step, called “stabilization,” is aimed at saturating highly reactive hydrogen-deficient compounds. The second step, called “deoxygenation,” aimed to remove bio-oil oxygen, primarily as H 2 O. This study examined the impact of varying bio-oil concentrations (0, 10, 20, 30, 40 wt.% of WCO) on the upgraded oil's yield, composition, and fuel properties. The resulting hydrotreated oil was distilled into gasoline-range, kerosene-range, and diesel-range hydrocarbons at <150 °C, 150 to 250 °C, and 250 to 350 °C, respectively. The yield of the hydrotreated oil indicates that as the bio-oil concentration increases, the amounts of coke (0.7 to 2.4 %) and water (2 to 10 wt. %) increase while the organic layer yields decrease (80 to 63 %). The coke yield was comparable to the coke yield obtained when co-processing the pyrolytic lignin fraction. This suggests that coke is formed from both the sugar oligomers and the lignin-derived oligomers. The UV-fluorescence analysis on the hydrotreated oil shows that more polycondensed and conjugated ring compounds formed as the bio-oil concentration is increased. These compounds are precursors of coke. FTIR results showed that most raw materials were converted to biofuels after the hydrotreatment. To achieve less than 1 wt. % of coke yield, blends with up to 20 wt. % pyrolysis oil should be used. An increase in bio-oil concentration leads to a slight increase in gasoline yield and a decrease in kerosene and diesel yields. The identified carbon species found in the fuel cuts include n-paraffin, iso-paraffin, cycloparaffin, and aromatics. Further, the jet fuel cut (kerosene) was characterized by density, surface tension, and viscosity. Our product conforms to the standard specifications for sustainable aviation fuels (Jet A-1). Further research is suggested to fine-tune the operating parameters for achieving reduced coke yield and enhanced kerosene yield.

09 BIOMASS FUELS↗
DOE OSTI2021

Geochemical advances in Arctic Alaska oil typing – North Slope oil correlation and charge history

The Arctic Alaska petroleum province is geologically and geochemically complex. Mixed hydrocarbon charge from multiple source rocks and/or levels of thermal maturity is common within an individual oil pool. Biomarker and chemometric statistical analyses were used to correlate twenty-nine oils to five oil families derived from: (1) Triassic Shublik Formation (calcareous organofacies), (2) Triassic Shublik Formation (shaly organofacies), (3) Jurassic Kingak Shale, (4) Cretaceous shale (pebble shale unit and Hue Shale), and (5) Paleogene shale (Canning Formation). Age-diagnostic and source-related oil biomarker parameters establish clear genetic relationships between the normal oil-window components and their putative source designations. However, application of diamondoid analyses reveals mixed-oil accumulations with postmature charge contributions (diamondoid-rich and biomarker-poor) in many oils. Most sampled reservoirs contain a predominant charge derived from a single oil-window source plus a minor contribution from one or more higher maturity source(s). Variations in source organofacies also are recognized in the Shublik, Kingak, and Cretaceous oil families. In some cases, oils from multiple pools within a single field display relatively homogeneous geochemical profiles, suggesting a common source and migration pathway. For example, oil from the significant Pikka discovery is inferred to originate mainly from the calcareous Shublik Formation. In other cases, variability among oils from multiple pools within a single field (e.g., Milne Point, Colville River, and Northstar) likely indicates a more complex source, migration, and charge history. The results of this study may be useful for anticipating the composition of oil charge in stratigraphic traps with low-permeability sandstone reservoirs, where oil gravity and other chemical parameters may influence economic viability.

58 GEOSCIENCES↗
DOE OSTI2022

Coprocessing Biomass Fast Pyrolysis and Catalytic Fast Pyrolysis Oils with Vacuum Gas Oil in Refinery Hydroprocessing

Fast pyrolysis and catalytic fast pyrolysis (CFP) have been considered to be promising approaches for converting lignocellulosic biomass into liquid bio-oils followed by upgrading to produce fuel-range hydrocarbon products. Co-processing fast pyrolysis and CFP bio-oils with petroleum feedstocks leverages the existing petroleum refining infrastructure, which reduces Capex for the overall conversion technologies for biomass to fuel and enables fast adoption of the technologies and biofuels. Here, we reported the co-processing of different woody fast pyrolysis and CFP bio-oils with petroleum vacuum gas oil (VGO) at 5-25% bio-oil blending levels over a NiMo sulfide catalyst for mild hydrocracking. The catalyst activities over ~300 hours time on stream, the product yield and properties, and the biogenic carbon content in products are provided. Co-processing of the raw fast pyrolysis bio-oil in our configuration was not successful because the instability of the bio-oil resulted in reactor plugging and bio-oil stabilization by hydrogenation enabled their stable co-processing with VGO, whereas the CFP bio-oil can be co-processed without pretreatment. Simultaneous hydrodesulfurization, hydrodeoxygenation, and hydrocracking reactions occurred during co-processing and no obvious decrease in hydrodesulfurization and hydrocracking conversion of VGO was observed, suggesting the minimal impact of co-processed bio-oils on the reaction of VGO and also the simultaneous conversion of bio-oil and VGO to produce fuel products with much-reduced S and O content. Biogenic carbon content in co-processed products calculated by yield mass balance, together with results from isotopic measurements, indicates high biogenic carbon incorporation into liquid hydrocarbon products. In conclusion, higher biogenic carbon incorporation into fuel products was observed when co-processing CFP bio-oils than the fast pyrolysis bio-oils and over 90% of carbon in CFP bio-oil was incorporated into liquid hydrocarbon products.

09 BIOMASS FUELS↗
DOE OSTI2018

Improved Characterization and Modeling of Tight Oil Formations for CO 2 Enhanced Oil Recovery Potential and Storage Capacity Estimation

Tight oil formations such as those in the Bakken petroleum system are known to hold hundreds of billions of barrels of oil in place; however, the primary recovery factor for these plays is typically less than 10%. Tight oil formations, including the Bakken Formation, therefore, may be attractive candidates for enhanced oil recovery (EOR) using CO 2 . Multiphase fluid behavior and flow in fluid-rich shales can vary substantially depending on the size of pore throats, and properties such as fluid viscosity and density are much different in nanoscale pores than in macroscale pores. Thus it is critical to understand the nature and distribution of nano-, micro-, and macroscale pores and fracture networks. To address these issues, the Energy & Environmental Research Center (EERC) has been conducting a research program entitled “Improved Characterization and Modeling of Tight Oil Formations for CO 2 Enhanced Oil Recovery Potential and Storage Capacity Estimation.” The objectives of the project are 1) the use of advanced characterization methods to better understand and quantify the petrophysical and geomechanical factors that control CO 2 and oil mobility within tight oil formation samples, 2) the determination of CO 2 permeation and oil extraction rates in tight reservoir rocks and organic-rich shales of the Bakken, and 3) the integration of the laboratory-based CO 2 permeation and oil extraction data and the characterization data into geologic models and dynamic simulations to develop predictions of CO 2 storage resource and EOR in the Bakken tight oil formation. A combination of standard and advanced petrophysical characterization techniques were applied to characterize samples of Bakken Formation tight reservoir rock and shales from multiple wells. Techniques included advanced computer tomography (CT) imaging, scanning electron microscopy (SEM) techniques, whole-core and micro x-ray CT imaging, field emission (FE) SEM, and focused ion beam (FIB) SEM. Selected samples were also analyzed for geomechanical properties. X-ray CT imaging yielded information on the occurrence of fractures, bedding planes, fossils, and bioturbation in core, as well as data on bulk density and photoelectric factor logs, which were used to interpret porosity, organic content, and mineralogy. FESEM was used for characterization of nano- and microscale features, including nanoscale pore visualization and micropore and pore throat mineralogy. FIBSEM yielded micro- to nanoscale visualization of fracture networks, porosity and pore-size distribution, connected versus isolated porosity, and distribution of organics. Results from the characterization activities provide insight on nanoscale fracture properties, pore throat mineralogy and connectivity, rock matrix characteristics, mineralogy, and organic content. Laboratory experiments demonstrated that CO 2 can permeate the tight matrix of Bakken shale and nonshale reservoir samples and mobilize oil from those samples. Geologic models were created at scales ranging from the core plug to the reservoir, and dynamic simulations were conducted. The data from the characterization and laboratory-based activities were integrated into modeling research activities to determine the fundamental mechanisms controlling fluid transport in the Bakken, which support EOR scheme design and estimation of CO 2 storage potential in tight oil formations. Simulation results suggest a CO 2 storage resource estimate range of 169 million to 1.5 billion tonnes for the Bakken in North Dakota, possibly resulting in 1.8 billion to 16 billion barrels of incremental oil.

04 OIL SHALES AND TAR SANDS↗