Search USGS⌕ Search

SEARCH · Search USGS

Results for “Energy and Fuels”

Search indexed USGS publications on groundwater, aquifers, geologic maps, mineral resources and earthquakes. Explore source records by subject and place.

Quote a phrase for an exact phrase match. Source license links do not imply unrestricted reuse.

At least 37 records · Page 2Linked to original sources

Greenhouse gas emissions from an arid-zone reservoir and their environmental policy significance: Results from existing global models and an exploratory dataset

Reservoirs in arid regions often provide critical water storage but little is known about their greenhouse gas (GHG) footprint. While there is growing appreciation of the role reservoirs play as GHG sources, there is a lack of understanding of GHG emission dynamics from reservoirs in arid regions and implications for environmental policy. Here we present initial GHG emission measurements from Lake Powell, a large water storage reservoir in the desert southwest United States. We report CO 2 -eq emissions from the shallow (< 15 m) littoral regions of the reservoir that are higher than the global average areal emissions from reservoirs (9.4 vs. 5.8 g CO 2 -eq m −2 d −1 ) whereas fluxes from the main reservoir were two orders of magnitude lower (0.09 g CO 2 -eq m −2 d −1 ). We then compared our measurements to modeled CO 2 + CH 4 emissions from the reservoir using four global scale models. Factoring these emissions into hydropower production at Lake Powell yielded low GHG emissions per MWh −1 as compared to fossil-fuel based energy sources. With the exception of one model, the estimated hydropower emissions for Lake Powell ranged from 10−32 kg CO 2 -eq MWh −1 , compared to ∼400−1000 kg CO 2 -eq MWh −1 for natural gas, oil, and coal. We also estimate that reduced littoral habitat under low water levels leads to ∼50% reduction in the CO 2 equivalent emissions per MWh. The sensitivity of GHG emissions to reservoir water levels suggests that the interaction will be an important policy consideration in the design and operation of arid region systems.

Utah↗

Exploring methane behavior in Marcellus Shale micropores via contrast matching neutron scattering

Petroleum in shale reservoirs is hosted in organic matter and mineral pores as well as in natural fractures and voids. For thermally mature plays, e.g., the Marcellus Shale, methane and other light alkane gases are thought to be primarily contained in organic matter pores with radii ≦50 nm. Thus, in order to understand natural gas occurrence, transport, storage, and recoverability within unconventional reservoirs at the dry-gas stage of thermal maturity, it is critical to characterize the associated organic matter porosity across length scales from 50 nm down to the angstrom level. We utilized wide Q-range neutron total scattering to characterize deuterated methane (CD 4 ) adsorption at 60ºC up to the zero average contrast (ZAC) pressure (~60 MPa) within two mineralogically different samples collected from the same producing interval from the Middle Devonian Marcellus Shale. The neutron scattering approach used here provides structural information from the inter-atomic regime up to a nominal pore radius of ~12.5 nm and, by reaching the CD 4 ZAC pressure (~60 MPa), it is possible to examine the distribution of open versus closed pores within this pore size range in the samples. Our results indicate that ~10% of the largest pores measured are closed to CD 4 for a quartz-rich sample whereas up to 25% of pores with a nominal radius of ~12.5 nm are inaccessible within a sample with an equivalent proportion of quartz, carbonate, and clay. As pore size decreases, accessibility also decreases; all pores with radii ~0.5 nm are effectively closed to CD 4 in both samples. Additionally, up to ~4.5× more CD 4 is adsorbed within the quartz-rich sample at 60 MPa and we see no evidence for densification of CD 4 within the shale pores. These findings suggest that, for shale samples within the dry-gas window, (i) nanometer-scale porosity is primarily located within organic matter, (ii) the amount of available nano-porosity can vary widely over meter scales, and (iii) mineralogy plays a secondary role in dictating methane behavior within these systems.

West Virginia↗

Organo-facies and mineral effects on sorption capacity of low-maturity Permian Barakar shales from the Auranga Basin, Jharkhand, India

Shales associated with the Lower Permian (Barakar Formation) sediments of the Auranga Coalfield, India, occur in the immature–early mature stage. The sorption capacity of Barakar shale samples has been studied through high-pressure methane (CH 4 ) adsorption and low-pressure N 2 gas adsorption (LPN 2 GA) methods, supported with proximate analyses, programmed pyrolysis, optical petrography, and with energy-dispersive spectroscopy, X-ray diffraction, and inductively coupled plasma mass spectrometry. The sorption capacity is a function of the organic and inorganic constituents present in the shale samples. The methane sorption capacity (MSC) and Langmuir volume of the shale samples vary from 0.217 to 0.314 and 0.315 to 0.429 mmol/g rock, respectively. The BET-calculated surface area of the studied shales varies from 8.12 to 30.36 m 2 /g. The sorption capacities show the importance of the total organic content (TOC) through weak but positive correlations with MSC ( r 2 = 0.45) and S 1 values (mg hydrocarbons/g rock from programmed pyrolysis; r 2 = 0.40). Moreover, apparent inverse relationships were observed between MSC and clay mineral abundances, suggesting that individual clay mineral types may influence MSC, although more work is needed. The TOC-normalized MSC (MSC*) of shale samples shows a positive trend with quartz plus clay mineral content and ash yield of r 2 = 0.64 for both. In addition, MSC* shows a negative logarithmic relationship with S 1 + S 2 ( r 2 = 0.63) and a positive linear relationship with TOC-normalized total organic matter (TOM*) ( r 2 = 0.88, when 5 low TOM* samples are excluded) indicating complex relationships possibly including bitumen retention in the sample pore spaces. The micropore study of the samples through LPN 2 GA, applying Dubinin–Radushkevich, Dubinin–Astakhov, and density functional theory models, shows the dominance of micro-mesopore concentrations in the shale matrix of ∼2 nm pore diameter. However, these pores might be present as blind or closed pores. The presence of thorium and zirconium is reflective of terrigenous detrital matter, i.e., moderately to strongly recycled sediments. The fluviatile facies of deposited shales in the Auranga Coalfield are noted by the significant presence of kaolinite (32.5–78.3%), which suggests the importance of its effect on the sorption capacity of proximal terrigenous shales.

Jharkhand↗

Virtual special issue of recent advances on gas hydrates scientific drilling in Alaska

Gas hydrate refers to a non-stoichiometric clathrate that forms spontaneously in the natural environment whenever sufficient quantities of gases of appropriate size (most commonly methane) interact with abundant water under specific conditions of temperature and pressure. (1,2) Such conditions occur wherever the shallow geothermal gradient has been suppressed by either deepwater or thick permafrost, allowing for relatively low temperatures to coexist with elevated pressures. The volume of gas hydrate on Earth is difficult to constrain, (3) but it is sufficient that gas hydrate is a meaningful potential component of (1) the long-term natural cycling of carbon, (2) the nearer term environmental changes in response to warming climates, (4) and (3) future energy supply systems. Since the initial recognition of gas hydrate as an abundant component in nature in the late 1960s, a series of scientific drilling expeditions conducted by both the Integrated Ocean Discovery Program (and successors) and national research and development programs in Canada, Japan, China, the United States, South Korea, and others (5) have explored the occurrence and nature of gas hydrates. In particular, the desire for expanded energy supply options to support the economic development and energy security for nations around the globe is currently motivating a broad range of laboratory and numerical simulation studies in support of an ongoing series of field-based scientific tests of the potential commercial viability of gas extraction from natural gas hydrate deposits. (6)

Journal of Energy & Fuels↗

Examining water and proppant demand, and produced water production, associated with petroleum resource development in the Eagle Ford Group, Texas

More than 20,000 horizontal wells have been drilled and hydraulically fractured in the Eagle Ford Group since the discovery well in 2008, but a considerable amount of undiscovered petroleum remains. Recently, drilled wells have been hydraulically fractured with an average of nearly 13 million gallons of water and 16 million lb of sand, yielding a million or more gallons of produced water. To inform future petroleum development in the Eagle Ford, the U.S. Geological Survey (USGS) conducted a water and proppant assessment using a geology-based approach that builds on the 2018 USGS assessment of undiscovered technically recoverable petroleum. Using probabilistic input values and a Monte Carlo simulation, we determined that production of the remaining undiscovered technically recoverable oil and gas in the Eagle Ford Group would require approximately 687,565 Mgal (millions of gallons) of water and 839,702,000,000 lb of proppant (both are mean values of output distributions). This possible future petroleum production would also include 176,817 Mgal (mean value) of produced formation water. On average, oil wells require water volumes that are approximately twice the volume of oil that will be produced, and Eagle Ford gas wells require approximately 5.21 Mgal of water per billion cubic feet of gas (bcfg). Produced formation water volumes are approximately 60% of the produced oil volume and, for gas wells, will yield approximately 1 Mgal formation water per bcfg. Understanding the water and proppant requirements associated with petroleum exploration and the resulting volume of produced water can inform decisions regarding the future of Eagle Ford development.

Texas↗

Detailed description of oil shale organic and mineralogical heterogeneity via fourier transform infrared mircoscopy

Mineralogical and geochemical information on reservoir and source rocks is necessary to assess and produce from petroleum systems. The standard methods in the petroleum industry for obtaining these properties are bulk measurements on homogenized, generally crushed, and pulverized rock samples and can take from hours to days to perform. New methods using Fourier transform infrared (FTIR) spectroscopy have been developed to more rapidly obtain information on mineralogy and geochemistry. However, these methods are also typically performed on bulk, homogenized samples. We present a new approach to rock sample characterization incorporating multivariate analysis and FTIR microscopy to provide non-destructive, spatially resolved mineralogy and geochemistry on whole rock samples. We are able to predict bulk mineralogy and organic carbon content within the same margin of error as standard characterization techniques, including X-ray diffraction (XRD) and total organic carbon (TOC) analysis. Validation of the method was performed using two oil shale samples from the Green River Formation in the Piceance Basin with differing sedimentary structures. One sample represents laminated Green River oil shales, and the other is representative of oil shale breccia. The FTIR microscopy results on the oil shales agree with XRD and LECO TOC data from the homogenized samples but also give additional detail regarding sample heterogeneity by providing information on the distribution of mineral phases and organic content. While measurements for this study were performed on oil shales, the method could also be applied to other geological samples, such as other mudrocks, complex carbonates, and soils.

Energy & Fuels↗

Extraction of hydrocarbons from high-maturity Marcellus Shale using supercritical carbon dioxide

Shale is now commonly exploited as a hydrocarbon resource. Due to the high degree of geochemical and petrophysical heterogeneity both between shale reservoirs and within a single reservoir, there is a growing need to find more efficient methods of extracting petroleum compounds (crude oil, natural gas, bitumen) from potential source rocks. In this study, supercritical carbon dioxide (CO 2 ) was used to extract n -aliphatic hydrocarbons from ground samples of Marcellus shale. Samples were collected from vertically drilled wells in central and western Pennsylvania, USA, with total organic carbon (TOC) content ranging from 1.5 to 6.2 wt %. Extraction temperature and pressure conditions (80°C and 21.7 MPa, respectively) were chosen to represent approximate in situ reservoir conditions at sample depth (1920–2280 m). Hydrocarbon yield was evaluated as a function of sample matrix particle size (sieve size) over the following size ranges: 1000–500 μm, 250–125 μm, and 63–25 μm. Several methods of shale characterization including Rock-Eval II pyrolysis, organic petrography, Brunauer–Emmett–Teller surface area, and X-ray diffraction analyses were also performed to better understand potential controls on extraction yields. Despite high sample thermal maturity, results show that supercritical CO 2 can liberate diesel-range ( n -C 11 through n -C 21 ) n -aliphatic hydrocarbons. The total quantity of extracted, resolvable n -aliphatic hydrocarbons ranges from approximately 0.3 to 12 mg of hydrocarbon per gram of TOC. Sieve size does have an effect on extraction yield, with highest recovery from the 250–125 μm size fraction. However, the significance of this effect is limited, likely due to the low size ranges of the extracted shale particles. Additional trends in hydrocarbon yield are observed among all samples, regardless of sieve size: 1) yield increases as a function of specific surface area ( r 2 = 0.78); and 2) both yield and surface area increase with increasing TOC content ( r 2 = 0.97 and 0.86, respectively). Given that supercritical CO 2 is able to mobilize residual organic matter present in overmature shales, this study contributes to a better understanding of the extent and potential factors affecting the extraction process.

Pennsylvania↗

Consolidation and permeability of the B1 and D1 gas hydrate bearing sands and associated seal sediments of the extended-duration gas production test site on the Alaska North Slope

Gas hydrate, a solid combination of gas (mostly methane in nature) and water molecules stable at low temperatures and elevated pressures, occurs naturally in marine and permafrost-associated environments. Gas hydrate reservoirs, such as those in the Alaska North Slope, have been considered potential energy resources for gas production. To understand the petrophysical and geo-mechanical characteristics of the reservoir, core samples retrieved from the site of the JOGMEC-DOE-USGS collaborative gas hydrate R&D project have been analyzed in the laboratory for their hydraulic and mechanical properties. This paper focuses on both seal and reservoir samples associated with the B1 and D1 sands, which are evaluated for index properties (including porosity, grain size distribution, liquid and plastic limits, specific surface area, and specific gravity), consolidation, permeability, and water retention. Furthermore, the reservoir core samples were tested with pore-filling, laboratory-grown tetrahydrofuran hydrate, in order to assess reservoir behavior during gas production from hydrates. Under simulated in situ stress conditions, the seal and hydrate-free reservoir cores had a permeability anisotropy ratio of k h / k v = 3.0–5.0, and k h / k v = 2.4–3.0 for the reservoir tetrahydrofuran hydrate-bearing cores. The data suggest that depressurizing the reservoir to induce hydrate dissociation alters the reservoir effective permeability in three ways: permeabilities decrease due to porosity lost (e.g., the initial reservoir thickness can decrease by up to 5% upon 7 MPa depressurization), permeability increases due to the loss of solid hydrate in the pore space, and permeability anisotropy k h / k v decreases in response to the evolving pore-space geometry. We show that given the simulated in situ gas hydrate saturations (i.e., S h = 32% in core 7P-2E and S h = 21% in core 20P-4), gas production from the dissociation of tetrahydrofuran hydrate in the two tested cores results in a net increase in effective permeability and a decrease in k h / k v . This study highlights the importance of investigating seal and reservoir sediments and the impacts of depressurization on the porosity and permeability responses during production.

Alaska↗

Permeability and compressibility of “seal” sediment overlying the B1 sand gas hydrate reservoir: Hydrate 02 Geo Data Well, Prudhoe Bay unit, Alaska North Slope

An important element in evaluating the viability of extracting methane from a gas hydrate-bearing reservoir is establishing the effectiveness of the overlying bounding sediment as a seal to prevent gas loss, to enable effective depressurization, and to prevent fluid from entering the reservoir during production. This laboratory study presents results for index properties (e.g., grain density, grain size, and liquid limit), compressibility and swelling indices, and permeability measurements on sediment overlying the gas hydrate-bearing reservoir that was the target of the recent JOGMEC-DOE-USGS collaborative gas hydrate production testing project on the Alaska North Slope (ANS). Sediment analyzed in this study was collected during pressure coring operations in the HYDRATE 02 Geo Data Well (GDW). The ∼6.1 m sediment interval recovered in Cores 13P and 14P (878.74–884.88 m measured depth, MD) exhibited heterogeneous sedimentologic characteristics at the centimeter scale, with sediments ranging from clay to thin silty-sand lithologies. Permeability measurements and index-property correlations indicate the interval’s overall in situ vertical permeability ranges from 0.2 to 3.6 microdarcy (μD). Results for compressibility ( C C = 0.255 ± 0.02) and swelling index ( C S = 0.04 ± 0.01) are consistent with estimates based on mineralogy and liquid limit correlations. Based on the measured compressibility, the ∼3 MPa increase in effective stress during the stable phase of depressurization-induced production is anticipated to have imposed 2.43 cm of compaction per meter in the reservoir overburden, reducing permeability by ∼36%. The overburden sediment’s low in situ permeability (3 to 4 orders of magnitude below permeabilities measured in the gas hydrate-bearing part of the B1 sand (unit B)) suggests the B1 sand′s overburden provides an effective seal. Such a seal promotes efficient production by limiting fluid flow into the reservoir during depressurization-induced gas hydrate dissociation.

Alaska↗

Strength, stiffness, and Poisson’s ratio measurements for cements used in the well completions for the extended-duration gas production test on the Alaskan North Slope

As part of an extended-duration production test from a natural gas hydrate reservoir on the Alaska North Slope, a suite of optical-fiber sensors was encased in the completion cement to provide stable downhole monitoring around each of the four project wells. How the sensors respond to changes in the reservoir over time depends in part on properties of the LiteCRETE, ArcticCem, or Tuned Light cement in which each sensor is encased, and on how well the cement bonded to the well casing, sensors, and sediment formation. Here, we report on physical properties of the cements (compressive and tensile strength, stiffness, and Poisson’s ratio), on the downhole distribution of the cements used in each well, and on the cement bond quality. Physical property measurements are presented for cements sampled during the completion activities for the three wells completed in 2022–2023. Samples were cured while being submerged in water at 2–4 °C, then tested at intervals from ∼30 days to more than one year. After an initial period of rapid increase, cement strengths largely stabilized around 120 days in all cases, meaning that cements in all wells reached their nominal strength plateau four months or more before the production test began. Calculations based on recorded volumes of pumped cement show the subpermafrost, main hole portion of each well is encased only in the higher-density “tail” cement used in that well. Downhole cement evaluation logs from two wells demonstrate how the presence of sensors and other hardware outside the casing interferes with the cement evaluation assessment. Nonetheless, the cement evaluations indicate a generally good bond with the formation and sensors over the gas hydrate reservoir intervals.

Alaska↗

Oil in the Alaska North Slope gas hydrate reservoir: Micro-CT and flow simulation insights into permeability

Gas hydrate-bearing sands on the Alaska North Slope (ANS) host minor volumes of crude oil whose impact on formation permeability has never been quantified relative to a gas hydrate reservoir system. Here, we combine in situ pressure-core microcomputed-tomography (μ-CT), thermogravimetric analysis (TGA), gas-chromatography–mass-spectrometry (GC–MS), scanning-electron microscopy coupled with energy-dispersive spectroscopy (SEM-EDS), and Stokes-flow simulation to (i) quantify oil saturation, (ii) infer its source, and (iii) evaluate its influence on permeability after gas-hydrate dissociation. μ-CT and SEM-EDS imaging identify the host sediment as silty, with some grain-coating clay present. Eight representative 300 3 -voxel subvolumes extracted from a preserved pressure core (Core 15P-3c, from the B1 sand (unit B), HYDRATE 02 Geo Data Well (GDW), 886.96–887.29 m measured depth, MD) exhibit porosities of 0.34–0.37 and an average oil saturation of 0.09 ± 0.03, in comparison to an independent TGA-based estimate of 0.16. GC-MS fingerprints obtained from an adjacent depressurized core (Core 17P-1, 891.37–891.44 m MD), together with oil pore habit revealed by μ-CT, suggest that the oil is partly native but also includes contributions from mineral oil-based drilling fluid contamination. Further analysis of oil–porewater interactions and flushing tests confirms that native oil saturation in the analyzed samples ranges from 0.04 to 0.08 with an average of approximately 0.06, and the oil is highly immobile. Flow simulations demonstrate that the native oil saturation of ≈0.06 reduces permeability by approximately 50% due to both pore blockage and increased flow-path tortuosity. These findings reveal the potential presence of native oil within the ANS gas hydrate reservoir and suggest that future simulation models may need to account for its impact on permeability to improve long-term performance predictions of gas and water production.

Alaska↗

Depositional environment and diagenetic history of gas hydrate-bearing sediments of the Alaska North Slope (HYDRATE 02 Geo Data Well)

We characterized the lithological, solid-phase geochemical, and rock magnetic properties of sediment cores from subpermafrost strata on the Alaska North Slope collected as part of the U.S. Department of Energy (DOE), the Japan Organization for Metals and Energy Security (JOGMEC), and the U.S. Geological Survey (USGS) Collaborative Gas Hydrate Research and Development (R&D) Project in Alaska. Pressure cores were recovered from the HYDRATE 02 Geo Data Well (GDW) at the Kuparuk State 7-11-12 site through two hydrate-bearing sand reservoirs, the B1 and D1 sands, and their finer-grained bounding sediments. Both the B1 and D1 sands are quartz-rich, chert-bearing, very fine litharenite sands. These submature to immature sands are poorly to moderately sorted and angular with local fine-scale cross-stratification. The B1 sand has larger grains and a lower clay content as compared to the D1 sand. These sands are the upper portions of upward coarsening progradational sequences. The clay- and silt-rich bounding muds exhibit fine-scale wavy and lenticular laminations, suggesting episodic high energy deposition events. Overall, these sediments were deposited in a shoreface to nearshore marine environment during the Paleogene, modulated by changing depositional energy associated with sea level variation. Organic matter δ 13 C and C/N composition of these sediments indicate a source mixture of land plants and freshwater plankton, with possible minor presence of oil within the B1 sand. These sediments contain high and variable total sulfur (TS) content, suggesting porewater conditions influenced by variable salinity over time. Rock magnetic analyses indicate precipitation of greigite in the mud beneath the D1 sand, in the basal C shale overlying the B1 sand, and the mud beneath the B1 sand, likely due to intervals of sulfate limitation during periods of lower Arctic Ocean salinity. Based on pyrite abundance, TS, and δ 34 S-TS composition, the D1 sand and bounding sediments experienced more substantial sulfide precipitation. The unit E basal shale overlying the D1 sand contains a 0.25 m thick pyrite-dominant sand, indicating local bottom water anoxic conditions. X-ray fluorescence scanning and discrete measurements provide additional supporting interpretation of the depositional and diagenetic processes that have occurred at this site and track the relative amount of drilling fluid contamination with barium abundance in the core samples.

Alaska↗

Production of secondary microbial methane from a gas hydrate-bearing reservoir at the HYDRATE P1 Production Test Well (PTW-1) on the Alaskan North Slope

Gas hydrate in the Alaskan North Slope (ANS) is believed to contain as much methane as the known conventional gas accumulations in the Prudhoe Bay field. The JOGMEC-DOE-USGS Collaborative Gas Hydrate R&D Project conducted an extended-duration production test from the sub-permafrost, gas-hydrate saturated B1 sand reservoir (unit B) at the Kuparuk State 7-11-12 Site in the Prudhoe Bay Unit of the ANS. Using compositional and stable isotopic data measured on gas produced from well cuttings and pressure cores collected from the HYDRATE 02 Geo Data Well (GDW), we differentiate primary microbial, secondary microbial, and trace thermogenic gas sources. The upper part of the well contained predominantly primary microbial methane from near the surface to the SV6 stratigraphic horizon at 1133 ft (345.3 m) measured depth (MD). Below that, the gas composition transitioned to a mixture of mostly primary and secondary microbial methane to near the base of ice-bearing permafrost at 1968 ft (599.8 m) MD. With greater depth to 3558 ft (1084.5 m) MD, which includes the D1 sand (unit D), the B1 sand (unit B), and the base of gas hydrate stability at 3113 ft (948.8 m) MD, the gas composition was greater than 98% secondary microbial methane with the remainder being oil-associated thermogenic gas migrated from the deep Sadlerochit Formation. The unit B vertical gas profile derived from degassed pressure cores demonstrated that gas dissolved in the clay-rich sediment intervals bounding the B1 sand reservoir was distinct from dissolved and hydrate-caged gases in the sand-rich hydrate-bearing reservoir. The HYDRATE P1 Production Test Well (PTW-1) targeted and successfully extracted gas dissociated from hydrate gas in the B1 sand for 151 days when using an electrical submersible pump to depressurize the reservoir with subsequent depressurization achieved through the use of a jet pump. Gas produced from PTW-1 was mostly indistinguishable from the gas compositional profile measured through the B1 sand and generally distinct from dissolved gas in the bounding clay-rich sediments, confirming that the upper and lower bounding units limited infiltration into the reservoir during production. Isolation of the bounding units from the reservoir contributed to the unexpectedly high ratio of production gas to water observed during the extended-duration gas hydrate production test at PTW-1.

Alaska↗

Sulfur species in source rock bitumen before and after hydrous pyrolysis determined by X-ray absorption near-edge structure

The sulfur speciation of source rock bitumen (chloroform-extractable organic matter in sedimentary rocks) was examined using sulfur K-edge X-ray absorption near-edge structure (XANES) spectroscopy for a suite of 11 source rocks from around the world. Sulfur speciation was determined for both the native bitumen in thermally immature rocks and the bitumen produced by thermal maturation of kerogen via hydrous pyrolysis (360 &deg;C for 72 h) and retained within the rock matrix. In this study, the immature bitumens had higher sulfur concentrations than those extracted from samples after hydrous pyrolysis. In addition, dramatic and systematic evolution of the bitumen sulfur moiety distributions following artificial thermal maturation was observed consistently for all samples. Specifically, sulfoxide sulfur (sulfur double bonded to oxygen) is abundant in all immature bitumen samples but decreases substantially following hydrous pyrolysis. The loss in sulfoxide sulfur is associated with a relative increase in the fraction of thiophene sulfur (sulfur bonded to aromatic carbon) to the extent that thiophene is the dominant sulfur form in all post-pyrolysis bitumen samples. This suggests that sulfur moiety distributions might be used for estimating thermal maturity in source rocks based on the character of the extractable organic matter.

Energy & Fuels↗

The Iġnik Sikumi Field Experiment, Alaska North Slope: Design, operations, and implications for CO 2 −CH 4 exchange in gas hydrate reservoirs

The Iġnik Sikumi Gas Hydrate Exchange Field Experiment was conducted by ConocoPhillips in partnership with the U.S. Department of Energy, the Japan Oil, Gas and Metals National Corporation, and the U.S. Geological Survey within the Prudhoe Bay Unit on the Alaska North Slope during 2011 and 2012. The primary goals of the program were to (1) determine the feasibility of gas injection into hydrate-bearing sand reservoirs and (2) observe reservoir response upon subsequent flowback in order to assess the potential for CO 2 exchange for CH 4 in naturally occurring gas hydrate reservoirs. Initial modeling determined that no feasible means of injection of pure CO 2 was likely, given the presence of free water in the reservoir. Laboratory and numerical modeling studies indicated that the injection of a mixture of CO 2 and N 2 offered the best potential for gas injection and exchange. The test featured the following primary operational phases: (1) injection of a gaseous phase mixture of CO 2 , N 2 , and chemical tracers; (2) flowback conducted at downhole pressures above the stability threshold for native CH 4 hydrate; and (3) an extended (30-days) flowback at pressures near, and then below, the stability threshold of native CH 4 hydrate. The test findings indicate that the formation of a range of mixed-gas hydrates resulted in a net exchange of CO 2 for CH 4 in the reservoir, although the complexity of the subsurface environment renders the nature, extent, and efficiency of the exchange reaction uncertain. The next steps in the evaluation of exchange technology should feature multiple well applications; however, such field test programs will require extensive preparatory experimental and numerical modeling studies and will likely be a secondary priority to further field testing of production through depressurization. Additional insights gained from the field program include the following: (1) gas hydrate destabilization is self-limiting, dispelling any notion of the potential for uncontrolled destabilization; (2) gas hydrate test wells must be carefully designed to enable rapid remediation of wellbore blockages that will occur during any cessation in operations; (3) sand production during hydrate production likely can be managed through standard engineering controls; and (4) reservoir heat exchange during depressurization was more favorable than expected—mitigating concerns for near-wellbore freezing and enabling consideration of more aggressive pressure reduction.

Energy & Fuels↗

Extension of the analytical window for characterizing aromatic compounds in oils using a comprehensive suite of high-resolution mass spectrometry techniques and double bond equivalence versus carbon number plot

In this study, comprehensive two-dimensional (2D) gas chromatography–mass spectrometry (GC–MS), atmospheric pressure photoionization (APPI) quadrupole-Orbitrap mass spectrometry (MS), and Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS) were used to study the aromatic fractions of crude oil and oil shale pyrolysates (shale oils). The collected data were compared and combined in the double bond equivalence (DBE) versus carbon number plot to obtain a more complete understanding of the composition of the oil fractions. The numbers of peaks observed by each technique followed the order 2D GC–MS < Orbitrap MS < FT-ICR MS. The class distributions observed by Orbitrap MS and FT-ICR MS were similar to each other but different from that observed by 2D GC–MS. The DBE and carbon number distributions of the 2D GC–MS and Orbitrap MS data were similar for crude oil aromatics. The FT-ICR MS plots of DBE and carbon number showed an extended range of higher values relative to the other methods. For the aromatic fraction of an oil shale pyrolysate generated by the Fischer assay, only a few nitrogen-containing compounds were observed by 2D GC–MS but a large number of these compounds were detected by Orbitrap MS and FT-ICR MS. This comparison clearly shows that the data obtained from these three techniques can be combined to more completely characterize oil composition. The data obtained by Orbitrap MS and FT-ICR MS agreed well with one another, and the combined DBE versus carbon number plot provided more complete coverage of compounds present in the fractions. In addition, the chemical structure information provided by 2D GC–MS could be matched with the chemical formulas in the DBE versus carbon number plots, providing information not available in ultrahigh-resolution MS results. It was therefore concluded that the combination of 2D GC–MS, Orbitrap MS, and FT-ICR MS in the DBE versus carbon number space facilitates structural assignment of heavy oil components.

Energy & Fuels↗

Biogenic coal-to-methane conversion efficiency decreases after repeated organic amendment

Addition of organic amendments to coal-containing systems can increase the rate and extent of biogenic methane production for 60–80 days before production slows or stops. Understanding the effect of repeated amendment additions on the rate and extent of enhanced coal-dependent methane production is important if biological coal-to-methane conversion is to be enhanced on a commercial scale. Microalgal biomass was added at a concentration of 0.1 g/L to microcosms with and without coal on days 0, 76, and 117. Rates of methane production were enhanced after the initial amendment but coal-containing treatments produced successively decreasing amounts of methane with each amendment. During the first amendment period, 113% of carbon added as amendment was recovered as methane, whereas in the second and third amendment periods, 39% and 32% of carbon added as amendment was recovered as methane, respectively. Additionally, algae-amended coal treatments produced ∼38% more methane than unamended coal treatments and ∼180% more methane than amended coal-free treatments after one amendment. However, a second amendment addition resulted in only an ∼25% increase in methane production for coal versus noncoal treatments and a third amendment addition resulted in similar methane production in both coal and noncoal treatments. Successive amendment additions appeared to result in a shift from coal-to-methane conversion to amendment-to-methane conversion. The reported results indicate that a better understanding is needed of the potential impacts and efficiencies of repeated stimulation for enhanced coal-to-methane conversion.

Energy & Fuels↗

Investigation into the effect of heteroatom content on kerogen structure using advanced 13C solid-state nuclear magnetic resonance spectroscopy

To elucidate how different extreme heteroatom concentrations in oil shale kerogen may present and contribute to various structural features, three shale samples, containing kerogen with high oxygen content, low heteroatom content, and high sulfur content, were analyzed using advanced 13 C solid-state nuclear magnetic resonance (NMR) techniques, including multiple cross-polarization/magic angle spinning (multiCP/MAS), dipolar dephasing (multiCP/DD), and 2D 1 H– 13 C heteronuclear correlation (2D HETCOR). We found that oxygen in Estonian kukersite was present mostly in aromatic C–O structures and that nonprotonated aromatic carbons bonded to oxygen and alkyl chains led to more diverse aromatic signal distributions and structures in the kukersite organic matter than were observed in the other shales. The low-heteroatom kerogen present in Australian Glen Davis torbanite had the simplest structural pattern and the lowest aromaticity, despite having a lower atomic H/C ratio than the kerogens present in the other shales. The organic sulfur-rich Ghareb marinite from Jordan contained the highest aromaticity and most diverse alkyl structures among the three shales. 2D HETCOR with 1 H spin diffusion showed that the structural heterogeneity of the Glen Davis kerogen was <1 nm, indicating the preservation of structures present in precursor organic matter. Like previous NMR studies of shales and kerogens, this analysis of organic matter in whole shale samples with unusual heteroatom content demonstrates that structural characteristics in organic matter are not necessarily captured by kerogen typing based solely on elemental ratios (H/C, O/C) or programmed pyrolysis parameters and that NMR provides deeper insights into kerogen structure.

Energy & Fuels↗