ALBERT

Description: Electromagnetic (EM) methods were used to characterize (1) the general near-surface geology and stratigraphy and (2) the initial electrical conductivity distribution at a $${\mathrm{CO}}_{2}$$ enhanced oil recovery (EOR) site to assess and monitor possible near-surface environmental impacts of a carbon sequestration experiment. The field study was conducted at Cranfield Field, an EOR site where $${\mathrm{CO}}_{2}$$ is being injected into a depleted oil and gas reservoir in the Cretaceous lower Tuscaloosa Formation in western Mississippi. The study focused on Tertiary and younger strata between the ground surface and maximum depths of approximately 200 m (656 ft) that host groundwater more than 3000 m (9843 ft) above the oil and gas reservoir and injection zone. It included an airborne geophysical survey collecting frequency-domain EM data, time-domain surface EM measurements, borehole logging with EM induction, natural gamma spectra, and water-level measurements. Different approaches of temperature drift corrections for the borehole EM data were compared; good results of consistent and accurate conductivity values were produced by combining both directions of a two-way (uphole and downhole) measurement. The airborne EM provided data over a large area with sufficient detail to give an overview for the subsequent surface and borehole surveys, the surface time-domain data gave insight into greater depths, and the borehole induction data provided the necessary details. These three EM methods complement each other in areal coverage, lateral and vertical resolution, and exploration depth. Together, they can provide a comprehensive near-surface characterization of the study area that is necessary to establish initial-state conditions that support future monitoring of potential $${\mathrm{CO}}_{2}$$ migration to the near-surface environment.

Description: Numerical geochemical modeling was used to study the effects on pore-water composition and mineralogy from carbon dioxide (CO 2 ) injection into the Pennsylvanian Morrow B Sandstone in the Farnsworth Unit in northern Texas to evaluate its potential for long-term CO 2 sequestration. Speciation modeling showed the present Morrow B formation water to be supersaturated with respect to an assemblage of zeolite, clay, carbonate, mica, and aluminum hydroxide minerals and quartz. The principal accessory minerals in the Morrow B, feldspars and chlorite, were predicted to dissolve. A reaction-path model in which CO 2 was progressively added up to its solubility limit into the Morrow B formation water showed a decrease in pH from its initial value of 7 to approximately 4.1 to 4.2, accompanied by the precipitation of small amounts of quartz, diaspore, and witherite. As the resultant CO 2 -charged fluid reacted with more of the Morrow B mineral matrix, the model predicted a rise in pH, reaching a maximum of 5.1 to 5.2 at a water–rock ratio of 10:1. At a higher water–rock ratio of 100:1, the pH rose to only 4.6 to 4.7. Diaspore, quartz, and nontronite precipitated consistently regardless of the water–rock ratio, but the carbonate minerals siderite, witherite, dolomite, and calcite precipitated at higher pH values only. As a result, CO 2 sequestration by mineral trapping was predicted to be important only at low water–rock ratios, accounting for a maximum of 2% of the added CO 2 at the lowest water–rock ratio investigated of 10:1, which corresponds to a small porosity increase of approximately 0.14% to 0.15%.

Description: Substrate relief is a common characteristic of hard-bottom offshore banks and is associated with benthic biodiversity. Earlier studies revealed varying relief associated with offshore mesophotic communities. Correlations may exist between relief and benthic biodiversity, which in turn may be useful in determining drill sites. Such drill site determination requires obtaining an estimate of variability in relief on these banks and its associated geographic patterns. We performed fine-scale surveys of relief on 14 banks in the Gulf of Mexico to examine variation between them, geographic patterns, and possible processes influencing them: 28 Fathom, 29 Fathom, Alderdice, Bouma, Bright, Elvers, Geyer, Horseshoe, McGrail, Parker, Rankin, Rezak, Sidner, and Sonnier Banks. We used a multibeam sensor on a remotely operated vehicle, with resolution of approximately 0.5 m (2 ft). Average and standard deviation of relief were calculated at the transect, drop site, and bank levels of resolution. Sidner and McGrail Banks had the highest relief, and 29 Fathom and Sonnier had the lowest. Sidner Bank had relief averaging up to 11 m (36 ft) in height, whereas 29 Fathom Bank exhibited the lowest relief (range 1 to 2 m [3 to 7 ft]). Bright Bank and all others exhibited intermediate and variable relief at both the transect and drop site levels. Relief is not predictable on many banks because of high variability between drop sites. Some low-relief banks are predictable in their relief, lending themselves to predictions of benthic diversity and suitable drill sites. Relief decreased significantly as one moved northward in the study region. Relief exhibited a significant sinusoidal pattern from west to east. Banks with low relief occurred off Lake Calcasieu and Lafayette, Louisiana.

Description: CONFLICT OF INTEREST AND OTHER RELEVANT INFORMATION: Conflict of interest information is provided below for the authors of this paper. Chesapeake Energy Corporation (Chesapeake) funded the authors of this paper through their organizations of employment and, in the case of the senior author, privately, to do basic research to evaluate this very large data set and prepare the paper. Data were collected on behalf of Chesapeake by paid third-party consultants to comply with regulatory programs. The analyses and interpretations, and report writing, were done by the authors of the paper. The decision to submit the paper was that of the authors. The opinions and conclusions expressed in this paper are those of the authors and do not necessarily reflect those of Chesapeake. During the preparation of this paper, all authors worked for the organizations noted in authorship. Mark Hollingsworth is a current employee of Chesapeake, having worked there from February 2011 to the present. Prior to Mr. Hollingsworth’s employment by Chesapeake, he worked for TestAmerica Laboratories, Inc., which provided laboratory analytical consulting services to Chesapeake. Bert Smith is a former employee of Chesapeake, having worked there from May 2012 to September 2013, and has been employed by Enviro Clean Cardinal from November 2013 to the present. Enviro Clean Cardinal also does consulting work for Chesapeake. Prior to May 2013, Mr. Smith worked for Science Applications International Corporation, which did consulting work for Chesapeake. Elizabeth Perry works for AECOM, who provides energy consulting services to government and private industry, including Chesapeake. Rikka Bothun also worked for AECOM during most of the time this paper was under preparation but left AECOM in December 2014 and now works for a private consulting company that does not do consulting work for Chesapeake. None of the following authors (Don Siegel, Bert Smith, Elizabeth Perry, or Rikka Bothun) have competing corporate financial interests exceeding guidelines presented by AAPG Environmental Geosciences Journal. Mark Hollingsworth is a current employee of Chesapeake and owns stock in the company in an amount in excess of $5000. Donald Siegel is the lead author and contributor to the manuscript’s preparation, technical interpretations, and review of these data and the manuscript. Bert Smith contributed to the manuscript preparation, technical interpretations, and review of these data and the manuscript. Elizabeth Perry and Rikka Bothun contributed to the manuscript preparation, technical interpretations, and review. Mark Hollingsworth maintains the Chesapeake baseline data set and contributed to the manuscript preparation and review of these data and the manuscript. Due to confidentiality agreements with landowners whose wells were sampled, latitude and longitude cannot be shown on maps.

Description: CONFLICT OF INTEREST AND OTHER RELEVANT INFORMATION: Chesapeake Energy Corporation funded consultants and the authors of this paper through their organizations of employment and, in the case of Donald Siegel, privately to do basic research on this temporal data set and prepare the paper. The authors of this report did all analysis and writing. The opinions and conclusions expressed in this paper are those of the authors and do not necessarily reflect those of Chesapeake Energy Corporation. During the preparation of this paper, all authors worked for the organizations noted in authorship. Bert Smith is a former employee of Chesapeake Energy Corporation, having worked there from May 2012 to September 2013, and has been employed by Enviro Clean Cardinal since November 2013. While employed at Chesapeake Energy Corporation, he managed this temporal study, which was completed shortly after he left Chesapeake Energy Corporation. Enviro Clean Cardinal also does consulting work for Chesapeake Energy Corporation. Prior to May 2012, Bert Smith worked for Science Applications International Corporation, which consulted for Chesapeake Energy Corporation. Mark Becker has worked for Chesapeake Energy Corporation since March 2012; prior to that, he worked for the US Geological Survey for 24 yr. Donald Siegel works for Syracuse University, but he was funded privately for this work. Neither Bert Smith nor Donald Siegel have competing corporate financial interests exceeding guidelines presented by AAPG Environmental Geosciences . Mark Becker is a current employee of Chesapeake Energy Corporation and owns stock in the company in an amount in excess of $5000. Bert Smith is the lead author and contributed to the paper preparation, technical interpretations, and review of these data and paper. Mark Becker contributed to the paper preparation, technical interpretations, and review of these data and paper. Donald Siegel contributed to the paper preparation, technical interpretations, and review of these data and paper.

Description: 〈span〉〈div〉ABSTRACT〈/div〉The ability to accurately predict the probability of fluid migration from depth through existing wells based on known well properties, such as age and depth, would be enormously helpful in understanding how migration pathways develop and the identification of potential migration without extensive field tests. The presence of fluid pathways is an important environmental issue because such pathways allow gas, either naturally occurring methane or sequestered CO〈sub〉2〈/sub〉, to move into the atmosphere. In this paper, we explore the ability of various predictive models to forecast gas migration at existing wells in Alberta, Canada, based upon the characteristics of existing deep wells. Alberta was selected as a case study because of the availability of data in an area that has required wells to be tested for pathway development after rig release since 1995. Wells that do not demonstrate pathway development require no further testing until the well is abandoned. We show that accurately predicting fluid migration requires detailed information on well construction, production, and fluid properties, and even then, the models considered in this study misclassify a large number of wells. This suggests other factors may contribute to pathway formation. Of the models investigated, random forests provide the best results on this data set, correctly identifying 78% of the wells used.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉This study aims to decipher the groundwater status of the parts of Tigray area, Ethiopia using an integrated methodology of remote sensing and geographic information systems (GIS). Digitized vector maps of the study area, that is, geology, land use and/or cover, and drainage, were generated and converted to raster data. The theme weight and class weights were assigned to the raster maps of the respective parameters. Weight age to the layers was assigned using an analytical hierarchy process and further overlay analysis was carried out in the ArcGIS environment to decipher the groundwater resources of the study area.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The Fuling shale gas field is located in a mountainous area, with well-developed underground rivers and karst caves. It also has a highly concentrated population, so the shale gas development in this field is faced with environmental protection problems. Combined with the characteristics of surface natural environment in the Fuling shale gas field and the features of shale gas development engineering, the main environmental issues encountered in the development of the Fuling shale gas field were analyzed. Studies on intensive land use, water conservation and protection, harmless use and disposal of oil-based drill cuttings, recycling of wastewater from drilling and fracturing, and green environment management mode for shale gas development were conducted, and the green development technology system suitable for the Fuling shale gas field was established. Field applications showed that, after applying the green development technology, the land occupation was reduced by 62.l%, the recycling rate of drilling and fracturing wastewater was up to 100%, the oil content of treated oil-based drill cuttings was less than 0.3%, and carbon dioxide emission was reduced by 64.47 × 10〈sup〉4〈/sup〉 t (1.41 × 10〈sup〉9〈/sup〉 lb). Thus, the goal of zero contamination was realized during shale gas field development. Research showed that the green and environmental protection development technology for the Fuling shale gas field has served as a valuable demonstration in the environmental protection in large-scale development of shale gas fields in China.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Increased oil and gas production in many areas has led to concerns over the effects these activities may be having on nearby groundwater quality. In this study, we determine the lateral and vertical extent of groundwater with less than 10,000 mg/L total dissolved solids near the Lost Hills–Belridge oil fields in northwestern Kern County, California, and document evidence of impacts by produced water disposal within the Tulare aquifer and overlying alluvium, the primary protected aquifers in the area.The depth at which groundwater salinity surpasses 10,000 mg/L ranges from 150 m (500 ft) in the northwestern part of the study area to 490–550 m (1600–1800 ft) in the south and east, respectively, as determined by geophysical log analysis and lab analysis of produced water samples. Comparison of logs from replacement wells with logs from their older counterparts shows relatively higher-resistivity intervals representing the vadose zone or fresher groundwater being replaced by intervals with much lower resistivity because of infiltration of brines from surface disposal ponds and injection of brines into disposal wells. The effect of the surface ponds is confined to the alluvial aquifer—the underlying Tulare aquifer is largely protected by a regional clay layer at the base of the alluvium. Sand layers affected by injection of produced waters in nearby disposal wells commonly exhibit log resistivity profiles that change from high resistivity in their upper parts to low resistivity near the base because of stratification by gravity segregation of the denser brines within each affected sand. The effects of produced water injection are mainly evident within the Tulare Formation and can be noted as far as 550 m (1800 ft) from the main group of disposal wells located along the east flank of South Belridge.〈/span〉

Description: One of the challenges confronting carbon dioxide capture and sequestration (CCS) in geologic media over extended periods of time is determining the caprock sealing capacity. If the pressure of supercritical carbon dioxide $$({\mathrm{scCO}}_{2})$$ injected in the repository overcomes the caprock sealing capacity, leaking of $${\mathrm{scCO}}_{2}$$ may enter other porous formations, compromising the storage formation, or even may go back to the atmosphere, and thus the process of sequestration becomes futile. Carbon dioxide sealing capacity is controlled by two groups of parameters: (1)  texture (e.g., the pore-throat size, distribution, geometry, and sorting; median grain size, porosity, degree of bioturbation, specific surface area, preferred orientation of matrix clay minerals, orientation, and aspect of ratio of organic particles) and (2)  composition (mineralogical content, proportion of soft, deformable mineral grains to rigid grains, organic matter content, carbonate content, silt content, cementation, ductility, compaction, and ash content). The primary goal of this study was to investigate several parameters listed above and to estimate their respective contributions to sealing capacity to better understand its role in shale and carbonates. To assess the effect of textural and compositional properties on $${\mathrm{scCO}}_{2}$$ maximum retention column height, we collected 30 representative core samples from caprock formations in three counties (Cimarron, Texas, and Beaver) in the Oklahoma Panhandle. The study area was chosen because it hosts three depleted gas fields with a storage capacity of more than 35 million bbl and is situated at a crossroad leading to some significant $${\mathrm{CO}}_{2}$$ stationary sources from North Texas, South Kansas, and northern Oklahoma. We used mercury injection porosimetry, scanning electron microscopy (SEM), Sedigraph energy dispersive spectra (EDS), x-ray diffraction (XRD), Brunauer–Emmett–Teller-specific surface area, and total organic carbon (TOC) measurements to assess textural and compositional properties of collected samples. The range of $${\mathrm{scCO}}_{2}$$ column height for the samples used in this study is between 0.2 and 1358 m (0.66 and 4455 ft). The average $${\mathrm{scCO}}_{2}$$ column height is 351 m (1152 ft). The depth interval approximately 1400 m (4593 ft) could reach relatively high values of $${\mathrm{scCO}}_{2}$$ column height, up to 1200 m (3937 ft). The above-mentioned interval is composed of mainly Cherokee and Morrowan Formations (shale seals). Principal component analysis (PCA) was carried out to infer the possible relationships between textural and compositional parameters. Generally, composition of our samples (shales vs. carbonates and sandstones) indicates a relatively stronger control on caprock sealing capacity, although individual mineral makeup of shale samples seems not correlated with $${\mathrm{scCO}}_{2}$$ retention column heights. In the same time, many textural parameters play a significant role in determining the sealing capacity of carbonate caprocks.

Description: Net fluid production and pressure data were gathered to estimate the amount of $${\mathrm{CO}}_{2}$$ storage space available and the potential for additional oil recovery using $${\mathrm{CO}}_{2}$$ -enhanced oil recovery (EOR) in the Phacoides sandstone, McKittrick oilfield, San Joaquin Valley, California. The Phacoides reservoir has produced 61.5 million reservoir barrels of fluid, a volume equivalent to the subsurface capacity of 9.8 million metric tons of $${\mathrm{CO}}_{2}$$ . Reservoir pressure changes with fluid production suggest that injecting 1 million metric tons of $${\mathrm{CO}}_{2}$$ may raise reservoir pressures by 2 MPa (255 psi). We assume that the sealing capacity of the reservoir for $${\mathrm{CO}}_{2}$$ injection is equivalent to the conditions controlling the original hydrocarbon accumulation. If injection pressures exceed this limit, the $${\mathrm{CO}}_{2}$$ could leak through the caprock, from aging wellbores or along faults in the reservoir. Faulting has compartmentalized the reservoir into six major blocks with varying degrees of hydraulic communication. Injection wells will be required within each sealed fault block, resulting in additional costs for implementing a carbon capture and sequestration (CCS) project. Through $${\mathrm{CO}}_{2}$$ -EOR, an additional 17 million bbl of oil may be recoverable, thereby offsetting the cost of carbon storage. This is equivalent to 1.4 million metric tons of additional storage space. However, assuming that none of the carbon is captured, combustion of this additional oil will add approximately 7 million metric tons of $${\mathrm{CO}}_{2}$$ to the atmosphere, negating the available storage space in the reservoir and resulting in a net carbon gain to the atmosphere of 700,000 metric tons.

Description: It has been suggested by some that methane contamination of water wells is the main negative consequence of the development of natural gas resources. Concurrently, speculation in academic white papers and in the press that methane may be toxic has resulted in public concern. In northern Pennsylvania, methane being released from groundwater and entering homes (so-called stray gas) has become a focus of this concern. This phenomenon was widespread decades before shale gas development was initiated. This paper reviews the available literature on the safety and health hazards associated with natural gas. It concludes that the risks to homeowners are highest from flash fires occurring in methane oxygen gas clouds at relatively low methane concentrations collecting in poorly ventilated, confined areas of houses such as basements. Such risks can be mitigated effectively and in most cases at minimal cost. Methane can result in death from hypoxia (lack of oxygen) but only at methane levels in the air of more than 60%, which are unlikely to develop except under exceptional circumstances. There is no evidence that low to moderate levels of exposure to methane in air have any toxic effect on humans, and evidence for such effects at very high levels (already fatal because of hypoxia) is equivocal. It seems likely that methane at concentrations at least as high as 2.5% may well have positive health benefits for some diseases.

Description: Thousands of shale gas wells have been drilled and hydraulically fractured across the state of Pennsylvania over the past decade, and more wells are being drilled each year. The drilled lengths of these wells and the amount of water being used to hydraulically fracture (frac) them continue to increase. These increases have led to an increase in the volume of wastewater being produced each year. However, the ratio of energy produced per barrel of wastewater has increased significantly over the past six years. Recent data show the volume of wastewater produced in one year is approximately 20% of the volume of frac water used in that same year. With changes in state policies, drilling companies in Pennsylvania have been recycling most of their wastewaters over the past few years. The development of various treatment technologies and brine-resistant frac mixtures has allowed companies to recycle this wastewater for use in future frac jobs. Use of this recycled water does not appear to be having a significant effect on production of oil or gas from wells. Recycling wastewater can be very cost-competitive when compared to options such as disposal via waste-treatment plants or injection wells.

Description: Shale gas development in the United States has revolutionized energy production and supply, making the nation energy independent for the first time in decades. However, many people remain concerned that the large-scale hydraulic fracturing necessary to recover hydrocarbons from shale may degrade the environment, including groundwater. Improving the understanding of how groundwater may be impacted by shale gas development requires field monitoring at multiple sites on different shale plays under a variety of climates and hydrologic conditions. Such monitoring has been difficult to achieve because of a lack of access to commercial sites and an absence of funding to drill dedicated research wells.

Description: Many different rock intervals are used for brine disposal injection in the Appalachian Basin. The study area was defined as eastern Kentucky, Ohio, Pennsylvania, and West Virginia. Brine injection in the study area has increased from approximately 6–7 million barrels (bbl) per year in the early 2000s to 17.6 million bbl in 2012, mostly due to shale gas activity. A review of geologic properties and subsurface distribution of rock formations used for injection is useful to understand brine disposal operations in the region. Operational data on injection rates and pressures were compiled for 2008–2012 for more than 300 class II brine disposal wells. Several class II brine disposal wells were monitored with continuous wellhead pressure loggers to estimate reservoir properties and understand injection operations. Project results provide a catalog of injection rates for the various formations, which range from hundreds to more than 100,000 bbl per month per well. Hydrologic analysis of depleted hydrocarbon reservoirs and deep saline formations in the study area indicates that there is a large capacity for brine disposal, but the characteristics of the rock formations may limit injection rates. Based on hydrocarbon production and brine injection volumes from 2008 to 2012, approximately 9984 bbl of brine were routed to class II brine disposal wells per billion cubic feet gas production, which suggests ultimate demand of up to 706–2290 million bbl brine disposal related to unconventional Marcellus and Utica plays. Understanding the geology and operational history of the injection zones is critical to support safe, reliable, and environmentally responsible brine disposal in the region.

Description: Disposal of the liquid wastes generated during extraction of unconventional oil and gas resources in North America is increasingly becoming a constraint to development. Currently, the bulk of these wastes is disposed of by injection into deep bedrock formations. In certain development areas, the presence of suitable disposal formations is scarce, or disposal operations are difficult to site given area constraints. To address this challenge, a process of identifying high-value disposal targets (i.e., formations and locations) was developed using a combination of hydrogeological principles, multicriteria analysis, and geospatial mapping. This paper outlines the process developed to identify potential disposal targets to support oil sand development in Alberta and the results obtained.

Description: 〈span〉〈div〉ABSTRACT〈/div〉The middle Cambrian Maryville–Basal sands in the interval of 4600–4720 ft (1402.1–1438.7 m) in the Kentucky Geological Survey 1 Hanson Aggregates well (i.e., muddy sandstones separated by sandy mudstones) were evaluated to determine effective porosity (ϕ〈sub〉〈span〉e〈/span〉〈/sub〉), clay volume (〈span〉Vc〈/span〉), and supercritical CO〈sub〉2〈/sub〉 storage capacity. Average porosity and permeability measured in core plugs were 8.71% porosity and 2.17 md permeability in the Maryville sand and 10.61% porosity and 15.79 md permeability in the Basal sand. The ϕ〈sub〉〈span〉e〈/span〉〈/sub〉 and 〈span〉Vc〈/span〉 were calculated from the density log using a multiple-matrix shaly sand model to identify four formation lithologies: muddy sandstone, sandy mudstone, dolomitic mudstone, and dolomitic claystone. Average ϕ〈sub〉〈span〉e〈/span〉〈/sub〉 and 〈span〉Vc〈/span〉 calculated in the Maryville sand were 8.9% and 35.3%, respectively, and an average of 8.7% and 41.2% in the Basal sand, respectively. Calculated ϕ〈sub〉〈span〉e〈/span〉〈/sub〉 exhibits a good match with porosity measured in core plugs. Prior to step-rate testing, static reservoir pressure was 2020 psi (13.9 MPa), representing a 0.435 psi/ft (9.8 kPa/m) hydrostatic gradient, which is consistent with other underpressured reservoirs in Kentucky. The interval fractured at 2698 psi (18.0 MPa), yielding a fracture gradient of 0.581 psi/ft (12.7 kPa/m). Pressure falloff analysis suggests a dual-porosity/dual-permeability reservoir consistent with core data. Estimated 50th percentile supercritical CO〈sub〉2〈/sub〉 storage volume supercritical CO〈sub〉2〈/sub〉 storage volume, using 7% porosity cutoff for determining net reservoir volume, is 0.538 tons/ac (1.33 t/ha). Thin reservoir sands, low porosity and permeability, and low fracture gradient, however, preclude the Maryville–Basal sands as large-volume deep-saline CO〈sub〉2〈/sub〉 storage reservoirs in this area.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Porosity–permeability transforms were generated using an extensive data set covering two oil-bearing formations in Ohio: the Clinton Sandstone in eastern Ohio and the Copper Ridge Dolomite in central Ohio. The reservoirs were selected because of their historical importance as oil producers and their potential as targets for CO〈sub〉2〈/sub〉 use for enhanced oil recovery and associated geological storage. The porosity-permeability transforms generated in this study have coefficients of determination that are nearly double those in the published literature. Methods applying other information (e.g., lithofacies type and reservoir depth) to improve the transforms are also discussed. Ultimately, it was determined that although subdividing the Clinton Sandstone data by geologically similar areas constrained the porosity and permeability values, the data for most areas were too limited to yield robust correlations. Thus, the range of possible outcomes should be determined using the transform derived from all available data. The Copper Ridge values were largely not constrained when subdivided by depth.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The purpose of this study is to deconstruct the relationship between the Leaf River anticline and the preglacial bedrock paleotopography at the eastern terminus of the Plum River Fault Zone in Ogle County, Illinois, using a geostatistical approach. The contour maps derived from the elevation models provided detailed depictions of the ancient bedrock landscape and subsurface structure in the study area. The Leaf River anticline is interpreted to be a component of hanging-wall anticline at the terminus of the Plum River Fault Zone. The topographic high created by the anticline controlled local drainage and led to the development of the Leaf River paleovalley prior to the Pleistocene. The catastrophic failure of an ice damn during the Illinois glacial episode carved a glacial spillway into the north flank of the Leaf River anticline that interfaced with a tributary of the Leaf River paleovalley. This rerouted the preglacial drainage network and permanently diverted the ancient Rock River to its modern-day position. Ultimately, the subsurface geometry of the Leaf River anticline and its relationship to the local bedrock paleotopography were revealed by the elevation models. The position and development of the Leaf River paleovalley and glacial spillway interpreted in this study aligned with the regional interpretations for the evolution of the ancient bedrock landscape established in prior works. However, this study revealed that the Leaf River anticline and, by association, the terminus of the Plum River Fault Zone extend farther east into the region than indicated by prior works.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉In the last decade, production of shale gas has tremendously increased, and the need for local pre-exploitation baseline data on dissolved natural gas in aquifers has been stressed. This study investigated the origin of hydrocarbons naturally present in shallow aquifers of the Saint-Édouard area (Québec, eastern Canada), where the underlying Utica Shale is known to contain important gas resources that have not yet been exploited. Groundwater and shallow bedrock gas samples were collected and analyzed for isotopic composition of alkanes (δ〈sup〉13〈/sup〉C and δ〈sup〉2〈/sup〉H〈sub〉C1–C3〈/sub〉), dissolved inorganic carbon (δ〈sup〉13〈/sup〉C〈sub〉DIC〈/sub〉), and radiocarbon in methane and DIC (〈sup〉14〈/sup〉C〈sub〉DIC〈/sub〉, 〈sup〉14〈/sup〉C〈sub〉CH4〈/sub〉). This multi-isotope approach proved enlightening, and results revealed that (1) most of the methane in the region is of microbial origin; (2) partial contribution of thermogenic gas occurs in 15% of the wells; (3) processes such as late-stage methanogenesis and methane oxidation are responsible for ambiguous methane isotopic compositions; and (4) both microbial and thermogenic gas originate from the shallow bedrock aquifer, with the exception of one sample likely coming from deeper units. The thick succession of shales overlying the Utica Shale thus appears to act as an effective migration barrier for the shallow aquifers. However, evidence of upward migration of old brines near major fault zones indicates that these may serve as a preferential migration pathway over a certain depth but most likely no more than approximately 200–500 m (∼650–1640 ft). The geochemical framework presented here will hopefully be useful in other research projects, especially when conventional indicators of natural gas origin provide ambiguous results.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Urbanization modifies the natural water cycle. In this study, a weighted-rating multicriteria analysis was adopted to quantify the runoff index and to assess the impact of urbanization on the water cycle. The considered parameters are (1) slope, (2) permeability of soil, and (3) rainfall. Using the land use map, a runoff risk map was established. The approach was applied to Manouba catchment. The main results revealed that between 2004 and 2014, the area with a high runoff index increased from 32% to 39%. The runoff risk increased; in 2004, the high class covered 18% of the watershed area. This value became 30% in 2014. Results demonstrate that urbanization affects hydrological processes. This method is appropriate in other similar watersheds to estimate the runoff index.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉To better understand controls on the origin and evolution of brackish groundwater, the hydrogeochemistry of brackish groundwaters was studied within the Triassic Dockum Group across the Midland Basin in Texas. The suitability of Dockum Aquifer water for use in hydraulic fracturing fluid was examined because the area overlies the largest and most productive tight oil province in the United States. Groundwater generally flows southward and eastward across the basin. Transmissivities indicate that water yield from the Dockum Aquifer is mixed. Higher salinity (up to ∼100 g/L), group I water is found mainly in the center and western parts of the basin; chemistry of these meteoric waters is controlled by water–rock interaction with salinity increasing along its flow path via dissolution of halite and anhydrite, followed by salinity-enhanced carbonate dissolution and/or cation release from clays. Along the down-gradient basin margins, lower salinity (〈7.5 g/L), group II waters of various ion compositions are more commonly found. Group II waters are also meteoric but from local recharge including downward flow from the Edwards–Trinity or other aquifers. Despite having lower salinity, the water in the down-gradient southern and eastern margins of the basin can exceed acceptable SO〈sub〉4〈/sub〉 limits for cross-linked gel fluids. Generally, the majority of the water in the basin is suitable for use with slick-water hydraulic fracturing. Findings from this research provide important information on the complex controls on the chemistry of brackish groundwater and their potential beneficial uses in the oil and gas industry.〈/span〉

Description: Two-dimensional seismic refraction tomography was used to map the bedrock topography beneath Hallsands beach in southwest Devon, United Kingdom. Seismic refraction data were acquired from 11 spreads, 4 parallel to the beach and 7 normal to the beach, with either 12 or 24 geophones at 5-m (16-ft) spacing. Eight sediment cores were used to calibrate the velocity model. The bedrock consists of metasedimentary rocks that have a seismic velocity of 2100–2500 m/s (6900–8200 ft/s) and is overlain by variable amounts of gravel, peat, and muddy peat. Wood peat and peaty mud are differentiated within the peat as 700-m/s (2300-ft/s) velocity for wood peat and 1200-m/s (4000-ft/s) velocity for peaty mud. These refraction data were collected and processed in two dimensions, then imported into Petrel, a three-dimensional (3-D) geological modeling software package. The 3-D geologic model was built using the velocity attribute of the seismic refraction data. These selected data points were used to create 3-D horizons, surfaces, and contacts constraining the target bedrock surface from the overlying unconsolidated deposits. The bedrock surface beneath Hallsands beach is marked by two paleochannels. One paleochannel occurs in the north end of the beach beneath the axis of the modern valley. A second paleochannel occurs in the southern section of Hallsands beach centered along the axis of a tributary valley. Bedrock occurs at a depth of approximately –10 m (–33 ft) in the southern and northern sections of the main valley. Bedrock occurs at a depth of approximately –2 m (–6 ft) along the valley wall at the southern end of the beach east of the parking lot. Shore-perpendicular refraction lines differentiate layers within the peat, whereas shore-parallel lines delineate wood-peat, peaty-mud, and bedrock topography.

Description: Drilling for oil/gas and trawling on a continental shelf can cause damage to hard-bottom communities. Moving these activities offshore poses a threat to offshore communities. Habitat complexity is correlated with species diversity. The relationship of bottom relief to benthic species richness is not well understood in deeper communities. Relief may act as a proxy for species richness and disturbance risk. Geographic patterns in relief and richness are also not well understood. We gathered information on bottom relief and species richness of the sessile epibenthic community using a remotely operated vehicle. We surveyed hard bottom on the flanks of 13 banks in the north–central Gulf of Mexico, greater than 27-m (89-ft) depth, on the shelf and at the shelf edge. We found a positive asymptotic relationship between mean relief and species richness at the transect level. Secondary analyses at the drop site level revealed a similar relationship; variance was higher. The relationship was positively linear at the bank level. Analyses using standard deviation of relief yielded even stronger positive results. There was no significant relationship between species richness and latitude or longitude over the study area (215 km [133 mi]). When species richness was plotted in three dimensions, however, peaks in richness emerged in the southeastern study area and the western region, with a trough between them, coinciding with bottom relief. Species richness is positively correlated with bottom relief on banks in the northern Gulf of Mexico. Relief and species richness may be predicted at many spatial scales, up to hundreds of kilometers.

Description: The reservoir sedimentology and depositional environment of the Lower Cretaceous Alam El Bueib Formation in the Betty-1 well, Shoushan Basin, were investigated by studying lithofacies, petrography, and calcareous nannofossils. The sedimentary lithofacies indicate a fluvial to shallow-marine depositional environment. We have lithologically identified and described five lithofacies assemblages (massive-sandstone facies; cherty massive-sandstone facies; argillaceous-sandstone facies; heterolithic, laminated sandstone/shale facies; and sandy/silty–shale facies); we have petrographically identified and described seven microfacies (laminated claystone and siltstone; ferruginous quartz–arenite; feldspathic ferruginous quartz–wacke; quartz–arenite; anhydritic quartz–arenite; biomicrite; and sandy-limestone microfacies). Calcareous nannofossils were used to determine the age of the investigated deposits. The calcareous-nannofossil species led to the recognition of two nannofossil zones of the Early Cretaceous ( Nannoconus bermudezi zone of the Hauterivian and Nannoconus colomi zone of the Barremian). The studied sandstone reservoirs can be classified as compositionally immature feldspathic arenite and wacke. The main diagenetic minerals of the sandstones include authigenetic clay minerals, calcite cement, quartz overgrowth, and later ferroan carbonate. Wide porosity variations in sandstones correlate with an abundance of grain-coating clays and consequent inhibition of quartz cementation. Secondary porosity has been created mainly by feldspar, rock-fragment dissolution, and clay-matrix dissolution.

Description: Upward migration of brine because of pressurization resulting from injection is a risk of disposal of water produced with oil and geologic carbon storage. Analysis of the net production in each zone associated with oil production activities in the southern San Joaquin Valley, California, determined that net injection caused by disposal of water produced with oil occurred in zones above the shallowest zone with net production in several oil fields. The zones with net injection are also variously at depths just greater than the shallowest depths for geologic carbon storage or at depths intermediate between more typical geologic carbon storage depths and overlying groundwater with a total dissolved solids concentration appropriate for domestic use. As such, these net injections provide analogs for brine pressurization caused by geologic carbon storage, either in the injection zone around the CO 2 plume or in overlying zones caused by vertical leakage of brine or CO 2 . Hundreds of newspaper articles regarding groundwater contamination in the main newspaper in the southern San Joaquin area collectively reported on effects on groundwater from tens of sources at tens of locations. These effects resulted in the closure of about 100 water supply wells. However, no effects caused by upward migration of brine were reported. Of the shallowest zones with oil production–related activity in each field, the Fruitvale field, Main area, Etchegoin pool had the largest cumulative net injection volume. This pool is also intersected by numerous faults and approximately 900 wells related to oil production, each providing a potential pathway for upward fluid migration. Total dissolved solids and nitrate concentration data are available from greater than 100 water supply wells overlying this pool. Analysis of these data determined there was no significant groundwater quality change likely attributable to upward migration of brine ( p 〈 0.05). It is not known if this is because the application of current underground injection control regulations is effective or because upward migration of brine, which is a dense phase, to groundwater is unlikely. The different engineering and economic implications of these two hypotheses suggest the need for future work to ascertain which is correct under different conditions.

Description: The successful implementation of geologic carbon sequestration depends on the careful evaluation of the petrophysical characteristics of the storage reservoir. Two petrophysical properties, porosity and permeability, constrain the reservoir in terms of its storage potential and injectivity. These two key parameters may vary significantly in scale within a reservoir. Likewise, the analytical tools that are useful for measuring these properties also vary and only assess pores of a given scale. In this investigation, 52 rock samples that consist of carbonates having a high degree of dolomitization were obtained from the Cambrian–Ordovician Knox Supergroup from different depth intervals; these samples span a significant area of the Midwestern United States. The samples were analyzed for total porosity and pore-size distribution using a variety of techniques, including petrographic image analysis, helium porosimetry, gas adsorption, mercury porosimetry, and ultrasmall-angle/small-angle neutron scattering. Capillary entrapment, or "residual saturation," is that part of the injected CO 2 that remains trapped in micropores after the pressure elevated by the injection process returns to ambient reservoir pressure. Results from low-pressure nitrogen and carbon dioxide adsorption and from mercury injection capillary pressure are important in that they provide insights about small pore size that otherwise cannot be resolved by standard helium porosimetry or by image analysis software. Results from these analyses suggest that micro- and mesoporosity control capillary entrapment, whereas macroporosity controls permeability.

Description: 〈span〉〈div〉ABSTRACT〈/div〉Groundwater is the major source of drinking water in both urban and rural India. Estimation of natural groundwater recharge is essential for the sustainable development of groundwater. Natural recharge was estimated by various methods, such as the water level fluctuation method, water balance method, linear regression model, and nonlinear regression model. The recharge estimates by the water balance method was compared with the recharge obtained from the water level fluctuation method for the study area and found to be in good agreement.Estimation of recharge by the water level fluctuation method is laborious, and envisaging the difficulties in the availability and reliability of data, the water balance method is taken as the standard for developing regression equations in the present study. Simpler linear and nonlinear regression models were developed for the study area to estimate natural recharge by correlating with the water balance model. The models were calibrated with 10-yr data and validated with 5-yr data. The statistical analysis showed that no significant difference exists between the recharge estimate by the water balance method and the two estimates of natural recharges, such as linear regression and nonlinear regression models. The average recharge percentages from the water level fluctuation method, water balance method, linear regression model, and nonlinear regression model are 15.09%, 14.92%, 14.62%, and 14.57%, respectively, for the watershed during the study period. The study proves that regression equations can be efficiently used in recharge computation with proper calibration for ungauged basins, and laborious data-intensive computation methods can be eliminated.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The White River watershed encompasses four major tributaries within a basin area of 130 km〈sup〉2〈/sup〉 (1595 mi〈sup〉2〈/sup〉) in extreme northwestern Nebraska. An examination of the historical (1968–1975) aqueous geochemistry data (major cations and anions and total dissolved solids [TDS]) supplied by the Nebraska Department of Environmental Quality revealed that the TDS is relatively low (130–1200 mg/L), excluding Big Cottonwood Creek (BCC), with a basin-wide median of 340 mg/L. The median TDS for the BCC is 1880 mg/L (brackish); the median values for Na and SO〈sub〉4〈/sub〉 are 385 and 897 mg/L, respectively. Mineralization in the river increases steadily downstream. The scatter plots of meq/L concentrations for selected anions and cations reveal the impact of silicate mineral (e.g., feldspar) weathering on the aqueous geochemistry throughout the watershed. These ubiquitous feldspar minerals most likely originated along the eastern slope of the Front Range during the Late Cretaceous and Tertiary (Laramide orogeny). Twenty-nine samples for three White River stations and the BCC exceed the US Environmental Protection Agency secondary maximum contaminant levels for TDS and/or SO〈sub〉4〈/sub〉 in drinking water supplies at 500 and 250 mg/L, respectively. Uncontaminated streams that drain marine shales (typically containing S-bearing minerals) nationwide typically show an excess of Na and a deficiency of Ca and Mg. This is due in part to cation exchange of Ca in solution for Na on clay minerals. Consequently, the weathering of shale terrains commonly produces an Na-SO〈sub〉4〈/sub〉 brackish surface-water runoff as is the case with BCC, which drains the Pierre Shale hills.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Landslides are geologic events that cost Pennsylvania $127 million in 2018. Landslide susceptibility models, or maps that depict where landslides are likely to occur, are helpful tools for the public and private sectors to use to mitigate the cost and damage caused by mass movements. However, Pennsylvania’s most current statewide susceptibility map for landslides is broad and only suitable for analysis at the state level. The majority of northeastern Pennsylvania (NEPA) falls within a low susceptibility zone, but within this zone are undefined areas of moderate to high susceptibility. This broad range of susceptibility provides no slope-specific description of the moderate to high classifications. Pennsylvania’s coarse resolution susceptibility model is likely caused by the lack of a comprehensive landslide inventory for the entire state that might be used in data-driven methods of susceptibility modeling. To create a high-resolution susceptibility map for NEPA, a landslide inventory for NEPA was constructed based on enhanced imagery and analysis of light detection and ranging–derived digital terrain models. A data-driven bivariate frequency ratio method was used for the creation of a 30-m pixel-resolution susceptibility map that is both qualitatively and quantitatively more robust than the most current model within the region. Our results indicate that within NEPA, slope failures are most influenced by the slope derivative of elevation. Slopes are most susceptible to failure along steep valleys created by rivers and streams within the Appalachian Plateau, as well as areas with steep slope within the Ridge and Valley areas of the study region.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Subsurface disposal of salt water coproduced with oil and gas has become a critical issue in the United States because of linkages with induced seismicity, as seen in Oklahoma and northcentral Texas. Here, we assess the spatiotemporal and stratigraphic variations of salt-water disposal (SWD) volumes in the Permian Basin. The results of this analysis provide critical input into integrated assessments needed for handling of produced water and for emerging concerns, such as induced seismicity.Wellbore architecture, permits, and disposal volumes were compiled, interpreted for disposal intervals and geologic targets, and summarized at formation, subregion, a 100-mi〈sup〉2〈/sup〉 (260-km〈sup〉2〈/sup〉) area, and monthly volumes for the years 1978–2016. Geologic targets were interpreted by intersecting the disposal intervals with gridded stratigraphic horizons and by reviewing well logs where available.A total of 30 billion bbl (∼5 trillion L) were disposed into 73 geologic units within 6 subregions via 8201 active SWD wells for 39 yr. Most disposal occurred in the Midland Basin and Central Basin Platform (CBP) over the first 34 yr but shifted from the CBP to the Delaware Basin over the last 5 yr (2011–2016) with the expansion of unconventional oil and gas production. Approximately half of the salt water is disposed above the major unconventional reservoirs into Guadalupian-aged formations, raising concerns of overpressuring and interference with production. Operators are exploring deeper SWD targets; however, proximity to crystalline basement poses concerns for high drilling costs and the potential for induced seismicity by reactivation of deep-seated faults.〈/span〉

Description: Cambrian–Ordovician strata of the midwestern United States are considered a promising reservoir for geologic storage of carbon dioxide. To assess the potential of the Ordovician St. Peter Sandstone, storage-resource estimates were generated using a hierarchical approach to estimating prospective storage resources. The method employs a series of increasingly sophisticated analyses to better facilitate an understanding of the uncertainty in the estimates. Results demonstrate how uncertainty of storage-resource estimates varies as a function of data availability and quality as well as the underlying assumptions used in the application of specific storage efficiency factors. In the simplest analysis, storage-resource estimates were calculated from updated regional-scale mapping of the gross thickness of the formation and by applying a single best estimate of the mean porosity for the entire formation. This analysis follows the technique prescribed by the US Department of Energy and yields storage-resource estimates ranging from 3.3 to 35.1 billion t CO 2 in the Michigan Basin and 1.0 to 11.0 billion t CO 2 in the Illinois Basin at the 10% and 90% probability levels. The second analysis incorporated generalized models of the diagenetic history of the formation throughout the two basins by implementing depth-dependent functions of porosity that lead to more realistic portrayals of spatially variable results. Similar resource estimates were calculated for the Michigan Basin, but reduced estimates (43%) were found for the Illinois Basin. The third analysis explicitly accounted for the local-scale spatial variability in reservoir quality using net-porosity calculations, resulting in a significant increase in the low-range resource estimate for the Michigan Basin and dramatic increases for Illinois Basin resource estimates (factor of 3 to 11 increases). A fourth analysis was conducted for the Michigan Basin that used advanced reservoir characterization to define reservoir properties for multiple reservoir facies and yielded resource estimates significantly larger than the third analysis and a larger range of uncertainty. This study highlights how different factors impact the expected uncertainty in storage-resource estimates, and analysis suggests that estimates from the first two approaches provide excessively conservative results, whereas the second two approaches tend to overestimate the resource.

Description: Two different approaches have been used to evaluate the potential for CO 2 geologic sequestration and CO 2 -assisted enhanced oil recovery in the major oil fields in Ohio: a volumetrics-based method, which uses field volumetric data to calculate CO 2 storage capacity, and a production-based method, which uses historical oil and gas production data to calculate CO 2 storage capacity. The fields were selected based on their historical importance as oil and gas producers as well as the availability of data in published sources. The storage capacity found using the production data–based methodology—878 million t—is believed to be more representative than that found using the volumetrics-based method because it uses actual production data to calculate void space for CO 2 storage rather than estimated efficiency factors. This estimated capacity is higher than previously reported values based on efficiency factors and is enough to support the storage of 25% of annual emissions from 45 of Ohio’s largest power plants for a period of 36 yr.

Description: This study demonstrates the application of aeromagnetic surveys for locating late 1800s-era oil and gas wells in Hillman State Park. The study area in southwestern Pennsylvania offered several unique challenges to locating legacy wells. Location records for many of Pennsylvania’s legacy wells do not exist. Those that do exist are often incomplete and inaccurate, and old wells were commonly abandoned without effective plugging. Now, unplugged legacy wells may serve as vertical migration pathways for fluids and gas associated with modern oil and gas operations. Wells in Hillman State Park were abandoned in the early 1900s, leaving little evidence of a well site. However, the steel well casing commonly remained at the site. Between 1940 and 1960, 50% of the land area at Hillman State Park was surface mined for coal. The removal of coal overburden also removed the upper well casings in surface-mined areas to the depth of the coal. The wells were then buried under mine spoil during regrading operations. Today, much of Hillman State Park is covered in trees and dense vegetation, and locating wells with ground-level searches is difficult, time consuming, and often futile. The airborne magnetic survey used in this study identified well locations, including buried wells in mined areas, based on the unique magnetic signature of vertical, steel well casing. The results of the aeromagnetic survey were combined with aerial photography, historic maps, and high-resolution topographic data in a geographic information system to refine well locations prior to verification with a ground search.

Description: Surface and airborne gas monitoring programs are becoming an important part of environmental protection in areas favorable for subsurface storage of carbon dioxide. Understanding structural architecture and its effects on the flux of fluids, specifically CO 2 and CH 4 , in the shallow subsurface and atmosphere is helping with designing and implementing next-generation monitoring technologies, including unmanned aerial vehicles (UAVs). An important aspect of this research is using subsurface fracture data to inform the design of flight pathways for UAVs in the Farnsworth oil unit of the Anadarko Basin. The target zone for CO 2 storage and enhanced oil recovery in the Farnsworth oil unit is in the upper Morrow sandstone at subsurface depths greater than 2000 m (6562 ft). Field study reveals that sandstone and chert in the High Plains Aquifer contain numerous joints that provide crucial insight into aquifer architecture and subsurface flow pathways. Properties of more than 1700 joints were measured in the field and in high-resolution satellite images. Two distinctive joint systems interpreted as a conjugate pair were identified in the study area. Joint spacing follows a lognormal statistical scaling rule. These fractures appear to be the product of an east–northeast regional compressive stress and may have a significant effect on flow in the High Plains Aquifer system. Based on the results of this research, design of UAV flight paths should be oblique to fractures in a way that maximizes the likelihood of CO 2 and CH 4 flux of systematic joints and cross joints.

Description: Development of geothermal energy in sedimentary basins is an attractive option given the availability of data from the oil and gas industry. Previous geothermal studies in sedimentary basins have focused on temperatures and petrophysical properties. In this study, the focus is placed on historical reservoir performance. In the Western Canada Sedimentary Basin, estimated temperatures and measured fluid production and injection rates at existing wells are combined to provide a per-well estimate of thermal power production. Nearly 700 of these hypothetical geothermal wells would produce 1 MW of power, and a total of 6 GW could be produced if all wells were converted to geothermal wells. Many of these wells may not be suitable for immediate use because of temperature anomalies resulting from injection of cooler water into target strata. Further research is needed to characterize the magnitude and extent of these anomalies. Geothermal potential should also be considered in the development of oil and gas resources in sedimentary basins.

Description: The stress regime in the Illinois Basin was investigated to assess how the rock column might respond to the injection of fluids, including coproduced formation brines and supercritical CO 2 .This response is a concern because injection practices could increase pore fluid pressure and potentially induce seismicity. Data were collected to determine the magnitude and orientation of a three-component stress field: vertical stress ( S v ) and minimum ( S h ) and maximum ( S H ) horizontal stresses. The S v was evaluated with a six-layer lithostratigraphic column. A two-layer pressure–depth S v model was generated for the central part of the basin, and a single pressure gradient model was constructed for the surrounding region. In the central part of the basin, the S v gradient is 24.9 MPa/km (1.11 psi/ft) to a depth of 2134 m (7000 ft), followed by a gradient of 27.1 MPa/km (1.20 psi/ft) below 2134 m (7000 ft). For the area surrounding the deep basin, the S v gradient was 25.5 MPa/km (1.13 psi/ft). The S h was evaluated from multiple data sources, primarily hydraulic fracture records or extended leak-off tests. The S h gradient calculations ranged from 24.1 to 27.3 MPa/km (1.07 to 1.21 psi/ft). The S h values for the basal Paleozoic clastic units are lower than those for units in the overlying horizons. The S H was based on a critically stressed model yielding values between 40.0 and 82.6 MPa/km (1.77 to 3.65 psi/ft). Stress orientation data for the Illinois Basin were collected from multiple sources. The orientation of S H across the study area is relatively uniform in strike at approximately N60°E. Marked deviations in S H result from localized structural discontinuities.

Description: This study simulated the injection of supercritical phase $${\mathrm{CO}}_{2}$$ into the South Georgia Rift (SGR) basin to evaluate the feasibility of long-term storage. Because of the lack of basin data, an equilibrium model was used to estimate the initial hydrostatic pressure, temperature, and salinity gradients that represent our study area. For the equilibrium model, the USGS SEAWAT program was used and for the $${\mathrm{CO}}_{2}$$ injection simulation, TOUGH2-ECO2N was used. A stochastic approach was used to populate the permeability in the injection layer within the model domain. The statistical method to address permeability uncertainty and heterogeneity was sequential Gaussian simulation. The target injection depths are well below the 1 km (~0.62 mi) depth required to maintain $${\mathrm{CO}}_{2}$$ as a supercritical fluid. There were very little data pertaining to the properties in the deep Jurassic/Triassic $$(\mathrm{J}/{\mathrm{T}}_{\mathrm{r}})$$ SGR basin formations. So, conservative porosity and permeability starting points were postulated using data from analogous basins. This study simulated 30 million tons of $${\mathrm{CO}}_{2}$$ injected at a rate of 1 million tons per year for 30 yr, which is the minimum capacity requirement by the U.S. Department of Energy (DOE) for a viable $${\mathrm{CO}}_{2}$$ storage reservoir. In addition to this requirement, a 970-yr shut-in time (no injection) was also simulated to better determine the long-term fate and migration of the injected $${\mathrm{CO}}_{2}$$ and to ensure that the SGR basin could effectively contain 30 million tons of $${\mathrm{CO}}_{2}$$ . The preliminary modeling of $${\mathrm{CO}}_{2}$$ injection indicated that the SGR basin is suitable for geologic storage of this U.S. DOE stated minimum capacity.

Description: Examination of historical water-quality data (major cations and anions and total dissolved solids [TDS]) for Rock Creek, located in eastern Nebraska’s saline wetlands north of the Platte River, revealed that concentrations of sodium (Na), chloride (Cl), and TDS increased significantly in the downstream reach below the town of Ceresco, exceeding the U.S. Environmental Protection Agency (USEPA) secondary drinking water standards of 250 mg/L for Cl and 500 mg/L for TDS. Research into the probable source(s) of these inorganic constituents revealed that the Dakota Formation of Late Cretaceous age subcrops in the study area and typically yields water with elevated concentrations of Na, Cl, and TDS in southeastern Nebraska. This brackish to saline water upwells to the surficial aquifer and Rock Creek streambed. Additionally, the significant levels of Na and Cl correlate well with the occurrence of unique saline wetlands along Rock Creek downstream from Ceresco. Public-domain geochemical speciation software codes (Visual MINTEQ and NETPATH) were used to characterize and investigate aqueous geochemistry of Rock Creek discharge and to calculate mixing proportions of Dakota Formation water and stream discharge. The NETPATH output suggests that 3.3%–18% of discharge in Rock Creek approximately 10 km (6.2 mi) southeast of Ceresco, Nebraska, originates from the Dakota Formation and probably the underlying Pennsylvanian bedrock. Hopefully, this paper will be the impetus for an up-to-date, comprehensive, and geochemical-rich data investigation of the Dakota Aquifer’s impact on the inorganic water quality of Rock Creek.