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: The Cretaceous rocks of Florida have been recognized as potentially suitable reservoirs for geologic carbon dioxide (CO 2 ) sequestration. Specifically, the upper member of the Upper Cretaceous Lawson Formation, together with the lower part of the Paleocene Cedar Keys Formation, is presented here as a potential composite CO 2 storage reservoir that is mainly composed of porous dolostone sealed by thick anhydrites of the overlying middle Cedar Keys Formation. Many of the porous intervals within the Cedar Keys-Lawson storage reservoir display lateral continuity and have an average porosity range of 20%–30%. The estimated CO 2 storage capacity for the reservoir is approximately 97 billion t of CO 2 , which means the Lawson and Cedar Keys Formations composite reservoir could potentially support CO 2 sequestration for hundreds of large-scale power plants in the southeastern United States for their entire 40-yr lifespan. Because most of the previous research on the Lawson Formation is concentrated in north-central and northeastern Florida and southern Georgia, this study further characterizes the formation and its CO 2 sequestration potential in south-central and southern Florida.

Description: Geochemical reactions that may occur on CO 2 injection into a sandstone formation in Missouri (MO) were investigated by means of geochemical modeling. Five possible injection sites were considered: two in the northwestern part of the state, two in the northeastearn part, and one in the southwestern part. The Geochemist Workbench software was used to investigate solubility trapping and mineral precipitation. Modeling was performed for two periods: an injection period of 10 yr and a postinjection period where the reactions proceeded to equilibrium. The work presented substantial challenges. Among them are uncertainty in kinetic constants for the dissolution and precipitation of minerals on CO 2 injection. Model results include equilibrium values for CO 2 stored via solubility trapping ranging from 49-g CO 2 /kg free formation water in Northeast MO to 78-g CO 2 /kg free formation water for Southwest MO. Mineral trapping is significantly lower, between 2.6- and 18.4-g CO 2 /kg free formation water. The model shows siderite and dawsonite as the major carbonate minerals formed, in this order. On a volumetric basis, northwest MO sequestration values were slightly greater than those obtained for northeast MO because of the somewhat greater depth and higher injection pressure at the injection target (Lamotte Sandstone) at the northwestern sites. However, the greater thickness of the aquifer for the northeastern sites provided overall greater sequestration capacity. Greene County was altogether unfit for sequestration because of the low total dissolved solids value of the formation water.

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: We evaluated the geochemical transformations that would likely occur after injecting CO2 into a sandstone formation using The Geochemist's Workbench(R), with the intent of simulating CO2 solution and mineral storage mechanisms. We used a hypothetical reservoir intended to closely resemble the Lamotte Sandstone in southwest Missouri, a reservoir rock found at about 600-m (1970-ft) depth, well above the recommended depth for CO2 sequestration of 800 m (2625 ft). In the absence of specific water chemistry and lithology data for this formation at the proposed injection site, the model considered two best estimates of each input parameter. Carbon dioxide (CO2) sequestered in the dissolved phase was found to range between 76.74 and 76.80 g/kg free water, and the pH dropped from 7.7 to 4.8 after a 10-yr injection period. During a 50-yr postinjection interval with no additional CO2(g) added, the model predicted the pH to rise from 4.8 to 5.3 and various minerals to precipitate, among them magnesite, nontronite-Mg, and gibbsite, as well as smaller amounts of siderite and dolomite. Magnesite, siderite, and dolomite contribute to removal of carbon. In general, the model is very flexible, allowing the user to incorporate variations in temperature, pressure, water chemistry, solid-phase mineralogy, and kinetics. Modeling steps are described here as well as the results, which are all based in 1 kg of free water. To determine the total sequestration potential, transport modeling is needed, in addition to the geochemical modeling presented here.

Description: Engineered landfill liner systems are expensive to install and represent a challenge to several developing countries. Alternatively, native soils, preferentially clays, can be used as cost-effective bottom liners. The purpose of this work is to justify the reliance on the ability of the clays at the Kharga-Dakhla land stretch, Western Desert, Egypt, to act as a containment and barrier for pollutants that might be generated in a landfill leachate. This is particularly valid in hyperarid regions where many environmental requirements for landfill liner design are relaxed, as precipitation is rare and percolation to buried wastes is practically absent. The availability of native clays and clay-bearing sediments in the study area, both on surface and subsurface, makes it a potential landfill site. Collaborating techniques have been used to determine the mineralogical, geochemical, and geotechnical characteristics of the sediments constituting the Quseir Formation (Upper Cretaceous). These techniques include x-ray diffraction analysis, differential thermal analysis, cation exchange capacity (CEC), swelling properties, Atterberg limits, porosity, and hydraulic conductivity. The obtained results indicate that the investigated clayey sediments are dense and compact. They have low hydraulic conductivity that ranges from 1 x 10 -10 to 4.96 x 10 -11 cm/s, with moisture content that does not exceed 7%. The swelling values of samples containing smectite range between 250 and 500%. The plasticity limit of the red clay (floor of the Dakhla Oasis) ranges between 11 and 18%, which indicates its suitability as a landfill lining material. Values for CEC are generally high and increase with increasing smectite content. It reaches as much as 69 meq/100-g sample, indicating enhanced ability for natural attenuation and can act within the containment system for metal pollutants. The obtained mineralogical, geochemical, and geotechnical data suggest that the studied clays can be used, effectively, as a viable alternative liner system for solid waste and/or secured landfills, replacing the costly state of the art liner systems. Satisfying siting criteria, the availability of the clays, and the easy way and their low cost of extraction provide a cost-effective solution to the problem of landfill lining in developing countries.

Description: The Cambrian Mount Simon Sandstone is the major target reservoir for ongoing geologic carbon dioxide (CO 2) sequestration demonstrations throughout the midwest United States. The potential CO 2 reservoir capacity, reactivity, and ultimate fate of injected CO 2 depend on textural and compositional properties determined by depositional and diagenetic histories that vary vertically and laterally across the formation. Effective and efficient prediction and use of the available pore space requires detailed knowledge of the depositional and diagenetic textures and mineralogy, how these variables control the petrophysical character of the reservoir, and how they vary spatially. Here, we summarize the reservoir characteristics of the Mount Simon Sandstone based on examination of geophysical logs, cores, cuttings, and analysis of more than 150 thin sections. These samples represent different parts of the formation and depth ranges of more than 9000 ft (〉2743 m) across the Illinois Basin and surrounding areas. This work demonstrates that overall reservoir quality and, specifically, porosity do not exhibit a simple relationship with depth, but vary both laterally and with depth because of changes in the primary depositional facies, framework composition (i.e., feldspar concentration), and diverse diagenetic modifications. Diagenetic processes that have been significant in modifying the reservoir include formation of iron oxide grain coatings, chemical compaction, feldspar precipitation and dissolution, multiple generations of quartz overgrowth cementation, clay mineral precipitation, and iron oxide cementation. These variables provide important inputs for calculating CO 2 capacity potential, modeling reactivity, and are also an important baseline for comparisons after CO 2 injection.

Description: Subsurface geologic storage of carbon dioxide calls for sophisticated monitoring tools with respect to long-term safety and environmental impact issues. Despite extensive research, many factors governing the fate of injected carbon dioxide (CO2) remain unclear. To identify possible risks through leakage of the CO2 storage reservoir, a program for monitoring of the CO2 flux at the surface was started at the Ketzin test site, which allows to distinguish between natural temporal and spatial flux variations and a potential leakage. To gain adequate long-term baseline data on the local background CO2 flux variations, CO2 soil gas flux, soil moisture, and temperature measurements were conducted once a month during a 6-yr period. Furthermore, soil samples were analyzed for their organic carbon and total nitrogen contents. The mean flux of all sampling sites before the CO2 injection (2005-2007) was 2.8 {micro}mol m-2 s-1 (ranging from 2.4 to 3.5), with a Q10 factor of 2.4, and in the years after commencing injection (2009-2010), 2.4 {micro}mol m-2 s-1 (ranging from 2.2 to 2.5), with the same Q10 factor. The CO2 flux rate is mainly controlled by the soil temperature. A significant influence of diurnal temperature variation and soil moisture was not detected. The spatial variability of the CO2 flux among the 20 sampling locations ranges from 1.0 to 4.5 {micro}mol m-2 s-1, depending on the organic carbon and total nitrogen content of the soil. Through comparison with the long-term measurements, unusual high CO2 fluxes can theoretically be distinguished from natural variations.

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: Today, an increased emphasis on the distribution, potential volume, and cost to develop CO 2 geologic sequestration resources exists. In the presence of climate change, the need to make accurate and clearly understandable assessments of carbon sequestration potential, which can be used by the government and industry to plan for technology deployment, has never been greater. We compare three CO 2 storage assessment methodologies: the approach applied by the U.S. Department of Energy in its Carbon Atlas III, the modified U.S. Geological Survey methodology, and the CO 2 Geological Storage Solutions methodology. All three methodologies address storage resources in porous geologic media in sedimentary basins, namely oil and gas reservoirs and saline formations. Based on our analyses, these methodologies are similar in terms of computational formulation. We find that each of the proposed methodologies is science and engineering based. As such, they are important in identifying the geographical distribution of CO 2 storage resource and regional carbon sequestration potential at the national and basin-scale levels for use in energy-related government policy and business decisions. Policy makers need these high-level estimates to evaluate the prospective function that carbon capture and sequestration technologies can play in reducing CO 2 emissions over the long term. The value of these high-level assessments of CO 2 storage resource is to help inform decision makers in governments and industry as to whether carbon capture and sequestration is a climate mitigation option worth pursuing in particular regions.

Description: Concerns about potential climate change related to greenhouse gas emissions have spurred researchers across the world to assess the viability of geologic storage of CO 2 . In the Illinois Basin in the United States, the Cambrian Mount Simon Sandstone has been targeted as a reservoir for carbon capture and storage (CCS). In this CCS system, the Eau Claire Formation is expected to serve as the primary seal to prevent upward migration of the CO 2 plume; however, little work has been done to specifically determine how well it will function as a seal. Although the lateral extent and thickness of the Eau Claire Formation, along with its generally low permeability, certainly make it a prime candidate to serve in this capacity, the primary depositional fabric and mineralogy, which are the fundamental controls on the petrophysical charter of this unit, remain poorly constrained. Therefore, the purpose of this study is to investigate the lithologic, mineralogical, and petrophysical properties of the Eau Claire Formation in an effort to characterize its potential as a functional seal in a CCS system. Sixty-six core-derived Eau Claire Formation samples from seven wells within the Illinois Basin are described using a combination of petrography, reflectance spectroscopy, x-ray diffraction, geochemical, and petrophysical analyses. These analyses show that the Eau Claire Formation contains five different lithofacies (sandstone, clean siltstone, muddy siltstone, silty mudstone, and shale) with fine-scale heterogeneities in fabric and mineralogy that greatly influence the petrophysical properties. Porosity, permeability, and entry-pressure data suggest that some, but not all, lithofacies within the Eau Claire Formation have the capability to serve as a suitable CCS seal. Abundant authigenic minerals and dissolution textures indicate that multiple generations of past fluid-rock interactions have occurred within the Eau Claire Formation, demonstrating that much of the formation has behaved as a fluid conduit instead of as a seal. Minerals that would be potentially reactive in a CCS system (including carbonate, glauconite, and chlorite) are common in the Eau Claire Formation. Dissolution of these and other phases in the presence of carbonic acid could potentially jeopardize the sealing integrity of the unit. Although complexities in the sealing properties exist, the dynamics of the CCS system and the potential for precipitation of new minerals should allow the Eau Claire Formation to serve as an adequate seal.

Description: Producers adjacent to a natural-gas storage field claimed that the natural gas they were producing was native gas from the area and not storage gas being pulled from the nearby gas storage field. The objective of this work is to apply a combination of area-specific and generic geochemical fingerprinting techniques to determine the source(s) of the natural gas being produced by third-party producers outside the gas storage field and to determine the extent of storage gas migration beyond geologic faults that lie between the production area and the gas storage field. An extensive set of natural-gas samples from the storage field, observation wells around the field, and third-party wells was analyzed for gas hydrocarbon and nonhydrocarbon compositions, as well as stable carbon isotopic compositions of methane and ethane. Gas chemical compositional data, including concentrations of the natural native gas tracer, helium, and ethane carbon isotope, were used to establish the unique fingerprints of native gas and storage gases (end-member sources) and to compare those end-member-source fingerprints to those of natural gas in the third-party wells. The analysis determined that gas in both the observation wells and third-party wells was, in fact, storage gas.

Description: This study has evaluated the hydrogeochemistry of some parts of the aquifer underlying and near Abakaliki City, Nigeria, to better understand the local groundwater quality conditions. Twelve representative groundwater samples from water boreholes (wells) in the study area were analyzed for their hydrogeochemical properties: pH, electrical conductivity (EC), turbidity, total dissolved solids (TDS), total hardness, chemical oxygen demand, Ca2+, Mg2+, Na+, K+, , , Cl−, , and . The aquifer is situated in the fractured shales of Abakaliki Formation. The dominant ions in most samples are Ca2+, Mg2+, , and Cl−. Furthermore, strong positive correlations exist between EC-TDS, Na+-TDS, , and . Piper trilinear diagrams were used to classify the hydrogeochemical facies, which included Ca-Mg-Cl and Ca-Mg-Na-Cl-SO4 water types. Ratios of Na-Cl ranged from 0.12 to 0.73, with a mean of 0.55, which is consistent with those of fresh water. The results of this study indicate that the groundwater local to the Abakaliki City poses no threat to human consumption, health, or the environment because the concentrations of physicochemical parameters that can be used to evaluate drinking water quality are within the World Health Organization standard specification.

Description: With almost 200 coal-burning power plants in the region, the Ohio River Valley is an important region to evaluate potential formations for carbon dioxide (CO2) storage. In this study, we consider whether injection-induced stress changes affect the viability of the Rose Run Sandstone, considered as a potential effective storage unit. Our study uses a coupled geomechanical and reservoir simulator that couples fluid flow to induced stress and strain in all the significant stratigraphic units from the surface to the crystalline basement. The pressure and stress variations were modeled during CO2 injection, focusing on injection from a single well. The model uses a constant pressure condition on the boundary of the system. Both reservoir and surface deformation were simulated, and the possibility of reaching shear failure in the reservoir was tested. Carbon dioxide injection in the Rose Run Sandstone aquifer is not likely to cause any significant surface deformation. To consider the potential of increasing injectivity, simulation of a static fracture with a half-length of 300 m (984.3 ft) was considered. As the modeling shows that, with constant injection rate, the fracture can propagate beyond the propped length, a dynamic fracture propagation was also studied. This was achieved by allowing the fracture to grow as a function of a propagation criteria based on effective stress. Because of the favorable stress state of the Rose Run Sandstone, the propagation is primarily in the lateral direction, and no upward fracture propagation through the cap rock has been observed in the model. Finally, we demonstrate that dynamic fracture propagation significantly increases the possible injection rates, and its modeling is useful for determining optimal injection rates.

Description: A by-product of petroleum extraction, produced waters (PWs) containing selenium (Se), arsenic (As), and low-molecular-weight organics (LMWOs) may be generated. Pilot-scale constructed wetland treatment systems (CWTSs) were designed and built to evaluate the removal of these constituents from simulated fresh PW (SFPW). Study objectives were to characterize a fresh PW and determine the constituents of concern (COC); formulate an SFPW; design and build a pilot-scale CWTS for SFPW; and measure performance (i.e., COC removal rates and extents). The treatment goals for this study were to decrease Se concentration in SFPW from approximately 50 {micro}g/L to less than 5 {micro}g/L via microbial reduction; decrease As concentration in SFPW from approximately 20 {micro}g/L to less than 5 {micro}g/L via iron coprecipitation; and decrease LMWO concentration in SFPW from approximately 25 mg/L to less than 1 mg/L via biodegradation. To determine COC removal rates and extents and environmental factors, measurements included analysis of Se, As, LMWOs, dissolved oxygen, conductivity, pH, oxidation-reduction potential, alkalinity, hardness, and temperature. Mean outflow Se concentrations ranged from less than 1 to 47.1 {micro}g/L. Mean outflow As concentrations ranged from 5.7 to 9.5 {micro}g/L, and the mean outflow LMWO concentrations were less than 1 mg/L for all treatments and the untreated control. Organic carbon amendments had a significant effect on Se removal and no effect on As or LMWO removal. This pilot-scale study illustrates that CWTSs can enhance Se removal from SFPW and that removal can be achieved to meet stringent discharge limits. More research is needed to advance the techniques of As removal in CWTSs designed to simultaneously target Se.

Description: One method to beneficially use water produced from coalbed methane (CBM) extraction is subsurface drip irrigation (SDI) of croplands. In SDI systems, treated CBM water (injectate) is supplied to the soil at depth, with the purpose of preventing the buildup of detrimental salts near the surface. The technology is expanding within the Powder River Basin, but little research has been published on its environmental impacts. This article reports on initial results from tracking water and solutes from the injected CBM-produced waters at an SDI system in Johnson County, Wyoming. In the first year of SDI operation, soil moisture significantly increased in the SDI areas, but well water levels increased only modestly, suggesting that most of the water added was stored in the vadose zone or lost to evapotranspiration. The injectate has lower concentrations of most inorganic constituents relative to ambient groundwater at the site but exhibits a high sodium adsorption ratio. Changes in groundwater chemistry during the same period of SDI operation were small; the increase in groundwater-specific conductance relative to pre-SDI conditions was observed in a single well. Conversely, groundwater samples collected beneath another SDI field showed decreased concentrations of several constituents since the SDI operation. Groundwater-specific conductance at the 12 other wells showed no significant changes. Major controls on and compositional variability of groundwater, surface water, and soil water chemistry are discussed in detail. Findings from this research provide an understanding of water and salt dynamics associated with SDI systems using CBM-produced water.

Description: Using a process-based approach, a pilot-scale constructed wetland system was designed and built for treating water produced from an oil field in sub-Saharan Africa. The characteristics of the oil field-produced water were compared with water quality guidelines for irrigating crops and watering livestock to identify constituents of concern (COC) requiring treatment. The COC identified in the produced water include oil, grease, and metals (Zn, Ni, Fe, Mn). A pilot-scale constructed wetland treatment system was then designed and built based on biogeochemical pathways (i.e., sorption, oxidation, and reduction) for transferring and transforming the identified COC to achieve target concentrations meeting water quality guidelines. The pilot-scale treatment system consisted of three series of wetland cells, with four cells in each series. Two series of subsurface flow wetland cells were constructed with each cell having a two-layer hydrosoil of pea gravel and medium-size gravel planted with Phragmites australis. In addition, a series of free water surface wetland cells was constructed, with each cell containing sandy hydrosoil and planted with Typha latifolia. The design allows adjustment of parameters (i.e., hydraulic retention time and organic content of the hydrosoil) to promote the conditions needed to achieve treatment of COC through the identified biogeochemical pathways. This study provides an example of the design and construction of a pilot-scale wetland treatment system using a process-based approach.

Description: At Cranfield field, Mississippi, a monitored carbon dioxide (CO2) sequestration and enhanced oil recovery project provides a unique opportunity to study sealing properties of a marine shale as a CO2-confining zone. The reservoir is in the amalgamated fluvial basal sandstone of the lower Tuscaloosa Formation at depths of more than 3000 m (9843 ft). The marine mudstone of the middle Tuscaloosa forms a continuous regional confining system of approximately 75 m (246 ft). A 6-m (20-ft) core was retrieved from the middle Tuscaloosa marine mudstone approximately 70 m (230 ft) above the CO2 injection zone. We conducted a series of characterizing analyses on the core that would enable us to assess with high confidence seal performance over geologic time. The core displays considerable heterogeneity at centimeter to decimeter scales, with lithology varying from silt-bearing clay-rich mudstone to siltstone and very fine grained sandstone. In total, nine microfacies are recognized in the core. Petrographic, mineralogical, and chemical analyses (scanning electron microscopy, x-ray diffraction, and x-ray fluorescence) show that calcite cements preferentially form in coarser grained beds and have greatly reduced porosity and permeability, making silty and sandy beds less permeable than mudstone. Mercury intrusion capillary pressure tests show desirable sealing capacity for all samples capable of retaining a CO2 column of 49 to 237 m (161-778 ft) at 100% water saturation. Permeability and porosity of all facies are less than 0.0001 md and 4%, respectively. Pores in the samples are at nanometer scales, with modal pore-throat sizes less than 20 nm. Scanning electron microscopic imaging on ion-milled surfaces confirms that nanopores are scarce and generally isolated.

Description: We evaluated the pore volume available for a specific potential geologic carbon dioxide (CO2) storage site in the Upper Ordovician Queenston Formation near the AES Corporation Cayuga coal-fired power plant in Tompkins County, New York. Core data collected 25 mi (40 km) from the plant reveal that the Queenston Formation is a relatively homogeneous fine- to medium-grained sandstone with hematite cement. Seismic and core data indicate that the formation was deposited in a fluvial system with mobile channels and has thickness maxima that trend north-northwest. Porosity is a major factor affecting geologic CO2 storage potential, and it is important to understand discrepancies among porosity measured from core plug, neutron porosity, density-derived porosity, and thin-section point count values. Relative to core plug-derived porosity values, the neutron porosity log is more reliable than the electron density porosity values. Thin sections reveal that hematite cement is the primary factor affecting porosity variability. Seismic, core, and well-log data suggest that in a 25-mi2 (65-km2) area surrounding this power plant, the Queenston Formation can sequester 18 million metric tons ({+/-}11 million metric tons) of CO2 emission from the Cayuga power plant ([~]8 yr of CO2 output, with a range of 3-12 yr), although many uncertainties must be better constrained to obtain a more accurate estimate. Because the Queenston Formation near the Cayuga power plant is relatively homogeneous, most of the formation at this location offers the potential for CO2 storage in its pore space.

Description: A growing concern that increasing levels of greenhouse gases in the atmosphere are contributing to global climate change has led to a search for economical and environmentally sound ways to reduce carbon dioxide (CO2) emissions. One promising approach is CO2 capture and permanent storage in deep geologic formations, such as depleted oil and gas reservoirs, unminable coal seams, and deep brine-containing (saline) formations. However, successful implementation of geologic storage projects will require robust monitoring, verification, and accounting (MVA) tools. This article deals with all aspects of MVA activities associated with such geologic CO2 storage projects, including site characterization, CO2 plume tracking, CO2 flow rate and injection pressure monitoring, leak detection, cap-rock integrity analysis, and long-term postinjection monitoring. Improved detailed decision tree diagrams are presented covering the five stages of a geologic storage project. These diagrams provide guidance from the point of site selection through construction and operations to closure and postclosure monitoring. Monitoring, verification, and accounting techniques (both well-established and promising new developments) appropriate for various project stages are discussed. Accomplishments of the Department of Energy (DOE) Regional Carbon Sequestration Partnerships field projects serve as examples of the development and application to geologic storage of MVA tools, such as two-dimensional and three-dimensional seismic and microseismic, as well as the testing of new cost-effective monitoring technologies. Although it is important that MVA and computer simulation efforts be carefully integrated to ensure long-term success of geologic storage projects, this article is limited to a discussion of MVA activities. This article is an extension of a report published in 2009 by the DOE National Energy Technology Laboratory titled, "Best Practices for Monitoring, Verification, and Accounting of CO2 Stored in Deep Geologic Formations," to which interested readers are referred for more details on MVA tools. Ultimately, a robust MVA program will be critical for establishing carbon capture and storage as a viable greenhouse gas mitigation strategy.

Description: The Mount Simon Sandstone (Cambrian) has significant potential for use as a reservoir for geologic carbon sequestration in the Midwest region, but lithologic variations within the unit remain poorly understood. Petrophysical heterogeneities controlled by the changes in lithologic and diagenetic character challenge the process of estimating the storage capacity of this reservoir. Geophysical logs from wells across the Midwest region were interpreted to define three lithostratigraphic subunits within the Mount Simon Sandstone: an upper unit that has relatively high gamma-ray (GR) values caused by the admixture of argillaceous material; a middle unit defined by relatively lower GR values that result from a cleaner quartzose sandstone and potentially constitutes the main reservoir and flow unit within the formation (the GR values of this unit also display the lowest amount of vertical variability through the section); and a lowermost unit defined by GR values that, in general, progressively increase with depth toward the base of the formation. This downward increase is caused by the increased nonquartz fraction in the formation as the top of the Precambrian basement is approached. In all three units, but especially in the lowermost one, the admixture of feldspars and the presence of dissolution porosity complicate storage capacity calculation. In addition to quartz overgrowths and compaction phenomena that reduce pore volume, the presence of other diagenetic products further complicates the distribution of porosity and permeability within the unit. Storage capacity was calculated only for the middle unit within the Mount Simon Sandstone using values derived from GR and porosity geophysical logs (sonic, neutron, and density). The range of storage capacity found in this study is primarily controlled by reservoir thickness because the variation in porosity within this middle unit is less than that in the other units. However, an assessment of the vertical distribution of porosity and permeability at each site will be required to determine the best intervals with the best flow and storage properties.

Description: Identifying the source of stray gas in drinking water supplies principally relies on comparing the gas composition in affected water supplies with gas samples collected in shows while drilling, produced gases, casing head gases, pipeline gases, and other potential point sources. However, transport dynamics of free and dissolved gas migration in groundwater aquifers can modify both the concentration and the composition of point source stray gases flowing to aquifers and occurring in the groundwater environment. Accordingly, baseline and forensic investigations related to stray gas sources need to address the effects of mixing, dilution, and oxidation reactions in the context of regional and local hydrology. Understanding and interpreting such effects are best addressed by collecting and analyzing multiple samples from baseline groundwater investigations, potential point sources, and impacted water resources.Several case studies presented here illustrate examples of the natural variability in gas composition and concentration data evident when multiple samples are collected from produced gases, casing head gases, and baseline groundwater investigations. Results show that analyses of single samples from either potential contaminant point sources or groundwater and surface water resources may not always be sufficient to document site-specific baseline conditions. Results also demonstrate the need to consistently sample and analyze a variety of baseline groundwater and gas composition screening parameters. A multidisciplinary approach is the best practice for differentiating among the effects of fluid and gas mixing, dilution, and natural attenuation.

Description: Most surface water and shallow groundwater occurring in northeastern Nebraska are of the calcium bicarbonate type, with minor concentrations (e.g., 10–200 mg/L) of sulfate (SO4). Examination of historical water quality data (major cations and anions) for Ponca Creek, a predominantly ephemeral stream in northeastern Nebraska, revealed that SO4 concentrations ranged from about 110 to almost 1000 mg/L and contribute to a calcium sulfate hydrochemical facies. Consequently, most SO4 concentrations were above the U.S. Environmental Protection Agency secondary maximum contaminant level in drinking water of 250 mg/L. Sulfate concentrations for the same period for a nearby stream, Verdigre Creek, range from about 20 to 120 mg/L. Research into probable sources of the elevated SO4 in Ponca Creek revealed that a Late Cretaceous shale, the Pierre Shale, occurs at or near the land surface throughout most of the creek's drainage area, whereas alluvium, other Quaternary deposits, or the Tertiary Ogallala Formation comprises the streambed in Verdigre Creek. The Pierre Shale, encompassing soils formed on this Cretaceous shale, is rich in sulfate-bearing minerals (e.g., gypsum, pyrite, jarosite) that comprise the principal source of the high sulfate in drainage basin soils, alluvium, creek discharge, and shallow groundwater of the Ponca Creek watershed. A public domain geochemical speciation software (Visual MINTEQ) was used to investigate aqueous SO4 geochemistry of Ponca Creek flow. Calculated saturation indices for Ponca Creek waters suggest that they are slightly undersaturated with respect to gypsum and anhydrite despite significant sulfate dissolution and are slightly supersaturated with respect to calcite in numerous samples.

Description: The Susquehanna River Basin drains 27,510 mi2 (71,251 km2), covering parts of New York, Pennsylvania, and Maryland, and provides 50% of the freshwater inflow to the Chesapeake Bay. The Susquehanna River Basin Commission (SRBC) is a federal-interstate compact agency regulating surface and groundwater withdrawals, diversions, and consumptive uses of water, including those associated with natural gas development. Although specific black gas-bearing shale formations are already identified, including the Marcellus, Utica, Antes, Burket, Geneseo, Mandata, Middlesex, Needmore, and Rhinestreet, the SRBC regulatory activity is applicable to any and all gas-bearing formations (Figure 1). The SRBC does not regulate wastewater discharges or pollution incidents because these are already regulated by member jurisdictions of SRBC. As a water resource...

Description: The Ohio River Valley Water Sanitation Commission (ORSANCO) is an interstate compact water pollution control commission created jointly in 1948 by eight states (Indiana, Illinois, Kentucky, New York, Ohio, Pennsylvania, Virginia, and West Virginia) with the approval of the U.S. Congress (Figure 1). The mission of ORSANCO, as provided in the Ohio River Valley Water Sanitation Compact, is to regulate activities in the rivers, streams, and waters of the Compact district (i.e., the Ohio River Basin as it exists within the eight signatory states) to mitigate existing and future surface water pollution. The Ohio River is an important natural resource in many regards. Along its 981-mi (1579-km) length, it provides habitat for more than 120 species of fish and facilitates the transport of 200+ million tons of goods per year. In addition, more than 5 million people rely on the Ohio River as their drinking water supply. The Ohio River Valley Water Sanitation Commission, in consonance with its mission and the broad powers granted to it under the Compact, operates programs to improve surface water quality in the Ohio River and its tributaries, such as the...

Description: Pennsylvania is not only the birthplace of the modern petroleum industry but also the focus of the modern Marcellus Shale gas play. For more than 150 yr, Pennsylvania has experienced a rich history of oil and gas exploration and production, witnessed the advent of modern petroleum regulations, and now sits deep in the heart of the largest domestic shale gas play the United States has ever seen. Although a known source rock for decades, the Marcellus Shale was not considered a viable gas reservoir until Range Resources Corporation (Range) discovered the play with its completion of the Renz No. 1 well in Washington County in October 2004. Using horizontal drilling and hydraulic fracturing techniques used by operators working the Barnett Shale gas play, Range has gone on to complete hundreds of horizontal shale gas wells in Washington County alone. Other operators have followed suit in counties from one corner of the state to the other, and as of June 2011, the Commonwealth has issued nearly 6500 Marcellus Shale gas well permits. Based on publicly reported well completion and production data, an average Marcellus Shale gas well requires 2.9 million gal of water during the hydraulic fracturing process and produces 1.3 mmcf gas/day. Furthermore, the U.S. Energy Information Administration has estimated that as of mid-2011, daily Marcellus Shale gas production in Pennsylvania exceeds 2.8 bcf. Because of the level of drilling activity and production associated with the Marcellus play, Pennsylvania has become the nexus of shale gas production and water management issues.

Description: The Eau Claire Formation of the midwestern United States was evaluated for its potential use as a confining unit (seal) overlying a sandstone reservoir to securely store injected $${\mathrm{CO}}_{2}$$ . This evaluation included: (1) lithofacies composition and distribution, (2) capillary entry pressure analysis, and (3) fluid- and fracture-pressure analysis. The regional distribution of lithofacies in the Eau Claire was evaluated by examination of core and log data from selected wells across the study area. Log data were used to define electro-lithofacies, which are spatially variable and represent a mixture of shale, siltstone, sandstone, limestone, and dolomite. Because of the significant variation in lithofacies and the complex spatial distribution, the entire interval should be considered in evaluating the seal capacity of the unit at a given locality. Mercury-injection capillary pressure (MICP) data were obtained on 17 samples of Eau Claire lithofacies ranging from muddy shale to sand/silt to evaluate the potential for capillary entry of fluids into the pore system of the lithofacies of the unit. Interpretation of these data indicated capillary failure of the muddy shale lithofacies is unlikely. However, many of the MICP samples contain millimeter-scale silt/sand interbeds, which would probably allow $${\mathrm{CO}}_{2}$$ entry but, because these beds commonly have very limited lateral continuity, they are very unlikely to provide pathways for large-scale $${\mathrm{CO}}_{2}$$ leakage through the interval. Evaluation of structural settings, lithostatic and existing formation aquifer pressures in the Eau Claire, in conjunction with the height of $${\mathrm{CO}}_{2}$$ columns stored in the underlying Mount Simon Sandstone (Cambrian), suggest that fluid pressures induced by a static buoyant $${\mathrm{CO}}_{2}$$ plume are unlikely to induce fractures in the formation. However, elevation of the aquifer pressure during injection may be capable of creating fractures within the unit.

Description: Hydraulic fracture stimulation (HFS) of unconventional oil and gas reservoirs is of public concern with respect to fugitive gas emissions, fracture height growth, induced seismicity, and groundwater quality changes. We evaluate the potential pathways of fugitive gas seepage during stimulation, in production, and after abandonment; we conclude that the quality of the casing installations is the major concern with respect to future gas migration. The pathway outside the casing is of particular concern as it likely leads to many wells leaking natural gas from thin intermediate-depth gas zones rather than from the deeper target reservoirs. These paths must be understood, likely cases identified, and the probability of leakage mitigated by methods such as casing perforation and squeeze, expanding packers of long life, and induced leakoff into saline aquifers. HFS itself appears not to be a significant risk, with two exceptions. These occur during the high-pressure stage of HFS when (1) legacy well casings are intersected by fracturing fluids and when (2) these fluids pressurize nearby offset wells that have not been shut in, particularly offset wells in the same formation that are surrounded by a region of pressure depletion in which the horizontal stresses are also diminished. This paper focuses on the issue of gas migration from deeper than the surface casing that occurs outside the casing caused by geomechanical processes associated with cement shrinkage, and we review the origin of the gas pulses recorded in noise logs, landowner wells, and surface-casing vents.

Description: This paper explores some basic economics of the climate change issue and how government response may impact the petroleum industry. Possible economic aspects are addressed by examining past and projected fossil fuel production numbers, calculating their resulting emissions, and then projecting how regulations or taxes might affect energy prices and production. Nine medium to major petroleum companies, which do business in the USA, are currently factoring in some kind of carbon emission restrictions into their long-range business plans. A driver for these plans is that the vast majority of countries, including the world’s largest $${\mathrm{CO}}_{2}$$ emitters, have formally agreed to limit their $${\mathrm{CO}}_{2}$$ emissions to avoid a 2°C (3.6°F) rise in global temperatures. Because there is no agreement yet on a set number of allowable emissions, this paper utilizes estimated carbon budgets from one paper, Meinshausen et al. ( 2009 ). Some pertinent results derived herein are the following: 1) oil and natural gas only comprise 33.3% of potential $${\mathrm{CO}}_{2}$$ emissions from fossil fuels; 2) under a $$\sim 50\%$$ probability scenario of exceeding 2°C (3.6°F), all proven reserves of oil and natural gas (as of 2012) could be consumed, whereas only 56% could be utilized with continued coal consumption. To demonstrate how a market approach might limit carbon emissions, a simple model shows how an annually increasing carbon tax affects the relative price of fossil fuels and alternative energy. The objective of this paper is to present arguments that there are economic reasons for American Association of Petroleum Geologists (AAPG) to address the issue of climate change.

Description: Geological sequestration of $${\mathrm{CO}}_{2}$$ for enhanced oil recovery (EOR) has been in use for decades, but it now represents a potentially economical method of mitigating anthropogenic $${\mathrm{CO}}_{2}$$ output. However, current understanding of the interaction between injected $${\mathrm{CO}}_{2}$$ and the reservoir rock is limited and prevents accurate estimation of reservoir $${\mathrm{CO}}_{2}$$ capacity. Delineating the diagenesis of the reservoir is useful in predicting post- $${\mathrm{CO}}_{2}$$ injection changes in reservoir porosity and permeability. The Albian Donovan Sand member of the Rodessa Formation, Citronelle Field, Alabama, is the subject of an ongoing Department of Energy $${\mathrm{CO}}_{2}$$ -EOR suitability study. The arkosic Donovan Sand is highly heterogeneous, containing conglomeratic intervals, low to extensive poikilotopic calcite cement, loose to tight grain packing, and low 〈1% to high (5%) porosity (primary and secondary) observed in thin section. It forms the basal members of laterally discontinuous upward-fining parasequences that define a marine to brackish to fluvial delta system. The diagenesis of the Donovan Sand occurred in five stages: 1) pre-burial and compaction–formation of extensive calcite cement; 2) partial dissolution of calcite cement and framework feldspars; 3) secondary calcite cementation, localized dolomitization, and calcite and anhydrite concretion formation; 4) hydrocarbon charge; and 5) pyrobitumen development. Primary porosity is dominant, but substantial secondary porosity was formed during stage 2. Following injection of $${\mathrm{CO}}_{2}$$ , water injection and oil and gas production rates dropped below modeled values. We propose that the $${\mathrm{CO}}_{2}$$ injection dissolved calcite cement proximal to the injection well and reprecipitated it nearby with the effect of reducing porosity and/or permeability.

Description: We use sediment ages and mercury (Hg) concentrations to estimate past and future concentrations in the South River, Virginia, where Hg was released between 1930 and 1950 from a manufacturing process related to nylon production. In a previous study, along a 40 km (25 mi) reach, samples were collected from 26 of 54 fine-grained deposits that formed in the lee of large wood obstructions in the channel and analyzed for grain size, Hg concentration, and organic content. We also obtained radiometric dates from six deposits. To create a history that reflects the full concentration distribution (which contains concentrations as high as 900 mg/kg [900 ppm]), here, we treat the deposits as a single reservoir exchanging contaminated sediments with the overlying water column, and assume that the total sediment mass in storage and the distribution of sediment ages are time invariant. We use reservoir theory to reconstruct the annual history of Hg concentration on suspended sediment using data from our previous study and new results presented here. Many different reconstructed histories fit our data. To constrain results, we use information from a well-preserved core (and our estimate of the total mass of Hg stored in 2007) to specify the years associated with the peak concentration of 900 mg/kg. Our results indicate that around 850 kg (1874 lb) of Hg was stored in the deposits between 1955 and 1961, compared to only 80 kg (176 lb) today. Simulations of future Hg remediation suggest that 100-yr timescales will be needed for the South River to remove Hg-contaminated sediments from the channel perimeter through natural processes.

Description: SONAR, historical and aerial photographs, and vibracoring were used to assess the type and thickness distribution of sediments impounded by Gold Ray Dam on the Rogue River in southern Oregon. From these data, a volume of about 400,000 cubic yards ( $$\sim 306,000\hbox{ \hspace{0.17em} }{\mathrm{m}}^{3}$$ ) of sediment was determined for the inundated area of the reservoir. Overall, sediment volumes in the impounded part of the reservoir were less than expected. There are three possibilities that may explain the perceived absence of sediment: (1) the gradient of the Rogue River in this stretch is less, and therefore sediment yields are less; (2) the extraction of gravels and/or other impediments upstream decreased the availability of sediments delivered into the reservoir; and/or (3) sediment was deposited by a prograding delta that filled in the inundated area of the floodplain upstream from Gold Ray Dam. The amount of sediment deposited on this inundated floodplain may have been as much as 1,800,000 cubic yards ( $$1,380,000\hbox{ \hspace{0.17em} }{\mathrm{m}}^{3}$$ ), bringing the total amount of sediment impounded by Gold Ray Dam to $$\sim 2,200,000\hbox{ \hspace{0.17em} }\hbox{ \hspace{0.17em} }\mathrm{cubic}$$ yards ( $$\sim 1,700,000\hbox{ \hspace{0.17em} }\hbox{ \hspace{0.17em} }{\mathrm{m}}^{3}$$ ). Applied sedimentology is not only vital to developing a depositional model for the filling of a reservoir, but also providing insights into depositional and erosional changes that will occur upon the removal of a dam. In particular, the processes of delta formation, reoccupation of abandoned channels, and avulsion are paramount in determining sediment accumulation and distribution in reservoirs.

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: Reprocessing of the SeisData6 coastal plain profile was motivated by the need to provide enhanced subsurface imaging critical to site characterization studies for CO 2 storage within the South Georgia Rift (SGR) basin. The objectives were to identify and interpret subsurface reflectors for evidence of the buried Triassic basin and its underlying characteristics. Our new interpretation, supported by analysis of well data, has helped substantiate the presence of a Triassic basin beneath the coastal plain sediments in Southeast Georgia. This basin is approximately 2.2 km (1.7 mi) deep and 170 km (106 mi) wide and appears to coincide with the subsurface convergence of the southwest and northeast extensions of the Riddleville and Dunbarton basins that are subsidiaries of the main SGR. It is characterized by distinctively higher seismic velocities relative to the overlying coastal plain sediments and manifests a series of subhorizontal reflectors below the topmost reflector. We reinterpreted the topmost reflector to originate from a change in velocity and density between the Cretaceous coastal plain sediments and the underlying Triassic rocks. This does not always originate from the Pre-Cretaceous basalt contrary to previous interpretations. The interpreted absence of basalt from this study is consistent with Heffner et al. (2012) showing that basalt is not prevalent throughout the SGR basin. Seismic discontinuities in the southeast of the basin suggest Triassic normal faults. Our data show no clear evidence for the Augusta fault that was identified in other studies in the vicinity of the Piedmont–coastal plain boundary in Georgia and South Carolina.

Description: The West Virginia Division of Energy is currently evaluating several deep saline formations in the Appalachian Basin of West Virginia that may be potential carbon dioxide (CO 2 ) sequestration targets. The Silurian Newburg Sandstone play, developed in the 1960s and 1970s, primarily involved natural-gas production from reservoir rock with well-developed porosity and permeability. High initial pressures encountered in early wells in the Newburg indicated that the overlying Silurian Salina Formation provides a competent seal. Because of the large number of CO 2 point sources in the region and the favorable reservoir properties of the formation (including an estimated 300 bcf of natural-gas production), the Newburg Sandstone was evaluated for the potential geologic storage of CO 2 . Within the Newburg play, there are several primary fields separated geographically and geologically by saltwater contacts and dry holes. Previous studies have determined the storage potential within these individual fields. This study shows that the Newburg is more suitable for small-scale injection tests instead of large-scale regional storage operations.

Description: Shales are becoming the most important source of natural gas in North America, and replacement of coal by natural gas is reducing CO 2 emissions and improving air quality. Nevertheless, shale gas is facing strong opposition from environmental nongovernmental organizations. Although these organizations have greatly exaggerated the potential negative environmental impacts of shale gas and shale oil, methane leakage and contamination of groundwater and surface water by flowback and produced waters are serious concerns. These contamination pathways are not unique to shale gas and shale oil, and they are manageable.

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: Porosity and permeability are key petrophysical variables that link the thermal, hydrological, geochemical, and geomechanical properties of subsurface formations. The size, shape, distribution, and connectivity of rock pores dictate how fluids migrate into and through micro- and nano-environments, then wet and react with accessible solids. Three representative samples of cap rock from the Eau Claire Formation, the prospective sealing unit that overlies the Mount Simon Sandstone, a potential $${\mathrm{CO}}_{2}$$ storage formation, were interrogated with an array of complementary methods. neutron scattering, backscattered-electron imaging, energy-dispersive spectroscopy, and mercury porosimetry. Results are presented that detail variations between lithologic types in total and connected nano- to microporosity across more than five orders of magnitude. Pore types are identified and then characterized according to presence in each rock type, relative abundance, and surface area of adjacent minerals, pore and pore-throat diameters, and degree of connectivity. We observe a bimodal distribution of porosity as a function of both pore diameter and pore-throat diameter. The contribution of pores at the nano- and microscales to the total and the connected porosity is a distinguishing feature of each lithology observed. Pore:pore-throat ratios at each of these two scales diverge markedly, being almost unity at the nanoscale regime (dominated by illitic clay and micas), and varying by one and a half orders of magnitude at the microscale within a clastic mudstone. Individual minerals, primarily illite and glauconite, have unmistakable pore and pore-throat signatures and contribute disproportionately to connected reactive surface area. The pore types created or evolved during diagenesis mediate profound differences between bulk and pore-network-accessible mineral associations in the mudstones. Results of this study can ultimately be used to inform reactive-transport simulations of effective reactive surface area.

Description: $${\mathrm{CO}}_{2}$$ geologic sequestration has been recognized as a potential greenhouse gas mitigation strategy. Regional $${\mathrm{CO}}_{2}$$ geologic storage in deep saline formations will likely involve the injection of $$\sim 10$$ to 100 million metric tons (11 to 110 million tons) of $${\mathrm{CO}}_{2}$$ per year using a network of $$\sim 10$$ to 50 wells over an area covering $$\sim 10\mbox{--}100$$ sq. miles ( $$26\mbox{--}259\hbox{ \hspace{0.17em} }\hbox{ \hspace{0.17em} }{\mathrm{km}}^{2}$$ ). Some of the wells will be injecting into closed volumes because of symmetry, thus providing the bounding case in terms of pressurization and brine efflux. This study describes a parametric analysis of the problem using characteristics typical of the Arches Province in the United States Midwest where Paleozoic rocks form broad arch and platform structures. Two-dimensional radial-cylindrical models developed with the numerical simulator STOMP (Subsurface Transport Over Multiple Phases) are utilized to investigate the impact of well spacing, injection depth, and reservoir characteristics of the injection zone (Mount Simon) and cap rock (Eau Claire) on system performance. Multiple linear regression analysis is then used to develop correlation equations between these design variables and performance metrics, such as cumulative $${\mathrm{CO}}_{2}$$ -mass injected and $${\mathrm{CO}}_{2}$$ -plume extent. The correlations are tested on new synthetic test sites, and are found to predict the performance metrics quite accurately. These results serve as a proxy simulator to quickly evaluate various design options, instead of having to run time-consuming numerical simulations, and can therefore be applied for developing optimal injection strategies for regional $${\mathrm{CO}}_{2}$$ storage in the Arches Province.

Description: Quantifying the success or failure of states in effectively and safely managing natural gas development is important for regulators, elected officials, and citizens to engage in productive dialog around natural gas development and the process of hydraulic fracturing. Accordingly, this study provides a detailed analysis of notices of violations from the Pennsylvania Department of Environmental Protection from January 2008 to August 2011, categorizing each violation for 3533 wells drilled. Of the 2988 violations, 1844, or 62%, were for administrative or preventative reasons. The remaining 38%, or 1144 notices of violations, were for environmental violations, which were associated with 845 unique environmental events. These events were classified into major and nonmajor categories based on the level and severity of the pollution. Blowouts, uncontrolled venting, and gas migration are considered as severe and, hence, are classified as major. The top quartile of water contamination and land spills is 400 gal and provides the threshold in this study for major events in these two categories. Of these major events, less than 1% or 25 involved these major impacts. In all but six of these cases, the resulting environmental impacts have been completely mitigated. The 820 nonmajor environmental events concern site restoration, water contamination, land spills, and cement and casing events, which do not involve what is classified as having major environmental impact. The number of polluting environmental events per well drilled declined by 60% between 2008 and August 2011, from 52.9% of all wells drilled in 2008 to 20.8% to August 2011. The regulatory data evaluated in this study may serve as an appropriate litmus test for neighboring states as they move forward with regulating shale energy development. In particular, we find that each of the underlying causes associated with these specific events could have been either entirely avoided or mitigated under the proposed regulatory framework of the New York State.

Description: Open faults and fractures act as a major control of fluid flow in the subsurface, especially in fine-grained, low-permeability lithologies. These discontinuities commonly form a part of seal bypass systems, which can lead to the failure of hydrocarbon traps, CO 2 geosequestration sites, and waste and injected fluid repositories. We evaluate mesoscale variability in fracture density, morphology and the variability in elastic moduli in the Jurassic Carmel Formation, a proposed seal to the underlying Navajo Sandstone for CO 2 geosequestration. By combining mechanostratigraphic outcrop observations with elastic moduli derived from wireline-log data, we characterize the variability in fracture pattern and morphology with the observed variability in rock strength within this heterolithic top seal. Outcrop inventories of discontinuities show that fracture densities decrease as bed thickness increases and that fracture propagation morphology across lithologic interfaces vary with changing interface type. Dynamic elastic moduli, calculated from wireline-log data, show that Young's modulus ranges by as much as 40 GPa (5,801,510 psi) across depositional interfaces and by an average of 3 GPa (435,113 psi) across the reservoir-seal interface. We expect that the mesoscale changes in rock strength will affect the distributions of localized stress and thereby influence fracture propagation and fluid flow behavior within the seal. These data provide a means to closely tie outcrop observations to those derived from subsurface data and estimates of subsurface rock strength. The characterization of rock strength variability is especially important for modeling the response of caprocks to changing stress conditions associated with increased fluid pressures and will allow for better site screening and subsurface fluid management.

Description: The occurrence of several water crises in India over the years has resulted in the formulation of strategies that promote sustainable development of groundwater resources. For such planning efforts, the evaluation of groundwater recharge zones is a vital component of the water balance equation. Therefore, this study presents a systematic scientific analysis of various morphometric parameters relating to groundwater flow in hard rock terrain. The numerical classification scheme presented herein constitutes an integrated approach that shows how to leverage basic watershed information to evaluate prospective sites and measures at various scales for the purposes of water resources development and management. We have used our morphometric analysis of the Mamundiyar watershed of southern India to demonstrate the use of this classification scheme as a helpful tool in the watershed development planning process. The results of this relative ranking of Mamundiyar subbasins, using various parameters that are ultimately indicative of surficial rock permeability, show the usefulness of this classification scheme in identifying suitable rainfall infiltration sites. Together with an evaluation of the various hydrogeologic conditions in a given basin, this type of numerical classification scheme can be developed and applied to properly identify recharge sites in the planning stages of sustainable watershed development, as well as in already active watersheds, perhaps where extractive industries are working or certain land use practices exist, to evaluate potential relationships between hydrogeologic regimes and these anthropogenic activities.

Description: Two azimuthal resistivity surveys were completed using the square array within the Mamu Formation, Enugu area, Nigeria, to characterize the orientation and porosity of fractures. The target consists of a shallow (〈30 m [98 ft]) fracture zone that corresponds to the average completion depth for the water supply wells in the study area. Fracture orientation, fracture porosity, and coefficient of anisotropy of the investigated media were determined from the azimuthal resistivity data. Results of the survey data indicate that the fractures trend generally in the northwest–southeast direction at depths of 7.1, 10.0, 20.0, and 28.3 m (23.3, 32.8, 65.6, and 92.8 ft). The fracture porosity ranged between 0.68% and 17%. The coefficient of anisotropy () ranges between 1.00 and 1.12. Fractures at localities with relatively high values of possess relatively high fracture porosity and relatively low specific surface area and thus are more likely to be permeable. These interpretations were in agreement with the information collected at bedrock outcrops during this and previous studies. It is therefore true that the data obtained from this study will enhance the understanding of the permeable zone, fluid migration pattern, and vulnerability of the groundwater to mine drainage problems in the Enugu area.

Description: With the exploration and the production of the Marcellus Shale come inevitable unavoidable environmental impacts to the surface of the Earth and associated waters of the United States including wetlands and streams. Environmental impact assessment includes measurement of impacts to aquatic resources, much of which is associated with the production and transportation of Marcellus Shale gas to market. The Commonwealth of Pennsylvania has prepared a rapid resource condition assessment protocol that will be applied to determine the existing quality of Pennsylvania streams to assess impacts to those streams and to quantify appropriate compensatory mitigation for impacts to these water resources. This protocol, advanced by the Bureau of Waterways Engineering and Wetlands of the Pennsylvania Department of Environmental Protection, builds on prior work of the U.S. Army Corps of Engineers Norfolk District and the Unified Stream Methodology of the Virginia Department of Environmental Quality to provide a consistent and rapid condition assessment for projects to obtain water obstruction and encroachment permits, for water quality certifications, as well as general permits that affect waterways, floodways, and/or floodplains.

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.