Final manuscript post peer review, without publisher's formatting or copy editing (postprint)

ABSTRACT Recent concerns about climate change and greenhouse gas emissions have a clear effect on the energy sector, directly affecting the use of fossil fuels. Companies and countries that depend on these sources of energy (so-called not clean) take actions to search for palliative solutions. The production of atlases of carbon capture and storage (CCS) is one of the collaborative actions that seeks to systematize and organize several aspects involving the use of CCS technologies. This paper focuses on an analytical overview of approaches addressed by five different CCS atlases published by Brazil, the United States, Canada, Mexico, Norway, and South Africa. The five atlases are available for public access; an analytical overview could substantiate the academic and technical decisions related to the future publication of a new atlas for any country and suggests the inclusion of new topics such as social and environmental issues.

Carbon capture and storage is a critical technology for ensuring a range of clean energy options are available to meet future energy demand in the United States and abroad. A total of 1079 industrial CO2 emission sources are located in the northeastern United States, where challenging surface and subsurface conditions limit onshore CO2 storage potential. A systematic resource assessment was conducted using industry-standard resource classification methods established by the Society of Petroleum Engineers’ Storage Resources Management System to characterize CO2 storage resources in the middle–northern Atlantic offshore region along the eastern United States. Storable CO2 quantities and storage efficiencies were estimated for Cretaceous- and Jurassic-age sandstone sequences. Regional data integration and analysis were conducted to estimate storable quantities and storage efficiencies using probabilistic methods with static volumetric calculations and dynamic simulations. Offshore storage efficiencies range from 1% to 13%, with regional-scale estimates of 37–403 billion t (Gt) of CO2 classified as prospective storage resources. Dynamic CO2 injection simulation in a middle Cretaceous sequence on the eastern flank of the Great Stone Dome suggests 30–51 million t of CO2 can be stored and contained within the time and pressure constraints assumed for a commercial storage project. The regional Cretaceous and Jurassic plays identified in the offshore study region have prospective storage resources sufficient for long-term storage of CO2 from nearby industrial sources onshore. Continued resource discovery efforts are recommended to assess the development and commerciality of the potential storage identified near the Great Stone Dome.

ABSTRACT 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-mi2 (260-km2) 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.

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 CO2, 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.

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 SO4 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.

To achieve reclamation certification, oil-and-gas operations in Alberta, Canada are required to monitor the revegetation of idle well pads that no longer support operations. Currently, monitoring is completed by oblique, helicopter-collected photography and on-the-ground field surveys. Both monitoring strategies present safety and logistical challenges. To mitigate these challenges, a remote-sensing project was completed to develop and deploy a reproducible workflow using high-spatial-resolution satellite imagery to monitor revegetation progress on idle well pads. Seven well pads in the Aspen region of Alberta, Canada were selected for workflow development, using imagery from 2007, 2009, and 2011. Land-cover classes were derived from the satellite imagery using a training dataset, a series of vegetation indices derived from the satellite imagery, and regression tree classification programs, and were used to evaluate changes in vegetation cover over time. A refined version of this general workflow was then deployed across 39 well pads in the Firebag region of Alberta, Canada, using imagery from 2010 to 2016. In 2016, fieldwork was conducted across a subset of 16 well pads in the Firebag region, which facilitated a formal accuracy assessment of the land-cover classifications. This project demonstrated that high-spatial-resolution satellite imagery could be used to develop accurate land-cover classifications on these relatively small landscape features and that temporal land-cover classifications could be used to track revegetation through time. Overall, these results show the feasibility of remote-sensing–based workflows in monitoring revegetation on idle well pads.

ABSTRACT 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.

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.