Review ofTOUGH2 Numerical Modeling of the WCS Facility, Andrews County, Texas

The Bureau of Economic Geology (BEG) was tasked with reviewing the TOUGH2 numerical modeling submitted by WCS (two 3D models and one 2D model for the low-level application and one 2D model for the byproduct application). The preliminary step to the review consisted of the lengthy installation of the software and ensuring that the results agreed with those supplied by WCS and the software developers. The TOUGH2 2D transport modeling by the applicant addressed subsurface-parameter uncertainty in a relatively thorough fashion except for one variable: assumed top-boundary fluxes of ~0.01 inch/yr are too low. Simulations performed for and presented in this report with top flux increases to 0.1 and 1 inch/yr lead to much less conservative results, decreasing breakthrough time from ~14,000 years (applicant's base case) to less than 5,000 years (flux x 10) and less than 1,000 years (flux x 100) for Tc-99. Chloride's breakthrough time, used as a marker for the byproduct facility, also decreases from over 1,000 years (applicant's base case) to less than 200 years in other cases. Note that cases in which simulation results do not meet concentrations suggested by regulations do not necessarily invalidate the site. Because the 2D model used in the simulations is so conservative, a more realistic conceptual model consistent with site geology and hydrology would probably yield results that would be less extreme than some of those presented in this analysis. It is, however, the applicant's charge to develop such models, for example, by modeling the bottom liner (as applicable), by evaluating fracture extent and connectivity, and by better understanding the source (leachate chemical composition was obtained with no credit given to containers; in addition, high water flux is also likely to translate into a much lower radionuclide concentration). TOUGH2 3D models do provide insight into the behavior of the natural system but should be better calibrated and better constrained to provide arguments to the unproven applicant's contention that the system is and has been at steady state for tens of thousands of years.Bureau of Economic Geolog

Self Sealing Evaporation Ponds for Desalination Facilites in Texas

The State of Texas has taken a renewed interest in desalination of brackish water. Because the Texas population is expected to grow tremendously in coming decades, many municipalities and other water-supplying entities will need to supplement their current freshwater sources. Desalination of brackish water is high on the list of water-source alternatives for supplying some or all of the increased water needs in many communities. However, disposal of desalination concentrates may pose legal, technical, and economic barriers, especially for smaller communities with water supplies of less than one million gallons per day (MGD). In this report, we examine evaporation ponds and the possibility of incorporating a low-permeability layer (precipitant) into the pond-liner system as a liner component or possibly as the liner itself. One aspect of this analysis was to investigate the regulatory requirements and barriers of using self-sealing ponds, if this strategy proves to be a technically viable alternative to standard pond liners. Another part of the work consisted of understanding the favorable chemical conditions, natural or induced, for the precipitation of such a compound(s). The third and last facet of this work was to investigate the savings or extra costs of this approach. The following observations characterize the regulatory issues relating to self-sealing pond liners. (1) No significant regulatory barriers currently exist that would prevent the permitting of self-sealing evaporation pond-liner technologies at desalination facilities in Texas. (2) No Federal authorizations are required, but a Texas Land Application Permit (TLAP) must be obtained from the Texas Commission on Environmental Quality (TCEQ) Water Quality Division. (3) TCEQ has considerable latitude for approving alternative permit requirements for industrial permits. Rules for municipal wastewater treatment are used as guides for the evaluation of industrial evaporation ponds but do not impose strict regulatory requirements. Currently approved pond liners include a 3-foot-thick layer of in-situ clay or compacted clay (with a maximum hydraulic conductivity of 10-7 cm/s) or a geomembrane liner (polyvinyl chloride [PVC], high-density polyethylene [HDPE], butyl rubber, polypropylene, etc.) of 30 mils (0.76 mm) or more with leak detection monitoring. An alternative liner technology may be approved by TCEQ if it can be demonstrated to achieve and maintain equivalent containment capabilities to the pre-approved liners and that the resulting liner material(s) will not deteriorate because of reactivity with salinity or other compounds in the effluent stream or other ambient conditions. Supporting demonstration information may include previous research, pilot projects, and monitoring data from existing operational facilities currently utilizing the proposed technology. Regulatory processing for the permitting of an evaporation pond could be simplified if the self-sealing technology were recognized by the TCEQ as an accepted type of liner, equivalent to compacted clay or geomembrane liners. No statutory change or rulemaking would be required to revise the permit instructions to add self-sealing pond liners to the list of acceptable methods, although compelling scientific and engineering evidence would be necessary to justify such a modification.Bureau of Economic Geolog

Risk-based approach to assess CO2 storage capacity

Bureau of Economic Geolog

Historical and 2006–2025 estimation of ground water use for gas production in the Barnett Shale, North Texas

The Barnett Shale play, currently the most prolific onshore gas play in the country, has seen a quick growth in the past decade with the development of new "frac" (a.k.a. fracture stimulation) technologies needed to create pathways to produce gas in the very low permeability mudstones. This technology uses large amounts of water in a short period of time to develop a gas well. There are currently over 5,600 wells producing gas from the Barnett Shale, with thousands more likely to be drilled in the next couple of decades as the play expands out of its core area. A typical vertical completion consumes approximately 1.2 million gallons, and a typical horizontal well completion 3.0 to 3.5 million gallons of fresh water. Almost 8,000 acre-feet of water (from all sources) was used in 2005, mostly in an area equivalent to a Texas county. This usage has raised some concerns among local communities and other groundwater stakeholders, especially in the footprint of the Trinity aquifer. In this study, we present projections of groundwater use by the oil and gas industry through 2025. Total water use is highly uncertain, being dependent on the price of gas above all. We approach this uncertainty by developing high, medium, and low scenarios that can be somewhat understood as cases with decreasing gas prices. Other important factors include geologic risk factors in the Barnett (maturity of the shale, thickness of the formation, presence of features limiting or hampering well completion), technological factors (horizontal vs. vertical wells, water recycling), operational factors (number of well completions that can be done in a year, proximity of a fresh-water source), and regulatory factors. The high scenario cumulates most of the high-end water use of the previous parameters, whereas the low scenario uses the low values of their range. The low scenario utilizes 29,000 AF of groundwater to the 2025 horizon (1,500 AF/yr on average), a clear retreat from the current annual rate of water use by the industry, corresponding to a large drop in gas price. The high scenario calls for a total water use between 2007 and 2025 of 417,000 AF of groundwater (~22,000 AF/yr on average). It corresponds to sustained high gas prices allowing operators to expand to all economically viable areas and produce most of the accessible resource but also includes the assumption that water use is not limiting. All scenarios assume that operators continue using water at a per-well rate similar to that of today and that no technological breakthrough will bring it down. The medium scenario assumes a groundwater use of 183,000 AF (~10,000 AF/yr on average). In the high scenario, groundwater use steadily climbs from ~5,000 AF/yr in 2005 to 20,000 AF/yr in 2010 and then slowly increases to a maximum of ~25,000 AF/yr in 2025. The medium scenario follows a similar path, climbing to a maximum of ~13,000 AF/yr in 2010 and then slowly decreasing to ~7,500 AF/yr in 2025. The medium case is not necessarily the most likely. Because the Barnett Shale play is dependent on gas prices, a more accurate statement would be to formulate that the medium case is the most likely under the condition that gas prices stay at their current level.Bureau of Economic Geolog

Pressure perturbations from geologic carbon sequestration: Area-of-review boundaries and borehole leakage driving forces

We investigate the possibility that brine could be displaced upward into potable water through wells. Because of the large volumes of CO2 to be injected, the influence of the zone of elevated pressure on potential conduits such as well boreholes could extend many kilometers from the injection site—farther than the CO2 plume itself. The traditional approach to address potential brine leakage related to fluid injection is to set an area of fixed radius around the injection well/zone and to examine wells and other potentially open pathways located in the “Area-of-Review” (AoR). This suggests that the AoR needs to be defined in terms of the potential for a given pressure perturbation to drive upward fluid flow in any given system rather than on some arbitrary pressure rise. We present an analysis that focuses on the changes in density/salinity of the fluids in the potentially leaking wellbore.Bureau of Economic Geolog

In Vitro Versus in Situ Ruminal Biohydrogenation of Unsaturated Fatty Acids from a Raw or Extruded Mixture of Ground Canola Seed/Canola Meal

Raw or extruded blends of ground canola seeds and canola meal were used to compare in vitro and in situ lag times and rates of disappearance due to ruminal biohydrogenation of unsaturated fatty acids. The in situ study resulted in higher lag times for biohydrogenation for polyunsaturated fatty acids and lower rates of biohydrogenation of unsaturated fatty acids than the in vitro study, so the in situ biohydrogenation of polyunsaturated fatty acids was not complete at 24 h of incubation. With both methods, rates of biohydrogenation of polyunsaturated fatty acids were higher than for cis-9C18:1. Extrusion did not affect the rate of biohydrogenation of cis-9C18:1, but resulted in higher rates of biohydrogenation of polyunsaturated fatty acids with higher proportions of trans intermediates of biohydrogenation at 4 h of incubation in vitro and at 8 h of incubation in situ. These results suggest that extrusion affects the isomerization of polyunsaturated fatty acids, rather than the hydrogenation steps. In conclusion, in vitro and in situ methods can both show differences of ruminal metabolism of unsaturated fatty acids due to processing, but the methods provide very different estimates of the rates of disappearance due to biohydrogenation

Geographical, Geological, and Hydrogeological Attributes of Formations in the Footprint of the Eagle Ford Shale

This document provides an overview of the geological characteristics of formations within the footprint of the South Texas Eagle Ford (EF) Shale play, with a particular focus on water. The EF play, spanning approximately 25 counties, has experienced significant development in recent years, with expansion into additional counties to the north. Despite its recent growth, the EF area has a long history of oil and gas exploration and production, with over 110,000 wells drilled in the past century, excluding the approximately 5,000 EF wells as of March 2013. The EF shale serves as a source rock, supplying oil and gas to reservoirs such as the Big Well, Pearsall fields, and the Giddings field. While predominantly rural, the EF area encompasses several large cities such as San Antonio and Laredo, which border its edges. This document focuses on two key aspects of hydraulic fracturing (HF) in the EF play: water use and water disposal. The South Texas location of the play, coupled with its limited surface water resources, intensifies perceived conflicts with other water users. The significant depth of the folded Paleozoic basement beneath the EF (exceeding 15,000 ft) allows for a thick sediment sequence of Jurassic and younger age. Positioned in the middle of this sequence (approximately 4,000 to 11,000 ft deep), the EF shale is separated from the ground surface by numerous formations, including the Midway Clay. This geological setup provides multiple horizons for fluid disposal. The thickness of the EF varies from approximately 100 ft east of Austin to over 500 ft at the Mexican border. The sedimentary sequence above the basement initially comprises carbonate-rich formations such as the Edwards, Glenrose, and Austin Chalk formations, with the EF itself being a carbonate mudrock. Towards the end of the Cretaceous period, the succession transitions to siliciclastic formations characterized by alternating sandstones and claystones deposited in fluvial and/or deltaic environments. Some sand-rich intervals within this succession form freshwater aquifers in the EF footprint, including the Carrizo aquifer, as well as other aquifers of lesser water quality such as the Wilcox and Yegua-Jackson aquifers. Shallow subsurface water tends to be brackish outside of the aquifer outcrop areas. In 2011, water use in the EF play amounted to approximately 24 thousand acre-feet (AF). The top HF users in the EF during that year were Webb (4.6 kAF), Karnes (3.9 kAF), Dimmit (3.7 kAF), and La Salle (2.9 kAF) counties. Although overall water use has increased, water use per well has decreased due to operational changes, including a shift from gas to oil and condensate production and the use of gelled HF treatments instead of slick-water treatments. Currently, operators recycle minimal amounts of flowback/produced water, with brackish water accounting for approximately 20% of total water use. Recycling remains limited due to insufficient flowback volumes for subsequent HF operations, particularly in the early stages. Flowback/produced water is primarily disposed of in injection wells, with approximately 2,500 Class II injection wells active between 2008 and 2012, many of which are associated with waterflood operations rather than disposal. Preferred disposal horizons include formations of the Navarro-Taylor Groups in the Maverick Basin and the Wilcox and Edwards formations.Bureau of Economic Geolog

Refining the Conceptual Model for Flow in the Edwards Aquifer Characterizing the Role of Fractures and Conduits in the Balcones Fault Zone Segment

The south-central section (Figure 1) of the regionally extensive Edwards aquifer is developed in 450- to 900-ft-thick Lower Cretaceous (Albian) platformal carbonates (Hovorka and others, 1996). Original sediments composed of aragonite, calcite, dolomite, and gypsum have been extensively replaced by calcite within the aquifer and are in the process of forming a highly porous and strongly heterogeneous limestone rock. Hydrologically significant heterogeneities within this rock include variable rock fabrics and structural features. Variable rock fabrics include lateral and vertical variation of depositional facies character in response to Cretaceous depositional processes, which has formed beds of varying solubility and mechanical properties. These variable rock fabrics are stacked to form regionally extensive stratigraphic intervals having distinctive rock properties that are mapped as formations and hydrostratigraphic members. Major stratigraphic units referred to in this paper include the Kainer and Person Formations of the San Marcos Platform, Devils River Formation of the San Marcos Platform margin, and West Nueces, McKnight, and Salmon Peak Formations of the Maverick Basin (Figures 1a and 2). Syndepositional karst was developed at the top of and possibly within the Edwards Group on the San Marcos Platform, and this karst has created a zone of high permeability of unknown continuity at the top of the Edwards Formation (Maclay 1995; Hovorka and others, 1998, their figure 29). Regional doming and intrusion of Upper Cretaceous mafic igneous bodies through the Edwards Group in the Uvalde Uplift created additional complexity in this part of the aquifer (Figure 1b). Extensional down-to-the-coast faulting forming the Balcones Fault system overprinted earlier-formed heterogeneity. Faulting had a critical role in aquifer evolution because it (1) increased permeability by forming fracture networks and (2) greatly increased hydrologic gradient by uplift of the base of the Edwards Group to elevations greater than 1,500 ft above sea level in the west part of the aquifer, whereas at the maximum downdip extent of the freshwater aquifer the top Edwards is at 3,400 ft below sea level (Figure 1b).Bureau of Economic Geolog

Impact of Mixed Gas Stream on CO2 Plume Characteristics during and after Carbon Storage Operations in Saline Aquifers

The goal of this short study was to explain the effects of CO2 stream impurities (CH4 and N2) on (1) plume spread, (2) rate and extent of major trapping mechanisms, (3) CO2 storage capacity, and (4) well injectivity. The injection-stream base case consists of a 95% CO2 stream with 2.5% CH4 and N2. We varied the CO2 fraction from 75% to 100% (on a mole basis), defining three bounding cases: CO2BC, CH4BC, and N2BC containing 100% CO2, 75% CO2 and 25% CH4, and 75% CO2 and 25% N2, respectively. In a parametric study of the stream composition, we defined a simple generic reservoir with a uniform permeability of 300 md, a dip of 2°, and porosity of 25%. The model contains 120 300-ft-long cells in the dip direction and also includes four baffles with no permeability parallel to its top and bottom. The gas was injected for 30 years at a depth of about 6,000 ft and at a rate of 26 MMSCFD (equivalent to 0.5 Mt/yr of pure CO2) in a single well located in the downdip section of the model and perforated in the lower third of the 1,000-ft thickness of the injection formation. Temperature is constant at 135°F. Results are numerically monitored for 1,000 yr after start of injection. The modeling was done using CMG-GEM software, and we used a user-defined set of PVT properties. A sensitivity analysis on important model parameters was also done to assess their importance relative to the parametric-study results. The study considers only the two trapping mechanisms (residual saturation and brine dissolution) largely impacted by injection-stream composition. Plume spread, or maximum extent, is a strong function of composition. The maximum extent ranges from 10,350 ft for CO2BC to more than twice the distance for CH4BC (22,250 ft) and N2BC (24,250 ft) and varies approximately linearly for intermediate values. Similarly, time for the plume to reach the top of the formation varies from 14 yr (N2BC) to 18 yr (CH4BC) to 60 yr (CO2BC). The main difference between gas components is solubility in brine—CO2 is approximately 10 times more soluble than CH4 and N2 on a mole basis. The buoyant driving force, expressed as the ratio of gas-brine density difference to gas viscosity, is also approximately four times higher in the CH4BC and N2BC cases, and the ratio keeps increasing because the fraction of CH4 and N2 increases as CO2 dissolves.Bureau of Economic Geolog

Oil & Gas Water Use in Texas: Update to the 2011 Mining Water Use Report

In Spring 2012, we undertook an update of the hydraulic fracturing sections of the TWDB-sponsored report titled “Current and Projected Water Use in the Texas Mining and Oil and Gas Industry” that we published in June 2011 (Nicot et al., 2011). The 2011 report provided estimated county-level water use in the oil and gas industry in 2008 and projections to 2060. This 2012 update was prompted by two main events: (1) a major shift of the oil and gas industry from gas to oil production, displacing production centers across the state and impacting county-level amounts; (2) rapid development of technological advances, resulting in more common reuse and in the ability to use more brackish water. The timely update was enabled by a faster than anticipated development, translating into abundant statistical data sets from which to derive projections, and by an increased willingness of the industry to participate in providing detailed information about water use in its operations. This document follows the same methodology as the 2011 report but differs from it in two ways. Our current update clearly distinguishes between water use and water consumption. The 2011 report does not include reuse from neighboring hydraulic fracturing jobs, recycling from other industry operations or other treatment plants, and use of brackish water. Our update also presents three scenarios: high, low, and most likely water use and consumption with a focus on water consumption. This update has been reviewed by the TWDB and should supersede oil and gas industry projections from the 2011 report.Bureau of Economic Geolog