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Environmental concerns with unconventional oil and gas development are frequently centered on elevated water usage and the induction of seismic events during waste disposal. Reuse of produced water for subsequent production well stimulation can effectively address these concerns, but the variability among such samples must be well understood. Twenty-four samples of wastewater from unconventional oil and gas development were collected from south and west Texas to assess their variability and feasibility for direct reuse. Bulk metrics were collected, including total organic carbon, total nitrogen, as well as total dissolved and suspended solids. The profiles of pertinent inorganic constituents were also evaluated. Variations were not only seen between regions but also among samples collected from the same region. For example, the average total organic carbon for Eagle Ford samples collected was 700 ± 500 mg/L, while samples collected from the Permian Basin featured an average total organic carbon concentration of 600 ± 900 mg/L. The Permian Basin total organic carbon ranged from 38 to 2600 mg/L. The total dissolved solids levels had the same variability between regions, with an average value for Eagle Ford of 20,000 ± 10,000 mg/L and a Permian Basin value of 150,000 ± 40,000 mg/L. However, samples were more reproducible within a given region. Collectively, the data indicate that the direct reuse of raw produced water for subsequent production well development without treatment is not feasible based on the reported reuse thresholds. Unconventional development wastewater samples from the Permian Basin were also compared to produced water values from conventional oil and gas wells in the same region, as reported by the United States Geological Survey. Samples collected in the Permian Basin consistently demonstrated lower ionic strength compared to conventional produced water data. [ABSTRACT FROM AUTHOR]

The lower Permian of the Midland Basin of West Texas consists of mudrocks with some tight sandstones and carbonate-dominated intervals (Wolfcamp and Spraberry formations) averaging a thickness of 975 m (3200 ft). They have been the target of a large revitalization of oil and gas production from the basin using hydraulic fracturing stimulation and horizontal well technology. Little is known about the aqueous geochemistry of these intervals. We sampled produced formation water from 53 wells across the basin and put them in the context of the basin flow history. Analyzing for major and minor elements and stable water and strontium isotopes, we determined that: (1) TDS values vary from 72 to 135 g/L, decreasing with increasing depth and increasing stratigraphic age; (2) ionic composition is consistent with that of Na–Cl brines found elsewhere in the basin with no major impact of meteoric input or halite dissolution as sometimes seen in the Permian Basin; (3) stable water isotopes (δ18O +5.0 ± 2.0‰ and δ2H −28 ± 5‰ VSMOW) are enriched; slightly radiogenic 87Sr/86Sr ratio is consistent with local carbonates. Interpretative results suggest that the modern resident brines of the low-permeability Lower Permian originated as Permian evaporative brines coeval with Upper Permian thick halite deposition. They would have dolomitized Permian carbonates in their gravity-driven downward migration and been further modified through water-rock interactions, including smectite-illite conversion. • Geochemical profiles: 53 hor. wells organized in 4 clusters representing 8 benches. • TDS from 72 to 135 g/L, decreasing with increasing depth and stratigraphic age. • Na–Cl brines, ∼no meteoric input, no halite dissolution, common processes. • Geochemistry of each bench is different and discriminatory but part of a continuum. • Wolfcamp C and D show strong evidence of illite-smectite conversion. [ABSTRACT FROM AUTHOR]

A side effect of hydraulic fracturing (HF) is the inoculation of the subsurface with surficial microorganisms, many of which could affect production and the chemistry of produced water (PW). There is little knowledge of what organisms are selected for once brought to the subsurface. The current practice to control microbial growth is to include a biocide in the HF fluids. However, biocides add a significant cost to these fluids and has potential consequences to health, safety, and the environment. In this study, we evaluate the microbial community composition of PW and freshwater in the Eagle Ford Shale (EF) to determine what organisms survive in production wells during the HF process. We also assess the effectiveness and necessity of the tri-n-butyl tetradecyl phosphonium chloride (TTPC) biocide for controlling microbial growth in these wells. At greater than 4 km depth, temperatures in EF are >160 °C conditions that do not support viable microbial communities, but at shallower depths, microbial communities may be viable. Freshwater and PW samples were collected and cultured in representative subsurface conditions at 128 °C and 60 °C, in the presence or absence of biocide and measured for their composition and viability using molecular methods and microscopy. Results indicate the presence of a diverse microbial community and these communities contain populations of microorganisms that may have the potential to affect production such as through hydrocarbon degradation and bioclogging. Furthermore, laboratory experiments simulating EF downhole conditions show that cells lose viability due to high temperatures, regardless of biocide. At lower temperatures, >50% of viable cells remain in cultures even with biocide present. Results imply that at depth, introduced cells are sterilized due to temperature while at shallower depths, TTPC may not be completely effective in biomass control, prompting the need to further explore options for microbial control. [ABSTRACT FROM AUTHOR]

Carbon dioxide (CO 2) enhanced oil recovery (EOR) provides a pathway for economic reuse and storage of CO 2 , a greenhouse gas. One challenge with this practice is ensuring CO 2 injection does not result in target reservoir fluids migrating into overlying shallow (<1000 m) groundwater formations. Effective monitoring for leakage from storage formations could involve measuring sensitive chemical indicators in overlying groundwater units and within the producing formation itself for evidence of deviation from an initial state. In this study, produced waters and overlying groundwaters were monitored over a five-year period to evaluate which geochemical signals may be useful to ensure that oilfield produced waters did not impact overlying groundwaters. During this five-year period, a mature carbonate oil reservoir in the Permian Basin transitioned from a waterflooding operation to a water-alternating-gas injection (WAG), in which the formation was flooded with CO 2 and various mixtures of produced water. Significant increases in dissolved inorganic constituents [alkalinity, TDS, Na+, Cl−, SO 4 2− were observed in produced waters following CO 2 injection; however, carbonate reservoir dissolution-precipitation reactions appear to be minimal and injected CO 2 appears to be stored via solubility trapping. Although there are statistically significant geochemical variations following CO 2 injection, applying isometric log-ratios to certain parameters establishes a narrow range for post-CO 2 injection produced waters. This narrow range can be considered a baseline for post-CO 2 injection produced waters; this baseline can be utilized to monitor overlying local groundwaters for produced water intrusion. Additionally, certain parameters [Na+, Ca2+, K+, Cl−, alkalinity, and TDS] display large concentration disparities between produced water and overlying groundwaters; these parameters would be sensitive indicators of produced water intrusion into overlying groundwaters. • Produced waters reflect distinct effects of waterflooding and CO 2 injection. • Significant increases in produced water parameters occur following CO 2 injection. • Injected CO 2 likely stored via solubility trapping; ionic trapping appears minimal. • Produced water geochemistry parameters applied as groundwater monitoring tools. • Produced water intrusion into groundwater was not observed following CO 2 injection. [ABSTRACT FROM AUTHOR]

The lower Eagle Ford Group (LEFG) is one of the most productive continuous hydrocarbon plays in the United States but few associated produced waters data and minimal interpretation have been published. This effort focuses on results from compositional and isotopic data from 39 produced water samples collected from horizontal wells producing from the LEFG in south central Texas. The depth of the LEFG increases by approximately 1 km across the study area, from northwest (2.9 km) to southeast (3.9 km). Associated increases in calculated reservoir temperature (125–165 °C), development of reservoir over-pressuring (400–800 bars total pressure), and increased thermal maturity (heavy oil to gas condensate) also occur along this trend. Produced water salinity starts at nearly 100 g/L in the shallowest samples and decreases linearly with depth to <35 g/L. Comparison of Br/Cl and 87Sr/86Sr data between LEFG produced waters and the Louann salt, suggests that halite recycling is the mechanism generating salinities greater than seawater. Decreasing salinity with depth and thermal maturity in the Gulf Coast Basin have previously been shown to be a result of release of inter-layer water during smectite to illite conversion. The produced water samples show increasing δ18O and decreasing δ2H with depth, which is attributed temperature-dependent isotope fractionation of O and H exchange between seawater and clays and calcite with increasing temperature. Multiple sources of data indicate that the waters in the LEFG are not connate, but rather entered the unit prior to smectite-illite conversion. Presence of allochthonous water in many major tight oil and shale gas plays in the U.S., including the LEFG, suggests there is an unknown mechanism allowing for water flow into low permeability reservoirs. [ABSTRACT FROM AUTHOR]

Managing produced water from oil and gas wells constitutes a significant portion of the costs of operating a well. In this work, we have designed two different centralized water treatment facilities capable of managing produced water from oil and gas wells in Texas and Louisiana, both of which convert the produced water into the following valuable resources: ten-pound brine and fresh water. The two main designs each use commercially available technology with varying levels of establishment in treating produced water. Both treatment processes remove oil and grease and suspended solids, reduce the divalent ion concentrations, and concentrate the brines to a near-saturation state. The baseline design uses chemical precipitation to remove the divalent ions to meet the reuse specifications, whereas the advanced design uses nanofiltration (NF) membranes to separate divalent ions and uses reserve osmosis (RO) membranes to partially concentrate the brine. Both models use mechanical vapor recompression to concentrate the brine up to NaCl saturation. The baseline process is shown to be cost-effective for low-hardness brines. In the case of high hardness, the chemical precipitation step is cost-prohibitive. We find that NF membranes are a promising alternative to chemical precipitation as a means of separating monovalent and divalent ions. Unlabelled Image • Treating produced water can generate valuable products cost-effectively. • Treatment process is viable for high salinity (>30,000 mg/L) brine. • Net revenue is currently dependent on brine salinity and hardness. • Nanofiltration and reverse osmosis membranes are promising treatment methods. • Process is effective in reducing waste volume sent to saltwater disposal wells. [ABSTRACT FROM AUTHOR]