Assessing natural vs. anthropogenic sources of methane in drinking water aquifers is a critical issue in areas of shale oil and gas production. The objective of this study was to determine controls on methane occurrences in aquifers in the Eagle Ford Shale play footprint. A total of 110 water wells were tested for dissolved light alkanes, isotopes of methane, and major ions, mostly in the eastern section of the play. Multiple aquifers were sampled with approximately 47 samples from the Carrizo-Wilcox Aquifer (250-1200 m depth range) and Queen City-Sparta Aquifer (150-900 m depth range) and 63 samples from other shallow aquifers but mostly from the Catahoula Formation (depth <150 m). Besides three shallow wells with unambiguously microbial methane, only deeper wells show significant dissolved methane (22 samples >1 mg/L, 10 samples >10 mg/L). No dissolved methane samples exhibit thermogenic characteristics that would link them unequivocally to oil and gas sourced from the Eagle Ford Shale. In particular, the well water samples contain very little or no ethane and propane (C1/C2+C3 molar ratio >453), unlike what would be expected in an oil province, but they also display relatively heavier δ13 Cmethane (>-55‰) and δDmethane (>-180‰). Samples from the deeper Carrizo and Queen City aquifers are consistent with microbial methane sourced from syndepositional organic matter mixed with thermogenic methane input, most likely originating from deeper oil reservoirs and migrating through fault zones. Active oxidation of methane pushes δ13 Cmethane and δDmethane toward heavier values, whereas the thermogenic gas component is enriched with methane owing to a long migration path resulting in a higher C1/C2+C3 ratio than in the local reservoirs.
Geochemical interactions between shale and hydraulic fracturing fluid may affect produced-water chemistry and rock properties. It is important to investigate the rock–water reactions to understand the impacts. Eight autoclave experiments reacting Marcellus and Eagle Ford Shale samples with synthetic brines and a friction reducer were conducted for more than 21 days. To better determine mineral dissolution and precipitation at the rock–water interface, the shale samples were ion milled to create extremely smooth surfaces that were characterized before and after the autoclave experiments using scanning electron microscopy (SEM). This method provides an unprecedented level of detail and the ability to directly compare the same mineral particles before and after the reaction experiments. Dissolution area was quantified by tracing and measuring the geometry of newly formed pores. Changes in porosity and permeability were also measured by mercury intrusion capillary pressure (MICP) tests. Aqueous chemistry and SEM observations show that dissolution of calcite, dolomite, and feldspar and pyrite oxidation are the primary mineral reactions that control the concentrations of Ca, Mg, Sr, Mn, K, Si, and SO4 in aqueous solutions. Porosity measured by MICP also increased up to 95%, which would exert significant influence on fluid flow in the matrix along the fractures. Mineral dissolution was enhanced and precipitation was reduced in solutions with higher salinity. The addition of polyacrylamide (a friction reducer) to the reaction solutions had small and mixed effects on mineral reactions, probably by plugging small pores and restricting mineral precipitation. The results suggest that rock–water interactions during hydraulic fracturing likely improve porosity and permeability in the matrix along the fractures by mineral dissolution. The extent of the geochemical reactions is controlled by the salinity of the fluids, with higher salinity enhancing mineral dissolution.
Effective, considerate shale play water management supports operations and protects the environment. A parameter often overlooked is total dissolved solids (TDS) of produced water from the formation. Knowledge of TDS is important to meet these dual goals. Subsurface TDS typically increases with depth. However, produced-water samples from the Eagle Ford Shale show a strong TDS decrease by a factor of ∼10 with increasing well depth (∼200 000 ppm at ∼2.5 km to 18 000 ppm at ∼3.6 km). Water stable isotopes strongly suggest that the low TDS is not due to dilution by meteoric water. Rather, we attribute the change to smectite-to-illite conversion, in which the smectite interlayer water is released into the pore space. Depth, temperature, and other related indicators (source for K, excess silica) support such a mechanism. In addition, water-isotope patterns and 87Sr/86Sr ratios suggest a conversion operating with limited contributions external to the shale. Order-of-magnitude calculations show that the 8% of mixed-layer clay present on average in the Lower Eagle Ford Shale is sufficient to bring formation water TDS to observed levels when some of the resident water is expelled. Understanding that the low salinity is an intrinsic property of the formation water rather than due to short-term mixing allows stakeholders to have a more optimistic outlook on water recycling and on using produced water for other uses (irrigation, municipal).
Abstract Clusters of elevated methane concentrations in aquifers overlying the Barnett Shale play have been the focus of recent national attention as they relate to impacts of hydraulic fracturing. The objective of this study was to assess the spatial extent of high dissolved methane previously observed on the western edge of the play (Parker County) and to evaluate its most likely source. A total of 509 well water samples from 12 counties (14,500 km 2 ) were analyzed for methane, major ions, and carbon isotopes. Most samples were collected from the regional Trinity Aquifer and show only low levels of dissolved methane (85% of 457 unique locations <0.1 mg/L). Methane, when present is primarily thermogenic (δ 13 C 10th and 90th percentiles of −57.54 and −39.00‰ and C1/C2+C3 ratio 10th, 50th, and 90th percentiles of 5, 15, and 42). High methane concentrations (>20 mg/L) are limited to a few spatial clusters. The Parker County cluster area includes historical vertical oil and gas wells producing from relatively shallow formations and recent horizontal wells producing from the Barnett Shale (depth of ∼1500 m). Lack of correlation with distance to Barnett Shale horizontal wells, with distance to conventional wells, and with well density suggests a natural origin of the dissolved methane. Known commercial very shallow gas accumulations (<200 m in places) and historical instances of water wells reaching gas pockets point to the underlying Strawn Group of Paleozoic age as the main natural source of the dissolved gas.
Abstract Understanding the source of dissolved methane in drinking‐water aquifers is critical for assessing potential contributions from hydraulic fracturing in shale plays. Shallow groundwater in the Texas portion of the Haynesville Shale area (13,000 km 2 ) was sampled (70 samples) for methane and other dissolved light alkanes. Most samples were derived from the fresh water bearing Wilcox formations and show little methane except in a localized cluster of 12 water wells (17% of total) in a approximately 30 × 30 km 2 area in Southern Panola County with dissolved methane concentrations less than 10 mg/L. This zone of elevated methane is spatially associated with the termination of an active fault system affecting the entire sedimentary section, including the Haynesville Shale at a depth more than 3.5 km, and with shallow lignite seams of Lower Wilcox age at a depth of 100 to 230 m. The lignite spatial extension overlaps with the cluster. Gas wetness and methane isotope compositions suggest a mixed microbial and thermogenic origin with contribution from lignite beds and from deep thermogenic reservoirs that produce condensate in most of the cluster area. The pathway for methane from the lignite and deeper reservoirs is then provided by the fault system.
