https://cyberleninka.org/article/n/651108.pdf

Application of organic petrography in North American shale petroleum systems: A review

Understanding the transport of hydraulic fracturing (HF) fluid that is injected into the deep subsurface for shale gas extraction is important to ensure that shallow drinking water aquifers are not contaminated. Topographically driven flow, overpressured shale reservoirs, permeable pathways such as faults or leaky wellbores, the increased formation pressure due to HF fluid injection, and the density contrast of the HF fluid to the surrounding brine can encourage upward HF fluid migration. In contrast, the very low shale permeability and capillary imbibition of water into partially saturated shale may sequester much of the HF fluid, and well production will remove HF fluid from the subsurface. We review the literature on important aspects of HF fluid migration. Single-phase flow and transport simulations are performed to quantify how much HF fluid is removed via the wellbore with flowback and produced water, how much reaches overlying aquifers, and how much is permanently sequestered by capillary imbibition, which is treated as a sink term based on a semianalytical, one-dimensional solution for two-phase flow. These simulations include all of the important aspects of HF fluid migration identified in the literature review and are performed in five stages to faithfully represent the typical operation of a hydraulically fractured well. No fracturing fluid reaches the aquifer without a permeable pathway. In the presence of a permeable pathway, 10 times more fracturing fluid reaches the aquifer if well production and capillary imbibition are not included in the model.

Hydraulic fracturing fluid migration in the subsurface: A review and expanded modeling results

https://escholarship.org/content/qt3vk8g0tb/qt3vk8g0tb.pdf?t=pz01yd

Methane clumped isotopes: Progress and potential for a new isotopic tracer

Geochemistry of shale gases from around the world: Composition, origins, isotope reversals and rollovers, and implications for the exploration of shale plays

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 km2 ) 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 km2 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.

Controls on methane occurrences in shallow aquifers overlying the Haynesville Shale gas field, East Texas.

The Haynesville Shale is an organic rich sedimentary rock found in northwestern Louisiana, eastern Texas, and southwestern Arkansas. It was deposited during the Late Jurassic in a marine environment. Average thickness varies from 200 to 300 ft (60–90 m). The Haynesville Shale is typically found at depths of 10,000 ft (3 km) or more and is characterized by ultra low permeability. It is an area of active exploration and development for natural gas especially in northwestern Louisiana. Results from an earlier thermal-mechanical model suggest that Jurassic temperature gradients were more than twice the current regional value of 0.0135 to 0.02°F/ft (25 to 35°C/km). Thus, Jurassic age sediments have been close to their current temperatures for the last 100 m.y. Using subsurface data, a simple model of heat transport by advection and conduction and fluid flow by compaction was used to estimate temperature, maturation, and fluid pressure through time for the Haynesville Shale. High heat flow in the Early Cretaceous contributed to high temperature gradients and early maturation of hydrocarbons. Rapid sedimentation in the Early Cretaceous resulted in generation of significant overpressure within the Haynesville Shale. This overpressure cannot be maintained over geologic time because the unit is too thin and there was subsequent uplift and erosion. Hydrocarbon generation produced additional overpressure in the Late to mid-Cretaceous and the Late Paleogene. However, under most conditions, model overpressures do not exceed the fracture gradient.

Jeffrey A. Nunn

Papers

Burial and Thermal History of the Haynesville Shale: Implications for Overpressure, Gas Generation, and Natural Hydrofracture