Microbial methane from subsurface organic-rich units such as coals and shale support approximately 5% of the United States and Canada's energy needs. In the deep subsurface, microbial methane is formed by the metabolism of primarily CO2, H2, and acetate by methanogens. These metabolites are the by-products of multi-step biodegradation of complex organic matter by microbial consortia. This study investigates microbial methane in the Illinois Basin, which is present in organic-rich shallow glacial sediments (surficial), Pennsylvanian coals (up to 600 m depth), and the Upper Devonian New Albany Shale (up to 900 m depth). Findings from the study show that hydrogeochemical conditions are favorable for methanogenesis in each reservoir, with a decrease in groundwater flushing rates corresponding to a decrease in average reservoir depth and an increase in carbon isotopic fractionation. The deeper reservoirs (coals and shale) were paleopasteurized, necessitating re-inoculation by methanogens. The microbes were likely advectively transported from shallow sediments into the coals and shale, where areas of microbial methanogenesis correlate with freshwater recharge. The recharge in the shale was primarily sourced from paleoprecipitation with minor contributions from glacial meltwater during the Pleistocene (4He ages). All areas sampled in the shale were affected by Pleistocene recharge, however groundwater ages in areas of microbial methanogenesis are younger (average 0.33 Ma) than areas with thermogenic methane (average 1.0 Ma). Estimates of in-situ microbial methane production rates for the shale (10-1000 TCF/Ma) are 104-106 times slower than laboratory rates. Only limited biodegradation is observed in the shale. In-situ stimulation of methane production may be most effective if aimed at increasing production of the supporting microbial consortia as well as methanogens. Trace metal concentrations in the shale are below known levels of inhibition or enhancement, with the exception of Fe, suggesting that microbial methanogenesis is not repressed by any of the measured trace metals and may be improved with the addition of Ag, Co, Cr, Ni, and Zn.

Thesis advisor: Paul Strother / The Rogersville Shale of the Middle to Late Cambrian Conasauga Group was deposited on the margins of Laurentia, in what is now eastern Tennessee. Based on 21 thin section samples from the ORNL-Joy2, core five distinct microlithofacies are described, trace fossils characterized, and palynological data interpreted. This investigation concluded that the Rogersville Shale was deposited in a shallow, restricted marine or possibly estuarine environment that would have been exposed to terrestrial runoff. Previous work on the Conasauga Group placed deposition of the Rogersville Shale within an intercratonic basin in approximately 250m of water, perhaps significantly deeper. This investigation found that the Rogersville Shale was likely deposited in a lagoonal setting or restricted estuarine environment that had freshwater input. / Thesis (MS) — Boston College, 2008. / Submitted to: Boston College. Graduate School of Arts and Sciences. / Discipline: Geology and Geophysics.

The Anna Shale (Pennsylvanian) is an organic-rich, marine black shale that commonly overlies the Herrin (No. 6) Coal of the Carbondale Formation, Illinois Basin. Disk-shaped iron sulfide concretions, called pyrite suns, which are commonly up to 10 cm or more across are found in the lowest few centimeters of the Anna Shale in coal mines near Sparta in southwestern Illinois. This area is the only known location where pyrite suns of this size have been found, suggesting that unusual geochemical and/or depositional conditions led to their formation. The primary objective of this study was to evaluate the geochemical conditions at the time of Anna Shale deposition in the area where the pyrite suns formed.

Initial studies to determine the thermodynamic solubility product (Ksp) of gypsum and CaCO3 were conducted. The influence of different electrolyte salts at different concentrations upon the solubility of gypsum and CaCO3 was then tested. Analytical data was utilized in conjunction with a computer to calculate the activity of CaCO3 and gypsum, the ion pair concentration and the solubility product. Indifferent salts increased the solubility of gypsum and CaCO3, and salts with a common ion decreased the solubility of gypsum and CaCO3. Lithium was found to be the dominant monovalent cation present in these marine derived soils. In most cases the lithium concentration was greater than the sodium plus potassium (Na++K+) concentrations. All soils were found to be high in calcium and sulfate and the 1:1 soil water suspensions were saturated with respect to the constituent mineral gypsum. Salt release from Mancos shale is controlled by the parabolic diffusion law. Two diffusion controlled reactions occur: (a) a fast surface reaction and (b) a slow mineral weathering reaction. The fast reaction, accounting for 80-90 percent of the total salt production is due to the dissolution of salt from the surface of the mineral particles and to the dissolution of the fine (<.10 mm) mineral fraction. This reaction occurred in less than 2 minutes. The slow reaction accounting for 10-20 percent of the salt production is due to the dissolution of the larger more resistant mineral fraction, and proceeds for several days. Chemical equilibrium was reached in less than 72 hours for the small natural occurring size fraction (<.10 mm), while 7 to 9 days was required for equilibrium in the larger (>.25 to >1.0 mm) size fractions, respectively. Soil columns were leached with deionized water to allow the calculation of potential to produce 3.15 tons of salt per acre inch, and the salt accounted for 1.89 percent of the soil's total mass.

Unconventional natural gas extraction from the Marcellus Shale requires millions of gallons of water to fracture shale and release natural gas from the formation. This process produces water with high levels of total dissolved solids (TDS); and, efforts to recycle these fluids has stimulated microbial growth in produced water. The objective of this study was to analyze the ionic composition of and characterize microorganisms from Marcellus produced water samples. A semi-synthetic culture medium was designed with high TDS to enrich for halophilic microbes, which yielded robust cultures that were able to grow over a wide range of salinities. DNA extracted from aerobic cultures was used for 16s rDNA clone libraries and Automated Ribosomal Intergenic Spacer Analysis (ARISA). ARISA and 16S gene sequencing revealed differences in bacterial composition between Marcellus and freshwater samples. Sequencing of 16S gene indicated the presence of Halomonas, Thalassospira and other genera related to halophilic and petroleum degrading species. / Bayer School of Natural and Environmental Sciences / Environmental Science and Management (ESM) / MS / Thesis

In 2007, the Barnett Shale in the Fort Worth basin of Texas produced 1.1 trillion cubic feet (Tcf) gas and ranked second in U.S gas production. Despite its importance, controls on Barnett Shale gas well performance are poorly understood. Regional and vertical variations of reservoir properties and their effects on well performances have not been assessed. Therefore, we conducted a study of Barnett Shale stratigraphy, petrophysics, and production, and we integrated these results to clarify the controls on well performance. Barnett Shale ranges from 50 to 1,100 ft thick; we divided the formation into 4 reservoir units that are significant to engineering decisions. All but Reservoir Unit 1 (the lower reservoir unit) are commonly perforated in gas wells. Reservoir Unit 1 appears to be clay-rich shale and ranges from 10 to 80 ft thick. Reservoir Unit 2 is laminated, siliceous mudstone and marly carbonate zone, 20 to 300 ft thick. Reservoir Unit 3 is composed of multiple, stacked, thin (~15-30 ft thick), upward coarsening sequences of brittle carbonate and siliceous units interbedded with ductile shales; thickness ranges from 0 to 500 ft. Reservoir Unit 4, the upper Barnett Shale is composed dominantly of shale interbedded with upward coarsening, laterally persistent, brittle/ductile sequences ranging from 0 to 100 ft thick. Gas production rates vary directly with Barnett Shale thermal maturity and structural setting. For the following five production regions that encompass most of the producing wells, Peak Monthly gas production from horizontal wells decreases as follows: Tier 1 (median production 60 MMcf) to Core Area to Parker County to Tier 2 West to Oil Zone-Montague County (median production 10 MMcf). The Peak Monthly oil production from horizontal wells is in the inverse order of gas production; median Peak Monthly oil production is 3,000 bbl in the Oil Zone-Montague County and zero in Tier 1. Generally, horizontal wells produce approximately twice as much oil and gas as vertical wells.This research clarifies regional variations of reservoir and geologic properties of the Barnett Shale. Result of these studies should assist operators with optimization of development strategies and gas recovery from the Barnett Shale.

This research identifies and analyzes the breadth and depth of the network of non-profit environmental organizations, sportsmen-oriented conservation groups, county conservation districts and state parks that advocate for or against Marcellus Shale drilling within northeastern and southwestern Pennsylvania where drilling occurs. The purpose of this study is to identify where resources are being mobilized and where environmental activities that focus on Marcellus Shale issues are underrepresented in the state. Results show that the counties with a higher number of gas wells do not necessarily have a higher level of environmental advocacy and that a lack of resources is a common barrier to this type of work. Organizations are better connected locally within the northeast. Counties which need to bolster their Marcellus Shale advocacy efforts in the northeast include: Carbon, Pike, Potter, Sullivan, Susquehanna and Wayne; and in the southwest: Beaver, Bedford, Blair, Fayette, Fulton, Greene, Somerset and Washington. / McAnulty College and Graduate School of Liberal Arts; / Graduate Center for Social and Public Policy / MA; / Thesis;

Time-rate analysis and time-rate-pressure analysis methods are available to estimate reserves and study flow performance of wells in unconventional gas reservoirs. However, these tools are often incorrectly used or the analysis can become difficult because of the complex nature of the reservoir system. Conventional methods (e.g., Arps' time-rate relations) are often used incorrectly to estimate reserves from such reservoirs. It was only recently that a serious study was conducted to outline the limitations of these relations and to set guidelines for their correct application. New time-rate relations, particularly the Duong and logistic growth model, were introduced to estimate reserves and forecast production from unconventional reservoirs. These new models are being used with limited understanding of their characteristics and limitations. Moreover, well performance analyses using analytical/semi-analytical solutions (time-rate-pressure) are often complicated from non-uniqueness that arises when estimating well/formation properties. In this work, we present a detailed study of the Duong model and logistic growth model to investigate the behaviors and limitations of these models when analyzing production data from unconventional reservoirs. We consider production data generated from numerical simulation cases and data obtained from unconventional gas reservoirs to study the quality of match to specific flow regimes and compare accuracy of the reserve estimates. We use the power-law exponential model (PLE), which has been shown to model transient, transition and boundary-dominated flow regimes reliably, as a benchmark to study performance of Duong and logistic growth models. Moreover, we use the "continuous EUR" approach to compare these models during reserve estimation. Finally, we develop four new time-rate relations, based on characteristics of the time-rate data on diagnostic plots. Using diagnostic plots we show that the new time-rate relations provide a quality match to the production data across all flow regimes, leading to a reliable reserve estimate. In a preliminary study, we integrated time-rate model parameters with fundamental reservoir properties (i.e., fracture conductivity (Fc) and 30 year EUR (EUR30yr)), by studying 15 numerical simulation cases to yield parametric correlations. We have demonstrated a methodology to integrate time-rate model parameters and reservoir properties. This method avoids the non-uniqueness issues often associated with model-based production data analysis. This study provides theoretical basis for further demonstration of the methodology using field cases.

There is a huge demand in the industry to forecast production in shale gas reservoirs accurately. There are many methods including volumetric, Decline Curve Analysis (DCA), analytical simulation and numerical simulation. Each one of these methods has its advantages and disadvantages, but only the DCA technique can use readily available production data to forecast rapidly and to an extent accurately. The DCA methods in use in the industry such as the Arps method had originally been developed for Boundary dominated flow (BDF) wells but it has been observed in shale reservoirs the predominant flow regime is transient flow. Therefore it was imperative to develop newer models to match and forecast transient flow regimes. The SEDM/SEPD, the Duong model and the Arps with a minimum decline rate are models that have the ability to match and forecast wells with transient flow followed by boundary flow. I have revised the Duong model to forecast better than the original model. I have also observed a certain variation of the Duong model proves to be a robust model for most of the well cases and flow regimes. The modified Duong has been shown to work best compared to other deterministic models in most cases. For grouped datasets the SPED & Duong models forecast accurately while the Modified Arps does a poor job.

Gardiner Dam is located on the South Saskatchewan River approximately 100 km south of Saskatoon, SK. After the start of construction, the River Embankment experienced downstream movement in the shale portion of the foundation. Observed movements are occurring on a well-defined shear plane within the shale layer. This continuing foundation deformation raises concerns regarding the long-term stability of the structure and the effect of continuing deformation on the integrity of the embankment and ancillary works. The mechanism(s) responsible for the ongoing movements are not fully understood. As such, prediction of on-going deformation has had only a limited success. In the work presented in this dissertation, historic geotechnical instrumentation data was used to identify a potential mechanism of movement within the shale foundation. The potential mechanism thus identified can be briefly described as a combination of elastic deformation and consolidation within the shale. As the reservoir level rises, part of the increase in horizontal thrust is transferred to the shale. Since the shale is relatively stiff and has a low hydraulic conductivity, the increase in loading is; therefore, transferred to the porewater, resulting in generation of excess porewater pressures in shale. When the reservoir is high a portion of the excess porewater pressure dissipates. The observed horizontal movement along the shear zone is then developed from elastic deformation and horizontal consolidation of the shale from dissipation of excess porewater pressure. An analytical model was developed from the proposed conceptual model and had general success predicting the horizontal displacement based on the reservoir level and time period. However, the model was sensitive to the reservoir level and several variables within the shale including the hydraulic conductivity and porewater parameter B. Overall, the material variables such as hydraulic conductivity and B can be refined; however, without having an accurate reservoir prediction into the future, the ability for this model to predict the displacement in the foundation will be limited.