Case studies can be instructive in the evaluation of other coalbed methane (CBM) development opportunities. The San Juan basin, located in New Mexico and Colorado in the southwestern U.S. (Figure 1), is the most prolific CBM basin in the world. It produces more than 2.5 Bscf/D from coals of the Cretaceous Fruitland formation, which is estimated to contain 43 to 49 Tscf of CBM in place. For a long time, the Fruitland formation coals were recognized only as a source of gas for adjacent sandstones. In the 1970s, after years of encountering gas kicks in these coals, operators recognized that the coal seams themselves were capable of commercial gas rates. CBM development benefited greatly from drilling and log data compiled from previous wells targeting the deeper sandstones and an extensive pipeline infrastructure that was built to transport conventional gas. These components, along with a U.S. federal tax credit and the development of new technologies such as openhole-cavity completions, fueled a drilling boom that resulted in more than 3,000 producing CBM wells by the end of 1992. The thickest Fruitland coals occur in a northwest/southeast trending belt located in the northeastern third of the basin. Total coal thickness in this belt locally exceeds 100 ft and individual coal seams can be more than 30 ft thick. The coals originated in peat swamps located landward (southwest) of northwest/southeast trending shoreline sandstones of the underlying Pictured Cliffs formation. The location of the thickest coals (Figure 1) coincides with the occurrence of overpressuring, high gas content, high coal rank, and high permeabilities in the San Juan fairway ("fairway"). The overpressuring is artesian in origin and is caused by water recharge of the coals through outcrops along the northern margin of the basin. This generates high vertical pressure gradients, ranging from 0.44 to 0.63 psi/ft, which allow a large amount of gas to be sorbed to the coal. Coal gas in the San Juan basin can contain up to 9.4% CO2 and 13.5% C2 . Chemical analyses suggest that thermogenic gases have been augmented by migrated thermogenic and secondary biogenic gas sources, resulting in gas contents ranging up to 700 ft 3 /ton. Coal rank in the fairway ranges from medium- to low-volatile bituminous and roughly coincides with those portions of the basin that were most deeply buried. Coals in the fairway typically have low ash and high vitrinite contents, resulting in large gas storage capacities and excellent permeabilities of 10 md from well-developed cleat systems.
This article discusses the geology, depositional setting, and hydrogeology of promising CBM areas, along with a discussion of data sources that can help in evaluation of prospects. Foreland basins are flexural troughs that form in front of rising mountain belts. These basins, which include the Black Warrior and San Juan basins of the U.S., have provided more than 90% of the world's coal gas production to date. Cratonic basins such as the Williston basin, which straddles the U.S./Canadian border, are simple structural depressions that favor the deposition of widespread, continuous coal seams. Intermontane basins, which are common in the Appalachian Mountains of the eastern U.S., form within mountain belts and often are structurally complex, resulting in a more heterogeneous coal distribution.
Relative permeability curves in coalbed methane reservoirs (CBM), acquired by analysis of production data, can differ from laboratory-measured curves due to complications such as stress-desorption dependent permeability and cross-formational flow. This paper aims to derive relative permeability curves for coalbed methane reservoirs using production data analysis, as well as discuss curve characteristics and shapes. Field examples from the San Juan Basin in the US and the Qinshui and Ordos Basins in China are presented to provide a worldwide view of relative permeability curve shapes. These field examples are analysed using a tank type model, a common production data analysis tool, and the influential factors on curve shapes are discussed. The results and analysis indicate that permeability enhancement during the life of the well, and cross-formational flow between the coal seam and adjacent formations, can strongly control curve shapes. These effects, when not detected, can result in irregular relative permeability curve shapes obtained by analysis of production data. Direct measurement of permeability enhancement requires time-lapse production tests while investigation of cross-formational flow of water into coal seams requires hydraulic connectivity assessment, which are time consuming and expensive to conduct. The signatures of relative permeability curves presented in this study allow indirect determination of permeability enhancement and cross-formational flow in coal seam gas reservoirs.
Chen, Zhiming (State Key Laboratory of Petroleum Resources and Prospecting in China University of Petroleum, Beijing, and University of Texas at Austin) | Liao, Xinwei (State Key Laboratory of Petroleum Resources and Prospecting in China University of Petroleum, Beijing) | Zhao, Xiaoliang (State Key Laboratory of Petroleum Resources and Prospecting in China University of Petroleum, Beijing)
Forecasting coalbed-methane well performance in the Qinshui Basin is a key task for predicting future gas production, There is evidence suggesting that complex fracture geometry and multiple hydraulic-fracture networks might develop. Unfortunately, very limited work has been published on the production analysis of multiple-fractured vertical wells (MFVWs) in coalbed-methane reservoirs. To better understand the production performance of the MFVWs, a new, fast, and reliable methodology is presented in this paper. This semianalytical methodology is derived from an analytical reservoir solution and a numerical fracture solution. Dual-porosity, gas-diffusion, gas-adsorption, and stress-sensitivity effects are considered. Verification of the methodology is accomplished through comparison with synthetic-reservoir-simulation cases and with field-performance data. Good agreement is shown between results from the proposed methodology and those from a reservoir-simulation model. Results from this study indicate increasing transient-gas-production rate and cumulative gas recovery with increasing natural-fracture permeability, gas-storage coefficient, Langmuir volume, fracture conductivity, and fracture length. The transient gas-production rate and cumulative gas recovery were found to decrease with increasing stress-sensitivity coefficient. The parameters found to have the strongest and weakest effects on the gas-production rate were the nature-fracture permeability and the fracture conductivity, respectively. Results from this study on MFVWs in coalbed-methane reservoirs indicate fracture length is more important than fracture conductivity in terms of its effect on gas productivity.
ABSTRACT: Most cases of floor failure are ignored by operators because it causes very little damage or disruption to mining operations. However, in rare cases, floor failure is excessive enough to cause ventilation, rib stability and safety concerns. In July 2016, a longwall mine in southwestern Virginia mining in the Pocahontas Number 3 seam completed the longwall recovery in Panel 25. After the recovery was complete and mining resumed in Panel 26, slight floor heave of one or two inches was observed in the mains entries 7 and 8 just north of the Panel 25 recovery area. After the longwall recovery in Panel 26 in January 2017, the floor heave was reactivated and increased up to as much as 1.2 meters (4 feet) in isolated locations and spread to disturb entries 4 through 8 that caused significant damage to stoppings and overcasts in isolated areas. The floor heave increased by as much as 0.6 centimeters (0.23 inches) in 2 days. Rib dilation was measured to be as much as 0.5 centimeters (0.21 inches) per day. The Mine requested NIOSH researchers’ assistance to understand the mechanisms behind the significant floor heave and the elevated stresses that are associated with full extraction mining. NIOSH and mine personnel discovered that overburden thickness in excess of 609.6 meters (2000 feet), 0.6 to 1.8 meters (2 to 6 feet) of water sensitive fireclay in the floor and massive sandstones in the roof, horizontal stress orientation and bottom of coal elevations were all contributing factors to the floor heave. This paper covers the geological exploration, in-mine measurements, observations and the resulting forecast mapping that explain why the significant floor heave occurred and best practices on how to mitigate future floor heave to enhance safety and production.
Floor failure (heave) occurs when high stresses exceed the bearing capacity of the floor strata. Usually the effects of floor heave are time dependent with exposure to moisture hydrating shrink-swell clays such as kaolinite and vermiculite from ancient soil horizons immediately below the coal deposit. In most cases two types of floor failure can occur that have very different outcomes in safety and production. The first type of floor heave occurs when a pillar is driven into soft floor and the soft floor (usually clay) exhibits a plastic flow that displaces the rock upwards around the pillar into the mined entry and is referred to as pillar punching.
ABSTRACT: Shale rocks play an essential role in petroleum exploration and production. They can occur either as caprocks for subsurface storage in conventional reservoirs or as unconventional reservoir rocks for hydrocarbon extraction via hydraulic fracturing. The utilization of a shale rock depending on its ability to immobilize fluids: caprocks requires a low permeability and resilience to the in-situ formation of fractures; on the contrary, unconventional reservoir rocks need a significant increase of permeability by engineering hydraulic fracturing. The mechanical properties of the rock are the key factor that determines the likelihood of fracture initiating and propagating. This paper used two types of shale rock as representatives of a shale cap rock (Pottsville shale) and a source rock (Marcellus shale), to relate the mechanical properties and differences in their mineralogical composition and microstructures.
Indentation tests were conducted at both micro and nanometer level on drilled rock core samples to get the mechanical properties of bulk and individual phases of these multiphase materials. Results from micro-indentation showed Pottsville shale sample had overall higher bulk mechanical properties. The difference in mechanical properties is the result of the alteration in microstructures and mineralogical composition. The mechanical properties map created from nano indentation results showed the distribution of each single phase based on differential mechanical properties. This indicated higher hard grain content in Pottsville over Marcellus shale. This paper showed the utilization of nano-indentation to provide a direct link between geochemistry and geomechanics of shale rocks. Through mechanical properties mapping, individual phase properties can be correlated with the bulk response of the rock and the volumetric proportions of each phase can be estimated. The maps could be also useful for modeling the rock behavior to predict the fracture occurrence potential, as it linked the microstructural features with their mechanical properties.
Shale rocks play an essential role in petroleum exploration and production. Shale rocks can occur either as unconventional reservoir rocks for hydrocarbon extraction via hydraulic fracturing or as caprocks for conventional reservoirs and subsurface gas/ waste storage. In general, shale formations which permeability can be significantly enhanced by the formation of hydraulic fractures can be the target for hydrocarbon extraction. Shale rocks that exhibit low permeability and resilient to the formation of fractures are ideal for underground storage (CO2 sequestration, waste disposals). The ability to produce gas from rocks previously considered caprocks is an unprecedented and innovative feat, resulting in an over-supply of natural gas to the North American market in recent years (Clarkson, 2016). On the other hand, carbon capture and storage (CCS) is, by far, the only technology which can reduce emissions on a significant scale from fossil fuel power plants and industrial sources (Global CCS Institute, 2015).
ABSTRACT: Shale cap rocks are nature’s best hydraulic barrier geomaterials. They are effective seals for underground hydrocarbon bearing formations as well as CO2 storage formations in carbon capture and storage (CCS) projects. The sealing properties of shale rocks are directly related to its minerals and the internal arrangement of clay and non-clay minerals. This is known as the microstructure. Since shales are predominantly composed of clay minerals, the type and amount of clay minerals contained within the rock are the key factors of its sealing properties. The goal of this study is to gain a better understanding of how different types of clays behave in a typical CO2 storage reservoir condition.
Clay minerals have layered structures which often carry negative surface charges. The combination of large reactive surface areas and charge bring complexity in terms of their reactivity to fluids. Therefore, even the same type of clays can have different properties depending on their depositional environment, which was influenced by different fluid properties (pH, T, P, salinity). The same is also true of the exposure of clay-rich rocks to reactive fluids during geologic times as well as under subsurface engineering conditions (nuclear waste storage, injection of waste water and fracking fluids in oil&gas, and carbon sequestration). For this study, artificial shale rock samples were designed using purified natural minerals in different ratios. These samples allowed us to observe the impact of the mineralogical composition on mechanical properties and obtain a systematically quantified comparison between samples. Indentation tests were conducted to evaluate changes in mechanical properties as a result of composition alteration, while Scanning Electron Microscopy (SEM) was used to probe any changes to microstructures. Observations in this study indicate: a) high clay content shale formation has better sealing properties because its mechanically more stable and has lower permeability due to the low porosity; b) increasing the salinity of pore fluid can decrease the thickness of double layers of clays, causing an increase in permeability because of the increase of effective porosity. Salinity has an additional weaker effect on the mechanical properties because as the sample dries, salt crystallized within the sample and creates an internal expansion force resulting in integrity failure.
Caprocks are essentially defined as low permeability formations, and sometimes, but not necessarily, with low porosity. More than 60% of effective seals for geologic hydrocarbon bearing formations which act as natural hydraulic barriers constitute shale caprocks (Allen and Allen, J.R., 2005). The effectiveness of cap rock depends on its ability to immobilize fluids, which include a low permeability and resilience to the in-situ formation of fractures as a result of the pressurized injection. The alteration in sealing properties of shale rocks is directly related to the differences in its mineralogical composition and microstructure.
Viswanathan, H. S. (Los Alamos National Laboratory) | Carey, J. W. (Los Alamos National Laboratory) | Karra, S. (Los Alamos National Laboratory) | Porter, M. L. (Los Alamos National Laboratory) | Rougier, E. (Los Alamos National Laboratory) | Currier, R. P. (Los Alamos National Laboratory) | Kang, Q. (Los Alamos National Laboratory) | Zhou, L. (Los Alamos National Laboratory) | Jimenez, J. (Los Alamos National Laboratory) | Makendonska, N. (Los Alamos National Laboratory) | Chen, L. (Los Alamos National Laboratory) | Hyman, J. D. (Los Alamos National Laboratory)
Shale gas is an unconventional fossil energy resource that is already having a profound impact on US energy independence and is projected to last for at least 100 years. Production of methane and other hydrocarbons from low permeability shale involves hydrofracturing of rock, establishing fracture connectivity, and multiphase fluid-flow and reaction processes all of which are poorly understood. The result is inefficient extraction with many environmental concerns. This work uses innovative high-pressure microfluidic and triaxial core flood experiments on shale to explore fracture-permeability relations and the extraction of hydrocarbon. These data are integrated with simulations including lattice Boltzmann modeling of pore-scale processes, finiteelement/ discrete element models of fracture development in the near-well environment, and discrete-fracture network modeling of the reservoir. The ultimate goal is to make the necessary measurements to develop models that can be used to determine the reservoir operating conditions necessary to gain a degree of control over fracture generation and fluid flow.
Shale gas is an unconventional fossil energy resource that is already having a profound impact on US energy sector, with reserves projected to last for nearly 100 years . The increased availability of shale gas (i.e., methane), which produces 50% less CO2 than coal, is primarily responsible for US emissions in 2011 dropping to their lowest levels in 20 years . Production of methane and other hydrocarbons from low permeability shale involves hydrofracturing of rock, establishing fracture connectivity, and multiphase fluid-flow and reaction processes, all of which are poorly understood. The result is inefficient extraction with many environmental concerns [3,4]. Industry is motivated to reduce the 70 to 140 billion gallon per year water demand because there are droughts in the west, a lack of deep injection wells in the east, and possible forthcoming regulations . Our goal is to use unique Los Alamos National Laboratory (LANL) microfluidic and triaxial core flood experiments integrated with stateof- the-art numerical simulation to reveal the fundamental dynamics of fracture-fluid interactions to transform fracking from an ad hoc tool to a safe and predictable approach based on solid scientific understanding. The goal is to develop CO2-based fracturing fluids and fracturing techniques to enhance production, reduce waste-water, while simultaneously sequestering CO2 .
Most sedimentary rock formations (tight or highly porous) have geochemical characteristics that can lead to significant reactive ion exchange processes in aqueous media in the presence of carbondioxide. While geomechanical properties such as rock stiffness, Poisson’s ratio and fracture geometry largely govern fluid flow characteristics in deep fractured formations, the effect of mineralization can lead to flow impedance in the presence of favorable geochemical and thermodynamic conditions. Shale caprock which seals more than 60% of oil and gas reservoirs have natural fractures that are unevenly distributed in the geosystem. Experimental works which employed the use of analytical techniques such ICP-OES, XRD, and SEM/EDS techniques in investigating diagenetic and micro-structural property of crushed shale caprock/CO2-brine system concluded that net precipitation reaction processes can affect the distribution of petrophysical nanopores in the seal rock. The results showed that geochemical precipitates can be formed such that fluid flow through open micro and macro fractures may be constrained. Simulation results reported by various researchers suggested that influx-induced mineral dissolution/precipitation reactions within shale caprocks can continuously close micro-fracture networks, while pressure and effective-stress transformation first rapidly expand then progressively constrict them. This experimental research investigates the impact of in-situ geochemical precipitation on conductivity of open micro-fractures under geomechanical stress conditions. Fracture conductivity in core samples of shale caprock with known mineralogical composition from different formations where CO2 injection is on-going are quantitatively evaluated under axial and radial stress using pressure pulse-decay liquid permeametry/core flooding systems. Modeling of the diffusion controlled fluid flow and induced fracture diagenetic alterations in the shale caprocks can be performed using CMG-GEM with artificial core imposing axial and radial geomechanical stress. The possibility of rock-fluid geochemical interactions constricting natural fracture conductivity in long term subsurface CO2 sequestration can lead to significant improvement in shale caprock seal integrity and mitigate injection induced geomechanical perturbation.
Key words: fracture diagenesis, conductivity loss, aqueous carbondioxide, shale geochemistry, geomechanics.
Coalbed methane reservoirs of the Black Warrior Basin in Alabama are highly prolific, having produced more than 69 x 109 m3 of gas and 254 x 106 m3 of water since 1980. These reservoirs have long been thought to contain a mixture of thermogenic and late-stage biogenic gases, but relatively little is known about geochemical dynamics of coalbed methane generation in the Black Warrior basin. Sampling and geochemical analysis of water and gas from these reservoirs provides crucial insight into the mechanisms of coalbed gas generation and how to prospect for areas where significant resources may lie hidden.
Thermogenic gas was generated principally during the Alleghanian orogeny, when Pennsylvanian coal-bearing strata approached maximum burial depth. During Mesozoic-Cenozoic unroofing, a meteoric recharge system developed along the southeast basin margin, which fed fresh water directly into the metallurgical coal, thus setting the stage for late-stage bacterial methanogenesis. Microbial CO2 reduction is the dominant metabolic pathway for late-stage methanogenesis in Black Warrior coalbed methane reservoirs, and the produced gases become progressively depleted in 13C as coal rank decreases away from the basin margin. Much of the microbial gas lies in a part of the Black Warrior basin that was overlooked by early exploration efforts, which focused on coal thickness, thermal maturity, and absolute gas content. Integrated analysis of subsurface geochemical systems that also consider gas saturation, gas mobility, and basin hydrodynamics can help unlock new reserve areas in mature exploration provinces and can help identify attractive prospects for unconventional gas development in frontier areas that may not otherwise be obvious.