Coal Gas Reservoirs Research Articles

Study on Supercritical Carbon Dioxide Fracturing Coalbed Gas Method

The difference between coal reservoir and conventional natural gas reservoir leads to difficulty for fracturing coal seam, also extremely low permeability in coal seam affects seriously the coalbed gas production. However, supercritical carbon dioxide has unique properties that promote pores and cracks, improve coal seam permeability and replace of CH4 in coal and rock seam. This paper researches on fracturing principle, generational capacity and carrying capacity, anti-reflection effect. At the sametime, based on the problem of change permeability in coal seam, the paper also analyes characteristics of coal reservoir and coalbed gas and combines with properties of supercritical carbon dioxide, which points out the feasibility and necessity that using supercritical carbon dioxide as fracturing carrier in coalbed gas exploitation realizes anti-reflection and increasing production.

PVTX Properties of H2O-CO2-"salt" at PTX Conditions Applicable to Carbon Sequestration in Saline Formations

Among the many scenarios that have been proposed to reduce the amount of carbon dioxide (CO2) emissions to the atmosphere, carbon-capture and storage (CCS) in geological reservoirs represents the method most technologically feasible and capable of accommodating the large amounts of CO2 that are generated on an annual basis by combustion of fossil fuels (IPCC, 2005). Geological environments and processes that have been proposed for CCS include deep, unmineable coal seams, depleted oil and gas reservoirs, organic-rich shale basins, deep saline formations, and mineral carbonation of basalts. Of these various options, the one that is most attractive owing to its widespread distribution and capacity to store large amounts of CO2 is deep saline formations, with the U.S. Department of Energy reporting that saline formations in the United States could potentially store more than 2,100–20,000 billion metric tons of CO2 (DOE, 2012). A recently released assessment of geologic carbon dioxide storage potential (USGS, 2013) estimates a capacity ranging from 2,400 to 3,700 billion metric tonnes (Gt) of CO2, which corresponds to the low end of the DOE estimate. When supercritical CO2 (scCO2) is injected into a saline formation, it may be stored in various ways. Initially, the CO2 will be stored by structural and stratigraphic trapping, whereby scCO2 is trapped beneath an impermeable confining layer that prohibits the upward migration of the more buoyant scCO2. Some scCO2 may also be stored by residual trapping in pores via capillary forces. In the discussion to follow, we include residual trapping with structural/stratigraphic trapping as all of these processes involve the storage of a scCO2 phase and, as such, the volume requirements are assumed to be identical for these storage mechanisms for a given mass of CO2. Over time, …

Optimisation and economical evaluation of infill drilling in CSG reservoirs using a multi-objective genetic algorithm

Water production in the early life of Coal Seam Gas (CSG) recovery makes these reservoirs different from conventional gas reservoirs. Normally, a large amount of water is produced during the early production period, while the gas-rate is negligible. It is essential to drill infill wells in optimum locations to reduce the water production and increase the gas recovery. To optimise infill locations in a CSG reservoir, an integrated framework is developed to couple the reservoir flow simulator (ECLIPSE) and the genetic algorithm (GA) optimisation toolbox of (MATLAB). In this study, the desired objective function is the NPV of the infill drilling. To obtain the economics of the infill drilling project, the objective function is split into two objectives. The first objective is the gas income; the second objective is the cost associated with water production. The optimisation problem is then solved using the multi-objective solver. The economics of the infill drilling program is investigated for a case study constructed based on the available data from the Tiffany unit in San Juan basin when gas price and water treatment cost are variable. Best obtained optimal locations of 20 new wells in the reservoir are attained using this optimisation framework to maximise the profit of this project. The results indicate that when the gas price is less than $2/Mscf, the infill plan, regardless of the cost of water treatment, is not economical and drilling additional wells cannot be economically justified. When the cost of water treatment and disposal increases from $0.01/STB to $4/STB, the optimisation framework intelligently distributes the infill wells across the reservoir in a way that the total water production of infill wells is reduced by 26%. Simulation results also indicate that when water treatment is an expensive operation, lower water production is attained by placing the infill wells in depleted sections of the coal bed, close to the existing wells. When water treatment cost is low, however, infill wells are freely allocated in virgin sections of the coal bed, where both coal gas content and reservoir pressure are high.

Laboratory measurement and modeling of coal permeability with continued methane production: Part 1 – Laboratory results

This paper, first of a two-part series, discusses the results of a laboratory-scale study completed to establish the permeability variation trend with continued production of methane from coal-gas reservoirs. The field condition of uniaxial strain, assumed in the analytical models developed for permeability prediction, was replicated in the study. The results showed that the permeability of coal increases continuously, the rate of increase accelerating at low pressures. The primary reason for the increase appears to be the decrease in horizontal stress resulting from the sorption-induced volumetric strain, the so called “matrix shrinkage” effect. In the second part, experimental data is used to validate the commonly used permeability prediction analytical models and present a modification for one to improve its ability to predict permeability changes.

Interactions of multiple processes during CBM extraction: A critical review

Abstract Coal permeability models are required to define the transient characteristics of permeability evolution in fractured coals during CBM recovery. A broad variety of models have evolved to represent the effects of sorption, swelling and effective stresses on the dynamic evolution of permeability. In this review, we classify the major models into two groups: permeability models under conditions of uniaxial strain and permeability models under conditions of variable stress. The performance of these models is evaluated against analytical solutions for the two extreme cases of either free shrinking/swelling or constant volume. For the case of free shrinking/swelling none of the swelling/shrinking strain contributes to the change in coal permeability because effective stresses do not change. Conversely, for the case of constant volume the full swelling/shrinking strain contributes to the change in coal permeability because the coal is completely constrained from all directions. Therefore, these two solutions represent the lower bound and the upper bound behaviors of permeability evolution, respectively. Review of laboratory observations concludes that although experiments are conducted under conditions of free shrinking/swelling the observed response is closest to that for constant volume condition. Similarly, review of in-situ observations concludes that coal gas reservoirs behave close to the constant volume condition although these observations are made under undefined in-situ stress and constraint conditions anticipated to be intermediate between free swelling and constant volume (i.e. for uniaxial strain). Thus comparison of these laboratory and field observations against the spectrum of models indicates that current models have so far failed to explain the results from stress-controlled shrinking/swelling laboratory tests and have only achieved some limited success in explaining and matching in situ data. Permeability models under uniaxial strain are more appropriate for the overall behavior of coal gas reservoirs under typical in situ conditions while models representing variable stress conditions are more appropriate for behavior examined under typical laboratory conditions. Unlike permeability models under the uniaxial strain condition, models under the constant volume condition are effective-stress based and can be used to recover the important non-linear responses due to the effective stress effects when mechanical influences are rigorously coupled with the gas transport system. Almost all the permeability models are derived for the coal as a porous medium, but used to explain the compound behaviors of coal matrix and fracture. We suggest that the impact of coal matrix-fracture compartment interactions has not yet been understood well and further improvements are necessary.

Characterisation of a microbial community associated with a deep, coal seam methane reservoir in the Gippsland Basin, Australia

There is growing interest in optimising biogenic coal seam methane generation; however, relatively little is known about the microbiology of coal. To begin to address this deficiency, the biodiversity of a microbial community within a deep coal gas reservoir was investigated using the Amplified Ribosomal DNA Restriction Analyses (ARDRA) method. Additionally, a cultured subset of organisms from this community was examined for the ability to produce methane. ARDRA revealed that this community included both bacterial and archaeal lineages. The bacterial community was dominated by proteobacterial and Firmicutes taxa, though one actinobacterial taxa was also detected. This study is the first report of methanogenic archaea in an Australian coal seam gas reservoir. Cultures derived from the microbial community in the groundwater were able to produce methane from yeast extract and H 2 /CO 2 , but did not produce methane from coal. The ecological and physiological implications of these data are discussed.

Laboratory Investigation on the Permeability of Coal During Primary and Enhanced Coalbed Methane Production

Abstract Coalbed Methane (CBM) has grown into an important natural gas resource in North America in recent decades. The economical development of CBM heavily relies on coal permeability. The coal permeability is provided through a network of coal cleats and natural fractures. It is greatly affected by the confining stresses and the coal matrix response during gas adsorption and desorption in primary and enhanced recovery processes. This paper is focused on a laboratory investigation of coal permeability variability with different operating parameters. Core flood experiments in coal have been conducted with methane production and methane displacement by CO2. The permeability to different gases (CH4, CO2) under equilibrium conditions was measured at different confining stresses. The coal permeability to helium, which was reported in previous work, provides a comparison baseline. The permeability of a coal core to gases shows a strong dependence on net confining pressure and exhibits strong hysteresis. The CH4 permeability is relatively smaller than the corresponding He permeability, demonstrating a swelling effect of coal by CH4. The adverse effect of CO2 on coal permeability is also shown. The paper focuses on the experimental results obtained to date. Introduction Coalbed methane (CBM) is an unconventional natural gas resource that is gaining increasing worldwide attention. Successful CBM production depends on two factors: coal gas content and reservoir permeability. Coal gas content means the amount of gas presented in coal, and the reservoir permeability reflects the rate of the gas that could be produced. Unlike conventional gas reservoirs, methane is stored by adsorption onto the subsurface of the coal seams. The ability of coal to store gas is a function of coal rank, reservoir temperature and pressure which is related to coal depth. The primary CBM production is to deplete the reservoir pressure to desorb the methane gas from coal. Using CO2 for enhanced CBM production or using coal beds for CO2 sequestration has also received intense research interest in recent years. CO2 has been proven to have more than twice the affinity to coal than CH4(1). Limited studies have shown the concept of CO2-ECBM to be technically viable. However, the mechanisms have not been fully understood. Permeability of coal is recognized as the most important parameter controlling CBM and ECBM (enhanced CBM) production. Coal cleats are responsible for the permeability of coal. Flow through the cleats is dominated by Darcy flow that relates flow rate to permeability and pressure gradient(2). Methane is the major component of the coalbed gas. Measuring coal permeability tomethane is crucial for evaluating CBM production rate. When injecting CO2 into the coalbeds in ECBM production, the interaction of coal with dense CO2 can be inferred from the permeability changes. Measuring coal permeability to CO2 is the fundamental step to investigate the CO2-ECBM process and the potential of CO2 sequestration. Measuring meaningful coal permeability is more difficult than measuring reservoir rock permeability. Only a limited number of research groups have measured the permeability of coal by core flooding, and have pointed out some of the associated difficulties(3–5).

The role of spatial variability in coal seam parameters on gas outburst behaviour during coal mining

Abstract Gas outburst is recognized as a potentially fatal hazard to be managed during the mining of gassy coal seams. Gas outbursts in Australian coal mines have been associated with the presence of geological structures in the coal and surrounding rocks, having a range of spatial scales from millimetres to metres. The contributing mechanisms are influenced by coal gas reservoir variables including gas composition, fluid pressure, desorption pressure and rate, porosity, intrinsic permeability and relative permeability. They are also influenced by geomechanical variables such as strength, in situ stress and mining-induced stress. The work described here concerns the influence of variability of permeability and strength on outburst behaviour. Key coal properties are characterised for a field site in an operational underground coal mine and then used in a series of hypothetical simulations of outburst initiation. At the field site an array of horizontal holes was cored in-seam. Well tests for permeability and stress were performed in the holes and recovered core was tested in the laboratory for permeability, strength and sorption properties. For permeability and strength sufficient numbers of measurements were obtained to describe these properties statistically assuming that the measurements are uncorrelated spatially. Analysis of the cumulative probability distributions of the field and laboratory permeability data shows a strong size effect that cannot be linearly up-scaled. Using Monte Carlo techniques, these statistical descriptions are used to generate realisations of property values across the model grid used in the simulation analyses. The stochastic model approach demonstrates that the variability of the permeability and strength fields can lead to both outburst and non-outburst outcomes from the same measured input data, depending on the corresponding spatial distribution of permeability and strength at the face. These results suggest the potential application of this approach as a tool for outburst risk analysis and assessment.

99/01130 Improved gas-in-place determination for coal gas reservoirs : Mavor, M. J. et al. Proc. Gas Technol. Symp., 1996, 439–450

99/01130 Improved gas-in-place determination for coal gas reservoirs : Mavor, M. J. et al. Proc. Gas Technol. Symp., 1996, 439–450

Gas-In-Place Determination for Coal Gas Reservoirs: ABSTRACT

Gas-In-Place Determination for Coal Gas Reservoirs: ABSTRACT

Recent Advances in Coal Gas-Well Openhole Well Completion Technology

This paper reviews the current applications of openhole techniques in the San Juan basin. Examples of recent advances and details for the use of the technology are documented in many of the references. The range of reservoir properties required for successful implementation of the technology is included. Hypotheses proposed to explain the success of the openhole wells are presented. The paper concludes with a discussion on future advances required to improve current completion procedures and the potential applicability of the process to other reservoir rock types.

Improved Procedures for Collection and Interpretation of Coal-Gas Reservoir Gas Content and Natural Fracture Geometry Data

The validity of quantitative coal-gas reserve analyses depends upon the accuracy of formation evaluation data used as input parameters for reservoir simulation of fluid productivity. Coal-gas reservoir deliverability is strongly influenced by gas-in-place resources, natural fracture (cleat) permeability, and gas desorption and diffusion characteristics. Estimates of these parameters are predicted upon knowledge of coal core-gas content and cleat geometry. Ironically many accepted procedures for collecting and interpreting these data are still incomplete, and therefore coal-gas reserve analyses commonly are erroneous. Improved procedures for collecting and interpreting gas content and cleat geometry data are highlighted using eight Gas Research Institute Fruitland Formation (Upper Cretaceous) wells in the San Juan basin (Colorado and New Mexico). Fruitland gas content values, in places, have been underestimated by 30-85% (786 SCF ton vs. 122 to 557 SCF/ton, dry, mineral-matter-free basis), and therefore the corresponding gas-in-place resource estimates are commensurably conservative. Gas desorption measurements must be performed at reservoir temperature: dry, mineral-matter-free normalizations and canister headspace corrections must be performed correctly; and gas composition must be periodically quantified to correctly estimate the actual methane reserves and sorption time. Collection of cleat geometry data on whole cores is routinely biased because only the most apparent cleat systemsmore » are analyzed. Detailed macroscopic and X-ray radiograph data on cleat geometry for slabbed polished blocks should be collected as a function of bed thickness, lithology, and interconnectivity to further define core-scale cleat permeability and diffusion coefficient distributions.« less

Sedimentology of Paleochannels on Foreland Coastal Plain, Judith River Formation (Upper Cretaceous), Southeast Alberta: ABSTRACT

The upper 90 m (295 ft) of the sub-Bearpaw Judith River Formation, continuously exposed in the badlands along the Red Deer River 185 km (115 mi) east of Calgary, is famous for the unrivaled assemblage of dinosaur fossils. Dinosaur Provincial Park presents a rare opportunity to view the architecture of a foreland coastal-plain sequence as well as to clarify the origin and distribution of subbituminous coal zones and gas reservoirs associated with this formation across southeast Alberta. The distal reaches of paleodrainage from the developing Cordillera to the Western Interior seaway are being examined by north-south traverses across the badlands. Sharp-based paleochannel units, enclosed by rooted, olive-gray mudstone sequences that are commonly 4-6 m (13-20 ft) thick, vary between 2 end members. The first contains laterally accreted sand-mud couplets with abundant macrofloral debris, and represents cyclical, low-energy growth of point bars, possibly with an estuarine influence. The second, mainly comprising cosets of large trough cross-beds with mudstone intraclasts, was formed by episodic aggradation of high-energy systems. An intermediate composite type displays evidence for an energy increase as channel sinuosity decreased. This variation in paleochannel type is a tributed to alternating alluviation/rejuvenation associated with an unstable base level. Coal zones and potential reservoirs appear to be associated with the transgressive and regressive phases, respectively, of the Bearpaw coast. Amalgamation of paleochannels--marked by laterally extensive horizons of bone fragments, lithic and intraclastic gravel--is more common seaward over the axial region of the Sweetgrass arch. End_of_Article - Last_Page 496------------

Coal Anisotropism and its Relationship to Methane Concentration in Coal: ABSTRACT

Variations of methane concentration in coal appear to correlate well with the optical anisotropic properties of the coal. Some medium- and low-volatile bituminous coal beds in the Appalachian coal basin vary in methane concentration by 5 to 10 times; their optical anisotropy also varies by 2 to 3 times. High-volatile bituminous coals of Appalachian basin tend to contain more methane than bituminous coals of similar rank in the Rocky Mountain region. The Pennsylvanian Appalachian coals are also more anisotropic than the Cretaceous Tertiary Rocky Mountain coals. The technique can thus be used as an exploration tool for potential coal gas reservoirs. End_of_Article - Last_Page 535------------