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Location of the San Juan Basin relative to the Western Interior seaway. Modified from Palmer and Scott (1984), after Williams and Stelck (1975) and Irving (1979).
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The Fruitland Formation [Upper Cretaceous) in the San Juan Basin, although an "unconventional" source of natural gas, surpasses many conventional reservoirs in production, reserves, and original resources. Production and reserve values confirm the San Juan Basin as the world's leading producer of coalbed gas, and they establish the Fruitland fairwa...
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Citations
... San Juan Fruitland formation is the world-leading producer of CBM that surpasses lots of conventional reservoirs in production and reserve values. Particularly, Fairway wells have the most extended production history and remarkably high production rates being produced for more than 20 years [47,48]. Now, they are at their mature stage of pressure depletion, and production becomes challenging for these wells at extremely low reservoir pressures (<100 psi) [45]. ...
... Table 2 lists the reservoir parameters determined from the integration of high-resolution gamma-ray log and density log, and well log header. Based on the interpretation of wireline logs, the investigated wells are located in the regionally overpressured area characterized by pressure gradients of 0.44 to 0.48 psi/ft with reservoir pressure exceeding 1500 psi, consistent with previously reported ranges [47]. ...
... The absolute and relative permeability of cleats controls Darcy flow, and these rock properties serve as calibration parameters throughout history matching. This is because they are the least welldefined reservoir properties in the literature, and these simulated permeability values should fall into the reported ranges documented in Ayer's work [47] for the San Juan Fairway region. By incorporating the matrix strain model into the analytical permeability model, the growth of absolute permeability during pressure depletion is predicted by Palmer and Mansoori (P-M) model [75]: ...
Exploitation of coalbed methane (CBM) acts as a synergy between increased natural gas demand and reduced greenhouse gas emissions to the atmosphere. However, substantial CBM resources lie undeveloped because of unfavorable economic conditions. Accurate forecast of production based on a thorough understanding of physical mechanisms is the key to increase and sustain CBM recovery. CBM production involves complex multi-scale phenomena ranging from desorption and diffusion in nanoporous matrix at molecular level to Darcy flow of free gas in cleats at macroscopic level. Current computational modeling built on fracture flow and neglecting multi-scale coupled flow phenomena underestimates long-term production performance. In fact, experimental evidence indicated that matrix experienced a much greater increase in gas deliverability than cleats. In this work, apparent matrix permeability was derived to characterize diffusion rate and directly coupled into current modeling to decipher matrix deliverability and multi-scale flow. The proposed modeling workflow was applied to two field cases in San Juan Fairway with long production history of over 20 years, which assembled adequate forecast to field data. Besides, sensitivity analysis suggested that simulations neglecting matrix flow and solely updating fracture flow were prone to elevated prediction errors for long-term production when diffusive mass flux took the predominant role in overall gas transport. The multi-scale CBM model is convenient for elucidating complex gas transport physics in coal. The outcome of this work implies that a proper diffusion enhancement method can improve overall production rate and elongate total productive lifetime of CBM fields.
... In the southern and western margins of the San Juan Basin Fruitland, the coal rank is subbituminous B to high-volatile A bituminous. It increases to low-volatile bituminous in the north-central part of the basin [26,27]. Mannville coals are composed of inertinite varied from 35.8-51.0%, ...
The changes in the permeability of coal-bed reservoirs with methane, as associated with gas depletion, are the consequence of two opposing processes, namely geomechanical compaction that narrows down fractures, and matrix shrinkage, which, in turn, widens fractures. Many previous studies on the effects of these processes have emphasised, albeit not always, the circumstances and conditions that led to a greater coal permeability, with a natural decrease in the pore pressure of methane during its production, and, in consequence, to an increase in the cumulative volume of this gas. However, in some coal basins, there are beds where the methane production has failed to reach the appropriate level, whether in economic or engineering terms. This paper identifies some reasons for the failed attempts at well exploration of gas from such coal beds. Specifically, it describes seven parameters to be considered in relation to CBM, including geomechanical parameters such as Young’s modulus, Poisson’s ratio, and the initial porosity, which define coal cleat compressibility, a very important parameter, and parameters related to methane desorption, i.e., desorption-induced volumetric strain, the Langmuir pressure, and the initial pressure of gas within the bed. In addition to cleat compressibility, there are other, equally important parameters, such as the rebound pressure and recovery pressure, which are defined by the following parameters in order of importance: Young’s modulus, desorption-induced volumetric strain, initial pressure of methane, the Langmuir pressure, and Poisson’s ratio. To assess the impact of these parameters on changes in permeability, we used the Cui-Bastin model. The simulation results were analysed to allow us to present our findings.
... Coalbed permeability is very sensitive to overburden and directed tectonic stress. Fruitland coalbed permeability in the producing regions of the San Juan basin is generally 5-60 md, and it is greatest in the fairway area (Ayers, 2003). The gas content of Fruitland coals is generally 150 scf/ton less in the southern two-thirds of the San Juan basin. ...
... The Fruitland formation is abnormally pressured relative to a freshwater hydrostatic gradient (0.433 psi/ft). Most wells in the Fruitland formation are completed with cased holes and fracture stimulation (Ayers, 2003). ...
... Table 4 presents the history matching results. The estimated parameters are within the range for Fruitland formations (Ayers, 2003). These parameters were then used to predict the future performance of the well for an additional 40 years. ...
... The Late Cretaceous Kirtland Formation of the San Juan Basin, New Mexico and Colorado (Fig. 1A), is a regional aquitard and reservoir seal (Ayers, 2003). It was deposited by streams fl owing toward the retreating shoreline of the Western Interior Seaway in an alluvial plain with fl oodplain and channel depositional environments, which were landward of the swampy environments of the underlying Fruitland Formation (Fig. 1B;Fassett and Hinds, 1971;Fassett , 2009). ...
... The Kirtland For-mation is divided into upper and lower shale (i.e., mudstone rich) members and a middle sandstone-rich member, the Farmington Sandstone (Bauer, 1917;Fassett and Hinds, 1971;Stone et al., 1983;Molenaar and Baird, 1992). Throughout most of the basin the Kirtland Formation conformably overlies the coal-bearing Fruitland Formation (Fassett and Hinds, 1971), which contains the world's most prolifi c coalbed methane play (Ayers, 2003). ...
Mudstone pore networks are strong modifiers of sedimentary basin fluid dynamics and have a critical role in the distribution of hydrocarbons and containment of injected fluids. Using core samples from continental and marine mudstones, we investigate properties of pore types and networks from a variety of geologic environments, together with estimates of capillary breakthrough pressures by mercury intrusion porosimetry. Analysis and interpretation of quantitative and qualitative three-dimensional (3D) observations, obtained by dual focused ion beam-scanning electron microscopy, suggest seven dominant mudstone pore types distinguished by geometry and connectivity. A dominant planar pore type occurs in all investigated mudstones and generally has high coordination numbers (i.e., number of neighboring connected pores). Connected networks of pores of this type contribute to high mercury capillary pressures due to small pore throats at the junctions of connected pores and likely control most matrix transport in these mudstones. Other pore types are related to authigenic (e. g., replacement or pore-lining precipitation) clay minerals and pyrite nodules; pores in clay packets adjacent to larger, more competent clastic grains; pores in organic phases; and stylolitic and micro-fracture-related pores. Pores within regions of authigenic clay minerals often form small isolated networks (< 3 mu m). Pores in stringers of organic phases occur as tubular pores or slit- and/or sheet-like pores. These form short, connected lengths in 3D reconstructions, but appear to form networks no larger than a few microns in size. Sealing efficiency of the studied mudstones increases with greater distal depositional environments and greater maximum depth of burial.
... Drilling of the injection well provided the opportunity to core and study the Kirtland Formation. The Kirtland Formation conformably overlies the Fruitland Formation and is considered a regional aquitard and reservoir seal [26]. The purpose of studying the Kirtland Formation is threefold. ...
Natural helium is a screening tool for identifying the presence or absence of caprock imperfections. Imperfections can be manifested as a variety of features or processes, including insufficiently low permeability, preferential flowpaths such as fractures and faults, and the propensity for capillary breakthrough. Theory and simulations detail how various types of imperfections affect the spatial distribution of natural helium above, within, and below caprock in a single-phase, brine-saturated system. Specifically, the distribution of natural helium can reveal the presence of preferential flowpaths through formations with low matrix permeability. The distribution patterns of helium shed insight on the size, shape, location, and connectedness of imperfections in caprock. We show how imperfections associated with characteristic distributions of natural helium will affect the retention of CO2. We discuss the advantages of natural helium, together with temperature distributions, for revealing imperfections and the optimum locations for sampling the natural tracers. This research is being carried out to support design and interpretation of ongoing field-testing by the Southwest Regional Partnership on Carbon Sequestration. Specifically, we are evaluating seal integrity of the Partnership’s Pump Canyon Enhanced Coalbed Methane- CO2 Storage Demonstration, located in the San Juan Basin, New Mexico. The caprock at this site is the Kirtland Formation. This formation is composed of a variety of continental deposits (sandstones, siltstones, mudrocks, and shales) and is ideal for investigating the capability of helium to characterize sealing integrity of a very heterogeneous caprock. We present results of analyses of noble gases and a variety of petrological and petrophysical analyses on core through this caprock. These results are used to investigate the presence of imperfections and their potential impact on CO2 migration and the overall viability of utilizing natural helium as a screening tool. The authors gratefully acknowledge the U.S. Department of Energy and the National Energy Technology Laboratory for sponsoring this project.
... Fassett (1991) notes that coalbed methane production from the Fruitland coals began in the mid-1970s. Fruitland production is partitioned into four type-producing areas (Meek and Levine, 2006) and the pilot site is located in what was originally an over pressured area referred to as the High Rate Fairway, a giant unconventional methane gas play (Ayers, 2003). The High Rate Fairway lies in the north central part of the basin and wells in the fairway originally produced with flow rates greater than 10 MMCF per day. ...
In this study we analyze data on fractures and possible faults in the surface, primary seal and cover strata to evaluate site integrity and the viability of long term CO 2 retention for the Southwest Regional Partnership on Carbon Sequestration's San Juan Basin Fruitland Coal pilot test. The project is funded by the U.S. Department of Energy and is managed by the National Energy Technology Laboratory. Near-surface shear wave anisotropy and drilling induced breakouts support the interpretation that retained tectonic stress anisotropy influences the development of near-surface fracture systems. Shear wave anisotropy in the vicinity of the borehole is characterized by an average fast-shear direction of N36E along the length of the borehole. Drilling induced breakout trends are tightly clustered with mean orientation of N57W. Open fractures observed in general have random distribution. Aperture distribution is significantly log normal. Attribute analysis of 3D seismic reveals the presence of narrow field scale zones of discontinuity in time slice view that have pronounced NE trending mode. Additional post-stack processing reveals discontinuities in profile view that are interpreted as minor faults and fracture zones. The results of the analysis suggest that fractures, fracture zones and possible faults may disrupt the reservoir and primary sealing strata. Interpreted faults and fracture zones have limited vertical extent and major penetrative faults are not observed in the 3D seismic interpretations. The results provide the basis for developing discrete fracture Wilson et al – draft 03/05/10 1 networks for use in flow simulation to evaluate the potential for significant long term leakage through the sealing strata.
The objective of this study was to develop tools to analyze the production profile of unconventional gas reservoirs where adsorption is a dominant storage mechanism. Specifically, the research is focused on analyzing the conditions that affect the time needed to achieve peak gas production rate. To this end, we have successfully derived the analytical expressions for the reservoir pressures at which peak gas production occurs under various operating scenarios.
The methodology involves the development of a system of generalized two-phase material balance equations for boundary dominated flow in unconventional gas reservoirs where adsorption is a dominant storage mechanism. The resulting analytical ODEs are then solved numerically (Runge-Kutta) which yields a semi-analytical solution for pressure and saturation versus time. Once the pressure and saturations are determined numerically, gas and water production rates, along with their derivatives, are determined analytically and used to analyze the production profiles. Through the analytical derivatives, reservoir and fluid parameters can be modified to observe their effects on the time to peak gas rate.
In this study, three different well specifications were investigated (constant flowing well pressure, constant well drawdown, and constant water production rate) with only two of the three well specifications resulting in a peak gas production rate - no peak gas production rate was observed for the water rate specified wells. Furthermore, the developed semi-analytical model, under appropriate conditions, gives results comparable to numerical reservoir simulator. The paper will discuss conditions at which the material balance results are comparable to full reservoir simulation.
Through this research, a new material balance method has been developed that can be presented in different domains (pressure, time, and cumulative produced fluids domains). Also, the novel use of derivatives from the generalized material balance equations was applied in this research to analytically and graphically analyze the production profile. Furthermore, in addition to the peak gas production rate, additional inflection points were observed that have not been reported in the current literature.
Coalbed methane is now large-scalely explorated and exploitated in the world. The Changzhi coalbed methane block, south-central Qinshui Basin, is a new resource target zone for coalbed methane exploration and exploitation in China. However, the gas content distribution of this block and its influential factors have not yet studied. Based on the recent coalbed methane exploration and exploitation activities, the gas content distribution of coal reservoir in this block was studied. The results show that the gas content hold by the coal reservoir is 7.0 − 21.7 m³/t, which was determined by a combining control effect from geologic structure and hydrogeology. The Changzhi coalbed methane block has experienced multiple-stages geologic structure evolution, especially a tectonic-thermal event during the middle Yanshanian Orogeny improved the coal to the current Ro,max 1.9 − 2.7% and meanwhile the coalbed methane was greatly generated. Subsequently, the widespreadly developed normal fault structures during the Himalayan Orogeny accelerated the coalbed methane escape through the “gas escape windows”, particularly where the location within the distance of about 1300 m to the “gas escape window” the gas content decreases significantly. Moreover, due to the action of the later Himalayan Orogeny, the slope areas of most Yanshanian fold structures were structurally cross-cut by the Himalayan normal faults, and thus an “open” syncline folds were formed. The coal reservoir was depressurized surrounding this “open” syncline structure and consequently the hydrodynamic losing effect has resulted in a comparatively lower gas content therein. By the control of geologic structure and hydrogeology, this block can be generally, compartmentalized into three hydrodynamic systems including the western groundwater stagnation region, the middle runoff region, and the north-eastern recharge region, where the hydrodynamic sealing effect at the groundwater stagnation region has made a comparatively higher gas content for the coal reservoir, but the hydrodynamic losing effect at the recharge region and runoff region has made a comparatively lower gas content of the coal reservoir.
The majority of known coalbed methane (CBM) production worldwide comes primarily from high-abundance CBM-enrichment areas or ‘fairways.’ The high-abundance CBM-enrichment areas are primarily characterised by large CBM resources with high single-well productions. CBM accumulation areas from the medium- to high-rank coals in the southern Qinshui Basin and the Hancheng CBM fields in the Ordos Basin were investigated based on regional geological analyses and physical analogue experiments. The results show that gas contents in the study areas increase with depths over the range from approximately 300 to 800 m, while permeabilities generally decrease with depths. Intervals with optimal gas content and permeability exist at a moderate depth along an inclined coal seam under the coupled control of temperature and stress. Brittle–ductile transition deformation increases the permeability and the pore-specific surface areas of coals. The gas content and permeability of the CBM reservoirs are shown to be two key factors determining the formation of high-abundance CBM areas. The coupling of gas enrichment and high permeability provides a favourable combination for CBM accumulation and high production. Combining CBM exploration and development practices in the study areas with physical analogue experiments, two CBM-enrichment models for medium- to high-rank coal have been recognised for different geological conditions, including (1) the model controlled by the depth in the slope zone and (2) the model controlled by the coal brittle and ductile in the deformation zones.
