Analysis and interpretation of the thermal test of gas hydrate dissociation in the JAPEX/JNOC/GSC et al. Mallik 5L-38 gas hydrate production research well Abstract:The objectives of this study were to 1) analyze the data from a field test of thermally induced dissociation of gas hydrate in the JAPEX/JNOC/GSC et al. Mallik 5L-38 gas hydrate production research well; 2) validate and calibrate the numerical model; and 3) determine important parameters describing gas hydrate behaviour and dissociation. The initial conditions and properties of the gas hydrate deposit were determined using supporting geological and geophysical data. Direct measurements provided the necessary boundary conditions. The numerical model was calibrated against the cumulative volumes of produced gas, a process that increased confidence in the model. Two possible scenarios of thermal dissociation, using unadjusted and smoothed data, are proposed to interpret the field test results. The parameters of the dominant physical processes are estimated by inverse modelling (history matching). Their results compare favourably with previously published data. Additionally, estimates of long-term production are made, and an alternative well configuration is proposed to substantially increase gas production.
Marcellus Shale occurs at depths of 1.5-2.5 km (5000 to 8000 feet) where most geologists generally assume that thermogenic processes are the only source of natural gas. However, methanogens in produced fluids and isotopic signatures of biogenic methane in this deep shale have recently been discovered. This study explores whether those methanogens are indigenous to the shale or are introduced during drilling and hydraulic fracturing. DNA was extracted from Marcellus Shale core samples, preinjected fluids, and produced fluids and was analyzed using Miseq sequencing of 16s rRNA genes. Methanogens present in shale cores were similar to methanogens in produced fluids. No methanogens were detected in injected fluids, suggesting that this is an unlikely source and that they may be native to the shale itself. Bench-top methane production tests of shale core and produced fluids suggest that these organisms are alive and active under simulated reservoir conditions. Growth conditions designed to simulate the hydrofracture processes indicated somewhat increased methane production; however, fluids alone produced relatively little methane. Together, these results suggest that some biogenic methane may be produced in these wells and that hydrofracture fluids currently used to stimulate gas recovery could stimulate methanogens and their rate of producing methane.
Summary The major emphasis of the U.S. DOE's coalbed methane research has been on estimating the magnitude of the resource and developing systems for recovery. Methane resource estimates for 16 basins show that the greatest potential is in the Piceance, Northern Appalachian, Central Appalachian, potential is in the Piceance, Northern Appalachian, Central Appalachian, Powder River, and Greater Green River coal basins. Small, high-potential Powder River, and Greater Green River coal basins. Small, high-potential target areas have been selected for in-depth analysis of the resource. Industry interest is greatest in the Warrior, San Juan, Piceance, Raton Mesa, and Northern and Central Appalachian basins. Production curves for several coalbed methane wells in these basins are included. Introduction The DOE has integrated all the available geologic and coal resource data acquired over the past 8 years to determine the stratigraphic units and geographic areas where coalbed methane production potential is classified as favorable. Sixteen basins have been studied (Fig. 1). The integration of these data has removed the uncertainty about what production potential exists and where the favorable production potential exists and where the favorable geologic trends are located in the basins. Table 1 gives a summary of the resource estimates for the basins and target areas for further exploration and/or development. Known coalbed methane production activity is also presented in six of these basins with examples of well production curves. Background Coal resources in the U.S. are widespread and abundant, with various types of coals underlying about 13%, or 380,000 sq miles [984 200 km2], of the land area within the contiguous U.S. Coals are present in 37 states, with coal-bearing areas representing a substantial percentage of the total area in many of these states. Coals vary in thickness from less than 1 to >200 ft f less than 0.3 to >61 m] and in depth from near surface to >10,000 ft [ >3050 m]. By today's mining standards, nearly 90% of all coals in the U.S. are considered unminable. Methane is present in nearly all U.S. coalbeds as natural gas formed during the coal formation process and is absorbed in the structure of the coal. Higher-ranking coals (bituminous and anthracite) may have from 200 to 500 ft3 methane/ton 16.2 to 15.6 m3/Mg) of coal, whereas the lower-rank coals (subbituminous and lignite) may contain less than 200 ft3 /ton [ less than 6.2 M 3 /Mg]. Gas content usually increases significantly with depth. Sand formations adjacent to coal seams and fractures where methane has accumulated by desorption may serve as reservoirs for additional quantities of released gas. Most of the available coalbed methane data are from mining areas in the eastern U.S. where the coalbeds are well defined and mining is extensive. Estimates of coalbed methane in the western U.S. are less accurate because the distribution of the coal and methane content has not been determined in many beds more than 3,000 ft [914 m] deep. The eastern coals are mostly bituminous or higher in rank, and western coals are generally of subbituminous to bituminous rank. Since 1978, the DOE has supported the assessment of gas potential in coalbeds throughout the U.S. and the recovery and use of methane associated with mining operations. Recent efforts have focused on the use of coalbed methane for regional economic gas self-sufficiency, energy parks, self-help, and cogeneration or small-power potential. The following major resource data have been acquired: coal rank, specific gas content, reservoir properties, coal thickness, overburden characteristics, well test data, and pre- and poststimulation data. This information provides insight into the volume of methane in place and allows for prediction of the potential of the various coalbed reservoirs. Existing geologic potential of the various coalbed reservoirs. Existing geologic data and limited reservoir property data in many of the basins permit the development of a rational approach for identifying areas with a high potential for the production of coalbed methane. Current Industry Activity The current level of activity and interest in coalbed methane development is focused on six basins. These include three eastern basins with shallow coals (Northern Appalachian, Central Appalachian, and Warrior) and three western basins with deep coals (San Juan, Raton Mesa, and Piceance) (Fig. 2). The remaining basins listed here have areas designated for high-potential coalbed methane development. The Appalachian basin is divided into three coal basins: the Northern, Central, and Warrior (southern). U.S. coalbed methane development began as early as the 1930's in the Northern Appalachian coal basin in the Pittsburgh coal seam. Production activity currently is highest in the Warrior basin in Alabama. Interest in development of coalbed methane reserves continues for the Northern and Central Appalachian basins. Most of the coal in the Appalachian basin is Mississippian and Pennsylvanian in age and is located at <2,000 ft [<610 m]. JPT P. 821
The U.S. Department of Energy's National Energy Technology Laboratory (NETL) established an Extreme Drilling Lab to engineer effective and efficient drilling technologies viable at depths greater than 20,000 feet. This paper details the challenges of ultra-deep drilling, documents reports of decreased drilling rates as a result of increasing fluid pressure and temperature, and describes NETL's Research and Development activities.NETL is invested in laboratory-scale physical simulation. Their physical simulator will have capability of circulating drilling fluids at 30,000 psi and 480 °F around a single drill cutter. This simulator will not yet be operational by the planned conference dates; therefore, the results will be limited to identification of leading hypotheses of drilling phenomena and NETL's test plans to validate or refute such theories.Of particular interest to the Extreme Drilling Lab's studies are the combinatorial effects of drilling fluid pressure, drilling fluid properties, rock properties, pore pressure, and drilling parameters, such as cutter rotational speed, weight on bit, and hydraulics associated with drilling fluid introduction to the rock-cutter interface. A detailed discussion of how each variable is controlled in a laboratory setting will be part of the conference paper and presentation.
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