• Journal of the Korean Institute of Gas
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• v.27 no.3
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• pp.98-107
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• 2023

This study presents a well spacing design for coalbed methane(CBM) reservoirs using the experimental results of methane gas adsorption measurement of coal samples obtained from North Kalimantan Island, Indonesia. The gas productivity analysis shows that the cumulative gas production increases as the Langmuir volume increases. This indicates that the maximum gas adsorption directly affects the gas production. In addition, the maximum gas production increases with the increase of reservoir permeability, and the dewatering period is shortened. In particular, the cumulative gas production increases as the production influence area increases. However, when comparing productivity per unit well, the maximum cumulative gas production is found between 2,000 ft of depth and 80-160 acres of the influence area. When reservoir depth and production influence area are considered simultaneously, the results of the appropriate well depth and spacing calculations show that gas productivity is highest between 600-2,000 ft. In this case, it is appropriate to design well spacing in the range of 80-160 acres. Therefore, well spacing design considering coalbed depth in undeveloped CBM reservoirs can be accomplished using gas sorption test results from coal samples.

• Geomechanics and Engineering
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• v.29 no.2
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• pp.145-154
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• 2022

Complex geological conditions have a great influence on the mining of coalbed methane (CBM), which affects the extraction efficiency of CBM. This investigation analyzed the complicated geological conditions in the Liujia CBM block of Fuxin. A geological model of heterogeneities CBM reservoirs was established to study the influence of strike direction of igneous rocks and fault structures on horizontal well layout. Subsequently, the dual-porosity and dual-permeability mathematical model was established, which considers the dynamic changes of porosity and permeability caused by gas adsorption, desorption, pressure change. The results show that the production curve is in good agreement with the actual by considering gas seepage in matrix pores in the model. Complicated geological structures affect the pressure expansion of horizontal wells, especially, the closer to the fault structure, the more significant the effect, the slower the pressure drop, and the smaller the desorption area. When the wellbore extends to the fault, the pressure expansion is blocked by the fault and the productivity is reduced. In the study area, the optimal distance to the fault is 70 m. When the horizontal wellbore is perpendicular to the direction of coal seam igneous rock, the productivity is higher than that of parallel igneous rock, and the horizontal well bore should be perpendicular to the cleat direction. However, the well length is limited due to the dense distribution of igneous rocks in the Liujia CBM block. Therefore, the horizontal well pumping in the study area should be arranged along the direction of igneous rock and parallel plane cleats. It is found that the larger the area surrounded by igneous rock, the more favorable the productivity. In summary, the reasonable layout of horizontal wells should make full use of the advantages of igneous rock, faults and other complex geological conditions to achieve the goal of high and stable production.

• Journal of the Korean Institute of Gas
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• v.22 no.3
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• pp.65-73
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• 2018

Coalbed methane has a nonlinear desorption curve depending on the pressure, so an appropriate production system should be constructed considering this phenomenon. The capacity and specification of the coalbed methane gas production facility are determined by the gas flow rate and pressure in the coalbed, which is the external boundary condition of the system. Thus, it is essential to analyze these characteristics in gas production. The gas inflow equation was calculated using the reservoir flow model and utilized as the boundary condition of the whole production facility in this study. Also, to understand the effect of pressure drop on the gas flow in the production facility, the nodal analysis was performed using the flow analysis simulator of production equipment, and we determined the proper specifications and operating conditions of the production facility. This study presents a design criteria as to production and gathering system capable of effectively transporting coalbed methane.

• Journal of the Korean Institute of Gas
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• v.23 no.3
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• pp.7-19
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• 2019

In this study, a model was developed for estimating deliverability considering the pressure dependent permeability and predicting production profile with Material Balance Equation(MBE) for Coalbed Methane(CBM) fields. The estimated deliverability was compared with the conventional deliverability based on CBM well testing data with coefficient of determination($R^2$). As a result, the former was 0.76 and the latter was 0.69. It was confirmed that the deliverability which consider the pressure dependent permeability is more adoptable when representing the productivity of CBM fields. Through this process, in order to calculate pressure dependent permeability when well testing data exist, a method to infer reservoir pressure within the radius of investigation was proposed. The production profile of 31 gas wells was predicted for 15 years, using the estimated deliverability and the MBE. After that, the results was compared with simulation results of the literature. The simulation results did not account the pressure dependent permeability and the developed model results considered that. As the applied field permeability rised 1.17 times, field production rate was increased approximately 15% than the literature results. According to other researches, the permeability of CBM fields can be rise 6 ~ 25 times. For these cases, the production profiles may have significant difference with conventional gas fields.

• The Journal of Engineering Geology
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• v.24 no.3
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• pp.423-429
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• 2014

Development of a reservoir pressure core sampler (PCS) with a built-in data logging system (DLS) for recording real-time temperature and pressure observations is critical in domestic hydrocarbon production to accurately measure and monitor reserves of shale gas, coalbed methane, and gas-hydrate. Another purpose of this new technology is to minimize the loss of gas from the core as the drill core is collected. This is accomplished by maintaining the pressure of the sample from the moment the drill core is obtained at depth, thus allowing an accurate analysis of shale gas, coalbed methane gas, and gashydrate within the core. Currently, the United States and European countries have monopolized the development and marketability of PCS technologies. We are thus developing a reservoir PCS by analyzing the operating principle and mechanisms of the existing PCS, and by conducting tests on the existing PCS. We further aim to develop a PCS with a maximum operating pressure of 100 bar, a maximum operating temperature of $-20^{\circ}C$ to $40^{\circ}C$, and a pressure loss rate of 10%.

• Journal of the Korean Institute of Gas
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• v.22 no.1
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• pp.64-77
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• 2018

This paper presents the prediction of the original gas in place(OGIP) by using the material balance method and decline curve analysis method with production history and pressure transient test data for four coalbed methane wells in the Horseshoe Canyon field. In this study, the conventional gas equation and the Jensen and Smith(J&S) equation were used to material balance analysis, and the Arps' empirical correlation and Khaled method were applied to decline curve analysis. From the results, the OGIP estimated from the conventional gas and the J&S method was small in difference as under 12%. Also, in case of decline curve analysis, it was found that the Khaled method has appropriated to calculate the OGIP, because the OGIP was estimated as unlimited value by the Arps' equation from the decline exponent of 1 - 3.5. The OGIP difference between conventional gas method and Khaled method was calculated as 8.67% ~ 31.04%, and those between J&S method and Khaled method was 13.67% ~ 26.49%.

• Economic and Environmental Geology
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• v.47 no.5
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• pp.551-561
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• 2014

Natural gas is the world's fastest-growing fossil fuel, with consumption increasing from 113 trillion cubic feet(Tcf) in 2010 to 185Tcf in 2040. While conventional natural gas streams from the earth relatively easily, unconventional gas finds are more difficult to develop and more costly to produce. Right now, there are six main types of unconventional gas, including deep gas, gas-containing shale, coalbed methane(CBM), geopressurized zones, Arctic and subsea hydrates, and tight gas. Tight gas refers to natural gas reservoirs locked in extraordinarily impermeable, hard rocks(sandstone, siltstone or carbonate sedimentary rocks). In this study, we analyzed total 375 papers(2000-2014) of tight gas by country, institution, international cooperation etc.

• Journal of Advanced Marine Engineering and Technology
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• v.39 no.9
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• pp.973-980
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• 2015

With their wide geographical distribution, unconventional resources are continuously compared against conventional resources, but their development is expanding because TRRs (Technical Recoverable Resources) are similar to conventional resources. In particular, there is active development of unconventional gas resources such as shale gas, tight gas, CBM (coalbed methane) and gas hydrate. However, it is difficult to calculate the material properties of unconventional resources, especially the gas content, with current geophysical logging technology. Additionally, some overseas companies have monopolies on related equipment and materials. Therefore, this study developed a reservoir PCS (Pressure Core Sampler). It can collect core samples without gaseous loss by maintaining high pressure from the moment the core is sampled and record pressure and temperature in real time. Successful performance testing was also carried out for official verification of the manufactured PCS. The reservoir PCS will contribute to the acquisition of geophysical well logging data as well as accurate and reliable cores.