• Journal of the Korean Institute of Gas
• /
• v.20 no.1
• /
• pp.13-22
• /
• 2016

This paper presents development of an appropriate procedure and flow chart to analyze shale gas production data obtained from a multi-fractured horizontal well according to flow characteristics in order to calculate an estimated ultimate recovery. Also, the technical considerations were proposed when a rate transient analysis was performed with field production data occurred to only $1^{st}$ transient flow. If production data show the $1^{st}$ transient flow from log-log and square root time plot analysis, production forecasting must be performed by applying different method as before and after of the end of $1^{st}$ linear flow. It is estimated by an area of stimulated reservoir volume which can be calculated from analysis results of micro-seismic data. If there are no bottomhole pressure data or micro-seismic data, an empirical decline curve method can be used to forecast production performance. If production period is relatively short, an accuracy of production data analysis could be improved by analyzing except the early production data, if it is necessary, after evaluating appropriation with near well data. Also, because over- or under-estimation for stimulated reservoir volume could take place according to analysis method or analyzer's own mind, it is necessary to recalculate it with fracture modeling, reservoir simulation and rate transient analysis, if it is necessary, after adequacy evaluation for fracture stage, injection volume of fracture fluid and productivity of producers.

• Journal of the Korean Institute of Gas
• /
• v.19 no.5
• /
• pp.13-19
• /
• 2015

This paper presents a hydraulic fracture propagation model to describe propagation more realistically. In propagating the hydraulic fractures, we have used two criteria: maximum tangential stress to determine the fracture initiation angle and whether a hydraulic fracture intersects a natural fracture. The model was validated for the parameters relevant to fracture propagation, such as initiation angle and crossing ability through natural fracture. In order to check whether a hydraulic fracture crosses a natural fracture, the model results on crossing state excellently matched with the experimental data. In the sensitivity analysis for direction of maximum horizontal stress, frictional coefficient of fracture interface, and natural fracture orientation, the results show that hydraulic fracture intersects natural fracture, and then, propagated suitably with theoretical results according to fracture interaction criterion. In comparison of this model against vertical fracture approach, it was ascertained that there are discrepancies in fracture connectivity and stimulated reservoir volume.

• Tunnel and Underground Space
• /
• v.31 no.1
• /
• pp.41-51
• /
• 2021

The hydraulic fracturing developed to improve permeability of tight reservoir is one of key stimulation technologies for developing unconventional resources such as shale gas and deep geothermal energy. The experimental study was conducted to improve disadvantage of hydraulic fracturing which has simple fracture pattern and poor fracturing efficiency. The fracturing experiments was conducted for tight rock using various fracturing fluids, water, N2, and CO2 and the created fracture pattern and fracturing efficiency was analyzed depending on fracturing fluids. The borehole pressure increased rapidly and then made fractures for hydraulic fracturing with constant injection rate, however, gas fracturing shows slowly increased pressure and less fracture pressure. The 3D tomography technic was used to generate images of induced fracture using hydraulic and gas fracturing. The stimulated reservoir volume (SRV) was estimated increment of 5.71% (water), 12.72% (N2), and 43.82% (CO2) respectively compared to initial pore volume. In addition, permeability measurement was carried out before and after fracturing experiments and the enhanced permeability by gas fracturing showed higher than hydraulic fracturing. The fracture conductivity was measured by increasing confining stress to consider newly creating fracture and closing induced fracture right after fracturing. When the confining stress was increased from 2MPa to 10MPa, the initial permeability was decreased by 89% (N2) and 50% (CO2) respectively. This study shows that the gas fracturing makes more permeability enhancement and less reduction of induced fracture conductivity than hydraulic fracturing.

• Journal of the Korean Institute of Gas
• /
• v.17 no.4
• /
• pp.58-69
• /
• 2013

This paper presents production data analysis for two production wells located in the shale gas field, Canada, with the proper analysis method according to each production performance characteristics. In the case A production well, the analysis was performed by applying both time and superposition time because the production history has high variation. Firstly, the flow regimes were classified with a log-log plot, and as a result, only the transient flow was appeared. Then the area of simulated reservoir volume (SRV) analyzed based on flowing material balance plot was calculated to 180 acres of time, and 240 acres of superposition time. And the original gas in place (OGIP) also was estimated to 15, 20 Bscf, respectively. However, as the area of SRV was not analyzed with the boundary dominated flow data, it was regarded as the minimum one. Therefore, the production forecasting was conducted according to variation of b exponent and the area of SRV. As a result, estimated ultimate recovery (EUR) increased 1.2 and 1.4 times respectively depending on b exponent, which was 0.5 and 1. In addition, as the area of SRV increased from 240 to 360 acres, EUR increased 1.3 times. In the case B production well, the formation compressibility and permeability depending on the overburden were applied to the analysis of the overpressured reservoir. In comparison of the case that applied geomechanical factors and the case that did not, the area of SRV was increased 1.4 times, OGIP was increased 1.5 times respectively. As a result of analysis, the prediction of future productivity including OGIP and EUR may be quite different depending on the analysis method. Thus, it was found that proper analysis methods, such as pseudo-time, superposition time, geomechanical factors, need to be applied depending on the production data to gain accurate results.