A Parametric Study on the Benefits of Drilling Horizontal and ...

A Parametric Study on the Benefits of Drilling Horizontal and Multilateral Wells in Coalbed Methane Reservoirs Nikola Maricic, SPE, Chevron Corporation; Shahab D. Mohaghegh, SPE, West Virginia University, and Emre Artun, SPE, Chevron Corporation

Summary Recent years have witnessed a renewed interest in development of coalbed methane (CBM) reservoirs. Optimizing CBM production is of interest to many operators. Drilling horizontal and multilateral wells is gaining popularity in many different coalbed reservoirs, with varying results. This study concentrates on variations of horizontaland multilateral-well configurations and their potential benefits. In this study, horizontal and several multilateral drilling patterns for CBM reservoirs are studied. The reservoir parameters that have been studied include gas content, permeability, and desorption characteristics. Net present value (NPV) has been used as the yard stick for comparing different drilling configurations. Configurations that have been investigated are single-, dual-, tri-, and quad-lateral wells along with fishbone (also known as pinnate) wells. In these configurations, the total length of horizontal wells and the spacing between laterals (SBL) have been studied. It was determined that in the cases that have been studied in this paper (all other circumstances being equal), quadlateral wells are the optimum well configuration. Introduction Several studies in the past have examined the impact of different reservoir properties on CBM production (Ertekin et al. 1988; Zuber 1998; Katyal et al. 2007), including the effect of secondary (micro-) permeability (Gamson et al. 1993; Mavor and Gunter 2006; Palmer et al. 2006). This paper is dedicated to examining the impact of different horizontal-well configurations (multilateral) on the production and recovery in CBM reservoirs. In this section, a brief background on reservoir-engineering aspects of CBM production is presented along with details on the reservoir simulator used for modeling the cases used in this study. Some basic introduction about horizontal wells and their impact on production behavior is also presented. CBM Background. Coal represents an unusual reservoir rock, resulting from its highly complex reservoir characteristics. One of the characteristics that distinguish coal seams from conventional gas reservoirs is that coal represents both the source and the reservoir rock at the same time. Unlike conventional sandstone reservoirs, where the gas is found in free state within the pore structure of the rock, the methane gas is adsorbed onto the internal structure of the coal, which allows a significant amount of gas to be stored in the coal rock (Saulsberry et al. 1996). The coal-seam system is a complex heterogeneous reservoir characterized by a naturally fractured system, macropores (also known as the cleat system), and micropores (the coal-matrix system). In general, the coal cleat system is orthogonal, with one direction cross cutting the other, and it varies from case to the case with significant impact on the coal deliverability (Remner et al. 1986). The CBM production depends highly on the fracture system, fracture spacing, and fracture interconnection. If the cleat system for any reason is not

Copyright © 2008 Society of Petroleum Engineers This paper (SPE 96018) was accepted for presentation at 2005 SPE Annual Technical Conference and Exhibition, Dallas, 9–12 October, and revised for publication. Original manuscript received for review 11 July 2005. Revised manuscript received for review 10 July 2008. Paper peer approved 2 August 2008.

976

developed enough, gas production could be difficult. This occurs because of the low values of porosity and permeability in the matrix, making it almost impossible for gas to move from the matrix into the fractures. At the beginning, the coal system is in equilibrium, and typically, water must be produced continuously from coal seams to reduce the reservoir pressure and release the gas. Gas from the coal can be produced only after initial dewatering of the system and upon reaching low reservoir pressure. Once the pressure drops lower than the “critical desorption point,” methane desorbs from the coal surface (Guo et al. 2003). The dewatering process can take anywhere from a few days to several months, which depends on CBM-well configuration. Generally, the water production declines until the gas rate reaches the peak value. This “time to peak gas” is a critical parameter because the gas production starts declining after reaching the maximum (Roadifer et al. 2003). Upon reaching the peak, gas production starts to decline and behavior of CBM production becomes similar to that of conventional reservoirs. Simulation Details. All simulation models for this study were performed by use of a commonly used commercial simulator [CMG’s Advanced Compositional Reservoir Simulator (GEM 2006)]. The commercial simulator used in this study is a fully compositional model used to model reservoir-engineering cases where fluid composition and their interactions are essential to the understanding of the recovery process. It is an engineering tool for modeling complex reservoirs with complicated phase-behavior interactions, which impact directly on the recovery mechanisms used to optimize the recovery (Arenas 2004). In our implementation of the simulation runs, automatic timestep was used in the range of 0.01 to 365 days. Furthermore, an adaptive-implicit solution method (fully implicit strategy) with stability switching was used where wellblocks and neighboring blocks are set implicitly. All other blocks are checked in every timestep for stability after convergence (GEM 2006). The simulation runs represented a dual-porosity model with the matrix-tofracture and fracture-to-fracture flow calculations. A formulation of the Gilman and Kazemi type was used for the shape-factor calculation and a pseudocapillary pressure model with corrections was used for the matrix-to-fracture transfer calculations. Rock-compressibility values used in the study at the state of equilibrium were 1.0 E−06 psi−1 at reference pressure of 412 psi for the matrix and fractured systems. The Peng-Robinson equation of state was selected, and the constant reservoir temperature was set as 113°F. Relative permeability curves shown in Fig. 1 were used for all the simulation runs that are presented in this paper, with an initial water saturation of 92.7% in the cleat system. It must be noted that during this study, matrix shrinkage owing to production and (therefore) its potential impact on stress-related permeability were not taken into account. Although such considerations may have impacted the overall production behavior, it would not have impacted the overall conclusions of this study. Readers are encouraged to see Shi and Durucan (2005) and Gu and Chalaturnyk (2005) for details on this topic. Horizontal Wells. Methane can be drained through smalldiameter horizontal holes. The main advantages of horizontal wells are that the well direction, shape, and position can be controlled. December 2008 SPE Reservoir Evaluation & Engineering

Fig. 2—CBM-production rates from horizontal and vertical wells.

lowing an exceedingly small contact between them and the coal seam, are rarely, if ever, acceptable producers. Production rates do not exceed a few thousand cf/D, and they are hindered further by relative permability problems caused by the presence of associated water (Deimbacher et al. 1992). Figs. 2 and 3 demonstrate comparison of production rates and of cumulative production, respectively, between vertical and horizontal wells from a typical CBM reservoir.

Fig. 1—Relative permeability curves used in this study.

By use of horizontal wells, an almost ideal position of the well can be determined and implemented with respect to principle permeability directions of the coal (Osisanya and Schaffitzel 1996). Proper positioning of the well, and proper length of the borehole, can contribute significantly to draining large areas. An effective stimulation technique may be a horizontal borehole placed perpendicular to face-cleat direction, thus providing maximum access to the primary flow channels (Logan 1988). One question is which shape of horizontal well to drill to produce larger amount of gas in the shortest possible time. Drilling horizontal wells in coal seams is highly important to the sweep efficiency. As the length of the well and contact of wellbore to coal seam increase, the time for water production decreases. Usually, the gasproduction curves of vertical and horizontal wells will differ significantly from each other. In a short time, the horizontal well will dewater the system, and significant water production will take place. The gas-flow peak will occur soon after the well starts to produce. The most important part of the gas-flow curve is probably just after gas flow peaks. The slope of the curve is important because the well will produce like a conventional gas reservoir from that point. The flatter the curve, the better production will be for the rest of the well’s life. The issue is that horizontal wells are capable of draining the system fast because of much longer wellbore contact with the reservoir. Consequently, the adsorption process is triggered quickly, and the well will elicit a steep negative decline curve relatively fast. After reaching the peak, the gas production will start to decrease, again owing to the large contact area between the horizontal well and the reservoir. Vertical wells, al-

Fig. 3—CBM cumulative production from horizontal and vertical wells. December 2008 SPE Reservoir Evaluation & Engineering

Parametric Study: Systematic Approach In this study, a number of simulations have been performed to investigate the influence of different horizontal-well shapes, their various length, SBL, and various reservoir properties on the deliverability of a certain type of coal. To explain various steps performed in this study better, a flow chart is used (Fig. 4). The starting point of this research was determining the different horizontal-well configurations that would be used and implemented in the study. As a result, five horizontalwell shapes were examined: single-lateral, dual-lateral, trilateral, quadlateral, and fishbone (pinnate). No matter which horizontal shape has been applied to the reservoir simulator, the vertical length (depth from the surface to the horizontal-kickoff point) is constant in all cases during this study. Definitions of a lateral well, SBL, and vertical depth are illustrated in Fig. 5. Investigated well configurations are illustrated in Fig. 6. Sensitivity analysis (parametric study) represents a set of simulation runs in which all parameters are kept constant, but only one is changed systematically. This approach enables us to monitor changes of simulation outputs influenced by only one variable. The first step taken in this part of the approach was to develop a model representing CBM and test it by use of different well configurations. A dual-porosity model was used to create a CBM reservoir

Fig. 4—Flow chart of the study presented here. 977

Fig. 5—Definitions of terms related to a lateral well.

including a Gilman-Kazemi shape-factor calculation. A Cartesiangrid model has been chosen for the modeling of the CBM reservoir, which has the input parameters shown in Table 1. This homogeneous model by use of a Cartesian grid has been formed with a constant drainage area of 320 acres, consisting of 30×30 square blocks with each side measuring 120 ft. As previously mentioned in this section, regardless of the horizontal shape applied to the reservoir simulator, the vertical length is constant in all cases during this study. The production period has been determined as 15 years. The parametric study is divided into three parts. In the first part, the influence of well configuration and SBL is investigated considering the five configurations mentioned earlier in this section. In the second part, the influence of several reservoir/coal properties such as permeability, time constant, gas content, and desorption characteristics is investigated. The third part involves a study on thickness. In each part, gas recovery and NPV results at the end of the 15-year production period are presented. NPV is calculated at a discount rate of 8% after considering the costs associated with drilling operations. The most important cost factor was the horizontal drilling cost, which was assumed as USD 100/ft after discussion with industry professionals. It should be noted that this is an average value for a drilling operation under perfect conditions, and it might increase as problems arise during drilling. Futhermore, remedial operations or standard operating procedures such as wellbore cleanups are not considered in the calculation of NPV. Such operations can increase well operating costs significantly and drive down NPV.

Fig. 6—Investigated well configurations.

cases. For the pinnate horizontal-well shape, another scenario was needed because of the specific shape of this well configuration. Another variable was introduced: namely the number of laterals. Reservoir Properties. The second part of the sensitivity analysis required the definition of coalbed-reservoir properties subject to change during the study. Knowing all the steps performed in the first part of this analysis, this time the minimum well length and SBL were defined and kept constant, and the reservoir data were changed one by one. The goal of this approach was to introduce a new dimension to the model, which is changing one reservoir property at a time. The quad-lateral well configuration with 680 ft

Well Configuration/SBL. The starting point in this part of the study is the vertical well placed in the middle of the reservoir with horizontals spreading out toward the upper-left corner of the model (Fig. 7). The single-lateral well configuration was the first one to be investigated. By definition, this was the only case in the study where SBL was not used. Well configurations with different horizontal lengths were simulated. The drainage area was kept constant, and for the whole set of simulations, only the horizontal length of the well and SBL were continuously changed step by step. Once SBL was determined (the narrowest one), it remained constant, changing only horizontal length from the shortest to the longest length while running the simulator for each different scenario that took place. The maximum length of a horizontal well is constricted by the shape and the size of the reservoir. With dual-, tri-, and quadlaterals, SBL was introduced as a variable. The process described for single-lateral wells was applied to the rest of investigated well shapes, taking into account the new variable (i.e., SBL). Upon creating all possible scenarios for a minimum value of SBL, a new SBL with a higher value than the previous one was introduced. Again, the same procedure took place, keeping SBL constant while changing horizontal length from minimum to maximum. After the completion of all possible cases for one configuration of horizontal wells, another configuration was introduced. The same procedure was applied to tri-lateral and quad-lateral horizontal-well configurations. The problem with the pinnate shape required some modification of this approach. Obviously, there is no SBL with the singlelateral horizontal configuration, but dual-, tri-, and quad-lateral configurations possess SBL, which was investigated in these three 978

December 2008 SPE Reservoir Evaluation & Engineering

Fig. 7—Single horizontal-lateral wells with different horizontal lengths.

of SBL has been used to conduct parametric studies to assess the effects of parameters such as permeability, time constant, and gas content. That configuration was chosen because it was the one that has yielded the best gas-recovery results. Thickness. In this part of the study, a relatively smaller model has been developed to investigate gas recovery in different cases on the basis of pay thickness. A 15×15-gridblock model was developed with the same gridblock size of 120 ft. Vertical depth was kept constant. Cases of a single layer with net-pay thicknesses of 4 ft and 12 ft and a case of three layers with a thickness of 4 ft each were simulated with well configurations of single-vertical, fourspot, and horizontal wells. Results and Discussion Well Configuration/SBL. With values of the actual gas production as the simulator output and calculating initial gas in place as 820 MMscf and initial water in place as 520,000 bbl, gas recovery for each well configuration has been calculated and plotted against total horizontal length of the well. Gas recovery vs. totalhorizontal-length shape behavior is shown in Fig. 8. Gas-recovery December 2008 SPE Reservoir Evaluation & Engineering

Fig. 8—Gas recovery for single-lateral well configurations. 979

Fig. 9—Gas recovery for dual-lateral well configurations.

Fig. 10—Gas recovery for tri-lateral well configurations.

results for dual-, tri-, and quad-lateral and pinnate configurations are shown in Figs. 9 through 12, respectively. The best producers from five different well configurations have been compared with one another (Fig. 13). Our investigation shows that the quadlateral well configuration with an SBL of 680 ft and total horizontal length of 8,000 ft is the one with the highest gas recovery (approximately 36%). The strongest competitor, the pinnate well configuration, has a little better recovery (38%) but for the total horizontal length of 18,000 ft. But the question is whether to drill an additional 10,000 ft of horizontal section to recover 2 to 3% more gas. If these two horizontal-well configurations are compared for the same total horizontal length of 8,000 ft, it is obvious that the quadlateral well configuration can recover 5 to 10% more gas. Although a larger horizontal length increases the total gas recovery, increasing horizontal-drilling costs must be considered to find out the optimum configuration. Fig. 14 shows NPVs for the quad-lateral well configuration, which is now the recommended well configuration. The graph shows the results with respect to the horizontal length and SBL. This graph suggests the optimum configuration would be the quad-lateral well configuration with an SBL of 680 ft and a total horizontal length of 3,100 ft.

0.35 of overall gas recovery (Fig. 15). Fig. 16 reflects the NPV values for each case, and it shows a similar trend. Time Constant. Values of 10, 50, 150, and 200 days have been assigned to the time constant, ␶ (i.e., coal-desorption time), to see the changes in the reservoir behavior resulting from the timeconstant parameter. After 15 years of production, overall gas recovery did not differ too much with varying values of the time constant. It has been observed that overall gas recovery would have a range of 0.26 and 0.29 for time-constant values changing between 10 days and 200 days (Fig. 17). Because it is a known fact that the time constant mainly affects the earlier production from a CBM reservoir, it has been decided to consider the first year’s production in each case. Fig. 18 shows the cumulative gas production during the 15 years of production for each case with different time-constant values ranging from 10 to 200 days. As discussed, as far as the long-term production (i.e., 15 years in this case) is concerned, time constant does not have a significant effect on overall gas recovery. While the gas produced after the first year is approximately 120 MMcf for a time constant of 10 days, when the time constant is as large as 200 days, the first year’s production is approximately 80 MMcf. Considering the expected difference in production of 40 MMcf of gas, it can be concluded that the time constant has a significant effect on the first year’s production of the reservoir. It is observed that the difference in cumulative production after the first year remains constant during 15 years of production. Assuming a gas price of USD 5/Mscf, this difference would be equal to as much as USD 200,000. This difference is clearly reflected in Fig. 19, which shows NPV values for each case. Gas Content. Gas content is one of the most important parameters that influences the gas recovery from coalbeds.

Reservoir Properties. The quad-lateral well configuration with 680 ft of SBL and with a horizontal length of 8,000 ft has been used to investigate the influence of parameters such as permeability, time constant, and gas content. Permeability. The fracture permeability in i and j directions has been changed together so as to have values of 2, 5, 8, 10, and 15 md, while the permeability in the k direction is kept constant at 2 md. Gas recovery after 15 years of production has increased with increasing permeability, as expected. Permeability values changing between 2 and 15 md had a corresponding range of 0.19 and

Fig. 11—Gas recovery for quad-lateral well configurations. 980

Fig. 12—Gas recovery for pinnate well configurations. December 2008 SPE Reservoir Evaluation & Engineering

Fig. 13—Gas recovery comparing best producers.

Fig. 14—NPV of quad-lateral horizontal-well configurations.

Gas content is a measurement of the actual gas contained in a given resevoir (Schraufnagel and McBane 1994). The same system has been simulated with different values of gas content as 350, 395, and 450 scf/ton. Considering these values, five different isotherms have been generated by changing Langmuir volume and pressure constants, which are controlled by maximal adsorbed mass and Langmuir adsorption constant, respectively. Characteristics of these five isotherms are shown in Table 2. One of the isotherms is an average isotherm for Northern Appalachia, and others are defined as modifications to that isotherm. Initial reservoir pressure is kept at 450 psi for all cases. The graph that shows the behavior of each isotherm is shown in Fig. 20, which indicated the corresponding gas content with respect to pressure for the saturated case for each isotherm. The final gas recoveries after 15 years of production for each isotherm are shown in Fig. 21 and the corresponding NPV are shown in Fig. 22. The isotherms are ranked on the basis of the recovery as Modification 3, Northern Appalachia, Modification 1, Modification 2, and Modification 4, respectively. Considering the isotherm curves shown in Fig. 20, the decline behaviors of the five isotherms support the gas-recovery values. Fig. 21 shows the NPV results for each case, which show a trend similar to the one obtained for gas recovery.

graph also clearly shows that drilling horizontal wells is more favorable, than drilling vertical wells.

Thickness. Fig. 23 shows gas-recovery results for each well configuration and for each case, which include a case with a single layer of 4-ft thickness, a case with a single layer of 12-ft thickness, and the case with three layers, each with a thickness of 4 ft. This graph clearly shows that horizontal-well configurations bring the best gas recovery. The large gap between the gas-recovery results for the case with a single layer of 4 ft and others is caused by the difference in the initial gas in place. In our analysis, the case with the single layer could not recover its investment. The case with three layers had an NPV profile like the one shown in Fig. 24. This

Fig. 15—Effect of permeability on gas recovery. December 2008 SPE Reservoir Evaluation & Engineering

Conclusions A parametric study to determine the benefits of drilling horizontal and multilateral wells in CBM reservoirs is presented. Various well configurations, such as single-, dual-, tri-, and quad-lateral and fishbone (also known as pinnate), were investigated while considering parameters such as SBL and total horizontal length. Sensitivity analyses also were conducted to examine the effects of thickness, number of layers, and various reservoir/coal parameters such as permeability, time constant, and gas content. It was noted that gas content is a major contributor to gas recovery from CBM reservoirs. Major conclusions of this study can be summarized as follows: 1) The optimum well configuration can be determined by considering the total horizontal length, SBL, and number of laterals. Higher horizontal length increases the contact with the coal seam and yields a higher gas recovery, but it also increases the associated drilling costs at the same time. After considering the economics, the optimum configuration, which is suggested by this study, is a quad-lateral well configuration with SBL of 680 ft and total horizontal length of approximately 3,100 ft. 2) Time constant has no significant effect on the overall recovery. It is an important factor that influences the production in the first year, however, and thus the economics of the first year of production. Nomenclature i, j, k ⳱ indecies identifying directions x, y, z, respectively kr ⳱ relative permeability, fraction krw ⳱ water relative permeability, fraction krg ⳱ gas relative permeability, fraction Sw ⳱ water aturation, fraction

Fig. 16—Effect of permeability on NPV. 981

Fig. 17—Effect of time constant on gas recovery.

Fig. 20—Five isotherms defined with different pressure and volume constants (PL and VL).

PL ⳱ Langmuir pressure constant, m/Lt2, psi VL ⳱ Langmuir volume constant, L3, scf ␶ ⳱ desorption time constant, t, days Acknowledgment The authors would like to thank Computer Modelling Group Ltd. for providing the software used in this study. References

Fig. 18—Effect of time constant on cumulative gas production.

Arenas, A.G. 2004. Development of gas production curves for coalbed methane reservoirs. MS thesis, West Virginia University, Morgantown, West Virginia. Deimbacher, F.X., Economides, M.J., Heinemann, Z.E., and Brown, J.E. 1992. Comparison of Methane Production From Coalbeds Using Vertical or Horizontal Fractured Wells. JPT 44 (8): 930–935; Trans., AIME, 293. SPE-21280-PA. DOI: 10.2118/21280-PA. Ertekin, T., Sung, W., and Schwerer, F. 1988. Production Performance Analysis of Horizontal Drainage Wells for the Degasification of Coal Seams. JPT 40 (5): 625–632. SPE-15453-PA. DOI: 10.2118/15453-PA. Gamson, P.D., Beamish, B.B., and Johnson, D.P. 1993. Coal Microstructure and Micropermeability and Their Effects On Natural-Gas Recovery. Fuel 72 (1): 87–99. DOI: 10.1016/0016-2361(93)90381-B. GEM Advanced Compositional Reservoir Simulator, Version 2006 User Guide. 2006. Calgary, Alberta: CMG. Gu, F. and Chalaturnyk, R.J. 2005. Analysis of coalbed methane production by reservoir and geomechanical coupling simulation. J. Cdn. Pet. Tech. 44 (10): 33–42. Guo, X., Du, Z., and Li, S. 2003. Computer Modeling and Simulation of Coalbed Methane Reservoir. Paper SPE 84815 presented at the SPE Eastern Regional Meeting, Pittsburgh, Pennsylvania, 6–10 September. DOI: 10.2118/84815-MS. Katyal, S., Valix, M., Thambimuthu, K. 2007. Study of parameters affect-

Fig. 19—Effect of time constant on NPV.

Fig. 21—Final gas recoveries for five isotherms after 15 years of production. 982


Fig. 22—NPVs for five isotherms after 15 years of production.

ing enhanced coal bed methane. Energy Sources, Part A: Recovery Utilization and Environmental Effects 29 (3): 193–205. Logan, T.L. 1988. Horizontal Drainhole Drilling Techniques Used for Coal Seam Resources Exploitation. Paper SPE 18254 presented at the SPE Annual Technical Conference and Exhibition, Houston, 2–5 October. SPE-18254-MS. DOI: 10.2118/18254-MS. Mavor, M.J. and Gunter, W.D. 2006. Secondary Porosity and Permeability of Coal vs. Gas Composition and Pressure. SPEREE 9 (2): 114–125. SPE-90255-PA. DOI: 10.2118/90255-PA. Osisanya, S.O. and Schaffitzel, R.F. 1996. A Review of Horizontal Drilling and Completion Techniques for Recovery of Coalbed Methane. Paper SPE 37131 presented at the International Conference on Horizontal Well Technology, Calgary, 18–20 November. DOI: 10.2118/37131-MS. Palmer, I.D., Cameron, J.R., and Moschovidis, Z.A. 2006. Permeability changes affect CBM production predictions. Oil & Gas J. 104 (28): 43–50. Remner, D., Ertekin, T., Sung, W., and King, G. 1986. A Parametric Study of the Effects of Coal Seam Properties on Gas Drainage Efficiency. SPERE 1 (6): 633–646. SPE-13366-PA. DOI: 10.2118/13366-PA. Roadifer, R.D., Moore, T.R., Raterman, K.T., Farnan, R.A., and Crabtree, B.J. 2003. Coalbed Methane Parametric Study: What’s Really Important to Production and When? Paper SPE 84425 presented at the SPE Annual Technical Conference and Exhibition, Denver, 5–8 October. DOI: 10.2118/84425-MS. Saulsberry, J.L., Schafer, P.S., and Scraufnagel, R.A. eds. 1996. A Guide to Coalbed Methane Reservoir Engineering. Technical Report GRI-94/ 0397, Gas Research Institute, Chicago, Illinois. Schraufnagel, R. and McBane, R. 1994. Coalbed Methane—A Decade of Success. Paper SPE 28581 presented at the SPE Annual Technical Conference and Exhibition, New Orleans, 25–28 September. DOI: 10.2118/28581-MS. Shi, J.-Q. and Durucan, S. 2005. A Model for Changes in Coalbed Permeability During Primary and Enhanced Methane Recovery. SPEREE 8 (4): 291–299. SPE-87230-PA. DOI: 10.2118/87230-PA.

SI Metric Conversion Factors acre × 4.046 873 E+03 ⳱ m2 bbl × 1.589 873 E–01 ⳱ m3 ft × 3.048* E–01 ⳱ m E–02 ⳱ m3 ft3 × 2.831 685 °F (°F–32)/1.8 ⳱ °C psi × 6.894 757 E+00 ⳱ kPa *Conversion factor is exact.


Fig. 23—Gas-recovery results for different well configurations and for different cases of thickness.

Nikola Maricic is a petroleum engineer with the Chevron Energy Technology Company’s (ETC) reservoir simulation consulting team in Houston. E-mail: [email protected]. His research includes reservoir characterization and CBM simulation studies. Maricic has been working in the area of gasstorage reservoirs, heavy-oil production and operations, and, recently, black-oil reservoir simulation. He holds a BS degree from University of Belgrade (2002) in Serbia and an MS degree from West Virginia University (2004), both in petroleum engineering. Shahab D. Mohaghegh is a professor of petroleum and natural gas engineering at West Virginia University in Morgantown, West Virginia. E-mail: [email protected]. He has 17 years of experience applying Artificial Intelligence and Data Mining (AI&DM) to the upstream oil and gas industry including all aspects of CBM reservoir engineering and production. He holds BS and MS degrees in natural gas engineering from Texas A&M University and a PhD degree in petroleum and natural gas engineering from Penn State University. Emre Artun is works for Chevron ETC’s reservoir simulation consulting team in Houston. E-mail: [email protected]. He holds a PhD degree from Penn State University, an MSc degree from West Virginia University, and a BSc degree from Middle East Technical University, Turkey, all in petroleum and natural gas engineering. He also holds a graduate minor in computational science from Penn State.

Fig. 24—NPV results for the case with three layers, each with a thickness of 4 ft, for different well configurations.

983