Evaluation of gas production from multiple coal seams: A simulation study and economics

International Journal of Mining Science and Technology xxx (2018) xxx–xxx

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International Journal of Mining Science and Technology journal homepage: www.elsevier.com/locate/ijmst

Evaluation of gas production from multiple coal seams: A simulation study and economics Yanting Wu a,b, Zhejun Pan b,⇑, Dingyu Zhang a, Zhaohui Lu c, Luke D. Connell b a

College of Geoscience and Surveying Engineering, China University of Mining and Technology (Beijing), Beijing 100083, China CSIRO Energy Business Unit, Clayton South, VIC 3169, Australia c Chongqing Institute of Geology and Mineral Resources, Chongqing 400042, China b

a r t i c l e

i n f o

Article history: Received 27 October 2017 Received in revised form 24 January 2018 Accepted 21 March 2018 Available online xxxx Keywords: Multiple coal seam Production simulation Economic viability Sensitivity Coalbed methane

a b s t r a c t Gas production from multiple coal seams has become common practice in many coal basins around the world. Although gas production rates are typically enhanced, the economic viability of such practice is not well studied. In order to investigate the technical and economic feasibility of multiple coal seams production, reservoir simulation integrated with economics modelling was performed to study the effect of important reservoir properties of the secondary coal seam on production and economic performance using both vertical and horizontal wells. The results demonstrated that multiple seam gas production of using both vertical and horizontal wells have competitive advantage over single layer production under most scenarios. Gas content and permeability of the secondary coal seam are the most important reservoir properties that have impact on the economic feasibility of multiple seam gas production. The comparison of vertical well and horizontal well performance showed that horizontal well is more economically attractive for both single well and gas field. Moreover, wellhead price is the most sensitive to the economic performance, followed by operating costs and government subsidy. Although the results of reservoir simulation combined with economic analysis are subject to assumptions, multiple seam gas production is more likely to maintain profitability compared with single layer production. Ó 2018 Published by Elsevier B.V. on behalf of China University of Mining & Technology. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).

1. Introduction Coalbed methane (CBM), or coal seam gas (CSG), along with shale gas and tight gas, are important unconventional natural gas. The global recoverable CBM resource is estimated to be 49 trillion m3, accounting for 21.7% of world unconventional gas resources [1]. Gas production from coal seams is also important for coal mining safety as CBM is a hazardous gas in mining [2,3]. Much of the early CBM development has been primarily focused on single coal seams (or groups). Thin seams (i.e., less than 6 m) in the United States were usually bypassed in favor of developing the gas resource in much thicker coals [4], because thick and continuous coalbeds were considered to have greater gas resources. However, with the depletion of more attractive thicker coal seams, development has moved towards thinner coal seams. In many CBM plays, coal seams are generally thin while the total thickness of multiple coal seams through a certain interval can be large [5–9]. Gas production from multiple thin coal seams has become a common practice in many basins. The first commercial production ⇑ Corresponding author. E-mail address: [email protected] (Z. Pan).

of CBM in Alberta, Canada, was established in 2002 from the Horseshoe Canyon Formation [6] where number of coal seams vary from 5 to 30 per well [7]. In 2012, nearly all coalbed methane wells drilled in Alberta have targeted the thin coal seams in the Horseshoe Canyon Formation (ultimate gas in place 5.07 trillion cubic meters) and Belly River coal zones along the Calgary-Red Deer corridor [8]. In Appalachian basin of southwestern Virginia, the United States, the thickness of a single coal seam is usually 1.5–1.8 m, while total thickness of multiple coal seams can be above 4.6 m [9]. CBM wells are typically completed in 3–5 coal seams and gas production of 250–500 MCFD (6875–13,750 m3/day) is quite common for a single well [9,10]. In the Black Warrior Basin, the United States, CBM is produced from multiple thin coal seams ranging from 0.3 m to 2.0 m thick distributed through more than 300 m section [11]. Multi-seam completion technology was developed in the Black Warrior Basin to recover gas from numerous coal seams with varied reservoir properties [12]. Multi-seam well completion methods have also been developed at Rock Creek, Alabama project; gas is produced from at least ten thin coal seams over a 122 m interval in the Mary Lee and Black Creek coal groups [13]. Outside of North America, CBM wells completed in multiple coal seams have also been exercised. For instance, wells drilled in

https://doi.org/10.1016/j.ijmst.2018.03.008 2095-2686/Ó 2018 Published by Elsevier B.V. on behalf of China University of Mining & Technology. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).

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Hedong coal basin, located along the eastern flank of the Ordos Basin in China, generally targeted up to 10 coal seams with the cumulative coal thickness ranging from approximately 7.6 m to 19.8 m, with individual seams ranging up to 5.8 m in thickness [14]. In Australia, the Bowen and Surat Basins have long been recognized as potential CBM giant with annual CSG production of 337 PJ (9.58 billion cubic meters) [15]. The gas is primarily produced from thin high permeability coals in the Jurassic-age Walloon Coal Measures in the Surat Basin and from several relatively thick Permian-age coal seams in the Bowen Basin [16]. Production from the large number of individual coal seams are co-mingled in a single vertical well in the Surat Basin [16]. The Walloon Coal Measures contain up to 24 seams in the Surat Basin [17]. In 2011, the Surat Basin had overtaken the Bowen Basin as the chief supplier of natural gas in general, but of CSG in particular [16]. Despite common practice of multiple seam production, little has been done to understand the economic viability of such practice, as multi-seam completion costs more than single seam completion. Decreasing profits might occur for multiple seam production despite higher production rate when additional investment cannot be paid back by increased production. This may become unfavorable for maximizing the economic return of the CBM project. Thus the practicality of multi-seam well versus single-seam well should be evaluated based on both the technical and the economic factors. Efforts have been made to systematically study commingled CBM reservoir production performance from the technical point of view. Clarkson et al. applied pressure transient analysis to Horseshoe Canyon CBM wells production data to study the contribution of each seam on total gas production [18]. Burgoyne and Clements proposed a probabilistic approach to predict CBM well performance using multi-seam well test data [19]. Zhang et al. studied favorable regions for multi-seam coalbed methane joint exploitation based on a fuzzy matter-element model [20]. The impacts of a number of geological factors such as coal thickness, burial depth, gas content, reservoir pressure gradient, and reduced water level on the gas production were analyzed and estimated [20]. In the work of Jiang et al., multiple seam gas production process of a fractured vertical CBM well was simulated using COMET3 numerical simulation software and the interlayer interference mechanism of multi-seam drainage was illustrated [21]. Some effort has been paid to the economic assessment of CBM projects. Dhir et al. presented a technique for determining the economic feasibility of proposed coalbed methane investments [22]. Luo et al. have evaluated CBM development in China by Net Present Value [23]. Nasar et al. compared the economical practicality of different drilling patterns in deep, thick CBM reservoirs under diverse reservoir properties with Net Present Value (NPV) analysis [24]. Sander and Connell conducted the economic assessment of enhanced coal mine methane drainage as a fugitive emissions reduction strategy [25]. However, no work has been done to study multi-layer CBM production from the economic perspective. Moreover, there are no work to study the impact of reservoir properties, such as permeability, reservoir pressure, and gas content, on the economics of the commingled production performance. The objective of this study is to investigate the technical and economic feasibility of gas production from multiple coal seams under various scenarios with different reservoir properties. Both vertical well and horizontal well were studied to compare the economics. In this work, an approach integrating reservoir simulation and economics modelling was applied. A coalbed methane reservoir simulator, SIMED II was first verified using the field gas production data of a Horseshoe Canyon CBM well to test the applicability of SIMED II in commingled production. Then a series of simulation studies were performed to investigate key properties that affect gas production from multiple coal seam and the

economic returns were compared between gas production from multiple-seam and single-seam completions to assist decisions on whether multiple seam production is more profitable.

2. Methodology 2.1. Multiple seam CBM production simulation Production forecasts are essential for computing anticipated returns from proposed investments. In this work, the coalbed methane simulator, SIMED II, was used to perform the production prediction. SIMED II is a two-phase, three dimensional, multicomponent simulator designed to model coalbed methane reservoirs and detailed description of this simulator is documented elsewhere [26]. However, the simulator has not been verified for gas production from multiple coal seams using field data. Therefore, the first step in this work was to use field production data from Horseshoe Canyon CBM well presented in [18] for history match. The detailed reservoir parameters used in the simulation can be found in Clarkson [18], in which a four-layer dry CBM reservoir was analytically modelled. The objective of this validation is to match the commingled production data while simultaneously matching gas rates from each coal layer. The bottom hole pressure (BHP) in Fig. 1 was used to control the well production and the gas production rate was calculated to perform history match. Fig. 2 shows the simulation results of commingled production while single layer rates at 365th day is shown in Fig. 3. It shows that SIMED II simulation of the gas production rate (red color) is in reasonable agreement with the measured production data (blue color) despite derivations after 570 days which may due to adjustment of operation treatment such as re-stimulation [18] and the BHP used in this work is constant after about 300 days.

2.2. Economic evaluation method Discounted Cash Flow (DCF) method was used to evaluate the economic viability of multiple seam CBM production under different scenarios. This approach is generally adopted in the oil and gas industry [27]. Commonly used indicators include the net present value (NPV), the internal rate of return (IRR), and the payback period [28]. All three indicators were used in this study to provide different and complementary attributes of economic feasibility. NPV is the present value of cash flows discounted at an average rate io. It is a fundamental parameter to express value of a project assuming success [29]. IRR is the interest rate for which the NPV equals to zero. It measures the investment efficiency [22]. Rather than focusing on the return from cash flows, the payback period is the length of time required to recover the cost of an investment [30]. Unlike NPV and IRR, It ignores the time value of money [31]. This indicator is relatively more important to smaller investors,

Fig. 1. Bottom hole pressure used in simulation validation.

Please cite this article in press as: Wu Y et al. Evaluation of gas production from multiple coal seams: A simulation study and economics. Int J Min Sci Technol (2018), https://doi.org/10.1016/j.ijmst.2018.03.008

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Y. Wu et al. / International Journal of Mining Science and Technology xxx (2018) xxx–xxx Table 1 Economic evaluation model inputs of CBM well (modified from [33]).

Fig. 2. Matching of the production data.

Parameters

Values

Units

Drilling and completion cost (vertical well) Surface investment Operating costs Fracturing costs Wellhead price Government subsidy Value added tax City maintenance and construction taxes, education fees, other local taxes Income tax Discount rate Production life Gas commoditization rate

1.4

Million yuan/well

10.08 0.5 0.2 1.5 0.3 5% 10%

Million yuan/km2 Yuan/m3 Million yuan/section Yuan/m3 Yuan/m3

25% 12% 30 0.95

Year

for well length exceeding 500 m. To account for variations of economic performance depending on different input data, sensitivity analysis of critical economic parameters were also performed. 3. Case studies and discussion

Fig. 3. Layer allocated rate match at 365th day.

who are concerned about liquidity and risk exposure [32]. It does not address chance of project success [32]. The equations for calculating NPV and IRR are defined as follows [33]:

NPV ¼

T X t ðCI  COÞt ð1 þ io Þ

ð1Þ

t¼0 T X ðCI  COÞt ð1 þ IRRÞt ¼ 0

ð2Þ

t¼0

where CI is the cash inflow; CO is the cash outflow; io is the discount rate; t is the year sequence; and T represents producing life of the project. For CBM projects, cash inflows include sales revenue and government subsidies. Cash outflows include investment, production costs and expenses, taxes and fees. Investment is mainly composed of well drilling and completion investment and surface facilities [33]. By far, the most commonly used drilling and completion technique is cased hole completion with hydraulic fracture stimulation [34]. For multi seam vertical well completion, multiple coal zones (several individual coal seams may be included in each stage) are sequentially perforated and hydraulically fractured from bottom to top [34]. Well cost is mainly affected by the depth of bottom target coal seam which affects drilling cost and number of target seams which affects perforating and fracturing costs. Cash flows are discounted over a 30-year project period at a rate of 12 percent in this study. Combined with the production forecasts generated by SIMED II and the basic economic assumptions listed in Table 1, three decision criteria can be obtained in various cases. The model inputs are obtained from various sources, but mainly from the data in Yang and Wang’s work [33] to consider CBM production in China’s scenario. Drilling and completion cost per well is 1.4 million yuan to the depth of 500 m [23] and 1000 Yuan/m for vertical well, and 2500 Yuan/m for horizontal well

Using the verified reservoir simulator, the sensitivity analysis of the production rate and three economic indicators to important reservoir parameters on commingled gas production from two coal seams were performed and discussed below. Compared with the technical and economic performance of single layer production, the economic viability of multiple seam CBM production can be obtained. Reservoir parameters used in the base case are listed in Table 2. The parameters of primary reservoir remained unchanged in all simulations, while changing one single parameter of secondary reservoir in order to evaluate its influence on multiple seam CBM production and economic profit. The simulations to be presented here are hypothetical and not intended to replicate a particular field site. While some parameters may be correlated, this is not considered in the analysis in order to simplify the comparisons. Key CBM reservoir parameters, including Langmuir volume, desorption pressure, reservoir porosity, reservoir permeability and coal seam thickness, are evaluated for economic analyses. Vertical well and horizontal well are both considered. 3.1. Effects of various reservoir parameters on vertical well To study the effects of various reservoir parameters on vertical well, a grid system of 19  19  3 was applied (the numbers refer Table 2 The reservoir parameters used in the base case simulation. Input parameters

Depth to the bottom of coalbed (m) Thickness (m) Langmuir volume (m3/t) Langmuir pressure (MPa) Desorption time (days) Initial reservoir pressure (MPa) Desorption pressure (MPa) Permeability (md) Porosity (%) Bulk density (g/cm3) Well radius (m) BHP (kPa)

Value Primary reservoir

Secondary reservoir

500 5 15 3 5 5 4 3 1 1.4 0.06 150

507 3 15 3 5 5 4 1 1 1.4

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to the grid system in X, Y, Z directions), with the grid size being 20 m  20 m in the X, Y directions. Therefore, the controlled reservoir area is 380 m  380 m in these cases. A hydraulic fracture length of 200 m with conductivity of 100 mdm was applied. Assuming that the hydraulic fracture does not penetrate in Z-direction and there is no crossflow between two coal seams. 3.1.1. Effect of Langmuir volume The Langmuir volume is the maximum gas adsorption capacity in coal. It is an important parameter that controls the coal adsorption capacity and is related to coal rank, as has been demonstrated in the single layer coal seam production. Langmuir volume of 8 m3/t, 10 m3/t, 12 m3/t, 15 m3/t, 18 m3/t, 20 m3/t was considered in the analyses below. Fig. 4 shows the simulated cases of gas production rates of single layer production (red solid line) and co-production of two coal seams (dotted lines). Langmuir volume of primary reservoir is 15 m3/t as shown in Table 2. For multiple seam CBM production, six cases with different Langmuir volume of the secondary reservoir ranging from 8 m3/t to 20 m3/t were modelled. The results show that multiple seam CBM production largely enhance gas rates than single layer production and larger Langmuir volume yields higher gas rates especially on late-life production after about 3.5 years in this case. When the Langmuir volume of the secondary reservoir is increased from 8 m3/t to 20 m3/t, the peak gas rate is increased from 2920 m3/d to 2970 m3/d. The predicted production is entered into the economic model to study the effect of Langmuir volume on co-production economics. Fig. 5 shows the NPVs of the seven cases including six cases of multiple seam CBM production and one case of single layer production. The NPVs for all seven cases are positive within 30 years of production and they reach plateau around 20 years. The single layer production yields the lowest NPV of 82,400 yuan within 30 years and requires much longer time to yield positive NPV (about 15 years). Multiple seam CBM production have demonstrated a competitive advantage over single layer production. The time to yield positive NPV is more than five years earlier than single layer production. When one more layer is targeted, the NPV is increased to 450,000 yuan with the smallest Langmuir volume at 8 m3/t, and largest Langmuir volume of 20 m3/t yields the highest NPV of 878,000 yuan over 30 years. Table 3 illustrates the effect of Langmuir volume on IRR and payback period. For single layer production, the internal rate of return (IRR) from the investment is 12.63%, slightly exceeding the 12% discount rate that is economically required by an investor. The Payback period is 4.8 years. All six cases of multiple seam CBM production achieve higher IRR (14.93–18.20%) and have shorter payback period (4.55–4.07 years), which are more economically attractive than single layer production.

Fig. 4. Gas rate of vertical well for different Langmuir volume of secondary reservoir.

Fig. 5. The effect of Langmuir volume on NPV of vertical well.

The economic results of three decision criteria indicate that Langmuir volume, which relates to the rank of the coal in the secondary layer, has relatively small effect on economic return and its value does not influence the comparative advantage of multiple seam CBM production over single layer production.

3.1.2. Effect of desorption pressure Desorption pressure is also an important parameter as desorption occurs when the pore pressure is reduced below the desorption pressure. It also controls the gas content when the adsorption isotherm is known. Six cases with different desorption pressure of 1 MPa, 2 MPa, 3 MPa, 4 MPa, 4.5 MPa, 5 MPa were modelled, which corresponds to gas content of 3.8 m3/t, 6.0 m3/t, 7.5 m3/t, 8.6 m3/t, 9.0 m3/t, 9.4 m3/t, respectively. Desorption pressure of the primary reservoir is 4 MPa, which corresponds to 8.6 m3/t in gas content. Other reservoir parameters are presented in Table 2. Fig. 6 shows gas production rates of single layer production (red solid line) and six cases of co-production from two coal seams (dotted lines) with varied desorption pressure of the secondary reservoir. The results show that when the desorption pressure of the secondary reservoir is too low at 1 MPa, it barely contributes to the overall production as the gas rate is almost the same with single layer production. This is because the gas content in the secondary reservoir is low and the reservoir pressure needs to be drawn down below 1 MPa before gas can be produced. The peak gas rate of single layer production is 2660 m3/d. When the desorption pressure is increased to 2 MPa, the peak gas rate is 2690 m3/d. It is increased to 3190 m3/d when desorption pressure of the secondary reservoir reaches 5 MPa. The economic viability of different cases are obtained based on the production rates. Fig. 7 shows the NPV as a function of time for the six cases of multiple seam CBM production (dotted lines) with different desorption pressure and one case of single layer production (red solid line). Desorption pressure (or gas content) has large impact on NPV. When desorption pressure of secondary reservoir is as low as 1 MPa (gas content of 3.8 m3/t), its after-tax NPV becomes negative and lower than single layer production (82,400 yuan), due to the increased costs whereas almost no production increase. When desorption pressure is increased to 2 MPa (gas content of 6 m3/t), NPV becomes slightly higher than single layer production after about 20 years and the final NPV is 138,000 yuan. Largest desorption pressure at 5 MPa provides the highest NPV of about 1,000,000 yuan over 30 years. Table 4 shows the effect of desorption pressure on IRR and payback period. Consistent with the NPV results, desorption pressure has large effect on IRR and payback period. For multiple seam CBM production with desorption pressure of the secondary reservoir at 1 MPa, the IRR is 11.47%, which is lower than the 12% dis-

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Y. Wu et al. / International Journal of Mining Science and Technology xxx (2018) xxx–xxx Table 3 The effect of Langmuir volume on IRR and Payback period for vertical well. Parameters

Single layer production

IRR (%) Payback period (Years)

12.63 4.80

Co-production of two coal seams Langmuir volume of secondary reservoir (m3/t) 8

10

12

15

18

20

14.93 4.55

15.47 4.50

15.92 4.47

16.49 4.43

16.95 4.41

18.20 4.07

a combination of NPV, IRR and payback period results suggest higher minimum desorption pressure or higher gas content is required for targeting an extra layer.

Fig. 6. Gas rate of vertical well for different desorption pressure of secondary reservoir.

Fig. 7. The effect of desorption pressure on NPV of vertical well.

count rate, making it unfavorable for investors. When desorption pressure is increased to 2 MPa, though it has slightly higher IRR (12.89%) than single layer production, the payback period is longer than single layer production. Only when desorption pressure of secondary reservoir is increased to as high as 3 MPa, all three economic indicators suggest significant improvements in economic feasibility of multiple seam CBM production than the single layer production. The largest desorption pressure at 5 MPa yields 18.2% IRR and payback period is decreased to 4.07 years. The economic results suggest desorption pressure, which is closely related to gas content, has significant impact on economic return. If the investor resorts to NPV as a sole criteria in economic assessment, a minimum desorption pressure of secondary reservoir is required and should be evaluated for the real case. However,

3.1.3. Effect of reservoir porosity Fig. 8 shows the effect of reservoir porosity on gas rates. The cleat porosity for primary reservoir is 1%. For multiple seam CBM production, five cases with different reservoir porosity of the secondary reservoir at 0.1%, 0.2%, 0.5%, 1%, 2% were considered in the analyses below. The results show that all five cases of multiple seam CBM production experience increase in gas production and reservoir porosity is negatively correlated with gas production. This is because coalbed reservoirs are almost fully water saturated (or nearly so) at initial conditions, increasing cleat porosity means higher water production rates and the longer time required to dewater the reservoir, because dewatering process is prolonged and gas relative permeability stays low that results in lower gas production rates. For co-production from two coal seams, the peak gas rate is increased from 2730 m3/d to 3870 m3/d when the cleat porosity of the secondary reservoir is decreased from 2% to 0.1%. The economics are studied for the effect of cleat porosity on co-production. As shown in Fig. 9, cleat porosity has great impact on NPVs and larger reservoir porosity results in smaller NPV. All five cases of multiple seam CBM production enhance NPVs than single layer production. When one more layer is targeted, the NPV is increased to 478,000 yuan with secondary reservoir porosity at 2%, and secondary reservoir porosity at 0.1% provides highest NPV of 1,380,000 yuan over 30 years.

Fig. 8. Gas rate of vertical well for different reservoir porosity of secondary reservoir.

Table 4 The effect of desorption pressure on IRR and Payback period for vertical well. Parameters

Single layer production

IRR (%) Payback period (Years)

12.63 4.80

Co-production of two coal seams Desorption pressure of secondary reservoir (MPa) 1

2

3

4

4.5

5

11.47 5.22

12.89 5.03

14.62 4.79

16.49 4.43

17.37 4.25

18.20 4.07

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Fig. 10. Gas rate of vertical well for different reservoir permeability of secondary reservoir.

Fig. 9. The effect of reservoir porosity on NPV of vertical well.

Table 5 shows the effect of secondary reservoir cleat porosity on IRR and payback period. Larger reservoir porosity results in lower IRR and longer Payback period. All five cases of multiple seam CBM production have higher IRR (14.90–21.53%) and shorter payback period (3.34–4.78 years) than single layer production, which is favorable for operators. The economic results of three decision criteria indicate that cleat porosity of secondary reservoir has great effect on economic return, which are all improved over that of single layer production. 3.1.4. Effect of reservoir permeability Reservoir permeability is an important parameter which controls fluid flow rate in the reservoir. Fig. 10 shows the effect of cleat permeability on gas rate. The cleat permeability of the main layer is 3 md. Reservoir permeability for secondary reservoir is varied between 0.05 md and 6 md. It can be seen that reservoir permeability has great impact on gas production behavior. Larger reservoir permeability results in higher peak gas rates due to higher drainage efficiency. When reservoir permeability of secondary reservoir is as low as below 0.1 md (including 0.1 md), secondary reservoir has no contribution to the overall production as the gas rates are almost the same as the single layer production. However, when permeability is increased from 0.1 md to 1 md, the peak production rate is increased from 2680 m3/d to 2950 m3/d. The peak gas rate can be as high as 5340 m3/d when the secondary reservoir permeability reaches 6 md. Adding the production into the economic model, the effect of reservoir permeability on co-production economics are obtained. Fig. 11 shows seven cases of simulation results of corresponding NPVs. As shown in Fig. 11, the NPVs of three cases of multiple seam CBM production when permeability of secondary reservoir is below 0.1 md (including 0.1 md) are negative and lower than single layer production, thus are not economically feasible. For the other three cases when permeability is varied between 1 md and 6 md, NPVs are much higher than single layer production between 731,000 yuan to 2,010,000 yuan. Table 6 shows the effect of reservoir permeability on IRR and payback period. Larger secondary reservoir permeability results in higher IRR and shorter payback period. When permeability of secondary reservoir is below 0.1 md (including 0.1 md), multiple

Fig. 11. The effect of reservoir permeability on NPV of vertical well.

seam CBM production have lower IRR than the 12% discount rate which is economically required and have longer payback period than single layer production, which further suggests that these cases of investment are not economically feasible. The economic results indicate reservoir permeability has significant impact on economic return and a minimum value of reservoir permeability (1md in this study) is required to make multiple seam CBM production economically feasible.

3.1.5. Effect of coal seam thickness To study the impact of coal seam thickness, five cases of multiple seam CBM production were modelled with thickness of the secondary reservoir ranging from 1 m to 5 m. The coal seam thickness of main layer is 5 m. As shown in Fig. 12, multiple seam CBM production have higher gas production rates than single layer production and larger coal seam thickness of the secondary reservoir generates higher peak gas rates. This is caused by the difference in the initial gas in place with variable coal seam thickness. The production rate is inputted into the economic model to study the effect of coal seam thickness on co-production economics. Fig. 13 shows simulated NPVs of the five cases of multiple seam CBM production and one case of the single layer production. All cases of multiple seam CBM production yield positive and higher NPV than single layer production. With 1 m coal seam

Table 5 The effect of reservoir porosity on IRR and Payback period for vertical well. Parameters

Single layer production

IRR (%) Payback period(Years)

12.63 4.80

Co-production of two coal seams Cleat porosity of secondary reservoir 0.1%

0.2%

0.5%

1%

2%

21.53 3.34

20.18 3.58

18.13 4.01

16.49 4.43

14.90 4.78

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Y. Wu et al. / International Journal of Mining Science and Technology xxx (2018) xxx–xxx Table 6 The effect of reservoir permeability on IRR and Payback period for vertical well. Parameters

Single layer production

IRR (%) Payback period(Years)

12.63 4.80

Co-production of two coal seams Permeability of secondary reservoir (md) 0.05

0.1

1

2

4

6

11.16 5.25

11.34 5.21

16.49 4.43

19.78 3.76

23.41 3.19

25.70 2.90

cases as considered as those applied above for vertical wells. The horizontal well drilling in the different seams use the same vertical section, so that drilling cost is saved.

Fig. 12. Gas rate of vertical well for different coal seam thickness of secondary reservoir.

thickness of secondary reservoir targeted, the NPV within 30 years almost doubled compared to single layer production at 154,000 yuan. Larger coal seam thickness generates higher NPV. Thickness of the secondary coal seam of 5 m can generate NPV as high as 1,280,000 yuan. Table 7 shows the effect of coal seam thickness on IRR and payback period. Though all cases of multiple seam CBM production have higher IRR than single layer production, the Payback period for case with 1 m coal seam thickness is longer than single layer production. 3.2. Effects of various reservoir parameters on horizontal well To study the effects of various reservoir parameters on horizontal well, a relatively larger model has been developed. A grid system of 50  49  3 was applied (the numbers refer to the grid system in X, Y, Z directions), with the same grid size being 20 m  20 m in the X and Y directions. The controlled reservoir area is 1000 m  980 m. Horizontal well length was set at 1000 m without fracturing. Though 7300-day-period production is simulated, production of only 1000 days to 2500 days is presented here as difference in gas rate is much larger in early time for horizontal well. Impact of reservoir properties of the secondary coal seam on gas production economics using horizontal well is studied and similar

Fig. 13. The effect of coal seam thickness on NPV of vertical well.

3.2.1. Effect of Langmuir volume Fig. 14 shows the effect of Langmuir volume on gas production rates of single layer production (red solid line) and co-production of two coal seams (dotted lines) of horizontal well. Langmuir volume of primary reservoir is 15 m3/t as shown in Table 2. Six cases for multiple seam CBM production with Langmuir volume of secondary reservoir ranging from 8 m3/t to 20 m3/t were modelled. The production profiles for multiple seam CBM production vary significantly with single layer production. Multiple seam CBM production have higher peak gas rates and decline more slowly than single layer production. For single layer production, it reaches peak gas rate of 50,500 m3/d quickly at 120 days and the gas rate declines rapidly. For multiple seam CBM production, larger Langmuir volume of the secondary reservoir results in higher gas production, and later peak arrival time. This is because in the simulation, the pump capacity is fixed therefore the maximum dewatering rate is fixed, which prolongs the dewatering process and the peak rate arrival time. The Langmuir volume of 20 m3/t has the largest peak gas rate of 57,900 m3/d. The production rate results are entered into the economic model to investigate the effect of Langmuir volume on coproduction economic profitability. Fig. 15 shows the NPVs of the seven cases, including six cases of multiple seam CBM production and one case of single layer production of horizontal well. The NPVs for all cases are positive within 30 years of production and they reach plateau around 20 years. The single layer production of horizontal well can yield NPV of 7,300,000 yuan over 30 years. Multiple seam CBM production have higher NPVs from 9,550,000 yuan to 14,000,000 yuan with Langmuir volume of the secondary reservoir ranging from 8 m3/t to 20 m3/t. The effect of Langmuir volume on IRR and payback period of horizontal well is presented in Table 8. For single layer production, the internal rate of return IRR from the investment (IRR = i for NPV = 0) is 25.39%, exceeding the 12% discount rate which is economically required. The payback period is 2.94 years. All six cases of multiple seam CBM production achieve higher IRR and shorter payback period than single layer production. The economic results of three decision criteria indicate that Langmuir volume has relatively small effect on co-production economic return and its value does not influence the comparative advantage of multiple seam CBM production over single layer production of horizontal well. 3.2.2. Effect of desorption pressure Fig. 16 shows the effect of desorption pressure on gas rate of horizontal well. Multiple seam CBM production have similar production profile with single layer production, though peak time are generally delayed due to the fixed dewatering rate as discussed in the previous section. Among six cases of co-production of two coal seams, four cases with desorption pressure of secondary reservoir larger than 2 MPa (including 2 MPa) have higher peak gas rates than single layer production. Desorption pressure of sec-

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Table 7 The effect of coal seam thickness on IRR and Payback period for vertical well. Parameters

Single layer production

IRR (%) Payback period (Years)

12.63 4.80

Co-production of two coal seams Coal seam thickness of secondary reservoir (m) 1

2

3

4

5

13.05 4.88

14.88 4.63

16.49 4.43

17.91 4.29

19.16 4.18

Fig. 14. Gas rate of horizontal well for different Langmuir volume of secondary reservoir.

Fig. 15. The effect of Langmuir volume on NPV of horizontal well.

ondary reservoir at 1 MPa has the lowest peak gas rate of 43,000 m3/d. The calculated production behavior is inputted into the economic model to compare the economic profitability of multiple seam CBM production and single layer production. Fig. 17 shows the effect of desorption pressure on NPVs. The desorption pressure of the secondary reservoir at 1 MPa yields the lowest NPV at 6,210,000 yuan, which is lower than single layer production. Other five cases of multiple seam CBM production have higher NPV than single layer production. The highest NPV case is the case with desorption pressure of 5 MPa (with an NPV of 14,170,000 yuan). Table 9 shows the effect of desorption pressure on IRR and payback period of horizontal well. Different to the NPV results, two cases of multiple seam CBM production with desorption pressure of the secondary reservoir at 1 MPa and 2 MPa have lower IRR (21.53% and 24.61% respectively) and longer payback period (3.36 years and 3.01 years respectively) than single layer production. Other four cases of multiple seam CBM production have higher IRR and shorter payback period than single layer production, thus are economically feasible and can be more profitable. The economic results indicate desorption pressure has significant impact on co-production economic outcome of horizontal well. If the investor resort to NPV as a sole criteria in economic assessment, a minimum desorption pressure of secondary reservoir at 2 MPa is required in this case. However, IRR and Payback period results suggest 3 MPa is preferred minimum desorption pressure for targeting an extra layer. 3.2.3. Effect of reservoir porosity Fig. 18 shows the effect of cleat porosity of the secondary reservoir on gas rates of horizontal well. The production rates for

Table 8 The effect of Langmuir volume on IRR and Payback period for horizontal well. Parameters

Single layer production

IRR (%) Payback period (Years)

25.39 2.94

Co-production of two coal seams Langmuir volume of secondary reservoir (m3/t) 8

10

12

15

18

20

26.21 2.90

27.47 2.76

28.64 2.64

30.31 2.48

31.89 2.34

32.91 2.26

Fig. 16. Gas rate of horizontal well for different desorption pressure of secondary reservoir.

Fig. 17. The effect of desorption pressure on gas rate of horizontal well.

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Y. Wu et al. / International Journal of Mining Science and Technology xxx (2018) xxx–xxx Table 9 The effect of desorption pressure on IRR and Payback period for horizontal well. Parameters

Single layer production

IRR (%) Payback period (Years)

25.39 2.94

Co-production of two coal seams Desorption pressure of secondary reservoir (MPa) 1

2

3

4

4.5

5

21.53 3.36

24.61 3.01

27.53 2.72

30.31 2.48

31.65 2.38

32.94 2.29

Table 10 The effect of reservoir porosity on IRR and Payback period for horizontal well. Parameters

Single layer production

IRR (%) Payback period (Years)

25.39 2.94

Co-production of two coal seams Reservoir porosity of secondary reservoir 0.1%

0.2%

0.5%

1%

2%

37.68 1.94

35.74 2.06

32.75 2.28

30.31 2.48

27.78 2.72

Fig. 18. Gas rate of horizontal well for different reservoir porosity of secondary reservoir.

multiple seam CBM production vary significantly with single layer production. Larger reservoir porosity yields lower peak gas rate and later peak time. Largest reservoir porosity of 2% has the lowest peak gas rate of 45,100 m3/d. This is because pump capacity is limited in all cases, therefore, dewatering the primary and secondary reservoir is prolonged with larger porosity in the secondary reservoir, leading to lower peak rate. Other four simulated cases of multiple seam CBM production have higher peak gas rates than single layer production. Smallest reservoir porosity of 0.1% yields highest peak gas rate of 71,200 m3/d, as dewatering of the secondary reservoir is more efficient and the contribution of gas production from the secondary reservoir becomes significant. The production rate is inputted into the economic model to compare the economic profitability of multiple seam CBM production and single layer production. Fig. 19 shows the effect of reservoir porosity on NPVs. All cases of multiple seam CBM production yield positive and higher NPV than single layer production over 30 years. The NPV of multiple seam CBM production with smallest reservoir porosity at 0.1% more than doubled (of 15,850,000 yuan) compared to single layer production (of 7,300,000 yuan). The largest reservoir porosity at 2% yields the lowest NPV of 10,840,000 yuan. Table 10 shows the effect of reservoir porosity on IRR and payback period of horizontal well. Larger reservoir porosity results in

Fig. 19. The effect of reservoir porosity on NPV of horizontal well.

Fig. 20. Gas rate of horizontal well for different reservoir permeability of secondary reservoir.

lower IRR and longer payback period. All five cases of multiple seam CBM production achieve higher IRR (27.78–37.68%) and shorter payback period (1.94–2.72 years) than single layer production, thus are more economically attractive than single layer production. The economic results suggest reservoir porosity has large impact on economic return and within a certain value range (0.1–2%), multiple seam CBM production has comparative advantage over single layer production. 3.2.4. Effect of reservoir permeability The results of the production simulations of varied reservoir permeability of the secondary reservoir are presented in Fig. 20. For multiple seam CBM production, when permeability of the secondary reservoir is as low as below 0.1 md (including 0.1 md), the gas production rates are almost the same as the single layer production. For the other three cases of multiple seam production when permeability of secondary reservoir is high enough above 0.1 md, targeting one more layer improve the gas production. The peak gas rate is increased from 58,000 m3/d to 58,800 m3/d and stays high for longer period of time when permeability is increased from 2 md to 6 md. The production rate is inputted into the economic model to compare the economic profitability of multiple seam CBM production and single layer production. Fig. 21 shows the effect of reservoir permeability on NPV of horizontal well. Higher reservoir permeability generates higher NPV. Two cases of multiple seam CBM production when reservoir permeability is lower than 0.1

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Fig. 21. The effect of reservoir permeability on NPV of horizontal well.

md (including 0.1 md) have lower NPV than single layer production. Largest reservoir permeability at 6 md yields the highest NPV of 20,460,000 yuan. Table 11 shows the effect of reservoir permeability on IRR and Payback period of horizontal well. Larger reservoir permeability results in higher IRR and shorter payback period. Consistent with NPV results, three cases of multiple seam CBM production with reservoir permeability of secondary reservoir lower than 0.1 md (including 0.1 md) have lower IRR and longer payback period than single layer production, thus targeting one more layer is not economically desirable. Other three cases of multiple seam CBM production have higher IRR and shorter payback period than single layer production, thus are economically favorable. The economic results indicate reservoir permeability has significant impact on economic return of horizontal well and a minimum value of the secondary reservoir permeability (1 md in this study) is required to make multiple seam CBM production more attractive than single layer production.

3.2.5. Effect of coal seam thickness of horizontal well Fig. 22 shows the effect of coal seam thickness on gas rates of horizontal well. Five cases of multiple seam CBM production with varied coal seam thickness of secondary reservoir ranging from 1 m to 5 m are modelled. Multiple seam CBM production have similar gas production profiles with single layer production, with higher peak gas rates and later peak time than single layer production. The largest coal seam thickness of 5 m has the highest peak gas rate of 57,200 m3/d. Fig. 23 shows the effect of coal seam thickness on NPV of horizontal well. Larger coal seam thickness results in higher NPV. When secondary layer is too thin at 1 m, multiple seam CBM production has almost the same NPV of single layer production. However, when the thickness of secondary reservoir is larger than 2 m (including 2 m), the NPVs of multiple seam CBM production are significantly larger than single layer production. The largest coal seam thickness of 5 m can yield highest NPV of 17,010,000 yuan. Table 12 shows the effect of coal seam thickness on IRR and Payback period. Larger coal seam thickness results in higher IRR and shorter payback period. Multiple seam CBM production with coal seam thickness of the secondary reservoir at 1 m has lower IRR (23.23%) and longer payback period (3.17 years) than single

Fig. 22. Gas rate of horizontal well for different coal seam thickness of secondary reservoir.

Fig. 23. The effect of coal seam thickness on NPV of horizontal well.

Table 12 The effect of coal seam thickness on IRR and Payback period for horizontal well. Parameters

Single layer production

IRR (%) Payback period (Years)

25.39 2.94

Co-production of two coal seams Coal seam thickness of secondary reservoir (m) 1

2

3

4

5

23.23 3.17

26.88 2.79

30.31 2.48

33.48 2.23

36.35 2.04

layer production, thus is not economically attractive. Other three cases of multiple seam CBM production have higher IRR and shorter payback period than single layer production. In general, thicker secondary reservoir will achieve more favorable economic results and a minimum value of coal seam thickness (2 m in this study) is required to make multiple seam CBM production more economically attractive than single layer production. 3.3. Comparison of vertical well and horizontal well performance The production simulation and economic assessment of a single vertical well and horizontal well shown above have demonstrated large difference in production rates and economics. In order to help

Table 11 The effect of reservoir permeability on IRR and Payback period for horizontal well. Parameters

Single layer production

IRR (%) Payback period (Years)

25.39 2.94

Co-production of two coal seams Reservoir permeability of secondary reservoir (md) 0.05

0.1

1

2

4

6

21.81 3.33

22.82 3.21

30.31 2.48

35.07 2.16

41.07 1.88

44.18 1.75

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Y. Wu et al. / International Journal of Mining Science and Technology xxx (2018) xxx–xxx

of the whole gas field using horizontal well is about three times that of the field using vertical wells. Fig. 25 shows the NPV results of using vertical wells (blue line) and horizontal wells (green line). Using horizontal wells has significantly enhanced profitability than using vertical wells especially for single layer production (solid line). The time when NPV becomes positive between single layer production and multiple seam CBM production of using vertical wells is more than five years for the whole field, while that of using horizontal wells is less than one year. The IRR and payback period results of using horizontal wells and vertical wells are illustrated in Table 13. It clearly indicates that horizontal wells outperform vertical wells as IRR of using horizontal wells is more than doubled that of using vertical wells. Therefore, using horizontal wells is more preferable in economics. Fig. 24. Gas rates comparison of vertical well and horizontal well.

3.4. Sensitivity analysis

Fig. 25. NPV for gas field project.

decide whether to drill a horizontal well or a vertical well, vertical and horizontal well performance were compared within same drainage area. 36 horizontal wells and 245 vertical wells were applied to cover a gas field of about 35.4 km2. Therefore, the whole area productivity is equal to the single well productivity multiplied by the number of wells. The gas rate results of the gas field are shown in Fig. 24. The increase in gas production rates of horizontal well is dramatic in the beginning of extraction due to high drainage efficiency from the increased formation exposures. The peak gas rate

The above economic viability studies are based on the basic assumptions of economic inputs presented in Table 1. To account for variations of economic performance depending on different input data, sensitivity analyses of the critical economic parameters are performed to understand risks associated with input uncertainty. Uncertainties considered include variations in wellhead price, operating costs and government subsidy. The base case listed in Table 2 is used to compare the single layer production and multiple seam CBM production. The NPV results of single vertical well and horizontal well with varying levels of economic parameters are shown in Figs. 26 and 27 respectively. The results illustrated that wellhead price has the most significant effect on the NPV, followed by operating costs and government subsidy. For vertical well, the economic feasibility of single layer production is highly sensitive to the variable change. Small change in the three variables (around 5%) will result in negative NPV, making the investment unprofitable. While multiple seam CBM production have far better results, only when the wellhead price decreases more than 15%, the NPV becomes negative. In regard to horizontal well, both single layer production and multiple seam CBM production give positive NPV within 20% change of the three variables. Thus, though the results of economic analysis are subject to restrictive assumptions, multiple seam CBM production can be highly possible to maintain profitability compared with single layer production.

Table 13 IRR and Payback period comparison of using vertical wells and horizontal wells for gas field. Parameters

IRR (%) Payback period (Years)

Single layer production

Co-production of two coal seams

Vertical well

Horizontal well

Vertical well

Horizontal well

12.63 4.80

25.39 2.94

16.49 4.43

30.31 2.48

Fig. 26. NPV of vertical well sensitivities.

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Y. Wu et al. / International Journal of Mining Science and Technology xxx (2018) xxx–xxx

Fig. 27. NPV of horizontal well sensitivities.

4. Conclusions In this study, production rates and economics of gas production from a primary single coal seam and a secondary coal seam using both vertical well and horizontal well are investigated to understand the economics of gas co-production from multiple coal seams. Impact of key reservoir properties of the secondary coal seam, including gas storage and flow properties, on production and economics are investigated. Comparison between using vertical wells and horizontal wells at gas field scale is performed. Although the results of economic analysis are subject to assumptions both on reservoir properties and economic analyses input, the following conclusions can be made: (1) In general, multiple seam CBM production has competitive advantage over single layer production as the economic profitability are significantly enhanced by targeting one more layer. However, the reservoir properties of the secondary coal seam, such as gas content and permeability, has significant impact on the economics. When desorption pressure (or gas content) and reservoir permeability are too low, targeting one more layer become less economically attractive than single layer production for both vertical well and horizontal well, even though the gas production rates are enhanced. (2) Horizontal well can significantly enhance economic profitability than vertical well, for both single well and for a gas field. Therefore, horizontal well is a more favorable well type for developing gas co-production from multiple coal seams. (3) Gas price has the most significant effect on the economic results, followed by operating costs and government subsidy for both single layer production and multiple seam CBM production. Acknowledgments Support from CSIRO Energy is acknowledged. A scholarship from the China Scholarship Council for the first author is acknowledged.

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