- Email: [email protected]
Regional- to Reservoir-scale Evaluation of CO2 Storage Resource Estimates of Coal Seams
Available online at www.sciencedirect.com
ScienceDirect Energy Procedia 114 (2017) 5346 – 5355
13th International Conference on Greenhouse Gas Control Technologies, GHGT-13, 14-18 November 2016, Lausanne, Switzerland
Regional- to reservoir-scale evaluation of CO2 storage resource estimates of coal seams Qian Zhanga,b, Kevin M. Elletta, *, John A. Ruppa, Maria Mastalerza, C. Özgen Karacanc a
Indiana Geological Survey, Indiana University, 611 N. Walnut Grove Ave., Bloomington, IN 47405, USA b Department of Geological Sciences, Indiana University, 1001 E. 10th St., Bloomington, IN 47405, USA c Office of Mine Safety and Health Research, NIOSH, 626 Cochrans Mill Rd., Pittsburgh, PA 15236, USA
Abstract Unmineable coal seams are an important target for investigating the economic viability of carbon capture and storage technology owing to their potential for simultaneous CO2 storage and enhanced coalbed methane production. As such, recent developments in integrated system models are aiming to explicitly incorporate coal seam storage and enhanced methane production into their economic analyses, however, such implementation currently relies on fairly uncertain prospective resource estimates derived from regional-scale analyses. In this paper, we evaluate the uncertainty of such prospective resource estimates, both for CO2 storage and for CO2 utilization potential (i.e., enhanced coalbed methane production from CO2 injection) via comparison to results from more detailed, local-scale reservoir simulations at numerous locations. Reservoir-scale simulations incorporate the dynamic system response to CO2 injection, whereas regional-scale prospective resource estimates rely on volumetric calculations of original gas-in-place from static geological models combined with assumed recovery factors. Results based on a case study of 12 different locations in the Illinois Basin, USA suggest that prospective resource estimates for CO2 storage may be systematically biased towards over-estimation. By developing a set of low-, mid-, and high-range estimates from model simulations, a total of 36 comparisons were made to the prospective resource estimates, of which 35 showed significantly lower results for the model-based estimates. Model sensitivity testing of variable CO2 injection rates indicated that the requirement to maintain reservoir pressure below the fracture gradient threshold is in part responsible for the lower limit of storage resource estimates obtained from the reservoir simulation results versus the prospective resource methodology which neglects such processes. In terms of enhanced methane recovery, results were far more comparable between the two methods for the low- and mid-range set of estimates, whereas the high-range estimates were still notably larger using the prospective resource methodology. We conclude that utilizing prospective resource estimates of enhanced coalbed methane potential in integrated system models appears feasible for the more conservative range of estimates, whereas CO2 storage estimates of coal seams are likely to produce overly optimistic results in the system model. We also note that for the Illinois Basin case study, both the modelling results and the regional-scale results indicate that a significant amount of additional well drilling beyond the existing
* Corresponding author. Tel.: +1-812-856-3671; fax: +1-812-855-2862. E-mail address: [email protected]
1876-6102 © 2017 The Authors. Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/). Peer-review under responsibility of the organizing committee of GHGT-13. doi:10.1016/j.egypro.2017.03.1661
Qian Zhang et al. / Energy Procedia 114 (2017) 5346 – 5355
coalbed methane infrastructure would need to be conducted in order for coal seams to be a viable alternative to other options in the region such as oil and gas reservoirs and deep saline formations. © 2017 The Authors. Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND license © 2017 The Authors. Published by Elsevier Ltd. (http://creativecommons.org/licenses/by-nc-nd/4.0/). Peer-reviewunder underresponsibility responsibility organizing committee of GHGT-13. Peer-review ofof thethe organizing committee of GHGT-13. Keywords: Resrvoir Modelling; Enhanced Coal Bed Methane; System Analysis; Illinois Basin
1. Introduction The advent of integrated system modelling tools for evaluating carbon capture and storage (CCS) technology implementation provides an intriguing new development towards facilitating decision-making on potential CCS projects [1]. Previous studies have suggested that coal seams may have a significant capacity for CO2 storage throughout the world [2-3] with the additional economic advantage of potential enhanced coalbed methane production (ECBM) because of the preferential adsorption of CO2 versus methane. Thus the incorporation of coal seam storage and ECBM processes into CCS system modelling tools would be an important improvement towards greater utility of such tools. We are aware of one such development at present for which the explicit implementation of coal seam storage and ECBM potential currently relies on prospective resource estimates derived from regional-scale analyses using a volumetric-based approach [4]. The focus of this study is to evaluate the uncertainty of such prospective resource estimates, both for CO2 storage and for ECBM via comparison to results from more detailed, local-scale reservoir simulations at numerous locations across the Illinois Basin, USA. This paper is a companion to a similar study on conventional oil and gas reservoirs [5], both of which support a new integrated systems model analysis for the Illinois Basin, USA [4]. Reservoir-scale simulations have the advantage of incorporating the dynamic system response to CO2 injection, whereas regional-scale prospective resource estimates rely on volumetric calculations of original gas-in-place from static geological models combined with assumed recovery factors. To date there have been numerous studies regarding coalbed methane production (CBM) and ECBM, but most studies are limited to laboratory experiments and reservoir simulations [5-10]. Insight from actual field tests of the ECBM process and CO2 storage in various coal seams is still fairly limited. One exception is the first and largest pilot CO2-ECBM test that was conducted in the San Juan Basin in the southwestern USA in which a total of 277 kt of CO2 was injected over a five-year period [11]. The authors noted that methane recovery was improved from 77 percent to 95 percent of the original gas in place at the Allison Unit [11]. For the Illinois Basin, only a single, small pilot test has been conducted at the Tanquary test site using one injection well and three monitoring wells [12]. The authors report a continuous injection of about 102 tons of CO2 from July, 2008 through December, 2008 with no CO2 breakthrough occurring at the monitoring wells [12]. Given the lack of available empirical results from field injection testing, particularly for our study area of the Illinois Basin, it is expected that the currently available prospective resource estimates are highly uncertain. Thus we have undertaken the following modelling-based study to evaluate this uncertainty with the goal of better informing the accurate implementation of coal seam storage and ECBM processes within the systems modelling approach.
2. Model Development 2.1. Study Area Reservoir-scale simulations of selected coal seams were conducted for a case study exploring the potential for postcombustion CO2 capture at a coal-fired power plant site in the Illinois Basin (Figure 1). Preliminary site screening led to the selection of 15 candidate sites for stacked reservoir storage, 12 of which were deemed to have potential for coal seam storage and ECBM. The commercial reservoir simulator GEMTM v.2015 (Computer Modeling Group Ltd) was used to evaluate the CO2 storage and methane production processes of up to seven coal seams at each of the 12
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geographic sites. An idealized, inverted five-spot pattern model with a dual porosity/permeability system was used for this study. The model was developed based on parameter evaluation and calibration to production data from an existing CBM operation in Sullivan County, Indiana (2007–2013) to ensure that results were consistent with a larger, heterogeneous reservoir model developed for this specific region [13]. This idealized model was then applied at the other potential storage locations in the study area where critical parameters such as coal seam depths and thicknesses had been mapped (Table 1) [14] but CBM production data were not available for comparison. Reservoirs were assumed to be normally pressured (i.e., hydrostatic conditions) and reservoir temperature was calculated based on a recent analysis of geothermal gradient across the Illinois Basin [15].
Fig. 1. Map of the study area in the Illinois Basin showing the coal-fired power plant at center of map (yellow star) and 15 specific sites that are being considered for their stacked CO2 storage and utilization potential (including the power plant site). Colors indicate the relative amount of enhanced coalbed methane potential estimated from a regional-scale prospective resource assessment (red is low, green-to-blue is high; yellow indicates region where coal seams are deemed unmineable and are thus excluded from consideration for CCS).
2.2. Sensitivity Analysis Once CO2 is injected into coal seams, it invades the pore space and adsorbs at solid-fluid interfaces and preferentially displaces methane. This process allows for CO2 storage in coals as well as enhanced gas recovery. Results from prior research suggest that the performance of enhanced coalbed methane recovery operations is dependent on many factors, including matrix/fracture permeability, cleat spacing, initial water saturation, wellbore skin effects, and Langmuir adsorption constants. To test the importance of these parameters on our model results for Illinois Basin coals, a sensitivity study was conducted using the reservoir model for the node 9 location in our study.
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The parameter ranges implemented in the sensitivity analysis (Table 2) represent a plausible extent of variability around the median, base-case value given the available data on coal seams in our study area [12-14]. Table 1. Model parameters for coal reservoir simulations. Site Information Depth (m) Thickness (m) Temperature (°C) Pressure (kPa)
Node 1
Node 2
Node 3
Node 4
Node 5
Node 6
Node 9
Node 10 Node 11
Node 12 Node 13 Node 14
259
320
198
259
198
381
229
381
320
381
259
137
5
4
5
4
5
5
7
4
7
5
5
2
20
22
18
20
18
24
20
24
22
24
20
17
2621
3214
2028
2621
2028
3807
2621
3807
3214
3807
2621
1435
Table 2. Summary of parameter ranges used for model sensitivity analysis. Parameters
Low
Median
High
Fracture permeability (md)
30
65
100
Cleat spacing (mm) Initial water saturation (%)
0.65 0.85
1.5 0.88
10 0.9
Wellbore skin (-)
-0.8
0
1
Langmuir Constants
Test 1
Test 2
Test 3
CH4 VL (scf/ton)
533
354
640
CH4 PL (psi)
512
276
464
CO2 VL (scf/ton)
1088
743
1089
CO2 PL (psi)
226
135
332
The results showed that among all tested parameters, fracture permeability was the most influential factor for methane production (Figure 2a). This is because after methane desorbs from coal seams, a higher fracture permeability allows better gas flow conduits, and thus favors methane production. Langmuir constant and wellbore skin factors also have substantial impacts on the cumulative methane production (Figures 2b and 2c). Increased methane production was observed with negative skin factor, due to enhanced gas flow near the wellbore. Initial water saturation also has limited effects; as higher water saturation leads to decreased methane production (Figure 2d). Cleat spacing was found to have minimal impact on methane production (Figure 3e).
3. Reservoir Simulations Given the dominant control of fracture permeability on simulation results, a set of low, medium, and high fracture permeability cases were evaluated at each site in the study, along with four different operational scenarios using different cutoff criteria for the CO2 injection operation: (1) the amount of CO2 being produced exceeds the amount of methane produced at the same time; (2) CO2 production rate exceeds 50 percent of the injection rate; (3) full CO2 injection for a set period of five years; and (4) extended CO2 injection operation until the enhanced methane production rate declines completely to the non-CO2, base-case methane production rate. While scenarios 1 to 3 represent varying operational decisions, scenario 4 is considered the most objective criteria in that CO2 operations cease at the point when further injection is no longer effective at driving any enhanced methane production.
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Fig. 2. Line graphs illustrating the effects of various factors on cumulative methane production. (a) fracture permeability; (b) Langmuir constants; (c) wellbore skin factor; (d) initial water saturation; (e) cleat spacing.
The base-case model scenario used to quantify the difference from, and thus effectiveness of the CO2 injection operations followed the CBM production history of Karacan et al. [13] with simply extending the methane production operation from July, 2007 to October, 2018. For the CO2 injection case, the first 6 years of reservoir operations follow the same history as the base-case simulation and then switch over to CO2 injection for a period of five years from October, 2013 to October, 2018. Injection rate was set to be a constant of 250 m3/day based on the Tanquary pilot test [12]. Three different cases of low-, mid-, and high-range fracture permeability were run for each of these simulation scenarios. In this way, the model was used to generate results for comparison to the equivalent ranges of resource estimates derived from regional-scale analyses.
3.1. Effects of CO2 injection on cumulative methane production Model results from node 9 provide an example of how CO2 injection impacts methane production from coals in our study area (Figure 3). For the base case, a total of 20.08, 21.6, and 22.23 MMscf methane was produced during
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the 11-year production in the low-, medium-, and high-range cases, respectively (Figure 3a). By comparison, for the enhanced recovery with CO2 injection, the cumulative methane production increased to 23.05, 24.45, and 24.74 MMscf, respectively (Figure 3b). Thus, the enhanced methane production was 2.97, 2.85, and 2.51 MMscf for the low-, medium-, and high-range cases, respectively. The corresponding ECBM recovery factors ranged from 11.3 percent to 14.8 percent, which are somewhat similar to but lower than the recovery factor estimated from the pilot test at the Tanquary site (~15 to 20 percent) [12].
Fig. 3. Line graphs comparing the influences from varying fracture permeability on cumulative methane production in the base-case model and the CO2 injection model.
3.2. Comparison with regional scale analyses For cutoff scenarios 1 to 3 listed above, regional-scale analyses were observed to overestimate the enhanced gas recovery potential relative to the reservoir simulation results for all the tested permeability cases. For instance, regional-scale ECBM potential was estimated to range from 0.125 MMscf/acre to 1.5 MMscf/acre, while reservoir simulation indicated the potential varying from 0.03 MMscf/acre to 0.2 MMscf/acre in those scenarios. A cross-plot of cutoff scenario 2 in which regional-scale analyses are plotted against simulation results (Figure 4), shows most of the data points located well below the 1:1 ratio line, indicating simulated results are significantly lower than the estimates from regional-scale analyses. However, in the case of cutoff scenario 4 with extended CO2 injection, reservoir-scale simulation results indicate that enhanced methane recovery in the low- and mid-range estimates is somewhat comparable to regional-scale results (on average, around 0.4 MMscf/acre or 0.028 MMm3/Ha; 15-20 percent recovery; Figure 5a–c). This result is also in reasonable agreement with the very limited results that were reported in the literature from CO2 injection pilot test studies [12]. However, when compared with the high-range, regional-scale analysis results, enhanced methane recovery from reservoir simulation is still much lower (Figure 5c). The total amount of CO2 stored in the coal seams is calculated by subtracting the amount of CO2 produced from wells in the model from the total amount of CO2 injected. With respect to CO2 storage, regional-scale results estimate that the storage resource in the twelve specific areas ranges from 100 to 1000 tonnes/acre (247 to 2470 tonnes/Ha). These regional estimates are significantly larger than our model results of <50 tonnes/acre (124 tonnes/Ha; Figure 6ac). Storage estimates from modelling indicate that using coal seams to achieve large-scale CO2 storage in the study area will require significant new well infrastructure beyond the existing CBM well infrastructure in the region.
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Fig. 4. Cross plots of scenario 2 for CO2-ECBM resource estimates between simulated results and regional-scale analysis (1 MMscf/acre = 0.07 MMm3/Ha): (a) low-range estimate; (b) mid-range estimate; (c) high-range estimate.
Fig. 5. Cross plots of scenario 4 for CO2-ECBM resource estimates between simulated results and regional-scale analysis (1 MMscf/acre = 0.07 MMm3/Ha): (a) low-range estimate; (b) mid-range estimate; (c) high-range estimate.
Fig. 6. Cross plots of scenario 4 for CO2 storage resource estimates between simulated results and regional-scale analysis (1 tonne/acre = 2.47 tonnes/Ha).
Qian Zhang et al. / Energy Procedia 114 (2017) 5346 – 5355
4. Discussion Results from this study suggest that the coal seam resource estimates that are currently being implemented into integrated system models appear to be reasonable for the CO2 utilization resource estimates (ECBM), but are overly optimistic for the CO2 storage resource estimates. The discrepancies between the two methods clearly highlight the limitations of the regional-scale approach wherein volumetric-based calculations are entirely static and are not capable of incorporating impacts from dynamic flow processes. For instance, the prescription of fixed original gas in place values, an assumed 5:1 ratio of CO2 to CH4 preferential adsorption displacement factor, and constant Langmuir adsorption isotherms all contribute to the differences observed between the two methods. There are also limitations to the idealized modelling approach and its assumptions. For example, model results assume an operational CO2 injection rate of 250 m3/day based on the single example of an actual injection operation in our study area (the Tanquery site pilot study). For a full five-year injection period and assuming no CO2 breakthrough, the maximum amount of CO2 that can be stored in such a case is inherently limited to 44.7 tonnes/acre. Therefore, we conducted additional model sensitivity analysis with the results confirming that increasing CO2 injection rates can ultimately promote higher levels of CO2 storage (Figure 7). However, results also illustrated that the maximum allowable reservoir pressure based on the fracture gradient criteria is a critical limitation to the ultimate amount of CO2 storage resource. For the example site shown in Figure 7, the fracture gradient threshold pressure would be reached at an injection rate of 2500 m3/day. At that injection rate, the amount of CO2 stored is 135 tonnes/acre. This model-based estimate, while indeed significantly higher than the result which assumed operational parameters identical to the Tanquery pilot test, is still far below the estimate from regional-scale calculations. Thus, we find that the requirement that reservoir pressure does not exceed the fracture gradient criteria effectively limits the CO2 storage resource of coal seams in our study area to values that are typically much lower than the regional-scale prospective resource estimates.
Fig. 7. Effects of increased injection rates on CO2 storage resource estimates, where circle indicates that the maximum allowable reservoir pressure has been reached at a depth of 229 m.
The impact of injection rates on the model estimates of ECBM resource was also tested (Figure 8). With full injection for five years in a medium permeability case, the maximum ECBM potential is approximately 0.2 MMscf/acre at the maximum injection rate of 2500 m3/day for this example site. This difference is only about 0.04 MMscf/acre higher than the result that assumes the Tanquery site operational injection rate of 250 m3/day. Thus, we conclude that our original assessment holds, whereby low- and mid-range ECBM resource estimates are comparable between the two methods, but high-range estimates are still significantly larger for the regional-scale analysis.
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Fig. 8. Scatter plot showing the impacts of increased injection rates on ECBM potential, where circle indicates that the maximum allowable reservoir pressure has been reached at a depth of 229 m.
5. Conclusions While CO2 storage and utilization for enhanced oil recovery in conventional reservoirs has a long history of empirical results from operational implementation, CO2 injection into unconventional reservoirs such as coal seams is at present an area of emerging R&D. Given the relative lack of results from field injection testing of CO2 in coal seams, it is expected that the currently available prospective resource estimates for CO2 storage and CO2 utilization for ECBM are highly uncertain. Thus we have undertaken a modelling-based study to evaluate this uncertainty by comparing regional-scale, volumetric-based resource estimates to results from detailed, local-scale reservoir simulation models for numerous sites across the Illinois Basin, USA. A specific goal of this study is to provide results that will better inform the accurate implementation of coal seam storage and ECBM processes within broader integrated CCS systems models that are currently under development. Results suggest that regional-scale prospective storage resource estimates are significantly biased towards overestimation, and thus may be unsuitable for application in CCS system models. In contrast, CO2 utilization resource estimates in the form of ECBM potential were quite comparable between the two methods so long as low- to midrange estimates are considered. In the case of extended CO2 injection (five-year period), reservoir simulation results indicate that ECBM potential is on average around 0.4 MMscf/acre of reservoir domain, which is comparable to the estimated 15 to 20 percent recovery factor for ECBM in regional-scale analyses. Model testing revealed that higher CO2 injection rates can increase ECBM potential as well as CO2 storage, but the maximum values are limited by the requirement to maintain reservoir pressure below the fracture gradient criteria. Volumetric-based approaches are not capable of accounting for such dynamic processes and this limitation can largely explain the observed differences in resource estimates between the two methods.
Acknowledgements This research was funded by the U.S.-China Clean Energy Research Center, Advanced Coal Technology Consortium (subcontract 10-733 of the West Virginia University Research Corporation). The authors wish to thank the Computer Modeling Group, Ltd. for their provision of a software license used in this study.
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References [1] Middleton RS, Bielicki JM. A scalable infrastructure model for carbon capture and storage: SimCCS. Energy Pol 2009;37:1052-60. [2] Gale J, Freund P. Coal-bed methane enhancement with CO2 sequestration: worldwide potential. Environ Geosci 2001;8:210–17. [3] Liu YF, Li XC, Bai B. Preliminary estimation of CO2 storage capacity of coalbeds in China. Chin J Rock Mech Eng 2005;24:2947–52. [4] Ellett KM, Middleton RS, Stauffer PH, Rupp JA. Facilitating CCS business planning by extending the functionality of the SimCCS integrated system model. Energy Proc 2017;this issue. [5] Wang S, Ellett KM, Ardekani AM. Assessing the utility of high-level CO2 storage and utilization resource estimates for CCS system modelling. Energy Proc 2017;this issue. [6] Jessen K, Tang GQ, Kovscek AR. Laboratory and Simulation Investigation of Enhanced Coalbed Methane Recovery by Gas Injection. Trans Por Med 2007;2:141-59. [7] Pekot LJ, Reeves SR. Modeling coal matrix shrinkage and differential swelling with CO2 injection for enhanced coalbed methane recovery and carbon sequestration applications. Pittsburgh: U.S. Department of Energy; 2002. [8] Prusty BK. Sorption of methane and CO2 for enhanced coalbed methane recovery and carbon dioxide sequestration. J Nat Gas Chem 2008;17:2938. [9] Harpalani S, Prusty, BK, Dutta P. Methane/CO2 sorption modeling for coalbed methane production and CO2 sequestration. Energy & Fuels 2006;20:1591-99. [10] Karacan CÖ. Heterogeneous sorption and swelling in a confined and stressed coal during CO2 injection. Energy & Fuels 2003;17:1595-1608. [11] Reeves S, Oudinot A. A technical and economic sensitivity study of enhanced coalbed methane recovery and carbon sequestration in coal. Pittsburgh: U.S. Department of Energy; 2004. [12] Finley R, Moulton S. Final report, midwest geological sequestration consortium (MGSC) phase II sequestration and enhanced coal bed methane: Tanquary farms test site, Wabash County, Illinois. Champaign: Illinois State Geological Survey; 2012. [13] Karacan CÖ, Drobniak A, Mastalerz M. Coal bed reservoir simulation with geostatistical property realizations for simultaneous multi-well production history matching: A case study from Illinois Basin, Indiana, USA. Int J Coal Geo 2014;131:71-89. [14] Mastalerz M, Rupp J, Drobniak A, Harpalani S, Anderson A, Korose C, Frailey S, Morse D. Assessment of CO2 sequestration and enhanced coalbed methane potential in unminable coal seams of the Illinois Basin, in Grobe M, Pashin JC, Dodge RL, eds, Carbon dioxide sequestration in geological media—State of the science: AAPG Studies in Geology 2009;59:149–71. [15] Proffitt TA, Ellett KM, Zuppann CW, Naylor S, Barrett ME, et al. Development and application of a new geothermal database for the Illinois Basin. Article 80277: American Association of Petroleum Geologists; 2013.
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ScienceDirect Energy Procedia 114 (2017) 5346 – 5355
13th International Conference on Greenhouse Gas Control Technologies, GHGT-13, 14-18 November 2016, Lausanne, Switzerland
Regional- to reservoir-scale evaluation of CO2 storage resource estimates of coal seams Qian Zhanga,b, Kevin M. Elletta, *, John A. Ruppa, Maria Mastalerza, C. Özgen Karacanc a
Indiana Geological Survey, Indiana University, 611 N. Walnut Grove Ave., Bloomington, IN 47405, USA b Department of Geological Sciences, Indiana University, 1001 E. 10th St., Bloomington, IN 47405, USA c Office of Mine Safety and Health Research, NIOSH, 626 Cochrans Mill Rd., Pittsburgh, PA 15236, USA
Abstract Unmineable coal seams are an important target for investigating the economic viability of carbon capture and storage technology owing to their potential for simultaneous CO2 storage and enhanced coalbed methane production. As such, recent developments in integrated system models are aiming to explicitly incorporate coal seam storage and enhanced methane production into their economic analyses, however, such implementation currently relies on fairly uncertain prospective resource estimates derived from regional-scale analyses. In this paper, we evaluate the uncertainty of such prospective resource estimates, both for CO2 storage and for CO2 utilization potential (i.e., enhanced coalbed methane production from CO2 injection) via comparison to results from more detailed, local-scale reservoir simulations at numerous locations. Reservoir-scale simulations incorporate the dynamic system response to CO2 injection, whereas regional-scale prospective resource estimates rely on volumetric calculations of original gas-in-place from static geological models combined with assumed recovery factors. Results based on a case study of 12 different locations in the Illinois Basin, USA suggest that prospective resource estimates for CO2 storage may be systematically biased towards over-estimation. By developing a set of low-, mid-, and high-range estimates from model simulations, a total of 36 comparisons were made to the prospective resource estimates, of which 35 showed significantly lower results for the model-based estimates. Model sensitivity testing of variable CO2 injection rates indicated that the requirement to maintain reservoir pressure below the fracture gradient threshold is in part responsible for the lower limit of storage resource estimates obtained from the reservoir simulation results versus the prospective resource methodology which neglects such processes. In terms of enhanced methane recovery, results were far more comparable between the two methods for the low- and mid-range set of estimates, whereas the high-range estimates were still notably larger using the prospective resource methodology. We conclude that utilizing prospective resource estimates of enhanced coalbed methane potential in integrated system models appears feasible for the more conservative range of estimates, whereas CO2 storage estimates of coal seams are likely to produce overly optimistic results in the system model. We also note that for the Illinois Basin case study, both the modelling results and the regional-scale results indicate that a significant amount of additional well drilling beyond the existing
* Corresponding author. Tel.: +1-812-856-3671; fax: +1-812-855-2862. E-mail address: [email protected]
1876-6102 © 2017 The Authors. Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/). Peer-review under responsibility of the organizing committee of GHGT-13. doi:10.1016/j.egypro.2017.03.1661
Qian Zhang et al. / Energy Procedia 114 (2017) 5346 – 5355
coalbed methane infrastructure would need to be conducted in order for coal seams to be a viable alternative to other options in the region such as oil and gas reservoirs and deep saline formations. © 2017 The Authors. Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND license © 2017 The Authors. Published by Elsevier Ltd. (http://creativecommons.org/licenses/by-nc-nd/4.0/). Peer-reviewunder underresponsibility responsibility organizing committee of GHGT-13. Peer-review ofof thethe organizing committee of GHGT-13. Keywords: Resrvoir Modelling; Enhanced Coal Bed Methane; System Analysis; Illinois Basin
1. Introduction The advent of integrated system modelling tools for evaluating carbon capture and storage (CCS) technology implementation provides an intriguing new development towards facilitating decision-making on potential CCS projects [1]. Previous studies have suggested that coal seams may have a significant capacity for CO2 storage throughout the world [2-3] with the additional economic advantage of potential enhanced coalbed methane production (ECBM) because of the preferential adsorption of CO2 versus methane. Thus the incorporation of coal seam storage and ECBM processes into CCS system modelling tools would be an important improvement towards greater utility of such tools. We are aware of one such development at present for which the explicit implementation of coal seam storage and ECBM potential currently relies on prospective resource estimates derived from regional-scale analyses using a volumetric-based approach [4]. The focus of this study is to evaluate the uncertainty of such prospective resource estimates, both for CO2 storage and for ECBM via comparison to results from more detailed, local-scale reservoir simulations at numerous locations across the Illinois Basin, USA. This paper is a companion to a similar study on conventional oil and gas reservoirs [5], both of which support a new integrated systems model analysis for the Illinois Basin, USA [4]. Reservoir-scale simulations have the advantage of incorporating the dynamic system response to CO2 injection, whereas regional-scale prospective resource estimates rely on volumetric calculations of original gas-in-place from static geological models combined with assumed recovery factors. To date there have been numerous studies regarding coalbed methane production (CBM) and ECBM, but most studies are limited to laboratory experiments and reservoir simulations [5-10]. Insight from actual field tests of the ECBM process and CO2 storage in various coal seams is still fairly limited. One exception is the first and largest pilot CO2-ECBM test that was conducted in the San Juan Basin in the southwestern USA in which a total of 277 kt of CO2 was injected over a five-year period [11]. The authors noted that methane recovery was improved from 77 percent to 95 percent of the original gas in place at the Allison Unit [11]. For the Illinois Basin, only a single, small pilot test has been conducted at the Tanquary test site using one injection well and three monitoring wells [12]. The authors report a continuous injection of about 102 tons of CO2 from July, 2008 through December, 2008 with no CO2 breakthrough occurring at the monitoring wells [12]. Given the lack of available empirical results from field injection testing, particularly for our study area of the Illinois Basin, it is expected that the currently available prospective resource estimates are highly uncertain. Thus we have undertaken the following modelling-based study to evaluate this uncertainty with the goal of better informing the accurate implementation of coal seam storage and ECBM processes within the systems modelling approach.
2. Model Development 2.1. Study Area Reservoir-scale simulations of selected coal seams were conducted for a case study exploring the potential for postcombustion CO2 capture at a coal-fired power plant site in the Illinois Basin (Figure 1). Preliminary site screening led to the selection of 15 candidate sites for stacked reservoir storage, 12 of which were deemed to have potential for coal seam storage and ECBM. The commercial reservoir simulator GEMTM v.2015 (Computer Modeling Group Ltd) was used to evaluate the CO2 storage and methane production processes of up to seven coal seams at each of the 12
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geographic sites. An idealized, inverted five-spot pattern model with a dual porosity/permeability system was used for this study. The model was developed based on parameter evaluation and calibration to production data from an existing CBM operation in Sullivan County, Indiana (2007–2013) to ensure that results were consistent with a larger, heterogeneous reservoir model developed for this specific region [13]. This idealized model was then applied at the other potential storage locations in the study area where critical parameters such as coal seam depths and thicknesses had been mapped (Table 1) [14] but CBM production data were not available for comparison. Reservoirs were assumed to be normally pressured (i.e., hydrostatic conditions) and reservoir temperature was calculated based on a recent analysis of geothermal gradient across the Illinois Basin [15].
Fig. 1. Map of the study area in the Illinois Basin showing the coal-fired power plant at center of map (yellow star) and 15 specific sites that are being considered for their stacked CO2 storage and utilization potential (including the power plant site). Colors indicate the relative amount of enhanced coalbed methane potential estimated from a regional-scale prospective resource assessment (red is low, green-to-blue is high; yellow indicates region where coal seams are deemed unmineable and are thus excluded from consideration for CCS).
2.2. Sensitivity Analysis Once CO2 is injected into coal seams, it invades the pore space and adsorbs at solid-fluid interfaces and preferentially displaces methane. This process allows for CO2 storage in coals as well as enhanced gas recovery. Results from prior research suggest that the performance of enhanced coalbed methane recovery operations is dependent on many factors, including matrix/fracture permeability, cleat spacing, initial water saturation, wellbore skin effects, and Langmuir adsorption constants. To test the importance of these parameters on our model results for Illinois Basin coals, a sensitivity study was conducted using the reservoir model for the node 9 location in our study.
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The parameter ranges implemented in the sensitivity analysis (Table 2) represent a plausible extent of variability around the median, base-case value given the available data on coal seams in our study area [12-14]. Table 1. Model parameters for coal reservoir simulations. Site Information Depth (m) Thickness (m) Temperature (°C) Pressure (kPa)
Node 1
Node 2
Node 3
Node 4
Node 5
Node 6
Node 9
Node 10 Node 11
Node 12 Node 13 Node 14
259
320
198
259
198
381
229
381
320
381
259
137
5
4
5
4
5
5
7
4
7
5
5
2
20
22
18
20
18
24
20
24
22
24
20
17
2621
3214
2028
2621
2028
3807
2621
3807
3214
3807
2621
1435
Table 2. Summary of parameter ranges used for model sensitivity analysis. Parameters
Low
Median
High
Fracture permeability (md)
30
65
100
Cleat spacing (mm) Initial water saturation (%)
0.65 0.85
1.5 0.88
10 0.9
Wellbore skin (-)
-0.8
0
1
Langmuir Constants
Test 1
Test 2
Test 3
CH4 VL (scf/ton)
533
354
640
CH4 PL (psi)
512
276
464
CO2 VL (scf/ton)
1088
743
1089
CO2 PL (psi)
226
135
332
The results showed that among all tested parameters, fracture permeability was the most influential factor for methane production (Figure 2a). This is because after methane desorbs from coal seams, a higher fracture permeability allows better gas flow conduits, and thus favors methane production. Langmuir constant and wellbore skin factors also have substantial impacts on the cumulative methane production (Figures 2b and 2c). Increased methane production was observed with negative skin factor, due to enhanced gas flow near the wellbore. Initial water saturation also has limited effects; as higher water saturation leads to decreased methane production (Figure 2d). Cleat spacing was found to have minimal impact on methane production (Figure 3e).
3. Reservoir Simulations Given the dominant control of fracture permeability on simulation results, a set of low, medium, and high fracture permeability cases were evaluated at each site in the study, along with four different operational scenarios using different cutoff criteria for the CO2 injection operation: (1) the amount of CO2 being produced exceeds the amount of methane produced at the same time; (2) CO2 production rate exceeds 50 percent of the injection rate; (3) full CO2 injection for a set period of five years; and (4) extended CO2 injection operation until the enhanced methane production rate declines completely to the non-CO2, base-case methane production rate. While scenarios 1 to 3 represent varying operational decisions, scenario 4 is considered the most objective criteria in that CO2 operations cease at the point when further injection is no longer effective at driving any enhanced methane production.
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Fig. 2. Line graphs illustrating the effects of various factors on cumulative methane production. (a) fracture permeability; (b) Langmuir constants; (c) wellbore skin factor; (d) initial water saturation; (e) cleat spacing.
The base-case model scenario used to quantify the difference from, and thus effectiveness of the CO2 injection operations followed the CBM production history of Karacan et al. [13] with simply extending the methane production operation from July, 2007 to October, 2018. For the CO2 injection case, the first 6 years of reservoir operations follow the same history as the base-case simulation and then switch over to CO2 injection for a period of five years from October, 2013 to October, 2018. Injection rate was set to be a constant of 250 m3/day based on the Tanquary pilot test [12]. Three different cases of low-, mid-, and high-range fracture permeability were run for each of these simulation scenarios. In this way, the model was used to generate results for comparison to the equivalent ranges of resource estimates derived from regional-scale analyses.
3.1. Effects of CO2 injection on cumulative methane production Model results from node 9 provide an example of how CO2 injection impacts methane production from coals in our study area (Figure 3). For the base case, a total of 20.08, 21.6, and 22.23 MMscf methane was produced during
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the 11-year production in the low-, medium-, and high-range cases, respectively (Figure 3a). By comparison, for the enhanced recovery with CO2 injection, the cumulative methane production increased to 23.05, 24.45, and 24.74 MMscf, respectively (Figure 3b). Thus, the enhanced methane production was 2.97, 2.85, and 2.51 MMscf for the low-, medium-, and high-range cases, respectively. The corresponding ECBM recovery factors ranged from 11.3 percent to 14.8 percent, which are somewhat similar to but lower than the recovery factor estimated from the pilot test at the Tanquary site (~15 to 20 percent) [12].
Fig. 3. Line graphs comparing the influences from varying fracture permeability on cumulative methane production in the base-case model and the CO2 injection model.
3.2. Comparison with regional scale analyses For cutoff scenarios 1 to 3 listed above, regional-scale analyses were observed to overestimate the enhanced gas recovery potential relative to the reservoir simulation results for all the tested permeability cases. For instance, regional-scale ECBM potential was estimated to range from 0.125 MMscf/acre to 1.5 MMscf/acre, while reservoir simulation indicated the potential varying from 0.03 MMscf/acre to 0.2 MMscf/acre in those scenarios. A cross-plot of cutoff scenario 2 in which regional-scale analyses are plotted against simulation results (Figure 4), shows most of the data points located well below the 1:1 ratio line, indicating simulated results are significantly lower than the estimates from regional-scale analyses. However, in the case of cutoff scenario 4 with extended CO2 injection, reservoir-scale simulation results indicate that enhanced methane recovery in the low- and mid-range estimates is somewhat comparable to regional-scale results (on average, around 0.4 MMscf/acre or 0.028 MMm3/Ha; 15-20 percent recovery; Figure 5a–c). This result is also in reasonable agreement with the very limited results that were reported in the literature from CO2 injection pilot test studies [12]. However, when compared with the high-range, regional-scale analysis results, enhanced methane recovery from reservoir simulation is still much lower (Figure 5c). The total amount of CO2 stored in the coal seams is calculated by subtracting the amount of CO2 produced from wells in the model from the total amount of CO2 injected. With respect to CO2 storage, regional-scale results estimate that the storage resource in the twelve specific areas ranges from 100 to 1000 tonnes/acre (247 to 2470 tonnes/Ha). These regional estimates are significantly larger than our model results of <50 tonnes/acre (124 tonnes/Ha; Figure 6ac). Storage estimates from modelling indicate that using coal seams to achieve large-scale CO2 storage in the study area will require significant new well infrastructure beyond the existing CBM well infrastructure in the region.
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Fig. 4. Cross plots of scenario 2 for CO2-ECBM resource estimates between simulated results and regional-scale analysis (1 MMscf/acre = 0.07 MMm3/Ha): (a) low-range estimate; (b) mid-range estimate; (c) high-range estimate.
Fig. 5. Cross plots of scenario 4 for CO2-ECBM resource estimates between simulated results and regional-scale analysis (1 MMscf/acre = 0.07 MMm3/Ha): (a) low-range estimate; (b) mid-range estimate; (c) high-range estimate.
Fig. 6. Cross plots of scenario 4 for CO2 storage resource estimates between simulated results and regional-scale analysis (1 tonne/acre = 2.47 tonnes/Ha).
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4. Discussion Results from this study suggest that the coal seam resource estimates that are currently being implemented into integrated system models appear to be reasonable for the CO2 utilization resource estimates (ECBM), but are overly optimistic for the CO2 storage resource estimates. The discrepancies between the two methods clearly highlight the limitations of the regional-scale approach wherein volumetric-based calculations are entirely static and are not capable of incorporating impacts from dynamic flow processes. For instance, the prescription of fixed original gas in place values, an assumed 5:1 ratio of CO2 to CH4 preferential adsorption displacement factor, and constant Langmuir adsorption isotherms all contribute to the differences observed between the two methods. There are also limitations to the idealized modelling approach and its assumptions. For example, model results assume an operational CO2 injection rate of 250 m3/day based on the single example of an actual injection operation in our study area (the Tanquery site pilot study). For a full five-year injection period and assuming no CO2 breakthrough, the maximum amount of CO2 that can be stored in such a case is inherently limited to 44.7 tonnes/acre. Therefore, we conducted additional model sensitivity analysis with the results confirming that increasing CO2 injection rates can ultimately promote higher levels of CO2 storage (Figure 7). However, results also illustrated that the maximum allowable reservoir pressure based on the fracture gradient criteria is a critical limitation to the ultimate amount of CO2 storage resource. For the example site shown in Figure 7, the fracture gradient threshold pressure would be reached at an injection rate of 2500 m3/day. At that injection rate, the amount of CO2 stored is 135 tonnes/acre. This model-based estimate, while indeed significantly higher than the result which assumed operational parameters identical to the Tanquery pilot test, is still far below the estimate from regional-scale calculations. Thus, we find that the requirement that reservoir pressure does not exceed the fracture gradient criteria effectively limits the CO2 storage resource of coal seams in our study area to values that are typically much lower than the regional-scale prospective resource estimates.
Fig. 7. Effects of increased injection rates on CO2 storage resource estimates, where circle indicates that the maximum allowable reservoir pressure has been reached at a depth of 229 m.
The impact of injection rates on the model estimates of ECBM resource was also tested (Figure 8). With full injection for five years in a medium permeability case, the maximum ECBM potential is approximately 0.2 MMscf/acre at the maximum injection rate of 2500 m3/day for this example site. This difference is only about 0.04 MMscf/acre higher than the result that assumes the Tanquery site operational injection rate of 250 m3/day. Thus, we conclude that our original assessment holds, whereby low- and mid-range ECBM resource estimates are comparable between the two methods, but high-range estimates are still significantly larger for the regional-scale analysis.
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Fig. 8. Scatter plot showing the impacts of increased injection rates on ECBM potential, where circle indicates that the maximum allowable reservoir pressure has been reached at a depth of 229 m.
5. Conclusions While CO2 storage and utilization for enhanced oil recovery in conventional reservoirs has a long history of empirical results from operational implementation, CO2 injection into unconventional reservoirs such as coal seams is at present an area of emerging R&D. Given the relative lack of results from field injection testing of CO2 in coal seams, it is expected that the currently available prospective resource estimates for CO2 storage and CO2 utilization for ECBM are highly uncertain. Thus we have undertaken a modelling-based study to evaluate this uncertainty by comparing regional-scale, volumetric-based resource estimates to results from detailed, local-scale reservoir simulation models for numerous sites across the Illinois Basin, USA. A specific goal of this study is to provide results that will better inform the accurate implementation of coal seam storage and ECBM processes within broader integrated CCS systems models that are currently under development. Results suggest that regional-scale prospective storage resource estimates are significantly biased towards overestimation, and thus may be unsuitable for application in CCS system models. In contrast, CO2 utilization resource estimates in the form of ECBM potential were quite comparable between the two methods so long as low- to midrange estimates are considered. In the case of extended CO2 injection (five-year period), reservoir simulation results indicate that ECBM potential is on average around 0.4 MMscf/acre of reservoir domain, which is comparable to the estimated 15 to 20 percent recovery factor for ECBM in regional-scale analyses. Model testing revealed that higher CO2 injection rates can increase ECBM potential as well as CO2 storage, but the maximum values are limited by the requirement to maintain reservoir pressure below the fracture gradient criteria. Volumetric-based approaches are not capable of accounting for such dynamic processes and this limitation can largely explain the observed differences in resource estimates between the two methods.
Acknowledgements This research was funded by the U.S.-China Clean Energy Research Center, Advanced Coal Technology Consortium (subcontract 10-733 of the West Virginia University Research Corporation). The authors wish to thank the Computer Modeling Group, Ltd. for their provision of a software license used in this study.
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