Economic modelling for coal bed methane production and electricitygeneration from deep virgin coal seams
V. Sarhosis a, b, *, A.A. Jaya a, H.R. Thomas a
a Geoenvironmental Research Centre, Cardiff School of Engineering, Cardiff University, CF24 3AA, UKb School of Civil Engineering and Geosciences, Newcastle University, NE1 7RU, UK
a r t i c l e i n f o
Article history:Received 22 October 2015Received in revised form1 April 2016Accepted 12 April 2016
Keywords:Economic modelCBM (Coal bed methane)Electricity generationCOE (Cost of electricity)South Wales Coalfield
* Corresponding author. School of Civil EngineeringUniversity, NE1 7RU, UK.
An investigation of the economic potential for recovering methane from virgin coal seams for electricityproduction at a study area in South Wales, UK, is presented. Utilizing the coal bed methane gas to fuel aCCGT (combined cycle gas turbine) will offer a low carbon option compared to fossil fuel fired powergeneration for the study area. Cost effectiveness is analysed using both technical and economic dataallowing for integration connecting the various sub-processes to the surface processes up to the pro-duction of electricity. The model considers both reservoir conditions and engineering factors to calculatethe EUR (enhanced ultimate recovery), the CAPEX (capital expenditure) and the OPEX (operationalexpenditure) of the coupled CBM-CCGT process. The projected UK Navigant gas prices and the DECCelectricity prices are then used to estimate the LCOE (levelised costs of electricity) and obtain thefinancial performance of the coupled CBM-CCGT process. Calculation results showed that the probablecost of electricity (LCOE) amounts to 37 £/MWh and the return on investment could be in the excess of77%. For the selected study area, the coupled CBM-CCGT process could potentially be an economic optionfor power generation.
Meeting the challenges of reduced carbon dioxide emissions andthe provision of competitive energy costs is more important thanever. Combine these two vital objectives with maintaining the se-curity of energy supply is considered vital and of strategic impor-tance for Europe. In UK, natural gas forms a key part of the energysupply and is important not only for electricity production, but alsofor domestic heating, cooking and industrial production [12]. Inrecent years, the UK has become increasingly dependent on gasimports, with annual UK gas consumption of approximately 85billion cubic meters; while the Government forecasts that nearly 70%of the UK's gas supply will be imported by 2025. In 2012, the BGS(British Geological Survey) estimated that there are approximately2900 billion cubic meters of onshore CBM (coal bed methane) in UK[10]. Evenwith a yield of 10%, the potentially recoverable resources ofCBM (at 290 billion cubic meters) could contribute significantly tosafeguard the energy needs of the country for the next decades to
and Geosciences, Newcastle
V. Sarhosis).
come and until the transition to renewables. Today, there are anumber of active CBM production sites in UK, including the one inStaffordshire and Airth in Scotland [14]. Current success in the pro-duction of CBM in these areas shows that it could be implemented inother parts of the UK, including South Wales [34].
Coal bed methane is gas of natural origin formed as part of thegeological process of coal generation, and is contained in varyingquantities within coal [36]. CBM can be recovered by drilling intothe coal seams, initially releasing water to lower the pressure andthen allowing the desorption of the methane gas from the internalsurfaces of the coal, where it is able to flow either as free gas ordissolved in water towards the production well at the surface. Bycontrolling the release of pressure in the coal seam, methane can becaptured [28,36,40]. Occasionally, CBM extraction may need to beenhanced by hydraulic fracturing when insufficient naturalpermeability of the coal exists [9]. Concentration levels of methanerecovered via these techniques can often exceed 95%, making thegas suitable for use as a direct replacement for conventional naturalgas in pipeline networks. This gas can then be compressed andsupplied to market (e.g. heating, chemicals, gas to liquids etc) [26].The high quality of the gas recovered from unmined coal seams alsorenders it suitable for replacing or supplementing conventional
qo initial productionqt production rate£ English pounds£m million English poundsA areaCAPEX capital expenditureCBM coal bed methaneCC carbon costCCGT combined cycle gas turbineCF cash flowCoI cost of investmentCOE cost of electricityd daysDECC department of energy and climate change in UKDR discount rateDTI department for trade and industryE percent of efficiencyEG electricity generationEIA environmental impact assessmentEUR estimated ultimate recoveryGc gas content of the coalGCP gas collection pointGCP gas collection pointGCU gas compression unitGfI gain from investmentGP gas producedGSU gas storage unith cumulative height of coalhr hourskm2 square kilometres
LCOE levelised cost of electricityLR loss ratiom metersmD millidarcyMW megawattMWhr megawatt hourn time periodNEG net electricity generationNG national gridNPV net present valueOGIP original gas in placeOPEX operational expenditureOC outgoing costsP10 90% probability of meeting or exceeding the estimated
proved volumeP50 50% probability of meeting or exceeding the estimated
probable volumeP90 10% probability of meeting or exceeding the estimated
possible volumePEDL petroleum exploration and development licencesR revenuesRF recovery factorROI return on investmentT time periodt tonneTC total costsUK United KingdomUoS use of systemrc density of coala decline raten years
V. Sarhosis et al. / Energy 107 (2016) 580e594 581
natural gas in a CCGT (combined cycle gas turbine system). Aschematic illustration of the CBM-CCGT process is shown in Fig. 1.Successfully developing a coal bed methane field requires pru-dently managing the technical as well as the economic aspects ofthe project. The profitability of a CBM (coal bed methane) project issite specific and is highly dependent on various geological andmarket dependant factors [19].
2. Objectives and methodology
This study presents a transparent documentation of the devel-opment and application of a model to investigate the economic
Coal Bed Methane
Gas Collec on Point (GCP)
Gas Separa on Unit (GSU) and Fire Stack
Gas Compression Unit (GCU)
Coal Bed Methane Process
Water Extrac on
Unit
Water Storage,
Treatment and Disposal
Distribu on through pipeline
CCGT Power Plant
Feed electricity
generated to na onal grid Residual gas
can be sent to na onal grid
Fig. 1. The coupled CBM-CCGT process.
viability of methane recovery from unmineable coal seams and thesubsequent electricity generation in a CCGT power plant. Themodeldeveloped for CBM-CCGT COE (cost of electricity) determination iscontrolled by geological, technical and market dependant modelinput variables adapted to site specific boundary conditions for anyselected target area worldwide. As a case study, data from a wellexploited site in the South Wales, UK is considered. Part of themodel is to predict the future gas production and electricity gen-eration from a target site, evaluate the CAPEX (capital expenditure)and the OPEX (operational expenditure) of the coupled CBM-CCGTprocess and determine the LCOE (levelised costs of electricity).Statistical analyses with the use of Monte Carlo analysis wereemployed and the degree of certainty defined based on thefollowing three scenarios: a) proved estimates (P10); b) probableestimates (P50); and c) possible estimates (P90). Cash flows for thedifferent scenarios were also determined and compared based onthe revenues obtained from selling electricity generated from theCBM-CCGT process to the national grid. The basic process layout forthe developedmodel of the coupled CBM-CCGT process is shown inFig. 2. A detailed description of the model and an application casestudy is presented in the following chapters.
The innovation provided by the present study is the discus-sion of a coupling scheme allowing for integration connectingthe various sub-processes to the surface processes up to theproduction of electricity. This procedure allows for flexibleadaptation of variations in the model as well as allows theimplementation of sensitivity studies which will be discussed infollow up publication.
Fig. 2. Flow chart for the dynamic model development.
V. Sarhosis et al. / Energy 107 (2016) 580e594582
V. Sarhosis et al. / Energy 107 (2016) 580e594 583
3. Factors influencing the CBM investment in South Wales,UK
3.1. Geology of the South Wales Coalfield
The South Wales Coalfield (Fig. 2) is situated within an asym-metrical syncline approximately 96 km East-West and 30 kmNorth-South and covers an area of about 2690 km2. It is anerosional remnant of a formerly extensive area of Carboniferousgeology [20]. The depth of the coalfield varies enormously acrossthe entire area. In the east, the lowest coal seams do not reachdepths greater than 60 m below OD (Ordnance Datum) while in thewest (near Gorseinon) they are found at much greater depthexceeding 1800 m below OD [1]. The geology of South Walesdistinctly displays awide range of formations and rock exposures ofvarying ages and periods. The lithology of the area consists ofDevonian formations, Carboniferous Limestones and Millstonesformations and then the South Wales Coal Measures. The SouthWales Coal Measures consist of: a) the Lower Coal Measure; b) theMiddle Coal Measure; and c) the Upper Coal Measure. The CoalMeasures are all of Carboniferous age and lie upon the LowerCarboniferous Limestones; which in turn lie upon the Devoniansandstone (Fig. 3). The coal rank in the South Wales Coalfield variesfrom high volatile bituminous coals in the south and east crops toanthracite coals in the north-western part of the Coalfield [4]. TheLower Coal Measures can be observed to havemore anthracitic coalseams compared to the Middle Coal Measures and the Upper CoalMeasures. The Upper Coal Measures have more sub-bituminousranked coal which are located at the southern part of the SouthWales Coalfield [4].
Fig. 3. A simplified geology of the South Wales Coalfield
3.2. Reservoir conditions, policies and commercial opportunities inSouth Wales
The gas recovery has a direct impact on the economics of a coalbed methane scheme. A sound resource base, ideally consisting of afew thick permeable coal seams with high content (>7 m3/t) isrequired for successful coal bed methane development. The SouthWales Coalfield is characterised by gassy coal seams with relativelyhigh methane content [24]. Based on 173 samples from 24 bore-holes taken at an average depth of 702 m, the mean methanecontent was found to be 13.3 m3/t [5]. The average values derivedfrom 18 anthracite coal samples taken from three boreholes were18.3 m3/t at an average depth of 692 m [5].
Also, methane flow ratesmeasured in seam boreholes in UK coalmines are generally 0.1 m3 per day per meter of the boreholelength. In NorthWales at the Point of Ayr Colliery, borehole flows ashigh as 62 m3 per day per meter length have been encountered invirgin conditions [7]. However, there is little evidence that suchflows can be produced in other parts in Wales. Coal permeability isanother factor that influences the profitability of the coal bedmethane operation and links directly to the amount of gas pro-duction. Coal permeability depends on the maturity, the cleatsystem and its degree of openness or mineralisation. Discontinu-ities in the coal, such as micro-fractures at the matrix and cleats ofthe coal contribute to the permeability and therefore the recoveryof coal bed methane. Discontinuities provide pathways for bulkfluid and gas to flow at faster desorption rates [17]. According toHunt and Steele [23] and Hughes & Logan [22]; a natural perme-ability greater than 1 mD is needed for the CBM operations to beeconomically attractive. The permeability of coal bed in the South
showing the locations of the Coal Measure outcrops.
V. Sarhosis et al. / Energy 107 (2016) 580e594584
Wales Coalfield ranges from 1 to 10 mD, which enforces the eco-nomic potential for recovering coal bed gas from this area [37]. Thepermeability of coal seam can be further enhanced by hydraulicfracturing when and if necessary [36] and in this case permeabilitycan be up to 30 mD.
There are a number of existing project developers, operators,producers and equipment manufacturers able to support thedevelopment of CBM in SouthWales [15]. These local expertise andequipment manufacturers will potentially influence future CBMproductions in the area as local supply of equipment will be a lotcheaper than importing equipment from other countries. Further-more, for Wales, a variety of legislation covers the individual ac-tivities related to unconventional gas developments [29]. PEDLs(Petroleum Exploration and Development Licences) are also awar-ded in a series of ‘rounds’ by the Department of Energy and ClimateChange [10]. Fig. 4 shows the sites in South Wales where PEDLswere awarded to entitled companies during the 14th round on the28th of July 2014.
4. Case study description and basic model assumptions
4.1. Study area
The area under investigation is a coal deposit of Carboniferousage with anthracite coals located on the upper reaches of the Neathand Dulais Valleys in the county of Neath Port Talbot, South Wales.The coal seams are suitable for conventional mining but there maybe an option to exploit their CBM potential before mining them. Forexamination, seven deep wells (at average depth 600 m), well logdata for all wells, more than 20 cross sections of the area as well ashistorical data from Coal Authority were considered.
The ground is primarily forestry, under the ownership/lease ofthe Forestry Commission. The area is characterized by deep and
Fig. 4. Areas that have been awarded PEDLs in South Wales during th
dense faults (Fig. 5). The largest discontinuity is a transcurrent faultthat runs up the Neath Valley with a displacement in order ofseveral kilometres.
The two major rivers Neath and Dulais are the principal con-trolling drainage elements in the area (Fig. 5). There are also a fewsmall rivers and streams that run across the hillside of the studyarea. The geological setting of the site is well defined due to historicborehole data. A cross-section of the study area is shown in Fig. 6.
4.2. Site selection criteria assumptions
The site selection criteriawere developed based on successes andfailures of previous experiments and pilot studies [4,10,24,39]. Thecriteria take into account the site characteristics, coal quality pa-rameters, depths, the geology and hydrogeology of the area aswell asenvironmental restrictions on the site. These criteria highlight themerits and demerits of the selected parameters, their importance insite selection and their economic and environmental potentials.Using the site selection criteria shown in Table 1, site buffers weredrawn and the coal resource area identified and estimated (Fig. 7).The coal resource area found to be equal to 4.14 km2.
4.3. Coal seams considered and assumed range of their properties
Geological surveys show that the overall research area providesthree coal seams suitable for coal bed methane which were investi-gated in the scope of the present study to ensure fuel supply for theCCGT plant for up to 41 years. The target coal seams are: a) the Eigh-teen Feet; b) the Nine Feet; and c) the Bute. The depth of the targetedcoal seams ranges from 562 m to 623 m (ref. Fig. 6). Desorption testson twelve coal samples taken from the boreholes have been under-taken at the laboratory. From the results analysis it was found that thedesorbed coal gas content ranges from 10.1 to 16.5 m3/t.
e 14th Round in 2014 (Map updated on 9th of March 2015) [31].
Fig. 5. Waterways and geological faults of the study area (For color figure refer to the electronic version).
V. Sarhosis et al. / Energy 107 (2016) 580e594 585
4.4. Assumptions for the estimation of the gas in place
Based on the geological and reservoir conditions, volumetricanalysis undertaken to calculate the volume of the methane in thecoal beds [27]. The OGIP (original gas in place) that is trapped in thecoal seams calculated from Eq. (1) [36]:
OGIP ¼ A� h� rc � Gc; (1)
where A is the area (m2); h is the cumulative height of coal in thearea (m); rc is the density of the coal (t/m3); and Gc is the gascontent of the coal (m3/t). Also, the amount of recoverable gascalculated using Eq. (2) [36]:
EUR ¼ OGIP � RF; (2)
where EUR is the enhanced ultimate recovery (m3), RF (Recoveryfactor) is the recovery factor and is equal to the ratio of the gasproduced to the initial gas content (%). Due to the uncertainties inthe reservoir parameters (e.g. coal seam thickness, recovery factor,gas content, depth of coal seams and methane drainage diameters),a probabilistic approach based on the Monte Carlo analysis [39]used for the estimation of the EUR. The amount of gas to be pro-duced ranked according to the degree of certainty as follows:
a) “Proved” there is a 90% probability of meeting or exceeding theestimated proved volume (P10);
b) “Probable” there is a 50% probability of meeting or exceedingthe estimated probable volume (P50); and
c) “Possible” there is a 10% probability of meeting or exceeding theestimated possible volume (P90).
4.5. Composition of coal bed methane and gas production ratesassumptions
Samples of coal bed methane gas were obtained directly fromthe vertical boreholes during and after drilling. The samples wereanalysed by gas chromatography for the presence of hydrocarbons[2]. Methane in the gas varied from 95 to 99 percent; carbon di-oxide from 0.1 to 2 percent. The majority of samples containedethane, propane, and butane at concentrations below 2%. Verysmall concentrations of hydrogen and helium were found in somesamples. Also, oxygen and nitrogen were present in very smallconcentrations, possibly as a result of air contamination. In thepresent study, it was assumed that the coal bed methane gascontains 97 percent of pure methane that can be compressed andfed via pipeline directly to fuel a CCGT.
4.6. Infrastructure and planning assumptions
Drilling of boreholes, installation of pipelines, gas collectionpoints, storage tanks, and construction of roadways for access onsite are some of the most important infrastructure facilitiesrequired for coal bed methane development. Borehole productionmay last for many years and often drilling is carried out sequen-tially throughout the life of the project. The cumulative gas pro-duction and the reservoir conditions of the site have been used tocalculate the extent of the volumetric drainage. For the three sce-narios considered in this study, a circular drainage pattern has beenassumed. The radius of the draining area ranged from 480 m to650 m [8,21] with the majority of drilling to be undertaken in thefirst year.
Fig. 6. Cross section of the site (For color figure refer to the electronic version).
Table 1Assumptions for the site selection criteria for CBM operations.
Selection criteria Value Reference
Resource area Greater than 1 km2 [24]Gas content Greater than 8.4 m3/t [10]Seam thickness Greater than 1.5 m [10]Depth of coal seams Greater than 500 m and less than 1000 m [39]Coal rank Greater than Bituminous [4]Permeability of coal and bedrock Greater than 1 mD [10]Proximity to populated areas 1000 m away [39]Proximity to underground mine workings 100 m away [39]Proximity to fault zones 500 m away for major fault;
200 m away for minor fault[39]
Proximity to waterways 25 m away [39]Proximity to aquifers 1000 m away [39]
V. Sarhosis et al. / Energy 107 (2016) 580e594586
Moreover, it was assumed that for every five boreholes at leastone GCP (gas collection point) is required. Fig. 8 shows the locationsof the boreholes for the three scenarios under investigation (i.e.P10, P50 and P90). The larger the methane drainage area, the lesserthe number of boreholes to be drilled on site.
Also, the water in the coal beds contributes to pressure in thereservoir that keeps methane gas adsorbed to the surface of thecoal. This water must be removed during the gas extraction processby pumping in order to lower the pressure in the reservoir andstimulate desorption of methane from coal. As the amount of wellsincreases, the amount of water to be extracted will also increase. Inthe present study and since there were not past coal bed methaneactivities in the South Wales Coalfield, data from the Black warriorBasin in Alabama obtained. Based on 2917 wells, the average waterproduction was 58 barrels per day per well (assuming that 1 barrel
contains 4.5 litters) [35]. The specification of suchwater abstractionhave been used in the present study for the estimation of the sizeand number of pumps as well as for the waste water treatmentfacilities and fees for the water discharge.
4.7. Electricity generation from CCGT assumptions
The potential of recovering methane from the deep coal seamsand feeding it into a 50 MWCCGT power plant has been examined.Technical data about the proposed CCGT power obtained from anexisting 50 MW CCGT power plant located in Yorkshire and oper-ating for the last 20 years. The technical characteristics of CCGTpower plant are shown in Table 2. The expected electricity gener-ation by the coupled CBM-CCGT process depends on the capacity ofthe power plant and the expected efficiency. The capacity and
Fig. 7. Site buffers and the coal resource area (For color figure refer to the electronic version).
V. Sarhosis et al. / Energy 107 (2016) 580e594 587
lifespan of the CCGT plant depends on the size of the CBM reserve.The EG (electricity generation) per year in MWh can be calculatedby:
EG ¼ PC� d� hr� E ð%Þ; (3)
where EG is the electricity generation in (MWh), PC is the powercapacity in (MW), d are the days of operation of the power plant(e.g. 365 for a year), hr the hours of operation of the power plant(e.g. 24 h per day) and E is the percent of efficiency of the powerplant.
In the present study, it was assumed that the electricity gener-ation could range from 2.83 to 2.65 MWh per year for the P10 andP90 scenarios accordingly.
5. Calculation results and discussion
5.1. Calculation of volumetrics
To consider the range of reservoir conditions and engineeringfactors influencing the volumetrics (Equations (1) and (2)), statis-tical distributions were defined for each of the input parameters.The evaluation of the enhanced ultimate recovery was performedvia Monte Carlo analysis [18,27]. Table 3 shows the minimumvalues, most likely values, maximum values, and standard de-viations defining the distributions of the input parameters. Acombination of literature survey and site specific data obtained aspart of the current work have been used to gain an understandingof the gas content of the perspective site in the South WalesCoalfield. The minimum and maximum values are those obtainedfrom experimental tests on coal samples obtained during drillingexploration. The most likely methane content was set to 15.65 m3/t
(with a standard deviation of 0.455). Values of the recovery factor,RF, were taken from van Bergen et al. [39]. The value of the RF isrelated to the potential restrictions on the flow in the coal seamwhich in the South Wales Coalfield are of particular low coalpermeability [13]. This uncertainty can realistically be addressedthrough gaining more field experience in the region. Monte Carlosimulation for the effective gas storage capacity was performed andproduced the results shown in Fig. 10 and Table 4. Fig. 9 shows thecumulative probability plot of the Monte Carlo simulation resultsfor the effective methane storage capacity of the perspective sitewhile the P10, P50 and P90 percentiles are indicated. From thecalculations, the total proved effective storage capacity is3.48 � 108 m3 (P10 scenario), with a probable capacity of3.73 � 108 m3 (P50 scenario) and a possible capacity of3.96 � 108 m3 (P90 scenario). These results have been calculatedusing the methodology described in Section 2. Also, the net effi-ciency of CCGT power plant ranged from 60.5% to 64.5% for the P10and P90 scenarios accordingly [33].
5.2. Decline curve analysis for the gas production and lifespan ofthe coupled CBM-CCGT process
For the estimation of future gas production, the decline curveanalysis using the exponential decline technique used [25]:
qt ¼ qoe�aT ; (4)
where qt represents the production rate (m3/day); qo is the initialproduction (m3/day); a is the decline rate (m3/day); T is the time indays. The decline rate (a) and the time rate (T) calculated usingequation (4). Also, the LR (loss ratio) and the cumulative GP (gasproduced) evaluated using equations (5) and (6) below:
Fig. 8. Spatial location of the boreholes for: a) P90 - 11 boreholes; b) P50 - 15 boreholes; c) P10 - 18 boreholes (For color figure refer to the electronic version).
Table 2Key time periods and technical data for the CCGT power plant.
CCGT plant data P90 P50 P10 Units
Key Time Periods Total pre-development period 1 1 1 YearsConstruction period 1 1 1 yearsPlant operating period 20 15 10 years
Technical Data Net power output 50 50 50 MWNet efficiency 65 63 61 %Average load factor 100 100 100 %Energy requirement for CCGT 2.03 1.48 0.954 1010 MJAmount of gas needed to be supplied over the lifespan 4.84 3.52 2.27 108 m3
Electricity generation per year 2.85 2.76 2.67 105 MWh
Table 3Summary of the input values used for Monte Carlo simulations of the key parameters used to evaluate the EUR and volumetrics.
Parameters Range Min Mean Max Standard deviation Normal value Units
Fig. 9. Monte Carlo simulation results for the EUR (estimated ultimate recovery) at the perspective site in South Wales Coalfield: a) Cumulative probability of the EUR showing theP10, P50 and P90; b) Histogram of the Monte Carlo simulation results.
0
50
100
150
200
250
300
350
400
450
2014 2019 2024 2029 2034 2039 2044 2049 2054 2059
Cum
ulat
ive
Gas
Pro
duct
ion
(mill
ion
m3 )
Years
P90 P50 P10
Fig. 10. Cumulative gas production rate over the lifespan of the CBM-CCGT process.
V. Sarhosis et al. / Energy 107 (2016) 580e594 589
LR ¼ qo � qTqo
¼ 1� e�aT (5)
GP ¼ qo � qTa
(6)
Results from the gas production decline curve analysis used toobtain the number of boreholes to be drilled each year. Also, the
Table 4Monte Carlo simulation results for the different parameters.
P90
EUR (Estimated Ultimate Recovery) 3.96Average depth of boreholes 639Methane drainage diameter of the CBM boreholes 620Net efficiency of CCGT power plant 64.5
Table 5Recoverable coal bed methane for P10, P50 and P90 scenarios studied.
Gas production P90
Total gas produced perborehole over the lifespan
3.60
Gas produced per borehole forthe first year only
2.02
total amount of gas produced for each borehole over the lifespan ofthe project calculated by dividing the EUR (estimated ultimate re-covery) to the number of boreholes drilled.
Since there are no past CBM activities in Wales and gas flowrates from coal seams are limited [7], for the purpose of this study,gas production rates obtained from the Black Warrior Basin inAlabama, USA. According to Jones et al. [24] and Creedy [6]; BlackWarrior Basin has similar characteristics to that of the South WalesCoalfield in UK. Using Eqs. (4)e(6), isotherms presenting the log-arithmic gas production rate (qT) against time (t) have been createdand the total amount of gas recovered per year estimated (Table 10).From Table 5, the probable amount of gas to be produced over theentire life of the CBM process found to be equal to 3.49 � 107 m3/t.Also, the cumulative coal bed methane production and the lifespanestimated using the results from the gas production decline curveanalysis (Fig. 10). From the calculations, the lifespan for the coupledCBM-CCGT process found to range from 41 to 25 years for the P90and P10 scenarios accordingly (Table 6).
5.3. CAPEX (Capital expenditure)
CAPEX includes the total funds needed to acquire infrastruc-ture and equipment for the CBM-CCGT development. CAPEXestimated using the reservoir and geological property conditionsof the site and cost of the infrastructure and equipment shown inTables 7 and 8.
P50 P10 Units
3.73 3.48 108 m3
600 560 m550 480 m62.5 60.5 %
P50 P10 Units
2.49 1.93 107 m3/t
1.80 1.70 106 m3/t
Table 6Lifespan for the coupled CBM-CCGT process.
P90 P50 P10 Units
The lifespan of the CBM-CCGT process 41 37 25 YearsTime for selling electricity 20 15 10 YearsTime for producing gas 41 37 25 YearsTime for selling gas only 21 22 15 Years
Table 8The CAPEX (capital expenditure) for the CCGT development.
CCGT capital costs (CAPEX) Costs Units Reference
Pre-licencing, technical and design 12 £/kW [33]Regulatory, licencing and public enquiry 0.4 £/kW [33]Engineering, procurement and construction 640 £/kW [33]Infrastructure 16.5 £/kW [33]
V. Sarhosis et al. / Energy 107 (2016) 580e594590
Also, for each of the P10, P50 and P90 scenarios and from Fig. 8,the length of the pipelines estimated. The cost for the constructionof the pipelines is shown in Table 9. The cost of the frackingequipment and the number of water pumping units required foreach scenario estimated based on the number of boreholes to bedrilled and results are shown in Table 10. The CAPEX for CBMproduction is shown in Fig. 11. Also, the CAPEX for the CCGT powerplant includes licencing, engineering, procurement, constructionworks and is shown in Table 11.
5.4. OPEX (Operational expenditure)
OPEX includes the total funds required for ongoing operationssuch as well drilling, hydraulic fracturing, water extraction from theboreholes and water treatment facilities, and the overall mainte-nance of the CBM-CCGT infrastructure facilities. Costs shown inTables 12 and 13 have been used for the estimation of the OPEX.Such costs are representative for the UK market.
Drilling cost is highly dependent on the depth of the target coalseams and the number of boreholes. In this study, the majority ofthe drilling work considered to be undertaken at the first year. Thecost of hydraulic fracturing will also depend on the depth of thetarget coal seams, the reservoir properties (e.g. permeability) andthe amount of frackingmaterial (e.g. fracking fluid, propends etc) tobe injected in the boreholes. The cost of pumping water out of thewell will depend primarily on the local geological conditions. Basedon the amount of water to be extracted, the size of the pumpsdetermined. Based on historic data from past CBM exploration, itwas assumed that the amount of water to be abstracted from eachborehole per day could be on average 58 barrels per day [35]. Foreach of the scenarios studied, the total cost of drilling, fracking andextracting water is shown in Table 14. Also, the maintenance costassumed to be equal to 10% of the actual costs for each equipmentand infrastructure facility. Fig. 12 shows the total OPEX for the CBMdevelopment over the entire lifespan of the project. From Fig. 12,drilling of the boreholes and maintenance costs are by far thelargest. Table 15 shows the OPEX for the CCGT process and includesthe operating costs and maintenance costs.
Table 7The costs of infrastructure and equipment (CAPEX) for CBM development.
Others Cost of decommissioning boreholesSafety, monitoring, licences and verification costsEnvironmental impact assessmentOther infrastructures
5.5. CoI (Cost of investment)
Cost of investment includes the funds required for the planningperiod as well as for the OPEX for the first year of the project. Eq. (7)shows the CoI (cost of investment) for a CBM-CCGT includes boththe total CAPEX and OPEX.
CoI ¼ CAPEXn þ OPEXn ; (7)
where n is equal to the time period in years.The costs of investment is shown in Table 16 and has been
calculated by adding the CAPEX and OPEX for the coupled CBM andCCGT process. The discount rate estimates for coal bed methaneoperations are subject to a significant degree of uncertainty in UK.The approach for estimating the future evolution of discount ratesrelies on high-level policy scenarios and this is not part of thisstudy. The discount rate considered in this study is equal to 5%.Although a 5% discount rate might be adequate for government, itwould not possibly be adequate for any company. However, un-certainties and assumptions made in the model can be asses in thecontext of a sensitivity study and quantify the potential risk; suchstudied are not part of this paper. The NPV (net present value) totalcosts estimated using the cost of investment and investment peryear.
5.6. Net present value and LCOE (levelised costs of electricity)
The NPV (net present value) of EG (electricity generation)calculated by Ref. [11]:
NPV EG ¼X
n
NEGn
ð1þ DRÞn; (8)
where NEG is the net electricity generation, n is equal to the timeperiod and the DR (discount rate) is the interest rate in percentages.The expected outputs are expressed in net present value terms,resulted in discounted future costs, when comparing to the outputtoday. The expected costs are also expressed in net present valueterms, resulted in discounted future costs, when compared to costs
Table 9Cost of constructing the pipeline network (to be read in conjunction with Table 1).
P90 P50 P10
a) Distance of pipelines from the GCP (gas collection point) to boreholes (m) 5437 m 7822 m 8871 mCosts £630,683 £907,298 £1,029,009b) Distance of pipelines from GCP to GSU (gas storage unit) (m) 4388 m 4817 5008 mCosts £508,972 £558,763 £580,892c) Distance from GSU to CCGT power station and NG (national grid) 37,000 m 37,000 m 37,000 mCosts £4,292,000 £4,292,000 £4,292,000Total costs £5,431,655 £5,758,061 £5,901,901
Table 10Cost of water pumping unit and fracking equipment (to be read in conjunction withTable 1).
P90 P50 P10
Water pumping unit 11 15 18Costs £220,000 £300,000 £360,000Fracking unit 11 15 18Costs £330,000 £450,000 £540,000
0 2 4 6
Costs of road construction
Costs of Gas Collection Points and GasCompression Units
Costs of Methane Pipeline
Costs of gas storage and gas cleaning upfacility
Costs of Licences, EIA, monitoring,verification and accommodation
Costs of other infrastructure
Costs of fracking and water pumpingequipment
CB
M
Costs (£ in Millions)P90 P50 P10
Fig. 11. CAPEX for the CBM development.
Table 11CAPEX for the CCGT power plant only.
CAPEX for CCGT Costs
Costs of pre-licencing, technical and design £600,000Costs of regulations, licencing and public enquiry £20,000Costs of engineering, procurement and construction £32,000,000Costs of infrastructure £825,000
Table 12The cost of operations per unit (OPEX).
Operations and costs Costs Units Reference
Drilling boreholes 556 £/m e
Fracking per meter depth along the borehole 58 £/m [16]Fracking fluid 5.50 £/m3 [16]Proppant 40 £/m3 [16]Water pumping 0.03 £/m3 [38]Labour 300,000 £/year e
Electricity for general purposes 10,000 £/year [14]Fuel for water pumps 10,000 £/year [14]Water disposal (no treatment) 50,000 £/year [38]Remediation costs (one off) 100,000 £ [10]
V. Sarhosis et al. / Energy 107 (2016) 580e594 591
today. The sum of NPV (net present value) of the TC (total expectedcosts) of developing a CCGT for each year is:
NPVCBM�CCGT ¼X
n
ðCAPEX þ OPEX Þnð1þ DRÞn ; (9)
where DR is the discount rate. According to the DECC [11]; thelevelised cost of electricity generation is the discounted lifetimecost of ownership and use of a generation asset, converted into anequivalent unit of cost of generation in £/MWh.
The levelised cost of the CCGT is the ratio of the total costs of ageneric CCGT plant (including both CAPEX and OPEX), to the totalamount of electricity expected to be generated over the plant'sentire lifetime. Both are expressed in net present value terms. Thismeans that future costs and outputs are discounted, whencompared to costs and outputs today. The LCOE (levelised cost ofelectricity) expressed by:
LCOE ¼ NPVTC
NPVEG; (10)
where NPV of TC is the net present value of the total costs and NPVof EG is the NPV (net present value) of electricity generation. Thelevelised costs relates only to those costs accruing to the owner (oroperator) of the asset [11].
The LCOE (levelised costs of electricity) calculated by dividingthe NPV total costs by the NPV electricity generation. The total NPVsand the LCOE for each CBM reserves are shown in Table 17. TheLCOE for a typical CCGT power plant in the UK is in the range of70e80 £/MWh [11]. The LCOE in this study is lower and ranges from34 to 42 £/MWh since only a 50MW capacity CCGT power plant hasbeen considered.
5.7. R (Revenues) and CF (cash flows)
The amount of gas to be fed to a CCGT power plant per year isfixed. Depending on the gas production flow rates, there may bethat a significant amount of the yearly produced gas will be fed tothe CCGT while the remaining gas will be sold to the national gasgrid. Therefore, revenues may well arise from both: a) the elec-tricity to be produced by the CBM-CCGT process; and b) the surplusgas which will be fed into the national gas grid (Fig. 1). Effectively,the electricity produced will be sold to the national electricity gridaccording to the wholesale electricity price per year whereas theremaining gas produced will be sold to the national grid accordingto themarket price of gas. Future gas prices can be derived from theprojections available by Navigant (UK prices) and shown in Fig. 13.In 2014, the gas price was £0.24 per m3 [11]. The increase in thefuture gas prices are due to the projected yearly inflations, thegrowth in economy and the growth in GDP (gross domestic prod-uct) [30]. The wholesale electricity prices projected by DECC [11]can be used to calculate the revenues from selling the electricitygenerated from the coupled CBM-CCGT (Fig. 14).
Table 13The costs of operations for a CCGT.
CCGT operating costs (OPEX) Costs Units References
Operating and maintenance fixed fees 23,182 £/MW/year [33]Operating and maintenance variable fees 0.100 £/MWh [33]Insurance 2727 £/MW/year [33]Connection and UoS (Use of System) charges 1484 £/MW/year [33]Carbon costs 1.0 £/MWh [33]
Table 14The costs of drilling, fracking and extracting water for each CBM reserves.
OPEX costs for CBM P90 P50 P10
Costs of drilling boreholes (£m) 3.88 4.29 4.10Costs of Fracking (£m) 0.54 0.66 0.64Costs of water Extractions (£m) 1.35 1.67 1.35
0 10 20 30
Costs of drilling, fracking and waterextrac on
Costs of Maintenance
Costs of fuel and electricity
Costs of water disposal and remedia on
Costs of Labour
Costs in £ (Millions)P90 P50 P10
Fig. 12. The OPEX for CBM development.
Table 15The OPEX for CCGT power plant only.
OPEX for CCGT P90 P50 P10
Costs of operating and maintenance(fixed) (£m)
23.2 17.4 11.59
Costs of operating and maintenance(variable) (£m)
0.57 0.41 0.26
Costs of insurance (£m) 2.73 2.05 1.36Costs of connection and UoS
(use of system) (£m)1.48 1.11 0.74
CC (Carbon costs) (according to DECC)(£m)
48 31 16
Table 16The cost of investment and the investment per year.
P90 P50 P10
Cost of investment (£m) 46 47 46Investment per year for CBM-CCGT (£m) 4.75 4.55 4.21Investment per year for CBM only (£m) 0.95 0.999 1.01
Cash flow analysis should also be carried out to determine thecumulative gains from the revenues made after deducting theyearly outgoing costs, tax and insurance [36]. The cumulative CF(cash flow) at a given time calculated using Eq. (11):
CFn ¼X
nðRn � OCnÞ; (11)
where R are the revenues (or the total amount of cash the businessreceives from customers as payment for use of gas), OC are theoutgoing costs and n is the time period.
Revenues from selling electricity and coal bed methane to thenational grid have been calculated and are summarised in Fig. 15.Revenues from selling electricity to the national grid estimatedusing the DECC wholesale electricity prices [10]. Also, the revenuesfrom selling the excess coal bed methane have been determinedusing the Navigant UK gas prices [30]. From Fig. 16, for the differentP10, P50 and P90 scenarios studied, revenues described by adeclining trend which follows the production of coal bed methaneand electricity generation trends obtained. Also, Fig. 16 shows theoverall NPV of the project starting from CAPEX in year zero and thecumulating the subsequent annual cash flows multiplied by thediscount factor (1/(1 þ DR))t. Also, the yearly investment, 20% VAThave been deducted from the revenues. From the results analysis it
£0
£2
£4
£6
£8
£10
£12
£14
£16
£1820
14
2016
2018
2020
2022
2024
2026
2028
2030
2032
2034
2036
2038
2040
2042
2044
2046
2048
2050
2052
2052
Reve
nues
in M
illio
ns (£
)
Years
P90 P50 P10
Fig. 15. Revenues from selling electricity and coal bed methane to the national grid.
Fig. 16. Overall NPV for the project for each CBM reserves studied.
V. Sarhosis et al. / Energy 107 (2016) 580e594 593
was found that for the P90 scenario, payout obtained after fouryears and the cumulative profits obtained over the project life are£100 million (Fig. 12).
5.8. ROI (Return on investment)
ROI (Return on investment) used to determine the amount ofadditional profits produced due to a certain investment. ROI iscommonly used to compare different scenarios for investments andassess the one to produce the greatest profit and benefit. The ROIcalculated using Eq. (12):
ROI ð%Þ ¼ GfI� CoICoI
x 100; (12)
where GfI is the gain from investment and CoF is the cost of in-vestment. In Equation (12), “Gain from Investment” refers to theproceeds obtained from the sale of the investment of interest.Because ROI is measured as a percentage, it can be easily comparedwith returns from other investments, allowing one to measure avariety of types of investments against one another.
For each of the three scenarios studied, the return on invest-ment calculated and comparisons made. First, the cost of in-vestment needed to start the CBM-CCGT was estimated and thenit was used to calculate the ROI according to the Eq. (12). Theresults are shown in Table 18. For the three scenarios studied, the
Table 18The ROI (return on investment) for each of the CBM reserves.
P90 P50 P10
ROI (Return on Investment) (%) 116% 78% 40%
ROI ranged from 40% to 116% while the probable ROI found to beequal to 78%.
6. Conclusions
The development and application of a dynamic model forcalculating the return on investment for a coupled CBM-CCGToperation at a study area in the South Wales Coalfield is pre-sented. A coal resource area was selected based on a series of siteselection criteria. Statistical analysis on the reservoir parameters(i.e. thickness of the coal seams, recovery factor and gas content)have been undertaken. Using results fromMonte Carlo simulationsthe EUR (enhanced ultimate recovery) estimated for the threescenarios: a) P10 - possible; b) P50 - probable; and c) P90 - provedvalues. Also, the revenues for utilising the recoverable coal bedmethane to generate electricity by a CCGT power plant and sellingthe electricity generated to the national electricity grid has beencalculated.
The economics of the CBM are highly site specific dependingupon the reservoir quality and cost/price relationships found ineach individual basin and specific project. In this study, every effortmade to make this analysis on basis using common assumptions.The process design and parameter value choices underlying thisanalysis are mainly based on public domain literature. For thesereasons, these results are not indicative of potential performance,but are meant to represent the most likely performance given thecurrent state of public knowledge.
At the perspective site, for the P50 scenario, results from theoverall model show that the coupled CBM-CCGT development canyield a cash flow profit of £83 million in 37 Years. This results inreturn on investment of 77.6% based on an investment of £47million for the first year. Also, the LCOE (levelised costs of elec-tricity) calculated and found to range from 34.3 to 41.8 £/MWhaccordingly. For the selected study area, the coupled CBM-CCGTprocess is considered as an economic option for power generation.
The methodology presented in this paper can be applied to anynew or emerging coal bed methane development project to assistin quantification of the economics. In the future, a sensitivity studywill be undertakenwith the aim to provide and evaluate the overalleconomic viability of South Wales CBM resource and the factorswith most impact on the economic viability of CBM resource.
Acknowledgements
The work described in this paper has been carried out as part ofthe SEREN project within the GRC (Geo-environmental ResearchCentre) at Cardiff University and funded by the Welsh EuropeanFunding Office (WEFO). The financial support is gratefullyacknowledged.
References
[1] Adams HF. The seams of the South Wales Coalfield, a monograph. London: TheInstitute of Mining Engineers; 1967.
[2] Airey EM. Gas emission from broken coal. An experimental and theoreticalinvestigation. Internat J Rock Mech Hin Sci 1969;5:475e94.
[3] Archer C, Glaister S. Investing in roads: pricing, costs and new capacity.Department of Civil and Environmental Engineering. Imperial College London;2006. November 2006.
[4] Bevins RE, White SC, Robinson D. The South Wales coalfield: low grademetamorphism in a foreland basin setting. Geol Mag 1996;133:739e49.
[5] Creedy DP. Methods for the evaluation of seam gas content from measure-ments on coal samples. Min Sci Technol 1986;3:141e60.
[6] Creedy DP. Prospects for coalbed methane in Britain. In: Coalbed methaneextraction, an analysis of UK and European resources and potential fordevelopment. Cavendish Conference Centre, London January 1994; 1994.
[7] Creedy DP. Coalbed methane e the R&D needs of the UK. DTI Cleaner coaltechnology report No. COAL R163. Haewell, UK: ETSU; 1999.
[8] Clarkson CR. Production data analysis of unconventional gas wells: reviewtheory and best practices. Int J Coal Geol 2013:101e46.
[9] Clarkson CR. Reservoir engineering for unconventional gas reservoirs: whatdo we have to consider?. In: Society of Petroleum Engineers. SPE NorthAmerican Unconventional Gas Conference and Exhibition, Woodlands, 14e16June 2011, Texas, USA; 2011.
[10] DECC. The unconventional hydrocarbon resources of Britain's onshore basinse coal Bed Methane CBM. 2013. Promote UK Report 2013.
[11] DECC. Electricity generation costs for July 2013. 2013. Department of Energy& Climate Change 3 Whitehall Place, 13D/185.
[12] DECC. Dukes natural gas 2014. 2014. National statistics.[13] DECC. The unconventional hydrocarbon resources of Britain's onshore basins
e coalbed methane (CBM). London, UK: DECC; 2015a.[14] DECC. Oil and gas: petroleum licensing guidance. 2015. Available at: https://
www.gov.uk/guidance/oil-and-gas-petroleum-licensing-guidance.[15] DTI. UK capability: coalbed methane extraction and utilisation. 2001. UK
Capability Report October 2001.[16] EnergyBiz. USA hydraulic fracturing technology evolves and improves. 2014.
[17] Freij-Ayoub R. Opportunities and challenges to coal bed methane productionin Australia. J Petroleum Sci Eng 2012;1e4:88e9.
[18] Gray I. Reservoir engineering in coal seams part 1: the physical process of gasstorage and movement in coal seams. SPE Reserv Eval Eng (SPERE) 1987:28e34.
[19] Hammond GP, Ondo Akwe SS, Williams S. Techno-economic appraisal offossil-fuelled power generation systems with carbon dioxide capture andstorage. Energy 2011;36(2):975e84.
[20] Harris IH, Davies GA, Gayer RA, Williams K. Enhanced methane desorptioncharacteristics from South Wales anthracites affected by tectonically inducedfracture sets. In: Gayer RA, Harris I, editors. Coalbed methane and coal geol-ogy, 109. Geological Society Special Publication; 1996. p. 181e96.
[21] Hosking LJ, Thomas HR, Sarhosis V, Koj A, Price N. Assessment of reservoirconditions and engineering factors influencing coal bed methane recovery inthe South Wales Coalfield. In: XV Panamerican Conference on Soil Mechanicsand Geotechnical Engineering, Buenos Aires, Argentina; 2015.
[22] Hughes BD, Logan TL. How to design a coalbed methane well. Pet Eng Int1990;5(62):16e20.
[23] Hunt AM, Steele DJ. Coal bed methane development in the Appalachian basin.Q Rev Methane Coal Seams Technol July 1991;1(No. 4):10e9.
[24] Jones NS, Holloway S, Smith NJP, Browne MAE, Creedy DP, Garner K, et al. UKcoal resource for new exploitation technologies. Department of Trade andIndustry; 2004 [Report No. Coal R271 DTI/Pub URN 04/1879].
[25] Mazumder S, Wolf KHAA. An overview of the potentials and prospects ofcoalbed methane exploration and exploitation in the permo-carboniferous
coal measures of the Barakar formation, Jharia basin, India. In: GeologicaBelgica, Special Issue on Coal, 7, No. 3e4; 2004. p. 147e56. ISSN: 1374-8505.
[26] Khalilpour R, Karimi IA. Evaluation of utilization alternatives for strandednatural gas. Energy 2012;40(1):317e28. http://dx.doi.org/10.1016/j.en-ergy.2012.01.068. ISSN 0360-5442.
[27] McGlade C, Speirs J, Sorrell S. Unconventional gas e a review of regional andglobal resource estimates. Energy 2013;55(15):571e84. ISSN 0360e5442.
[28] Moore TA. Coalbed methane: a review. Int J Coal Geol 2012;101:36e81.[29] National Wales Assembly UK, Llewellyn L. National Wales assembly report:
shale gas and CBM (unconventional gas). 2012. NWA report September 2012.[Paper no. 12/041].
[30] Navigant UK. Unconventional gas: the potential impact on UK gas prices.2014. Report for Department of Energy and Climate Change (DECC).
[31] Oil and Gas Authority. Oil and Gas: onshore maps and GIS shapefiles. 2013.Available at: https://www.gov.uk/oil-and-gas-onshore-maps-and-gis-shapefiles [accessed 12.03.15].
[32] Oosterhuis F. Costs and benefits of the EIA directive. 2007. Final report for DGEnvironment under specific agreement. No. 07010401/2006/447176/FRN/G1.
[33] Parsons Brinckerhoff. Electricity generation cost model e 2011 Update revi-sion 1. 2011. Report for Department of Energy and Climate Change (DECC).
[34] Plaid Cymru Shadow Minister for Energy. Unleashing Wales' natural resourcepotential. 2014. Policy Paper Plaid Cymru February 2014.
[35] Rice CA, Nuccio V. Water produced with coal-bed methane. 2000. USGS FactSheet, 2 p, available online at: http://pubs.usgs.gov/fs/fs-156-00.
[36] Rogers R, Ramurthy M, Rodvelt G, Mullen M. Coalbed methane: principles andpractices second edition. LLC, Starkville: Halliburton. Oktibbeha Publishing;2007 [MS 39759].
[37] Shi JQ, Durucan S. A model for changes in coalbed permeability during pri-mary and enhanced methane recovery. 2005. SPE Reservoir Evaluation andEngineering (SPERE).
[38] SouthWest Water. How much water is a cubic metre and how much does itcost?. 2015. http://southwestwater.custhelp.com/app/answers/detail/a_id/172/~/how-much-water-is-a-cubic-metre-and-how-much-does-it-cost%3F[accessed 03.03.15].
[39] Van Bergen F, Pagnier HJM, Damen K, Faaij APC, Ribberink JS. Feasibility studyon CO2 sequestration and enhanced CBM production in zuid-limburg. 2003.Report for Novem 2003.
[40] Wang GGX, Zhang X, Wei X, Fu X, Jiang B, Qin Y. A review on transport of coalseam gas and its impact on coalbed methane recovery. Front Chem Sci Eng2011:139e61.
[41] Zhou F, Hou W, Allinson G, Wu J, Wang J, Cinar Y. A feasibility study of ECBMrecovery and CO2 Storage for producing CBM field in Southeast Qinshui Basin,China. Int J Greenh Gas Control 2013;19:26e40.
