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The Economics of CO 2 EOR in the UKCS: A Case Study of a Cluster Development in the Central North Sea Professor Alex Kemp and Dr Sola Kasim
The Economics of CO2 EOR in the UKCS: A Case Study of a Cluster Development in
the Central North Sea
Professor Alex Kemp and
Dr Sola Kasim
The present research study sets out to examine whether a CO2 collecDon hub based at St Fergus (or Peterhead) plus a cluster of fields in the Central North Sea and Outer Moray Firth could produce an economically viable industry over the longer term. The concept is hub with communal pipeline spokes and cluster EOR developments to produce economies of scale and risk sharing.
Economic Benefits of Hub and Communal Spokes
1. Economies of scale at hub with respect to compression and other acDviDes necessary to prepare CO2 for transportaDon in supercriDcal form to oil fields.
2. Economies in transportaDon costs through use of exisDng pipelines where possible. ModificaDons and refurbishment (someDmes major) may be necessary. Spur pipelines to some individual fields will be necessary.
3. Pipelines which can be used to supply more than 1 field (with added spurs) include Miller, Goldeneye, and old ForDes oil pipeline (with major refurbishment).
4. Various fields were considered for detailed modelling with consideraDon being given to their EOR potenDal eventual capacity, potenDal injecDvity, as well as proximity to exisDng pipelines. The following fields were analysed: (a) ForDes, Alba and Nelson (b) Buzzard (c) Claymore, Tartan, ScoX, Miller and Brae
UK Oil Fields with Significant CO2 InjecDon EOR PotenDal and Backbone Pipelines
ExisDng and PotenDal Pipelines in a FuturisDc CO2-‐EOR Cluster System
Relevant Details of the Selected Fields Name Distance from
onshore hub (km)
Water depth (m)
(1)
OOIP (mmbbls) (2)
Produced oil as at end 2012 (mmbbls) 3)
Water cut as at end 2012 (%) (4)
Decommissioning status (5)
Alba 190 138 1000 432 90 Field-‐in-‐producDon
Brae 230 106 610a 399 73 Field-‐in-‐producDon
Buzzard 62 100 1200 358 21 Field-‐in-‐producDon
Claymore 141 104 1460 590 78 Field-‐in-‐producDon
ForDes 171 128 5100 3618 90 Field-‐in-‐producDon
Miller 242 100 345 a 311b 90 b Decommissioned
Nelson 176 87 790 432 91 Field-‐in-‐producDon
ScoX 146 140 946 399 90 Field-‐in-‐producDon
Tartan 144 140 136 a 111 87 Field-‐in-‐producDon
Sources: Column 1: DECC Column 2: (a) DECC for recoverable reserves originally present.
(b) Several sources described in the text. Column 3: Operators’ database.
Column 4: Authors' own calculaDons from DECC data. Column 5: Operators’ database
Notes: (a) Recoverable reserves originally present (b) As at 2007 when oil producDon ceased
Methodology 1. Financial SimulaDon Modelling of Costs and
Returns 2. Both DeterminisDc and StochasDc Variables
to Reflect Risks (Monte Carlo Technique employed)
𝑁𝑃𝑉𝑖 = ∑ (𝑅𝑡−𝐸𝑡−𝑋𝑡)(1+𝑟)𝑡
𝑇𝑡=1 –∑ 𝐶𝑡
(1+𝑟)𝑡 𝑇𝑡=0 (1)
where:
Rt = revenues at time t
Et =operating expenses (OPEX) at time t
Xt = tax paid at time t
Ct = the capital expenditure at time t
r = the discount rate (10% used in study)
t = time (t0 = 2020)
T = terminal year (=2050 in study)
Table 1: A Spreadsheet model of key EOR-‐related investment variables
A Physical data Year 1 Year 2.... Final Year (i) Distances to: (a) Backbone pipeline (km) or, (b) Onshore CO2 hub (km) (ii) Reserves (a) OOIP (mmbbls) (b) Produced oil to date (mmbbls) (c) COP date (without EOR) (iii) Water-related (a) Water depth (m) (b) Water cut (%) (iv) Wells (a) No. of existing injectors (b) No. of existing producers (c) No. of injectors modified for EOR (d) Well capacity (MtCO2/year) (v) CO2 Injection (a) Volume of CO2-EOR purchased (MtCO2/year) (b) Volume of CO2 recycled (MtCO2e/year) (c) Volume of hc gas produced (MtCO2e/year) (d) Volume of CO2 injected (MtCO2/yr) (vi) Production (a) Injection-output ratio (tCO2/bbl) (b) EOR oil production (mmbbls/yr) (c) Volume of CO2 emissions infield
Table 1: A Spreadsheet model of key EOR-‐related investment variables (cont.)
B1 Financial data – Costs 1. CAPEX (Ct) (i) Infrastructure investment (a) Pipeline investment (£m) (b) Well rework (£m) (c) Surface facility (£m) (ii) Injector capital (£m) (iii) Recycle system (£m) (iv) Monitoring (£m/MtCO2/year) Total Incremental CAPEX (£m) 2. OPEX (Et) (i) Cost of purchased CO2 (£m) (ii) Recycle cost (iii) Purchase of CO2 allowances under EU-ETS (£m) (iv) Other Incremental O&M (£m) Total Incremental OPEX (£m) B2. Financial data – Revenues (Rt) (i) Oil price (ii) CO2 Sequestration fees (£m) Total revenue (£m) Tax allowances (£m)
Tax paid (£m) (Xt)
Net cash flow
Physical RelaDonships 1. Imported CO2 dominates the whole process
in the early years. Subsequently CO2 is produced with EOR and recycled CO2 becomes increasingly significant. Modelling adapted from studies of USA experience.
RelaDonships between injected and produced gases
0
1
2
3
4
5
6
7
1 2 3 4 5 6 7 8
MtCO2/year
time period
Volume of hc gas produced (MtCO2e per year)
Volumes of CO2-‐EOR purchased (MtCO2/yr)
Volume of CO2 produced and recycled (MtCO2e per year)
Volume of CO2 injected (MtCO2/yr)
Physical RelaDonships (cont.)
2. EOR yield from CO2 injecDon (barrels per tonne) treated as stochasDc variable with minimum of 0.38, most likely of 0.55 and maximum of 0.63 (all based on Senergy (2009)).
Physical RelaDonships (cont.)
3. Diminishing returns over Dme in yield captured in following relaDonship: Ot = a1It + a2It² + µt
where: Ot = oil yield per tonne of CO2 injected at time t It = amount of CO2 injected at time t µt = the error term
Capital Costs (StochasDc) Total calculated as sum of elements as follows: a) Surface faciliDes-‐fixed plagorm or sub-‐sea
wellheads b) Wells rework/conversion and injecDon c) CO2 recycle system d) Monitoring capex e) Number of CO2 injecDon wells determined by
esDmated EOR potenDal and exisDng wells. All above esDmated from literature
Pipeline CAPEX (£m) Total CAPEX (£m)
Networked Non-‐networked Range Mean
15 72 381-‐434 408
3 79 295-‐337 316
1 33 804-‐920 802
9 85 667-‐771 719
126 126 1534-‐1714 1620
171 171 569-‐634 601
11 68 523-‐597 500
3 80 1402-‐1622 1500
5 82 444-‐507 475
OperaDng Costs Total calculated as sum of elements as follows: a) Field operaDng costs b) Recycling costs c) CO2 price with 2 cases: (i) Low Price with minimum of £0, most likely £5, and
maximum £20 (per tonne) all in real terms from 2020 onwards
(ii) High Price based on CPF at £30 per tonne in 2020 increasing to most likely value of £76 between 2030 and 2050.
Revenues
1. Oil price stochasDc in period 2020-‐2050 with minimum value of $90 per barrel likeliest $128, and maximum $195 (real terms).
2. Storage fees stochasDc with minimum £8 per tonne, £11 most likely and £14 highest.
0
20
40
60
80
100
120
140
160
180
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
Oil Price AssumpAons £ barrel (real 2013 prices)
OBR Central OBR High DECC Central DECC High Source: OBR July 2013
World oil prices in three cases, 1990-‐2040 (2011 dollars per barrel, Brent crude oil)
Source: EIA 2013
CumulaDve CO2 Stored by 2050 Field Name PotenDal CO2 Supply
(MtCO2)
Alba 18
Brae 14
Buzzard 39
Claymore 28
ForAes 77
Miller 21
Nelson 25
ScoQ 45
Tartan 21
TOTAL 288
CumulaDve EOR Field Name EOR (mmbbls)
Alba 36-‐67
Brae 30-‐54
Buzzard 60-‐145
Claymore 64-‐107
ForAes 177-‐296
Miller 48-‐80
Nelson 52-‐94
ScoQ 105-‐224
Tartan 48-‐80
TOTAL 610-‐1116
A Comparison of EOR NPVs under AlternaDve Carbon Price and Tax Regimes
Field name
Mean NPV (£m) (real 2010)
Coefficient of variaAon
CumulaAve tax paid (£m)
Low Price Mean per barrel (£/bbl)
Pre-‐tax Post-‐tax
Low Price
High Price 81% rate 62% rate CAPEX
OPEX
Low Price
High Price
Low Price
Low Price
High Price
Alba 299 -‐160 54 0.26 -‐0.51 1747 1337 10 35 73
Brae 190 -‐175 34 0.39 -‐0.42 1173 898 10 37 66
Buzzard 1000 -‐31 383 0.12 -‐4.40 Na 3377 9 57 140
Claymore 569 -‐19 104 0.15 -‐4.04 3324 2544 10 59 108
ForDes 1300 -‐726 234 0.15 -‐0.32 7154 5476 9 171 326
Miller 378 -‐171 141 0.21 -‐0.51 Na 1770 11 34 80
Nelson 465 -‐175 85 0.19 -‐0.54 2649 2027 9 34 80
ScoX 1300 -‐265 235 0.13 -‐0.74 6662 5100 10 99 217
Tartan 407 -‐141 74 0.20 -‐0.62 2109 1614 9 39 84
A Comparison of Pipeline Costs and EOR NPVs (Low CO2 price, post-‐tax NPVs)
Field NPV (£m) Pipeline CAPEX (£m)
networked non-‐networked networked non-‐networked Alba 60 50 15 72
Brae 32 17 3 79 Buzzard 387 375 1 33
Claymore 99 85 9 85 ForDes 224 224 126 126 Miller 136 136 171 171 Nelson 80 70 11 68 ScoX 225 211 3 80 Tartan 70 56 5 82
Total 344 796
NPVs at 95%Probability under AlternaDve Carbon Price AssumpDons
Field NPV range @ 95% probability (£m)
Low Price High Price minimum maximum minimum maximum
Alba 26 82 -‐319 2 Brae 8 61 -‐323 -‐27 Buzzard 293 472 -‐303 241 Claymore 73 134 -‐176 137 ForDes 163 305 -‐1200 -‐262 Miller 80 201 -‐345 4 Nelson 53 117 -‐364 14 ScoX 172 299 -‐656 126 Tartan 44 104 -‐315 33
Post-‐Tax Returns under AlternaDve Tax AssumpDons and Low CO2 Price
Field name Post-‐tax Mean NPV (£m) (real2010)
NPV/I
With PRT removed ExisAng tax rate With PRT removed
(i.e. 62% rate)
Alba 112 0.17 0.35 Brae 71 0.11 0.24 Buzzard 383 0.51 0.51 Claymore 213 0.16 0.33 ForDes 480 0.15 0.32 Miller 141 0.26 0.26 Nelson 174 0.17 0.34 ScoX 482 0.17 0.35 Tartan 153 0.17 0.35
Alba: Probability distribuDon of the NPVs
Alba: Probability distribuDon of the NPVs
(£m)
• Qualifying criteria: capital costs per incremental tonne of reserves exceeding £60. Allowance increases linearly to maximum of £50 per tonne when capital costs reach £80 per tonne.
• Allowance spread over 5 years. • Maximum allowance: £250m. in non-‐PRT-‐paying fields £500m. in PRT-‐paying fields • BFA currently does NOT apply to CO2 EOR
£ per tonne
50
0 60 80Capital costs per tonne of incremental reserves (£)
Brownfield Allowance
BROWNFIELD ALLOWANCE and the ECONOMICS of CO2-‐EOR
Item Alba Brae Buzzard Claymore ForAes Miller Nelson ScoQ Tartan
EOR oil (million tonnes) 6 4 13 9 26 7 8 21 7
Oil price (£/$/bbl) 88/140 88/140 88/140 88/140 88/140 88/140 88/140 88/140 88/140
CAPEX (£m) 408 316 862 719 1624 601 560 1512 475
CAPEX/tonne (£/tonne) 71 70 67 77 63 83 66 73 68
Pre-‐tax NPV/i 0.84 0.58 1.22 0.79 0.77 0.63 0.83 0.85 0.84
BFA field allowance (£m) 163 117 237 390 204 250 135 500 147
Maximum allowance (£m) 500 500 250 500 500 250 500 500 500
Brae (small EOR, PRT field)
Brown Field Allowance (BFA)
Item current x2 x4 x5
unit allowance(£/bbl) 5 10 20 25 Maximum allowance (£m) 500
BFA used (£m) 117 237 474 593
NPV/I post-‐tax 0.13 0.16 0.22 0.24
Miller (medium EOR, non-‐PRT field)
Brown Field Allowance (BFA)
Item current x2 x4 x5
unit allowance (£/bbl) 7 14 28 35
Maximum (£m) 250
BFA used (£m) 250 517 1034 1293
NPV/I post-‐tax 0.41 0.45 0.54 0.58
ForAes (large EOR, PRT field)
Brown Field Allowance (BFA)
Item current x2 x4 x5
unit allowance (£/bbl) 3 6 12 15
Maximum (£m) 500
BFA used (£m) 204 408 836 1407
NPV/I post-‐tax 0.17 0.19 0.24 0.27
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