Introduction to Africary’s Theunissen 50 MW IPP Project ...
Transcript of Introduction to Africary’s Theunissen 50 MW IPP Project ...
COPYRIGHT RESERVED – PROPERTY OF AFRICAN CARBON ENERGY
Mr. Johan Brand,
Director,
African Carbon Energy
10 October 2017
Introduction to Africary’s Theunissen
50 MW – IPP Project
600 MW – PPP Project
1,950 bbl/day – CtL Project
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Location of Theunissen UCG 16 tcf exploration and production (E&P) Facility
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Resource Classification
AreaSAMREC *
Classification
Gross CoalVolumes
(million tons)
Gross SyngasVolumes (PJ)
SPE Category**Gross GasVolumes
(tcf)
UCG Project Measured 3.7 721P Reserve
(Proven) 15 years72 bcf
PalmietkuilFarms
Indicated+
Inferred
5.0+
21447
2P Reserve (Proven + Probable)
120 years0.5 tcf
TheunissenResource
Inferred 1,000 16,5603P Reserve
(Proven + Probable + Possible)
16.6 tcf
3
* SAMREC classification as signed off by a Competent person.
**SPE = Society of Petroleum Engineers category, but the values in the table are indicative only
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The TUCG Project Status
Step 1: Domestic Gas-IPP program a suitable electricity Market - from DOE
Step 2: Purchased UCG coal 2012: 1 billion ton Resource - from BHP
Step 3: Explored the resource and obtain surface rights (600 ha)
Step 4: Designed and finalized engineering for the mine & 50MW power station
Step 5: Bankable Feasibility Study + Financial assessment – PWC
Step 6: Received Environmental Approval & Emission permits in 2015
Step 7: Received Mining Right Application Approval in 2016
Step 8: Bank project support approval – Signed Nedbank
Step 9: EPC and O&M service level agreements – Signed Group5
Step 10: IPP Office indicated domestic Gas RFP in 2018
PPA Offtake Agreement and Financial Close by Q4/2018
Operations planned from Q4/2020 [24 month construction period]
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Africary’s future:120 year’s of coal under our farms
8
60 years of production in the East Farm
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OWNERS CAPACITY (bbls/ day)
NATREF (Total + Sasol) 108 5000
SASOL >160 000
SAPREF (Shell + BP) 180 000
PETROSA 45 000
CHEFREF (Chevron + Caltex) 110 000
Liquid fuels production
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Flow Scheme Options
10
Combined Heat and Power Generation
Methanol& Higher Alcohols
Substitute Natural Gas (SNG)
FT Syncrude
Hydrogen
GasificationSyngas
To Oxo Chemicals & Derivatives
MTBEFormaldehideDMEAcetic AcidAcetaldehydeAcetic AnhydrideChloromethanesDMTMMAMethyl Amine
Ethylene & Propylene
Gasoline &Diesel Fuel
Gasoline & Diesel FuelEthylene & Propylene
Urea (fertiliser)
To Refining Upgradingto Naphtha Steam CrackerAlpha OlifinsLube Oil Based StockSpecial Waxes
To Hydrogenation (Pet refining & Others)To HydrocrackingTo Ammonia SynthesisPossible Fuel-Cell Fuel
Possible Fuel-Cell Fuel
IGCC (Integrated
Gasification Combined
Cycle) or Gas-Engine
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World Bank mini-GTL evaluation
Overall Risk and Time to Commercialization
TIME TO COMMERCIALIZATION
OV
ER
ALL R
ISK
LONGSHORT
HIGH
LOW
METHION
OBERON
Africary has signed agreement with CGTL to perform a CTL study for 2,000 bbl/day
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12
CompactGTL’s Demonstration Plant Aracaju, Brazil
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Case 1a: Dual stage FT unit with H2:CO ~1.92 and cooler on FT tail gas
Syngas from
Battery limits
PSA /
membrane
(TBC)
P2P1
P5
Make-up H2
FT reaction
water
FT tail gas
to fuel
Syngas
to FT
Battery limits of FT unit
P4 Synthetic crude
FT stage 1 FT stage 2
FT cooling system
To fuel gas
P3
Tag Description Mass flow [kg/h]
Vol flow Properties Remarks
P1 Syngas from battery limits 30000 57650Nm3/h See Table 1 Assumed feed gas composition as per Africary Process Design Basis document
P2 Syngas to FT unit 30000 57650Nm3/h See Table 1 Feed gas rate to FT reactors to be finalised when H2generation scheme defined
P4 Synthetic crude (from FT) 6220 1210bpd
Reference (for Case 1a&
Case1b)
Routed to Upgrader for naphthta & diesel production Note: Syncrude for this case (Case 1a) used as reference to evaluate impact of TG chiller
P3 FT tail gas (to fuel) 13030 18150Nm3/h See Table 2 Indicative composition of fuel gas assuming no FT tail gas recycle
P5 FT reactionwater 10440 - See Table 3 Typical composition of combined FT reaction water from product separators in FT unit.
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http://www.sapia.org.za/
Positive Economic Impact
UCG-Polygeneration cost benefits are:
Modular design reduce complexity
Quick (24 months) implementation
Production can be scaled between electricity and liquid fuels
The SA economy has huge demand for LPG, LNG and Hydrogen as alternative fuels
Naphtha production is discouraged with almost no market / demand
The South African Basic Fuel Price
(BFP) is ~ R6.00 per litre or about
$60-70 / bbl and provides a hedge
against the USD oil price
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The economics – Max Fuels
Product Own Use UnitSellable
Production UnitPrice
(ZAR)/unitTurnover
(Rm/year)Annual
Turnover
Oxygenlocal
productionkg/hr kg/hr 0.00 R -0
R 1 642
Nitrogen 5 000 kg/hr kg/hr 0.10 R -4CO2 / (Credits) 10 000 kg/hr kg/hr (0.10) R 8Coal 67 074 kg/hr kg/hr 0.14 R -75Water 62 m3/hr kg/hr 0.01 R -4Electricity 27 MWh 27 MWh 1 030 R 2Diesel 11 294 litre/hr 6.00 R 564Naphtha 200 kg/hr 1 484 litre/hr 6.00 R 64LPG 35 kg/hr 72 kg/hr 17.00 R 5LNG/CNG 8 150 kg/hr 8.00 R 543
Hydrogen 90 580 kg/hr 132.00 R 538Sulphur 206 kg/hr 1.00 R 2
UCG-Polygeneration with several products:
Oxygen requires 8 MWe and is incorporated in the Own Use.
The main sellable product is Ultra Low Sulphur Diesel
LNG/CNG production has a price premium, due to lower fuel taxes
Production can be scaled between electricity and liquid fuels, but in this case Electricity is minimized and is operated on tail and waste gas streams
Hydrogen is priced at $10/kg
Naphtha production to be sold as Illuminating Paraffin.
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The Economics – Max Fuels
Opex includes a 10 year payment at 10% interest of R 4,658 billion
Preliminary financials supports a UCG polygeneration detail study and cost modeling
CAPEX Cost Unit Quantity Unit Exchange rate
Gross annual profit
ASU 13 $/bbl 1 950 bbl/day 13.20 R/Euro R 341
R 651
UCG 15 $/bbl 1 950 bbl/day 13.20 R 379Shift + AGR 31 $/bbl 1 950 bbl/day 13.20 R/Euro R 791FT + Refining 53 $/bbl 1 950 bbl/day 13.20 R/Euro R 1 364LNG 680 $/tpa 70 416 t/a 13.20 R/$ R 632H2 PSA + Compression 5 Euro 580 kg/hr 15.50 R/$ R 78Power Gen 650 Euro/kW 27 000 kW 13.20 R/Euro R 373OBL 12 $/bbl 1 950 bbl/day R 300Indirect and EPCM 19 $/bbl 1 950 bbl/day R 500
Total R 4 658
OPEX Cost Unit Quantity Unit Exchange rateGas Processing + FT 15 $/bbl 1 950 bbl/day 13.20 R/$ R 141Powergen excluding fuel 15 $/MW 27 kW 13.20 R/$ R 45Overheads 5 $/bbl 1 950 bbl/day 13.20 R/$ R 47Capital and Interest R 758
R 991
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Step 1: Purchased UCG coal 2012: 1 billion ton Resource
Step 2: Approved Mining Right Application in 2016
Step 3: Measured 3.7 mT and obtain surface rights (600 ha)
Step 4: Market: Domestic Gas-IPP program + ULSD + LNG
Step 5: Environmental Approval – Half way if power is approved
Step 6: Designed and finalize PFS and BFS engineering for UCG & 30MW & 1,950 bbl/day
Step 7: Financial assessment and then Bankable Feasibility Study
Step 8: IDC project support
Step 9: EPC and O&M service level agreements
Step 10: Offtake Agreements
The CTL Project Status