RULES OF THUMB FOR SCREENING LNG DEVELOPMENTS

Transcription

1 RULES OF THUMB FOR SCREENING LNG DEVELOPMENTS Presentation to IE Aust Perth, 2/10/12 Prepared by Nick White, Director Process Engineering, Clough Presented by Dr Julie Morgan

2 Introduction There are currently A$170 billion of LNG liquefaction projects under development in Australia This presentation provides some rules of thumb for making screening level assessments ofonshore onshore, base loadlng liquefaction developments and includes: Gas reserves required to support an LNG development Criteria for selection of LNG export rather than alternatives such as a pipeline The relationships between production capacity, refrigeration power and emissions LNG storage, loading and shipping requirements CAPEX breakdown of the main components of an LNG development

3 Why Choose LNG for Gas Export? Pipeline vs LNG development determined by distance from supplier to customer: <2500 km: pipeline >2500 km: LNG Liquefaction reduces specific volume of gas by a factor of 600 makingtransportation of large volumes of gas by ship feasible Alternative shipping options such as gas to liquids and compressed natural gas either immature, and/or more expensive LNG a proven technology with excellent safety record Non explosive in liquid or vapour state in unconfined spaces Only one major accident at the operating facilities world wide LNG is environmentally friendly Significantly lower CO2 emissions than coal or oil

4 Feed Gas Supply Gas reserves required: 1 tcf of gas required per Mtpa of LNG over 20 years For an offshore gas field in Australia the minimum economic LNG plant capacity would be approx 4 Mtpa requiring 4 tcf of gas Where does the feed gas go (conventional natural gas)? LNG - 85% Fuel - 8% LPG - 3% C5+ - 2% CO2-2%

5 LNG Liquefaction Plant and LNG Train A LNG plant comprises: Feed gas pipeline reception facilities One or more LNG trains comprising: Gas Pre treatment (Acid Gas (CO2 & H2S) Removal, Dehydration, Mercury Removal) NGL Removal Liquefaction (condenses the NG) End flash (auto refrigerates LNG, removes N2 and recompresses end flash gas for use as fuel gas) Fractionation Separates LPGs for refrigerant and/or product Product storage and loading (including BOG) LNG, Condensate, LPG Refrigerant storage Utilities Power, heating medium, fuel gas, water, instrument air, nitrogen General facilities Firewater, flares, drains, plant buildings and infrastructure Feed Gas from Pipeline Reception Facilities CO2 and H2S Removal Dehydration Mercury Removal LNG Train LPG & C5+ Removal (LNG quality control) Liquefaction Fractionation LPG and Condensate to Storage End Flash Fuel Gas LNG to Storage

6 How Much Power to Produce 1 Mtpa of LNG? Mtpa = Daily production at Tav (tpd) x 365 days pa x System Availability BOG losses Typical average ambient temperature in Northern Australia, Tav = 27 o C 1 Mtpa = 3,220 tpd (37 kg/s) x 365 x 0.88 x (1 0.03) Assuming overall system availability of 88% and 3% BOG losses Enthalpy change to liquefy methane: HG HL = 861 kj/kg Refrigeration duty: H = 37 x 861/1000 = 32 MW Typical specific power for base load LNG plant at an average ambient temperature of 27 o C is 1,120 kj/kg (13 kw/tpd) Refrigeration compression power (work): W = 37 x 1120/1000 = 41 MW Heat rejected dto atmosphere: Q = W + H = = 73 MW Heat Rejection, Q GAS: HGH LNG LIQUEFACTION UNIT LNG: HLH Work, W

7 Rules of Thumb for Liquefaction Plants Factors impacting LNG production: Ambient temp: 1 o C increase reduces LNG production by approx 1.7% Refrigerant condenser: 1% increase in UA increases production by approx 0.3% Feed gas pressure: 1 bar increase raises production by approx 0.7% Feed gas MW: 1% increase raises production by approx 1.4% Fuel gas consumption: 7 to 9% of feed flow (depending on liquefaction technology (specific power) and driver type) Dehydration unit mol sieve regeneration flow: ~7% of feed gas flow CO 2 produced by process: Combustion: 0.25 t CO 2 / t LNG (base load plant with industrial GTs) From AGRU: 1 mol% CO 2 in feed equates to approx 0.03 t CO 2 / t LNG Quantity of LNG shipped ~85% of rundown capacity when account taken of system availability and BOG Overall system availability typically ~88% BOG losses from storage & loading facilities ~3% of LNG rundown rate

8 Size Range of Liquefaction Plants LNG Train Typical Liquefaction Application Capacity Range Technology Mtpa Mini LNG <0.1 Nitrogen expander Peak shaving plants, vehicle fuel, ship boil off gas liquefaction Mid Scale 0.2to 1.5 Single mixed refrigerant For domestic consumption, transport by road or rail Base Load 3 to 5* Propane pre cooled Overseas export by ship mixed refrigerant, dual mixed refrigerant, pure component cascade * 3 to 5 Mtpa trains provide the optimum capacity in terms of economies of scale although larger trains have been constructed (e.g.8 Mtpa in Qatar)

9 Comparison of Liquefaction Technologies Liquefaction Technology Relative LNG Train Capacity Efficiency Range, Mtpa Single expander 1.7 <0.1 Dual expander to Single mixed refrigerant (SMR) to 1.5 Pure component cascade to 6 Propane pre cooled mixed refrigerant (C3 MR) 1.0* 1 to 5 Dual mixed refrigerant (DMR) to 5 APCI APX (C3 MR plus nitrogen expander cycle) to 8 * Specific power at an average ambient temperature of 27oC is approximately 1120 kj/kg (13 kw/tpd)

10 LNG Storage, g, Loading and Shipping Storage volume: volume of largest ship plus 3 days production (approx.) To date largest tank volume 200,000 m 3 MaximumLNG loadingberth occupancy about 50% Typically 8 Mtpa per loading berth to allow for maintenance and other downtime Number of ships determined by ship capacity and distance to import terminal Shipping i from NW Australia to north Asia: Ai one 130, m 3 ship can transport 1 Mtpa (i.e. 15 round trips pa) Conventional ships 130,000 to 145,000 m 3, latest Qmax ships 260,000 m 3

11 Costs of a Base Load LNG Development Current CAPEX of Greenfield LNG developments in Australia (includes upstream development and LNG plant) ~A$2,500 to 3,000/tpa Subsequent ttrains (brownfield) economically very attractive ti as much can be shared with the foundation project giving economies of scale (e.g. gas supply pipelines, LNG storage and loading, infrastructure) LNG Supply Chain CAPEX Breakdown: Upstream Development: 10% LNG Plant: 40% LNG Transportation: 30% Receiving ing & Re gasification Terminal: 20% LNG Plant CAPEX Breakdown: Pre treatment: 6% Liquefaction: 50% Utilities: 16% LNG Storage: 18% Loading Facilities: 10% Note: Liquefaction only 20% of total t supply chain CAPEX. OPEX typically 3% of CAPEX per annum

12 Conclusion Simple rules of thumb have been presented that allow high level screening ofonshore, base loadlng developments withrespect to: Selection of preferred export option Relationship between gas reserves and plant capacity Facility requirements and capacities Factors influencing i process performance Indicative development costs and economies of scale Finally, it should be noted dthese are only rules of thumb and should be used accordingly