Examples are given below for two different types of development project, i.e. a deep or ultra-deep offshore development project and a LNG (liquefied natural gas) supply system (entire cycle including liquefaction, transport and regasification).
Chapter 4Investments and costs
These two examples will give readers a better understanding of the orders of magnitude of the overall costs of projects in the petroleum industry and, in particular, the technical costs expressed per barrel of oil or per unit calorific value of gas, as appropriate.
4.4.5.1 Deep and ultra-deep offshore
This is a very topical theme: many companies are currently interested in exploration in water depths in excess of 1 000 m and even occasionally 2 000 m.
Advances in subsea technologies mean that it now appears feasible to produce hydro-carbons discovered at such depths at a competitive cost.
At more familiar water depths up to 300–400 metres technological progress has led to significant reductions in costs. The cost of producing a barrel of oil (exploration, development and exploitation) at such depths had fallen from $13–15 in the 1980s to $5–7 in 2000 and grew again over $20.
Extrapolating these results suggests that the development of offshore resources in deeper waters should be economically feasible. There are many production concepts of proven viability at moderate depths which could realistically be assumed to constitute the starting point for evaluating deep or ultra-deep offshore development projects (Fig. 4.18).
The petroleum industry is currently focusing its efforts on very deep waters (>2 000 m), with the objective of getting to 3 000 m.
A. Costing methodology
A possible development programme can be evaluated on the basis of two major categories of parameters, those which describe the reservoir itself and those which describe its geographical location.
Chapter 4Investments and costs
Figure 4.18 Deep offshore production concepts.
Parameters associated with the reservoir are usually obtained from a “speculative” seismic exploration survey and by interpreting local geological phenomena. These parameters allow the size of the target object to be estimated, that is the reserves and the extent of the reservoir, as well as its potential, i.e. the density of the reserves, reservoir productivity and the types of fluids.
The second category of parameters includes “physical” data (distance from the coast, water depth, depth of reservoir under the seabed) and data which describe the environment.
These latter data relate to the oceanographic and meteorological conditions, the existing petroleum infrastructure and the extent to which it would be available, the market prospects for the production, local regulations, tax regime, etc.
The values of these parameters will point the evaluator towards the most appropriate development plan.
B. Example of estimation of capital costs
By way of illustration the investment costs are estimated for two prospects of contrasting size and location, both situated in 1500 m of water.
a. Prospect in the Gulf of Guinea
This prospect is situated in 1 500 m of water in the Gulf of Guinea. The hydrocarbon deposits, of centred morphology, extend over an area of 90 km2. They consist of multilayer reservoirs lying at depths of between 900 and 1 700 m below the sea bed. The reserves are estimated to be 750 Mbbl of oil, and the field would have a life of about 20–25 years. The production will plateau at 200 000 bbl/d.
Because of the lack of a local petroleum infrastructure and the remoteness of the markets, the development is based on a FPSO acting as a gathering station for a subsea production network (Fig. 4.19).
Chapter 4Investments and costs
430 m
Cluster of 10 subsea wells
Gathering lines (length ~ 3 km)
• production 2 x 12”
• test 1 x 6”
Export lines (length ~ 2 km) 3 x 12”
Water depth 300 m
Offloads to tanker FPSO (capacity 200,000 bbl/d)
Multiple mooring lines (16 moorage lines)
Figure 4.19 Example of development concept, deep offshore (Gulf of Guinea).
The FPSO, tethered in a fixed position by 16 mooring lines, will comprise a hull 300 m long and 60 m wide with the capacity to store 2 Mbbl of oil. The treatment plant and util-ities will be situated in one or more independent modules on the upper deck. Their net weight (empty) is estimated at 20 000 t.
The production wells will be connected to production manifolds which are joined to the gathering lines. Each production line is made up of two pipes thermally insulated by means of a layer of foam in a metallic case. The water injection wells are connected in twos to the injection manifolds. Three water injection wells are connected to the FPSO by three inde-pendent lines.
The production lines, water and gas injection lines are connected to the FPSO by flexible, thermally insulated connections. A control and command umbilical is attached to each production line and water and gas injection line from the wells and the manifolds.
The oil is pumped into tankers at a loading buoy anchored at a distance of 2 km from the FPSO. The associated gas is re-injected into the top of the reservoir.
In order to determine the sensitivity of this development scheme to the size of the recov-erable reserves per well, two cases are considered, in which there are 48 and 63 production and water and gas injection wells respectively.
The capital costs were estimated by reference to projects similar to the one in question in the Gulf of Guinea and Brazil (see Table 4.6).
Chapter 4Investments and costs
b. Prospect in the Gulf of Mexico
This prospect is situated in 1 500 m of water in the Gulf of Mexico. The reservoir, with an elongated morphology, has an area of 22 km2. It is multilayered, at depths of between 1 800 and 3 000 m below the sea-bed. The reserves are estimated to be 180 Mboe, and the field would have a life of about 15–20 years. The production will plateau at 60 000 bbl/d of oil and 100 Mft3/d of gas. This production level will be achieved by means of 15 wells.
The development concept adopted involves a “spar” floating production platform with a deep draft (Fig. 4.20) with wellhead at the surface and the production being dispatched to existing installations. In contrast with a subsea development, this design has the advantage of carrying out the drilling and production from the same platform, allowing servicing to be carried out on a well without having to mobilise a drilling rig. This system also overcomes the problem of having to transport a multiphase effluent over a long distance. The spar
Table 4.6 Gulf of Guinea prospect: development investments ($M). Water depth: 1500 m – Reserves: 750 Mbbl.
Case 1 Case 2 48 wells 63 wells
Production vessel 1 700 1 700
Subsea equipment & control system 1 000 1 300
Gathering lines 1 700 1 900
Company costs1 600 700
Provisions 500 600
Drilling – Wells 2 000 2 600
Total capital cost ($M) 7 500 8 800
Capital cost ($/boe) 9.9 11.7
1. Project management and supervision, studies, preliminary work, insurance.
comprises a floating structure with a circular cross-section at water surface level and along the length of the flotation tanks on which the production and drilling modules are placed.
The cylindrical shell is 37 m in diameter and 215 m in height, with a hollow square cavity of 18 m square in the middle containing the risers. The spar is anchored by means of 12 semi-taut catenary cables. The risers connecting the seabed to the wellhead at the surface are main-tained under tension independently by means of flotation modules inside the cavity in the shell. The riser contains a special joint at the level of the spar keel in order to accommodate movements of the riser relative to the platform.
The drilling and production module, including the living quarters for 110 persons, is made up of 3 decks 55 m in length, providing a total surface area of the order of 9 000 m2. The empty weight of this module is approximately 9 000 t. All the wells are pre-drilled as far as the surface casing. Four of the wells are drilled into the target formation so that production can commence shortly after the installations are erected and connected. The remaining wells are drilled from the spar.
After separation, the products are exported to pre-existing installations situated in shal-lower water by means of two independent pipelines, i.e. a 10" line, 60 km in length for gas and a 16", 70 km line for oil.
The capital costs were estimated from available data as indicated in Table 4.7.
Chapter 4Investments and costs
Figure 4.20 Artist’s impression of a spar.
Chapter 4Investments and costs
These two examples of deep offshore prospects show that, depending on location, the unit technical costs for fields of quite different sizes can be of a comparable order of magnitude.
4.4.5.2 LNG cycle
The LNG supply cycle comprises, in addition to the gas production and condensate stabili-sation plants, the following subsystems (Fig. 4.21):
– The liquefaction plant, which provides for the treatment, refrigeration and liquefaction of the feed gas, and the storage and loading of the liquefied gas;
– A fleet of LNG tankers to ship the LNG from the treatment plant to the terminal;
– The reception terminal where the LNG is regasified and, possibly, an associated power station.
A. Description
The main characteristics of each component of the cycle are reviewed below.
a. Liquefaction (Fig. 4.22)
There are strict limits on contaminants in the LNG (CO2between 50 and 100 ppmv, total sulphur approximately 3 ppm moles). Gas treatment units upstream of the liquefaction are
Table 4.7 Prospect in Gulf of Mexico: capital cost of development ($ millions).
Water depth: 1 500 m – Reserves: 180 Mbbl.
Production platform1 900
Subsea equipment & control system –
Collection network –
Export system 100
Company costs2 180
Provisions 120
Drilling – Wells 300
Total capital cost ($M) 1 600
Capital cost ($/boe) 8.9
1. Including the drilling function\equipment and the production and export risers.
2. Project management and supervision, studies, preliminary work, insurance.
Pre-processing Liquefaction LNG
GPL Feed
gas
Sales gas
Temperature = – 160°C LNG
plant
Regasification
Losses: 2% + 8% + 2% + 1% = 13%
Refrigeration
LGN Precooling
Figure 4.21 The LNG cycle.
more expensive than traditional liquids removal units. Any mercury in the feed gas is treated at this level; finally the gas is dried by means of molecular sieves before refrigeration.
Two refrigeration cycles are generally needed in order to produce the LNG. The first cycle, which usually produces pure propane, cools the feed gas (usually to –20/30°C) and the refrigerant for the second cycle. The second cycle, which uses a mixture of nitrogen and light hydrocarbons, allows the gas to be condensed and cooled to –160°C. These units make use of large compressors driven by gas or steam turbines.
The natural gas is liquefied in an exchanger (just one per train) with a large heat exchange surface. They are usually spiral tube exchangers 4 metres in diameter and some 60 metres in height.
Depending on the nitrogen content of the feed gas, the liquefied gas will be passed to a denitrification unit in order to reduce the nitrogen content to a level acceptable for its transport (normally 1%). The nitrogen-rich off-gas from this unit is returned to the fuel gas stream.
The heavy hydrocarbons are separated in a fractionation unit. This unit produces a gas rich in ethane which is routed back into the LNG stream. It also produces a propane/butane stream which can be reinjected into the LNG or sold as a separate product and finally, a heavier product with the characteristics of a light condensate.
The liquefied gas is then stored in cryogenic tanks at atmospheric pressure fitted with loading pumps. The gas resulting from the evaporation of the LNG (“boil-off”) is returned to the fuel gas stream by means of dedicated compressors.
The LNG is transferred from the loading bay onto LNG tankers by means of cryogenic loading arms. In view of the size and draft (approximately 14 m) of these vessels, and the precautions which must be taken during product transfer, a dedicated jetty and associated port facilities are needed. A large LNG factory may have several jetties. The LNG plant at Bontang in Indonesia, for example, has three jetties.
Chapter 4Investments and costs
Figure 4.22 Simplified flowchart of a LNG plant.
The liquefaction plant requires the following facilities: a cooling circuit (generally sea water), a heating system (steam, thermal oil or hot water) for the reboilers, fuel gas, power, compressed air and nitrogen (for inerting), a system for gathering and treating the liquid effluents and a system for flaring and liquids burning.
Air-cooling is possible, but all the major plants (except North West Shelf in Australia) use sea water as the coolant.
b. Transport
The LNG market is characterised by long-term contracts, and a dedicated fleet of LNG tankers is normally used to transport the product. The number and size of the tankers forming the fleet is a function of annual volumes of LNG to be transported and the transport distance.
The most common size for a tanker is 135,000 m3or 65,000 dwt, or in energy terms, 3 TBtu per tanker-load. Much larger ships with a 250,000 m3capacity now exist.
A LNG tanker sails typically at 18–19 knots. The longest routes (from the Middle East to Japan) are approximately 6,300 nautical miles and the shortest (Algeria to Spain) about 350 nautical miles.
c. Regasification
On arrival at the reception terminal the LNG is transferred to storage tanks, and subsequently vaporised, after cryogenic pumping, and made available to the end-user. The gases which form due to the natural evaporation of LNG in the terminal installations are reincorporated into the liquefied gas before pumping. The vaporisation is effected either in trickle evapo-rators or in submerged flame vaporisers. If the calorific value of the gas is too high, nitrogen or air is injected into the sales gas.
B. Size of the units
In order to estimate the capital costs it is essential to know the capacity of the plant and the unit size of the liquefaction trains.
a. Capacity of the plant
There are 30 LNG plants throughout the world in 2011. Their capacities range from 1.1 Mt/y (Camel, Algeria, commissioned in 1964) to several 10 Mt/y (Qatar). The capacity of a plant depends on the size of the reserves which it will process and the market for which it will produce.
Only one plant, in Kenai, Alaska, operates with a single liquefaction train; all the other plants have multiple trains. The maximum number of trains is eight, in Bontang.
b. Size of the trains
The capacities of trains of recent design can reach 8 Mt/y, using more powerful mechanical drives. The liquefaction trains are sized on the basis of the markets at which the plant is aimed, but also on the optimum production rate associated with the power of the refriger-ation machine (initially assumed to be 14 kW per tonne of LNG per day).
High-power industrial gas turbines come in only a limited number of sizes. The most appropriate turbine with a power which meets the requirements is therefore chosen. When choosing the rated capacity of the turbine, it should be borne in mind that the power actually available depends on the temperature of the air (there is a 0.7% variation in output power per °C): the capacity of the train will therefore be a function of temperature.
Chapter 4Investments and costs
It should also be noted that most liquefaction plants have been debottlenecked at some stage in their lifetime, leading to an increase compared with the initial (“design” or “name-plate”) capacity of 10–40% or even more.
c. Storage capacity
As a rule of thumb, the storage capacity should be no less than the capacity of a tanker plus a certain number of days” production for the plant when operating at full capacity. This number of days will depend on the particular circumstances of the case, particularly the avail-ability of tanker capacity (which may be disrupted by weather conditions, for example). As a first approximation, 4–5 days should be taken.
The number and sizes of the tanks will depend on the chosen capacity, but also on the unit cost, given that these are lower for a large than a small tank. LNG storage tanks are large: up to 250 000 m3for an above-ground tank.
d. Size of LNG tankers
The size of a LNG tanker can reach 250 000 m3, but smaller vessels might be chosen for short routes depending on the limitations of the destination port.
C. Energy losses
An estimate is made in this section of the mean energy efficiency of the entire LNG supply cycle; this parameter is indispensable for any technico-economic analysis.
The liquefaction plant requires around 10–12% of the feed gas for its own use. The precise figure depends on the pre-treatment necessary, the installations used to load the LNG onto the tankers, the source of power (gas or steam turbine) and the intrinsic efficiency of the liquefaction process.
There is some evaporative loss of LNG during transportation, and this will be burned in the vessel’s boilers. In addition, some LNG will be used to keep the storage areas cold for the return journey. The loss of saleable product is estimated at between 1 and 3%, according to the distance involved. In addition an average of about 1% of the LNG will be used during regasification.
The total energy loss over the entire LNG supply cycle is around 13% (± 2%) of the feed gas.
D. Technical costs
One of the measures of technical costs most commonly found in the literature is the specific project costs (limited to the turnkey or contractor’s cost), expressed in $ per t/y capacity.
These specific costs vary in the range $500 to $800 per t/y, according to the technical defi-nition, but also as a function of environmental factors such as the composition of the gas, the cost of labour, the adequacy and preparation of the onshore or offshore site, the remoteness of the site and the logistics. These costs also depend on the market conditions at the time the construction contract is signed. For a preliminary estimate of the cost of the LNG supply cycle it is suggested that the figures in Table 4.8 are used.
Consider a LNG project involving the transportation of 5 Mt/y over 6 000 nautical miles.
By applying the data in Table 4.8 and by making a few simplifying assumptions, we arrive at a production cost CIF5including regasification but excluding feedgas for LNG of approx-imately $3/MBtu. These costs are broken down in Fig. 4.23.
Chapter 4Investments and costs
5. Cost, Insurance and Freight: the price including the cost of the merchandise, insurance and maritime freight as far as the destination port.
Chapter 4Investments and costs Table 4.8 Estimation of the cost of an LNG cycle using standard factors.
Plant (capacity Proposed cost % Cost range
5 Mt/y, 2 trains) ($M) of total cost ($M)
Reception Proposed cost % Cost range
terminal ($M) of total cost ($M)
Storage 300 33
Cost structure for the LNG cycle ($/MBtu)
OPEX
Figure 4.23 Cost structure for the LNG cycle ($/MBtu feedgas excluded).