Onshore option

Recall that the onshore option is flexible and can change production levels (and thus variable costs) to match demand levels between 60,000 and 150,000. In the following analysis, we calculate the expected profits at each node in the decision tree (represented by the corresponding values of D and E) starting in Period 2 and working back to the present (Period 0). With the onshore option, exchange rates do not affect profits in euro because both revenue and costs are in euro. 

In Period 2, the total profit for D-Solar at the node D = 144, E = 10.89 for the onshore option is thus given by... 

As with the onshore option, we start by evaluating profits at each node in Period 2 and then back our evaluation up to Periods 1 and 0. Recall that the offshore option is not fuUy flexible and can change production levels (and thus variable costs) only between 100,000 and 130,000 panels. Thus, if demand falls below 100,000 panels, D-Solar still incurs the variable production cost of 100,000 panels. If demand increases above 130,(X)0 panels, the offshore facility can meet demand only up to 130,000 panels. At each node, given the demand, we calculate the expected profits accounting for the exchange rate that influences offshore costs evaluated in euro. 

Observe that for the node D = 80, = 8.10, D-Solar has a lower expected profit from the offshore option (Table 6-17) relative to the onshore option (see Table 6-15) because the offshore plant incurs high variable cost, given its lack of flexibility (cost is incurred for 100,000 units even though only 80,000 are sold), and all offshore costs become expensive, given the strong yuan. 

Not surprisingly, costs are several times higher than conventional wells. Nevertheless, overall project economics may favour ERD over other development options. For example, BP developed the offshore part of the Wytch Farm Oilfield (which is located under Poole Harbour in Dorset, UK) from an onshore location. The wells targeted the reservoir at a vertical depth of 1,500 meters with a lateral displacement of over 8,000 meters (Fig. 3.20). The alternative was to build a drilling location on an artificial island in Poole Bay. ERD probably saved a considerable amount of money and advanced first oil by several years. 

One of the most comprehensive economic studies was done in two phases. The first phase addressed whether the location of the treating facilities should be offshore or onshore. The second phase evaluated the process design options. The outcome of the first phase recommended onshore natural gas treating facilities the second phase recommended implementation of the turboexpander process design. The process options evaluated for this project are listed below ... 

Transportation of C02 by ships is suitable for offshore geological C02 storage and is favourable for longer distances (Heddle et al., 2003). One of the options where the use of ships could be favourable is the transportation of C02 from the onshore harbour with an intermediate storage facility to the underground geological storage site located offshore. There, C02 could be transferred into an injection well via a vertical pipeline. Ships would most probably come into play to supply offshore enhanced oil recovery projects with C02 (compare, e.g., Barrio et al., 2004). 

A key factor in the C02 capture and storage system is the need for a functioning transportation system for the C02 captured at energy conversion units. The transport options suitable for the quantities produced by large power stations or industrial plants would mainly be pipeline transport for onshore distances and ship transport for the offshore area.6... 

Construction costs for artificial floating islands will quite different when compared to onshore or natural island locations. The floating island structure costs will be balanced against the high cost of land and environmental protection for shore and island locations. On balance, for most locations the use of the floating islands may be no more costly than other options. 

The first commercial Twister installation was implemented by Pefronas and Sarawak Shell Berhad (SSB) on the Bll offshore gas processing facility in Decanber2003. The unit dehydrates bOOMMcfd of non-associated sour gas fed to the onshore Malaysian LNG plant at Bintulu, to control pipe corrosion, and has at the time of writing being in continuous operation since start-up with over 99% availability. Table 9.1 compares capital expenditure for the Twister and other options for offshore gas development... 

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