4.1 Methodology

For the representative cases we estimate the equipment sizes, the capital, operating and decommissioning costs, as well as the costs per tonne of CO2-e avoided for CO2 transport and injection. The costs are presented in US$2010 terms. They are based on limited cost and reservoir data and have a large margin of error. This reflects the high degree of uncertainty in estimating injection reservoir characteristics and unit costs.

We estimate the costs of the transport and injection projects both excluding and including potential fiscal effects. In this section we examine the economics excluding fiscal effect. The following section shows the effects of fiscal terms.

We have modelled only transport and injection economics and have not modelled the economics of capture or the sources emitting the CO2. We have not carried out detailed assessments of enhanced oil recovery or enhanced gas recovery economics.

The main methods used for the analyses are listed and discussed below.

1. We assume for the representative cases (but not necessarily for the specific cases studies discussed in Section 6) that the methane being produced from the formations under consideration is delivered to the market as sales gas (not LNG). We assume that moderate levels of CO2 are acceptable in the sales gas (e.g. 15%) and that membranes are used to remove CO2 from the raw gas. This means that the injection gas will be a mixture of CO2, methane and other hydrocarbons.

2. The basis for the assumption above is an underlying premise that high CO2 content gas discovery development economics will support only partial CO2 separation using membranes. This reflects the costs of gas discovery construction and operation as well as prevailing natural gas producer prices. The premise follows what we understand to be typical practice across South-East Asia. This implies that in many cases more complete CO2 separation using solvent absorption is not viable or is significantly less viable than separation using membranes.

3. For all but the two Central Sumatra Basin cases and the Kutei Basin case, the number of wells estimated on the basis of simple reservoir simulation studies (see below) leads to top-hole injection pressures that are above the critical pressure of CO2. Therefore, for most cases the injection gas is compressed from ex-capture conditions (2.5 MPa, 25°C) to a sufficiently high pressure (at least 8 MPa) to keep it in a supercritical state throughout the transport and injection process.

4. For the Central Sumatra Basin cases and the Kutei Basin case we compress it to at least 4 MPa rather than 8 MPa. This means that the injected gas remains in a subcritical state.

5. For the purposes of this analysis we assume that the ratio between methane and other hydrocarbons (namely ethane) is 4-to-1. The assumed content and composition of the discoveries are given in Table 3.

Table 3 – Assumed content and composition of individual representative natural gas fields with high CO2 content for base cases

6. We calculate the composition of the sales gas and injection gas using simple mass balances3. We make a preliminary optimisation of the mass balances by varying the CO2 recovery rate and the sales gas CO2 concentration to minimise the hydrocarbon loss-rate (the portion of the total hydrocarbons in the injection gas). We apply the following constraints —

(a) The rate of CO2 removal from the raw gas (removal rate) is less than or equal to 90%,

(b) The concentration of CO2 in the sales gas (sales gas CO2 concentration) is between 0% and 20%, and

(c) The volume of lost hydrocarbons is greater than zero.

In calculating the flow-rate of the sales gas, we do not take into account gas used in producing power for the transport and injection process.

7. Figure 6 shows the results of the optimisation for the representative cases as a function of the concentration of CO2 in the raw gas.

Figure 6 – Results of optimising sales and injection gas compositions as a function of raw gas composition

Figure 6 shows that as the CO2 content in the raw gas increases, the CO2 removal rate has to increase in order to satisfy the sales gas constraint. This optimisation shows that high CO2 removal rates are required even for moderate CO2 concentrations (up to 20%) in the raw gas.

For two cases (Talang Akar Fm in the N.W. Java Basin and Cycle V in the Baram Delta Basin) with 80% CO2 in the raw gas, the optimisation cannot satisfy the constraints. For these cases, the constraints are relaxed and solutions are found with removal rates of 92% and sales gas CO2 concentrations of 25 vol%.

For all cases with CO2 concentrations in the raw gas above 20%, it is likely that multi-stage separation would be required to achieve CO2 concentrations in the sales gas of 5% or less. This condition would apply, for instance, when producing LNG.

8. Having determined the compositions and flow-rates of the sales and injection gas streams, we choose three sensitivity flow-rates. Each of these flow-rates is given in Table 4 together with the final values of the CO2 removal rate, sales gas CO2 concentration and hydrocarbon loss rate. The mass flow-rate for the raw gas, sales gas and injection gas streams are given in Table 5, while Table 6 shows the volumetric flow-rates for each stream. Finally, Table 7 gives the volumetric composition of each stream.

9. CO2 avoided in transport and injection is the CO2 injected less the CO2 emitted in supplying energy to the compressors and auxiliary equipment required for transporting and injecting the CO2. In our calculations of CO2 avoided, we take into account only that CO2 emitted as part of the transport and injection process. We do not take into account (a) those CO2 emissions associated with supplying energy to capture the CO2 and (b) the CO2 not captured. This approach means that it is not valid to add the costs per tonne of CO2 avoided in transport and injection as calculated in this report to the costs of CO2 avoided in capture calculated separately.

We also calculate the flow-rates of the produced gas (methane, CO2 etc) and any injected gas (methane, CO2 etc) in terms of their CO2 equivalent (CO2-e). The CO2-e mass of methane is the mass of methane multiplied by its Global Warming Potential (GWP) as defined by the US Environmental Protection Agency. The 100 year GWP of methane and ethane are estimated at 25 and 5.5 respectively [36].

We calculate the CO2-e avoided using the following equation –

CO2-e avoided = CO2-e injected (methane, CO2, etc.) less CO2 emitted during transport and injection (no other gases ar emitted) (2)

10. We assume that energy from a gas-fired generator is used to provide the additional energy for all transport and injection operations including compression and auxiliary equipment. The power plant does not have CO2 capture facilities. The power plant, compressor and auxiliary equipment is assumed to require a separate fixed platform near the central processing platform.

11. We assume that a single compressor train occupies one unmanned platform. We assume that the compressors' service lives are between 25 to 30 years. Therefore they do not need replacing during the project's life.

12. The pipelines used to transport CO2 are made from X70 carbon-steel line pipe. For onshore pipelines, we exclude the effects of terrain and land use on pipeline costs.

13. We have not included the cost of installing power transmission lines along the pipeline route to provide power for compression at the point of injection.

14. Vertical wells are used for injecting CO2 into onshore storage formations. For offshore reservoirs we use deviated wells. For the representative cases we use our best estimate of well costs based on available cost data. For specific case studies, well costs were reviewed by the project operators.

Table 4 – Results of optimisation for individual representative discoveries together with mass flow-rates base and sensitivity cases

Table 5 – Volumetric flow-rates for the raw, sales and injection gas streams for individual representative high CO2 content discoveries

Table 6 – Mass flow-rates for the raw, sales and injection gas streams for individual representative high CO2 content discoveries

Table 7 – Volumetric composition-rates for the raw, sales and injection gas streams for individual representative high CO2 content discoveries

15. We estimate the required number of injection wells using simple reservoir simulations. Injection takes place in the centre of the formation and occupies 25% of the total formation area. We make this assumption because formation heterogeneity and structure, faulting, sweet spots for injection and so on mean that the whole formation will not practically be available for injection.

Increasing the injection area is expected to increase injectivity for a given total injection rate. However, increasing the injection area within the formation lowers the aquifer strength and so the overall injectivity is not expected to increase significantly. That part of the location surrounding the injection area is an aquifer. The simulation grid size varies depending on the area of the location.

For a given number of injection wells, by repeated simulations we establish iteratively the maximum rate of CO2 that can be injected over the injection period without the pressure in the reservoir exceeding its fracture pressure. This maximum rate is then established for different numbers of wells. The maximum depends on the properties of the reservoir including its permeability, reservoir thickness and fracture pressure. An example of the results of the simulations is shown in Figure 7.

Figure 7 – Example results of reservoir simulation

16. We assume that each project lasts for 20 years. To get the annual raw gas production rate we divide the total resource content of the formation by the project life.

17. The number of injection wells estimated by simulations is likely to provide a lower limit to the wells required because the simulations omit other factors that influence injection (such as tubing effects and reservoir heterogeneity). We therefore apply an empirically-based contingency factor to take these other factors into account.

18. We do not consider the design or costs of monitoring CO2 storage before during of after the injection period. The design will be very case-specific and we do not have sufficient data to enable a proper analysis of the monitoring system.

19. The capital costs include the costs of extra power, compression, pipelines and injection both platforms and wells. In addition, we calculate the auxiliary costs of constructing the transport and injection project. We refer to these costs as 'On-Costs'. They include insurance, obtaining rights-of-way, legal and regulatory costs, contingency and so on.

20. We report the capital, operating and decommissioning costs for each case examined as well as the present value of these costs. We also present the specific cost of CO2-e avoided. The specific cost of CO2-e avoided is calculated by dividing the present value of all costs by the present value of CO2-e avoided.

3 The degree to which a membrane system will separate the different components of a feed stream is described in terms of its selectivity. Selectivity is the ratio of mole fractions in the injection gas divided by the ratio of mole fractions in the raw gas. We assumed a CO2/CH4 selectivity of 12 and a CO2/C2H6 selectivity of 30.