6.2 Natuna discovery

The Natuna gas field was discovered by Italy's Agip in 1973 and are located in the Greater Sarawak Basin about 1,100 km north of Jakarta and 225 km northeast of the Natuna Islands [40]. The field is in Indonesia's northernmost territory in the South China Sea at a water depth of 145 m. The Natuna discovery is the largest undeveloped gas discovery in Southeast Asia with an estimated resource of 46 Tcf of recoverable methane. We assume that this is at the 50% confidence level. However, this figure will need to be refined by further appraisal work [41].

In 2008, the Indonesian government awarded the Natuna block to Pertamina after cancelling former operator ExxonMobil's production sharing contract. However, it is possible that other companies would be joint venture partners with Pertamina in any development of the discovery.

Figure 20 shows the location of the Natuna discovery in Indonesia.

Figure 20 – The location of Natuna gas field in Indonesia

For the purpose of this analysis, we assume that the development of the Natuna discovery involves transporting the raw gas onshore to Great Natuna Island (Natuna Besar). At the onshore treatment plant the CO2 is removed and compressed for transport. The purified methane gas is then liquefied at an LNG plant to be built on the island.

Pertamina has said that production of the Natuna discovery could start in 2017 provided that the plan of development is approved. At full capacity, the Natuna discovery could produce about 16 million tonnes per year of LNG. This corresponds to 690 Bcf per year (1,830 MMscf/d) of natural gas.

Table 20 describes the composition of the raw, sales and injected gas assumed for the analysis.

Table 20 – Composition of raw, sales and injected gas

Volumetric flow-rate (MMscf/d) Raw gas Sales gas Inj. gas
Methane 1,393 1,393 0
Other hydrocarbons 348 348 0
CO2 4,262 85 4,177
Total 6,003 1,826 4,177
Mass flow-rate (Mt/yr) Raw gas Sales gas Inj. gas
Methane 9.8 9.8 0.0
Other hydrocarbons 4.6 4.6 0.0
CO2 82.3 1.6 80.7
Total 96.7 16.0 80.7

6.2.1 Storage formation

The Natuna discovery is located in the East Natuna Basin in the Miocene Terumbu Formation. For the purpose of this study, we assume that CO2 is injected into the Terumbu Formation below the Natuna discovery. The assumed injection site is located approximately 200 km from the project central processing facility on Great Natuna Island.

The middle Miocene to Lower Pliocene Terumbu Formation is the primary reservoir in the East Natuna Basin. The formation is composed of a series of platform and reefal carbonate build-ups. These carbonate build-ups are surrounded by tight fine-grained carbonates and shales deposited around their margins [63]. The reservoir quality in the build-ups is excellent. In this analysis, we assume an average porosity of 24% and an average permeability of 250 mD. The thickness of the formation varies from 300 m to over 1,525 m.

We have not obtained any data on the fracture pressure. For the purpose of this case study, we assume a constant fracture pressure gradient of 16 MPa/km.

Table 21 summarises the reservoir properties of the Terumbu Formation.

Table 21 – Storage formation properties

The reservoir properties are clearly subject to large uncertainties and variations in them can have a significant effect on the injectivity, capacity and the results of the economic analysis. we do not warrant that, after taking the uncertainties into account, the formation has sufficient capacity to hold the volumes of CO2 that would be emitted from the a development of the Natuna discovery. Therefore, estimating the number of wells required is highly uncertain. We assume that 90 wells are required for CO2 injection. However, further appraisal will refine this number. Clearly, a lower areal extent and formation thickness could increase the required number of wells and the costs significantly.

6.2.2 CO2 handling

For each of the 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. We have modelled only transport and injection economics and have not modelled the economics of capture or the sources emitting the CO2.

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

  1. We assume that 98% of the CO2 produced with the methane is captured and injected into the subsurface. Therefore 2% of the CO2 emissions are not captured but are exported along with the methane. As a preliminary assumption, we assume separation using solvent absorption with a cryogenic polishing stage.
  2. We assume that energy from a gas-fired power plant 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 are located on Great Natuna Island.
  3. We assume an injection period of 75 years to calculate the costs of transport and injection. This corresponds to the expected life of the natural gas development.
  4. We assume that the compressors' service lives are about 25 to 30 years – about one third of the project life. To take this into consideration, we increase the number of compressors for cost estimating purposes. We calculate that 10 compressor trains are needed to compress the injected gas. However, taking into account compressor sparing for a project life of 75 years, in total 25 compressors are purchased.
  5. In all cases, the injected gas is compressed from capture conditions to a sufficiently high pressure (at least 8 MPa) to keep it in a supercritical state throughout the transport and injection stages. We estimate the compressor duty to be 203 MW.
  6. The captured CO2 is transported through three 1,050 mm parallel X70 carbon-steel pipelines with a maximum pipeline pressure of 18 MPa (2,610 psia). We assume that the pipelines carry the CO2 200 km to the injection platforms. An alternative to this is separating the CO2 offshore and transporting it a short distance to the injection sites. Separation offshore would be more expensive than separation onshore. However, transport would be less expensive. We have not analysed the trade-offs between offshore and onshore separation and transport.
  7. The CO2 is injected into the subsurface using 90 × 220 mm deviated wells from three steel jacket platforms.

6.2.3 Cost estimates

We estimate the total extra capital cost for CO2 transport and injection to be US$5,975 million. Approximately 15% of the extra capital is spent on drilling wells. The annual extra operating cost is about US$180 million per year. At the end of the project the site is decommissioned at a real cost of approximately US$1,470 million. In Table 22 we report unit capital costs for major equipment items. More detailed results are provided in Table 23.

Table 22 – Summary of estimated unit costs of CO2 transport and storage for Natuna

Items Units Source Results
Unit Capital Costs
Power plants US$ million/MW Estimated 0.4
Source compressor US$ million/(Mt/yr) Estimated 28.2
Pipeline US$ thousand/km.mm Estimated 2
Wells US$ million/well Estimated 10
Injection platforms US$ million/platform Estimated 156
Injection platforms US$ million/slot Estimated 5.2
Total extra capital cost US$ million Estimated 5,975
Annual extra operating cost US$ million/yr Estimated 176
Extra decommissioning cost US$ million Estimated 1,472
Specific cost of CO2-e avoided US$/t CO2-e avoided Estimated 7.6

The specific cost of CO2-e avoided quoted in Table 17 is the net present value of the real costs divided by the net present value of the CO2-e avoided over a 75 year injection period.

Table 23 – Detailed estimated costs of CO2 transport and storage for Natuna

6.2.4 Effects of fiscal terms

In Section 5 of this report, we discuss the effect of the fiscal terms on the economics of representative projects. Applying the same type of analysis to the Natuna development gives the results shown in Table 24.

Table 24 – Effect of fiscal terms on CO2 transport and storage for Natuna

PV of CO2-e avoided Mt 692
Before-tax PV of all costs US$ million 5,274
Before-tax cost of CO2-e avoided US$/t 7.6
Fiscal relief % 58% – 76%
After-tax PV of all costs US$ million 1,266 – 2,216
After-tax cost of CO2-e avoided US$/t 1.9 – 3.2
Minimum price of CO2 before Government Take US$/t 7.6
Minimum price of CO2 after Government Take US$/t 10.3

6.2.5 Conclusions

In our best estimate, the addition of CO2 transport and injection facilities to the development of the Natuna discovery would require additional capital costs of about US$5,975 million in US$2010 terms. The extra annual operating costs would be approximately US$180 million per year and the additional decommissioning costs would be about US$1,470 million incurred after a CO2 injection period of 75 years.

Such a project would avoid emitting approximately 80 Mt/yr of CO2 to the atmosphere, which gives a total of about 6,000 Mt over the assumed 75 years life of the project.

We estimate that the specific cost of CO2-e avoided is US$7.6 per tonne.