6.1 Tangga Barat

The fields comprising the Tangga Barat Cluster were discovered during 1980 and 1993 and are located about 150 km northeast of Kertih, Terengganu offshore Peninsular Malaysia in the PM 313 Block at water depths in the range 60 m to 71 m [77]. Figure 19 shows the location of the Tangga Barat Cluster fields.

The estimated proven plus probable recoverable natural gas resources are 1,070 billion cubic feet. The fields remain undeveloped. The content level of CO2 is beyond the gas specification required for gas sales.

The current operator of the Tangga Barat Cluster is Petronas Carigali Sdn Bhd (PCSB) which holds a 100% working interest.

Figure 19 – The location of Tangga Barat Cluster gas fields [76]

Source: Darman, N. H. and A. R. B. Harun (2006). Technical Challenges and Solutions on Natural Gas Development in Malaysia. Beijing, China, Petronas / Petronas Carigali.

We assume that the development of the Tangga Barat Cluster comprises a total of 3 producing platforms and 1 central processing platform. We assume that the central processing platform accommodates all processing facilities, natural gas compression, main power generation, utilities and living quarters for field operations. The processing platform is 52 kilometres from the existing Resak production complex from which a 28 inch two-phase pipeline transports gas to the Resak Onshore Gas Terminal at Kertih. The Resak pipeline has sufficient spare capacity for the additional gas produced from Tangga Barat fields.

The development of the fields is designed for a capacity of 305 MMscf/d of raw gas with an initial blended CO2 level of 34% prior to CO2 removal. The raw gas will be processed, pre-treated and CO2 content reduced to 10% to meet sales gas specification. For the purpose of this case study, we assume an annual average sales gas rate of 220 MMscf/d. This allows a 15-year production life of the fields. We assume that the CO2 is separated from the raw gas with membranes.

After separation, approximately 10% of the sales gas is CO2. The separated gas stream is 94% CO2 and 6% methane and other hydrocarbons. This gas stream is transported and injected into a nearby saline formation.

Table 15 describes the composition of the raw, sales and injected gas assumed for the analysis in this report.

Table 15 – Composition of raw, sales and injected gas

Volumetric flow-rate (MMscf/d) Raw gas Sales gas Injection gas
Methane 161 156 5
Other hydrocarbons 40 40 1
CO2 104 23 81
Total 305 219 87
Mass flow-rate (Mt/yr) Raw gas Sales gas Injection gas
Methane 1.1 1.1 0.0
Other hydrocarbons 0.5 0.5 0.01
CO2 2.0 0.4 1.6
Total 3.7 2.1 1.6

6.1.1 Storage formation

CO2 disposal studies carried out by Hong, T. Y., et al. [38] identified underground geological storage sites near the Tangga fields where the injected CO2 volumes can be stored without increasing the reservoir pressure above the fracture pressure. The assumed storage site is located approximately 20 km from the Tangga Barat processing platform.

In this study, we assume that the separated gas stream is injected into a saline formation below the Tangga gas reservoirs (E Group) in the Malay Formation. E Group reservoirs were deposited in an estuarine depositional environment during the Early to Late Miocene. Reservior rocks have 25–30% porosity and up to 1,000 mD permeability [78]. Another source indicates that porosity ranges between 15% and 35% and permeabilities of main reservoirs ranges between 2 mD and 1,200 mD. Based on discussions with Petronas, we assume an porosity of 10% and a permeability of 290 mD for this analysis.

Based on data provided by Petronas, the reservoir pressure is 13.8 MPa (2,000 psi) and the fracture gradient is 14.7 MPa per kilometer (0.65 psi per feet).

Table 16 summarises the reservoir properties of E Group.

Table 16 – Storage formation properties

These assumptions are subject to large uncertainties and variations in them can have a significant effect on the results of the economic analysis.

6.1.2 CO2 handling

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 78% of the CO2 produced with the methane is captured and injected into the subsurface. Therefore 22% of the CO2 emissions are not captured but are exported along with the methane.
  2. 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. A separate fixed platform is required for the power plant, compressor and auxiliary equipment.
  3. We assume an injection period of 15 years to calculate the costs of transport and injection.
  4. In this case, the injection gas is compressed from atmospheric 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 4 MW.
  5. The pipeline used to transport the injection gas is made from X70 carbon-steel line pipe with a maximum pipeline pressure of 18 MPa (2,610 psia). We assume a 20 km pipeline between the compression platform and the injection platform. We estimate that a 250 mm pipe will be required.
  6. The separated gas stream is injected into the subsurface using 4 × 220 mm deviated wells from a steel jacket platform. We assume the same number of wells as planned by Petronas.

6.1.3 Cost estimates

We estimate the total extra capital cost for transport and injection to be US$220 million. The annual extra operating cost is US$8 million per year. At the end of the project the site is decommissioned at a real cost of US$50 million. In Table 17 we report unit capital costs for major equipment items. More detailed results are provided in Table 18.

Table 17 – Summary of estimated unit costs of CO2 transport and storage for Tangga Barat

Items Source Results
Unit Capital Costs
Power Plant US$ million/MW Estimated 0.8
Compressor US$ million.yr/Mt Estimated 19.2
Pipeline US$ thousand/km.mm Estimated 11
Wells US$ million/well Estimated 10
Injection platform (per platform) US$ million/platform Estimated 51
Injection platform (per slot) US$ million/slot Estimated 6.4
Total extra capital cost US$ million Estimated 220
Annual extra operating cost US$ million/yr Estimated 8
Extra decommissioning cost US$ million Estimated 50
Specific cost of CO2-e avoided US$/t CO2-e avoided Estimated 14.1

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 15 year injection period.

Table 18 – Detailed estimated costs of CO2 transport and storage for Tangga Barat

6.1.4 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 Tangga Barat development gives the results shown in Table 19.

Table 19 – Effect of fiscal terms on CO2 transport and storage for Tangga Barat

PV of CO2-e avoided Mt 18.4
Before-tax PV of all costs US$ million 260.2
Before-tax cost of CO2-e avoided US$/t 14.1
Fiscal relief % 63% – 88%
After-tax PV of all costs US$ million 32 – 97
After-tax cost of CO2-e avoided US$/t 1.7 – 5.3
Minimum price of CO2 before Government Take US$/t 14.1
Minimum price of CO2 after Government Take US$/t 26.4

6.1.5 Conclusions

The addition of CO2 transport and injection facilities to the development of the Tangga Barat discovery would require additional capital costs of about US$220 million in US$2010 terms. The extra annual operating costs would be approximately US$8 million per year and the additional decommissioning costs would be about US$50 million incurred after a CO2 injection period of 15 years.

Such a project would avoid emitting approximately 2.5 Mt/yr of CO2-e to the atmosphere, which gives a total of 37.5 Mt over the assumed 15 years life of the project.

The specific cost of CO2-e avoided is US$14 per tonne.