Oil & Gas - Maximising Recovery Programme (formerly SHARP) IOR Views

Context

Two groundbreaking North Sea Carbon Capture and Storage (CCS) projects with IOR have been announced in the last year. In 2005 BP and its partners publicised engineering studies on injection of CO2 from Peterhead power station into the Miller reservoir. In 2006 Shell and Statoil announced a large project injecting CO2 from a power station at Tjeldbergodden into the Norwegian Draugen and Heidrun fields.

The UK government has also recently completed an Energy Review which included CCS. It concluded that the UK had natural and commercial advantages to benefit from CCS technology and it will therefore continue to work with international partners to remove regulatory barriers and promote a commercial demonstration. It is also committed to strengthening the EU Emissions Trading Scheme, with the aim of developing a more efficient carbon market. It is expected that CCS will be included in the scheme in the near future. The UK Treasury is also considering input from a recent consultation on the barriers to wide-scale commercial deployment of CCS in the UK and the potential role of economic incentives in addressing those barriers. A North Sea basin Task Force, made up of private and public organisations from the North Sea rim, with the aim of developing regulation and management of CO2 storage under the North Sea, is due to report in Spring 2007.

Project

This article summarises some timely results from an example of detailed 3D field scale multi-well modelling of Water Alternating Gas (WAG) CO2 injection using heterogeneous geology representative of the North Sea, including general conclusions from a simple economic model. The project investigated flood optimisation, including measures to reduce the back production of CO2.

Water Flooding

The model has 21 producers and 12 peripheral injectors.  Water was injected for 20 years maintaining average field pressure through voidage replacement. The target production rate was set at 10% of the initial hydrocarbon pore volume per year, with a minimum field rate of 10 Mstb/d. Producers were constrained to a maximum 90% watercut and minimum oil rate of 1 Mstb/d. The water flood recovery after 20 years was 40% which is typical for a UKCS field of this type, especially as down dip gas injection would normally be started some time before the end of normal field life. Where water has flooded remaining oil saturations are low, typically 25 to 35%, (Sorw =25%). However, there is a significant volume of bypassed oil in disconnected pathways.

CO2 Flooding

Injection of CO2 was modelled from the end of the water flood for six years by converting the water injectors into WAG or Continuous Gas Injection (CGI) injectors. Miscible CO2 injection was modelled using the Todd-Longstaff model. The wells were controlled by maintaining the reservoir pressure at its initial value with a maximum gas production rate of 7 MMscf/d, a maximum watercut of 95%, a minimum oil rate of 500 stb/d and a minimum BHP of 1200 psia. Some effort was made to optimise the CO2 injection both through use of simulator controls and ad hoc adjustments. This included phasing of production wells, adjustment of CO2 injection rates to oil production and varying the length of CO2 injection cycles. This last item was achieved by simulating CO2 injection cycles from three to nine months, each with a total cycle time of one year. This provided cases with WAG ratios of 1:3, 1:1 and 3:1. In addition to these WAG cases CGI was simulated, equivalent to a WAG ratio of zero. In this case all production wells were reopened annually in order to equivalence the WAG cases. Other optimisation methods were tried, such as closing high GOR completions, but these were not found to improve outcomes significantly more than the methods already in use, so were not retained.

Figure 1: For this example, IOR after 6 years is relatively insensitive to WAG ratio, though more CO2 is sequestered at lower WAG ratios

Figure 2: For this example, the CO2 volume needed to produce an equivalent IOR volume rises to over 3 at low WAG ratios, but CO2 back production can be contained for all WAG ratios considered (Unit Recycling Ratio means no CO2 back production).

Simple Economic Model

A simple economic model was used incorporating the value of both IOR and CO2 sequestration. As the CO2 injection duration was limited to just six years, discounting was not included. The model assumes prior and continuing water flooding during WAG. The value of the IOR from WAG/CGI is just the product of the oil price and the IOR volume. The CO2 sequestration value is the product of the CO2 credit value and the total CO2 sequestered. The WAG/CGI injection cost is the sum of the costs of capturing, transporting, injecting and back producing CO2 plus water injection and base facility costs.

Table 1: CO2 Costs

Figure 3: Even for low cost CO2 capture (e.g. IGCC), CO2 import costs (capture & transport) are expected to exceed reservoir costs. Integrated Gasification Combined Cycle (IGCC) is a pre-combustion decarbonisation coal burning power plant using coal as fuel.

Figure 4: Even for a low CO2 capture cost scenario, at intermediate CO2 credit values, WAG costs are unlikely to be offset by CO2 credits, though IOR value should be sufficient to give positive project values.

Cost estimates were derived from the following sources:

• CO2 Injection for IOR and Storage: Opportunities and Challenges for the North Sea, Dr F Gozalpour, Dr S Ren & Prof B Tohidi, IOR Views, Issue 10
• Carbon Dioxide Capture and Storage: A Win-Win Option?
• Progressive Energy Ltd
• Internal DTI Reports

These are rough general estimates with a fair degree of uncertainty, so may change. These costs do however reflect the current expectation that capture and transport costs will dominate over injection and production.

Figure 5: For a scenario with low cost CO2 capture and higher CO2 credit values, WAG costs could nearly be offset by CO2 credits

Figure 6: For a low capture cost scenario, CO2 sequestration credits would need to be at least  $55/tonne to fully offset total costs