CO₂ Flooding of UKCS Reservoirs

Eugene Balbinski (eugene.balbinski@ecltechnology.com) of ECL Technology Ltd (http://www.ecltechnology.com) summarises the findings of work undertaken for the DTI’s Oil and Gas Directorate under the SHARP programme investigating the potential for CO₂ injection in UKCS reservoirs.

The physical properties of CO₂ make it a potentially significant IOR (Incremental Oil Recovery) injection gas, with application in situations that would not benefit from hydrocarbon gas injection. The history of successful CO₂ injection projects in the US Permian Basin bears testimony to this view. CO₂ injection could increase UKCS reserves substantially and dispose of a significant fraction of the CO₂ emitted by the UK power generation/industry.

Tertiary CO₂ injection in onshore North American fields is a successful IOR technique that regularly achieves incremental oil recoveries in the range 4-12% STOIIP (Stock Tank Oil Initially In Place). Retained gas volumes are typically 10-25% HCPV (Hydrocarbon Pore Volume) for tertiary CO₂ WAG (Water Alternating Gas) floods. The incremental oil production, expressed in reservoir barrels, is generally between 50 and 100% of the volume retained in the reservoir.

Although UKCS fields are at higher pressures than onshore CO₂ projects, the higher temperatures compensate to give similar CO₂ densities at reservoir conditions in both UKCS and Permian Basin floods. Consequently, similar quantities of CO₂ would be required to sweep a given reservoir volume in both cases.

Benefits
The overall benefits from CO₂ injection if it were implemented on a large scale in the North Sea are wide ranging, Figure 1. At the individual field level, the direct economic benefits include the incremental oil produced from CO₂ injection and the additional waterflood reserves resulting from any field life extension and consequent satellite tie-ins. At the national level, there are benefits to government from increased economic activity, reduction in CO₂ emissions and strategic positioning for exporting technology and expertise.

Figure 1: Direct and associated benefits from CO₂ injection (Click image for larger view)

The total volume of incremental oil available from CO₂ injection into UKCS reservoirs has been estimated from historical screening work at roughly 1700 MMstb. Note that the data on which this work was based is mostly at least ten years old, though this should be adequate for a preliminary estimate. It can be seen from Figure 2 that peak incremental recovery rates in excess of 500 MMstb/d may be achievable in the period 2015 to 2020. The bulk of the initial incremental recovery is expected from a relatively large number of WAG projects, though the bulk of the total recovery is estimated to be provided by a few large GSGI (Gravity Stable Gas Injection) projects. Although this is likely to be generally correct, if the work on which these estimates were updated, it is probable that it would now be thought that WAG would be a more appropriate technique for some of the larger GSGI schemes. Figure 2 probably therefore underestimates the likely contribution from WAG schemes. This is important as these would be of shorter duration and potentially more economic, as incremental oil is achievable earlier in a project’s lifetime.

Figure 2: Incremental oil production rate from CO₂ injection (Click image for larger view)

The total CO₂ that might be sequestered by reservoir injection has been estimated from the same data to be about 700 million tonnes. This is about 1.4 times total estimated UKCS emissions for 1999. Figure 3 shows that the bulk of the sequesterable CO₂ is from GSGI schemes. This conclusion is also subject to the same possibility that a greater share might be found to be due to WAG schemes if the work on which it is based were updated. However, it is more robust because GSGI schemes, if applicable, are intrinsically a more efficient way of sequestering gas than WAG schemes, as most of the gas injected can be sequestered. This is because the GSGI technique essentially relies on gradually filling the whole reservoir with gas, whereas WAG schemes may successively re-cycle gas, flooding different limited pathways through the reservoir each time. The degree of re-cycling necessary in WAG schemes is very dependent on particular field heterogeneities and therefore cannot be reliably estimated from the screening work on which these results are based. The volume of gas re-injected is therefore likely to be higher for WAG schemes, than for a good GSGI scheme.

Figure 3: Potential CO₂ injection rates for UKCS (Click image for larger view)

It can be seen from Figure 4 that the window of opportunity for UKCS CO₂ injection is limited. By 2005 the potential for incremental oil will start to decline significantly and will suffer a steep decline after 2011. Most of the potential at risk from delay initially is from WAG schemes, as these should be implemented a few years before production would otherwise cease. GSGI schemes may be left until a reservoir is close to ceasing production.

Figure 4: Window of opportunity for CO₂ injection potential on UKCS (Click image for larger view)

Development Scenarios
Construction of realistic CO₂ injection scenarios is complex because of the large number of fields that are potentially involved and the need to develop a CO₂ production and delivery infrastructure. The CO₂ injection infrastructure can be considered at three different levels, as illustrated in Figure 5.

• major infrastructure to deliver CO₂ at a regional level, where injection into a number of fields may be needed to justify the pipeline CAPEX
• tie-in of groups of fields accessed by main regional infrastructure, where each group of fields consists of a main hub field with a significant CO₂ injection target or late COP date
• injection of CO₂ from hub fields into surrounding satellite fields

Figure 5: Schematic diagram illustrating regional CO₂ infrastructure (Click image for larger view)

A key issue in developing any strategy is the phasing of the infrastructure development and the timing of CO₂ injection in specific reservoirs, taking into account the window of opportunity provided by the remaining life of the target fields.

The most appropriate strategy developed will depend on the effective cost of CO₂. If CO₂ has a price purely determined by the cost of separation and transport, then strategies will be favoured that maximise the volume of incremental oil recovered for the CO₂ retained in the reservoir. For example, WAG floods could be followed with a further waterflood to recover mobile CO₂. Alternatively, if there is an environmentally driven fiscal incentive for sequestering CO₂, it may be attractive to run CO₂ injection schemes sub-optimally in a classical IOR sense, to increase the volume of CO₂ retained in reservoirs.

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