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

Potentials of CO2/IOR and Storage in the North Sea

CO2 injection for improved oil recovery (IOR) has been extensively investigated and commercially pursued since early 1960s.  Worldwide, there have been over 80 CO2 IOR projects; all of them in onshore operations.  In the late 1970s and early 1980s, the UK Department of Trade and Industry (Department of Energy at that time) was keen to initiate CO2 injection in the North Sea.  Clearly CO2 was not seen as a gas to be sequestrated (for CO2 mitigation) at that time but as an effective gas injection agent for IOR based on the onshore experience in the US.

Industry experience of past and current CO2 IOR onshore field projects has indicated that tertiary CO2 injection in onshore North America can achieve incremental oil recoveries in the range of 4-12 % OOIP over water flooding.  The reported net gas utilisation of most fields was less than 8000 scf/STB (227 sm3/STB), and some had utilisation of less than 6000 scf/STB (170 sm3/STB).  In other words, approximately one tonne of CO2 injected can produce 2.5-3.3 STB of oil.  There have been no offshore CO2 IOR field projects, though there have been many studies, and several proposed and implemented hydrocarbon gas injection projects (using WAG mode) in the North Sea.  For instance, the predicted IOR for one of the ongoing WAG injection projects in Gullfaks is 5% OOIP, while for Brage, it is 9-12% OOIP.

The incremental oil recovery potential and CO2 storage capacity in the North Sea region, via CO2 injection, has been evaluated by the DTI (in a study undertaken by ECL Technology Ltd formerly AEA Technology) for reservoirs with over 100 million STB OOIP.  It was concluded that the UKCS (UK Continental Shelf) IOR potential was in the region of 350-850 million STB for WAG schemes and 800-1400 million STB for gravity stabilised gas injection (GSGI) schemes.  The net CO2 retention capacity from WAG was around 150 millions tonnes, whereas that for the GSGI schemes was around 550 million tonnes.  There were around 60 potential WAG projects, but far fewer GSGI opportunities.  The CO2 retention potential from GSGI projects was approximately 3 times larger than that of WAG injection.

It is expected that similar CO2 IOR potential and storage capacity exist in the Norwegian sector of the North Sea.  Therefore, the total CO2 IOR potential can be over 2300 millions STB oil, and the gas storage potential can be in the order of 1400 million tonnes CO2, in the whole North Sea oil reservoirs.

North Sea CO2/IOR Study

For North Sea CO2/IOR and storage projects, the economic challenge is the added cost of CO2 separation, transportation and extra cost on CAPEX and OPEX, such as the cost of adapting platforms and well completions to handle CO2.  There are a few published data on CO2 IOR in selected mature fields in the North Sea, focused on project feasibility and reservoir simulation studies, such as for Fulmar, Forties, Gullfaks and Ekofisk.

In this study a scoping CO2/IOR economic analysis was conducted for a North Sea reservoir, where CO2 is captured from onshore power plants and transported to the North Sea for injection.  The data used for the economic calculation are listed in Table 1.  The calculated oil production cost, including or excluding the cost of separation/transportation, is given in Table 2.  The calculation results show that the cost for separation and transportation of CO2 is much higher than the cost of offshore injection.  The total direct unit cost of oil production using CO2 captured from a power plant in a mature North Sea oil field can be as high as over $40/STB oil.  Approximately 76% of the total cost is attributed to CO2 capture and transportation.

Processes	Cost Estimation
CO2 injection rate	200 MMscf/day
Injection Pressure	350 bar
Projection Duration	20 years
Compressor and Installation	$20 and $6 million
Total Compression and Injection Cost	$0.5/Mscf
Pipeline (400km onshore, 100km offshore)	$900 million, CAPEX only
CO2 Capture Cost (from a coal fired power plant of 500 MW)	$1.5/Mscf, CAPEX and OPEX
Total CO2 Transportation Cost	$1.0/Mscf
Produced Gas Processing Cost	60% of compression and injection cost

(1 Mscf=1000scf=28.32sm3)

Table 1 - Basic Economic Data Used for a North Sea CO2 IOR Case Study

Process/Operation	Cost
CO2 utilisation ratio: CO2/Oil, Mscf/STB	13.1
CO2 capture cost, $/Mscf	1.5
CO2 transportation cost, $/Mscf	1.0
CO2 compression and injection cost, $/Mscf	0.5
Produced Gas Processing (recycle), $/Mscf	0.3
Oil production cost, $/STB, including CO2 separation & transportation	43.2
Oil production cost, $/STB, excluding CO2 separation & transportation	10.5

(1 STB=0.11563 sm3, 1 Mscf=28.3 sm3 )

Table 2 - Cost Estimation for 20 Years CO2 IOR operation

It should be noted that, though 10.7% IOR was achieved over 20 years CO2 injection in the simulated North Sea field (Figure 1), the CO2 utilisation was around 13 Mscf/STB oil, which was much higher than that reported in many onshore fields (i.e. 6-8 Mscf/STB oil).  The reservoir chosen in the simulation study may not be the best for gas injection IOR, and the CO2 utilisation efficiency can be improved through better reservoir management and well control.  This will further reduce the oil production cost.  Novel and more advanced technologies are needed to bring down the cost of CO2 capture from power plant flue gases.  The cost of transportation can be reduced when large diameter pipelines or existing pipeline facilities are used.

Figure 1-Reservoir Simulation Results for Incremental Oil Recovery (IOR, %OOIP) for Different CO2 Injection Scenarios for a North Sea Field.  Gas Injection Started after 15 Year Water Flood

North Sea Uncertainties and Challenges

Although many operators consider CO2 injection is a technically proven IOR technique, which can be conducted in their fields if this offers a satisfactory financial return, there are still some technical concerns over the projects, especially in offshore operations, such as in the North Sea.  The following issues may pose technical challenges to the combination of CO2 IOR and storage projects, which should be investigated and considered in project design.

1. Operating costs could be much higher on offshore platforms, especially in a challenging environment like the North Sea.  Efforts need to be made to form a consortium of several fields to share necessary infrastructure in order to reduce the cost.
2. Field installations are aging, and furthermore the majority of fields have naturally low levels of CO2.  Therefore, the facilities are not designed for high levels of corrosion resistance.  Whilst it may be possible to protect some parts of the system with inhibitors, some would have to be replaced.  Upgrading old platforms can be very expensive.
3. No transport solution exists for CO2 in the required quantities for the North Sea, and must be implemented from scratch.
4. Offshore fields tend to be developed with much lower well densities than those onshore.  This has two effects.  It reduces the sweep efficiency; hence less oil is recovered.  It also means that it takes longer for incremental oil to reach the producers, which has a highly detrimental impact on net present value calculations.  Unfavourable reservoir characteristics in the North Sea may further contribute to poor sweep efficiency due to early CO2 breakthrough as a result of mobility contrast, gas override, and reservoir heterogeneity.
5. Recovery from most North Sea fields via water flooding is already high, around 40-70%.  The remaining oil is scattered across the large reservoir formation, indicating a difficult IOR target for WAG process, or low gas utilisation efficiency even for GSGI process.
6. For offshore operations, such as in the North Sea, the risks of IOR and safe CO2 storage due to possible insufficient reservoir characterisation need to be assessed.  It has been assumed that CO2 storage in subsea geo-structures would be safer than onshore structures due to the possibility of hydrate formation in the seabed, which may block any possible CO2 leakage due to unidentified seepages.  The window of opportunity in terms of the offshore infrastructures is also of major concern.  The question to be answered is when and how long the CO2 IOR project in the offshore fields can be operated, and can extra CO2 be injected for storage after the IOR operation has ceased?

Concluding Remarks

The majority of previous studies on CO2 IOR and storage were evaluated using a low oil price of approximately $16-$20/STB for project approval.  It is obvious that the high cost of CO2 capture and low oil price would be the main barriers for oil producers to apply the technology, especially offshore where the risk is high.  However, the current high and volatile oil price has opened a window of opportunity for CO2 IOR operations.  The influence of volatile oil pricing on the project development and risk needs to be reinvestigated.  On the other hand, the current European Union Emissions Trading Scheme that was introduced in January 2005 will also have a positive effect on promoting CO2 IOR and/or storage projects, as it did on CO2 re-injection in Norwegian offshore projects, although it was initially thought the carbon emission credits would unlikely be sufficient.  In a low oil price environment, the oil industry must be provided with some kind of incentive to ensure a positive economic return for carrying out CO2 injection and storage projects.