Published by the DTI Oil & Gas Directorate for the reservoir engineering and IOR community in the UK.
Send comments on this issue and contributions for next issue to iornewsletter@senergyltd.com by 15 December 2002.

Session on CO₂ Sequestration and the Use of CO₂ to Improve Oil Recovery at the DTI's IOR Research Dissemination Seminar, 25 June 2002

Because of environmental concerns there is a new impetus in investigating the possible use of oil and gas reservoirs for the long term storage of CO₂ (known as sequestration). If in addition, the CO₂ can be used to boost oil recovery factors then this may make the process more economically attractive.

There was a lively session on CO₂ sequestration and the use of CO₂ to improve oil recovery at the DTI's IOR Research Dissemination Seminar held on 25 June 2002 at the Aberdeen Exhibition and Conference Centre.

A vision of large scale separation and compression plants taking waste CO₂ from, say, power stations and feeding this into a pipeline and compressor network infrastructure connecting all the major facilities in the North Sea emerged. The CO₂ would be used to enhance recovery in one reservoir; once this was exhausted a proportion of the CO₂ would be back produced by blow down, recompressed and then transported via the infrastructure to the next reservoir where the sequence would be repeated. Once all North Sea reservoirs had been exhausted the depleted reservoirs would be used for the long term storage (or sequestration) of the CO₂. Although all of this would be unlikely to be economic in its own right, restrictions on the amount of CO₂ that can be disposed of to the atmosphere and the possible imposition of a carbon tax might well mean that this becomes an economic reality in the medium term.

Five presentations were made in the CO₂ session at the seminar. Articles on two of these can be found in this newsletter; Subsurface Issues for CO₂ Flooding of UKCS Reservoirs presented by Stephen Goodyear and Potential UKCS CO₂ Retention Capacity from IOR Projects presented by Claire Woods.

Picture shows (from left) Roger Skinner (BP), Jim Riding (British Geological Survey). Erik Lindeberg (SINTEF), Stephen Goodyear (AEA Technology - now with Shell) and Claire Woods (AEA Technology - now with Shell) (click image for larger view)

Erik Lindeberg (erik.lindeberg@iku.sintef.no) of SINTEF Petroleum Research in Trondheim, Norway pointed out that with countries like India and China undergoing rapid economic growth, CO₂ emissions will continue to rise, even with a substantial switch from coal burning power generation to oil and gas or even renewables. Many countries have committed themselves to reducing CO₂ emissions.

The separation and subsequent disposal of CO₂ in underground formations is one of the only large scale options available. The technology is to some extent already in existence, but the longer term integrity of the storage is still problematic. Also, disposal of the CO₂ would increase the cost of electricity by 40-80%. By injecting the CO₂ into oil reservoirs where a benefit would be expected in terms of additional oil recovery, this disposal cost could be offset in whole or in part.

In 1982 such a project, collecting anthropogenic CO₂ from a power station and injecting it into an oil reservoir to increase recovery was implemented in Lubbock, Texas, although this project has now ceased.

Other separation and injection projects were implemented in the USA and South Africa.

There are, however, many issues which need to be addressed for example:

• the logistics of transporting the CO₂ from the source (separation plant) to oil field
• the supply and demand scenarios may be different
• breakthrough of CO₂ at producers
• corrosion of metal components and cement
• long term integrity
• legal responsibility for sequestered CO₂

There is some experience in the Norwegian sector of the North Sea at Sleipner where CO₂ produced from the field has been re-injected into an overlying aquifer. What is probably needed is a CO₂ transport infrastructure (i.e. a network of pipelines and compressors) to minimise transport costs and to allow the CO₂ to be switched between fields. Such a network is already benefiting fields in the Permian Basin in West Texas, although the CO₂ is from naturally occurring sources.

At present the cost of sequestrating CO₂ is $25-55 per tonne. The minimum oil price for this to be economic would be $25 per barrel. Factors like the Norwegian carbon tax would act as an incentive to pursue disposal in oil reservoirs.

Roger Skinner (skinnerr@bp.com) of BP spoke about the potential to increase recovery from Forties by injecting CO₂.

In September 2000 the Fortes Field celebrated 25 years of production. Recovery up to this point is approximately 60% of the original of oil in place. The field contains undersaturated oil and is being developed under waterflood. A screening study investigating IOR options highlighted CO₂ injection as technically feasible, suggesting an additional recovery in the range 5-10% of the initial oil in place (STOIIP), subject to further work on the investment economics of the project and corporate sanction.

The results of a subsurface study of the CO₂ injection scheme showing the sensitivity of the incremental oil recovery to some of the key uncertainties were presented.

The strategy used in the study, captures the complex physics of the IOR process through fine scale, 3D, compositional, finite difference simulations of ‘type’ sections of the reservoir. The results from these simulations are then used to calibrate ‘recovery’ curves that capture the characteristics of oil mobilisation as well as the returned solvent volumes. The calibrated curves are then applied in a scale-up streamline simulation to identify a full field response

We hope to have a more detailed article by Roger on this in the next issue of this newsletter.

Jim Riding (jbri@bgs.ac.uk) of the British Geological Survey spoke about the Weyburn Project.

The International IEA Weyburn CO₂ Monitoring Project is currently analysing the effects of a miscible CO₂ flood into a Carboniferous carbonate reservoir rock at a mature onshore Canadian oilfield. Anthropogenic CO₂ from a nearby coal gasification plant is being injected into the reservoir as part of an enhanced oil recovery operation and it is hoped that this gas will be stored permanently.

The European contribution to this project includes the analysis of the pre-injection hydrochemical, hydrogeological and geochemical conditions in the reservoir in order to recognise changes resulting from injection of the CO₂. These baseline studies also include analysing gas concentrations in soil and groundwater to determine potential migration pathways. The CO₂ distributions are irregular and reflect anthropogenic or near surface phenomena; seasonal variations in CO₂ fluxes are present. There are currently no correlations between gas anomalies and injection wells or pipelines. Changes from these baseline conditions as a result of CO₂ injection are also under investigation and will be the focus of future activities. These include the effects of CO₂ injection on the hydrochemical, hydrogeological and geochemical properties of the rock, computer modelling of the reservoir, microseismic monitoring and extensive risk/ safety assessments.

The presentation described the geological and engineering aspects to the operation.

An extra contribution to the newsletter on CO₂ sequestration has been submitted by David Hicks of CMG: Modelling Enhanced Coal Bed Methane Production and Trapping in Sedimentary Basins

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