Enhanced Gas Recovery Potential from CO2 Injection into Depleted Dry Gas Reservoirs - Update Using SNS Field Model

In a previous article Graham Paterson of ECL Technology Ltd (graham.paterson@ecltechnology.com) described some results of a study investigating the EGR potential of CO2 injection into depleted dry gas reservoirs using generic models. This is one of several means of sequestrating CO2 for environmental reasons currently under consideration. Since most dry gas reservoirs achieve very high recovery factors through depletion (leaving a small target for EGR), such injection schemes may not be directly economic without an environmental value placed on CO2 sequestration. It was concluded that it might be possible to achieve a positive EGR by CO2 injection into a depleted gas reservoir late in field life. However, it was noted that a large throughput of CO2 was required to maximise the EGR.

In this article, he provides some further results from a DTI SHARP programme project using a simulation model typical of a large southern North Sea (SNS) dry gas field.

The model represents a mature, but only partially depleted reservoir with initial gas in place of several TCF. The reservoir model covers a large area and includes heavy faulting. Gas is produced through a number of platforms. The model dimensions are 67 x 103 x 17, with gridblock areal extents of between approximately 500 and 1000 ft and layer thicknesses ranging between 50 and 400 ft. There are 86,836 active grid blocks and, as before, compositional simulation was used.

At the end of the history match period, the gas recovery was around 75% of GIIP. The ultimate reserves using a base case blowdown scenario were predicted to be around 82% GIIP. Scenarios have been considered in which CO2 is injected into a cluster of wells defined by a simulation group (corresponding to a platform or satellite structure). This approach was adopted as it is thought it may be more practical from a facilities and economic viewpoint if CO2 injection was required for a limited part of the field only. Sensitivities in which injection of CO2 is delayed have also been considered as well as assessing the effect of limiting CO2 production by shutting in wells when a certain CO2/hydrocarbon gas ratio is reached (e.g. 50%).

It was found that it was possible to achieve a small but positive EGR (defined as production from a particular case minus production from the natural depletion case) from the field model in some cases, see Figure 1.

Figure 1: Enhanced Gas Recovery as Percentage of Remaining Gas-In-Place (Click for larger view)

Higher EGRs are evident in cases in which CO2 injection is delayed until later in field life. For example, in a case in which injection starts after approximately 10 years, an EGR of around 0.9% of remaining GIP was predicted. Limiting CO2 production and shutting in wells as limits are reached improves the EGR. For example, with a 50% CO2 production limit the EGR is increased from 0.9 to 2.7% of remaining GIP. This is because the CO2 contacts a greater volume of the reservoir. This scenario also maximises the CO2 remaining in the reservoir, with about 99% of injected CO2 remaining in the reservoir compared to about 25% in the equivalent case with no limit on CO2 production.

Figure 2: CO2 Remaining in Reservoir as a Percentage of CO2 injected (Click for larger view)

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