Gravity stable miscible gas injection in steeply dipping sandstone reservoir

This page provides a reservoir management case study for a steeply dipping sandstone field in which gravity stable miscible gas injection techniques have been implemented.

Background and geological information

This field was formed by a piercement salt plug that breached a regional fault system. The reservoir is composed of unconsolidated sands that dip away from the salt dome at 65 to 85°. The reservoir is divided into several fault blocks. Within each block, the sand is relatively homogeneous. Porosity averages 26.5%, and permeability averages 1.3 darcy. Oil gravity is 38° API.

Program used

This project is operated as a gravity-stable, hydrocarbon-miscible flood. The injection rate corresponds to a velocity of roughly one-half the critical velocity required for gravity-stable operations. A volume, corresponding to 17% PV, of enriched gas (natural gas liquids plus solution gas) was injected. This was followed by injection of solution gas alone. When injection is completed, blowdown of the gas cap is expected to recover approximately 90% of the enriched gas and a significant portion of the injected solution gas, thus reducing the effective cost of the solvent.

3D reservoir simulations were carried out to examine four depletion scenarios:

• Primary depletion by gravity-stable gas-cap expansion
• Waterflooding at constant pressure
• Gravity-stable immiscible gas injection at constant pressure
• Gravity-stable hydrocarbon miscible flood at constant pressure

Maintaining constant pressure improves recovery by eliminating shrinkage of oil over the course of displacement. Core flood experiments gave recoveries similar to those predicted by the simulations. Miscible residual oil saturation in core floods was 7% of pore volume (PV). Slimtube experiments were also carried out to determine the level of enrichment required to achieve miscibility at a given pressure level. A minimum miscibility pressure (MMP) was selected that was consistent with the volume of enriching natural gas liquids available for the project.

Recovery performance

Primary production occurred through gas-cap expansion. Approximately 6.2% of original oil in place (OOIP) had been recovered when miscible gas injection began. Estimated ultimate recovery is 50% of OOIP for primary recovery in both sands, 74% for total recovery after miscible flood in one sand, and 86% for total recovery after miscible flood in a second sand. These recovery levels were determined by tracking gas fronts with pulsed-neutron capture logging and material-balance calculations. These recovery levels are consistent with simulations that were carried out during planning of the miscible project. To date, conformance has been excellent, with field recoveries similar to those seen in core floods.

Field surveillance management

Routine pressure measurements, pulsed-neutron capture logs, and pressure-transient testing were used to:

• Monitor reservoir performance
• Contact movements
• Identify areas of good and poor communication

Pressure initially was allowed to decline to slightly above the minimum miscibility pressure (MMP) and was then maintained by scheduling injection volumes equal to production. Pressure maintenance became a challenge because of increasing gas-oil ratio (GOR), which resulted in watercut increases and reservoir pressures below the MMP in some areas. Pressures were then increased and maintained by curtailing production from high GOR wells.

Pressure communication between injectors and producers has been good in reservoir A. In reservoir B, pressure communication between injectors and producers has been somewhat hindered by faults and shale barriers that act as baffles.

Noteworthy papers in OnePetro

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External links

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See also

Reservoir management

Miscible flooding

PEH:Reservoir_Management_Programs