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Sandstone reservoir with combination drives and injection

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This page provides a reservoir management case study for a sandstone reservoir with combination drive supplemented with gas and water injection.

Background and geological information

This field produces from a structure that lies above a deep-seated salt dome (salt has been penetrated at 9,000 ft) and has moderate fault density. A large north/south trending fault divides the field into east and west areas. There is hydraulic communication across the fault. Sands were deposited in aeolian, fluvial, and deltaic environments made up primarily of a meandering, distributary flood plain. Reservoirs are moderate to well sorted; grains are fine to very fine with some interbedded shales. There are 21 mapped producing zones separated by shales within the field but in pressure communication outside the productive limits of the field. The original oil column was 400 ft thick and had an associated gas cap one-third the size of the original oil column. Porosity averages 30%, and permeability varies from 10 to 1500 md.

Program used

The primary recovery mechanism was a combination of a strong, directional waterdrive in the eastern part of the field, solution-gas drive in the western part of the field, and gas-cap expansion. Initial screened openhole completions resulted in uneven water advance caused by permeability differences between zones. A workover program converted all wells to selective, single-zone completions that allowed better control of aquifer advance. The directional waterdrive resulted in gas-cap tilting to the west despite return of all produced gas to the gas cap and extraneous water production on the east side. Water injection around the downdip periphery of the western part of the field was used to:

  • Waterflood the western area
  • Equalize pressure between east and west areas
  • Prevent gas-cap tilting

Because of low dip, recovery by gas-cap expansion was a less efficient recovery mechanism.

When field oil production declined to 4,500 B/D with 98% water cut and an average gas oil ratio (GOR) of 30 Mcf/bbl, gas sales were necessary to maintain acceptable profitability. When gas-cap depressuring was initiated, remaining oil production was thought to be coming from low permeability, thin intervals that would be affected minimally by accelerated water influx accompanying depressuring. Oil production is expected to continue well beyond the time the gas cap is depleted. Gas will be trapped behind advancing water, but reservoir-pressure decline will result in percolation of liberated dissolved gas from the residual oil in the water-invaded zone. This analysis came from a tank-type reservoir simulation model. To date, reservoir pressure has declined from 2,150 to 1,525 psi because the aquifer has been unable to offset the increased withdrawal rates.

Frac packing has provided sand control and near-wellbore stimulation. Conventional gravel packing also has been used when water proximity has been a concern. Plugback workovers and additional well conversions will be used to achieve maximum gas recovery. Original development was on 20-acre spacing. Selective infill drilling has been used to improve the sweep of injected water and to drain isolated parts of various zones.

Recovery performance

The combined recovery factor for all the recovery mechanisms is 66% of original oil in place (OOIP). A contributing factor to this high recovery is a mixed wettability rock yielding waterdrive residual oil saturation of 12 to 13%, based on single-well chemical-tracer tests.

Field surveillance and management

There have been several major reservoir studies of the field during its history to determine and upgrade the depletion strategy. There also has been a sustained surveillance program to monitor reservoir performance. Surveillance has focused on:

  • Maintaining liquid injection-production balance
  • Monitoring area pressures
  • Use of cased-hole logging to monitor gas/oil contacts (GOCs)

Several segment and individual well simulation models have been used throughout the life of the field to better understand the waterfront movement, to adjust injection and offtake locations, and to mitigate bypassing of oil. Cased-hole logging programs (neutron or pulsed neutron) are now conducted at 3-month intervals to monitor the uneven water advance. Reservoir pressure is measured monthly. Pulsed-neutron logs are proving very valuable in locating bypassed oil in the shaley sand sections. Pressure maintenance by waterdrive and injection has permitted wells to produce by natural flow/artificial lift. This allowed cost-effective tubing logging and pressure surveillance.

Noteworthy papers in OnePetro

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External links

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See also

Reservoir management