A number of mature waterflooded fields, such as Brent in the North Sea and others elsewhere are undergoing tertiary recovery by depressurisation. Pressure depletion is achieved by stopping water injection and by producing from the aquifer as well as the hydrocarbon bearing strata. Previously bypassed oil rims and trapped oil and gas are then released. This paper discusses how mineral scale deposition is affected by the change in reservoir conditions that occur during blow down.
Pressure maintenance by waterflooding may prevent reservoir fluids from dropping below the CO2 bubble point until they are in the production string. However, as a result of depressurisation, the CO2 bubble point will move down the tubing and into the formation. Calcite scales form as a result of the increase in pH that occurs when CO2 is evolved, and thus the calcite scaling problem will migrate into the near production well formation during depressurisation. The balance of oil-water and gas-oil capillary pressures changes with pressure depletion, resulting in the mobilisation of previously trapped form ation brines. Waterflooding also results in large volumes of seawater being injected into the oil bearing strata. During depressurisation, this seawater is back produced through the former injectors. Depending on the strength of the aquifer, formation brine may also be produced. If these brines are incompatible, then mixing in the wellbore or near well formation will result in sulphate scale damage. Calculations demonstrate that co-production of aquifer and injected brines may occur for more extensive periods at the critical mixing ratios than would be typical of conventional production scenarios. Former injection wells will produce at near 100% watercuts, with the result that large volumes of water need to be protected. Calculations of reservoir temp eratures and the scaling potentials show that the problem is exacerbated by the fact that during water injection these zones will have been cooled.
A number of mature waterflooded fields, such as Brent in the North Sea and others elsewhere are undergoing tertiary recovery by depressurisation1-5. Pressure depletion is achieved by stopping water injection and by producing from the aquifer as well as the hydrocarbon bearing strata. Previously bypassed oil rims and trapped oil and gas are then released. Since early 1998, the Brent field has been undergoing depressurisation to recover an additional 1.5 Tscf of gas and 34 MMstb of oil, extending the field life by 5-10 years. The platform topsides have been redeveloped and refurbished, with process facilities for low-pressure operations installed, at a cost of over US$ 2 billion4.
The plan is to depressurise the reservoir in order to release solution gas from the bypassed (unswept) and remaining (swept or residual) oil, and to produce the gas, once it has migrat ed to the crest of the structure. Implementing the depressurisation plan is more activity and labour intensive than in a conventional development. The criteria to be managed include gas production and availability, oil production, water production, gas injection, pressure and gas cap size in each reservoir unit and area of the field, gas lift, and ESPs. Maintaining sufficient gross liquid production from the start of depressurisation has necessitated the provision of artificial lift. Gas lift has been installed in a number of wells, while ESPs have been used in low GOR and water producing wells to increase lift. As the reservoir pressure declines there is a transition from gas lift to high rate ESPs to enhance voidage. A number of infill wells have been located in the water-flooded oil leg to gain additional oil production, albeit at high water-cut and with a potential reduction in gross rate.