Increased oil and particularly gas production may be achieved in waterflooded reservoirs by stopping further water injection, and depressurising the reservoir to release solution gas. Pressure depletion may be accelerated by back producing injected brines. However, there is the possibility that these brines may cause formation damage by mobilising fines or deposition of inorganic scales. Scale deposition in production wells may also occur as a result of pressure depletion, with calcite scales being precipitated when the system drops below the CO2 bubble point pressure. This paper discusses the assessment and prediction of scale related formation damage problems that are likely to occur during depressurisation of a case study field. The potential for the specific problem arises from the formation of barium sulphate scale as a result of mixing of injected and formation brines during production. Data used in this study includes well brine chemistries and an existing finite difference reservoir simulation model of the field depressurisation, which was used to calculate the mixing of injected and formation brines, and the movement of the mixing and temperature fronts during waterflooding and subsequent depressurisation.
This study has determined that the behaviour of the scaling potential for each well in this field is different. Also, the degree of scaling, both deep within the reservoir where it does the least damage, and around the wellbore (for both injectors and producers) where it may adversely affect production, can be predicted by detailed modelling using both conventional and reaction-flow simulations. Former injectors converted to water production or infill wells drilled in the aquifer for pressure depletion may experience an increase in the scaling potential that significantly impacts the economics of the project because of the need for extensive prevention (inhibition) treatments. The increased scaling potential in these wells is a result of the dynamics of brine mixing in the reservoir, the lowering of reservoir temperature in the vicinity of injection wells during waterflooding, and the large volumes of water that require to be produced to achieve depressurisation. The magnitude of the scaling problem and the economic impact are lower for the production wells due to lower water production rates and higher temperatures.
A number of mature waterflooded fields are candidates for tertiary recovery by depressurisation, as is currently occurring in the Brent Field, North Sea. Pressure depletion is achieved by stopping water injection and producing from the aquifer as well as the hydrocarbon bearing strata. Solution gas in the residual oil, previously bypassed oil rims and attic oil is then released.The decision to implement depressurisation in any waterflooded field has significant economic considerations. By evaluating the scaling tendency, the uncertainty and cost due to potential losses from scale-related deferred oil and gas production may be minimised.
This process should involve a thorough review of the current scale management practice, followed by a detailed study of which parameters will change as a result of depressurisation.
A candidate field for post-waterflood depressurisation has been studied to identify the potential impact of scale damage on production.A predictive reservoir simulation model, designed specifically to evaluate depressurisation,  was adapted to study the changes in some of the parameters that are expected to impact scale precipitation. This paper describes the application of this model of reservoir depressurisation to evaluate the scaling potential in production wells and former injection wells when they are used for back production of injection seawater.
The calculations performed using the conventional finite difference flow model do not incorporate reaction calculations, although they may be used to demonstrate the propagation of the mixing zone. To model scale precipitation, the consequent ion loss, and permeability impairment, a commercial reaction transport simulator was used.