Abstract
An offshore field is producing oil from multiple reservoirs with peripheral water injection scheme. Seawater is injected through a subsea network and wellhead towers located along the original reservoir edge. However, because its OWC has moved upward, wells from wellhead towers are too remote to inject seawater effectively, with some portion going to the aquifer rather than oil pool. Therefore, it is planned to migrate injection strategy from peripheral to mid-dip pattern. An expected risk is scaling by mixing incompatible seawater and formation water. Such risk and mitigation measures were evaluated.
To achieve the objective, the following methodology was applied: 1. Scale modelling based on water chemical analysis. 2. Define scale risk envelope with three risk categories 3. Tracer dynamic reservoir simulation to track formation water, connate water, dump flood water, injection seawater and treated seawater. 4. Review the past field scale history data 5. Coreflood experiment to observe actual phenomena inside the reservoir with various parameters such as water mixing ratio, sulphate concentration, temperature and chemical inhibitor 6. Consolidate all study results, conclude field scale risk and impact of mitigation measures.
Scale prediction modelling, verified by coreflood tests, found that mixing reservoir formation water and injection seawater causes a sulphate scale risk, with risk severity depending on mixing ratio and sulphate concentration. Reservoir temperature was also found to correlate strongly with scale risk. Therefore, each reservoir should have different water management strategy. Scale impact is limited in the shallower wide reservoir with cooler reservoir temperature. Such reservoir should therefore have mid-dip pattern water injection to avoid low water injection efficiency with possible scale inhibitor squeezing as a contingency option. On the other hand, deeper reservoir has higher risk of scaling due to its higher temperature, causing scale plugging easily in reservoir pores and production wells. For such reservoir, peripheral aquifer water injection, treated low-sulphate seawater with sulphate-removal system, or no water injection development concept should be selected.
By using modelling and experiment to quantify the scale risk over a range of conditions, the field operator has identified opportunities to optimize the water injection strategy. The temperature dependence of the scale risk means, in principal, that different injection strategy for each reservoir can minimize flow assurance challenges and maximize return on investment in scale mitigation measures.
