Temporal and spatial development of scaling in reservoir aquifers triggered by seawater injection: Three-dimensional reactive mass transport modeling of water–rock–gas interactions

Abstract

Abstract A new numerical modeling approach enables us to calculate the spatial and temporal development of chemical water–rock–gas interactions, including scaling in oil reservoirs which undergo seawater injection. This approach links such simultaneous hydrogeochemical interactions with the three-dimensional flow of pore water in a semi-generic reservoir aquifer. Zero-dimensional modeling and calculating saturation indices, which are based on just one seawater and one formation water analysis, are commonly used to evaluate the type and the intensity of wellbore scaling. This type of generalization about the fate and behavior of minerals (dissolution or precipitation) is incapable of correctly predicting scale formation. Our modeling results show that scaling and other water–rock–gas interactions are integrated in a complex web and are coupled to the flow of pore water. Even the same mineral shows different hydrogeochemical behaviors at different reservoir locations. In our case study, calcite dissolves near the injectors and is precipitated within the producers. The injection strategy determines hydraulics processes which lead to the mixing of seawater with formation water throughout the reservoir aquifer and within producers. Consequently, non-autoscales newly form (1) widely within the reservoir aquifer due to dispersion, and (2) intensively at the spots where the margins of seawater plumes approach to and converge close to the producers. On the other hand, water injection triggers the dissolution of primary minerals. Consequently, aqueous ions are released into pore water which later flows to producers. Such ions can be sequestrated as scale minerals in the reservoir aquifers or in the producers. Thus, coupled hydraulic and hydrogeochemical processes constantly alter the composition of seawater. Accordingly, original seawater will not reach the producer. In terms of equilibrium thermodynamics, scaling is an inevitable consequence of seawater injection. However, our modeling results reveal that several parameters that could be technically controlled can strongly affect the intensity of scaling processes as well as their spatial and temporal development, for example, the spatial arrangement of injectors and producers, decrease in total pressure, and CO 2 partial pressure in the pressure drop zone surrounding producers. Our study demonstrates that three-dimensional modeling is a useful tool for identifying the type of scale minerals and for quantifying their spatial and temporal distribution. It can help to predict the areas where the porosity and permeability properties of reservoirs strongly change due to mineral dissolution and/or precipitation induced by seawater injection. Different modeling scenarios can be calculated for case-specific hydrogeochemical and hydraulic conditions in oilfields of interest. The results gained about the distribution, the amount and the timing of scale formation help to optimize the water injection strategy in order to avoid the “worst case” of scale formation in reservoirs to extend the wellbore life.