Effects of salinity and rock clogging on injectivity dynamics of flooding wells: Experiments, modeling and validation on field data

Abstract

Injection of water into a rock formation is a common oilfield services technology to maintain high reservoir pressure and increase ultimate recovery of hydrocarbons. While flowing through the well from surface to the rock formation, injected water typically transports fine particles, for example, fine sand grains and calcite precipitated at surface pipeline conditions while mixing water from different sources (e.g., fresh, Cenomanian and formation brine). In the framework of the two-fluid approach to suspension flow modelling, we formulate mathematical model for linear filtration of a particle-laden suspension in the vicinity of a fractured flooding well and transport of ion concentration (salinity). Two major factors of well injectivity decline are described, namely, particle trapping with associated reduction in permeability and porosity of the rock as well as the effect of salinity of injecting water leading to clay swelling, calcite precipitation and change of relative permeabilities of the rock with respect to water and oil. We calibrate suspension filtration model against in-house experiments on clogging of artificial and natural rock cores, in which the profiles of fines concentration along the cores are obtained using X-Ray computed tomography and analysis of 3D rock reconstruction images. The water injection model is adopted to conditions of Priobskoye oilfield of Western Siberia by using the results of standard laboratory experiments on fluid-fluid (calcite precipitation) and fluid-rock (clay swelling, migration of internal fines) compatibility, as well as the effect of salinity on oil displacement and analysis of solid fraction in the injecting water. The calibrated model is then used to describe field data on dynamics of injection rate of three flooding wells. It is obtained that the simulations predict the long-term injectivity dynamics of the wells very well, while at early times (up to 5 months from the start of injection) the model underestimates the injection rate. While fitting the model to field data, we varied only two parameters, namely, solids concentration in the injecting water (in the range provided by lab experiments) and trapping coefficient (the range is limited to result of experiments made with target rock cores). It is demonstrated that only a combination of injectivity decline factors allows to describe the long-term flooding rate of the wells. Ignoring either particle trapping or salinity effects lead to significant overestimation (up to 50%) of the long-term injection rate. Parametric study of water injection showed that two-fold increase in solids concentration in the injecting water as well as oil compressibility lead to similar decrease in long-term injection rate of a well.