Effects of Kaolinite on Fines Migration and Formation Damage

Abstract

The presence of residual oil or gas during fines migration in porous media greatly affects particle mobilization and capture. This paper investigates the effects of kaolinite content on fines migration and formation damage in the presence of oil residual. We carried out corefloods on engineered sand-packs that contained different percentages of kaolinite. Each core sample was subjected to brine injections varying from seawater salinity to freshwater. Measurements of the pressure drop and effluent particle size distributions were performed for each injection. It was determined that the main cause of permeability decline was pore throat straining by kaolinite. A higher decline of permeability accompanied by intensive fines production was encountered during freshwater injection. If compared with fines migration under single-phase flow, having a residual phase showed a significant decrease in formation damage and the amount of produced kaolinite. The laboratory data were matched with the analytical model for one-dimensional linear flow. A close agreement between the coreflood data and the model was obtained. The model coefficients were used for well injectivity decline prediction using a numerical one-dimensional radial injection model. The kaolinite content and the residual oil phase greatly impacted the well injectivity decline.

Well Injectivity during CO2 Geosequestration: A Review of Hydro-Physical, Chemical, and Geomechanical Effects

“…Permeability decline due to fines migration is one of the most common reasons for injectivity impairment and is commonly caused by kaolinite, quartz, microcline, muscovite, illite, chlorite, and silt clays. ,,− The related short-term risk of fines migration is lowest in quartz-rich sandstones and is highest in calcite cemented facies. ,, It generally increases due to the presence of impurities.…”

A Review on Chemical Sand Production Control Techniques in Oil Reservoirs

“…Note that using chemical methods may face challenges such as determining some operational parameters, e.g., the injection rate and the optimal concentration of the injectants . Side issues should also be meticulously considered, such as the reduction of formation permeability due to clogging the porous media, improper distribution of chemicals under downhole conditions, low diffusion depth of the chemicals into the wellbore, temperature sensitivity and stability of chemicals, and the so-called chemical–rock and chemical–formation fluid interactions. , However, despite all these technical problems, chemical methods have attracted significant attention to tackle sand production, particularly in narrow hydrocarbon wells, multiple completion wells, and formations composed of extra fine sand. , …”

A Two-Phase Numerical Model of Well Test Analysis to Characterize Formation Damage in Near-Well Regions of Injection Wells

“…To improve oil recovery, line drive patterns have been widely employed in offshore oilfields, as shown in Figure 1. However, formation damage is quite common in near-well regions of injection wells in offshore oilfields due to interaction between injection water and clay minerals [1][2][3][4][5][6][7][8][9][10][11][12]. To characterize the formation damage and estimate reservoir properties, transient pressure data observed from the testing wells are usually interpreted by traditional pressure transient analysis models [13][14][15][16][17][18][19][20][21][22], which are simplified single-phase models divided into two or three regions according to the properties of formation and fluids.…”