Oil Recovery and Fracture Reconsolidation of Diatomaceous Reservoir Rock by Water Imbibition at High Temperature
Authors: ikeda Maki , Tang Guo-Qing , Ross Cynthia Marie , Kovscek Anthony Robert 
Published: December 2007

Abstract
Spontaneous imbibition and coreflood experiments were conducted on samples from two diatomaceous oil reservoirs to measure oil recovery as a function of temperature and to quantify changes, if any, in the rock fabric resulting from the flow of brine and synthetic steam condensate (180–230°C, pH = 7 and 10) through diatomite subjected to a radial confining stress. Spontaneous imbibition tests at temperature gauge oil recovery potential at negligible pressure gradient. Numerous imbibition tests show that oil recovery from diatomite is accelerated and enhanced at elevated temperature mainly due to a systematic shift toward greater water. Comparison of results for cores from different diatomite reservoirs appears to indicate that dissolution of calcium-bearing minerals tends to retard fines production and delay changes in core wettability. Longterm corefloods examine the ability of diatomite to sustain thermal operations. Core permeabilities following significant volumes of high temperature fluid injection (greater than 10 PV) decreased by roughly 10%, in most cases, whereas porosity alteration varied from 5 to 30%. These alterations in core properties had no apparent negative effect on oil recovery behavior. Nevertheless, X-ray computed tomography (CT) scanning revealed that the grain density of samples increased during the flow of hot alkaline fluids and that cores became more homogeneous. Hot alkaline fluid injection combined with moderate confining stress lead to "reconsolidation" of fractured cores. The increase of grain density is not linked to opal-A to opal-CT transformation but rather to the combined effects of compaction, fines mobilization, and dissolution of susceptable minerals. Tracer characterization of cores supports visual and X-ray CT inspection that suggests that fractured cores behave in a more homogeneous, unfractured fashion that aids oil recovery following heating and application of confining stress.
The study of oil recovery from diatomite is of particular interest due to the 12–18 Bbbl of oil in place1. We lack, however, a general understanding of oil recovery mechanisms from this low permeability fractured rock and any associated transformations of the rock matrix. Generally, steam injection appears to lead to favorable oil recovery2,3. A variety of mechanisms appear to improve recovery during steam injection into diatomite, as detailed next4.
First, heating leads to thermal expansion of the oil as well as viscosity reduction. Because of thermal expansion and viscosity reduction, injected fluids do not have to contact oil directly in order to enhance recovery. Second, steam injection is accompanied by significant condensation of water vapor leading to low salinity, high pH, hot fluid that subsequently imbibes into the rock matrix displacing oil. In previous studies, diatomite samples have exhibited a preferential shift toward water wetness as a result of hot-fluid injection5,6
Despite the advantages of thermal recovery for light- and heavy-oil diatomite and documented improvement in oil recovery at field scale2,3,7,8, a frequently mentioned complicating factor is rock dissolution and transformation of silica from an unstable amorphous to a stable paracrystalline phase, the so-called opal-A to opal-CT transformation9. Simply put, these effects need to be understood better. For example, dissolution occurs when hot water contacts the rock and precipitation appears as silica laden fluid flows into cooler portions of the reservoir. The distribution and the phase of the silica precipitates is an open question. Moreover, results indicate that mechanical properties of the rock change under the influence of injection fluid composition and pH, temperature, and initial oil saturation10,11.