Jeremie Dautriat

Mechanical instability induced by water weakening in laboratory fluid injection tests

To assess water-weakening effects in reservoir rocks, previous experimental studies have focused on changes in the failure envelopes derived from mechanical tests conducted on rocks fully saturated either with water or with inert fluids. So far, little attention has been paid to the mechanical behavior during fluid injection under conditions similar to enhanced oil recovery operations. We studied the effect of fluid injection on the mechanical behavior of the weakly consolidated Sherwood sandstone in laboratory experiments. Our specimens were instrumented with 16 ultrasonic P wave transducers for both passive and active acoustic monitoring during loading and fluid injection to record the acoustic signature of fluid migration in the pore space and the development of damage. Calibration triaxial tests were conducted on three samples saturated with air, water, or oil. In a second series of experiments, water and inert oil were injected into samples critically loaded up to 80% or 70% of the dry or oil-saturated compressive strength, respectively, to assess the impact of fluid migration on mechanical strength and elastic properties. The fluids were injected with a low back pressure to minimize effective stress variations during injection. Our observations show that creep takes place with a much higher strain rate for water injection compared to oil injection. The most remarkable difference is that water injection in both dry and oil-saturated samples triggers mechanical instability (macroscopic failure) within half an hour whereas oil injection does not after several hours. The analysis of X-ray computed tomography images of postmortem samples revealed that the mechanical instability was probably linked to loss of cohesion in the water-invaded region.

Ultrasonic monitoring of spontaneous imbibition experiments: Precursory moisture diffusion effects ahead of water front

Fluid substitution processes have been investigated in the laboratory on 14 carbonate and siliciclastic reservoir rock analogues through spontaneous imbibition experiments on vertical cylindrical specimens with simultaneous ultrasonic monitoring and imaging. The motivation of our study was to identify the seismic attributes of fluid substitution in reservoir rocks, and to link them to physical processes. It is shown that (i) the P-wave velocity either decreases or increases when the capillary front reaches the Fresnel clearance zone, (ii) the P-wave amplitude is systematically impacted earlier than the velocity is, (iii) this precursory amplitude decrease occurs when the imbibition front is located outside of the Fresnel zone, (iv) the relative variation of the P-wave amplitude is always much larger than that of the P-wave velocity. These results suggest that moisture diffuses into the pore space ahead of the water front. This postulate is further supported by a quantitative analysis of the time evolution of the observed P-wave amplitudes. In a sense, P-wave amplitude acts as a precursor of the arrival of the capillary front. This phenomenon is used to estimate the effective diffusivity of moisture in the tested rocks. The effective moisture diffusivity estimated from the ultrasonic data is strongly correlated with permeability: a power-law with exponent 0.96 predicts permeability from ultrasonic monitoring within a factor 3 without noticeable bias. When the effective diffusivity is high, moisture diffusion affects ultrasonic P-wave attributes even before the imbibition starts and impacts the P-wave reflectivity as evidenced by the variations recorded in the waveform coda.

Changes in microstructure and mineralogy of organic-rich shales caused by heating

Understanding of microstructural changes in gas shales caused by their thermal maturation is of practical importance for evaluation of extractability of hydrocarbons from these low permeability reservoirs through methods such as sweet spot mapping from surface seismic. Two organic-rich shales (ORS), one with extremely high total organic carbon (TOC) and the other extremely low TOC are chosen for this study. The Upper Jurassic Kimmeridge Shale from and the Upper Cretaceous Mancos Shale contain around 23% and 1% TOC, respectively. Samples are subjected to temperatures in the range of 300 to 510°C. Changes in their mineralogical composition, TOC, weight and microstructure with temperature increase are monitored. The Kimmeridge Shale shows rapid decomposition of the organic matter at the temperatures of 370-390°C. This process is accompanied by fracture development and propagation. The Mancos Shale exhibits shrinkage of the solid organic matter with mobile bitumen expulsion and relocation. No fracture development is directly observed in microtomograms. Further work has to be done to understand whether the ability of shale to develop a fracture network depends on its TOC content, the mineralogical composition of its inorganic matrix or on other parameters.