The drilling/fracturing of lateral wells in thinly laminated source rocks often confronts critical wellbore instability and fluid loss problems. These problems are mainly caused by the leakage of the fluids into the rock matrix through a system of fine layers and immense network of natural fractures. It is conceived that the penetration of fluids perturbs the rock’s effective stress state or alters its strength. Nevertheless a thorough understanding of the instability phenomenon has not been introduced yet where numerous questions over the underlying mechanisms remain unresolved. For instance in a mixed-wet rock system it is unclear how an oil based mud (OBM) or water based mud (WBM) invades the different pore volumes; What are the effects of the clay content, types (swelling or not) and total organic content (TOC) including their spatial distribution in the shale matrix, and so on?

In this work, we perform nuclear magnetic resonance (NMR) measurements on highly laminated source rocks which are sequentially saturated by spontaneous imbibition of diesel and 5% KCl brine. We probe the rate and capacity of oil/brine imbibition focusing on the wetting characteristics of the bedding planes, the effects of mineralogy, TOC, and the connected pore network in the kerogen and inorganic matrix on the fluid distribution inside these rocks. Hence, we provide guidelines for optimizing drilling-fluid design, horizontal drilling and fracturing operations.

For each of the source rocks studied, samples were drilled parallel and perpendicular to the beddings. Then, each sample is cut into twin plugs which are submitted to two sequent imbibition experiments: 1- regular imbibition experiment where one of the twin plugs imbibed oil and the other imbibed brine for varied times, and 2- reverse imbibition experiment where the twin plugs are interchanged to imbibe the other fluid. The mineral elements, phases and the TOC of the rocks were measured using X-ray Fluorescence (XRF), X-ray Diffraction (XRD) and HAWK pyrolysis, respectively.

The measured NMR T2 spectra showed that all samples were able to imbibe both oil and brine with a clear preference of oil indicating a mixed wettability state of these source rocks. This is attributed to the coexistence of organic and inorganic pores in these rocks. Moreover, the prevalence of surface relaxation on the NMR dynamics was prominent as all T2 relaxations took place at time scales (T2 ≤ 100 ms) much shorter than their bulk values. Upon imbibition, brine is observed to flow along the bedding planes which are rich in clay minerals and therefore forming pathways of minimum flow energy. Indeed, the interaction between brine and clay is identified to be the potential driver of the rock stability problems especially near the wellbore; however it is firmly dependent on the type of existing clays. Oil is absorbed faster than brine and in larger volumes. The discrepancies between oil and brine imbibition is magnified by the presence of fractures which enhanced the network connectivity of both hydrophobic and hydrophilic pores or even across them. Furthermore, the fractures allowed the fluids to surpass the vertical bedding planes and thus accelerating the fluid distribution processes inside the pore space.

You can access this article if you purchase or spend a download.