The new practices in well drilling as highly inclined, multilateral, and long horizontal section caused wellbore instability issues as a result of rock geomechanics alteration. Economically, wellbore instability issues can increase the total drilling cost by 10–20% and is responsible for an annual economic loss of
$1–6 billion in the oil industry worldwide [
1,
2]. During drilling operations, the drilled well penetrates many subsurface rock formations such that the drilling fluids interact with the rock minerals. The mineralogical compositions of the rock formations and the chemical activity of the drilling fluids play a critical role in the rock–fluid interaction, and downhole drilling conditions such as temperature, pressure, and exposure time control the degree of interactions during drilling operations. Most wellbore instability problems were reported during the long exposure time during drilling operations [
3,
4]. Formation damage is another effect of long exposure time. Drilling for only 15 min with overbalanced pressure can reduce the well productivity by 6–10% due to damage mainly caused by filtrate invasion and interaction with the formation [
5]. Davarpanah et al. [
6] developed a numerical model for formation damage based on experimental sensitivity analysis that involved contact time of the rock and drilling mud (from 0.5 to 2.5 h). The study results showed that increasing the contact time resulted in increasing the formation damage as the rock pore throats and cracks were filled with the drilling mud. The precipitation of drilling fluid solids is one of the critical factors for formation damage, and therefore, the new research for utilizing formate fluids for the drilling operations showed less formation damage with the formate fluids due to low solid amounts in its composition in addition to compatibility with reservoir rock [
7,
8]. The drilling fluid components affected the rock wettability and permeability significantly [
9]. The results of drilling fluid–rock interactions can potentially affect both the petrophysical and geomechanical properties of the drilled formations [
10]. It is therefore important to consider the exposure time effects on rock–drilling fluid interaction on the design of drilling and completion programs to mitigate wellbore instability issues as much as possible.
The rock geomechanical properties are considered key input parameters for geomechanical earth models, drilling and completion design, and stimulation operations [
11,
12,
13]. Rock Young’s modulus and Poisson’s ratio are necessary for stress evaluation [
14]. Many studies utilized the dynamic moduli to estimate the static moduli to be used as inputs for the modeling purposes as the case of reservoir simulation and earth modeling [
14,
15]. The rock unconfined compressive strength (UCS) is the most significant parameter among these properties for evaluating rock geomechanical behavior [
16], and the strength is controlled by many rock parameters such as rock porosity, internal friction angle, grains particle size, and the cohesive forces [
17]. Young’s modulus (
E) represents the rock stiffness as it is the measure of rock sample resistance against the compressional uniaxial stress. Poisson’s ratio (
υ) is defined as the measure of the rotation of the lateral expansion to the longitudinal contraction of the rock sample. Lamé’s parameters (λ and
G) are elastic moduli, where
G is also known as the rigidity or shear modulus which describes the rock resistance against shear deformation. Bulk modulus (
K) is one of the most important elastic moduli,
K is defined as the ratio of hydrostatic stress to the volumetric strain, and the inverse of K is the rock compressibility. The uniaxial compaction modulus or oedometer modulus (
H) represents the plane wave modulus or the compressional P-wave modulus. The elastic moduli
E, λ, G, K, and
H are all measured in the same units as stress units [
18].
Drilling Fluid–Rock Interactions
Several works studied the effects of drilling fluids interactions with shale formations [
10,
19]. The effect of drilling fluids on the geomechanical properties of sandstone is not well studied; a very limited work is found in the literature in this area [
20]. Previous experimental studies on the interaction between shale rocks and water indicated a weakening effect on rock mechanical properties [
21,
22,
23,
24].
Each formation has distinguished values for its geomechanical parameters based on its lithology, rock properties, and fluid flow conditions such as pressure and temperature [
25,
26]. The rock deformation and changes in internal pore systems affect the propagation of the sonic compressional and shear waves (
Vp and
Vs) through the rock samples and, as a result, affect the elastic moduli [
27]. The sonic wave velocity depends on the rock pore geometry and intrinsic rock properties. As the rock porosity increases,
Vp and
Vs decrease. Also, the velocities increase with increasing the effective pressure as the pressure will cause the rock compressibility and create good contact for the rock matrix. The rock saturation was found to affect the sonic wave velocity as the rock saturated with oil was found to increase the
Vp but did not affect the
Vs [
28].
Xu et al. [
15] showed that there is a strong relationship between rock UCS and
E, where the relation degree changed from rock type to another as sandstone and mudstone and that is because of the rock lithology. Yadav et al. [
29] performed an experimental work to address the change in geomechanical properties (Young’s modulus, Poisson’s ratio, and peak strength) of Berea sandstone and shale samples after interaction with water-based mud (WBM) and oil-based mud (OBM). Using the triaxial test, they found that OBM is better than WBM in preserving the shale strength. Kitamura and Hirose [
30] studied the effect of distilled water on the strength of different sandstone types as Rajasthan, Shirahama, and Berea sandstone. They carried out the indentation test to evaluate the rock hardness. Ultrasonic wave velocities and UCS were performed, and the results showed that UCS and Young’s modulus increased when the porosity decreased.
Muqtadir et al. [
31] studied the effect of fluid saturation on Scioto sandstone strength properties. Results showed that the rock samples that were saturated with brine (3 wt.% KCl) were significantly weaker than the oil-saturated samples. The UCS and the tensile strength (TS) of the brine-saturated samples decreased by 9% and 40%, respectively, while in oil-saturated samples, the reduction was 10% and 25%, respectively. Xu et al. [
20] studied the effect of drilling fluid on tight sandstone hardness. WBM and OBM were used, and the results showed that, after two hours, sandstone hardness decreased rapidly by 22.9% with WBM and by 10.1% with OBM. However, after 2 h and up to 15 days, the hardness decreased to 33.1% with WBM while the hardness remained constant with OBM. For OBM, temperature change has only a little effect on the hardness while hardness decreased at a temperature above 122 °F (50 °C) for WBM.
Motra and Stutz [
32] showed that the dynamic elastic moduli (
E, K, and
G) of the metamorphic rocks (quartz mica schist, and amphibolite) were found to be a function of pressure and temperature. The sonic data results showed that P and S wave velocities increased with pressure increase and decreased with temperature increase. Karakul [
33] studied the change in the strength of the clay-bearing rock due to the effects of drilling fluids. The study used claystone and mudstone rock types to study the drilling fluid effect on rock strength. The results indicated that the polymer-based drilling fluid is recommended and that bentonite- or KCl-based mud as polymer-based mud did not affect the rock UCS and tensile strength, and hence, it will not enhance the instability issues.
Mohamed et al. [
34] evaluated the effect of water-based mud (WBM) and oil-based mud (OBM) on the geomechanical properties of different core samples. The experiments were run for different exposure times between the mud and the rock samples (30 min, 1 day, and 2 days) under 300 psi differential pressure and 250 °F. The results showed that
UCS decreased as the exposure time increased for limestone samples. Lamik et al. [
35] presented a new rock strength parameter that can be derived from the drilling parameters while drilling or from the sonic slowness log. The parameter is very sensitive to the lithology and helped to identify the rock type and formations’ boundary. Bageri et al. [
36] studied the effect of the drilled rock geomechanical properties on the drilling fluid properties as the cuttings from the drilled formations were mixed with the drilling fluids with different concentrations. The study showed that the cutting weight percentage in the total fluid, UCS, and E of the drilled sandstone affects the properties of the rheological properties of the drilling fluid.
The objective of this paper is to assess the change in the acoustic properties, dynamic elastic moduli of Buff Berea sandstone, and its failure parameters (UCS and TS) due to interaction with barite-weighted WBM for different exposure time. The new contributions of this study involve, for the first time, assessing the effect of exposure time on the changes in geomechanical properties of the Buff Berea sandstone, modifying the aging cell for the filtration loss apparatus to accommodate rock sample, using NMR and SEM analysis to detect the effect of the exposure time after the interaction process with the drilling fluid, and integrating the petrophysical-geomechanical with statistical analysis to develop new sets of correlations that can be used to predict the geomechanical properties as a function of exposure time and porosity reduction.