Asphaltene precipitation and deposition have been a formation damage problem for decades, with the most devastating effects being wettability alteration and permeability impairment. To this effect, a critical look into the laboratory studies and models developed to quantify/predict permeability and wettability alterations are reviewed, stating their assumptions and limitations. For wettability alterations, the mechanism is predominantly surface adsorption, which is controlled by the asphaltene contacting minerals as they control the surface chemistry, charge, and electrochemical interactions. The most promising wettability alteration evaluation techniques are nuclear magnetic resonance, ζ potential, and the use of high-resolution microscopy. The integration of such techniques, which is still missing, would reinforce the understanding of asphaltene interaction with rock minerals (especially clays), which holds the key to developing a strategy for modeling wettability alteration. With regard to permeability impairment, surface deposition, pore plugging, and fine migration have been identified as the dominant mechanisms with several models reporting the simultaneous existence of multiple mechanisms. Existing experimental findings showed that asphaltene deposition is non-uniform due to mineral distribution which further complicates the modeling process. It also remains a challenge to separate changes due to adsorption (wettability changes) from those due to pore size reduction (permeability impairment).

Reservoir rock wettability has been linked to the adsorption of crude fractions on the rock, with much attention often paid to the bulk mineralogy rather than contacting minerals. Crude oil is contacted by different minerals that contribute to rock wettability. The clay mineral effect on wettability alterations is examined using the mineral surface charge. Also, the pH change effect due to well operations was investigated. Clay mineral surface charge was examined using zeta potential computed from the particle electrophoretic mobility. Clay minerals considered in this study include kaolinite, montmorillonite, illite, and chlorite. Results reveal that the clay mineral charge development is controlled by adsorption of ionic species and double layer collapse. Also, clay mineral surface charge considered in this study shows that their surfaces become more conducive for the adsorption of hydrocarbon components due to the presence of salts. The salt effect is greater in the following order: NaHCO₃ < Na₂SO₄ < NaCl < MgCl₂ < CaCl₂. Furthermore, different well operations induce pH environments that change the clay mineral surface charge. This change results in adsorption prone surfaces and with reservoir rock made up of different minerals, and the effect of contacting minerals is critical as shown in our findings. This is due to the contacting mineral control wettability rather than the bulk mineralogy.

Scale formation and deposition in the subsurface and surface facilities have been recognized as a major cause of flow assurance issues in the oil and gas industry. Sulfate-based scales such as sulfates of calcium (anhydrite and gypsum) and barium (barite) are some of the commonly encountered scales during hydrocarbon production operations. Oilfield scales are a well-known flow assurance problem, which occurs mainly due to the mixing of incompatible brines. Researchers have largely focused on the rocks' petrophysical property modifications (permeability and porosity damage) caused by scale precipitation and deposition. Little or no attention has been paid to their influence on the surface charge and wettability of calcite minerals. Thus, this study investigates the effect of anhydrite and barite scales' presence on the calcite mineral surface charge and their propensity to alter the wetting state of calcite minerals. This was achieved vis-à-vis zeta-potential (ζ-potential) measurement. Furthermore, two modes of the scale control (slug and continuous injections) using ethylenediaminetetraacetic acid (EDTA) were examined to determine the optimal control strategy as well as the optimal inhibitor dosage. Results showed that the presence of anhydrite and barite scales in a calcite reservoir affects the colloidal stability of the system, thus posing a threat of precipitation, which would result in permeability and porosity damage. Also, the calcite mineral surface charge is affected by the presence of calcium and barium sulfate scales; however, the magnitude of change in the surface charge via ζ-potential measurement is insignificant to cause wettability alteration by the mineral scales. Slug and continuous injections of EDTA were implemented, with the optimal scale control strategy being the continuous injection of EDTA solutions. The optimal dosage of EDTA for anhydrite scale control is 5 and 1 wt % for the formation water and seawater environments, respectively. In the case of barite, in both environments, an EDTA dosage of 1 wt % suffices. Findings from this study not only further the understanding of the scale effects on calcite mineral systems but also provide critical insights into the potential of scale formation and their mechanisms of interactions for better injection planning and the development of a scale control strategy.

A review of the pressure transient analysis of flow in reservoirs having natural fractures, vugs and/or caves is presented to provide an insight into how much knowledge has been acquired about this phenomenon and to highlight the gaps still open for further research. A comparison-based approach is adopted which involved the review of works by several authors and identifying the limiting assumptions, model restrictions and applicability. Pressure transient analysis provides information to aid the identification of important features of reservoirs. It also provides an explanation to complex reservoir pressure-dependent variations which have led to improved understanding and optimization of the reservoir dynamics. Pressure transient analysis techniques, however, have limitations as not all its models find application in naturally fractured and vuggy reservoirs as the flow dynamics differ considerably. Pollard’s model presented in 1953 provided the foundation for existing pressure transient analysis in these types of reservoirs, and since then, several authors have modified this basic model and come up with more accurate models to characterize the dynamic pressure behavior in reservoirs with natural fractures, vugs and/or caves, with most having inherent limitations. This paper summarizes what has been done, what knowledge is considered established and the gaps left to be researched on.