IndexIntroductionDiscussion of the problemMaterials and methodologyProgress and resultIntroductionDiagenesis has been described as a term that encompasses all matrices of biological, physical and chemical processes, which act and transform sediments from phase initial deposition until shortly before metamorphism. Nadir (2017). The significant role of diagenesis in geologic systems in creating and destroying porosity through pore-clogging dissolution and cementation has been recognized for many decades (Zhang et al., 2017), a key concept and a recent area of ​​keen interest for diagenetic studies (traceable to the growing and continuous frontier exploration in the deepest part of the basins), is the diagenetic realm of deep burial. Say no to plagiarism. Get a tailor-made essay on "Why Violent Video Games Shouldn't Be Banned"? Get an original essayThis is characterized by the action of very aggressive basinal fluids that create many processes, such as cementation, dissolution, and recrystallization that act to define the final petrophysical pathway of reservoirs (Moore, 2001). Investigation into this unknown realm has ranged from traditional or classical approaches with the use of petrographic and field characterization techniques, to more sophisticated and advanced phases involving quantitative and experimental approaches with the use of advanced microscopy such as electron microscopy scanning, computed tomography scanning (CT -Scan) and other computer-assisted techniques with modeling, for a correct evaluation and understanding of the process (Giles, 1997; Nader, 2017). One of the most important factors influencing the diagenesis of deep burials and which deserves our critical evaluation is the presence of liquid hydrocarbons in reservoir rocks (Choquette and James, 1987). It was Johnson (1920) cited in (Bukar, 2013), who first revealed the role that hydrocarbons can play in the diagenesis of reservoir rocks through the inhibition of cementation. Since then, this has remained a topic of growing concern and interest, with many reviews and investigations using various case studies (Worden et al., 1998; Neilson and Oxtoby, 2008; Bukar, 2013; Kolchugin et al., 2016). . But also with some controversies and uncertainties, such as the debate on oil-inhibiting cementation, questions regarding the source and transport of the huge volume of CaCo3 during the diageneis. The unusual increase in porosity permeability in the North Sea Fulmar Formation is much more than the average expected at their depth, based on global porosity depth trends (Wilkinson and Haszeldine, 2011), as well as in the Kharaib Formation, Abu Dhabi (Neilson et al. al., 1998) and many other reservoirs have provided a very solid basis, beyond the influence of overpressure, for agreement with the school of thought that petroleum can inhibit cementation. However, on the other hand, the presence of oil inclusions (fig. 1), as well as the lack of a change or contrasting porosity between oil and water in some reservoirs, has formed the basis for doubting or contradicting the oil-inhibiting cementation theory, giving rise to the second school of thought which insists that oil does not inhibit cementation (Bjorkum et al., 1993). A is the view in plane polarized light. B is the same image in the cathodoluminescence view. (Caja et al., 2006). It is important to note that fluids play a very important role during diagenesis; they can act as a means of transport, they can dissolve and re-precipitate the cements during this process. It therefore follows that even the presence of hydrocarbons which is also a fluid in its own right canbe able to significantly influence diagenesis. Generally according to Worden et al (1998) oil can influence diagenesis in any or all of the following processes. I. By impeding or reducing the flow path for mass transport, this may limit cementation to the thin film of irreducible saturation water on the rock grains. However, the effectiveness of all these processes and the degree of inhibition of the cement depend on the times and level of saturation of the hydrocarbons as well as the wettability of the tanks. (Worden et al., 1998; Kolchugin et al., 2016). The case studies that have demonstrated that oil cannot inhibit cementation are probably those in which oil placement occurred late, after cementation had already occurred. But one thing certainly remains, that the fate of diagenesis never remains the same. As oil enters the system, the oil can limit aqueous phase flow and mass transfer processes, making the pore network tortuous or coating grains in the reservoir with a wet oil. system, (Worden et al., 1998) reducing cementation. 1. 3. The kinetics and thermodynamics of calcite growth and cementation It is known that most limestones have depositional porosities of approximately 40 -70%, Pray and Choquette (1969), Prajpti et al (2017), but this is usually reduced to < 5% with little or no contribution from compaction (Bathurst, 1970; Prajapati et al., 2017), this reduction has serious implications for the role of carbonate cementation in the occlusion of pore spaces during pore diagenesis limestones. Understanding the kinetics and thermodynamics of calcite precipitation using our inorganic geochemical tools will be critical to establishing the rate of calcite cementation in geologic processes. The growth and development of calcite is believed to occur in three phases (Helt 1978): I. Formation of a supersaturated solution II. Crystal nucleation III. Crystal growth. Crystal nucleation involves the assembly of ions to form particles for further growth and is considered the first step in calcite precipitation. Particles with nuclei below the critical size are dissolved into the solution, while those that have exceeded this threshold set the pace for the crystal. growth. Where K is a constant, p the number of molecules required to assemble to form a critical nucleus, I is the induction time required for a critical size nucleus to assemble, and C the initial concentration of the supersaturated solution. Subsequent to formation, crystals begin to grow by surface propagation on the critical nuclei formed, based on classical and non-classical theorems. The classical theorem establishes the growth of crystals by incorporation of monomers by attachment and detachment on the active sites of the crystal planes. The key processes are adsorption, surface energy differential and diffusion. Experimental studies on the growth rate of calcite are performed using calcite or other materials as the nucleation site (seeded approach) or without seeding, which results in spontaneous crystallization (Rybacki 2010). Seeded experiments are best for studying the growth rate of crystals (Rybacki 2010), because they allow the process to be monitored gradually before crystallization occurs rather than occurring instantaneously. Numerous experiments have been conducted (Jaho et al., 2015; Declet et al., 2016 etc.; Liszka et al., 2016) using various combinations such as the reaction of calcium chloride and sodium bicarbonate with rocks and glass particles in flow experiments based on Darcy's law, given as: Q= KA. dh/dLWhereQ is the fluid flow rate, K is the hydraulic constant, A is the cross-sectional area, and dh/dL is the hydraulic gradient. (Hubbert, 1956) These experiments demonstrated that the rate of growth and precipitation of calcite is influenced mainly by the saturation level (ca+), temperature, pH, ionic activity and the nature of the nucleation substrate (Rybacki, 2010 ; Declet et al , 2016). Calcite precipitation occurs in a slightly to high alkaline environment, but becomes erratic above pH>10, experimental work has observed optimal precipitation from 7.5 to 9.0 pH. (Ruiz-Agudo et al., 2011; Declet et al., 2016). According to Declet et al (2016) an excessive or excessive increase in pH reduces the surface concentration for calcite growth and increases supersaturation which also reduces particle size. Higher supersaturation increases the nucleation rate forming smaller crystals in contrast to lower supersaturations with lower rate but larger crystals (Jaho et al., 2015). Experiments on the influence of temperature revealed that temperature plays a role in the polymorphic distribution of calcite crystals. Calcite is more favored at lower, ambient temperatures comparable to the aragonite polymorph which predominates at approximately 800 (Morse et al., 2007). Another means by which calcite can be precipitated is through the process of microbial-induced calcite precipitation (Ashraf et al., 2017; Cheng and Shahin, 2019). This is an efficient process with a conversion mechanism of approximately 90% of calcite precipitation in less than a day (Al-Thawadi 2011 cited by Ashraf et al, 2017). However, at higher concentrations of calcium ions, urease activity can arrest the hydrolysis of urea. Increasing temperature from 20-600°C can promote urease activity, but a decrease is observed above 700°C due to deactivation of the enzyme (whiffin 2004 cited by Ashraf et al, 2017). In order to prevent the by-products and relics of microbes from adding to the clogging of porosity, the precipitation and growth mechanism of inorganic calcite is preferred in this work. Discussion of the problem The lack of adequate accessibility to oil fields due to their size and burial inevitably results in the sampling of only a fraction of fields. Geologists must therefore rely heavily on subsurface modeling to determine the distribution of porosity and permeability in reservoirs. But, for such models to be accurate, a thorough understanding of the controls and parameters that influence diagenesis, such as the presence of oil in the subsurface, should be clearly known and taken into account in the applied models. Our understanding of the effect of the presence of oil during diagenesis on cementation inhibition is well known and demonstrated (Neilson et al., 1998; Worden et al., 1998; Kolchugin et al., 2016), but the conclusions have been largely limited to qualitative studies and are based primarily on petrographic data. Therefore, other influential factors such as capillary pressure, oil composition, and mineralogical variations between oil and water are rarely fully taken into account (Worden et al., 1998). This leads to a biased and less accurate estimate of the impact of oil on cementation. The key question therefore is: if oil can inhibit cementation, at what saturation level, degree or rate can this occur? (Kolchugin et al., 2016). This question can best be answered by comparing the rate of cementation in the water and oil sections under the same conditions obtained primarily, if not only, through experimental studies. If this is not.