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The Impact of Hydrocarbon Emplacement on Carbonate Diagenesis

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Diagenesis has been described as a term that encompasses all the arrays of biological, physical and chemical processes, that act and transform sediments from the initial stage of deposition until just before metamorphism. Nader (2017). The significant role of diagenesis in geological systems in creating and destroying porosity via dissolution and pore occluding cementation, has long been recognised for many decades (Zhang et al. , 2017), key concept and a recent area of keen interest in diagenetic studies(traceable to the increased and continuous frontier exploration in deeper part of basins), is the deep burial diagenetic realm.

This is characterised by the action of very aggressive Basinal fluids that create many processes, such as cementation, dissolution and recrystallization which act to define the ultimate petro physical pathway of reservoirs (Moore, 2001). Investigation into this unknown realm has spanned from traditional or classical approaches with the use of petrographic and field characterisation techniques, to more sophisticated and advanced stages involving quantitative and experimental approaches with the use of advanced microscopy like Scanning electron Microscopy, Computer Tomography-Scan (CT-Scan) and other computer assisted technique with modelling, for proper assessment and understanding of the process (Giles, 1997; Nader, 2017). One of the most important factors that influences deep burial diagenesis and worth our critical assessment is the presence of liquid hydrocarbons in reservoir rocks (Choquette and James, 1987).

The Role of Hydrocarbon Emplacement in Diagenesis

It was Johnson (1920) cited in (Bukar, 2013), who first revealed the role that hydrocarbons can play in the diagenesis of reservoir rocks through cementation inhibition. Since then, this has remained a subject with rising concerns and interest, with a lot of review and investigations using various case studies (Worden et al. , 1998; Neilson and Oxtoby, 2008; Bukar, 2013; Kolchugin et al. , 2016). But also with some attendant contentions and uncertainties, like the oil inhibit cementation debate, questions regarding the source and transport of the huge volume of CaCo3 during diageneis.

The unusual increase in the porosity-permeability in the Fulmar Formation of the North sea much more than the average expected at their depth, based on the world porosity depth trend (Wilkinson and Haszeldine, 2011), as well as in the Kharaib Formation, Abu Dhabi (Neilson et al. , 1998) and many other reservoirs has given a very strong basis beyond the influence of over pressure to agree with the school of thoughts that oil can inhibit cementation. However, on the other hand, the presence of petroleum inclusions (fig. 1) as well as lack of a change or contrasting porosity between the oil and water legs in some reservoir has served the basis to doubt or contradict the oil inhibit 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 polarize light. B is the same image in cathoduluminescence view. (Caja et al. , 2006). It is important to note that fluids play very important role during diagenesis; they can act as transporting mediums, can dissolve and re- precipitate cements during this process. It therefore follows that the presence of hydrocarbons which is also a fluid in its right may also be able to significantly affect diagenesis. Generally according to Worden eta al (1998) oil can affect diagenesis in any one or all of the following processes. I. By hindering or reducing the flow pathway for mass transport, this can limit cementation to the thin film of the irreducible water of saturation on the rock grains.

However the effectiveness of all these processes and degree of cement inhibition depends on the timing and level of hydrocarbon saturation as well as the wettability of the reservoirs. (Worden et al. , 1998; Kolchugin et al. , 2016). The case studies that demonstrated that oil cannot inhibit cementation, are probably those in which oil emplacement was late, after cementation had already occurred. But one thing certainly remains, that the fate of diagenesis never remains the same when oil steps into the system, oil can limit the aqueous phase flow and mass transfer processes, making the pore network tortuous or coat the grains in the reservoir in an oil wet system,(Worden et al. , 1998) reducing cementation. 1. 3. The Kinetics and Thermodynamics of Calcite Growth and CementationIt has been known that most limestones have depositional porosities of about 40 -70%, Pray and Choquette (1969), Prajpti eta al (2017), but this is usually reduced to a value < 5% with little or no contribution from compaction (Bathurst, 1970; Prajapati et al. , 2017), this reduction has serious implication on the role of carbonate cementation in the occlusion of pores spaces during the diagenesis of limestones. Understanding of the kinetics and thermodynamics of calcite precipitation using our inorganic geochemistal tool box will be vital in establishing the rate of calcite cementation in geological processes. Calcite growth and development is believed to occur in three stages (Helt 1978): I. Formation of supersaturated solutionII. Crystal Nucleation III. Crystal growth. Crystal nucleation involves the assemblage of ions to form Particles for further growth and is regarded as the first step for calcite precipitation, Particles with nuclei below the critical size are dissolved back into the solution, while those who have exceeded this threshold set the pace for crystal growth. Where K is a constant, p the number of molecules needed to assemble to form a critical nuclei, I is the induction time needed for a nucleus of critical size to be assembled, and C the initial concentration of the supersaturated solution. Subsequent to formation, crystals begin to grow by the propagation of the surfaces on the critical nuclei formed, based on classical and non-classical theorem. The classical theorem establishes the growth of crystals by the incorporation of monomers through attachment and detachment on active sites of crystal planes. Key processes are adsorption, surface energy differential and diffusion. Experimental studies of calcite growth rate is either performed by using calcite or other materials as nucleation site (seeded approach) or unseeded, which results into spontaneous crystallization (Rybacki 2010). Seeded experiment are the best for studying the rate of crystal growth (Rybacki 2010), because they allow the process to be monitored gradually before crystallization takes place rather than occurring instantly. A number of seeded experiment have been carried out (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/dLWhere Q is rate of fluid flow, K is the hydraulic constant, A is the cross sectional area and dh/dL is the hydraulic gradient. (Hubbert, 1956)These experiments showed that the rate of calcite growth and precipitation is mainly influenced by the level of saturation (ca+), temperature, pH,the ionic activity and the nature of the nucleation substrate (Rybacki, 2010; Declet et al. , 2016). Calcite precipitation occurs in slightly to high alkaline environment, but becomes irregular beyond pH>10, experimental work has observed optimum precipitation from 7. 5- 9. 0 pH. (Ruiz-Agudo et al. , 2011; Declet et al. , 2016). According to Declet eta al (2016) too much or excess increase in pH reduces the surface concentration for calcite growth and increases the supersaturation which also reduces the particle size. Higher supersaturation increases the rate of nucleation while forming smaller crystals in contrast to lower supersaturations with lower rate but bigger crystals(Jaho et al. , 2015). Experiment on the influence of temperature has revealed that temperature plays a role in the polymorph distribution of calcite crystals. Calcite is more favoured at lower and ambient temperatures comparable to aragonite polymorph which predominates about 800(Morse et al. , 2007). Another means through 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 of about 90% conversion mechanism of calcite precipitation in less than a day (Al-Thawadi 2011 cited from Ashraf et al, 2017). However, at higher concentrations of calcium ions, the urease activity can stop urea hydrolysis. Increase in temperature from 20-600C can promote urease activity but a decrease is observed beyond 700C due to enzyme deactivation (whiffin 2004 cited by Ashraf eta al, 2017). In order to avoid the byproducts and relicts of the microbes from adding to porosity occlusion, the inorganic calcite precipitation and growth mechanism is preferred in this work.

Problem Discussion

The lack of proper accessibility of petroleum reservoirs due to their size and burial, inevitably results in the sampling of only a fraction of reservoirs. Geologists then have to rely greatly on subsurface modelling to determine the distribution of porosity and permeability in reservoirs. But, in order for such models to be accurate, a thorough understanding of the controls and parameters that influence diagenesis like oil presence at the subsurface would have to be clearly known and factored into the models applied. Our understanding the effect of oil presence, during diagenesis on cementation inhibition has been well known and demonstrated (Neilson et al. , 1998; Worden et al. , 1998; Kolchugin et al. , 2016), but the conclusions has been largely limited to qualitative studies and rely mostly on petrographic data. As such other influential factors like capillary pressure, oil composition and mineralogical variations between the oil and water legs are rarely fully accounted for(Worden et al. , 1998). This leads to a biased and less accurate estimation of the impact of oil against cementation. The key question therefore is: if oil can inhibit cementation, at what level of saturation, degree or rate can this occur? (Kolchugin et al. , 2016).

This question may be best answered by comparing the rate of cementation in the water and oil leg at the same condition afforded mainly if not only, through experimental studies. If this is not possible, one needs to produce samples in conditions that mimic oil and water legs. Therefore, the aim of this work is an attempt to provide a strong evidence that oil can inhibit cementation and to quantify its impact through experimentation and pore scale modelling, on the rate of cementation. Emphasis has been placed on calcite cementation because, calcite appears to be easier to precipitate than other cements. However, conclusions and findings can be applicable in mixed carbonates-silicates, and other reservoirs as well. The following questions will be addressed: I. What is the impact of calcite cementation rates on porosity and permeability distribution in porous rocks(i. e. the level of diagenesis in the water leg or absence of oil)II. What is the impact of wettability on carbonate cement precipitationIII. What is the impact of oil emplacement on the petro physical properties of carbonate rocks under laboratory controlled conditions from typical carbonate depositional settings? IV. Can we infer empirical relationships and develop a model to determine the mechanisms and dynamism of carbonate cementation in the presence of oil? V. Can we be able to determine the applicability of laboratory experiments at non-reservoir conditions in understanding the dynamism of a reservoir?

Materials and Methodology

MaterialsI. Rock samples: Samples from the oolitic ketton limestone, a middle Jurassic age rock which is part of the Lincolnshirre member, will be used for the experiment. They are about 99. 1% of calcite with a bimodal porosity distribution, which makes it suitable for calcite growth and precipitation, as well as for a good resolution under the micro-computer tomographic scan(µCT-scan)(Menke et al. , 2015). Samples representative of typical carbonates depositional settings will also be used, but in a later aspect of the studies. II. Pressure flow or core flooding set up for fluid injection at Teesside universityIII. Vacuum saturator at Teesside university for cleaning up the core plugsIV. Sodium bicarbonate salt and calcium chloride salt for calcite precipitationV. Sodium chloride salt (NaCl ) for ionic strengthVI. Sodium hydroxide(NaOH) for setting up the pHVII. Bicine (1M,Ph 8. 6) a pH buffer to maintain the pH range within 7. 8-9. 0VIII. Micro Computer tomographic scan (µCT-scan) for pore scale imaging at Teesside University.

Determination of the impact of hydrocarbon on calcite cementation for water wet rocks3 new core plugs of ketton limestone (K1, K2 and K3) similar to the ones used above will be cleaned with deionised water using the vacuum saturator. Imaging with µCT-scan will be done to assess the initial nature of the pores and then growth solution similar to the one used above will be injected into it, using the multi-channel pump, but this time around simultaneously with hydrocarbon oil at the rate of 0. 5cm3h-1. K1, K2 and K3, would be removed for CT imaging after 24hrs, 48hrs and 72 hrs respectively, in order to measure the size and level of cementation after flooding. This will be compared with the growth rate in experiment 2 above and used to assess the impact of hydrocarbon on calcite cementation in water wet rocks.

Determination of the impact of hydrocarbon on calcite cementation for oil wet rocks. 3 new core plugs similar to the ones above will be used but this time they would be cleaned and rinse with oil and made to be oil wet, using the vacuum saturator, before undergoing the same process enumerated above. These experiment will also be repeated on representative sample from typical carbonate depositional setting to make our results widely applicable The result from these experiments will be used to develop a pore scale geochemical model to apply to reservoir model problems.

Progress and Result

At the beginning of my program in January, the first 3 months were dedicated to studying and carving out a new research topic and proposal, this was coupled together with trainings and development via participations in various workshops and seminars. After the submission, the remaining periods were committed to further workshops and trainings as well as background studying, in preparation and writing of the literature review for the research. Some consultations were also made both within and outside of the university to source for information and support for this research. On the 9th of august 2018, a visit was made to the University of Teesside to form a collaboration and support, which will enable me run some of the lab work, involving the injection of fluids into rock plugs. At the time of submitting this report, arrangement and purchase of consumables and materials has been ordered, to kick start the preliminary experiments. The projections are that, by this same time next year, a lot of result will be generated to enrich the research.

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