Find three examples of this low-permeability reservoir rock from different papers and explain why these reservoirs have low permeability and what are the factors controlling permeability (e.g. diagenesis, burial/compaction, sorting) in each case?Carbonate rocks produce about 40% of all gas and oil and comprise several of the reservoirs in Western Canada and the huge reservoirs in the Middle East (Burnside and Naylor 2014, pp.2). Even though there are numerous types of carbonate reservoir, most fall with the following groups; Grains stones with enhanced primary porosity, reefs, and carbonates slope deposits, and chalks. The two principal properties needed from a rock to be viable reservoir are permeability and porosity (Glover 2010, pp. 247). Permeability is the rock capability to transmit a fluid and it depends importantly on the link between the pores. Darcys law institutes the basic connection between flow rate, pressure and permeability (Buiting and Clerke 2013, pp.267). One of the important aspects of carbonate deposition is that of material being biogenic. Reservoirs are deposited on shales, and quite often on waters that do not have high mud supplies (Cuthbertson, Ibikunle, McCarter and Starrs 2016, pp. 868). As a consequence, carbonate reservoirs have general low clay contents than sandstones. Figure 1 below shows the patterns of the elements in a carbonate reservoir. Figure 1: The patterns of the elements in a carbonate reservoir (M.Agar and Geiger, 2014).Intuitively, it is apparent that permeability will rely on absorbency; greater the permeability the higher the porosity (Ordonez-Miranda and Alvarado-Gil 2012, pp. 6736). The permeability also relies on the linkages of the pore spaces. The connectivity of the pores hinges on several elements such as diagenesis, compaction, scope and nature of grains, and grain size dispersal (sorting) (Glover and Walker 2009, pp. 18). Table 1 describes 3 examples of low permeable carbonate reservoirs rocks and the factors affecting them.Table 1: Example of low permeable carbonate reservoirs rocks and the factors affecting their permeability.Low permeable carbonate reservoirs Why they have low permeability Factors affecting their permeabilityChalk- Fine-grained is the nature of the rock, less rigid and undergo more compaction- Have a sheet-like deposit of great lateral content- Although fine-grained, they are stable during diagenesis- Less prone to early exposure to the meteoric water during the period of low sea-level- Early oil migration, overpressure, chalk lithology facies, burial depth, grain size, and mud content- Re-deposited chalk tends to form a thicker mass- Diagenesis, compaction, scope, and nature of grains, and grain size dispersal (sorting)Grain-stones with enhanced primary porosity- Composed of sand-size grains- The linkages of the pore spaces- Form pro-grading sheet or linear bars- Diagenesis, compaction, scope, and nature of grains, and grain size dispersal (sorting)Reefs- They have a vertical permeability- They can connect isolated porous and permeable zones- Form a massive ribbon or sheets- Diagenesis, compaction, scope, and nature of grains, and grain size dispersal (sorting) Choose one of these factors and explain, with reference to other papers, what this process is and how it occurs.Diagenesis is the word utilised for all the modification that sediment experiences after deposition and prior to the metamorphism change. The diverse procedures that come under the word are physical, biological and chemical (Collin, Mancinelli, Chiocchini, Mroueh, Hamdam, and Higazi 2010, pp. 228). They comprise cementation, deformation, compaction, dissolution, replacement, bacterial action, hydration, authigenesis, and recrystallisation and concretion growth (Moeck and Beardsmore 2014, pp. 245). The two significant diagenetic processes are compaction and lithification. Figure 2 shows the diagenetic setting as diagenesis of carbonates occurs in a variety of settings and by analysing the setting, we can interpret the porosity trend of that particular reservoir.Figure 2: The diagenetic setting of a carbonate reservoir (Folk and Kendall, 2013)One of the key influences of the meteoric-water diagenesis is the reordering of calcium carbonate by grains dissolution and the substitution of calcium carbonates as cement in pore spaces. Carbonates which are not lengthily modified during the initial diagenesis are specifically vulnerable to the chemical procedure like grain-to-grain pressure solution and stylolitization in the course of burial causes comparatively high calcium carbonate solubility. Dissolution of metastable stages may frequently be choosy, and initially, aragonite portions of shells may be dissolved while magnesium calcites stay complete. Cementation by calcium cement often happens in the deeper portions of the freshwater aquifers (Goater, Bijeljic and Blunt 2013, pp. 319). Cementation by carbonate is not limited to the fresh-water phreatic zones. It usually happens in pores spaces after sedimentation of atoms. This style of cementation is the route through which reefs are made firm as rocks. The procedure of replacement is termed as neomorphism which comprises the diagenetic methods in which the mature minerals, whether biogenic or abiotic in the source, are used and in their place concurrently occupied by novel crystals of the similar polymorph or mineral.Describe the mechanisms of migration in low permeability reservoirs.Initially, mature hydrocarbon has to migrate out of the source rock. At the time of burial, the rock becomes compressed and its interstitial liquid becomes over-pressured with respect to nearby rocks that have an extreme permeability, and from which fluid can move with larger comfort upwards. Hence, a fluid pressure gradient progress between the source and the surrounding, more porous rocks cause the water, fluid and hydrocarbons to move along the pressure gradient, normally upwards, although a down migration is probable (Dernaika, Kalam, and Skjaeveland 2014, pp. 10). This process is what is termed as primary migration and it takes place across the stratification.Therefore, migration is the movement of gas and oil within the sub-surface. Primary migration is the initial phase of the migration process which involves the hydrocarbon expulsion from their low-permeable, fine-grained source rock into a carried bed having much greater permeability. Secondary migration comprises movement of gas and oil within the carrier bed. Currently, only three primary mechanisms are given a serious consideration by most geologists: oil-phase expulsion, diffusion, and solution in the gas (Peel 2014, pp. 225).The importance of diffusion is limited to the thin source beds or edge of thick units. Similarly, it is most effective in immature rocks, where pre-existing light hydrocarbon pinch-out of the rocks before the onset of considerable generation and expulsion. The key problem with the diffusion mechanism is a dispersive force, whereas the hydrocarbon accumulation needs concentration. Therefore, diffusion mechanism has to be coupled with a powerful concentrating force to yield accumulation of considerable size (Han, Lee, Lu and McPherson 2010, pp. 7).Most popular mechanism today is the expulsion of hydrocarbon in a hydrophobic oily phase. There are three ways in which oil-phase expulsion can happen. One is a result of micro-fracturing induced by over pressuring during hydrocarbon generation (Osborn, Vengosh, Warner and Jackson 2011 pp. 8173). The second way is from very organic-rich rocks before the onset of strong hydrocarbon generation (Eppelbaum 2017). Finally, oil-phase expulsion can take place when bitumen forms a steady web that substitutes water as a wetting agent in the source rock.The final primary mechanism is the migration by molecular solution in water. While the aromatics are the most soluble in aqueous solutions, they are rare in oil accumulation, thus, discrediting the importance of this mechanism though it may be locally crucial. It can be termed that under compaction is important for primary migration. It will assist preserve the source rock permeability to a greater extent than in equilibrium state, while reaching temperature appropriate for considerable hydrocarbon generation.The process where hydrocarbons move along permeable and porous layers to its final accumulation is referred to as secondary migration. The mechanism is completely governed by the buoyancy forces and much less controversial than primary migration. The buoyancy forces are proportional to the differences in density between water and hydrocarbon. The key conduits for secondary migration are permeable sandstones beds and unconformities (Velaj 2015, pp. 125).Question 2 Option AWith reference to at least two papers, explain under what conditions salt diapirs make good hydrocarbon traps. Hydrocarbon traps from where the permeable and porous reservoir rocks such as sandstones and carbonates are surrounded by the rocks with little permeability that have the ability to avert the hydrocarbon from more upwards movement (Rashid, Glover, Lorinczi, Collier, and Lawrence 2015, pp. 150). Thus, a trap has the function of allowing entry to hydrocarbon and to obstruct their escape. Typically, low permeable rocks are compacted evaporates, shales and tightly cemented carbonates and sandstone rocks (Han et al. 2018). If the upwards loss of hydrocarbon is less than the provision of hydrocarbon from the cradle rocks to the reservoir, the hydrocarbons may still accrue and create a trap (Roberts and Bally2012, pp.43).Traps are normally categorised according to the mechanism that processes the hydrocarbon build up. The two chief classes of traps are those that are created by (structural traps) structural distortion of rocks, and those that are connected to diagenetic and depositional sorts in the stratigraphic traps (sedimentary sequence). Several reap result from both combination of above factors. For instance; stratigraphic pinch-out that is combined with tectonic tilting. Other traps result primarily from fracturing to hydrodynamic processes (Al?Qayim 2010, pp. 390).Salt domes build when salt is less dense than the superimposing rock, and the salt travels gradually upwards owing to its buoyancy. Thus, for the above to occur, there ought to be the slightest burden and the salt deposit width must be more than or 100m. The upward drive of salt through the sedimentary strata and linked distortion is signified as salt tectonics or halo kinetics (Archer, Alsop, Hartley, Grant and Hodgkinson 2012, pp. 2). It is worth noting that the movement may proceed for many hundred million years. Figure 3 shows the seismic image of a salt diapirs on the Brazil Margin and Gulf of Lions, France.Figure 3 shows the seismic image of a salt diapirs on the Brazil Margin (top) and Gulf of Lions, France (bottom) (Mervine, 2011).Salt configurations or diapirs are a type of geological distortion build up from the travel of mudstone, salt rock and other rock whose masses are lower than superimposing rock under the regulation of buoyancy/ gravity and regional strain. Structural combination and growth fault patterns generated from salt rocks and structures are important aspects in governing the type and distribution of post-salt turbidities. The salt move led to various salt deformations which have an influence on sedimentary sand dispersal which forms diverse structural and lithologic-stratigraphic traps (Bowman 2011, pp. 97). It is worth noting that compressional and extension ones are favourable for the hydrocarbon accumulation. As a result of salt piercement, covering strata are likely to create vault traps. Thus, salt piercement assists oil and gas under the salt rock to travel up to reservoir rocks along the fissures, ensuing hydrocarbon build up in large measure. Salt diapirs are simple to build unconformity assemblies which offer space for hydrocarbon accumulation. When the diapir is further established, it will fall and change into a coarse flexible deposit, which is valuable reservoir rock. In case there is a compact cap rock above, it would be a perfect trap.Salt edifices are favourable for the creation of sub-basin which are dispersed in extensional and compressional parts and are satisfactory for sandstone sedimentation (Eppelbaum, Katz and Ben-Avraham 2012, pp. 5). Salt flow forms several arrangements, lithological-stratigraphy traps, and multifaceted traps and also gives numerous intricate fault schemes which offer excellent ways for vertical short space hydrocarbon migration (Mousavi, Prodanovic and Jacobi 2012, pp. 244). The salt structure is very solid and soluble in acid, high visco-plasticity, and perfect heat conductivity. Similarly, it enables the oil window to extend down, so the basis rock is not low-mature or over matures. As a result of salt rock having heat conductivity, the pre-salt strata temperature is lesser than that of strata rock with no salt rock. Thus, the lower temperature prohibits the diagenesis of the pre-salt reservoir rock. An important aspect of salt structure exploration is that the strata at depth over 6000m, they have favourable permeability and porosity (Dernaika, Kalam and Skjaeveland 2014, pp. 9).As earlier mentioned, the salt structure is unlikely to grow impulsively from a horizontal sheet of evaporates due to buoyancy only (Dernaika 2015). Phases of salt diapirs are described as active, passive and reactive. Reactive diapirs happen in reaction to brittle overburden extension. The action can function irrespective of original overburden strength and thickness. The extension forms space directly above the salt layer, which permits the salt to emplace into superimposing regular fault grabens. The move from active happens when reactive diaper has gained a suitable perpendicular scope and the overload has been weakened by extension (Gu et al. 2017, pp. 100). The progression to the passive diapirs happens when the salt diaper has encroached and strapped aside the burden to the stage of salt emergence. Salt edifices augmented by shortening have distinctive features such as episodic progress, permitting dense arrays of strata to be dropped above the diapirs in between the advancement interval (Tang et al. 2017, pp. 1437). Additionally, they are characteristic by the pinched off or narrow channels from the salt layer and strata which are a little bit distorted, as the bend is taken up within the salt stratum.References:Al?Qayim, B., 2010. SEQUENCE STRATIGRAPHY AND RESERVOIR CHARACTERISTICS OF THE TURONIAN?CONIACIAN KHASIB FORMATION IN CENTRAL IRAQ. Journal of Petroleum Geology, 33(4), pp.387-403.Wiley, Retrieved from: https://doi.org/10.1111/j.1747-5457.2010.00486.x, [Accessed on 5 October 2018].Archer, S.G., Alsop, G.I., Hartley, A.J., Grant, N.T. and Hodgkinson, R., 2012. Salt tectonics, sediments and prospectivity: an introduction. 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