An integrated analysis of mineralogical and microstructural characteristics and petrophysical properties of carbonate rocks in the lower Indus Basin, Pakistan

3.1 Petrography

Petrographic studies of the selected samples were performed at the Geological survey of Pakistan, Karachi office. Leica optical microscope was used to identify minerals and fossils. Thin sections were prepared about to 0.03 mm thickness and were carefully studied under polarized microscopes.

3.2 Scanning Electron Microscopy (SEM) for Microstructural Analysis

The microstructure and diagenetic features of samples were examined using Scanning electron microscope (SEM). A JEOL-Japan Compact SEM at centralized sciences laboratory of University of Karachi, was used to observe microstructure and mineralogy of the samples. Polished thin sections were prepared for analysis and carbon coated and then these were examined using a JEOL, Tokyo, Japan Compact field-emission- SEM equipped with a link system Energy Dispersive X-ray microanalyzer (EDS). The purpose of SEM was to confirm the mineralogy obtained from XRD and to determine the diagenetic features of each sample that affect the reservoir quality and petrophysical properties of carbonate rocks. The main diagenetic processes that are responsible for altering the pore structure and carbonate reservoir rock properties were examined.

3.3 X-ray Diffraction (XRD)

Analysis for mineral composition of 1 cm³ representative samples was undertaken from collected outcrop blocks. XRD experiments for rock mineral analysis were conducted by preparing powder of less than 20 μm. XRD data was obtained using the spray dry technique using the X-ray Diffractometer PANalytical X’Pert Pro powder. The sample was powdered with 20 wt.% silicon, which acted as a standard. The powder of prepared samples was then sprayed in the furnace leading to formation of approximately 20 μm random sized grains with random orientations. These samples were then loaded into sample chamber and analyzed using diffractometer. The system prior to experiments and XRD results interpretations was calibrated using standard procedures. The minerals concentrations of samples obtained through diffraction patterns considering the intensity ratio of reference mineral and orientation.

3.4 Porosity

The plugs porosity was determined using the helium expansion porosimeter. The porosity was calculated using Boyle’s law porosity and determined as the difference of the core plug bulk volume which was measured with a caliper, and grain volume was measured adopted the Boyle’s law method. The principle involves the compression of gas into pores of rock samples. The experimental setup consists of two chambers. Initially, the helium gas was introduced into the two chambers and the valve between chambers kept open. Same time was allowed for pressure stabilization. This was followed by placing the core sample inside one of the chamber at pressure p₁, and was separated from the second chamber at pressure p₂. After few minutes of pressure stabilization, the valve between chambers is opened and wait until the pressure equilibrate and to reach a final pressure pf . The core sample pore volume was occupied by the helium gas used; hence the difference between the two test conditions would be the measure of the grain volume of the core.

3.5 Steady State Permeability Experiments with Tri-Axial Loading

Klinkenberg corrected steady-state gas permeability experiments were performed using an innovative permeability measuring experimental setup as shown in Figure 4. The system was calibrated prior to permeability measurement and tested for leaks. This system measures the permeability of samples of different sizes ranging from 2.5 cm and is capable of applying tri-axial loading through hydraulic pump. This setup is connected with gas cylinder to apply constant gas pressure and to record the stabilized gas rate at the outlet in order to measure the steady state permeability. The permeability measurements were made under different confining stress conditions. The experiments of the current study were performed applying different confining stress starting from 500 psi to maximum of 2500 psi with 500 psi incremental pressure.

Figure 4

Schematic is the experimental setup for steady state permeability measurement under confining stress conditions, the P1 and P2 are the upstream and downstream pressures respectively.

Mathematically, the gas permeability of the core samples was determined by adopting steady state procedure that can be described as follows;

where the flow rate is represented as Q that is related to the permeability kg, core plug cross-sectional area is represented as A, gas viscosity is μ, pressure across the length of core is P₁, which is upstream pressure and P₂ is the downstream pressure and length of the core samples is represented as L.

Further, the gas permeability measured was corrected for the gas slippage effects [31]. The phenomenon of gas slippage is described as when gas is allowed to flow through the very tiny pore capillaries with pore diameter similar to the mean free path of the gas molecules. The striking of gas molecules to the pore walls increases the flow rate of gas, which results in ultimate increase in gas permeability [32, 33]. Such increase in permeability resulting from molecules and pore walls interactions is most of ten known as Klinkenberg’s slippage effect (Figure 5) [31].

Figure 5

Illustration is an example of the Klinkenberg corrected permeability of sample using two different gases and different mean pressures [Modified after 34].

4.1 Petrography

Analysis of the carbonate samples from fossil assemblage and texture under petrographic microscope showed that these samples were deposited near fore-slope depositional environment according to [35] classification of carbonate rocks. The dolostone may be due to the increase of manganese content in sea water that would probably due to regression reducing the water depth. Thin section photomicrograph in Figure 6 displays the various petrographical descriptions and features of Jakkher Group carbonate rocks. Petrographic and SEM examination of the lower Indus Basin Jakkher Group rocks showed both primary and secondary porosity that was evident from micro-cracks and fractures. SEM observation showed that most of samples were exhibiting intergranular porosity along with associated micro pores exhibiting dense rock pore structure tending to very tight carbonate rocks. Further, it was noticed that some diagenetic processes have altered the rock porosity by precipitation and secondary filling of micrite muds within pore spaces resulting into the pore throats size reduction. Most of samples were very low in porosity and permeability due to the diagenetic alterations. These Jakkher Group carbonate rock features observed from thin section analysis and petrographical point of view are shown in Table 2 and Figure 6.

Figure 6

Thin section photomicrograph displays the petrographical description of carbonate rocks showing: [Plate A] point 1 displays the Nummulite and point 2 is Dolomite Rhomb. [Plate B] displays Discocyclina at point 1 and point 2 is the Peloidal Micrite. [Plate C] shows at point 1 are the Mg-Rich Dolomite crystal and at 2 is the Fe-Rich Dolomite crystal. [Plate D] the image shows the micro crack, fracture filled with carbonaceous material; and the point 2 displays the Calcisphere. [Plate E] observations are as 1, 2, 3, Quartz Crystals; 4, Micrite and point 5 is the Fe-Rich Dolomite Crystal. [Plate F] inside the image points 1, 2, 3, are the dolomite crystals surrounded by washed Nummulite walls. [Plate G] image displays the fractured Nummulite at the center surrounded by fine micrite mud. [Plate H] shows the Quartz crystal with calcite cement surrounded by coarse micrite mud. The scale bar = 20μm.

4.2 Mineralogy

Thin section study, SEM-EDS, and XRD studies have shown that the minerals in the Jakkher Group carbonates include the, calcite, dolomite and intermixes of clay and cementing materials as dominant mineral components [Figure 7 and Figure 8]. In addition, the aluminum (Al), silicon (Si), irons (Fe), and intermixes of clay and cementing materials were also noticed [Table 3]. These observed minerals establish the carbonate rock framework grains along with the minor amounts of clay and intermixes of cementing materials. The detailed descriptions and characteristics of some selected carbonate samples are provided in Table 3. An XRD study carried out confirmed that rocks mainly composed of the CaCO₃ limestone rock as shown in Figure 7.

Figure 7

Illustration is the XRD results from two of the Jakkher Group carbonate samples.

Figure 8

The microstructure and mineral compositions identified via EDS patterns and from SEM results are shown in Figure. The mineral contents in SEM photomicrograph of Jakkher carbonates; (18-JK-01) yellow arrows show calcite and red arrows show clay (chlorite). (18-JK-05) yellow arrow shows clay content and red arrow shows calcite; (18-JK-11) yellow arrows show coarse grained calcite and red arrow shows micritic calcite. (18-JK-13) all arrows show sparry calcite; (18-JK-04) all arrows show calcite, yellow shows the cleavage face of calcite grain; (18-JK-13) the arrow shows sparry calcite. In Figure the EDS patterns shows the dominating elements are Ca, C, and Mg.

The quality of the carbonate reservoirs essentially depends on the mineral constituents, rock texture, depositional settings, and diagenetic modification of porosity and permeability [36]. Porosity and permeability are two main petrophysical properties that are partly controlled by the textural characteristics of grain arrangement, size of the grains, shape and grain packing [36]. The grain textural properties are also influenced by the rock deposition that eventually is influenced by lithified actions, such as aging, mineral cementation, mineral compositional changes [37]. The presence of different minerals affects the reservoir quality in different ways in subsurface [38]. Some mineral components and their contents have great influence on the pore microstructure and have impact on fluid flow properties in the subsurface reservoirs. The reservoir rock permeability, porosity and sealing capacity could also be affected by the mineral compositions [37, 39]. Mineralogy has significant role in sediment diagenesis and controlling the fluid flow through rocks. The fluids that flow across the sedimentary environments brings different changes by cementations, dissolutions, particle movements, and authigenesis of minerals [38].

The samples showed that the dominant minerals are calcite and minor dolomite accompanied by some other accessory minerals. The dominating elements observed from SEM-EDS patterns are Ca, C, and Mg, showing the carbonate rock assemblage [Figure 8]. The Al was found in some of the studied samples, which indicates that the minor intermixed clay minerals are associated with samples. The Si observed from EDS patterns showed the siliciclastic influx within the carbonate rock samples. The SEM photographs revealed the main diagenetic features of the carbonate rocks. Carbonate rock fragments and associated mud are highly bio-mineralized yields of the existing marine organisms. Diagenesis can result into complex petrophysical properties of carbonate sediments and has strong influence on porosity and permeability impacting on the quality of carbonates reservoirs [20]. Thin sections petrographic analysis and scanning electron microscopy interpretations emancipated that the closer grain contacts, indicating a low diagenetic evolution. Despite the fact, the original sedimentary features such as well-sorted, very fine grained sediments along with their diversified intermixed sediments set out these reservoirs very tight exhibiting low permeability and low porosity reservoirs. It also showed very fine mixed terrigenous sediments with carbonates. Fine terrigenous components mixed with micrite cement, and also the grain coatings of illite-smectite on carbonate crystals. The Si element observed from SEM-EDS graphs shows the siliciclastic influx within the carbonate rock along with some ferrous materials. SEM studies shown that accordion-shaped calcite fragments were also noticed in sample 18-JK-01 in some places (Figure 8). The SEM-EDS analysis of sample 18-JK-01 shows the occurrence of kaolinite clay in form of booklets crystal flakes. Furthermore, the kaolinite clay has tendency to appear as an extra mineral that has tendency to reduce the permeability and porosity of carbonate reservoir rocks.

4.3 Porosity and Permeability

The basic properties of the samples of Jakkher Group are presented in Table 4. Few samples from Jakkher Group were sandy to argillaceous carbonates and most of them were exhibiting high volume of pure calcite and were characterized by a relatively low grain density of 2.70 g/cm³. The grain density for the samples exhibiting calcite minerals is of 2.81 g/cm³ on average. Furthermore, the grain boundary fractures could be observed within these carbonates from images of thin sections resulting into different porosity types. These samples were noticed that they developed two types of porosities (i) the porosities developed under the existence of microfractures and were ranged from 2.55 to 12.82%, with an average value of 3.86%, (ii) the porosities which developed in absence of micro-cracks and were ranging from 2.12 to 8.5% with an average value of 4.5%. Similarly, we observed a big variation in permeability values, the permeability measured were ranging from 0.013 to 5.8 mD for those samples without microcracks. The samples with obvious microfractures were exhibiting high permeability values and were discarded

from the analysis. Though, the samples with open microfractures permeability were determined as higher values ranging from 12.5 to 25 mDwith an average value of 15.5mD. Moreover, the porosity and permeability results obtained shows relatively linear trend line when plotted on a semilogarithmic graph, and the fitted correlation between values shows the power law relationship (Figure 9). However, the permeability and porosity data plotted did not appear in the linear relationship due to rock heterogeneity. The diagram of permeability-porosity scatter shows that the carbonate rocks studied encompass different pore size and pore-throat geometries.

Figure 9

The illustration of the relationship between Klinkenberg corrected permeability (nitrogen) and porosity (Helium).

From few thin sections analysis of Figure 6 Plate D displays the micro fractures resulting into high permeability values. The permeability and porosity data cross plotted showed few outliers in the Figure 9 that was due to micro cracks as observed rom thin section analysis. Furthermore, it is highly recommended that the impact of grain boundary fractures could be analyzed within these carbonates by preparing the polished surface thin sections. The permeability measured exceeding 20 mD is not included in the plot of permeability-porosity because this was resulting in big scatter on chart. The reason of such high permeability in the samples was the existence of obvious microfractures and micro-cracks as observed from one of the thin sections. These naturally fractured reservoirs would exhibit high permeability values and are expected to produce at commercial rates without application of fracturing the reservoirs for increasing permeability.

4.4 Klinkenberg Corrected Permeability and Slippage Parameters

There are many studies that have described the gas slippage effects particularly within tight gas sandstones and several models have been developed [40]. However, it is extremely important to analyze the gas slippage phenomena associated to tight carbonate rocks for permeability prediction and accurate assessments. In public domain, there are numerous correlations that narrate the gas slip factor and permeability relation describing the sandstone rocks relationship [31, 32, 33, 41, 42, 43, 44, 45, 46]. The values of some slippage parameters along with gas permeability obtained under varying overburden stress conditions. The relationship concerning to the permeability coefficients k_g of the samples 18-JK-01 and 18-JK-03 using nitrogen gas as pore fluid as a function of reciprocal of average pore pressure under varying pore pressure conditions is presented in Figure 10. The relationship between gas permeability and gas slip factor developed and found that there was scatter in permeability and slippage factor data (Figure 11). Such scatter in slippage parameters and permeability could be the results of carbonate rock heterogeneity and non-uniqueness of the pore size within studied samples. Hence, it is obvious that the permeability result would not be estimated from existing empirical correlations accurately due to carbonate rocks exhibits large heterogeneity and varying pore morphology. Additionally, in literature various researchers has attempted to provide with improved slippage estimation relation by inclusion of other parameters such as in model of Sampath and Keighin [42] porosity is included this might work well for sandstone rocks. Since carbonates are highly heterogeneous rocks having fractures and secondary porosity, these empirical relations might not fit well. It is highly recommended where necessary to measure these petrophysical properties in the laboratory to appropriately analyze the reservoir behavior and to predict the future performance.

Figure 10

Illustration shows the Klinberg corrected gas permeability of trhe carbonate samples.

Figure 11

Illustration shows the relationship between carbonate rock permeability and gas slippage factor.

4.5 Effect Of Overburden Stress

The permeability reduction due to overburden stress could significantly affect the overall output of the ultra-tight permeability reservoirs [29, 47, 48]. There have been few papers that have addressed stress sensitivity in impact on oil and gas reservoirs in Pakistan; this requires more researches attention in order to develop stress sensitivity low permeability reservoirs. Studies [29, 47, 49] have shown that the tight, low permeability reservoirs are more sensitive to the overburden stress than conventional reservoirs. The elements responsible for decreasing the permeability due to applied stress are the pore size and pore throat. However, the samples recovered from subsurface may results in formation of the micro-cracks. If confining stress is applied in laboratory, the micro-fractured samples will results in more reduction at higher overburden stress [47, 49]. From experimental observations, the absolute gas permeability has shown reduction for both samples of carbonate with increase in net stress (Figure 12). The net stress is characterized as following equation

Figure 12

The plot shows the permeability stress sensitivity of carbonate rocks.

where n _k = 1. Proposing a new conceptual model to describe the combined effect of stress, pore pressure, and slippage factor, we are capable of simulating the stress effect and slippage parameters effects. The experiments were performed to explore the implications of model for permeability stress sensitivity of carbonate samples coupling with other variables. This model shows the permeability decline in particular to ultra-low permeability carbonate rocks with increasing overburden stress. The model is expressed using the following equation,

In above equation, K_a represents the apparent permeability of the rock formations extrapolated to zero net stress, the stress sensitivity exponent is represented as γ and P_m represents the mean pressure and b is the gas slippage factor and is the slippage corrected permeability.

It was observed that the permeability increases when the pore pressure was decreased even at in- situ stress, such increase in permeability was the results of gas slippage [29, 50, 51]. However, we realized that the absolute permeability of carbonate samples decreased with increase in net stress. Hence, it is clear that net effect is the reduced permeability with increase in net stress at lower ranges of stress. It was because the gas slippage effects were low due to the high pore pressure. At higher net stresses and low confining stresses, the increased flow due to slippage balances the reduction of slip corrected permeability leading to increased values of permeabilities. Stress sensitivity of permeability to low permeability tight sandstone reservoirs is well documented [48, 49], however; the permeability measurement at in-situ stress is very challenging. In present study on carbonate samples permeability (Figure 12), we found that there was greater extent of permeability reduction at lower overburden stress which is due to the microfractures existence as microcrack was observed in one of the sample. Micro-cracks could have formed along the grain boundaries of the samples that resulted in increased in permeability at lower confining stress. Other authors [47] also reported that the effect of confining stress on samples permeability is controlled by presence of micro cracks. The main explanation of changes in gas permeability will be the result of changes in effective stresses, pore pressures and are essential for assessing their impact on reservoir quality by considering their relationship between gas permeability, stresses and gas slippage.

4.6 Controls On Fluid Flow Properties

The main reservoir rock parameters of fluid flow are the permeability which is controlled by its pore size and by pore-throat [52, 53]. In order to assess the impact of the processes that control the fluid flow in carbonate reservoirs and the associated features that are responsible in changing the pore sizes are essential to explain. Several publications have addressed the fluid flow behavior and its control by pore size changes, changes in rock permeability and pore connectivity [52]. The pore structure of carbonate rocks is diversified due to the heterogeneity of the rock textures. None of the samples have displayed macro sized pores as observed from thin section analysis with one exception which tended to micro-crack. The micro and nanopores are common in carbonate with some exceptions of nano and meso-pores [54].

An attempt was made to find the correlation between the rock-clay mineralogy impacts on permeability. The permeability data did not appear a relation with clay mineralogy and the correlation was very poor. This could be the results of rock heterogeneity as reported by other authors [7]. In addition, the permeability relationship of each sample with clay mineral show a clear scatter in correlation between measured permeability and the observed minerals (Figure 13). This shows that the mineralogy does not play any role in controlling the permeability and fluid flow within these rock types. However, the pore size and pore connectivity have significant impact on controlling the fluid flow behavior within these rocks [1].

Figure 13

Illustration shows permeability relation to clay volume.

4.7 Implication for Reservoir Quality

In order to determine the quality of reservoir rock, it is essential to have information about the reservoir petrophysical properties which is largely affected by the diagenetic processes. The main petrophysical properties such as porosity and permeability are mainly be affected by diagenetic processes [38]. Diagenetic changes may either increase or decrease aforementioned petrophysical properties of any reservoir. The most important diagenetic changes observed within Jakkher Group carbonate were the micrite mud cementation; compactions as well as uplifting and fracture nummulites at the centre were surrounded by fine micrite mud. More specifically, the cementation observed was the calcite, clays, and intermix of clays into pores associated iron oxides. These all acted to decrease the permeability and porosity of studied carbonate rock samples. Further, at few places, the samples were exhibiting primary porosities that were mainly due to intergranular, micro pores and nano size pore throats resulting into densely compacted tight rock. This is evident from samples porosity and permeability values which were very low and revealed that these carbonates are tight if developed will produce at very low flow rates until unless hydraulically fractured. Moreover, the clay mineralogy found to have very scattered distribution as observed from the Figure 13.

Due to overburden stresses and compactions, the grain boundaries of rocks get closer to each other making these rocks less permeable and are thought to be poor quality reservoirs [29, 50, 51, 55]. The stress sensitivity experiments on these carbonate rocks conducted showed significant decrease in permeability. These results have implications that if rocks are deeply buried and burial depth further progresses, these results into reduction in primary porosity due to overburden stresses and rock compaction. In samples studied in the study, there was also cement that has acted to decrease the additional compaction. In some sample, intermix of clay and micrite played a significant role in decreasing the permeability and porosity. More specifically, the pores and pore throats of tightly packed carbonates are very small and have resulted to act these reservoirs of poor quality.