Petrophysical properties of fault rock-Implications for petroleum production

Faults can have significant impact on reservoir productivity. Understanding the factors that controls the fluid flow properties of fault rocks provides a sound basis to assess the impact of faults on reservoirs productivity. Therefore, different aspects that affect the fluid flow within siliciclastic fault formations were investigated in this research project. Fault rock samples from a number of locations were analysed including: (i) core samples from central and southern North Sea fields; (ii) and outcrop samples from the 90 Fathom fault, Northumberland, UK and Miri airport road exposure, Malaysia as well as the Hopeman fault from Invernesshire, UK. The impact of faults on fluid flow was assessed by integrating the data from QXRD analysis, microstructural examination, X-ray tomography, mercury porosimetry for pore size distribution, absolute and relative permeability measurements as well as capillary pressure tests. Single phase and multiphase flow properties which were conducted at a range of stresses are the most comprehensive collection of high quality fault rock data. The permeability measurements made using gas gave higher values than with brine, which in turn gave higher values that when measured using distilled water permeability. The differences in permeability could be the results of clay particles swelling; mobilisation and retaining within the confined pore throats, although these effects depend on the rock mineralogy and pore fluid composition. Moreover, the permeability stress sensitivity was investigated. The results showed that at low confining stresses the permeability of the fault rock core samples showed high sensitivity to stress, whereas at higher confining stresses the permeability was less pronounced to stress. This might be due to the core damage effects and the microfractures formed due to stress release, which were observed from SEM images. The pore radius calculated from gas slippage parameters at low confining pressures was in the same order of magnitude as the micro fracture width. The micro cracks could be easily closed due to stress increase hence resulted in reduction of permeability. Overall, the stress sensitivity of fault rocks from outcrop is less than that from core. This is consistent with the idea that stress sensitivity is mainly the result of the presence of grain boundary microfractures formed as core is brought to the surface. This indicates that permeability measurements made on outcrop samples may be more reliable. Another key finding was that the published permeability data (e.g. Fisher and Knipe, 2001) compared with present study data which is obtained at in-situ stress using formation compatible brines showed that the published data may not be inaccurate as the use of distilled water gives lower permeability than brines and low stresses resulted in higher permeability than in-situ stress measurements. Therefore, the results indicate that two different laboratory practices used in previous studies partially cancel each other out so that the existing data is yet valuable. The effective gas permeability were also measured at a range of stresses and it was observed that the samples with lower absolute permeabilities were more stress sensitive to stress than high permeable samples. The relative permeability results obtained were incorporated into a specific example of synthetic reservoir model. These suggested that faults formed within low permeability sands might act as a barrier to fluid flow

Shale wettability characteristics via air/brines and air/oil contact angles and influence of controlling factors: A case study of Lower Indus Basin, Pakistan

Wettability is the fundamental parameter that influences the productivity of hydrocarbon reservoirs. The knowledge of this regarding shale formation is yet inadequate; thus, detailed analysis is essential for successful development of such reservoirs. The Early Cretaceous Sembar formations in the Lower Indus Basin, Pakistan, is considered as the key target for energy exploration; however, it exhibits large uncertainties due to the lack of data availability. Sembar shales hold significant hydrocarbon volumes rich in organic content; however, prior to this, no comprehensive research has been conducted to quantify the wetting behavior of these shales. Thus, precise information about the wetting behavior of Sembar shale formations is essential, as it is influenced by many factors. Therefore, in this study, we examined the wettability of Sembar shale samples by performing a suit of contact angle (CA) measurements. The CA measurements on shale samples were performed using different salt types (NaCl, KCl, MgCl2, and Reef Salt) and concentrations of 0.1 M and 0.5 M under ambient pressures and varying temperatures (25 - 50 °C). The CA was measured via air-brine and air-oil under prevailing pressure and temperature conditions. Subsequently, the sample morphology and surface topography were examined via field emission scanning electron microscopy and atomic force microscopy, respectively. The mineral compositions were obtained via X-ray diffraction studies. The results clearly show that the Sembar shale possesses a mixed wetting behavior. Under dry surfaces, they have large affinity to oil and deionized water in which the droplet spreads quickly on the sample surfaces. Conversely, the samples aged with n-decane and NaCl brines exhibited higher CAs than the untreated samples. Additionally, the CA measured by changing temperatures led to an increase for all brine droplets; the CA further increased as the concentrations of salts increased from 0.1 to 0.5 M. We then discussed the possible reasons for the discrepancy in CA values due to temperature changes and brine concentrations. Moreover, the CA was measured corresponding to the surface roughness from which it appears that it merely affects the wettability of these shale samples. However, the present study results lead to an improved understanding of the wettability of Sembar shale of the Lower Indus Basin in Pakistan

Influence of diagenetic features on petrophysical properties of fine-grained rocks of Oligocene strata in the Lower Indus Basin, Pakistan

Nari Formation is considered as one of the most important oil and gas exploration targets. These fine-grained tight sandstone reservoirs face enormous challenges due to their extremely low matrix porosity and permeability. Hence, in this regard, the study was carried out to collect the high-quality data on petrophysical properties along with mineralogy and microstructural characteristics and diagenesis. The experiments performed includes the petrographic study and scanning electron microscopy, and X-ray diffraction analyses. Besides, the measurement of petrophysical properties was carried out to assess the likely influence of the reservoir quality. The petrographic analysis shows predominantly fine- to medium-grained grey samples along with calcite, clay, lithic fragments and iron oxides. Further, the thin-section observations revealed that the quartz is a principal mineral component in all the analysed samples ranging from 52.2 to 92.9%. The bulk volume of clay minerals that range from 5.3 to 16.1% of. The porosity and permeability measured range from 5.08 to 18.56% (average 7.22%) and from 0.0152 to 377 mD (average 0.25 mD), respectively. The main diagenetic processes that affected the sandstones of Nari Formation are mechanical compaction, grain deformation, cementation and quartz dissolution and have played a significant role in influencing the quality of the reservoir rock. Overall, it appears that the primary petrophysical properties (porosity and permeability) were decreased due to the mechanical compaction, lithification, cementation, and framework grain dissolution. Based on the integrated mineralogical, microstructural analysis, and the laboratory-based petrophysical properties, the samples exhibited poor porosity, permeability, and moderate clay content, which indicate that the Nari Formation is a poor quality reservoir

Experimental evaluation of liquid nitrogen fracturing on the development of tight gas carbonate rocks in the Lower Indus Basin, Pakistan

Tight gas carbonate formations have enormous potential to meet the supply and demand of the ever-growing population. However, it is impossible to produce from these formations due to the reduced permeability and lower marginal porosity. Several methods have been used to extract unconventional tight gas from these reservoirs, including hydraulic fracturing and acidizing. However, field studies have demonstrated that these methods have environmental flaws and technical problems. Liquid nitrogen (LN2) fracturing is an effective stimulation technique that provides sudden thermal stress in the rock matrix, creating vivid fractures and improving the petro-physical potential. In this study, we acquired tight gas carbonate samples and thin sections of rock from the Laki limestone formation in the Lower Indus Basin, Pakistan, to experimentally quantify the effects of LN2 fracturing. Initially, these samples were characterized based on mineralogical (X-ray diffraction), petrography, and petro-physical (permeability and porosity) properties. Additionally, LK-18-06 Laki limestone rock samples were exposed to LN2 for different time intervals (30, 60, and 90 mins), and various techniques were applied to comprehend the effects of the LN2 before and after treatment, such as atomic force microscopy, scanning electron microscopy, energy-dispersive spectroscopy, nano-indentation, and petro-physical characterization. Our results reveal that the LN2 treatment was very effective and induced vivid fractures of up to 38 µm. The surface roughness increased from 275 to 946 nm, and indentation moduli significantly decreased due to the decreased compressibility of the rock matrix. Petro-physical measurements revealed that the porosity increased by 47% and that the permeability increased by 67% at an optimum LN2 treatment interval of 90 mins. This data can aid in an accurate assessment of LN2 fracturing for the better development of unconventional tight gas reservoirs

Development of Experimental Setup for Measuring Thermal Conductivity Characteristics of Soil

Thermal conductivity displays a key role in design of engineering structures where, thermal stresses resulting from heat and temperatures are of concern. Significant efforts were made to measure the thermal conductivity of different materials. For thermal conductivity characterization of soil samples it is essential to have very flexible set-up. Hence, this paper provides details about indigenously developed experimental setup for thermal conductivity measurement. The design of this newly developed setup is based on the basic principle of steady state heat flow. This experimental setup is designed in order to measure the thermal conductivity of various materials such as soils, rocks, concrete and any type of unbonded and bonded materials. In this paper, initially the theoretical background of the measurement techniques and the principle of heat flow are described, followed by design description and working procedure. The design has been kept very simple, adjustable for varying type and size of specimens and easy to operate with excellent level of accuracy as evident from system calibration. The accuracy and precision of the newly developed setup was verified by testing reference materials of known thermal conductivity and in the test results a high correlation coefficient (R2 = 0.999) between experimental data and fitting curve was achieved

Could shale gas meet energy deficit: its current status and future prospects

Abstract The production of gas from conventional reserves has shown steep decline, whereas the demand of hydrocarbons as energy source is rising. Hence, the resulting deficit of energy can be met by developing the unconventional energy resources. Among all unconventional energy resources, shale gas is relatively the potential source of energy to be developed in a sustainable way. However, the degree of uncertainty is large for sustainable development of shale gas reservoirs. The shale gas found is held in extremely low-permeability formations having poor porosity; the free gas and the adsorbed gas are also found together. Therefore, the production mechanisms of shale gas reservoirs are quiet complex than the conventional gas reservoirs. Hence, the shale gas resources sustainable development remain ambiguous. In order to find sustainable way of exploitation of shale gas resources, this manuscript reviews in detail, the shale gas potential in Pakistan and the world in terms of its distribution, production mechanism, policy implications and development trends

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

Carbonate rocks are believed to be proven hydrocarbon reservoirs and are found in various basins of Pakistan including Lower Indus Basin. The carbonate rock intervals of the Jakkher Group from Paleocene to Oligocene age are distributed in south-western part of Lower Indus Basin of Pakistan. However, there are limited published petrophysical data sets on these carbonate rocks and are essential for field development and risk reduction. To fill this knowledge gap, this study is mainly established to collect the comprehensive high quality data sets on petrophysical properties of carbonate rocks along with their mineralogy and microstructure. Additionally, the study assesses the impact of diagenesis on quality of the unconventional tight carbonate resources. Experimental techniques include Scanning Electronic Microscopy (SEM), Energy-Dispersive X-ray Spectroscopy (EDS), and X-ray diffraction (XRD), photomicrography, Helium porosity and steady state gas permeability. Results revealed that the porosity was in range of 2.12 to 8.5% with an average value of 4.5% and the permeability was ranging from 0.013 to 5.8mD. Thin section study, SEM-EDS, and XRD analyses revealed that the samples mostly contain carbon (C), calcium (Ca), and magnesium (Mg) as dominant elemental components.The main carbonate components observed were calcite, dolomite, micrite, Ferron mud, bioclasts and intermixes of clay minerals and cementing materials. The analysis shows that: 1) the permeability and porosity cross plot, the permeability and slippage factor values cross plots appears to be scattered, which showed weaker correlation that was the reflection of carbonate rock heterogeneity. 2) The permeability and clay mineralogy cross plots have resulted in poor correlation in these carbonate samples. 3) Several diagenetic processes had influenced the quality of carbonates of Jakkher Group, such as pore dissolution, calcification, cementation, and compaction. 4) Reservoir quality was mainly affected by inter-mixing of clay, cementation, presence of micrite muds, grain compactions, and overburden stresses that all lead these carbonate reservoirs to ultra-tight reservoirs and are considered to be of very poor quality. 5) SEM and thin section observations shows incidence of micro-fractures and pore dissolution tended to improve reservoir quality