Shale Interbeds Research Articles

Reservoir Potential Evaluation of the Middle Paleocene Lockhart Limestone of the Kohat Basin, Pakistan: Petrophysical Analyses

The Lockhart Limestone is evaluated for its reservoir potential by utilizing wireline logs of Shakardara-01well from Kohat Basin, Pakistan. The analyses showed 28.03% average volume of shale (Vsh), 25.57% average neutron porosity (NPHI), 3.31% average effective porosity (PHIE), 76% average water saturation (Sw), and 24.10% average hydrocarbon saturation (Sh) of the Lockhart Limestone in Shakardara-01 well. Based on variation in petrophysical character, the reservoir units of the Lockhart Limestone are divided into three zones i.e., zone-1, zone-2 and zone-3. Out of these zones, zone-1 and zone-2 possess a poor reservoir potential for hydrocarbons as reflected by very low effective porosity (1.40 and 2.02% respectively) and hydrocarbon saturation (15 and 5.20%), while zone-3 has a moderate reservoir potential due to its moderate effective porosity (6.50%) and hydrocarbon saturation (52%) respectively. Overall, the average effective porosity of 3.31% and hydrocarbon saturation of 24.10% as well as 28.03% volume of shale indicated poor reservoir potential of the Lockhart Limestone. Lithologically, this formation is dominated by limestone and shale interbeds in the Shakardara-01 well. Cross-plots of the petrophysical parameters versus depth showed that the Lockhart Limestone is a poor to tight reservoir in Shakardara-01 well and can hardly produce hydrocarbons under conventional drilling conditions.

Visualization of dynamic micro-migration of shale oil and investigation of shale oil movability by NMRI combined oil charging/water flooding experiments: A novel approach

Investigating the micro-migration processes of hydrocarbons within interbedded shale reservoirs, and quantitatively characterizing the movability of shale oil, are highly important for the exploration and development of continental shale oil. However, due to complex pore-fracture structures, the characterization of the micro-migration and movability of shale oil presents significant difficulties, and the lack of suitable technology restricts the understanding of shale oil accumulation mechanisms and the evaluation of movability. This study employs nuclear magnetic resonance imaging (NMRI) technology in conjunction with oil charging and water flooding experiments, to innovatively visualize and quantitatively characterize the dynamic micro-migration features and movability of hydrocarbons within the pore-fracture structures of shale. The results indicate a significant increase in oil saturation within the interbedded shale oil reservoir during the oil charging process, with the oil phase primarily accumulating in larger pores (T2 = 1–100 ms). The micro-migration and accumulation process of interbedded shale oil can be divided into three stages: the initial stage dominated by water phases in the pore spaces due to insufficient oil filling pressure, the intermediate stage marked by a rapid increase in hydrocarbons in the pore spaces, and the final stage where oil fills the entire pore system resulting in high oil saturation. The movability of different types of shale oil during water flooding varies significantly and is mainly influenced by pore-fracture structures. Interbedded shale oil reservoirs with larger pores exhibits a higher movable oil saturation (approximately 36.94%), while matrix-type shale oil reservoirs shows greater heterogeneity and lower fluid movability (approximately 14%). However, the shale oil movability of matrix-type shale oil reservoir with developed microfractures can reach 40%. More specifically, the fluid movability in smaller pore-microfracture structures (T2 < 0.5 ms) is as high as 56.88%, surpassing that in larger pores (T2 > 0.5 ms) (32.78%). Larger pores and microfractures substantially enhance the movability of hydrocarbons in the shale matrix, thus improving shale oil recoverability. In contrast, due to the higher capillary pressure (Pc) and flow resistance (Pv), smaller pores contribute less to the movability of shale oil. Overall, the outcomes of this study not only advance our understanding of the micro-migration and accumulation patterns of interbedded shale oil but also offer new insights for geological and engineering integration research on shale oil.

Organic Geochemical Evaluation of the Black Shale interbeds Within the Lithological Succession of the Al Aziziyah Formation, NW Libya

The samples under investigation represent the black shale in interbeds within the Al Aziziyah Formation, located in the NW part of Libya and were analysed using geochemical techniques method and a variety of organic geochemical parameters. The aim of this study is to assess the type of organic matter, thermal maturity, and environment of deposition, based on biomarker distributions and Rock-Eval pyrolysis. The Gas chromatograms of the saturated hydrocarbon fractions of the study samples display a smooth high-end member distribution of the n- n-alkanes extending beyond nC34. The sample displayed evidence of biodegradation as suggested by the presence of the loss of some of the lower molecular weight n-alkanes. The predominance of high molecular weight n-alkane in the study sample suggests a significant input of higher land plant organic matter into these sediments. Geochemical (Rock-Eval, Tmax. values ranging from 416-4390C typical of immature range). Another related feature of these rocks extracted is the presence of a high relative abundance of gammacerane, indicating an anoxic marine hypersaline source depositional environment. The relatively high abundance of common land-plant-derived biomarkers, such as oleananes, is a clear indication of major terrigenous input to the source of these extractable organic matters. The high abundance of C24 tetracyclic terpanes could be associated with higher land-plant, algae, or microbial sources, thereby suggesting a mixed source input. TOC valued &lt; 0.5 wt.%, in the analyzed samples can be considered as a poor source rock generative potential. Based on this study, it can be said that the interbedded shales of the Al Aziziyah Formation seem to have received substantial amounts of land-derived organic matter that has been transported into an open marine subtidal depositional setting had prevailed and was deposited in a photosynthetic-organisms dominated environment (thereby suggesting a mixed source input).

Variability of sedimentary pyrite δ34S records: A case study of slope shale of the Green Point Formation in western Newfoundland, Canada

The Green Point Formation in western Newfoundland, GSSP of the Cambrian-Ordovician (Є-O) boundary, is dominated by slope rhythmites of alternating lime mudstone and shale interbeds. This formation was deposited in a semi-restricted basin with varying connectivity to the open ocean. In the current study, we investigate textures and bulk δ34S signatures of pyrite (δ34Spy) in the shale to better understand factors influencing the sedimentary δ34Spy fluctuation. Petrographic and SEM examinations reveal two major types of pyrite: (1) framboidal pyrite and (2) anhedral to euhedral pyrite. The latter is further categorized into two subtypes: type 2a anhedral to subhedral pyrite characterized by relict framboidal textures and larger sizes (∼10 to 300 μm), and type 2b smaller (typically <10 μm) subhedral to euhedral pyrite. Type 1 pyrite was precipitated near the sediment-water interface (SWI), whereas type 2b pyrite was formed in sediments below the SWI with limited access to the overlying seawater sulfate. Type 2a pyrite was evolved from framboids during early and burial diagenesis. The bulk δ34Spy values, marked by a significant scatter (1σ =10.62‰), range broadly from −17.6 to +22.4‰ (VCDT) and exhibit a pronounced positive excursion of ∼20‰ near the Є-O boundary. The abundance of type 2b pyrite generally mimics the changes in δ34Spy, suggesting that the substantial δ34Spy dispersion could be partially attributed to differing proportions of type 2b pyrite within the samples. Moreover, notable negative correlations exist between the δ34Spy values and the abundances of Al, Th, ∑REE, and Fe, indicating that riverine fluxes might have influenced the Δ34Sseawater – pyrite by modulating the regional seawater sulfate and iron reservoir sizes. Therefore, rather than being indicative of oceanic redox oscillations, the positive δ34Spy excursion of ∼20‰ of this interval was probably driven by decreased sulfate and iron levels in the local waterbody. The decline in terrestrial input during this δ34Spy shift might have also contributed to a negative δ13Ccarb excursion by reducing nutrient supply and inhibiting primary productivity. Collectively, the bulk sedimentary δ34Spy variability recorded by the Green Point shale may be attributed to a combination of changes in regional terrigenous input and varying amounts of pyrite formed at different diagenetic stages within the samples. The general opposing trends between the δ34Spy signals and the abundances of Al, Th, ∑REE, and Fe, however, imply that fluctuations in riverine influxes might exert a stronger influence on the major δ34Spy trend. These findings suggest that bulk sedimentary δ34Spy variations may not be reliable evidence for perturbations of the global sulfur cycle.

Determining the drilling mud window by integration of geostatistics, intelligent, and conditional programming models in an oilfield of SW Iran

Accurate knowledge of pore and fracture pressures is essential for drilling wells safely with the desired mud weight (MW). Overpressure occurs when the pore pressure is higher than the normal hydrostatic pressure. There is a challenge regarding the pressure studies domain in an oilfield in SW Iran, where lack of geo-mechanical data limits exact mud window calculation. Also, the reservoir generally consists of carbonate rocks and contains no shale interbeds, so mechanical stratigraphy based on Gamma ray could not be applied. This study is to provide safe drilling considering MW to prevent the flow or loss in the vicinity of the new wells in the studied field. In this research, the formation pressures and mud window models are determined by combining geostatistical, intelligent, and conditional programming models and compared with real data. The conditional programming was also used to correct small out-of-range data. The highest correlation between the final effective pressure and velocity cube was observed in lower Fahliyan Formation with 0.86 and Ilam with 0.71.The modeled MW difference ranged between 2.5 and 30 PCF. Also, the maximum modeled MW is 150 PCF in the upper Fahliyan Formation. Heavy mud of more than 130 PCF is suggested for drilling the Khalij member and continues to the end of stratigraphy column. Best observed correlation comparing the drilled and modeled MW, especially achieved in the Fahliyan reservoir Formation with more than 100 PCF and the Ilam Formation with 80–100 PCF. Finally, 3D formation pressures are presented and recommended for further safe drillings.

A refined evaluation method for the stress field of the Chang 73 shale oil reservoir of northern Shaanxi

Shale oil resources are abundant in the Chang 73 reservoir in the eastern Ordos Basin. The thin interbeds of shale in the Chang 73 section of the Yanchang Formation in the oil-bearing section are developed with solid interlayer inhomogeneity and unclear longitudinal interlayer stress difference. This has resulted in unpredictable high seam extension heights during hydraulic fracturing. Based on the results of the Kaiser experiments, the lithological variability was finely described by combining with downhole core observations, and the longitudinal interlayer stress difference coefficient in the Chang 73 section was finely interpreted by using logging data to evaluate the regional distribution pattern of ground stress in the Chang 73 shale reservoir in northern Shaanxi. After studying 600 wells in north of Shaanxi, it was found that: the maximum longitudinal ground stress variation in the Chang 73 reservoir with a thickness of 30-50 m was 35-55 MPa, the minimum ground stress variation was 30-50 MPa, and the minimum was 30 MPa. The horizontal stress difference in the Chang 73 reservoir north of Shaanxi was 3.2-8.6 MPa. The maximum horizontal stress was high in the northwest and low in the southeast, with high values distributed in Jiyuan and Dingbian areas and low values distributed in Zhidan. The refined evaluation of the ground stress results guides the selection of the fracturing layer and the optimal design of the horizontal well trajectory in the field.

Effects of Loading Rate on Fracture Modes and Acoustic Emission Characteristics of Interbedded Shale Under Tension

Effects of Loading Rate on Fracture Modes and Acoustic Emission Characteristics of Interbedded Shale Under Tension

Vertical fracture propagation behavior upon supercritical carbon dioxide fracturing of multiple layers

There are abundant unconventional oil and gas resources in the sandstone–shale interbed of the Yanchang Formation in Ordos Basin. However, it is difficult to predict the growth of supercritical carbon dioxide (Sc-CO2) fracture height in sandstone–shale interbed reservoirs due to the developed interface and strong heterogeneity. To enhance the productivity of sandstone–shale interbed reservoirs, it is necessary to clarify the Sc-CO2 fracture evolution mechanism. In this study, a global embedded zero-thickness cohesive element method is proposed for numerical simulation of Sc-CO2 fracturing of sandstone–shale interbeds, and the effects of stress difference, interface strength, and perforation position on fracture vertical propagation pattern are investigated. The results lead us to three main conclusions. (1) The fracturing model is established using the global embedded cohesive element method combined with the nonlinear constitutive equation, which solves the problem that the cohesive element cannot effectively simulate the random propagation of Sc-CO2 fractures. (2) Under the combined influence of in situ stresses and natural weak surfaces, there are three typical fracture extension patterns: I-shaped, cross-shaped, and single-shaped. In addition, there are six interaction modes between the main fracture and the interlayer interface. Branch fractures and microfractures are easily formed when the main fracture penetrates the sandstone–shale interface. (3) The vertical stress difference is greater than 4 MPa, and the dimensionless comprehensive interface strength is between 0.3 and 0.4, so the simultaneous perforation in shale and sandstone is a favorable factor for the full expansion of fracture height. The results provide theoretical guidance for selecting the Sc-CO2 fracturing horizon of sandstone–shale interbed reservoirs.

A study of inter-stratum propagation of hydraulic fracture of sandstone-shale interbedded shale oil

The vertical production layer of a shale oil reservoir in the Songnan Region, China, is mainly sandstone-shale interbed, and the reservoir thickness is uneven. As a result of varying interlayer properties, the hydraulic fracture height is hard to increase, and the propagation pattern of the fracture is unclear. In this paper, features of sandstone-shale lithological combination in the Songnan Region were explored by indoor rock mechanics experiments, which clarified the rock mechanics parameters and characterized the anisotropic features. Combined with the well-logging curves, the dynamic and static elastic moduli, Poisson's ratio, and tectonic coefficient were obtained. An evaluation model for crustal stress in the Songnan Region of China was built based on the hydraulic fracturing data. Additionally, a numerical model for 3D propagation of hydraulic fracture was established based on the finite element method to obtain three forms of fracture propagation and the effects of eight parameters, including fracturing fluid injection rate, interface strength, vertical stress, horizontal stress, elastic modulus, etc., on the height and length of hydraulic fracture were investigated. The results showed that increased viscosity and vertical stress of fracturing fluid could effectively increase fracture propagation height, low interface strength, fracturing fluid injection rate, and maximum and minimum horizontal principal stresses, thus favoring the propagation of hydraulic fractures. This study provides some guidance for the efficient development of sandstone-shale interbedded reservoir fracturing.

Depositional controls on diagenetic evolution of the Lower Cretaceous Wealden Sandstones (Wessex Basin, southeast England)

Depositional processes hold crucial controls on the diagenetic processes, events and evolution in sedimentary basins. Using the example of non-marine, Lower Cretaceous Wealden Sandstones from Wessex Basin in southeast England, this study reveals the depositional controls on diagenetic evolution in a sedimentary basin. Seventy-four surface samples, from 6 field locations across the Wessex Basin in Dorset and Isle of Wight were subjected to laboratory analyses such as optical petrography, scanning electron microscopy and Quantitative Evaluation of Minerals by Scanning Electron Microscopy analysis. The degree of compaction in the Wessex Basin sandstones includes moderate packing with most grains in a mix of point and long contact, with rare grains displaying concave-convex or non-grain contact and a loose packing dominated by non-grain contacts, with minor point and long contacts. The authigenic mineral phases identified in the sandstones are quartz, kaolinite, calcite and halite in decreasing abundance. The dissolution of felspars observed in the Wessex Basin sandstones possibly provided the main source of silica for the quartz overgrowths, with silica sources adjacent to the site of cementation. The small amount of quartz overgrowths may have formed during shallow burial. The partial dissolution of quartz observed in the Wessex Basin sandstones is considered likely to be the result of flushing of organic-compound rich waters derived from shale interbeds, under low temperature conditions (c. 25–50 °C). The precipitation of authigenic minerals within the Wessex Basin had a limited impact on the porosity and permeability of sandstones. Detrital mineralogy appears to be the main depositional control on diagenesis and may also explain the low abundance of authigenic kaolinite in the Wessex Basin. Similarly, the shallow burial depth of the sandstones is considered to be the main factor inhibiting more pervasive quartz cementation within the basin.

Study of novel steam assisted gravity drainage multilateral wells with dynamic gridding

SAGD (steam assisted gravity drainage) performance and its stream chamber growth are primarily determined by the vertical permeability of a reservoir. To deal with inter-bedded shale (IBS)-isolated intervals in bitumen reservoirs and improve steam chamber conformance, novel multilateral (MLT) wells with laterals and/or vertical legs in their trajectories are drilled to penetrate IBS. PetroChina Canada LTD. (PCC) has implemented MLT wells as a technology trial to evaluate potential mitigation to the presence of IBS in its MacKay River SAGD Project. Taking into account both accuracy and efficiency, dynamic local grid refinement (DLGR) is incorporated into the description of the mass and heat transfer phenomena in the vicinities of MLT wells. Also, to represent MLT injection and production wells as open hole branches, their lateral properties are adjusted by considering pore-scale mechanisms of fluid flow and heat transfer. With all these novel features established, the impacts of MLT wells on steam chamber growth and oil recovery are evaluated. It is discovered that MLT wells are conducive to increasing both injectivity and productivity due to the improvement of contact and drainage areas. Besides, how MLT wells perform with various steam operation strategies, geological parameters, injection pressure and NCG (non-condensable gas) wind-down scenarios is assessed.

The Mo- and U-isotope signatures in alternating shales and carbonate beds of rhythmites: A comparison and implications for redox conditions across the Cambrian-Ordovician boundary

The Green Point Formation (GPF) of the Cow Head Group in western Newfoundland (Canada) includes the Global Boundary Stratotype Section and Point (GSSP) for the Cambrian-Ordovician (Є-O) boundary on Laurentia. This formation is composed primarily of thick, deep subtidal to slope deposits (rhythmites) of alternating lime mudstones and shale interbeds. Here, we employ isotopic and elemental data of Mo and U of these shales and carbonates to better understand their depositional environments and the open ocean redox conditions at the Є-O transition. The variability of δ98Moauth (−0.40 to +3.16‰) indicates variable aqueous sulfide concentrations ([H2S]aq) in bottom waters or porewaters during deposition of the shales. A significant positive correlation of shale [Mo]auth with [U]auth coupled with low Mo concentrations compared to Phanerozoic euxinic shales further points to weakly reducing (~dysoxic/suboxic to anoxic) benthic conditions with H2Saq primarily confined to porewaters. For the lime mudstones, the δ98Mo variability (−0.30 to +2.34‰) suggests variable [H2S]aq in porewaters during early diagenesis. Low Mo concentrations ([Mo]carb = 0.25 ± 0.80 μg/g, 2σ) and a poor correlation of [Mo]carb with δ98Mocarb indicate weak sulfidic ([H2S]aq < 11 μM) porewater conditions and possibly dysoxic to suboxic bottom environments. Thus, the δ98Mocarb may not track the δ98Mo of basin waters because of low [H2S]aq in porewaters and insignificant accumulation of authigenic Mo during early diagenesis. This explanation is consistent with a poor correlation between δ98Mocarb and the δ238U of basin waters (estimated from δ238Ucarb). A cautious examination of MoEF/UEF, δ98Moauth, and δ238Uauth of the shales suggests that the GPF was likely deposited in a basin with topographic barriers. During deposition of the lower and middle part of the studied interval, the barriers in combination with sea-level fluctuations may have caused partial isolation of the local basin from the open ocean. Rapid sea-level rises in the earliest Ordovician greatly increased the connectivity between the local basin and the open ocean, resulting in remarkable increases in MoEF/UEF, [Mo]auth, and [U]auth of the shales. The δ238U of the earliest Ordovician open oceans, inferred from δ238Ucarb, exhibited perturbations and an average value of −0.78 ± 0.33‰ (2σ), reflecting oceanic redox oscillations and expanded ocean euxinia compared to the modern oceans.

Experimental Study on the Interaction Between CO2 and Rock During CO2 Pre-pad Energized Fracturing Operation in Thin Interbedded Shale

To investigate the impact of CO2 on rocks during the whole period of CO2 pre-pad energized fracturing operation for thin interbedded shale reservoir, including fracturing and well shut-in, a series of laboratory triaxial fracturing experiments and CO2 soaking experiments were conducted on thin interbedded shale (from Jimsar formations). In these experiments, combined with computed tomography (CT), the effect of fracturing fluid, horizontal principal stress difference, vertical principal stress, and natural fractures on fracture morphology were studied respectively. And based on X-ray diffraction (XRD) and scanning electron microscopy (SEM) experiments, the dissolution of minerals and the changes of pore structure before and after CO2 soaking were analyzed. The results of the fracturing experiment show that the bedding planes are easy to be opened by low viscosity of CO2 and the longitudinal fractures intersect with bedding planes to build a complex fracture network. During CO2 fracturing of thin interbedded shale, the horizontal principal stress difference is no longer a crucial factor to form a complex fracture network, but the vertical stress and natural fractures play important roles. And the soaking experiments indicate that the main dissolved mineral is carbonate whose dissolution ratio can reach 45.2% after soaking for 5 days, leading to the expansion of original pores or the exposure of new pores.

Insights on deepwater turbidite sedimentary features from outcrops in onshore Northwest Sabah, Malaysia

This paper discusses findings of sedimentary features observed from deepwater outcrops in Northwest Sabah. The observations were based on 7 outcrop localities of Lower Oligocene – Upper Oligocene sections around Klias and Kudat Peninsulas, and Kota Kinabalu, covering Temburong, Belait, West Crocker, and Kudat formations. Temburong Formation (Lower Oligocene-Lower Miocene) was observed at Menumbok (Stop 1) and Tanjung Aru (Stop 2). It comprises interbedded shale and sandstone turbidite sequence representing deposition in deepwater setting. At Batu Luang (Stop 3) the deepwater turbidite Temburong Formation is observed overlain unconformably by stacked fluvial channel deposits of Belait Formation (Middle to Upper Miocene). Here, the overlying fluvial deposits comprise predominantly conglomerates which are believed to represent basal Belait Formation lies over regional unconformable surface correlatatable to Deep Regional Unconformity (DRU). Deepwater West Crocker Formation (Lower Oligocene-Lower Miocene) was observed at King Fisher-Sulaman, Kota Kinabalu (Stop 4), composed of predominantly thick sandstone interbedded with shale. Meanwhile, Sikuati Member of the Kudat Formation (Lower Miocene) was observed at Pantai Sikuati (Stop 5) and Bukit ‘V’ (Stop 6) outcrops. It consists of interbedded sandstone and shale of turbidite successions. At Tanjung Simpang Mengayau (Stop 7) thick sandstone interbedded with thin shales of Kudat Formation was observed. In general, the Temburong Formation at Stops 1 and 2 show Bouma sequence of Ta-Tb-Te successions, but relatively thicker Te at Stop 1 suggesting a prolonged mud suspension deposit compared to Stop 2. At Stop 3, the deepwater Temburong Formation was subjected to a substantial tectonic uplift and massive erosion associated with DRU. Further northwards at Stop 4 West Crocker Formation exhibits thicker Ta successions which implies deposition within a slightly higher energy regime as compared to that of Temburong Formation at Stop 3. Meanwhile, at Stops 5 and 6 different depositional energy levels are shown in the lower and upper stratigraphic intervals. In the lower interval deposition took place within a higher energy condition as shown by thick Ta. It was followed by gradual decreasing depositional energy regime in the upper interval as shown by predominance Tc-Td-Te. Meanwhile, at Stop 7 a thick massive graded sandstone overlain by thin mudstone bed was observed which implies a prolonged Ta succession followed by short-term Te of mud suspension deposits.

Effects of anisotropic changes on the conductivity of sedimentary aquifers, southeastern Niger Delta, Nigeria

Sundry soils/rocks are characterized by electrical properties with clearly or obscurely expressed anisotropies. These anisotropic effects may be low, moderate or high depending on the coefficient of anisotropy (λ). The vertical electrical sounding technique employing Schlumberger electrode configuration and lithological information from boreholes were deployed to characterize the lithological diversity in homogeneous and anisotropic geologic units that serve as aquifer systems and their overlaying layers in the coastal region of Akwa Ibom State. Based on the $$\lambda$$ , the assessed volume of sedimentary formation is classified into low anisotropy λ < 1.2, moderate anisotropy $$\left( {1.2 < \lambda \le 1.3} \right)$$ and high anisotropy $$\left( {\lambda > 1.3} \right)$$ with alluvium (64.3%), inter-bedded shale and sandstone (14.3%) and shale and slate (21.3%). The estimated percentage of respective compositional coverage indicates that alluvium is dominant, while the blended inter-bedded shale and sandstone as well as the shale and slate are minor geologic units in the Benin Formation. Inferred index of spread of alluvium indicates that the homogeneous and anisotropic units assessed are intrinsic/microscopic in nature as identified by the impressed current that passed through geologic system. The results showcased that the plot between the strike-dependent resistivity $$\left( {\rho_{\theta } } \right)$$ at arbitrary chosen strike and geometric mean resistivity $$\left( {\rho_{m} } \right)$$ can be used as a yardstick for inferring the degree of consistency of geologic compositions in homogeneous and anisotropic media. Both the quantitative (graphic) and qualitative (contour) results portend the thin possibility of having anisotropy free geologic units. The finding proposes that ground resistivity measurements and interpretations of geologic structures should be constrained by borehole information in order to firm up the intended plans for obtaining clearer, defendable and well-resolved subsurface structures.

Experimental study on the geomechanical properties and failure behaviour of interbedded shale during SAGD operation

Interbedded shale (IBS) impedes the development of a steam chamber and poses a serious threat to the success of any steam-assisted gravity drainage (SAGD) operation in a heavy-oil reservoir. Breaking up IBS has been a continual challenge for the industry. This study summarizes experimental studies on the geomechanical properties and failure behaviour of IBS during thermal stimulation. IBS cores were collected by means of fully sealed coring in northwestern China. Mineral composition analysis, porosity, and permeability measurement, as well as imbibition tests, were initiated to evaluate the potential of imbibition. First, shear failure behaviour was studied through triaxial compression tests. Second, pore structure and failure processes of IBS were investigated through thermal stimulation experiments. Mudstone IBS was considered as the focus. Its porosity was approximately 7% and permeability was approximately 100 nD while in-situ stress was applied. Although IBS contained considerable smectite components, it didn’t disintegrate under high-effective stress. Last, shear failure behaviour of IBS was observed by computer tomography (CT) scanning when IBS was heated up to 180 °C under constant radial confining pressure and axial constraint of strain. While imbibition causes disintegration of IBS, it is unlikely when under in-situ stress conditions. Fortunately, shear failure can be achieved under uniaxial boundary conditions with rapid heating.

Reservoir Potential Evaluation of the Middle Paleocene Lockhart Limestone of the Kohat Basin, Pakistan: Petrophysical Analyses

The Lockhart Limestone is evaluated for its reservoir potential by utilizing wireline logs of Shakardara-01 well from Kohat Basin, Pakistan. The analyses showed 28.03% average volume of shale (Vsh), 25.57% average neutron porosity (NPHI), 3.31% average effective porosity (PHIE), 76% average water saturation (Sw), and 24.10% average hydrocarbon saturation (Sh) of the Lockhart Limestone in Shakardara-01 well. Based on variation in petrophysical character, the reservoir units of the Lockhart Limestone are divided into three zones i.e., zone-1, zone-2 and zone-3. Out of these zones, zone-1 and zone-2 possess a poor reservoir potential for hydrocarbons as reflected by very low effective porosity (1.40 and 2.02% respectively) and hydrocarbon saturation (15 and 5.20%), while zone-3 has a moderate reservoir potential due to its moderate effective porosity (6.50%) and hydrocarbon saturation (52%) respectively. Overall, the average effective porosity of 3.31% and hydrocarbon saturation of 24.10% as well as 28.03% volume of shale indicated poor reservoir potential of the Lockhart Limestone. Lithologically, this formation is dominated by limestone and shale interbeds in the Shakardara-01 well. Cross-plots of the petrophysical parameters versus depth showed that the Lockhart Limestone is a poor to tight reservoir in Shakardara-01 well and can hardly produce hydrocarbons under conventional drilling conditions.

Reservoir Potential Evaluation of the Middle Paleocene Lockhart Limestone of the Kohat Basin, Pakistan: Petrophysical Analyses

The Lockhart Limestone is evaluated for its reservoir potential by utilizing wireline logs of Shakardara-01 well from Kohat Basin, Pakistan. The analyses showed 28.03% average volume of shale (Vsh), 25.57% average neutron porosity (NPHI), 3.31% average effective porosity (PHIE), 76% average water saturation (Sw), and 24.10% average hydrocarbon saturation (Sh) of the Lockhart Limestone in Shakardara-01 well. Based on variation in petrophysical character, the reservoir units of the Lockhart Limestone are divided into three zones i.e., zone-1, zone-2 and zone-3. Out of these zones, zone-1 and zone-2 possess a poor reservoir potential for hydrocarbons as reflected by very low effective porosity (1.40 and 2.02% respectively) and hydrocarbon saturation (15 and 5.20%), while zone-3 has a moderate reservoir potential due to its moderate effective porosity (6.50%) and hydrocarbon saturation (52%) respectively. Overall, the average effective porosity of 3.31% and hydrocarbon saturation of 24.10% as well as 28.03% volume of shale indicated poor reservoir potential of the Lockhart Limestone. Lithologically, this formation is dominated by limestone and shale interbeds in the Shakardara-01 well. Cross-plots of the petrophysical parameters versus depth showed that the Lockhart Limestone is a poor to tight reservoir in Shakardara-01 well and can hardly produce hydrocarbons under conventional drilling conditions.

Sequence Stratigraphic Framework of the Jurassic Samana Suk Carbonate Formation, North Pakistan: Implications for Reservoir Potential

The paper aims to establish a possible link between the sequence stratigraphy and reservoir potential of the Middle Jurassic carbonates of Samana Suk Formation, Kala Chitta Range, North Pakistan. The Samana Suk Formation is comprised of a monotonous sequence of thin- to thick-bedded bioturbated, cross-bedded, ripple marked, sandy, bioclastic carbonates with shale interbeds. The rock unit is the best analog of shallow to marginal marine carbonates due to its pronounced thickness, enhanced lithological variations, and diverse diagenetic features. To establish a possible link between the sequence stratigraphy and reservoir potential of the rock unit, the outcrop and petrographic features are used to record eight microfacies, deposited in a wide range of shallow to marginal marine environments including mudflats, lagoon, back shoals, and sand shoals. Based on the vertical stacking pattern of microfacies in a given time of deposition (170–160 Ma), one second-order local cycle (SLC-1), three regressive systems tracts (RSTs) and two transgressive systems tracts (TSTs) are delineated within the succession. The primary and secondary porosity of selected microfacies from each systems tracts are investigated using petrography, scanning electron microscopy, and energy-dispersive spectroscopy. The direct measurements of porosity and permeability of these microfacies types are carried out using high overburden pressure plug porosity and permeability analyses. Based on these investigations, higher reservoir potential is recorded for mudstones/wackestone microfacies of RST as compared to grainstone microfacies of TST. The higher porosity within RST and higher interconnectivity of available pores both in RST and in TST suggest that the Samana Suk Formation carries good reservoir potential.

Evaluation of Ranikot Sandstone Formation, Punjab Platform Basin Pakistan

Abstract The Ranikot sandstone Formation was investigated using TOC and Rock-Eval pyrolysis measurements. Ranikot Formation encountered in Bijnot well, Fort Abbas has been evaluated, which lies in Bahawalpur, middle Indus basin, particularly in Punjab platform. Analysis has been performed on sandstones, twenty well cutting samples of Ranikot Formation has been evaluated. Formation is predominantly sandstone with interbeds of shale. The analysed samples contains TOC ranging from 0.76-3.1 wt.%, The S2 values of Rock-Eval shows poor potential with values ranging from 0.46-1.05 mg HC/g rock. The samples have low hydrogen index values ranging from 21-113 mg HC/g TOC. Kerogen is predominantly Type III land derived organic matter. The analysed samples have Tmax ranging from 413-509 °C. The upper part of formation from 490-560m depth generally exhibits good to very good TOC content and is in the transition between immature and mature zone (Tmax 430-431 °C). The genetic potential in the entire rock unit is poor &amp;lt; 2.0 mg HC/g rock. On the basis of analysis performed the studied samples have shown that the formation has poor potential.