Hot Shale Research Articles

Orbital forcing and paleoenvironmental changes across the upper Ordovician glaciation-lower Silurian hot shale in the Risha gas field, northeast Jordan

This paper presents a comprehensive analysis of sedimentary successions and paleoenvironmental indicators in two wells, Rh3 and Rh46, located in NE Jordan, within the context of the Ordovician-Silurian boundary transition. By integrating spectral analysis, cyclostratigraphy and sedimentary architecture, significant shifts and cyclical patterns are identified, shedding light on paleoenvironmental changes and orbital forcing dynamics. The study reveals distinct lithological and geochemical signatures at the Risha/Mudawwara (Hirnantian/Rhuddanian) boundary, indicative of major shifts in depositional environments. Analysis of Milankovitch cycles suggests orbital forcing as a driver of sedimentary cyclicity, with implications for understanding climatic variations during the Ordovician-Silurian transition. Spectral analysis revealed significant cycles with different periodicities. Testing the sediment accumulation rates (SAR) revealed an optimum SAR at 5.9 and 4.6 cm/kyr in Rh3 and Rh46 wells, respectively. A new refined astronomical time scale (ATS) is created based on the 100 kyr eccentricity cycle. The new ATS assigns the Risha Formation to the Hirnantian age and revealed a probable time gap at the base of Risha Formation of about 0.3 myr in Rh46 well; deposition of the Risha Formation commenced at 444.88 myr and 444.58 myr in Rh3 and Rh46 wells, respectively, with sedimentation continuing up to the Ordovician/Silurian boundary at 443.07 myr. The Ordovician/Silurian transition experienced shortening in the obliquity and precession cycles. The tuned data show that the 41, 36 and 31 kyr obliquity cycles, in addition the 21, 19 and 16 kyr precession cycles, were recognised. Furthermore, 740, 425, 250, 147 and 100 kyr eccentricity cycles were also recognised. Notably, the study identifies the glacial/fluvioglacial Risha Formation is bounded by g4-g3 eccentricity nodes coinciding with Hirnantian stage boundaries that correspond to significant geological events, such as the Late Ordovician Mass Extinction and the Hirnantian glaciation events. The g4-g3 eccentricity cycle is estimated to be 1.8 myr. Surprisingly, the lower Silurian OAE coincided with the g4-g3 eccentricity node at the Ordovician/Silurian transition. Additionally, the application of DYNOT modelling has elucidated sea-level fluctuations and their relationship with sedimentary sequences, highlighting the role of tectonic and climatic factors in shaping the sedimentary architecture. Furthermore, the investigation of Th/U and Th/K ratios provides insights into marine and terrestrial depositional settings.

Silurian to early Devonian overmature hot shales in Eastern Taurus: Source rock characteristics and links to North African petroleum systems

The study area is located in the Eastern Taurus region and is characterized by the Paleozoic autochthonous Geyik Dağı Unit (GDU) in the northern Paleo-Tethys back-arc basin. The Eastern Taurus encompasses Silurian-Early Devonian units, which may have the characteristics to be called hot shales. In the study area, the Silurian black and organic lean shales and Orthoceras-bearing limestone and shale alternation have directly deposited on the Late Ordovician (Hirnantian) peri-glacial clastics. However, while Hot shale-I unit was deposited over the ice cover rebound-related paleo-depression areas in the southern Paleo-Tethys (North Africa) during the early Silurian (Rhuddanian- Early Telychian), turbiditic black lydite successions were deposited due to the radiolarian bloom in the northern Paleo-Tethys (Taurus Belt). Therefore, the studied black shales overlying the lydite successions correspond to the late Telychian hot shale II (Sheinwoodian and Pridoli- Lochkovian), which has only been defined in the Moroccan basins. On the other hand, both lydite occurrence and late Telychian-Sheinwoodian, and Pridoli-Lochkovian black shales (equivalents of Akakus and/or Tadrart formations) indicate that the Taurus basin under distinct paleoclimate conditions witnessed different bathymetry and nutrients source (e.g., silica). In addition, pyrolysis results indicate that the studied black shales belonging to GDU have lost 85–98% of their HC potential due to the overburden resulted from the allochthonous units. However, isotopic composition of the oils from the Adana basin and from the surface seepage samples show that these oils were expelled from Devonian shales. According to the pyrolysis and isotope data, we suggest that there may be a Pridoli-Lochkovian source rock unit in the Eastern Taurus, unlike the North Africa basins (except for Tadla basin). These data indicate that the basins developed over the Silurian-Early Devonian succession, which are believed not to have been affected by the nappe events, could have yielded an economic petroleum system over the onshore and/or offshore of eastern Mediterranean basins.

Geochemical and mineralogical characterizations of Silurian “Hot” shales: Implications for shale gas/oil reservoir potential in Jeffara basin-southeastern Tunisia, North Africa

The Silurian organic-rich hot shale deposits represent the origin of 80–90% Paleozoic sourced hydrocarbons on the entire Saharan Platform. As such, it is an area of significant interest for exploring its potential as an unconventional reservoir and gaining new insights into its properties. In this study, the geochemical and mineralogical analysis of eighty-two borehole samples from three studied wells (T, B, and M) located in Jeffara Basin, in southeastern Tunisa, distributed over a depth between 1200 m and 2200 m, show that the hot shale layer has significant potentials of an unconventional shale gas reservoir. According to the rock-eval and GCMS results, the total organic carbon (TOC) of the hot shale deposits is good to great, ranging between 0.54 wt% and 23.86 wt%, and the average hydrogen index (HI) is around ∼200 mg HC/g of TOC, which indicates that the hot shales were originally rich in type II/III organic matter (OM). The thermal maturity of the preserved OM is determined by the kerogen type with values varying from 0.4% to 1%, and Tmax values reaching 460 °C in T, B, and M wells which indicate that the hot shales preserved early mature to mature OM placed within oil/gas generation window. The calculated geochemical parameters reveal an average hydrocarbon generation potential (HGP) for the three studied wells of 20.37 kg HC/ton rock. In addition, the transformation ratios (TR) in T, B, and M wells are, respectively, 21.12%, 30% and 35.25%. However, only B and M wells show a cross-over layer, with oil saturation index (OSI) exceeding 100%, with significant potential as a hydrocarbon saturated source rock, making it a considerable target for unconventional oil exploration. Relevant results of Rock-Eval, biomarkers and XRD exhibit coherent features that reflect reducing marine conditions during the lower Silurian period. Moreover, the mineralogical composition was investigated to estimate the importance of frackable mineral fractions such as quartz (∼15%) and carbonates (calcite-dolomite). Mineral brittleness index (MBI) was calculated and compared to a well-known unconventional reservoir in the Neal shale member of the Floyd shale group in the Black Warrior Basin (US), which displays moderate to low MBI. The hot shales in the study area have a considerable MBI, which could be easily enhanced by hydraulic fracturing to liberate oil/gas from the potentially saturated unconventional shale reservoir.

Shale gas play of the silurian hot shale, Ghadames Basin, North Africa: Insights from integrated geochemistry and basin modeling

The lower Silurian hot shale in the Ghadames Basin was investigated to provide a regional assessment of the future prospects of shale gas play as an important unconventional resource system in one of the top African superglobal petroliferous sedimentary basins. The unconventional natural gas potential of the hot shale was studied based on regional improved organofacies assessment, thermal maturity, the timing of generation and expulsion, and sweet gas spot analysis, such as gas in place (GIP), total expelled gas (TEG), and total retained gas (TRG). The integration between regional geology and organic geochemistry, together with the proper regional utilization of the multi-dimensional basin modeling to better appreciate the importance of the Silurian hot shale as a key future shale gas unconventional-rich petroleum system (URPS) in the Ghadames Basin. The relationship between the richness and thermal parameters, such as the total organic carbon indicator (%TOC), hydrogen index (HI), measured and time step (calibrated models) vitrinite and equivalent vitrinite (%VRo) reflectance were used to develop quality control models for the regional natural gas spots of the Silurian hot shale were present-day mapping presentations are utilized as well for each parameter to better appreciate the lateral variability of the dry gas volumes. Regional basin control parameters from several key wells, such as heat flow levels, formation pressure system, and basin porosity were successfully utilized for the hot shale gas play resource screening (sweet spots) study utilizing multi-dimensional modeling approaches. The established regional spatial type B marine organofacies of the hot shale with excellent geochemical properties (∼18 %TOC) and regionally sufficient thermal maturation (∼2.45 %VRo, post-mature stage) indicate a significant amount of natural gas expelled and retained that has occurred in the Silurian hot shale system. The estimated GIP of the hot shale is about 120 bcf/km2 (equivalent to 320 bcf/section). The maximum expelled gas (TEG) amount is defined with values up to 88 bcf/section and the total estimated volume of the retained gas (TRG) is up to 96 bcf/km2, with the current geological architecture, geochemical properties, volumes, and distribution of the hot shale dry gas sweet spot in the Ghadames Basin. The hot shale can be considered in the near future for extensive further studies and exploration and development plans in Libya, Algeria, or Tunisia.

An Analysis of Silurian Paleo–Tethys Hydrocarbon Source Rock Characteristics in North Africa, the Middle East, and South China

In this study, we elucidate the genesis and distribution patterns of Silurian hot shale hydrocarbon source rocks by utilizing a comparative analysis of the evolutionary characteristics of plate tectonic activity in the Paleo–Tethys Ocean and the sedimentary filling characteristics of key basins in North Africa, the Middle East, and South China. We propose an explanation for the sedimentary genesis of world-class Silurian hydrocarbon source rocks in the Paleozoic craton basin of the ancient Tethys tectonic domain. This is achieved by scrutinizing the plate tectonic activity and evolution of the ancient Tethys Ocean and combining these findings with the paleotectonic sedimentation background of North Africa, the Middle East, and South China. Additionally, we compare Silurian hydrocarbon source rocks from these regions. The deep-water stagnant environment of the land shelf favors the preservation of organic matter, thereby forming high-quality hydrocarbon source rocks. Conversely, the shallow-water body of the land shelf is more turbulent, thus resulting in the poorer preservation of organic matter and, consequently, lower-quality hydrocarbon source rocks.

Organic matter enrichment in shale deposited proximal to paleo-uplifts and its impact on shale gas exploration

Much of the global exploration and development of shale gas is focused on organic-rich shale deposited in basin or slope/basin margin settings. There is a clear need to assess the degree to which organic-rich shale deposited in other settings, notably proximal to paleo-uplifts, are promising shale gas prospects. Organic-rich sediments that accumulated proximal to paleo-uplifts are recognized globally and include the Cambrian Niutitang Formation, Ordovician-Silurian transition “hot shales”, and modern sediments of the Black Sea. Though the subject of recent research efforts, much remains to be learned of the mechanisms of organic matter enrichment of fine-grained sediment deposited adjacent to paleo-uplifts. Our study focuses on the Ordovician Wufeng Formation that accumulated proximal to uplifted areas of the Upper Yangtze platform. Though the TOC content of the analyzed Wufeng Formation samples recovered from near the paleo-uplifts is less than that of Wufeng samples collected from basin or slope/basin margin settings, average TOC value of the former can still reach more than 2%. Wufeng Formation shale deposited proximal to paleo-uplifts accumulated under conditions of medium to high paleoproductivity, elevated terrigenous clastic input and sedimentation rate, and oxic-suboxic water column conditions. Principal component analysis suggests that the factor most critical to organic matter enrichment of Wufeng deposits proximal paleo-uplifts was paleo-redox conditions. The TOC abundance in Wufeng Formation shale deposited during late Katian stage is higher than that of shale deposited during Hirnantian stage. It was at the Hirnantian stage that the paleo-uplifts became most active in association with the Kwangsian Orogeny resulting in diminished paleoproductivity and preservation conditions as reflected in the reduced organic matter abundance of associated shale. Uplift of the paleo-uplift of the Yangtze Platform, a manifestation of the Kwangsian Orogeny during the Ordovician-Silurian transition, appears to have been largely responsible for spatial and temporal distribution differentiation of organic matter abundance of the Wufeng Formation of the Upper Yangtze Platform. Results of the present study contribute supplementary information regarding the mechanism of organic matter enrichment in shale and can provide guidance for shale gas exploration and development in geologically similar regions.

Chapter 6. Seismic expression of North Sea Jurassic sequences

Abstract Many of the stratigraphic sequences recognized in North Sea Jurassic well sections correspond to mappable surfaces on seismic sections. Typically, however, sequences are only mappable seismically within individual sub-basins, and seismic correlation between sub-basins, or across highs, is generally impossible without independent control from wells. Particularly prominent seismic sequence boundaries occur at near-base J54 in the Inner Moray Firth (‘Intra-Oxfordian Event’) the Viking Graben (‘Top Heather’ in this area), base J62 (‘Top Heather’, Moray Firth), base J66 (‘Top Lower Hot Shale’, Inner and Outer Moray Firth), base J71 (East Shetland Platform), base J73 (‘Top Siltstone Member’, Moray Firth) and top J70/base K10 (‘Base Cretaceous Unconformity’ (BCU), basin-wide). The BCU is the most frequently mapped seismic horizon in the North Sea Basin in Jurassic–basal Cretaceous studies. This surface, at the base of the Cromer Knoll Group, separates synrift sediments from post-rift successions above and marks a major shift in the tectonic evolution of the North Sea Basin.

The Lower Silurian (Hot Shale) Source Rocks of Western Iraq: Depositional Model and Stratigraphic Distribution

The Hoseiba Member, an Early Silurian basal mature hot shale of the Akkas Formation (Silurian) consists of about 80% of the Paleozoic hydrocarbon potential system, it is organic-rich with total organic carbon up to 16% as the main source for the Paleozoic gas resources in Iraq. The hot shale is the main source of rocks that are penetrated in deep wells in the western Iraqi desert such as Akkas-1, Qaim-1, and Khleisia -1, which are distributed due to paleo uplift in the restricted regional basin in the west, south, and northwest Iraqi desert and wedged to north thrust zone in Ora area of extreme northern Iraq, Ora subbasin to Aljezira NW and in the west where the approved source rocks of ‘Hot shale” Akkas -Widyian subbasin (Rephrase). The Hoseiba Member, basal hot shale in the Akkas Formation in Iraq and their correlative units are extended within neighboring countries Jordan, Syria, Saudi Arabia, Iran, Oman, and south Turkey. Qualitative and quantity of Hot Shales source rocks Silurian are Excellent in Akkas well -1 (0.95-16.62%) TOC in Akk-1 Akkas sub-basin west Iraq and an average thickness (30 m.) with 1-9.94% TOC in Kh-1 Al-Jezira sub-basin NW Iraq. The hot shale distribution was controlled by the Caledonian uplift that created paleo-high in northern Iraq and moderately deep to the northwest, and deep depression deposition in west and south desert Iraq. The hot shale expulsion and migration of hydrocarbon are controlled by the underlying main reservoir of the Khabour Formation K1 sandstone ember by block faulting

THE AGE, ORIGIN AND CONTEXT OF RESERVOIR SANDSTONES UNDERLYING THE LOWERMOST SILURIAN “HOT” SHALES IN THE WEST OF THE SULTANATE OF OMAN

The age and origin of reservoir sandstones which underlie the lowermost Silurian “hot” shales of the Sahmah Formation in the west of Oman is controversial. Here we describe one such sandstone which was cored and interpreted based on geological well evidence, and which then had to be re‐interpreted when definitive palynological results became available. The findings are enhanced when interpreted along with other deep wells in the area which have consistent palynological data.The western part of the Sultanate of Oman is a tectonically stable intra‐basinal high with low regional dips. In this area, the relief on the base‐Silurian unconformity of >250 m appears to be greater than that beneath the Permo‐Carboniferous unconformity which is well known for being highly erosive. The sandstones preserved beneath the base‐Silurian unconformity vary in depositional environment and reservoir quality from well to well, depending on their age, degree of erosion and differences in regional subsidence.There has been little evidence for the presence of Hirnantian‐aged deposits in Oman to date. However, some of the erosion and deep incisions which affect deposits of the Upper Ordovician Hasirah Formation are almost certainly related to falling sea levels accompanying the Hirnantian glaciation, just as the presence of the “hot shale” source rocks in the overlying Sahmah Formation are likely to be related to rising sea‐levels and anoxic conditions during the later deglaciation. Deformed strata in the Upper Ordovician deposits may reflect the instability of valley‐sides cut into weakly‐consolidated strata exposed during changes in sea‐level.The Sahmah oil play underlying the basal Silurian “hot” shales in Oman carries significant risks relating to the presence or absence of closures and reservoir, and the character, continuity and cementation of reservoir sandstones.

Abnormality of geothermal gradients in Iraqi western desert inferred from borehole temperatures

Geothermal gradient is an important tool in petroleum exploration and critical to several reservoir evaluations. Borehole Temperature data from 14 wells are utilized to find the geothermal tendency of the Western Desert in Iraq. The discrepancies in geothermal gradients throughout the area are a consequence of variability of sediment’s thermal conductivity, direction of groundwater flow, fault pattern, and heat generation. High value converts liquid hydrocarbon to dry gas and low value will not help organic matter to reach maturity level. The lowest gradient within the units above Palaeozoic Era’s section is 12.2 °C/km for well KH-9/7 in the eastern part of the area and the highest is 31.3 °C/km for well KH-5/4 in the middle part of the region. Whereas, the highest geothermal gradient which is 61.0 °C/km within the Palaeozoic section is recorded within Akkas Formation in 2100-2350 m subsurface. The mean geothermal gradient in Western Desert is 26 °C/km within the units younger than the Palaeozoic, but this average rises up to 40 °C/km within Palaeozoic units due to existence of Silurian hot shales and heat flow from the Proterozoic section especially from Halaban Group andesites.

In-situ stress analysis of Ahnet Basin, South western Algeria: A 1D geomechanical approach

This work aims to determine the present-day in-situ stress and pore pressure in the Ahnet Basin, Algeria, through a 1D geomechanical approach. We investigated the drilling-induced fracture (DIF) from FMI log data to ascertain the direction of maximum horizontal stress (SHmax) from the Ahnet Field. A mean orientation of N140° ( ± 10°) has been interpreted, which is NW-SE (N140°-N320°), with a local variation of ( ± 20°) compared to fields such as Illizi, Hassi Messaoud, and North Algeria, which can be explained by depth variation and intrinsic rock properties. A 1.05 psi/ft gradient of overburden stress (Sv) has been obtained from density. Pore pressure has been estimated from the sonic log by a normal compaction trend, indicates a hydrostatic regime from the surface to the top of the Silurian unit with an average pore pressure gradient of 0.43 psi/ft and an overpressure regime against the hot shale unit with a gradient of 0.58 psi/ft caused by the high in situ temperature in the study area and possible activity of the mega-shear zone. The poroelastic approach under transverse isotropic vertical conditions (VTI) has been used to calculate the minimum and maximum horizontal stress magnitudes. The outlines indicate a high-stress gradient close to 0.82 psi/ft, for Shmin calibrated with MDT stress points and 1.10 psi/ft for SHmax. The stress magnitudes results, suggest a present-day normal to strike-slip stress regime in the Ahnet Basin. Fault reactivation potential at two Silurian units has been inferred from the frictional theory analysis. The results indicate that increased pore pressure in hot shale formations due to by fluid injection and hydraulic fracturing causing shear slippage of the pre-existing faults, resulting in induced seismicity. Our study has contributed to the understanding of stress state origin in Ahnet Basin, the relationship between in situ temperature and pore pressure, and the fault stability analysis in such unconventional reservoir development.

The Paleozoic petroleum system of the Molla-Bismil area (Diyarbakır Basin, Turkey) and source rock properties of Lower Silurian (Llandovery) organic-rich shale

The Molla-Bismil area is a petroleum province, which hosts predominantly Paleozoic oil fields in the foreland area of the Diyarbakır Basin. The Arpatepe, Bahar, Yeniev, and Çalıktepe fields are Paleozoic oil field discoveries in the Molla-Bismil area to-date and have consequently been the focus of considerable research. This significant breakthrough reveals that the deep-wells in the Molla-Bismil area have proven the existence of a Paleozoic petroleum system. Prospective source rocks are located stratigraphically above the upper part of the Bedinan Formation (Upper Ordovician) reservoir, near the base of the Dadaş Formation (Llandovery, Dadaş-1 member). The lithology of the lower part of the Dadaş-1 member, also known as hot shales in the Molla-Bismil area, are typified by organic-rich brownish-black colored shale containing bitumen and thin limestone beds. New well data assists with the regional definition and correlation of typical source rock properties within the Diyarbakır Basin. Subsurface stratigraphy was derived for several deep wells from the Molla-Bismil area and core or drill cuttings from the Çatak-1, Bahar-1, Göksu-1R and Çalıktepe-2 wells were studied and reviewed for lithological and geochemical information. The understanding and prediction of the geochemical characterization of the Lower Silurian (Llandovery) organic-rich shales relevant for hydrocarbon production are crucial for Turkey's fossil fuel supply. Based on new drilling data, we re-examined the properties of the Llandovery organic-rich shales in the Molla-Bismil region. This study brings together new and previously unpublished knowledge about the Paleozoic plays of SE Turkey.

Major, trace, and rare earth element geochemistry of black shales from Devonian Sanai Formation in Northwestern Peninsula Malaysia: implications for the depositional environment, provenance, and tectonic setting

In this study major, trace, and rare earth elements (REEs) content of Sanai (SA) shales were determined by XRF-ICP-OES and ICP-MS. These results were used to probe tectonic setting, depositional environment, and provenance and of the SA Formation black shale. These black shales contain an average total organic carbon (TOC) content of 2.68 wt. %. Black shales from SA formation were deposited in the active continental margin based on ternary diagrams of La–Th–Sc and Th–Sc–Zr/10. SiO2 is rich in SA shales with avg. 59.5% while Al2O3 is the second most dominant major oxides with avg. 15.8%. Major oxides of the Western Peninsula (WP) Malaysia shale and hot shale gas reservoirs from China are also compared for the assessment. Redox element ratios infer deposition of the black shale most likely occurred in oxic to the anoxic environment. SA Formation black shales show a low Sr/Ba (< 0.5) value, indicating low salinity during the deposition. Geochemistry results indicate that the SA black shales seem to have been originated principally from the felsic source rock which might be granite in this case.

Shale gas potential of the lower Silurian hot shales in southern Iran and the Arabian Plate: Characterization of organic geochemistry

A significant phase of global warming appeared during the Llandovery and productive Silurian hot shale was preserved all over the world. The lower Silurian shale is the main effective source rock for most of the Paleozoic hydrocarbon in Iran and the Arabian platform. Silurian hot shales have become prospective resources for new energy such as shale gas. The regional distribution and shale gas potential of the lower Silurian hot shale in southern Iran and the Arabian plate are determined using outcrops and exploration well samples data from previous studies. The studied area has a high organic content (on average more than 2%), maximum burial depth is 5300 m, shale thickness of 30–200 m, organic matter maturities (most comparable), clay minerals content ranging from 20% to 57%, quartz content ranges from 20% to 49%, feldspar content ranges from 10% to 15% and calcite content ranges from 1.48% to 5% which all favor shale gas generation and accumulation. We concluded that southern Iran and east-central Saudi Arabia are two of the most sustainable and favorable locations for shale gas exploration and production for lower Silurian hot shale after assessing all of the key characteristics.

Silurian hot shale occurrence and distribution, organofacies, thermal maturation, and petroleum generation in Ghadames Basin, North Africa

The Silurian hot shale in one of the African superglobal petroliferous sedimentary basins (Ghadames) were studied to provide new regional insights regarding the organofacies type, occurrence and distribution, thermal maturation levels, and the timing of petroleum generation and expulsion. Based on regional integrated geochemical data such as Rock-Eval and Leco TOC, the evaluation of hot shale organofacies was carried out to characterize the type, occurrence and distribution and to obtain present-day regional maps of total organic carbon content (%TOCpd), hydrogen index (HIpd) and kerogen transformation (TRpd). The hot shale thermal maturation levels were obtained using pyrolysis Rock-Eval Tmax, equivalent vitrinite reflectance (%VRo), and one, two and three-dimensional calibrated basin modeling approaches. Results show that the hot shale was entirely dominated by typical marine organofacies type B (kerogen type I/II) with %TOC ranging from 2% to 17.5%, and hydrogen index ranged from 50 to 750 mg HC/g TOC with apparent systematic trends throughout the basin margins, and depocenter for both %TOC and HI. The hot shale thermal maturation study indicates a general maturation range from early to the post-mature stages with 0.45–2.45 %VRo and 380 °C–510 °C as pyrolysis temperature range. The one and two-dimensional kerogen transformation study based on the obtained refined thermal model shows a general range from 20% to 98% transformation levels with a systematic increase from the basin margins toward the basin depocenter. The hot shale oil window (top and bottom) is defined to be in the range of 1,400 m–4,000 m burial depth, while the dry gas window of the hot shale is presented at a burial range of 4,000 m–5200 m. Such an observation and current geological and geochemical conditions rank the hot to be an attractive potential sweet spot area as an unconventional shale oil/gas play target in Ghadames Basin for future exploration activity in western Libya, eastern Algeria, and southern Tunisia.

Lithofacies, mineralogy, and pore types in Paleozoic gas shales from Western Peninsular Malaysia

An experimental study including Fourier Transform Infrared (FTIR), thin section petrography, scanning electron microscope (SEM) imaging, and low-pressure nitrogen adsorption analysis has been conducted to assess the mineralogy, lithofacies, pore types, and pore properties of the potential Paleozoic gas shales from Western Peninsula (WP) Malaysia. In WP Malaysia, shale samples from seven Paleozoic Formations were investigated and classified into four age categories. FTIR analysis documented the presence of aromatic out of plane and in plane bending, aliphatic CH bending, OH functional group, and presence of quartz, carbonates, kaolinite, and illite minerals. Four lithofacies identified from the petrographic analysis of the Paleozoic shale include silica-rich argillaceous mudstone (SAM), clay-rich siliceous mudstone (CSM), silica dominated lithofacies mudstone (SD), and mixed carbonate mudstone (MCM). In comparison, the mineral content and lithofacies found in Paleozoic shales are close to the Niutitang, Longmaxi, Marcellus, and Eagle Ford shales. Furthermore, with high organic matter content, laminated fabric, and with more brittle mineralogy, SD lithofacies would be a highly promising type of lithofacies in WP Malaysia. FESEM studies show that organic matter pores, interparticle pores, and intraparticle pores are the main pore types. Pore sizes analyze through N2 adsorption reveal radii of lesser than 25 nm contribute mainly to porosity and total pore volume. Micropore volume of the WP Malaysia shale was found to be greatly similar to hot shales from USA and China, while surface area values of only older Paleozoic shales, i.e., S-D and Devonian, are close to USA shales.

Paleozoic sequence stratigraphy, depositional systems, and hydrocarbon habitats across the Arabian plate

The Paleozoic sedimentary section of the Arabian plate recorded the effects of numerous fluctuations in sea level and gentle epeirogenic movements. Eustatic changes in sea level over the Arabian plate resulted in transgressions and regressions and created many local and regional unconformity surfaces, identified by missing section and nondeposition. The distant deformation of the Caledonian tectonic orogeny and mountain building of the North Atlantic region, and the later Hercynian tectonic event, are partially responsible for eustatic sea-level changes. Additionally, detailed evidence of Paleozoic glacial erosion and glacial eustasy in the regressive sedimentary section over uplifted paleohighs comes from deep wells penetrating local exotic tectonic blocks. The resulting surfaces mark the sea-level falls associated with the glacial events in the Ordovician, Late Devonian, and Carboniferous–early Permian sediments. The depositional settings of the Cambrian–upper Permian rocks include deltaic and glacial settings and are expressed as alluvial–fluvial fans that grade into braided plains and shallow-marine carbonates flanked by distal shales. Late Permian sediment fill accompanied the development of widespread accommodation, resulting from a major sea-level rise, coinciding with a major period of carbonate–evaporite deposition, in which clastic sediments were only a minor factor. The regional sedimentary facies have good reservoir quality and are juxtaposed to regional source rocks and seals associated with both structural and minor stratigraphic traps. Production occurs in Precambrian through Permian strata in which mature clastic and shallow-water carbonate reservoirs occur, commonly sealed by shales, and sourced by Silurian hot shales or older source rocks in the section.

Organic petrography of Ordovician - Silurian rocks and their implications to hydrocarbon generation in the Akkas-1 well, western Iraq: New evidence for the Ordovician Gloeocapsomorpha and glaciation events

The Ordovician-Silurian hot shales are proved to be source for hydrocarbon in Akkas Field. New set of core samples of these important strata from Khabour and Akkas formations were examined from Akkas-1 well by organic petrography. The core samples of the Ordovician were found to be enriched in the liptinitic macerals that are mostly telalginite and lamalginite with lower abundances of vitrinite-like, inertinite and non-fluorescing network-forming matrix bituminite macerals. The studied Ordovician samples showed organic matter composition with large liquid hydrocarbon generation potentiality. The telalginite grains belong to the mat-forming algae that are found mostly in clusters and colonies. The early colonies are assigned to the Ordovician cosmopolitan Gloeocapsomorpha cyanobacterium. Several morphological variations in the telalginite particles are noticed through time that verifies their evolution. This is first record of this important oil prone organic matter in this region. In addition, unique micro-laminae are identified and attributed to the record of seasonal changes or varves. These varves indicate the summer/winter cyclic changes accompanied the Late Ordovician glaciation at western part of Arabian Peninsula and its influence on sedimentation in nearby basins. This cyclic pattern is also recorded for the first time as glaciation evidence in the Akkas-1 well. The seasonal changes of the summer/winter cycle are accompanied with some distinctions in the quantity and quality of the telalginite particles. The summer micro-laminae have large abundance of both organic matter and liptinite maceral. The Silurian hot shale has abundant liptinite maceral that are mostly bituminite and lamalginite. In addition, they are rich in redox sensitive trace elements that reveal anoxic depositional conditions. Ultralaminar structures are documented for the time in the bituminite of Silurian shale, which suggest a micro-algal origin. The source rock in the Silurian shale has a large potentiality to generate liquid hydrocarbon.

Reservoir characteristics and unconventional oil potential of Silurian aged Dadaş shale in southeast Turkey

The early Silurian to the earliest Devonian Dadaş formation in the Diyarbakır Basin, Southeast Turkey, is characterized by mainly organic-rich shale. The Dadaş-I member is the early Silurian basal “hot shale” of the Dadaş formation, and is an important source rock for many reservoirs in the basin and might carry significant unconventional oil potential.Dadaş-I member is characterized and divided into four lithofacies (L1, L2, L3, and L4) by using lithological data from logs of 24 offset wells supported by the core data (porosity, permeability, saturation, pyrolysis, SEM and XRD data). Petrophysical properties of these lithofacies suggest that the hydrocarbon potential of L1 is not attractive, whereas those of L2 and L4 are quite attractive. Additionally, the hydrocarbon potential of the L3 is significantly low.We performed three methodologies to quantify the unconventional hydrocarbon potential of Dadaş-I formation: Log-Based, Core-Based, and Mathematical Modeling of basin history. For Log Based and Core Based (volumetric) methods, we calculate in-place hydrocarbon volume by using porosity, saturation, thickness and areal extension. Average saturations are obtained from logs for the Log Based method and from cores wherever available for the Core Based method.The Mathematical model conducts basin deposition modeling which is done for two wells, called Derindere-1 and Çalıktepe-2. The current depth and thickness values, conformity or unconformity at any point in the stratigraphic line up are history matched by using a software. The model iterates over sedimentation time, speed, and tectonic activity at the well and calculates pressure and temperature to which the target formation is exposed during the depositional history. The model eventually estimates and outputs the hydrocarbon volume generated, migrated, and remained within unit rock, which can be applied to the entire basin to estimate unconventional volumes.The calculated OIPs for Diyarbakır Basin are 74.16, 65.72 and 26.66 109 bbls for Log Based, Core Based, and Mathematical Basin Modeling methods, respectively. Here we consider the mathematical model result more of a lower limit, contrary, the log-based result might be considered as the upper limit for OIP potential.

Brittleness computation from rock moduli without density

Brittleness is a key property for horizontal well placement, fracture development, and production sustainability assessments of unconventional shale and gas plays. Conventionally, brittleness is estimated from Young’s modulus and Poisson’s ratio, and averaged. As Young’s modulus is a function of density, field wide brittleness estimation from Young’s modulus after seismic inversion may be compromised because density is the least accurate estimate compared to acoustic impedance and shear impedance. A simple quantitatively equivalent brittleness computation can be made from using Young’s modulus × density rather than directly from Young’s modulus. Further, it is preferable to use the average brittleness estimation from Young’s modulus × density and shear modulus × density rather than the conventional average, because Poisson’s ratio is an indicator of lithology rather than brittleness. Examples of brittleness and total organic carbon estimation first from well logs, then from rock parameters inverted from 3D land seismic data successfully mapped a brittle shale zone in a Silurian hot shale, a known source rock onshore Turkey and now targeted as oil shale play. The estimated brittleness and total organic carbon showed agreement with the core analysis made at another well on the same prospect.