Organic Rich Research Articles

Assessment of the hydrocarbon potential in the black shales of the Jurassic Khatatba Formation and generated hydrocarbons, North Western Desert, Egypt: Depositional mechanism of organic rich rocks related to syn-rift differential subsidence

Jurassic rocks comprise the main source rocks in the Western Desert of Egypt. In this study, a rare case of Jurassic oil shale occurrence is recorded and studied as an extension of the Khatatba Formation. The study is based on an integrated model for oil shale deposition using seismic data, organic geochemical analyses, and palynomorph thermal alteration assessment to determine the hydrocarbon generation potential of these rocks. The seismic data were used to construct structure and lithofacies models and to relate the facies distribution with the geochemical parameters of the different rock units in addition to examining the lithofacies changes between the study wells adding value to the understanding of the environment of deposition and the structure of the study area. The Zahra, U. Safa, and L. Safa members are affected by two sets of normal faults, the first of which has a downthrown side to the east while the second set has downthrown westward sides. The 3D facies models show that the Zahra Member is composed mainly of limestone encountered in the central parts of the basin, while shale is mostly found in the north. The U. Safa consists mainly of sandstone and the L. Safa consists of sandstone and siltstone. The geochemical evaluation shows organic richness ranging from poor to good for the Zahra, while the Safa shows poor to excellent richness. Kerogen is Type III and IV in most samples. The Zahra samples are immature in the TUT-21X well and mature in only one sample from the AMOUN NE-2X well. The U. Safa samples are immature to marginally mature while the L. Safa samples are marginally mature to mature in the TUT-21X well and immature in the SHAMS-15X well. Palynomorph thermal alteration data confirm the above maturation levels. The bulk and biomarker composition of two oils samples from U. and L. Safa, AMOUN NE-1X well, are similar and indicate a terrigenous source of the kerogen. The oils are not biodegraded but are normal mature oils generated by kerogen that was deposited under oxic conditions. Data integration from this study can be used to show the variation in organic richness (TOC) and thermal maturity (Tmax) in the area between the four wells, which will help define the exploration risk and provide for a new vision for more exploration activity.

Elastic properties and pore structure characterization of selected shales in the sungai Perlis beds, Terengganu, Peninsular Malaysia

Studied drill core of the Sungai Perlis Beds in the Terengganu State, Peninsular Malaysia, consists of a diverse suite of organic rich shale lithofacies at various subsurface depths. Lithofacies were delineated on the basis bedding thickness, mineralogy, and organic richness carried out by X-ray diffraction and (XRD) total organic content (TOC) analysis. Field-emission scanning electron microscopy (FE-SEM) analysis was carried out to identify the pore structure, range of pore sizes and mineral arrangement within each lithofacies unit Elastic geomechanical properties (Young’s modulus and Poisson’s ratio) were measured on core samples from each lithofacies unit using static and dynamic approaches. The identified lithofacies include moderate TOC massive argillaceous shale (MTOCMAS), high TOC massive argillaceous shale (HTOCMAS) and high TOC massive siliceous shale (HTOCMSS). FE-SEM analysis shows that pores in all the lithofacies are mostly intergranular, associated with phyllosilicate minerals, and ranges from <1 micrometer to approximately 8 micrometer. Static and dynamic elastic properties measurement shows that shale lithofacies having a high content of phyllosilicate minerals has a lower Young’s modulus and a high Poisson’s ratio value while lithofacies rich in brittle minerals has a higher Young’s modulus and a low Poisson’s ratio value. A good correlation exists between mineralogical brittleness index of the lithofacies and their plane strain modulus. The plane strain modulus is found higher in lithofacies having abundance of brittle minerals in the matrix suggesting that the high TOC massive siliceous shale (HTOCMSS) would preferably allow formation of dense hydraulic fractures, as observed in the CT scan analysis of triaxially fractured specimen, compared to argillaceous shale lithofacies.

The Cretaceous succession of northeast Baffin Bay: Stratigraphy, sedimentology and petroleum potential

Eleven cored boreholes, with depths up to c. 360 m were drilled in north-east Baffin Bay, a frontier area offshore West Greenland by the vessel Joides Resolution. The cores were part of the Baffin Bay scientific shallow coring program, expedition 344S in 2012, funded by a consortium of eight petroleum companies. The main drilling target was a succession of dipping strata in the Kap York Basin that proved to be of Cretaceous age. Here we report the results of comprehensive core analyses involving lithofacies interpretation, palynological dating, palynofacies studies, isotope geochronology, organic geochemistry and reservoir characterization. The Lower Cretaceous succession comprises sandstones, mudstones and few thin coal beds of Albian age. Terrestrial material and a sparse and low diversity assemblage of brackish-water dinoflagellate cysts (dinocyst) species dominate the organic particles. The sedimentary environments range from floodplain to deep bay and suggest deposition in a large non-marine to brackish embayment. The kerogen type is immature to marginally mature, type III/IV, with very restricted potential for generation of petroleum or gaseous petroleum. The Upper Cretaceous sedimentary succession of Cenomanian–Turonian age consists of black marine mudstone with varying amounts of discrete sand layers. The amorphous organic material and marine dinocysts suggest that most of the succession was deposited in an anoxic–dysoxic to oxygen restricted palaeoenvironment, probably ranging from outer shelf and prodelta fringe to lower delta front. The organic richness and petroleum potential are variable. The black mudstones include organic rich intervals with TOC of 3–6%, HI of 200–350 and SPI value of 3.0, comparable to well-known petroleum source rock successions of this age worldwide. The δ13Corg curves for the Cenomanian–Turonian sections display values and trends characteristic of Oceanic Anoxic Event 2 (OAE2). A marine transgression between the Lower and Upper Cretaceous successions caused dramatic changes in depositional environments.

Resistivity of reservoir sandstones and organic rich shales on the Barents Shelf: Implications for interpreting CSEM data

Marine controlled source electromagnetic (CSEM) data have been utilized in the past decade during petroleum exploration of the Barents Shelf, particularly for de-risking the highly porous sandstone reservoirs of the Upper Triassic to Middle Jurassic Realgrunnen Subgroup. In this contribution we compare the resistivity response from CSEM data to resistivity from wireline logs in both water- and hydrocarbon-bearing wells. We show that there is a very good match between these types of data, particularly when reservoirs are shallow. CSEM data, however, only provide information on the subsurface resistivity. Careful, geology-driven interpretation of CSEM data is required to maximize the impact on exploration success. This is particularly important when quantifying the relative resistivity contribution of high-saturation hydrocarbon-bearing sandstone and that of the overlying cap rock. In the presented case the cap rock comprises predominantly organic rich Upper Jurassic–Early Cretaceous shales of the Hekkingen Formation (i.e. a regional source rock). The resistivity response of the reservoir and its cap rock become merged in CSEM data due to the transverse resistance equivalence principle. As a result of this, it is imperative to understand both the relative contributions from reservoir and cap rock, and the geological significance of any lateral resistivity variation in each of the units. In this contribution, we quantify the resistivity of organic rich mudstone, i.e. source rock, and reservoir sandstones, using 131 exploration boreholes from the Barents Shelf. The highest resistivity (>10,000 ​Ωm) is evident in the hydrocarbon-bearing Realgrunnen Subgroup which is reported from 48 boreholes, 43 of which are used for this study. Pay zone resistivity is primarily controlled by reservoir quality (i.e. porosity and shale fraction) and fluid phase (i.e. gas, oil and water saturation). In the investigated wells, the shale dominated Hekkingen Formation exhibits enhanced resistivity compared to the background (i.e. the underlying and overlying stratigraphy), though rarely exceeds 20 ​Ωm. Marine mudstones typically show good correlation between measured organic richness and resistivity/sonic velocity log signatures. We conclude that the resistivity contribution to the CSEM response from hydrocarbon-bearing sandstones outweighs that of the organic rich cap rocks.

Aptian\u2013Albian shale oil unconventional system as registration of Cretaceous oceanic anoxic sub-events in the southern Tethys (Bir M\u2019Cherga basin, Tunisia)

The Bir M’Cherga basin (North-east Tunisia), with about 600 km2 area, had recorded four Middle Cretaceous source rocks well stratigraphically correlated with the four known oceanic anoxic sub-events: OAE1a, OAE1b, OAE1c, and OAE1d. Variety of lithology, thickness and organic richness had characterized these source rocks. The sedimentary tectonic analysis, the petrology and geochemistry study established the petroleum system of these source rocks. Basin formation began early in the Barremian–Aptian interval by synsedimentary tectonics reactivating old basement faults. During the Aptian–Albian, the formed basin had a depocenter that recorded thicker black shales while its NW and SE edges remained raised under the Triassic halokinetic activities. The evolution of the sedimentary filling during this period generated two sedimentary cycles corresponding to two filling second-order fining and thickening upwards sequences. The black shales that constitute these source rocks are formed between subtidal and external platform environment and are interbedded with juxtaposed high organic rich layers and poor ones. The rich organic facies consists of dark shale that constitutes the source rock. The poor organic beds formed by light grey and nodular limestones constitute an intra host reservoir. Thereby, petroleum system consists in an “unconventional oil shale hybrid systems with a combination of juxtaposed organic-rich and organic-lean intervals associated to open fractures”. The kerogen is essentially amorphous, with marine planktonic origin and low ligneous organic matter contribution. This organic material of dark facies had been well preserved in an anoxic environment with little or no energy. Light grey limestones were of oxic-to-sub-oxic environment. The stage of the thermal evolution for these source rocks provided by IH/Tmax diagram is of the “oil window”. The average transformation ratio (TR) is estimated as 45% suggesting thus black shales are oil shale resources which still close about untransformed 55% of its hydrocarbon generating potential. The expulsion and release of oil into these source rocks are proven by the observation of hydrocarbons filling micro-cracks and by the variable values of the oil saturation index OSI ranging from 0 to 138%. The latter exceeds 100% near the paleo-high reliefs indicating two “oil crossover” areas attributed to the high degree of oil source rock saturation and accumulation of hydrocarbons considered ideal for hydraulic fracturing. This oil crossover is a consequence of secondary migration into black shale source rock, achieved by various faults created during the distensive phase that were reactivated again several times.

Total organic carbon evaluation of the Bowland Shale Formation in the Upper Bowland of the Widmerpool Gulf

Widmerpool Gulf is one of the basins in the carboniferous Bowland Hodder shale in Central Britain. The area of interest in the Widmerpool Gulf is the Bowland Shale Formation within the Upper Bowland. This paper focuses on evaluating the total organic carbon (TOC) from Rempstone 1 and Old Dalby 1 both penetrating the Bowland Shale Formation using Passey's delta Log R method. TOC is an essential property needed to have a productive shale gas play – accurate characterisation of TOC is critical in evaluating the potential of shale gas reservoirs because it closely relates to the amount of kerogen and therefore total gas content. Passey's method involves the use of well logs to obtain the organic richness i.e. TOC. It relies on the response of well logs to organic matter using an overlay of porosity logs and resistivity logs. Which causes a separation i.e. a delta Log R separation. The reasons for the delta Log R separation in an organic rich reservoir/non reservoir rocks is due to the presence of low density, high transit time kerogen and the presence of formation fluid i.e. oil, gas or water. Immature source rocks also observe a separation but only from the porosity log whilst non source rocks observe no separation. Rempstone 1 and Old Dalby 1 well logs were exported on Interactive Petrophysics to analyze the lithology of the intervals before been exported to Microsoft Excel to evaluate the parameters of Passey's equation to enable TOC determination. TOC estimates for the Upper Bowland Shale section in the Widmerpool Gulf and was found comparable to estimates obtained from British Geological Survey (BGS) RockEval core analysis report. This method proved to be a suitable way of estimating the total organic carbon using simple well logs.

Depositional environments of Late Cretaceous Gongila and Fika formations, Chad (Bornu) Basin, Northeast Nigeria

Organic geochemical and palynofacies studies of 172 ditch cuttings samples of possible source rock shales from the Late Cretaceous Gongila and Fika formations in the Chad Basin of NE Nigeria were carried out to determine their paleoenvironments of deposition. Although dominated by amorphous organic matter, C/S ratios and molecular parameters suggest the mostly organic lean shales (TOC contents typically below 1.5%) were deposited in a normal marine environment. Levels of oxygenation influenced by water depth in the depositional environment appear to control organic richness and quality of the dark grey shales.The organic rich (TOC > 2.0%) upper part of the Fika Formation was deposited under anoxic conditions during the Late Cretaceous and could represent an Oceanic Anoxic Event. Mature intervals where such conditions prevailed would have generated liquid hydrocarbon, although none were sampled here.A trend of increasing organic richness towards the central part of the larger Chad Basin observed in this and other studies supports the development of organic rich marine shales (average TOC contents of 2–3%) of equivalent age in the Termit Basin where water depth would have been deeper and oxygen conditions at levels that permitted preservation of marine organic matter.

Estimation of oil in-place resources in the lower Oligocene Mezardere Shale, Thrace Basin, Turkey

Abstract Tertiary Thrace Basin of northwestern Turkey contains Early/Middle Eocene through Pleistocene age sediments the thickness of which reaches up to 9000 m in its depocenter. In this time interval, the Mezardere Formation was deposited in the Early Oligocene (36 m.y.) through Middle Oligocene (30 m.y.). Mezardere Formation is characterized by thick marine-prodelta organic rich shales, marls and sandstones. Present and previous research results showed that the Mezardere Shale contains marine Type II+III kerogen (HI=3–744 mg HC/g TOC) and sufficient organic richness (TOC=0.08–3.39 wt%) and has favorable thermal maturity (%VRm=0.35–1.20) in order to generate oil, condensate as well as wet-gas. Furthermore, discoveries of conventional oil, condensate and wet-gas and correlation of these fluids with the Mezardere Shale gives us a confidence that Mezardere Shale may retain hydrocarbon fluids and could be a significant shale-oil play in the Thrace Basin. Hence, the aim of this study is to estimate oil in-place (OIP) resource volume in the Mezardere Shale. For this purpose, available Rock-Eval data acquired from 407 Mezardere Shale cuttings and core samples from 47 wells are studied and evaluated. Five out of 47 wells show relatively continuous “Oil Saturation Index, (OSI=S1/TOC*100”) values. It is crucial to note that measured S1 and therefore OSI values are corrected against the evaporation loss. Corrections are made for 35, 40, and 45 API oils which are assumed to be present in the Mezardere Shale as retained oil. OIP resource estimations are conducted for the five wells as well as for the determined core area (e.g., 1000 km2 in the northwestern Thrace Basin). An average Mean Swanson's value of OIP's of the five wells is estimated to be approximately 405 M bbl. The core area shows an average Mean Swanson's value of OIP as 325 MM bbl.

Comparison of Qingshankou Formation in Songliao Basin with Bakken Formation in Williston Basin

Based on geological background, this study is to understand the potential of tight oil of Qingshankou Formation in Songliao Basin by comparing lithofacies features, oil-generating conditions and reservoir characteristics. Hundreds of samples are analyzed to derive geochemical parameters, such as organic richness, kerogen type, and source rock maturity. The results indicate that source rocks of Qingshankou Formation are organic rich, contain oil-prone kerogen, and are thermally mature. The tight reservoir of Qingshankou Formation has complicated pore throat structure, abundant fractures, and an beneficial place for oil accumulation.

The Potentiality of Source Rocks in Hayat Oilfield Based on Well Data, North Western Desert, Egypt

A total of 51 ditch samples were collected from organic rich horizon including dark-grey shales and limestones of the two wells (Hayat Deep-20x: 32 samples; Hayat-1x: 19 samples) and analyzed by a Leco WR 12 apparatus and Rock Eval pyrolysis. These samples were used as evaluation in potential source rocks in the Hayat oilfield. The results showed the three significant source rock intervals, which were penetrated by the Hayat deep-20x and Hayat-1x: wells. (1) The Upper Cretaceous source interval does not have the capacity to generate significant quantities of hydrocarbons in Hayat Deep-20x well and have fair to good organic richness in Hayat-1x well. (2) The Lower Cretaceous source interval ranges from a poor to good source potential and enters to the early stage of hydrocarbon generation. (3) The Middle Jurassic source interval has good source potential and has the capacity to generate significant quantities of gas generation.

Quantitative analysis of seismic response to total organic content and thermal maturity in shale gas plays

Although shales constitute about 75% of most sedimentary basins, the studies dealing with their seismic response are relatively few, particularly for the organic rich shale gas. Mapping distribution of shale gas and identifying their maturation level and organic carbon richness is critically important for unconventional gas field exploration and development. This study analyses the sensitivity of acoustic and elastic parameters of shales to variations in pore fluid content. Based on the effective medium theory a rock physics model has been made by inversion of the shale stiffness tensor from sonic, density, porosity and clay content logs. Due to the lack of a generally agreed upon fluid substitution model for shale, a statistical approach to Gassmann’s Model using effective porosity in the near boundary conditions, has been developed to account for shale. Fluid substituted logs—for a variety of maturation levels—and gas saturations were generated and used to make the layered earth models. AVO and seismic forward modelling were performed using the rock physics modelled and the fluid substituted logs on layered models. As part of seismic forward modelling, simultaneous inversion is performed for each model to generate P-impedance, S-impedance and density volumes. The sensitivity of the models were analysed by histogram, cross plotting, cross section highlighting, and body checking techniques. This study showed a dramatic hydrocarbon content effect—specifically gas—in the seismic response of shales.

SILURIAN — LOWER DEVONIAN BLACK SHALES IN MOROCCO: WHICH ARE THE ORGANICALLY RICHEST HORIZONS?

Lowermost Silurian (Rhuddanian, lower Llandovery) black shales represent the main Palaeozoic petroleum source rock throughout North Africa and Arabia. The unit also occurs in parts of Morocco with recorded TOC values of up to 10.5%. However, in contrast to many other North African and Arabian countries, the Silurian‐Lower Devonian shale‐dominated succession in Morocco also contains a number of other horizons with elevated organic contents. In order to evaluate the organic richness and better understand the depositional mechanisms of this shale succession in Morocco, samples were collected from petroleum exploration wells, from the spoil heaps of shallow water wells and from outcrops, and were subsequently analysed. Graptolite biostratigraphy provided a high‐resolution correlation framework. The data was integrated with that from published and unpublished studies, and the results may help in improved predictions of the source quality of Silurian—Lower Devonian strata in Morocco.An Aeronian (middle Llandovery) shale sample with a high organic content (4.35% TOC) was recovered from the NE margin of the Tadla Basin, central Morocco. Based on gamma‐ray data from the subsurface, however, this horizon appears to be laterally discontinuous within the basin. Secondly, late Telychian‐Wenlock shales from the eastern Atlas Mountains were found to have TOC values of around 2.5%, and may be correlated with age‐equivalent organic‐rich strata in the Ghadames Basin (eastern Algeria, western Libya, southern Tunisia) and Iraq. Late Silurian shale‐limestone alternations in Morocco apparently do not contain major amounts of organic mattel; although comparable deposits in parts of western Algeria are believed to be organic rich. Early Devonian graptolitic black shales from the Tadla Basin and its margins contain high amounts of organic matter (around 5% TOC); however; the lateral continuity of this unit is at present unclear.We propose that high primary productivity during the Silurian‐Early Devonian provided the basis for the formation of these organic‐rich shales in Morocco. Sea level changes may have been an important additional factor. For example, the Rhuddanian organic‐rich shales were deposited during the initial stages of a transgression, when circulation was still restricted due to the pronounced pre‐Silurian relief. At other times during the Silurian‐Early Devonian in Morocco, deposits with elevated organic content seem to have been formed during periods of high sea level, which may have been associated with high primary productivity and/or a rise in the oxygen minimum zone onto the shelf.

Dolomite and nahcolite formation in organic rich sediments: isotopically heavy carbonates

High positive C isotopic ratios in many carbonates coincide with high organic carbon contents. Nahcolites in the Green River oil shales have carbon isotopic ratios up to +20%. Some samples of organic rich Monterey and Pismo Formation dolomites also are 13C-rich (δ 13C to +14%.). Combining the observations of unusual isotopic ratios and organic richness has led to proposed mechanisms of formation of nahcolites and dolomites. Bacterial fermentation produces 13C-rich carbon dioxide which in the organic rich sediments is formed in large amounts. This leads to chemical reasons for the occurrence of dolomite rather than calcite and nahcolite rather than trona in some shallow burials.