Wet Gas Window Research Articles

The effect of thermal maturity on porosity development in the Upper Devonian –Lower Mississippian Woodford Shale, Permian Basin, US: Insights into the role of silica nanospheres and microcrystalline quartz on porosity preservation

Organic-matter pores are considered to be the dominant contributor to total porosity in many shale reservoirs, and consequently much attention has been paid to investigate the factors influencing their generation, especially thermal maturity. Recent studies have shown that in addition to maturation of organic matter, other diagenetic processes also play important roles in evolution of pore systems, including compaction, mineral dissolution, and quartz cementation. This study investigates the effect of thermal maturity on porosity development in the siliceous Woodford Shale by integrating multiple techniques including helium pycnometry, low pressure gas (N2) adsorption, mercury injection capillary pressure, and field emission scanning electron microscopy (SEM) analyses. We compare samples from two long cores from Woodford Shale at different levels of thermal maturity, one in the early oil window (average calculated Ro = 0.69%) and the other in the wet gas window (average calculated Ro = 1.34%).Porosity, pore size, type, and volume vary systematically with the thermal maturity increasing from early oil window to wet gas window. Porosity measured by helium pycnometry averages 4.1% for early oil window samples, and increased by approximately 50% for the wet gas window samples (average porosity =6.3%). Both pore size and pore throat size distributions display decreasing trends from early oil window to wet gas window. Petrographic examination of SEM images shows that pores developed between clay platelets dominate in the early oil window samples, and secondary organic-matter pores are the dominant pore type in wet gas window samples. Porosity shows no obvious correlation to TOC content in both oil window and gas window samples, but correlates positive to silica content, suggesting that silica content largely controls variations in porosity. Both silica nanospheres and microcrystalline quartz were observed and appear to be significant in preserving pores from compaction by forming rigid frameworks that prevent pores from collapsing. Generation of secondary organic-matter pores and preservation of primary pores by silica nanospheres account for the net porosity increase from early oil window to wet gas window.

The effects of organic carbon content and thermal maturity on acoustic parameters in a black shale: Woodford Shale, Permian Basin, West Texas

We have derived relationships between organic carbon and acoustic properties in the Woodford Shale, an Upper Devonian organic-rich shale in the Permian Basin, Texas. Extensive core data enable us to relate measured total organic carbon (TOC) on core samples to gamma log response; in turn, gamma log-calculated TOC is compared with P-wave [Formula: see text] and S-wave [Formula: see text] velocities, density, and derivative properties including [Formula: see text], Young’s modulus, Poisson’s ratio, [Formula: see text], and [Formula: see text]. Because we sampled two wells at very different thermal maturity (early oil window and wet gas window), we can examine the effect of thermal maturity on these parameters. In both wells, [Formula: see text] and [Formula: see text] decrease with increasing TOC, exhibiting a rapid decrease from 0% to approximately 1.5% TOC, and a slower decrease above 1.5% TOC, similar to results from ultrasonic experiments on core samples, that we attribute to a shift from a mineral grain load-bearing to an organic matter load-bearing fabric. The [Formula: see text] decreases by 28% and [Formula: see text] by 20% over the range of 0.5%–12% TOC. [Formula: see text] and [Formula: see text] correlate more strongly to neutron porosity than to TOC in the less mature well, related to the development of a bitumen phase that is relatively soft and less dense and has greater impact on rock physical properties than kerogen; this effect disappears in the high-maturity well in which bitumen was further cracked to petroleum and physical properties of bitumen changed with increased aromatization. The effect of increased thermal maturity is to increase [Formula: see text] by approximately 12%, [Formula: see text] by 25%, and P-wave impedance by 12%. [Formula: see text] ratios decrease with increasing TOC, contrary to the behavior expected for the incorporation of a soft material into a rock. We suggest that the rock develops a horizontal planar fabric at lower TOC values that absorbs S-wave energy, counteracting the effect of the organic matter.

Fractional composition and evolution of residual oil from coal of Early Permian Shanxi Formation (P1s), Ordos Basin (China)

To explore the residual oil contents and its fractional compositions changes with thermal stress, experiment of a whole coal sample from lower Permian Shanxi formation (P1sh) of Ordos Basin (China) was conducted in the grain-based micro-scale sealed vessel to explore the residual oil contents, fractional compositions and evolution at different temperatures and maturities. The residual oil of Shanxi coal reach the maximum at Ro=0.92% which was only 47.87 mg/g TOC. In oil window, the residual oil of Shanxi coal is mainly composed of asphaltenes, aromatics and resins with less saturates, showing lower oil prospective. In wet and dry gas windows, the residual oil becomes lower due to oil expulsion and cracking into gases. The main fractional compositions of residual oil are mainly aromatics and resins, which are gas-prone and can be the source of coal-bed methane at higher maturity stages.

Evolution of water content in organic-rich shales with increasing maturity and its controlling factors: Implications from a pyrolysis experiment on a water-saturated shale core sample

Abstract In the present study, a pyrolysis experiment was performed on an immature water-saturated shale core sample, and a set of artificially matured subsamples (maturity with equivalent vitrinite reflectance values of 0.67–3.20%, i.e., EqVRo values) with initial water phases was obtained. The water content of these shale samples and its influencing factors were investigated. The results show that the water content significantly varies with maturity and is closely related to the hydrocarbon generation and expulsion, clay mineral transformation, and pore structure evolution of shales. According to the changes of water content with maturity and the main influencing factors, the evolution of the water content in shales is approximately divided into three stages. At the low maturity stage (0.67% 1.36%), with increasing maturity, the water content remarkably decreases at the wet gas window (1.36% 1.90%), which is mainly controlled by the displacement drainage of gaseous hydrocarbons. In addition, the pore structure evolution of shale, which changes its water-storage capacity, also has an influence on the water content evolution.

Petrographic and sorption-based characterization of bituminous organic matter in the Mandal Formation, Central Graben (Norway)

The Upper Jurassic Mandal Fm. of the Central Graben, Norway represents an important source rock that charged major petroleum accumulations in the North Sea, including the giant Ekofisk field. Nevertheless, exploration to date has been less successful than expected in marginal basin position such as the Cod Terrace, the Mandal High or the Søgne Basin, probably due to higher proportions of thermally stable (type III) kerogen. In an attempt to delineate changes in initial kerogen composition from later effects such as delayed expulsion of hydrocarbons, traditional organic petrography and scanning electron microscopy were combined with organic geochemical proxies and gas adsorption tests. The kerogen composition of the Mandal Fm. shows considerable variation. Samples hosting autochthonous coaly layers were found in wells from the Søgne Basin and the Cod Terrace, for which less generative potential was previously postulated. Nevertheless, samples hosting mainly vitrodetrinite were also found in basinal wells. A correlation of total organic carbon contents with liptinite percentages highlights enhanced bioproductivity or preservation efficiency for samples with abundant algal organic matter, that were likely deposited under deeper water and possibly oxygen-depleted conditions. By combining organic geochemical proxies with nitrogen sorption data, it could be proven that in case of the Mandal Fm., the (bituminous) organic matter fraction represents the controlling factor on abundance of micro- and mesopores and hence adsorptive gas retention. The amount of bitumen extractable from the Rock-Eval S2 peak (S2bitumen) shows a strong correlation with the total inner surface area, suggesting that small mesopores (<10–15 nm) are mainly associated with the high-molecular bituminous fraction represented by the S2bitumen, which appears non-porous at SEM-scale. Furthermore, the total inner surface area decreases strongly with thermal maturity, documenting a change in pore characteristics of the organic matter fraction (growth of mesopores and occurrence of macropores) by advancing hydrocarbon generation. Pyrobitumen-rich Upper Visean reference samples at peak oil and early wet gas window maturity show intense sponge-like pyrobitumen-hosted porosity coinciding with a low relative proportion of S2bitumen (high petroleum quality). Pyrobitumen is not affected by solvent extraction, thus not contributing high-molecular weight compounds to the extracted fraction. Such inert meso- to macroporous residues might contribute only relatively little to gas sorption capacity, but might represent important storage space for free gas, as well as flow pathways during expulsion.

A model for porosity evolution in shale reservoirs: An example from the Upper Devonian Duvernay Formation, Western Canada Sedimentary Basin

The influence of thermal maturity on porosity in shale samples from the Upper Devonian Duvernay Formation is examined. The samples span a maturity range from immature to the wet gas window. Porosity decreases from immature to the oil window, primarily because of compaction. Relatively high porosity of wet gas window samples is ascribed to formation of secondary organic pores, feldspar dissolution pores, and primary pore preservation by the quartz framework. The final decline in the porosity of the dry gas window samples is explained by greater compaction, the disappearance of secondary organic pores, and feldspar dissolution pores. Porosity correlates positively to quartz content and negatively to carbonate content; no relationship was evident between porosity and clay or total organic carbon content. No obvious correlations exist between rock composition and permeability except that SiO2 content shows a weakly positive correlation to permeability. Permeability is highest in immature samples, which have the greatest pore and pore-throat sizes. Nitrogen adsorption and mercury injection analysis show that pore and pore-throat sizes decrease with increasing maturity. Visible pores, imaged by scanning electron microscopy and helium ion microscopy, exist as organic pores, including bubblelike pores developed within organic matter (OM) and fissure-type pores, intraparticle pores mainly developed within carbonate grains, and interparticle pores either within a clay-rich matrix or between rigid mineral grains. In immature samples, the primary pores are interparticle pores between clay minerals and other mineral grains. The OM fissures are ubiquitous in oil window samples, and secondary bubblelike OM–hosted pores are well developed within gas window samples.

Organic geochemical characteristics of Jurassic petroleum system in Abadan Plain and north Dezful zones of the Zagros basin, southwest Iran

Jurassic succession has resulted in prolific oil and gas reservoirs in southwest Iran. In order to geochemically investigate the Jurassic petroleum system and assess the source rock of these hydrocarbons, 32 source rock samples (from well cutting and surface section) and 4 condensate samples were analysed using geochemical approaches. Rock-Eval pyrolysis and vitrinite reflectance measurement were done on rock samples. Then, condensate samples and source rock extracts were subjected to gas chromatography, gas chromatography–mass spectrometry and isotopic analyses in order to establish oil–oil and oil–source rock correlation. The hydrocarbon generation prediction was then confirmed by petroleum system modelling. The results indicated that the middle Jurassic Sargelu Formation with average total organic carbon (TOC) and hydrogen index values of 3.8% and 600 mg HC/g TOC, respectively, can be classified as good to excellent source rock with kerogen of type II. The maturity indicators revealed late oil to wet gas generation window for the Jurassic Sargelu Formation. Biomarker parameters showed marine carbonate source rock with advanced level of thermal maturity for the source rock of the condensates. Furthermore, there were good correlations between Jurassic Sargelu Formation and the studied oil and condensate samples which proved the Sargelu Formation as the main source rock of the Jurassic petroleum system in the study area. The basin modelling results also confirmed late oil to wet gas window maturity for the Sargelu Formation enabling it as a source rock for generating gas condensate accumulation in southwest Iran. The hydrocarbon generation from Sargelu Formation began in the late Cretaceous and its peak expulsion occurred in the Miocene time.

Thermal maturation assessment of multiple organic-rich intervals in the Khatatba Formation and its influences on hydrocarbon potentiality, North East Abu Gharadig Concession, elucidated by 1D basin modeling approach

ABSTRACTHydrocarbon generation and expulsion simulations of multiple organic-rich intervals with diverse kerogen types in the Khatatba Formation were performed. Generally, the organofacies exhibit an excellent generation potential for liquid hydrocarbons, gas plus oil and/or gas. The 1D forward approaches have been executed for the complex tectonic and basin-fill history. The spatial distribution of the Khatatba organofacies and allocation of significant discoveries from the Khatatba Formation are aligned perpendicular to the NE-SW Jurassic Fault System. The organic-rich intervals underwent several heating episodes throughout its burial history predominantly during the Cretaceous Rifting phase. Likewise, the organofacies underwent episodic expulsion of gas derived from either primary cracking (kerogen type III) or secondary cracking of oil (kerogen type II). The oil prone type II kerogen entered the oil window at JD-4 well close to the Albian whilst the wet-gas window since late Albian. Conversely, gas prone type III kerogen attained the dry-gas window from the time of early Oligocene at the JD-4 well prior to the wet-gas window of the JG-2 well (late Oligocene). Nevertheless, gas prone type III kerogen never reached the dry gas window at JG-2 well due to its low thermal maturation level. The burial effect, attributable to the thick basin-fill sediments (Masajid, Alam El Bueib, Abu Roash and Khoman formations), accelerated the thermal maturation at the JD-4 well. However, the organofacies revealed neither thermogenic gas generation nor gas secondary cracking at the JG-2 well and nix expulsion. The expelled hydrocarbon assumed to migrate laterally and near vertically from the southeastern part towards the north western part.

GEOCHEMICAL AND PETROPHYSICAL ASSESSMENT OF TELISA SHALE GAS RESERVOIR: A CASE STUDY FROM SOUTH SUMATRA BASIN, INDONESIA

The geochemical and petrophysical assessment of a shale gas reservoir in Telisa Formation inSouth Sumatra Basin was carried out to identify the gas potential distribution. The assessment was performedbased on geochemical and petrophysical data, which were integrated with and seismic attributes to spatiallydistribute the organic richness of the shale gas reservoir. The objectives of this paper are to characterize coresamples in terms of the total organic carbon (TOC), kerogen type and thermal maturity of shale gas layers thatwere derived from the well log data. In addition, seismic attribute analysis such as acoustic impedance, which isassociated with TOC, was explored to spatially distribute the shale gas potential. The assessment results showedthat the organic richness of the Telisa shale gas reservoir is classified into fair quality with TOC in the range of0.75-1 weight (wt) %. The kerogen type of the Telisa shale gas reservoir is considered as a mixture of type II/III(oil/gas prone) to type III (gas prone). In terms of vitrinite reflectance, the Telisa shale reservoir is categorized asin a mature stage, representing an oil window up to a wet gas window. The prospective reservoir distribution isindicated by a shale lithology characterized by a high acoustic impedance range of 20000-24000 ((m/s). (g/cc)).

3D BASIN MODELLING OF OLIGOCENE – MIOCENE MAIKOP SOURCE ROCKS OFFSHORE ROMANIA AND IN THE WESTERN BLACK SEA

Hydrocarbon discoveries in the Western Black Sea have proved the presence of both thermogenic and biogenic petroleum systems. The presence of Tertiary biomarkers in oils from the Romanian part of the Western Black Sea sub‐basin, and correlation with Oligocene to Lower Miocene black shales, suggests that the thermogenic petroleum system is sourced mainly by the Oligocene – Miocene Maikop Group. Older source rocks may also be present locally in other parts of the sub‐basin, but their contribution is currently poorly understood.This paper presents the results of 3D basin modelling which was intended to evaluate charge models for prospects in the Western Black Sea sourced by the Maikop Group shales. The model is built on the regional‐scale interpretation of recently acquired, long‐offset 2D reflection seismic data, and was calibrated with proprietary and published well, geochemical and temperature data. The sensitivity of the thermal models on source maturity was tested. The basin models investigated two end‐member heat‐flow scenarios, “hot” and “cold”. Whereas the “hot” model more successfully reproduces the field and well data in shelfal areas of the Western Black Sea, the “cold” model is considered to be more valid for deeper‐water areas. Hydrocarbon expulsion maps were calculated for both scenarios at key stratigraphic levels, with preferential migration routes identified.The results of the basin modelling suggest that the most likely source rocks for the oils in accumulations offshore Romania are located in the mid‐Maikop Group (Upper Rupelian? to Chattian). Core data from offshore wells indicate that the source rocks consist of black shales with fair to good oil generation potential (TOC ∼ 0.5 to 4.5%, HI &lt;600 mg/g TOC, and mixed Type II/III kerogen). At the present day, these shales are in the early oil window offshore Romania to the SE of the producing fields, and in the wet gas window further to the east. Hydrocarbon expulsion from the mid‐Maikop interval began during the Middle Miocene, but significant volumes of liquids were generated only in the Late Miocene with the peak of expulsion not yet reached. Charging the accumulations on the Romanian Shelf requires lateral migration along the base‐Oligocene unconformity over distances of about 20–50 km. In addition, hydrocarbons have charged underlying Eocene and Cretaceous reservoir sections by lateral downward migration, filling structural traps and spilling over to higher structural levels. The results highlight the underexplored potential associated with the Maikop Group in the Western Black Sea.

Gas-condensate potential of the middle-Jurassic petroleum system in Abadan plain, Southwest Iran: Results of 2-D basin modeling

ABSTRACTThe Jurassic petroleum system has been proven as prolific oil and gas prospects in the southwestern of Iran. During this study, 2-D regional modeling was done on two selected sections (north-south and east-west); furthermore, 1-D models were reconstructed on 7 deeply drilled wells in order to evaluate petroleum generation and source rock maturity histories in the Abadan Plain area in southwest Iran. The results revealed that the Middle Jurassic Sargelu Formation with average present-time TOC and HI values of 2.65wt% and 151 mgHC/gTOC, respectively, can be classified as good to excellent type II source rock. The initial TOC and HI values regarded for modeling are 5wt% and 620 mgHC/gTOC, respectively. The geochemical maturity parameters indicate a wet gas window for the Sargelu Formation. The modeling results show that the maximum temperature and vitrinite reflectance in the Sargelu Formation has reached 150 oC and 1.3%VRo. Generation of hydrocarbon in the Sargelu commenced during the Early Cretaceous, while the main expulsion happened in the Paleogene. 2-D models show that the Jurassic source rock has already reached a high transformation ratio within the studied area and, due to lack of intense tectonic activity, the maturity is the same throughout the studied area. Oil and gas migrated mostly vertically to the overlying traps which are existed in the Jurassic and Cretaceous succession. The results predict the existence of gas-condensate in the Jurassic petroleum system of the studied area.

Natural gas potential of Carboniferous and Permian transitional shales in central Hunan, South China

The Carboniferous Ceshui formation and Permian Longtan and Dalong formations were deposited in transitional settings preserved in what is now central Hunan Province, South China, as they are potential natural gas plays. In this study, we analysed the total organic carbon (TOC), vitrinite reflectance (Ro), kerogen type, mineralogy, porosity, permeability, and methane adsorption of representative shale samples from these rock units. Our results indicate that TOC content can be as high as 9.2%, with a mean (x̄) of 3.5%. The Permian shale formations were deposited in more strongly reducing environments than the Carboniferous Ceshui shale. The kerogen composition of the Carboniferous Ceshui shale is dominated by Type III, while both of the Permian shales contain primarily Type II kerogens; Ro values range from 1.1% to 2.4% (x̄ = 1.6%). The organic matter in all the studied shales is in the wet gas window of thermal maturity and is relatively less mature than Lower Palaeozoic marine shales in south China. Mineral compositions are dominated by quartz (x̄ = 53.8%) and clay (x̄ = 35.6%), suggesting a high brittleness index. Porosity ranges from 0.5% to 14% (x̄ = 6.4%), while permeability varies from 0.0026 micro Darcy (mD) to 0.0640 mD (x̄ = 0.0130 mD). The gas adsorption capacity varies from 1.24 to 4.53 cm3/g (x̄ = 2.40 cm3/g). Relatively less mature shale samples (Ro<1.5%) have low methane adsorption capacities, regardless of their TOC values. However, the methane adsorption capacity of more mature (Ro>1.5%) shales samples exhibit a positive correlation with TOC content.

AN INTRODUCTION TO THE PRECAMBRIAN PETROLEUM SYSTEM IN THE SANKURU‐MBUJI‐MAYI‐LOMAMI‐LOVOY BASIN, SOUTH‐CENTRAL DEMOCRATIC REPUBLIC OF CONGO

This study presents a preliminary assessment of the petroleum potential of the Meso‐Neoproterozoic Mbuji‐Mayi Supergroup in the Sankuru‐Mbuji‐Mayi‐Lomami‐Lovoy Basin in the southern‐central Democratic Republic of Congo. This basin is one of the least explored in Central Africa and is a valuable resource for the evaluation of the petroleum system in the greater Congo Basin area. Highly altered carbonates (potential reservoir rocks) and black shales (potential source rocks) are present in the Mbuji‐Mayi Supergroup, which can be divided into the BI and overlying BII groups (Stenian and Tonian, respectively). For this study, samples of the BIe to BIIe subgroups from five boreholes and two outcrops were evaluated with petrographic, petrophysical and geochemical analyses.Carbonates in the BIe to BIIe subgroups with reservoir potential include oolitic packstones and grainstones, stromatolitic packstones and boundstones, various dolostones, and brecciated and zoned limestones. Thin section studies showed that porosity in samples of these carbonates is mainly vuggy and mouldic with well‐developed fractures, and secondary porosity is up to 12%. Black shales in the BIIc subgroup have TOC contents of 0.5–1%, and the organic matter is interpreted to have been derived from precursor Type I / II kerogen. The thermal maturity of asphaltite in carbonate samples is indicated by Raman spectroscopy‐derived palaeo‐temperatures which range from ∼150 to ∼260°C, which is typical of low‐grade metamorphism. Raman reflectance (RmcRo%) values on asphaltite samples were between 1.0 and 2.7%, indicating mature organic matter corresponding to the oil and wet gas windows. Source rock maturation and primary oil migration are interpreted to have occurred during Lufilian deformation (650–530 Ma). The solid asphaltite present in fractures in the dolostones of the BIIc subgroup may represent biodegraded light oil from an as‐yet unknown source which probably migrated during the Cambrian‐Ordovician (∼540–480 Ma). This migration event may have been related to the effects of the peak phase of Lufilian deformation in the Katanga Basin to the SE.This study is intended to provide a starting‐point for more detailed evaluations of potential hydrocarbon systems in the Sankuru‐Mbuji‐Mayi‐Lomami‐Lovoy Basin and the adjacent greater Congo Basin area.

Re-establishing the merits of thermal maturity and petroleum generation multi-dimensional modeling with an Arrhenius Equation using a single activation energy

Thermal maturation and petroleum generation modeling of shales is essential for successful exploration and exploitation of conventional and unconventional oil and gas plays. For basin-wide unconventional resource plays such modeling, when well calibrated with direct maturity measurements from wells, can characterize and locate production sweet spots for oil, wet gas and dry gas. The transformation of kerogen to petroleum is associated with many chemical reactions, but models typically focus on first-order reactions with rates determined by the Arrhenius Equation. A misconception has been perpetuated for many years that accurate thermal maturity modeling of vitrinite reflectance using the Arrhenius Equation and a single activation energy, to derive a time-temperature index (ΣTTIARR), as proposed by Wood (1988), is flawed. This claim was initially made by Sweeney and Burnham (1990) in promoting their “EasyRo” method, and repeated by others. This paper demonstrates through detailed multi-dimensional burial and thermal modeling and direct comparison of the ΣTTIARR and “EasyRo” methods that this is not the case. The ΣTTIARR method not only provides a very useful and sensitive maturity index, it can reproduce the calculated vitrinite reflectance values derived from models based on multiple activation energies (e.g., “EasyRo”). Through simple expressions the ΣTTIARR method can also provide oil and gas transformation factors that can be flexibly scaled and calibrated to match the oil, wet gas and dry gas generation windows. This is achieved in a more-computationally-efficient, flexible and transparent way by the ΣTTIARR method than the “EasyRo” method. Analysis indicates that the “EasyRo” method, using twenty activation energies and a constant frequency factor, generates reaction rates and transformation factors that do not realistically model observed kerogen behaviour and transformation factors over geologic time scales.

Petroleum System Modeling of Jabal Kand Oil Field, Northern Iraq

The petroleum system of Jabal Kand Oil Field shows that the formations such as Tertiary Kolosh, Cretaceous Shiranish, and Jurassic Sargelu are immature and have not generated any oil Ro 0.55%. Other formations such as Gele Khana and other Triassic formations are with high maturity with Ro≥ 1.3% and are within wet and dry gas window while older formations are either within dry gas zone or completely generated hydrocarbon and depleted after hydrocarbon was expelled and migrated to reservoir rock of structure traps.

The Garbutt Formation of Liard Basin, British Columbia: a potential liquids-rich play

Abstract In Liard Basin of northern British Columbia, syn-depositional motion on the Bovie structure resulted in greater thicknesses of Cretaceous sediments. The Early Cretaceous Garbutt Formation was deposited during the initiation of a major marine transgression. Organic-rich shales and siltstones in its lower part record maximum flooding and have been informally termed the Radioactive Zone (RZ). The Garbutt Formation is dominated by shales and siltstones and is here subdivided into three informal units; the lower Garbutt Formation (LGF), the succeeding RZ and the upper Garbutt Formation (UGF). The combined thickness of the Radioactive Zone and lower Garbutt Formation is 40 to over 120 m thick and can be at greater than 2000 m depth in Liard Basin. The lower Garbutt Formation is not recognized east of the Bovie structure and the RZ is considerably thinner or absent locally, suggesting this area remained high relative to Liard Basin. Total organic carbon and Rock-Eval data suggest that the RZ is a good to very good source rock and that the LGF is also a good source rock. Organic matter is dominantly Type II kerogen, although more terrestrial Type III input becomes prevalent in western parts of the basin. Thermal maturity inferred from Tmax, in addition to hydrogen index levels, indicate that these rocks are in the oil window in northern Liard Basin and in the wet gas window within central Liard Basin. Porosities average 8% and matrix compositions average 39 wt.% quartz, 4 wt.% feldspar and calcite and 53 wt.% clays (illite/mica, kaolinite and chlorite). The properties of the RZ and LGF indicate that a potential liquids-rich shale gas play may occur within central Liard Basin.

ORGANIC GEOCHEMISTRY OF OIL AND NATURAL GAS IN THE WEST DIKIRNIS AND EL‐TAMAD FIELDS, ONSHORE NILE DELTA, EGYPT: INTERPRETATION OF POTENTIAL SOURCE ROCKS

Crude oil in the West Dikirnis field in the northern onshore Nile Delta, Egypt, occurs in the poorly‐sorted Miocene sandstones of the Qawasim Formation. The geochemical composition and source of this oil is investigated in this paper. The reservoir sandstones are overlain by mudstones in the upper part of the Qawasim Formation and in the overlying Pliocene Kafr El‐Sheikh Formation. However TOC and Rock‐Eval analyses of these mudstones indicate that they have little potential to generate hydrocarbons, and mudstone extracts show little similarity in terms of biomarker compositions to the reservoired oils. The oils at West Dikirnis are interpreted to have been derived from an Upper Cretaceous – Lower Tertiary terrigenous, clay‐rich source rock, and to have migrated up along steeply‐dipping faults to the Qawasim sandstones reservoir. This interpretation is supported by the high C29/C27 sterane, diasterane/sterane, hopane/sterane and oleanane/C30 hopane ratios in the oils. Biomarker‐based maturity indicators (Ts/Tm, moretanes/hopanes and C32 homohopanes S/S+R) suggest that oil expulsion occurred before the source rock reached peak maturity. Previous studies have shown that the Upper Cretaceous – Lower Tertiary source rock is widely distributed throughout the on‐ and offshore Nile Delta.A wet gas sample from the Messinian sandstones at El‐Tamad field, located near to West Dikirnis, was analysed to determine its molecular and isotopic composition. The presence of isotopically heavy δ13 methane, ethane and propane indicates a thermogenic origin for the gas which was cracked directly from a humic kerogen. A preliminary burial and thermal history model suggests that wet gas window maturities in the study area occur within the Jurassic succession, and the gas at El‐Tamad may therefore be derived from a source rock of Jurassic age.

Comparison of marine, transitional, and lacustrine shales: A case study from the Sichuan Basin in China

Shale reservoirs have different properties and production performance depending on their geologic nature. Study of Precambrian to Jurassic shales in the Sichuan Basin in China indicates that the marine, transitional environment and lacustrine shales have tremendous shale gas and oil potential. Regional shale property mapping, recent drilling and production data, lab tests of 187 samples for geochemistry, mineralogy and petrophysics, and comparison of properties between shales reveal the distinctive reservoir characteristics between different type of shales: the shale of marine origin exampled by widespread Precambrian to Silurian shales has high to over maturity, high TOC, highest brittle mineral content, lowest clay content (<40%), and high gas content; The shale of coal-associated transitional origin exampled by Upper Permian shale has the highest clay content (usually >50%) and high to over maturity; The shale of lacustrine origin exampled by Triassic to Jurassic shales is relatively clay-rich compared to the marine shale but is less clay-rich compared to transitional shale. The maturity of Triassic lacustrine shale is high, while the Jurassic shale is mature in the oil to wet gas window. All of the shales in the Sichuan Basin have porosity less than 9% and the marine shale has more micron-scale to nano-scale organic pores than the transitional and lacustrine shales. The marine shale has the lowest permeability, dominated by nanodarcy range permeability, while the lacustrine shale has the highest permeability, ranging from microdarcy to millidarcy. The marine shale in the Sichuan Basin has the best reservoir and completion quality.

Alteration of organic matter by ion milling

Ion milling is increasingly used as a mean of sample surface preparation for scanning electron microscopy (SEM) to provide high-resolution imagery needed for studying the nanoscale structure of mudstones. Application of this technique has introduced new insight into nano-structural properties within organic matter (i.e., organic porosity) as an important reservoir control factor in unconventional shale/tight rocks. The continuous bombardment of the sample surface by ions (e.g., Gallium, Argon) results in the formation of kinetic heat energy, hence heating the milled surface of the rock. While this technique has proven to provide a spectacular surface for studying the fine structures, the effect of initial heat transfer to the organic matter (OM) is not well understood. Optical properties of OM (reflectance and fluorescence spectrometry) respond to the degree of aromatization of organic molecules, caused by thermal alteration. The effects of ion milling on dispersed OM were studied on four different macerals (i.e., solid bitumen, pyrobitumen, zooclasts, and alginate) within mudrocks of different thermal maturity levels. These mudrocks were milled with a cryogenic broad ion beam (C-BIB) and a focused ion beam (FIB). The random reflectance (Ro), bi-reflectance and the fluorescence red/green quotient (Q) of the macerals were measured and compared before and after the milling processes.The results show that initial heating caused by ion bombardment results in significant thermal alteration of the OM surfaces. The C-BIB milling resulted in 10 to 53% increase in the Ro values of the studied macerals, depending on their initial chemical refractoriness. The higher energy FIB milling increased Ro values of the same macerals by one order of magnitude. The solid bitumen appears to be more susceptible to thermal alteration than more refractory macerals (e.g., zooclasts and pyrobitumen). Ion milling did not shift the fluorescence spectra in immature alginate, suggesting that thermal alteration caused by ion milling is limited to the surface and not the entire body of the maceral. This study also documents significant morphological and possible chemical changes in pyrite due to the ion beam incident thermal alteration in most samples.Since most ion beam SEM studies focus on organic nanoporosity within the OM, thermal alteration caused by ion milling may have serious implications for image-based physical analysis of pores. The possibility of increased nanoporosity due to rapid devolatilization of lighter organic compounds in macerals could potentially have a significant impact on organic porosity, especially at lower thermal maturities (i.e., oil and wet gas windows).

Thermal maturity and hydrocarbon generation of the Dawi Formation, Belayim Marine Oil Field, Gulf Of Suez, Egypt: a 1D Basin Modeling Case Study

The Upper Senonian Dawi Formation of Belayim Marine Oil Field, Gulf Of Suez, Egypt, is a promising source rock. However, the generation and expulsion of hydrocarbons from it are not assigned yet. This study throws the light on the maturation (generation and expulsion) of hydrocarbons from Dawi formation through the construction and evaluation of a multi-1D approach within the framework of a fully integrated dynamic geologic model which was performed with PetroMod software. The first step in a new basin model is to construct a conceptual model, so in this study, the penetrated preserved stratigraphic sequence divided into uninterrupted time series based on petrophysical interpretation of the logged sequence and age-equivalent formations. Detailed well log interpretation was performed for the reservoirs and organic-rich source rock intervals and integrated into a conceptual model used for 1D basin modeling. Geochemical data is used to calibrate the log interpretation in this respect, which enabled basin modeling with extraordinarily high resolution of the stratigraphic sequence, resulting in a detailed and calibrated burial and thermal model. The simulations for four wells in the study area show differences in burial, thermal history and maturity, and, in consequence, differences in petroleum generation and expulsion with time. The maturity of the organic-rich interval varies from immature to mature with a different tendency to produce oil depending on the kerogen type, basin evolution, and burial through time. The Dawi Formation of the Upper Senonian age has relatively high organic carbon content and the capacity to generate petroleum liquids and possibly gas by secondary cracking. The Dawi Formation generated oil around the Late Miocene-Messinian (∼5.88 Mabp) during deposition of the Zeit Formation at oil windows’ depth of 2384 m (TVDss). The organic-rich interval of the Dawi Formation in Belayim Marine Oil Field concession, Dawi-S, entered the oil windows close to the Late Miocene (Messinian ∼5.88 Mabp) during the deposition of Zeit Formation and has been in the wet gas windows (gas onset) since ∼5.42 Mabp (Late Miocene-Messinian). The oil windows’ depths range between 2329 m (∼3.5 Mabp Pliocene-Piacenzian) at BM-23 well and 2384 m (∼5.88 Mabp Late Miocene-Messinian) at 113-M-27 well, before the maximum burial was reached. The expulsion of hydrocarbons mainly related to basin evolution due to the Messinian Time Event ∼5.2 to ∼4 Mabp (Pliocene-Zanclean) and it started at ∼5.2 Mabp. If sufficient residual kerogen has remained, increased temperature, according to the combined effect of Tertiary deposition and elevated temperature in the Late Tertiary, may have led to late-stage oil expulsion in favorable parts of the basin.