Levels Of Thermal Maturity Research Articles

Impacts of Competitive Water Adsorption of Kerogen and Clay Minerals on Wettability of Organic-Rich Mudrocks

Summary Quantifying wettability of organic-rich mudrocks is important for reliable formation evaluation, optimizing production, predicting water/hydrocarbon production, and selection of appropriate fracture fluids. Recent publications suggest that kerogen wettability can vary as a function of thermal maturity, ranging from water- to hydrocarbon-wet at low to high thermal maturities, respectively. However, clay minerals tend to preferentially be water-wet. It is therefore important to determine which of these constituents have a dominant contribution to overall wettability of the rock. To answer this question, we introduce methods to quantify the relative water-adsorption capacities of clay minerals, kerogen, and organic-rich mudrocks at different thermal-maturity levels. We started with isolating kerogen from organic-rich mudrock samples using chemical and physical separation methods and synthetically matured them to different thermal-maturity levels. We then prepared synthetic organic-rich mudrock samples by mixing known quantities of clay minerals, nonclay inorganic minerals, and kerogen. We then performed water-vapor adsorption measurements on pure clay minerals, pure kerogen samples, and synthetic organic-rich mudrock samples under controlled humidity conditions. Nuclear magnetic resonance (NMR) measurements were then used to quantify the volume of water adsorbed on clay minerals and organic-rich mudrock samples. We used the flotation test to qualitatively assess the wettability of the synthetic organic-rich mudrocks. Water-vapor adsorption experiments showed that the volume of water adsorbed on the surface of nonheated kerogen samples at low thermal maturities is 5.31 mL/100 g, which decreases significantly to 0.09 mL/100 g when the kerogen sample is heat-treated to 450°C. The results can be attributed to strong attraction between the oxygen content in kerogen and water at low thermal maturities. We quantified the water-adsorption capacity of kerogen samples heat-treated at 450°C and found that volume of water adsorbed decreases with an increase in thermal maturity both in the presence and absence of bitumen. In the case of synthetic organic-rich mudrock samples, we found that the volume of water adsorbed in samples at higher thermal maturity decreases by 16% compared with organic-rich mudrocks at low thermal maturity at the same concentration of nonswelling clay minerals. Results from the flotation test showed that the oil-wettability of the synthetic organic-rich mudrock samples increases as its thermal maturity decreases, with a hydrogen index (HI) of 328 to 54 mg hydrocarbon/g organic carbon (mg-HC/g-OC). Results confirmed that kerogen and its geochemistry can have a significant influence on the overall wettability of organic-rich mudrocks even at low concentrations of 4 wt%. The outcomes of this paper can contribute to a better understanding of the parameters affecting wettability of organic-rich mudrocks and are promising for in-situ assessment of their wettability. This can potentially contribute to improved understanding of flow mechanisms in organic-rich mudrocks, which control hydrocarbon/water production.

Tectonic Evolution of the Northern Oman Mountains, Part of the Strait of Hormuz Syntaxis: New Structural and Paleothermal Analyses and U‐Pb Dating of Synkinematic Calcite

AbstractThe Oman Mountains expose Permo‐Mesozoic shelf rocks of Arabia overridden by continental slope/basinal sediments and Semail Ophiolites during Late Cretaceous. A major syntaxis is represented by the Musandam Peninsula and Dibba Zone. The overthrusting of allochthonous units onto the Musandam shelf carbonates initiated during the Cenomanian. Structural analyses in the Musandam Peninsula constrained top‐to‐the‐west thrusting that took place 74–60 Ma ago (U‐Pb datings of synkinematic calcites), about 15–30 Ma after the obduction of the Semail Ophiolite. The Dibba faults exhibit a first interval of thrusting (top‐to‐the‐west) followed by dextral slip. We propose that SW vergent thrusts, initially parallel to those of the Central and Southern Oman Mountains, were subsequently rotated to their present‐day NE‐SW strike during the development of the syntaxis and then reactivated by dextral slip. Mixed layers illite‐smectite (I‐S) constrain the thermal evolution of the passive margin sequence and of the allochthonous deep‐water sediments. In particular, the proximal Hawasina unit (Hamrat Duru) and Sumeini groups of the Dibba Zone are characterized by long‐range ordered mixed layers I‐S with an illite content of 90–95%, whereas Musandam carbonate units show mixed layers I‐S with illite layers ranging from 80–90%, indicating deep diagenetic conditions. Such levels of thermal maturity were acquired during the Late Cretaceous emplacement of a 3.5‐km‐thick pile of allochthonous units, which were removed by erosion and denudation since the Campanian. U‐Pb dating of synkinematic calcite vein highlights reactivation of thrusts at 13.2 Ma, likely due to the involvement of the Musandam area in the Arabia‐Eurasia collision.

Preliminary Investigation of the Effects of Thermal Maturity on Redox-Sensitive Trace Metal Concentration in the Bakken Source Rock, North Dakota, USA.

Samples were taken at different levels of thermal maturity in the unconventional Bakken source rock. Programmed pyrolysis derived Tmax, solid bitumen reflectance, liptinite group maceral UV fluorescence, and nuclear magnetic resonance spectroscopy as different thermal maturity indicators were utilized in order to compare redox-sensitive trace metal (TM) concentration to maturity variations and disclose any probable relationship. Comparing redox-sensitive TMs with total organic carbon revealed the presence of anoxic/euxinic conditions in the depositional environment of the Bakken Shale. Although some of the TMs (V and Mo) exhibit slightly positive correlations with some of the thermal maturity indices used in this study, the correlations between other redox-sensitive TMs with maturity were neutral. Collectively, this study demonstrates that thermal maturity may have an impact on some redox-sensitive TMs such as Mo and V concentrations in marine sediments. Additional samples spanning higher maturities will need to be included because there is a possibility that an increase in thermal maturity may lead to the release and liberation of some redox-sensitive TMs from the organic matter (OM) directly. Remineralization and decomposition of OM with thermal maturity advance could release sulfur as a source of thermogenic H2S, which could accelerate pore water/rock interaction and authigenic Fe-sulfides. This could enhance the capability of uptaking of most of the redox-sensitive TMs and increase their concentration in pore water.

Oil source rock characteristics of the pelagic carbonates in the Shabwah depression, southeastern Sabatayn Basin, Yemen

Bituminous lime mudstone from the Late Tithonian--Early Barremian Naifa Formation was collected from five wells in the Shabwah depression of the southeastern Sabatayn Basin for basic organic geochemical analyses. The collected samples’ nannofossil contents were also studied. The current study preliminarily evaluated the nature of the organic matter regarding the richness and type of organic facies and their relation to oil generation potential. Most of the lime mudstone samples are organically rich and include favorable source rocks, as indicated by the high TOC content of up to 1 wt%. The presence of the warm-water index nannofossil taxa Watznaueria barnesae suggests warm climate conditions, thereby contributing to high bioproductivity that consequently enhanced organic richness. The samples are also hydrogen rich, with HI values between 302 and 740 mg HC/g TOC, resulting in two dominant organic facies of kerogen Types I and II, and are consistent with high bioproductivity of phytoplankton algae in warm-water conditions during deposition. Both geochemical maturity values Tmax and PI indicate that the bituminous lime mudstones are at different thermal maturity levels and range from immature to early mature stages of the oil generation window. This implies that the bituminous lime mudstones were not buried to a sufficient depth for commercial oil generation. Therefore, further exploration efforts in deeper parts of the Shabwah depression, particularly in the area around well Misah-01, are recommended.

DIAMONDOIDS AND BASIN MODELLING REVEAL ONE OF THE WORLD'S DEEPEST PETROLEUM SYSTEMS, SOUTH CASPIAN BASIN, AZERBAIJAN

The South Caspian Basin has been one of the world's most prolific petroleum provinces since the 19th Century. However, despite the large number of discovered petroleum accumulations, the source rock sequence has not been penetrated by the drill in the offshore basin and is therefore poorly defined. In this paper, geochemistry together with broad estimates of in‐place volumes of petroleum fluids, onshore outcrop data and basin modelling have been used to place constraints on the source rock description.Diamondoids, the most thermally stable group of hydrocarbons, have been measured in a suite of liquid petroleum samples from Pliocene fluvio‐deltaic sandstone reservoirs at the Shah Deniz gas‐condensate field and the Azeri‐Chirag‐Gunashli oil field, offshore Azerbaijan. Samples from both fields exhibit elevated concentrations of diamondoids and C29 steranes, indicating a mixture of thermally cracked and non‐cracked petroleum. We use diamondoid concentrations to estimate that 4.8 B brl of oil may have been cracked to 12 Tcf of gas below the Shah Deniz reservoirs. Source rock properties from the outcropping Oligocene – Miocene Maikop and Diatom Formations have been used to model source rock maturation. The results indicate that pre‐cracking volumes of petroleum could be explained reasonably by the presence of source rock intervals in the offshore that are of similar richness but increased thickness compared to measured onshore outcrops.Relatively high diamondoid concentrations in Shah Deniz condensate (up to 160 ppm 3‐ + 4‐methyldiamantanes) are in agreement with gas isotope compositions (δ13C1 – δ13C3) with respect to thermal maturity. Both parameters indicate the presence of source rock that is at a high level of thermal maturity at a vitrinite reflectance equivalent (VRE) of ca. 1.5–2.0% Ro. Given the low geothermal gradients in the South Caspian Basin (16 – 17°C/km at Shah Deniz) and the relatively high temperatures required for maturation due to rapid, relatively recent burial and heating, the source rock must be buried to depths in excess of 13 km in the Shah Deniz drainage area. In the absence of any evidence of a working Mesozoic petroleum system in the South Caspian Basin, this depth of burial highlights the significant thickness of Paleogene sediments in the offshore basin. Of prolific petroleum‐producing basins, only in the deep‐water Gulf of Mexico are actively‐generating source rocks buried to similar depths.

Tracing the origin of petroleum using asphaltene carbon isotope ratios: Case study from the Songliao Basin, NE China

Type I and II kerogens, isolated from outcrop shales in the Songliao Basin, were performed a programed sealed-heating kinetic process. Both carbon isotope values of pyrolysis-residual kerogens and those of asphaltene extractions present gradual enrichments dependence on increasing Easy %Ro and biomarker maturity ratios. The carbon isotope (δ13C) values are used for the first time to analyze a close relationship between these kerogens and asphaltenes at the same level of thermal maturation, and identification oil–source rock correlation studies in theory. Such validity of the model was further tested by δ13C of asphaltenes and biomarker ratios in crude oils.

Molecular weight variations of kerogen during maturation with MALDI-TOF-MS

Kerogen is an amorphous organic matter (AOM) in fine grain sediments, which produces petroleum and other byproducts when subjected to adequate pressure and temperature (deep burial conditions). Chemical characteristics of kerogen by considering its biogenic origin, depositional environment, and thermal maturity has been studied extensively with different analytical methods, though its molecular structure is still not fully known. In this study, conventional geochemical methods were used to screen bulk rock aliquots from the Bakken Shale with varying thermal maturities. Organic matter was isolated from the mineral matrix and then a mass spectrometry method was utilized to quantify molecular weight distribution (MWD) of four different kerogens at various thermal maturity levels (immature to late mature). Furthermore, to complement mass spectrometry, Fourier transform infrared (FTIR) spectroscopy was employed as a qualitative chemical and structural investigation technique. The MWD of four samples was obtained by matrix-assisted laser desorption/ionization time-of-flight (MALDI-TOF) mass spectrometry, and the results are correlated with the absorption indices (CH3/CH2 ratio and aromaticity) calculated from the FTIR attenuated total reflectance (ATR) method. The results showed when the degree of maturity increases, the aliphatic length shortens, and the branching develops, as well as the aromatic structure becomes more abundant. Moreover, based on the MWD results, higher maturity kerogen samples would consist of larger size molecular structures, which are recognized as more developed aromatic, and aliphatic branching stretches. The combination of infrared spectroscopy (AFT-FTIR) and mass spectrometry (MALDI-TOF) provided MWD variations in organic matter samples as a function of maturity based on varying absorption indices and revealed the rate of change in molecular mass populations as a function of thermal maturity in a type II kerogen.

Depositional history of low-mature coals from the Puyang Basin, Yunnan Province, China

Late Miocene samples from the Xiaolongtan Formation in Puyang Basin were sampled systematically from bottom to top of the main coal seam. Organic petrological as well as geochemical methods have been applied, aiming at the reconstruction of the depositional environment. The studied samples contain abundant detrovitrinite and liptinite macerals with high ash but low to moderate sulfur contents. This data indicates that the samples were deposited in topogenic mires without marine influence, but with fluctuations of water table and/or water influx which are mirrored by ash and sulfur content. The low values of tissue preservation and vegetation index, but high values of gelification index and groundwater index (GWIAC) in the studied coal imply a peat accumulation in inundated marshes under slightly oxic to anoxic depositional conditions with input of herbaceous plants mainly. An extended data set on vitrinite reflectance, volatile matter, Rock-Eval Tmax and HI suggests a coalification ranging from subbituminous C to B coal.The high concentration of long chain n-alkanes in the studied samples is typical for kerogen derived predominately from higher terrestrial plants. The applied biomarker ratios together with the detected hopenes further confirm the low thermal maturity level, as well as high water table and terrestrial organic matter input during peat accumulation. The variable concentrations of terpenoids and sesquiterpenoids suggest a dominant angiosperm input, but with a relatively high proportion of gymnosperms during some periods of peat deposition.

Are we modeling the properties of unconventional shales correctly?

Technological advancements have led to impressive growth in hydrocarbon (HC) production from unconventional shale reservoirs. However, major limiting factors in shale gas development are i) low recovery of gas in place (<20%), (ii) a rapid decline in well productivity, iii) release of contaminants, despite the use of advanced hydraulic fracturing fluids and multiple fracturing stages. This is mainly due to a lack of understanding of the nanoscale physicochemical properties of shales, especially that of kerogen, the macromolecule that is not only the source of the majority of the HC’s in shales but also holds most of the HC’s in adsorbed state. Over the last few years, a large number of studies have been published on simulating the physicochemical properties of shale utilizing molecular models of kerogen. However, the molecular models of kerogen input into these simulations are based on the kerogen “type” derived from a very limited number of shale samples. In this paper, we examine the variations that can exist in kerogen structure within a particular kerogen “type” across different shale basins and single shale basin at similar thermal maturity levels. We propose that using kerogen “type” based structural models for molecular simulations could lead to inaccurate estimation of HC reserves, HC recovery, HC production, frackability, and quantity and quality of produced water. This study highlights the need for developing a better classification of kerogen based on its “molecular structure” instead of “type” for a more accurate prediction of physicochemical properties of shales.

Modeling of thermal and burial histories for selected deep formations in the Middle-Jurassic to Lower Cretaceous in Siba Gas field, Southern Iraq

The petroleum system of Middle Jurassic to lower cretaceous layers in Mesopotamian basin have excellent source rocks and reservoirs. The deep formations (Sargelu and Yamama) in Siba gas field are selected from seismic sections and drilling data to rebuild burial and thermal history by 1D-Petromode software to understanding the level of thermal maturation of organic matters, hydrocarbon accumulation, migration and generation in the study area. Results revealed that the vitrinite reflectance (VR0) of the Yamama formation had been reached to the main oil window at (0.89%), while the Sargelu formation had been reached to (1.31%) wet gas window at present day. The thermal history modeling showed that the expected maximum temperatures at present day reached to (126.8 °C and 155.4 °C) for Yamama and Sargelu formations, respectively, due to the increase in the tectonic subsidence in Miocene period. This may attribute to the development of organic matters and hydrocarbon generation as well as rise in pore pressures due to compaction of layers that lead to hydrocarbon migration from Jurassic source rock to lower cretaceous reservoirs.

Source Rock Characterization of Silurian Tanezzuft and Devonian Awaynat Wanin Formations the Northern Edge of the Murzuq Basin, South West Libya

Drill cutting samples (n = 92) from the Devonian Awaynat Wanin Formation and Silurian Tanezzuft Formation, sampled from three wells F1, G1 and H1, locate in the northern edge of the Murzuq basin (approximately 700 kilometers south of Tripoli). The studied samples were analyzed in the objective of their organic geochemical assessment such as the type of organic matter, depositional conditions and thermal maturity level. A bulk geochemical parameters and precise biomarkers were estimated, using chromatography-mass spectrometry (GC-MS) to reveal a diversity of their geochemical characterizations. The rock formations are having varied organic matter contents, ranged from fair to excellent. The total organic carbon (TOC) reached about 9.1 wt%, ranging from 0.6 to 2.93 wt% (Awaynat Wanin), 0.5 to 2.54 wt% (Tanezzuft) and 0.52 to 9.1 wt% (Hot Shale). The cutting samples are ranged oil-prone organic matter (OM) of hydrogen index (HI) ranged between 98 –396 mg HC/g TOC, related kerogen types are type II and II/III, with oxygen index (OI): 6 - 190 with one sample have value of 366 mg CO2/g. Thermal maturity of these source rocks is different, ranging from immature to mature and oil window in the most of Tanezzuft Formation and Hot Shale samples, as reflected from the production index data (PI: 0.08 - 034). Tmax and vitrinite reflectance Ro% data (Tmax: 435 – 454 &amp; Ro%: 0.46 - 1.38) for the Awaynat Wanin. Biomarker ratios of specific hydrocarbons extracted from represented samples (n = 9), were moreover used to study thermal maturity level and depositional environments. Pristine/Phytane (Pr/Ph) ratios of 1.65 - 2.23 indicated anoxic to suboxic conditions of depositional marine shale and lacustrine source rock.

Effects of thermal maturity and chemical composition of kerogen on its dielectric constant

Reliable formation evaluation using borehole geophysical measurements in organic-rich mudrocks requires knowledge about the physical properties of kerogen. For instance, estimates of water-filled pore volume are significantly affected by the assumptions made for dielectric permittivity of kerogen, which can be influenced by thermal maturity. However, the impact of thermal maturity of pure kerogen on its dielectric properties is not yet thoroughly understood. We quantify the dielectric constant of kerogen samples extracted from three formations, with different levels of natural thermal maturity, and we identify the impact of thermal maturity on their dielectric properties. We first isolate kerogen from mudrock samples using physical and chemical treatments. We then synthetically mature the samples in a controlled environment and measure their dielectric constant (at 1 GHz) using a microwave resonator. X-ray photoelectron spectroscopy (XPS) monitors the variation in chemical composition of kerogen. The dielectric constant of the kerogen samples varied significantly in the range of 1.89–3.2 upon being heat treated from 25°C to 650°C. The variation in the dielectric constant is explained by the alteration in the chemical composition and structure of kerogen as a result of thermal maturation. XPS measurements also showed an increase in aromatic carbon content in the kerogen samples as the thermal maturity increased. The documented results enable the integration of the kerogen geochemistry to the interpretation of dielectric measurements, which contributes to improved interpretation of dielectric logs in organic-rich mudrocks, and result in enhanced formation evaluation of these reservoirs.

Comparing biodegradation and thermal maturity of some Nigerian oils.

Organic geochemical (Biomarker) method using gas chromatography-mass spectrometry was used to access the thermal maturity and biodegradation levels of the Agbada, Afowo, Yolde, and Bima Formation oils. Results obtained reveals that the Sterane and homohopane maturity parameters for the studied oils and their corresponding trisnorhopane thermal indicators (Ts:Tm ratio) are consistent with the thermal maturity values of petroleum source rocks within the oil window. This suggests that all the studied oils were generated as conventional light oil, some of which later degraded into heavy oils. Total Ion Current (TIC) fragmentogram of the saturate fractions of the studied oils shows progressive depletion of chromatographically resolved hydrocarbons relative to the unresolved hydrocarbon mixture, forming an unresolved complex mixture (UCM) hump consistent with oils that have undergone biodegradation except for the reservoired Agbada1 oil which was deeply buried beyond 2000 m and hence not biodegraded. Where these reservoir sands occur at depths greater than 2000m, it is possible to find non-biodegraded oils in them as long as they are properly sealed and connected to active petroleum source rocks.

Burial and thermal history of the Upper Silesian Coal Basin (Poland) constrained by maturity modelling – implications for coalification and natural gas generation

Maturity modelling was carried out using basin and petroleum system modelling (BPSM) software in the lithologic sections of 17 wells of the Upper Silesian Coal Basin (Poland). The best fit between calculated and measured vitrinite reflectance (VR), porosity and density data was obtained by applying a thickness of eroded sedimentary overburden from 1700 m in the east to 4500 m in the west and relatively low to moderate heat flow values during the maximum late Carboniferous burial. These heat flow values were in the range 50–71 mW/m 2 , most likely owing to rapid deposition of molasse sediment that led to a downward deflection of the isotherms. The upper Carboniferous strata were heated to temperatures in the range c. 90–170 °C, which is in accordance with the moderate to high levels of thermal maturity of these rocks (c. 0.6–1.7%VR). The coal rank pattern was reached before the Variscan tectonic inversion at the transition between the Carboniferous and the Permian (c. 300 Ma). This coalification level was not overprinted by any later thermal processes. The coalification resulted in the generation of natural gases. The upper Carboniferous strata are characterized by early to late phases of hydrocarbon generation. The kerogen transformation ratio (c. 5–75%TR) values vary across the basin. Most coals generated significant amounts of hydrocarbons, which reached over 80 mg of methane per gram of total organic carbon. Although most hydrocarbons generated most likely were lost during the intense post-Variscan exhumation, the hydrocarbon potential of the basin is still substantial.

Pyrolysis analysis, organic petrology and thermal effects of volcanics on Bima Formation shales, Yola Sub-basin, Northern Benue Trough, Nigeria

The shale sediments of Bima Formation from the Yola Sub-basin of the Northern Benue Trough, northeastern nigeria were studied based on pyrolysis analysis (rock-eval pyrolysis) and organic petrology (vitrinite reflectance and palynofacies) to determine the thermal effects of Tertiary (Neogene) volcanics on the organic matter thermal maturity. The study revealed that shale samples are of Type III and Type IV kerogens. This indicates high thermal maturity level and classified the samples as late-oil window to post-mature stage of hydrocarbon generation. This high thermal maturity could be attributed due to the Tertiary volcanic intrusion in most part of the basin. The samples however, appeared as a good source of oil- and gas-prone hydrocarbons. This study therefore, suggests that, the initial oil and gas-prone of the Type II and II-III kerogens in the shales have been cracked into thermogenic gas probably due to the high thermal effects of Tertiary volcanic intrusion in the basin. This has yield the present-day Types III and IV kerogens. The volcanic plugs however, intruded the Cretaceous sedimentary successions of the Northern Benue Trough during the Tertiary period and as such, they enhanced thermal maturity of the organic matters within the shale samples.

Impact of Geochemical Properties on Wettability of Kerogen and Organic-Rich Mudrocks

SummaryThe wettability of organic-rich mudrocks has a significant effect on multiphase-fluid flow and hydrocarbon recovery. This important rock property has still not been well-quantified in organic-rich mudrocks. Kerogen constitutes a significant fraction of mudrocks and can considerably affect their wettability. Recent publications suggested that kerogen wettability is affected by the thermal maturity of rocks and can influence the wettability of mudrocks. In this paper, we experimentally quantify the influence of geochemistry and thermal maturity of kerogen on the wettability of organic-rich mudrocks, and the influence of thermal maturity and chemical bonding on the wettability of kerogen. The wettability of organic-rich-mudrock samples at different experimental thermal-maturity levels was measured using the sessile-drop method, and also qualitatively estimated using a Flotation test and spontaneous-imbibition experiments on crushed-organic-rich-mudrock samples. The concentration of minerals in the mudrock samples was quantified using X-ray diffraction (XRD) at different experimental maturity levels. We then isolated kerogen samples from an organic-rich-mudrock formation and experimentally matured them. The variation in the chemical-bonding state of carbon present in kerogen at different levels of natural and experimental thermal maturity was determined using X-ray-photoelectron-spectroscopy (XPS) measurements. Finally, the wettability of pure-kerogen samples at different thermal-maturity levels was quantified using the sessile-drop method and the effect of aromatic carbon content on the wettability of the kerogen samples was determined.The sessile-drop test performed on the organic-rich-mudrock-rock samples showed a 5° increase in contact angle with a 96% decrease in the hydrogen index (HI). The Flotation test showed that the oil-wet fraction of the mudrock samples increases by 81% as the heat-treatment temperature increases from nonheated to 650°C. The water-imbibition measurements in crushed-mudrock samples suggest that the volume of water imbibed was higher by 22 cm3 at lower thermal maturity [i.e., HI of 328 mg hydrocarbon/g organic carbon (mg HC/g OC)] compared with mudrock samples at higher thermal maturity (i.e., HI of 10 mg HC/g OC). Results indicate that the thermal maturity of kerogen could potentially affect the wettability of mudrocks and that the mudrock has higher water wettability at lower thermal maturity of kerogen. The experimental results also demonstrated that the wettability of kerogen changes from waterwet to hydrocarbon-wet with an increase in the aromatic carbon content. The contact angle of the water droplet on the kerogen samples from Formation A increased by 78° when the aromatic carbon concentration increased by 19%. The results contribute to a better understanding of the effects of kerogen wettability and thermal maturity on the wettability of organic-rich mudrocks. The outcomes can also have potential future contributions in understanding flow mechanisms in organic-rich mudrocks as well as in developing reliable rockphysics models for the interpretation of borehole geophysical measurements [e.g., electromagnetic and nuclear-magnetic-resonance (NMR) measurements] in organic-rich mudrocks.

Mud gas play

The presence of methane gas seepage in the mud volcano proves the existence of gas associated with over pressured zone in the subsurface. The analysis of C isotope on samples of methane gas seepage of mud volcano show the gas is thermogenic methane at the level of thermal maturity that is equivalent to the peak of petroleum formation. The mud of mud volcano extruded from overpressures zone beneath is predicted to have high gas storage capacity. The objectives of this paper are to define capacity of the mud of mud volcano system as a potential reservoir gas and its role in petroleum system. Isothermal absorption test is performed to answer the storage capacity of the mud of Kesongo and Lusi mud volcanoes system. Seismic data and velocity data show over pressured mud zone as chaotic zone with low velocity anomaly distributed crossing the reflector layer as chamber. The gas storage capacity of the mud based on adsorption test at the temperature of 65-degree Celsius ranges from 812 scf/ton up to 3,217 scf/ton shows it has capacity of gas reservoir. The adsorbed gas in over pressured mud shows different mechanism with that of the conventional reservoir. Adsorbed gas in over pressured mud can be proposed as unconventional gas reservoirs with new alternative hydrocarbon play: mudgas-play (MGP). Mud-gas-play is defined as the accumulated gas trapped in over pressured zone. Gas accumulations tend to be concentrated in the upper part of over pressured zone.

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.

Burial History Reconstruction of the Appalachian Basin in Kentucky, West Virginia, Pennsylvania, and New York, Using 1D Petroleum System Models

Nine 1D burial history models were built across the Appalachian basin to reconstruct the burial, erosional, and thermal maturation histories of contained petroleum source rocks. Models were calibrated to measured downhole temperatures, and to vitrinite reflectance (% Ro) data for Devonian through Pennsylvanian source rocks. The highest levels of thermal maturity in petroleum source rocks are within and proximal to the Rome trough in the deep basin, which are also within the confluence of increased structural complexity and associated faulting, overpressured Devonian shales, and thick intervals of salt in the underlying Silurian Salina Group. Models incorporate minor erosion from 260 to 140 million years ago (Ma) that allows for extended burial and heating of underlying strata. Two modeled times of increased erosion, from 140 to 90 Ma and 23 to 5.3 Ma, are followed by lesser erosion from 5.3 Ma to Present. Absent strata are mainly Permian shales and sandstone; thickness of these removed layers increased from about 6200 ft (1890 m) west of the Rome trough to as much as 9650 ft (2940 m) within the trough. The onset of oil generation based on 0.6% Ro ranges from 387 to 306 Ma for the Utica Shale, and 359 to 282 Ma for Middle Devonian to basal Mississippian shales. The ~1.2% Ro onset of wet gas generation ranges from 360 to 281 Ma in the Utica Shale, and 298 to 150 Ma for Devonian to lowermost Mississippian shales.

The Sinian-Cambrian formation shale gas exploration and practice in southern margin of Huangling paleo-uplift

The Sinian Doushantuo and the Cambrian Niutitang formations in southern China have a good shale gas resource potential. Although >20 wells have already been drilled in these formations, the shale gas production has been much lower than expected, due to the high thermal maturity of the rocks and the severely disturbed geological structure of the corresponding area. An industrial gas flow was discovered only in the Weiyuan region. To achieve the shale gas breakthrough of paleo-shale strata, it is necessary to find a shale reservoir with low thermal maturity and weak geological deformation. On the basis of the study on the Weiyuan, Huangling and other paleo-uplifts, a shale gas accumulation mechanism named “shale gas accumulating around the edges of paleo-uplifts” was proposed. It has been suggested that the shale gas is usually contained within the slope belt of a paleo-uplift margin characterized by a shallow burial depth, stable structure activity, and a low level of thermal maturity. Taking into account this accumulation mechanism, a large number of wells have been drilled on the southern edge of the Huangling paleo-uplift (western Hubei province). Organic-enriched shales with high shale gas content and low thermal maturity, have been found within the Sinian Doushantuo and the Cambrian Niutitang formations. To tackle the problems deriving from the low exploration level, complex geological structure, low temperature, and low pressure in the region, we proposed and applied innovative fracturing process, new complex fracturing techniques and new recovering technology systems. High and stable shale outputs were obtained from the Niutitang Formation (well Yangye-1HF, HF: Horizontal Well Fracturing) and from the Doushantuo Formation (well Yangye-2HF): 7.83 × 104 and 5.53 × 104 m3/day, respectively. These outputs were achieved following horizontal well section fracturing, which resulted in a significant breakthrough for the production capacity of the low-pressure shale gas reservoir in the complex tectonic region outside of the Sichuan Basin.