Geology topics

Tongwei Zhang

Publications and source records attributed to Tongwei Zhang.

At least 19 recordsLinked to original sources

USGS2024

Insights on using solid bitumen reflectance as a thermal maturity proxy in the Bakken Formation, Williston Basin, USA

To further refine the use of solid bitumen reflectance (BR o in %) as a measurement of thermal maturity in source-rock reservoirs, we examined its relationship to other thermal proxies in the Bakken Formation. Comparisons included criteria from programmed temperature pyrolysis, gas chromatography (GC), and Fourier transform infrared (FTIR) spectroscopy. Thirty-two organic-rich samples from the lower and upper shale members of the Devonian–Lower Carboniferous Bakken Formation were collected from eight cores across the Williston Basin, USA, at depths (∼7575–11,330 ft) representing immature through post peak oil/early condensate thermal maturity conditions based on proximity to current hydrocarbon production. Unmodified BR o values were correlated to programmed temperature pyrolysis parameters (hydrogen index, production index, and T max ), normal hydrocarbon and isoprenoid analysis of extractable organic matter (pristane/ n -C 17 and phytane/ n -C 18 ) from GC analysis, and peak ratios from FTIR spectroscopy (branching ratio and A -factor). Strong correlations between unmodified BR o values (not corrected to a vitrinite reflectance equivalent, VR e ) and other thermal proxies suggest that BR o can be used as a direct thermal proxy in marine Paleozoic source-rock reservoirs where vitrinite is rare or absent. Moreover, an apparent overestimation of VR e at the lowest thermal maturity investigated herein may argue against the application of BR o conversion to VR e in the Bakken Formation. Solvent extraction caused a consistent decrease in BR o when average post-extraction values from a given well were compared to BR o prior to extraction, although the decrease in mean value was not statistically significant. These results are discussed in the context of advocating for the use of unmodified BR o values as a best practice for thermal maturity determination in Paleozoic marine source-rock reservoirs.

Montana, North Dakota↗

USGS2021

Meter-scale lithofacies cycle and controls on variations in oil saturation, Wolfcamp A, Delaware and Midland Basins

Typical meter-scale lithofacies cycles from the Wolfcamp A in the Delaware and Midland Basins comprise basal carbonate facies overlain by calcareous or siliceous mudrocks. Siliceous mudstones are the most organic-rich facies with high total organic carbon ( TOC > 3 wt. %), whereas thin carbonate beds have the lowest organic matter (OM) content among the lithofacies present ( TOC TOC, programmed pyrolysis analysis, and residual gas analysis from rock crushing. Oil saturation index ( OSI ) (the amount of free oil normalized by TOC ; OSI = S 1 × 100/ TOC ) is used as an indicator of oil enrichment or depletion in the reservoir, where S 1 is volatile oil in programmed pyrolysis (temperature = 300°C). Both TOC -lean carbonate and TOC -rich mudstone lithofacies have high OSI in these meter-scale cycles (average OSI is 124.5 mg HC/g TOC for carbonate beds), indicating that migrated oil is present. Residual gas analyses show lower dryness values (C 1 /C 1–5 ) and higher oil indicator values (100 × C 4+5 /C 1–5 ) in TOC -lean carbonate beds compared to the TOC -rich mudstones, likely indicating a cumulative oil and gas charging effect through source rock maturation. Oil and gas generated at different stages of thermal maturation were partially expelled from OM-rich siliceous/calcareous mudstones into adjacent OM-lean carbonate beds. This study shows oil expulsion from source to adjacent carbonate beds is a key factor in variations of oil saturation in the Wolfcamp A.

AAPG Bulletin↗

USGS2020

Organic petrography of Leonardian (Wolfcamp A) mudrocks and carbonates, Midland Basin, Texas: The fate of oil-prone sedimentary organic matter in the oil window

To better understand evolution of oil-prone sedimentary organic matter to petroleum and expulsion from source rock, we evaluated organic petrographic features of Leonardian Wolfcamp A repetitive siliceous and calcareous mudrock and fine-grained carbonate lithofacies cycles occurring in the R. Ricker #1 core from Reagan County, Midland Basin, Texas. The objectives of the petrographic investigation were to estimate thermal maturity, identify organic matter types and abundances, and identify the presence or absence of migrated hydrocarbons in organic-lean carbonate layers. An integrated analytical program included geochemical screening [total organic carbon (TOC) content by LECO, programmed pyrolysis by hydrocarbon analyzer with kinetics (HAWK) including analysis of solvent-extracted samples], X-ray diffraction mineralogy, organic petrography, scanning electron microscopy with energy dispersive spectroscopy (SEM-EDS) including correlative light and electron microscopy (CLEM), and micro-Fourier transform infrared spectroscopy (μ-FTIR) analyses of solid bitumen. The data indicate all samples are early to middle oil window thermal maturity with solid bitumen reflectance (BR o ) values of 0.55–0.86% and T max of 440–455 °C. Organic matter is predominantly solid bitumen (as identified by optical microscopy) in all lithofacies with minor contributions from inertinite. Solid bitumen abundance decreases from siliceous mudrock (TOC >3.0 wt%) to calcareous mudrock (TOC 1.0 to 3.0 wt%) to fine-grained carbonate (TOC <1.0 wt%) lithofacies. Interpretations of petrographic data suggest siliceous and calcareous mudrocks are source rock lithofacies and contain solid bitumen (with petroleum generation potential) that is residual (what remains) from conversion of an original Type II sedimentary organic matter. In turn, fine-grained carbonates are interpreted as reservoir lithofacies which contained little or no original oil-prone sedimentary organic matter and at present-day contain only a minor component of migrated solid petroleum sourced from adjacent siliceous and calcareous mudrock lithofacies. This work helps to document petroleum generation and migration processes, improve unconventional reservoir characterization and better define areas of oil window thermal maturity in an area critical to United States hydrocarbon production.

Texas↗

USGS2019

Kinetics of elemental sulfur reduction by petroleum hydrocarbons and the implications for hydrocarbon thermal chemical alteration

Although sulfur-containing compounds are known to play a significant role in the diagenic and catagenic processes that generate oil and gas, relatively little is known about the kinetics of reactions between elemental S and petroleum hydrocarbons. To investigate this subject, a series of closed-system pyrolysis experiments using paraffin, a low-sulfur oil, and a high-sulfur oil with and without elemental S were conducted, and first-order chemical kinetics were fit to the experimental results. The average value for the activation energy required to reduce elemental S to H 2 S and to thermochemically alter higher molecular weight hydrocarbons to methane was calculated to be 193 kJ mol -1 (46 kcal mol -1 ). The results of this study demonstrate that under typical geologic conditions the rate of reduction of elemental S to H 2 S by petroleum hydrocarbons is quite rapid. The maximum time for substantial amounts of elemental S to persist in contact with petroleum hydrocarbons is estimated to be no more than a few million years in cool reservoirs (e.g., <80 °C), and in hotter reservoirs (e.g., >120 °C) the half-life of elemental S may be as short as hundreds of years. Additionally, the presence of elemental S substantially lowers the onset temperature of hydrocarbon thermal chemical alteration (TCA). The activation energy for TCA of a low-sulfur oil to generate methane is estimated to be lowered by 92 kJ mol -1 (22 kcal mol -1 ) due to the presence of elemental sulfur. Consequently, the presence of elemental S in petroleum reservoirs is expected to lower the thermal stability of oil and decrease the maximum depth at which oil occurs within a basin (thermal deadline). The observed acceleration of hydrocarbon TCA is possibly due to organic sulfur compounds (e.g., thiols and sulfides) that form through the reaction of H 2 S or polysulfides with hydrocarbons and subsequently thermally degrade leading to the formation of sulfur radicals that in turn enhance TCA reactions.

Geochimica et Cosmochimica Acta↗

USGS2018

Pore-types and pore-network evolution in Upper Devonian-Lower Mississippian Woodford and Mississippian Barnett mudstones: Insights from laboratory thermal maturation and organic petrology

Pore-evolution models from immature organic-matter (OM) -rich Barnett (0.42%R o ) and Woodford (0.49%R o ) mudstones were compared with models previously developed from low-maturity OM-lean Boquillas (Eagle Ford-equivalent) mudstones to investigate whether (1) different mineralogy (siliceous vs. calcareous) exerts different catalytic and sorption effects and influences OM-pore origin and evolution; and (2) different types of macerals show different OM pore evolution history. Laboratory gold-tube pyrolysis, scanning electron microscopy (SEM) and thin-section petrography, organic petrography, and geochemical characterization were used to investigate the role of bulk mineralogy, maceral type, and thermal maturation on OM-pore evolution. Results suggest that mineralogy has little impact on OM-pore development and evolution. Macerals, identified using both SEM (platy OM, particulate OM, organic–mineral admixtures, Tasmanites ) and organic petrology (vitrinite, inertinite, amorphous organic matter [AOM]/bituminite, telalginite [ Leiosphaeridia , Tasmanites ]), do affect the origin and evolution of OM pores owing to differences in chemical compositions, generation kinetics, and activation-energy distributions between Tasmanites , matrix bituminite, and other types of macerals. Leiosphaeridia and Tasmanites in Woodford mudstone samples exhibit a delay in onset and a shorter period of petroleum generation and pore development compared to the matrix bituminite in the Barnett and Woodford mudstone samples. Pre-oil solid bitumen was observed to have migrated into initial primary mineral pore networks at the bitumen generation stage in both Barnett and Woodford samples. At higher levels of thermal maturation, the volume of primary mineral pores decreases and the pore volume composed of modified mineral pores and OM pores becomes greater. Pore evolution and pore-type heterogeneity in these mudstones is a function of the initial mineral pore network, types of kerogen and macerals, and generation kinetics of individual macerals upon thermal maturation.

Oklahoma↗

USGS2018

Experimental investigation of the role of rock fabric in gas generation and expulsion during thermal maturation: Anhydrous closed-system pyrolysis of a bitumen-rich Eagle Ford Shale

Gold-tube pyrolysis experiments were conducted on miniature core plugs and powdered rock from a bitumen-rich sample of Eagle Ford Shale to investigate the role of rock fabric in gas generation and expulsion during thermal maturation. The samples were isothermally heated at 130, 300, 310, 333, 367, 400, and 425 °C for 72 h under a confining pressure of 68.0 MPa, corresponding to six levels of induced thermal maturity: pre-oil generation (130 °C/72 h), incipient oil/bitumen generation (300 and 310 °C/72 h), early oil generation (333 °C/72 h), peak oil generation (367 °C/72 h), early oil cracking (400 °C/72 h), and late oil cracking (425 °C/72 h). Experimental results show that gas retention coupled with compositional fractionation occurs in the core plug experiments and varies as a function of thermal maturity. During the incipient oil/bitumen generation stage, yields of methane through pentane (C 1 –C 5 ) from core plugs are significantly lower than those from rock powder, and gases from core plugs are enriched in methane. However, the differences in C 1 –C 5 gas yield and composition decrease throughout the oil generation stage, and by the oil cracking stage no obvious compositional difference in C 1 –C 5 gases exists. The decrease in the effect of rock fabric on gas yield and composition with increasing maturity is the result of an increase in gas expulsion efficiency. Pyrolysis of rock powder yields 4–16 times more CO 2 compared to miniature core plugs, with δ 13 C CO2 values ranging from −2.9‰ to −0.6‰, likely due to carbonate decomposition accelerated by reactions with organic acids. Furthermore, lower yields of gaseous alkenes and H 2 from core plug experiments sugge

Organic Geochemistry↗

USGS2017

Depositional environment and organic matter accumulation of Upper Ordovician–Lower Silurian marine shale in the Upper Yangtze Platform, South China

The main controlling factors of organic matter accumulation in the Upper Ordovician Wufeng–Lower Silurian Longmaxi Formations are complex and remain highly controversial. This study investigates the vertical variation of total organic carbon (TOC) content as well as major and trace element concentrations of four Ordovician–Silurian transition sections from the Upper Yangtze Platform of South China to reconstruct the paleoenvironment of these deposits and to improve our understanding of those factors that have influenced organic matter accumulation in these deposits. The residual TOC content of the Wufeng Formation averages 3.2% and ranges from 0.12 to 6.0%. The overlying lower Longmaxi Formation displays higher TOC content (avg. 4.4%), followed upsection by consistent and lower values that average 1.6% in the upper Longmaxi Formation. The concentration and covariation of redox-sensitive trace elements (Mo, U and V) suggest that organic-rich intervals of the Wufeng Formation accumulated under predominantly anoxic conditions. Organic-rich horizons of the lower Longmaxi Formation were deposited under strongly anoxic to euxinic conditions, whereas organic-poor intervals of the upper Longmaxi Formation accumulated under suboxic conditions. Positive correlations between redox proxies and TOC contents suggest that organic matter accumulation was predominantly controlled by preservation. Barium excess (Ba xs ) values indicate high paleoproductivity throughout the entire depositional sequence, with an increase in the lower Longmaxi Formation. Increased productivity may have been induced by enhanced P recycling, as evidenced by elevated C org /P tot ratios. Mo–U covariation and Mo/TOC values reveal that the Wufeng Formation was deposited under extremely restricted conditions, whereas the Longmaxi Formation accumulated under moderately restricted conditions. During the Late Ordovician, the extremely restricted nature of ocean circulation on the Upper Yangtze Platform in tandem with enhanced stratification of the water column promoted anoxic conditions favorable for the preservation of organic matter. During Early Silurian time, organic matter accumulation was principally controlled by changes in sea level, which affected terrigenous flux, redox conditions, and the degree of nutrition recycling.

Upper Yangtze Platform↗

USGS2017

Organic petrology of peak oil maturity Triassic Yanchang Formation lacustrine mudrocks, Ordos Basin, China

An organic petrology evaluation and a determination of solid bitumen reflectance BR o "> BR o were completed for organic-rich Triassic Yanchang Formation mudrocks ( n = 15 "> n = 15 ) from the Ordos Basin, north-central China, as part of a larger investigation of “shale gas” resources. These data were integrated with information from Rock-Eval programmed pyrolysis to show that the samples are in the peak oil window of thermal maturity and that organic matter is dominated by solid bitumen with minor amounts of type III kerogen (vitrinite and inertinite) from vascular land plants. Describing a “kerogen type” for these rocks based strictly on parameters determined from programmed pyrolysis is misleading because the original organic matter has converted to hydrocarbons (present as solid bitumen), a large proportion of which may have been expelled into adjacent reservoir facies. However, based on the comparison with immature-early mature lacustrine mudrock (Garden Gulch Member of Green River Formation) and marine shale (Boquillas Formation), we suggest that the original organic matter in the organic-rich samples examined for our study may have been type I/II kerogen with hydrogen index values of > 700    mg   HC / g "> > 700 mg HC / g TOC.

Ordos basin↗

USGS2017

Liquid hydrocarbon characterization of the lacustrine Yanchang Formation, Ordos Basin, China: Organic-matter source variation and thermal maturity

Source-rock samples from the Upper Triassic Yanchang Formation in the Ordos Basin of China were geochemically characterized to determine variations in depositional environments, organic-matter (OM) source, and thermal maturity. Total organic carbon (TOC) content varies from 4 wt% to 10 wt% in the Chang 7, Chang 8, and Chang 9 members — the three OM-rich shale intervals. The Chang 7 has the highest TOC and hydrogen index values, and it is considered the best source rock in the formation. Geochemical evidence indicates that the main sources of OM in the Yanchang Formation are freshwater lacustrine phytoplanktons, aquatic macrophytes, aquatic organisms, and land plants deposited under a weakly reducing to suboxic depositional environment. The elevated C 29 "> C 29 sterane concentration and depleted δ C 13 "> δ 13 C values of OM in the middle of the Chang 7 may indicate the presence of freshwater cyanobacteria blooms that corresponds to a period of maximum lake expansion. The OM deposited in deeper parts of the lake is dominated by oil-prone type I or type II kerogen or a mixture of both. The OM deposited in shallower settings is characterized by increased terrestrial input with a mixture of types II and III kerogen. These source rocks are in the oil window, with maturity increasing with burial depth. The measured solid-bitumen reflectance and calculated vitrinite reflectance from the temperature at maximum release of hydrocarbons occurs during Rock-Eval pyrolysis ( T max "> T max ) and the methylphenanthrene index (MPI-1) chemical maturity parameters range from 0.8 to 1.05 % R o "> 1.05 % R o . Because the thermal labilities of OM are associated with the kerogen type, the required thermal stress for oil generation from types I and II mixed kerogen has a higher and narrower range of temperature for hydrocarbon generation than that of OM dominated by type II kerogen or types II and III mixed kerogen deposited in the prodelta and delta front.

Ordos basin↗

USGS2017

Controls on pore types and pore-size distribution in the Upper Triassic Yanchang Formation, Ordos Basin, China: Implications for pore-evolution models of lacustrine mudrocks

Our main objectives are to (1) learn if pore-evolution models developed from marine mudrocks can be directly applied to lacustrine mudrocks, (2) investigate what controls the different pore types and sizes of Chang 7 organic matter (OM)-rich argillaceous mudstones of the Upper Triassic Yanchang Formation, and (3) describe the texture, fabric, mineralogy, and thermal maturity variation in the Chang 7 mudstones. Lacustrine mudstones from nine cored wells along a depositional dip in the southeastern Ordos Basin, China, were investigated. Helium porosimetry, nitrogen adsorption, and field-emission scanning electron microscopy of Ar-ion milled samples were applied. Measured average total porosity of samples from a proximal to distal transect ( ϕ = 5.0 % "> ϕ = 5.0 % ) is higher than those from the two adjacent cored wells ( ϕ = 2.3 % "> ϕ = 2.3 % ). This difference in porosity partly caused by differences in the clay mineral content implies that in the fluvial-deltaic-lacustrine depositional environment, reservoir quality can vary significantly in a short distance. Owing to the uneven distribution of the sample set from proximal to distal area, we mainly evaluate variations in the proximal setting. Results from nitrogen-gas adsorption experiments show that there are four distinct patterns of pore-size distribution within the Chang 7 member of the Yanchang Formation with no particular correlation with mineralogical composition and thermal maturity. The pore network within Chang 7 mudstones is dominated by OM-hosted pores, with a lesser abundance of interparticle and intraparticle pores. The size distribution of mineral-hosted pores within these mudstones is found to be closely related to the rock texture (sorting and grain size) and fabric. Mudstones with well-sorted grains and a higher percentage of coarser grains have more abundant mineral pores. The sizes of OM-hosted pores in these compaction-dominated lacustrine mudstones were one to two orders of magnitude smaller than those in the marine mudstones that display abundant early cementation.

Ordos basin↗

USGS2015

Introduction to special section: China shale gas and shale oil plays

In the last 10 years, the success of shale gas and shale oil productions as a result of technological advances in horizontal drilling, hydraulic fracturing and nanoscale reservoir characterization have revolutionized the energy landscape in the United States. Resource assessment by the China Ministry of Land and Resources in 2010 and 2012 and by the U.S. Energy Information Administration in 2011 and 2013 indicates China’s shale gas resource is the largest in the world and shale oil resource in China is also potentially significant. Inspired by the success in the United States, China looks forward to replicating the U.S. experience to produce shale gas to power its economy and reduce greenhouse gas emissions. By 2014, China had drilled 400 wells targeting marine, lacustrine, and coastal swamp transitional shales spanning in age from the Precambrian to Cenozoic in the last five years. So far, China is the leading country outside of North America in the viable production of shale gas, with very promising prospects for shale gas and shale oil development, from the Lower Silurian Longmaxi marine shale in Fuling in the southeastern Sichuan Basin. Geological investigations by government and academic institutions as well as exploration and production activities from industry indicate that the tectonic framework, depositional settings, and geomechanical properties of most of the Chinese shales are more complex than many of the producing marine shales in the United States. These differences limit the applicability of geologic analogues from North America for use in Chinese shale oil and gas resource assessments, exploration strategies, reservoir characterization, and determination of optimal hydraulic fracturing techniques. Understanding the unique features of the geology, shale oil and gas resource potential, and reservoir characteristics is crucial for sweet spot identification, hydraulic fracturing optimization, and reservoir performance prediction. Even though China shale gas and shale oil exploration is still in an early stage, limited data are already available. We are pleased to have selected eight high-quality papers from fifteen submitted manuscripts for this timely section on the topic of China shale gas and shale oil plays. These selected papers discuss various subject areas including regional geology, resource potentials, integrated and multidisciplinary characterization of China shale reservoirs (geology, geophysics, geochemistry, and petrophysics) China shale property measurement using new techniques, case studies for marine, lacustrine, and transitional shale deposits in China, and hydraulic fracturing. One paper summarizes the regional geology and different tectonic and depositional settings of the major prospective shale oil and gas plays in China. Four papers concentrate on the geology, geochemistry, reservoir characterization, lithologic heterogeneity, and sweet spot identification in the Silurian Longmaxi marine shale in the Sichuan Basin in southwest China, which is currently the primary focus of shale gas exploration in China. One paper discusses the Ordovician Salgan Shale in the Tarim Basin in northwest China, and two papers focus on the reservoir characterization and hydraulic fracturing of Triassic lacustrine shale in the Ordos Basin in northern China. Each paper discusses a specific area.

Interpretation↗

USGS2014

Experimental investigation of changes in methane adsorption of bitumen-free Woodford Shale with thermal maturation induced by hydrous pyrolysis

This study quantifies the effects of organic-matter (OM) thermal maturity on methane (CH 4 ) sorption, on the basis of five samples that were artificially matured through hydrous pyrolysis achieved by heating samples of immature Woodford Shale under five different time–temperature conditions. CH 4 -sorption isotherms at 35 °C, 50 °C, and 65 °C, and pressures up to 14 MPa on dry, solvent-extracted samples of the artificially matured Woodford Shale were measured. The results showed that CH 4 -sorption capacity, normalized to TOC, varied with thermal maturity, following the trend: maximum oil (367 °C) > oil cracking (400 °C) > maximum bitumen/early oil (333 °C) > early bitumen (300 °C) > immature stage (130 °C). The Langmuir constants for the samples at maximum-oil and oil-cracking stages are larger than the values for the bitumen-forming stages. The total pore volume, determined by N 2 physisorption at 77 K, increases with increased maturation: mesopores, 2–50 nm in width, were created during the thermal conversion of organic-matter and a dramatic increase in porosity appeared when maximum-bitumen and maximum-oil generation stages were reached. A linear relationship between thermal maturity and Brunauer–Emmett–Teller (BET) surface area suggests that the observed increase in CH 4 -sorption capacity may be the result of mesopores produced during OM conversion. No obvious difference is observed in pore-size distribution and pore volume for samples with pores <2.0 nm with the increase of thermal maturity based on CO 2 physisorption at 273 K. The isosteric heat of adsorption and the standard entropy for artificially matured samples ranged from 17.9 kJ mol −1 to 21.9 kJ mol −1 and from −85.4 J mol −1 K −1 to −101.8 J mol −1 K −1 , respectively. These values are similar to the values of immature Woodford kerogen concentrate previously observed, but are larger than naturally matured organic-rich shales. High-temperature hydrous pyrolysis might have induced Lewis acid sites on both organic and mineral surfaces, resulting to some extent, in chemical interactions between the adsorption site and the methane C–H bonds. The formation of abundant mesopores (2–50 nm) within organic matter during organic-matter thermal maturation makes a great contribution to the increase in both BET surface area and pore volume, and a significant increase in 2–6 nm pores occurs at maximum-oil-generation and oil-cracking to gas, ultimately controlling the methane-adsorption capacity. Therefore, consideration of pore-size effects and thermal maturity is very important for gas in place (GIP) prediction in organic-rich shales.

Marine and Petroleum Geology↗

USGS2013

Effect of organic matter properties, clay mineral type and thermal maturity on gas adsorption in organic-rich shale systems

A series of CH 4 adsorption experiments on natural organic-rich shales, isolated kerogen, clay-rich rocks, and artificially matured Woodford Shale samples were conducted under dry conditions. Our results indicate that physisorption is a dominant process for CH 4 sorption, both on organic-rich shales and clay minerals. The Brunauer–Emmett–Teller (BET) surface area of the investigated samples is linearly correlated with the CH 4 sorption capacity in both organic-rich shales and clay-rich rocks. The presence of organic matter is a primary control on gas adsorption in shale-gas systems, and the gas-sorption capacity is determined by total organic carbon (TOC) content, organic-matter type, and thermal maturity. A large number of nanopores, in the 2–50 nm size range, were created during organic-matter thermal decomposition, and they significantly contributed to the surface area. Consequently, methane-sorption capacity increases with increasing thermal maturity due to the presence of nanopores produced during organic-matter decomposition. Furthermore, CH 4 sorption on clay minerals is mainly controlled by the type of clay mineral present. In terms of relative CH 4 sorption capacity: montmorillonite ≫ illite – smectite mixed layer > kaolinite > chlorite > illite. The effect of rock properties (organic matter content, type, maturity, and clay minerals) on CH 4 adsorption can be quantified with the heat of adsorption and the standard entropy, which are determined from adsorption isotherms at different temperatures. For clay-mineral rich rocks, the heat of adsorption (q) ranges from 9.4 to 16.6 kJ/mol. These values are considerably smaller than those for CH 4 adsorption on kerogen (21.9–28 kJ/mol) and organic-rich shales (15.1–18.4 kJ/mol). The standard entropy (Δs°) ranges from -64.8 to -79.5 J/mol/K for clay minerals, -68.1 to -111.3 J/mol/K for kerogen, and -76.0 to -84.6 J/mol/K for organic-rich shales. The affinity of CH 4 molecules for sorption on organic matter is stronger than for most common clay minerals. Thus, it is expected that CH 4 molecules may preferentially occupy surface sites on organic matter. However, active sites on clay mineral surfaces are easily blocked by water. As a consequence, organic-rich shales possess a larger CH 4 -sorption capacity than clay-rich rocks lacking organic matter. The thermodynamic parameters obtained in this study can be incorporated into model predictions of the maximum Langmuir pressure and CH 4 - sorption capacity of shales under reservoir temperature and pressure conditions.

Conference Paper↗

USGS2012

Kinetics of uncatalyzed thermochemical sulfate reduction by sulfur-free paraffin

To determine kinetic parameters of sulfate reduction by hydrocarbons (HC) without the initial presence of low valence sulfur, we carried out a series of isothermal gold-tube hydrous-pyrolysis experiments at 320, 340, and 360 °C under a constant confined pressure of 24.1 MPa. The reactants used consisted of saturated HC (sulfur-free) and CaSO 4 in an aqueous solution buffered to three different pH conditions without the addition of elemental sulfur (S 8 ) or H 2 S as initiators. H 2 S produced in the course of reaction was proportional to the extent of the reduction of CaSO 4 that was initially the only sulfur-containing reactant. Our results show that the in situ pH of the aqueous solution (herein, in situ pH refers to the calculated pH value of the aqueous solution at certain experimental conditions) can significantly affect the rate of the thermochemical sulfate reduction (TSR) reaction. A substantial increase in the TSR reaction rate was observed with a decrease in the in situ pH. Our experimental results show that uncatalyzed TSR is a first-order reaction. The temperature dependence of experimentally measured H 2 S yields from sulfate reduction was fit with the Arrhenius equation. The determined activation energy for HC (sulfur-free) reacting with View the MathML sourceHSO 4 − in our experiments is 246.6 kJ/mol at pH values ranging from 3.0 to 3.5, which is slightly higher than the theoretical value of 227.0 kJ/mol using ab initio quantum chemical calculations on a similar reaction. Although the availability of reactive sulfate significantly affects the rate of reaction, a consistent rate constant was determined by accounting for the HSO 4 − ion concentration. Our experimental and theoretical approach to the determination of the kinetics of TSR is further validated by a reevaluation of several published experimental TSR datasets without the initial presence of native sulfur or H 2 S. When the effect of reactive sulfate concentration is appropriately accounted for, the published experimental TSR data yield kinetic parameters that are consistent with our values. Assuming MgSO 4 contact-ion-pair ([MgSO 4 ]CIP) as the reactive form of sulfate in petroleum reservoir formation waters, a simple extrapolation of our experimentally derived HSO 4 − reduction kinetics as a proxy for [MgSO 4 ]CIP to geologically reasonable conditions predicts onset temperatures (130–140 °C) that are comparable to those observed in nature.

Geochimica et Cosmochimica Acta↗

USGS2012

Effect of organic-matter type and thermal maturity on methane adsorption in shale-gas systems

A series of methane (CH 4 ) adsorption experiments on bulk organic rich shales and their isolated kerogens were conducted at 35 °C, 50 °C and 65 °C and CH 4 pressure of up to 15 MPa under dry conditions. Samples from the Eocene Green River Formation, Devonian–Mississippian Woodford Shale and Upper Cretaceous Cameo coal were studied to examine how differences in organic matter type affect natural gas adsorption. Vitrinite reflectance values of these samples ranged from 0.56–0.58 %R o . In addition, thermal maturity effects were determined on three Mississippian Barnett Shale samples with measured vitrinite reflectance values of 0.58, 0.81 and 2.01 %R o . For all bulk and isolated kerogen samples, the total amount of methane adsorbed was directly proportional to the total organic carbon (TOC) content of the sample and the average maximum amount of gas sorption was 1.36 mmol of methane per gram of TOC. These results indicate that sorption on organic matter plays a critical role in shale-gas storage. Under the experimental conditions, differences in thermal maturity showed no significant effect on the total amount of gas sorbed. Experimental sorption isotherms could be fitted with good accuracy by the Langmuir function by adjusting the Langmuir pressure (P L ) and maximum sorption capacity (Γ max ). The lowest maturity sample (%R o = 0.56) displayed a Langmuir pressure (P L ) of 5.15 MPa, significantly larger than the 2.33 MPa observed for the highest maturity (%R o > 2.01) sample at 50 °C. The value of the Langmuir pressure (P L ) changes with kerogen type in the following sequence: type I > type II > type III. The thermodynamic parameters of CH 4 adsorption on organic rich shales were determined based on the experimental CH 4 isotherms. For the adsorption of CH4 on organic rich shales and their isolated kerogen, the heat of adsorption (q) and the standard entropy (Δs 0 ) range from 7.3–28.0 kJ/mol and from −36.2 to −92.2 J/mol/K, respectively.

Organic Geochemistry↗

USGS2011

Monitoring a large volume CO2 injection: Year two results from SECARB project at Denbury’s Cranfield, Mississippi, USA

The Southeast Regional Carbon Sequestration Partnership (SECARB) early project in western Mississippi has been testing monitoring tools and approaches to document storage efficiency and storage permanence under conditions of CO 2 EOR as well as downdip injection into brine. Denbury Onshore LLC is host for the study and has brought a depleted oil and gas reservoir, Cranfield Field, under CO 2 flood. Injection was started in July 2008 and has now achieved injection rates greater than 1.2 million tons/year though 23 wells, with cumulative mass injected as of August, 2010 of 2.2 million metric tons. Injection is into coarse grained fluvial deposits of the Cretaceous lower Tuscaloosa Formation in a gentle anticline at depths of 3300 m. A team of researchers from 10 institutions has collected data from five study areas, each with a different goal and different spatial and temporal scale. The Phase 2 study began at the start of injection and has been using pressure and temperature as a tool for assessing permanence mostly in the oil productive interval. Real-time read-out shows high sensitivity to distant changes in injection rate and confirms the geologic model of reservoir compartmentalization. Above-zone pressure monitoring &sim;120 m above the injection interval is used to test the sensitivity of this approach for documentation of integrity of the confining system in an area of numerous well completions as pressure increase is induced in the reservoir by more than 70 bar. Monitoring of the High Volume Injection Test (HiVIT) area includes repeat measurements of aqueous geochemistry in the injection zone. Rock-water- CO 2 interactions in the reservoir as CO 2 dissolves are minimized by mineral “armoring” by abundant chlorite cement in high permeability reservoir sandstone. Geochemical monitoring of confined freshwater aquifers at depths of 70–100 m is underway. Groundwater analysis focuses on assessment of the sensitivity of this method to detect leakage above background variability. A repeat seismic survey of the HiVIT is planned for late 2010 to assess saturation change especially in downdip brine-only areas. A study focused on feasibility of monitoring the shallow subsurface to separate leakage from normal complex surface fluxes is underway at an monitoring array installed in October 2009 to assess the interactions of recharge, soil gas, and shallow groundwater aquifers. Recent well re-entry and tracer injection will provide further information to interpret observed elevated deep-sourced methane. The Detailed Area Study (DAS) is collecting dense time-lapse data from closely-spaced three well array of an injector and two observation wells. The observation wells were completed with fiberglass casing to facilitate electrical resistance tomography (ERT) measurements, and a diverse array of instrumentation was both cemented behind casing and suspended on tubing. Injection started at the DAS December 1, 2009. We have measured pulsed neutron and resistivity via wireline, downhole and above-zone pressure, distributed temperature, and fluid chemistry including introduced pulses of perfluorocarbons, noble gases, and SF6 as tracers. Between wells, time-lapse crosswell seismic and electrical resistance tomography (ERT) are used to measure saturation change. The goals are to measure changes as fluids evolve from single phase (brine) to two phase (CO 2 –brine) in order to document linkages between pressure and sweep efficiency. A time-lapse VSP survey bridges the vertical resolution and areal coverage between cross-well and surface seismic. The repeat surveys for many tools are scheduled for September, 2010. Reservoir characterization based on cores, historic and new wireline log data, production history, hydrologic tests, fluid analysis, and a three-D seismic survey have been used in multiple numerical models to predict reservoir response in order to design effective monitoring strategies and optimize deployment. History matching of observed response to predicted response is used to interpret results and improve confidence in conceptual models and numerical approaches. Probabilistic methods have been used to assess the significant uncertainties resulting from reservoir heterogeneity.

Mississippi↗

USGS2008

The role of labile sulfur compounds in thermal chemical sulfate reduction

The reduction of sulfate to sulfide coupled with the oxidation of hydrocarbons to carbon dioxide, commonly referred to as thermochemical sulfate reduction (TSR), is an important abiotic alteration process that most commonly occurs in hot carbonate petroleum reservoirs. In the present study we focus on the role that organic labile sulfur compounds play in increasing the rate of TSR. A series of gold-tube hydrous pyrolysis experiments were conducted with n -octane and CaSO 4 in the presence of reduced sulfur (e.g. H 2 S, S°, organic S) at temperatures of 330 and 356 °C under a constant confining pressure. The in-situ pH was buffered to 3.5 (∼6.3 at room temperature) with talc and silica. For comparison, three types of oil with different total S and labile S contents were reacted under similar conditions. The results show that the initial presence of organic or inorganic sulfur compounds increases the rate of TSR. However, organic sulfur compounds, such as 1-pentanethiol or diethyldisulfide, were significantly more effective in increasing the rate of TSR than H 2 S or elemental sulfur (on a mole S basis). The increase in rate is achieved at relatively low concentrations of 1-pentanethiol, less than 1 wt% of the total n -octane, which is comparable to the concentration of organic S that is common in many oils (∼0.3 wt%). We examined several potential reaction mechanisms to explain the observed reactivity of organic LSC. First, the release of H 2 S from the thermal degradation of thiols was discounted as an important mechanism due to the significantly greater reactivity of thiol compared to an equivalent amount of H 2 S. Second, we considered the generation of olefines in association with the elimination of H 2 S during thermal degradation of thiols because olefines are much more reactive than n -alkanes during TSR. In our experiments, olefines increased the rate of TSR, but were less effective than 1-pentanethiol and other organic LSC. Third, the thermal decomposition of organic LSC creates free-radicals that in turn might initiate a radical chain-reaction that creates more reactive species. Experiments involving radical initiators, such as diethyldisulfide and benzyldisulfide, did not show an increase in reactivity compared to 1-pentanethiol. Therefore, we conclude that none of these can sufficiently explain our observations of the initial stages of TSR; they may, however, be important in the later stages. In order to gain greater insight into the potential mechanism for the observed reactivity of these organic sulfur compounds during TSR, we applied density functional theory-based molecular modeling techniques to our system. The results of these calculations indicate that 1-pentanethiol or its thermal degradation products may directly react with sulfate and reduce the activation energy required to rupture the first S–O bond through the formation of a sulfate ester. This study demonstrates the importance of labile sulfur compounds in reducing the onset timing and temperature of TSR. It is therefore essential that labile sulfur concentrations are taken into consideration when trying to make accurate predictions of TSR kinetics and the potential for H 2 S accumulation in petroleum reservoirs.

Geochimica et Cosmochimica Acta↗

USGS2008

Experimental investigation on thermochemical sulfate reduction by H2S initiation

Hydrogen sulfide (H 2 S) is known to catalyze thermochemical sulfate reduction (TSR) by hydrocarbons (HC), but the reaction mechanism remains unclear. To understand the mechanism of this catalytic reaction, a series of isothermal gold-tube hydrous pyrolysis experiments were conducted at 330 °C for 24 h under a constant confining pressure of 24.1 MPa. The reactants used were saturated HC (sulfur-free) and CaSO 4 in the presence of variable H 2 S partial pressures at three different pH conditions. The experimental results showed that the in - situ pH of the aqueous solution (herein, in - situ pH refers to the calculated pH of aqueous solution under the experimental conditions) can significantly affect the rate of the TSR reaction. A substantial increase in the TSR reaction rate was recorded with a decrease in the in - situ pH value of the aqueous solution involved. A positive correlation between the rate of TSR and the initial partial pressure of H 2 S occurred under acidic conditions (at pH ∼3–3.5). However, sulfate reduction at pH ∼5.0 was undetectable even at high initial H 2 S concentrations. To investigate whether the reaction of H 2 S (aq) and HSO 4 - "> HSO4- occurs at pH ∼3, an additional series of isothermal hydrous pyrolysis experiments was conducted with CaSO 4 and variable H 2 S partial pressures in the absence of HC at the same experimental temperature and pressure conditions. CaSO 4 reduction was not measurable in the absence of paraffin even with high H 2 S pressure and acidic conditions. These experimental observations indicate that the formation of organosulfur intermediates from H 2 S reacting with hydrocarbons may play a significant role in sulfate reduction under our experimental conditions rather than the formation of elemental sulfur from H 2 S reacting with sulfate as has been suggested previously (Toland W. G. (1960) Oxidation of organic compounds with aqueous sulphate. J. Am. Chem. Soc. 82 , 1911–1916). Quantification of labile organosulfur compounds (LSC), such as thiols and sulfides, was performed on the products of the reaction of H 2 S and HC from a series of gold-tube non-isothermal hydrous pyrolysis experiments conducted at about pH 3 from 300 to 370 °C and a 0.1-°C/h heating rate. Incorporation of sulfur into HC resulted in an appreciable amount of thiol and sulfide formation. The rate of LSC formation positively correlated with the initial H 2 S pressure. Thus, we propose that the LSC produced from H 2 S reaction with HC are most likely the reactive intermediates for H 2 S initiation of sulfate reduction. We further propose a three-step reaction scheme of sulfate reduction by HC under reservoir conditions, and discuss the geological implications of our experimental findings with regard to the effect of formation water and oil chemistry, in particular LSC content.

Geochimica et Cosmochimica Acta↗