Seismic low velocity anomalies may indicate overpressure when related to porosity anomalies due to undercompaction. However, other processes can generate overpressure without porosity anomalies such as lateral transfer. Geological pore pressure modeling can help to explain such situations. Examples will be shown with anomalously low velocities in anticlinal settings not observed in surrounding synclines.

Shale reservoirs have not benefited from advanced modeling tools to the extent of conventional resources. Thus an approach is proposed to integrate key parameters, such as total organic carbon (TOC) content, methane adsorption and organic porosity in a basin simulator. Original TOC has an impact on both gas generated volume and gas retention within source rocks. The conversion of organic matter into hydrocarbons also creates additional intraparticle kerogen porosity in which oil and gas can be stored. In this work, a method is proposed to calculate the evolution of TOC, organic porosity and gas retention capacity (free versus adsorbed) through time in shale gas by means of petroleum system modeling. Gas adsorption potential on organic material is calculated using a Langmuir model, which accounts for pressure, temperature and remaining solid TOC. Organic porosity is calculated as the result of the change of the organic matter from solid immature kerogen to less dense fluid hydrocarbons during thermal maturation.The method is tested on a 3D basin model of the Mississippian Barnett Shale in Texas (USA). The computed organic porosity varies from 0% in immature zones, to a maximum of 4% of rock volume in organic-rich and mature zones. Computed retained methane in the Lower Barnett Shale ranges between 20 and 60 scf/t (from 1 to nearly 3 kg/m(3)) and is mainly concentrated in mature areas of the basin. Simulated results are consistent with available Barnett Shale data. Possible effects of assumptions made in the approach and perspectives are discussed. (C) 2013 Elsevier Ltd. All rights reserved.

Applying basin modeling technology to predict high-resolution fluid distribution and properties, taking into account the local high resolution of the sediment properties in fields and prospects has been a growing need for the past 10 yr. To minimize simulation time, local grid refinement (LGR) techniques have been introduced. The main interest of LGR is to gain computing time and memory with respect to classical methods, such are Tartan gridding. With LGR, it is possible to define local areas with high resolution in a regional model. The LGR approach gives a more detailed picture of individual fields or prospects while using models of reasonable size. The models incorporate various regional elements of the petroleum system that include source rock and seal, for instance, to obtain a detailed understanding of local processes such as trap filling history. To validate the LGR approach, a benchmark is performed. It aims at comparing the different refinement methods: (1) a high-resolution grid, (2) an LGR grid, (3) a Tartan grid, and (4) windowing. To test the behavior of and the results produced by LGR, this method is applied to a real case study from northern Kuwait. It illustrates the coupling between LGR and compositional three-dimensional Darcy flow modeling to predict the distribution of hydrocarbon composition and properties in local reservoir rock areas where accumulations are predicted. The LGR approach efficiently fills the gap between conventional basin modeling and reservoir modeling. Its application in northern Kuwait provides useful guidelines to predict API gravities, gas-oil ratio, and oil-water contact depth estimates in new prospects.

Abstract Applying basin modeling technology to predict high-resolution fluid distribution and properties, taking into account the local high resolution of the sediment properties in fields and prospects has been a growing need for the past 10 yr. To minimize simulation time, local grid refinement (LGR) techniques have been introduced. The main interest of LGR is to gain computing time and memory with respect to classical methods, such are Tartan gridding. With LGR, it is possible to define local areas with high resolution in a regional model. The LGR approach gives a more detailed picture of individual fields or prospects while using models of reasonable size. The models incorporate various regional elements of the petroleum system that include source rock and seal, for instance, to obtain a detailed understanding of local processes such as trap filling history. To validate the LGR approach, a benchmark is performed. It aims at comparing the different refinement methods: (1) a high-resolution grid, (2) an LGR grid, (3) a Tartan grid, and (4) windowing. To test the behavior of and the results produced by LGR, this method is applied to a real case study from northern Kuwait. It illustrates the coupling between LGR and compositional three-dimensional Darcy flow modeling to predict the distribution of hydrocarbon composition and properties in local reservoir rock areas where accumulations are predicted. The LGR approach efficiently fills the gap between conventional basin modeling and reservoir modeling. Its application in northern Kuwait provides useful guidelines to predict API gravities, gas-oil ratio, and oil-water contact depth estimates in new prospects.

This paper describes a case study from the Fort Worth Basin (USA), where the occurrence of residual gas in the Barnett shale was analyzed using standard basin modeling. The aim of this work was to determine to what extent conventional petroleum system simulation approaches can be applied to an unconventional system like gas shale. A sensitivity analysis was thus performed, to quantify the dependency of the residual mass of gas in the source rock at present day, on parameters involved in the generalized Darcy flow model, i.e., permeability, relative permeability, capillary pressure and adsorption threshold parameters. We found that gas retention in the source rock was mostly controlled by the gas relative permeability, and especially the gas expulsion saturation (i.e., ‘Satex’ value). High capillary pressure in the shale favours gas expulsion, however this process remains limited compared to relative permeability and permeability effects. Surprisingly, adsorption threshold values had nearly no effect on the residual mass of gas: adsorption was indeed largely compensated by the Satex effect. These results demonstrate that conventional basin modelling can reproduce the occurrence of a gas shale play, by adjusting at least gas relative permeability parameters in the source rock, especially the Satex value.

The problem of the maintenance of the production level, entailing the industrial development of new reservoir systems is vital in Western Siberia (Russia). Such targeted systems include the deep Neocomian deposits (Achimov Fm) and Late/Middle Jurassic reservoirs. Hydrocarbon fields occur in Neocomian sandstone lenses, disseminated within silt and marine shale deposits. These reservoirs, stratigraphically associated to a large and complex system of clinoforms, correspond to both deep-water sand facies of the Achimov Fm at the base of the slope, and deltaic and shoreface sandstones interbedded with shales at the top. They contain hydrocarbons originating from the Bazhenov Fm (20-70 meters), considered as the major source rock in this basin. Late Jurassic siliceous layers underneath the Bazhenov black shale constitute another reservoir system of interest. Accumulations were discovered in Late/Middle Jurassic sandy reservoirs, but their oil and gas habitats remain undervalued to date. These reservoirs, affected by fracturing and deformation, are characterized by a series of anticlines and synclines structures separated by sub-vertical faults.

The aim of this study is to estimate biodegradation rates of petroleum in natural reservoirs. For that purpose, a cross-section along the Carnaubais trend (ENE-WSW) in the Potiguar basin (Brazil) was modeled using Temis 2D. Most biodegraded reservoir oils are located in the southwest (onshore), within the Cretaceous sandstones of the Açu units that occur at shallow depth (<1000m). Deeper reservoirs containing non-biodegraded mature oils are located in the northeast area of the section. Basin modeling predicts that fluids generated from the two main source-rock levels of the Alagamar Fm. mixed before the filling phase of the reservoirs. Therefore, a single fluid is representative of the oil filling the reservoirs before biodegradation and its composition predicted by compositional modeling is comparable to non-biodegraded natural oil samples. Compositional modeling enables the description of fluids in terms of light and heavy fraction (C14−/C14+) and the chemical proportion of saturates/aromatics and NSOs. Based on calculations of hydrocarbon losses in different reservoirs obtained in Part 1 of this study, biodegradation rates at geological time scales were calculated as a function of residence time in the reservoir, temperature history, and intensity of hydrodynamics.

The aim of this study is to estimate hydrocarbon losses in natural reservoirs due to biodegradation processes. A series of 12 non-biodegraded and biodegraded oils were selected in the Potiguar Basin (Brazil). Most biodegraded reservoir oils are located in the southwestern part of the basin (onshore), within the Cretaceous sandstones of the Agu units that occur at shallow depths (< 1000 m). Deeper reservoirs, containing non-biodegraded but mature oils, are located in the northeastern area of the basin. Based on the chemical alteration of the saturates and aromatics observed in biodegraded oils, tentative estimates of absolute losses were calculated for the light hydrocarbons (saturates and aromatics) and for the heavy fractions such as C14+ linear and cyclo-alkanes and C14+ aromatics. Together with the estimation of losses on global classes, molecular studies clearly show that biodegradation scales based on saturated and aromatic biomarkers can be used as such but do not reflect the loss percentage by biodegradation on global classes. (c) 2006 Elsevier Ltd. All rights reserved.

We have devised an experimental method for calculating isotopic mass balances for the C-12 and C-13 in the pyrolysis products from a type II kerogen during artificial maturation in a closed system. The method also enables a study of the isotopic evolution of cracking products versus kerogen transformation ratios.The type II kerogen (Paris Basin) was at the onset of catagenesis. Pyrolysis was carried out in a confined closed system under isothermal conditions, at several temperatures (275-350 degrees C) and times at a constant pressure of 10 Mpa. Under these conditions, the kerogen transformation ratios covered a range from 1% to 87%. Pyrolysis effluents were separated into hydrocarbon gases (C-1-C-5), non-hydrocarbon gases (CO, CO2, H-2, H2S), C-6-C-14 products soluble in pentane (C-6-C-14 saturated, C-6-C-14 aromatics), C14+ products soluble in pentane (C14+ saturated, C14+ aromatics, resins 1). C14+ products soluble in dichloromethane (asphaltenes and resins 2) and residue insoluble in dichloromethane.Validation of mass and atomic carbon balances plus delta C-13 measurements was checked carefully in order to obtain accurate isotopic mass balances. Mass balances on pyrolysis products were higher than 97.7% of the initial kerogen amount. The delta C-13 fractionation observed between different pyrolysis products reached 18 parts per thousand, but only 2 parts per thousand between different C14+ fractions within the range of pyrolysis conditions. (c) 2005 Elsevier Ltd. All rights reserved.

With the use of general transition state theory and density functional theory, six reference reactions that are thought to play an essential role in the thermal cracking process of 9-methylphenanthrene have been studied. At the uB3LYP/6-31G(d,p) level, the transition state structures could be located on the 0 K potential energy surface for the three propagation reactions which induce no net creation/annihilation of radicals, and the calculated activation energies and preexponential frequency factor generally correspond well to experimental values. The transition states for two termination reactions were determined by replacement of a phenanthrenic by a phenylic aromatic moiety; it followed that such model reactions represent well systems with larger aromatic units. Only for the initiation reaction the transition state could not be located; in this case the activation energy was approximated by the change in overall enthalpy.

The objectives of the study are to compare product compositions and yields generated from lignite artificially matured by open nonhydrous pyrolysis, closed nonhydrous pyrolysis, and hydrous pyrolysis. The pyrolysis products were fractionated into CO2, H2O, CH4, C2–C5, C8–C14, C14+ saturates, C14+ aromatics and NSOs (resins+asphaltenes). All three methods generated high and similar quantities of water during pyrolysis that ranged between 14.6 and 15.2 wt.% of the original lignite. As a result of this high water content generated by the lignite, the experiments with no added water are referred to as nonhydrous rather than anhydrous. Rock-Eval pyrolysis and elemental analyses were conducted on the recovered lignite after solvent extraction to determine their residual hydrocarbon generation potential and to plot their position in a van Krevelen diagram, respectively. Residual lignite from the closed nonhydrous and hydrous experiments showed relationships between vitrinite reflectance (%Ro) values and atomic H/C ratios that occurred within the fields observed for natural maturation of coal. Although no significant differences in the atomic H/C ratios were observed between closed nonhydrous and hydrous pyrolysis, the vitrinite reflectance values were on the average 0.2% Ro lower in the residual lignite from the nonhydrous experiments. The remaining hydrocarbon generation potential as determined by Rock-Eval pyrolysis of the residual lignite showed that the nonhydrous residuals had on the average 16 mg more hydrocarbon potential per gram of original lignite than the hydrous residuals. This suggests there is a better release of the pyrolysis products from the lignite network in the hydrous experiments once generation occurs. For gas generation, at maximum yields, open nonhydrous pyrolysis generates the most hydrocarbon gas (21.0 mg/g original lignite), which is 20% more than closed nonhydrous pyrolysis and 29% more than hydrous pyrolysis. Closed nonhydrous pyrolysis generates on the average 14% more gas than hydrous pyrolysis, but the proportionality of the generated hydrocarbon gases is essentially the same for both pyrolysis methods. At maximum yields, CO2 generation is greatest in hydrous pyrolysis (99.5 mg/g original lignite), with yields being 37 percent higher than closed nonhydrous pyrolysis and 26% higher than open nonhydrous pyrolysis. The maximum yields of C14+ products are highest and similar for open nonhydrous pyrolysis and hydrous pyrolysis (125.6 and 125.9 mg/g lignite, respectively), and are more than 70% higher than closed nonhydrous pyrolysis. This difference in the maximum yields of C14+ products can be explained by differences in the proportionality between either cracking reactions that result in liquid product and char formation or trapping of generated products within the coal network (cross-linking reactions). Maximum yields of C14+ aliphatics from hydrous experiments may not have been attained, but the maximums that were observed and their GC traces are similar for the three pyrolysis systems.

The thermal decomposition of sedimentary organic matter, or kerogen, within the metagenesis zone (T > 160 degreesC) leads to the formation of large amounts of late gas, mainly composed by methane. With the purpose of understanding and quantifying the mechanisms of late methane generation, artificial maturation experiments were performed in closed system on natural samples of type II and type III mature kerogens (R-0 > 1.3%, H/C < 0.65). For each experiment, mass and atomic (C, H, and 0) balances were obtained by recovering, fractionating and quantifying the entire pyrolysis effluents. These data were interpreted by means of a kinetic schema based on three bulk reactions: one corresponding to the decomposition of short chain alkylated polyaromatics and diarenylalkanes that constitute partly mature kerogens, another one related to demethylation processes, a last one based on the autohydrogenation of the remaining pyrolysis residue. Kinetic parameters derived from these experiments confirmed that late methane is generated in sedimentary basins after the conditions of peak oil generation, between 160 degreesC and up to 240 degreesC. However, differences between type II and type III kerogens were observed for the generation of methane, revealing structural disparities between these two samples. This study showed also that the formation of methane was significantly affected by the experimental conditions. Compared to closed-system experiments, the amount of methane recovered in open-system experiments was 2 to 3 times lower. Moreover, the rate of methane generation in open system was not accounted for by the kinetic model calibrated on closed-system data. These discrepancies might be related to the modes of oxygen and hydrogen consumption during the early pyrolysis stages of these mature kerogen. Thus, it is essential to consider carefully the type of experimental data used in gas generation kinetics, since they might lead to diverging predictions for geological conditions.

The aim of this work is to determine the apparent rate, constants for dodecylbenzene (DDB) thermal cracking in laboratory conditions in order to evaluate alkylaromatic stability in geological conditions. Pyrolysis experiments were carried out under Argon:atmosphere, in anhydrous closed system (gold bags) during times,ranging from 1 to 72 h under isothermal conditions (325-425 degreesC). The global rate constants were determined based on the reactant. conversions obtained at various temperatures. For all temperatures investigated, bulk. decomposition of the DDB obeys first-order kinetics and the resulting apparent activation energy, derived from an Arrhenius diagram is found at 53.3.kcal/mol and the corresponding frequency factor A at 1.3. x 10(13) s(-1). When these kinetic parameters are. used for predicting global rate constants at lower temperatures, results show that the DDB should decompose below 166 degreesC assuming a constant thermal history at 1.25 degreesC/my. This means that, even within source rocks, the monoalkyl aromatics are likely to decompose during the, late stage of kerogen cracking. Consequently, depending on the timing of petroleum expulsion, the I expelled fluid may be depleted in alkyl aromatics due to their partial secondary cracking before the migration threshold is reached. The major products observed during DDB cracking are on-one hand, a light C-7-C-14 fraction dominated by decane (n-C-10) and undecene/undecane (alpha-C-11/n-C-11) toluene and ethyl benzene and on the other hand, heavy C14+ aromatic fraction. For DDB conversion lower than 88%, hydrocarbon gas generation was negligible and no insoluble residue was observed.

To make practical the molecular dynamics simulation of large scale reactive chemical systems (1000s of atoms), we developed ReaxFF, a force field for reactive systems. ReaxFF uses a general relationship between bond distance and bond order on one hand and between bond order and bond energy on the other hand that leads to proper dissociation of bonds to separated atoms. Other valence terms present in the force field (angle and torsion) are defined in terms of the same bond orders so that all these terms go to zero smoothly as bonds break. In addition, ReaxFF has Coulomb and Morse (van der Waals) potentials to describe nonbond interactions between all atoms (no exclusions). These nonbond interactions are shielded at short range so that the Coulomb and van der Waals interactions become constant as Rij → 0. We report here the ReaxFF for hydrocarbons. The parameters were derived from quantum chemical calculations on bond dissociation and reactions of small molecules plus heat of formation and geometry data for...

The simple carbon−carbon scission of ethane is investigated by performing quantum mechanical calculations. The approach described in this paper was developed to determine dissociation rate constants for both small and large organic molecules, such as n-alkanes or alkyl-benzenes, for reasonable ranges of computation time and accuracy. The methodology that we propose is based on generalized transition state theory, where transition states are defined along rate constant profiles and not along potential energy curves. Simulations reported in this paper aim to validate this methodology by examining the dissociation of ethane. Calculations, performed at the DFT B3:LYP 6-31G** theory level, correctly account for the looseness of the transition state as a function of temperature. Dissociation activation parameters obtained by this method are in good agreement with data available in the literature. Despite the assumptions made, the order of magnitude and the specific temperature dependence of rate constants for methyl recombination are also fairly predicted.

The aim of this work was to elaborate a mathematical model that accounts for the carbon isotopic composition of methane generated during the thermal cracking of two model compounds: 9-methylphenanthrene (9-MPh) and 1-methylpyrene (1-MPyr). Pyrolysis experiments were carried out; in an anhydrous closed system (gold vessels) during times ranging from 1 to 120 h under isothermal conditions (400-475 degreesC) at a constant pressure of 150 bar. Global rate constants were determined for methane generation from l-methylpyrene decomposition, similar to those determined by Behar et al. (see ref 36 in the text) for 9-MPh thermal cracking. Two main processes of methane formation were recognized: one related to the loss of the methyl group and the second corresponding to the opening of the aromatic rings, the second of which is hydrogen pressure dependent. The derived apparent first-order kinetic parameters were determined only for the first process: E = 55.6 kcal/mol and A = 4.2 x 10(12) s(-1). These parameters are in the same range as those found for methane generated from 9-MPh (ref 36). When these results are extrapolated to geological conditions, methane generation occurs at temperatures lower than 200 degreesC and, thus, constitutes a significant source for natural gas accumulations. This source of natural gas can compete with late methane generation from kerogen. Based on the global kinetic scheme proposed for methane generation, a model of carbon isotopic fractionation was elaborated for predicting the isotopic composition of methane. Results show that very high isotopic fractionation can take place when the methylated aromatics are thermally degraded: the demethylation reaction leads to an isotopic fractionation between the generated methane and its source which is significantly dependent upon the isotopic heterogeneity of the aromatic compound. This study shows that specific isotopic signatures in natural gas might fingerprint the secondary cracking of aromatics in deep reservoirs.