Search

There is a rich history of using light hydrocarbon distributions to characterize source and thermal maturity based on observations made on source rocks and petroleum fluids produced from conventional reservoirs. In this study, a suite of lower Eagle Ford oils and condensates was used to determine the accuracy and reliability of established light hydrocarbon parameters in an unconventional petroleum system. These samples have well defined organic source facies, generative temperatures, and extent of thermal cracking. They are largely free of the influence of long-distance migration, multiple charging events, reservoir alteration processes that commonly occur in conventional accumulations and free of contributions from other reservoirs along faults induced by fracturing. All established light hydrocarbon thermal maturity parameters are influenced to varying degrees by source facies. Ratios of i -C 4 / n -C 4 and quaternary/tertiary dimethylpentanes linearly correlate with %R o (R 2 > 0.8) with negligible sensitivity to differences in source facies. The Isoheptane and C 6 –C 7 branched/(branched + cyclic) hydrocarbon ratios correlate with %R o (R 2 > 0.8) but also are influenced by source facies. Some established C 7 parameters are affected by thermal cracking: i -C 5 / n -C 5 and toluene/ n -C 7 are the most sensitive ratios to the onset of intense hydrocarbon cracking (∼1.35 %R o) and do not appear to be significantly influenced by source facies, C 6 –C 7 branched/(branched + normal) hydrocarbons and methylcyclohexane/ n -C 7 both increase in response to cracking conditions but are significantly influenced by source facies, which is likely related to the presence of reactive clays. A revised formula for C temp is proposed: C temp = 161.9 + 29.4•(ln[2,4-DMP/2,3-DMP]). The revised C temp formula is applicable for oils/condensates with 2,4-DMP/2,3-DMP >0.25, expanding the practical limit from ∼120 to ∼160 °C, and yields C temp values consistent with the maximum exposure temperature with an accuracy of ∼ ±5 °C for most samples, excluding those that have been altered by evaporation. The Mango (1997) C temp formula should be used for lower maturity oils having DMP/2,3-DMP values < 0.25. Sample integrity is critical as many of the light hydrocarbon parameters are significantly altered by evaporative loss. • Light hydrocarbons (LH) of well characterized Lower Eagle Ford oils/condensate were examined. • The influences of source facies and thermal cracking on LH parameters were determined. • i C 4 / n C 4 and (2,2-+3,3-DMP)/(2,3-+2,4-DMP) accurately reflect thermal maturity with low source dependency. • Isoheptane ratio and C 6 –C 7 branched/(branched + cyclic) accurately reflect thermal maturity but are source dependent. • A revised formula for C temp is proposed when 2,4-/2,3-DMP >0.25: C temp = 161.9 + 29.44(ln[2,4/2,3-DMP]) [ABSTRACT FROM AUTHOR]

A rich variety of diamondoid indices exists that are assumed to be diagnostic of source facies, thermal maturity, the extent of oil cracking, mixed oils, and reservoir alteration processes. These parameters were developed either from empirical relationships observed in source rocks and oils produced from conventional reservoirs or laboratory experiments. Diamondoid parameters are now being routinely applied to unconventional oils; however, their accuracy and reliability have not been rigorously tested in these petroleum systems. Here, we examine diamondoid compositions in a suite of lower Eagle Ford oils and condensates with well-constrained source facies and thermal maturity established by other geochemical measurements and basin modeling. Diamondoid concentrations are low in samples from ∼0.8 to 1.35 %R o , and then increase significantly at higher maturity due to the cracking of less stable hydrocarbons. Most published maturity-dependent diamondoid indices are not diagnostic when maturity is ≲ 1.1 %R o and are influenced by source facies. Based on our data, their predictive accuracy is no better than ±0.2 %R o at higher maturity. Published source indices are not diagnostic of a specific kerogen type or lithofacies but may be used to differentiate sources in complex petroleum systems. Quantitative diamondoid analysis can be used to calculate the degree of oil-to-gas conversion; however, the natural variance in the baseline concentration of 3-+4-methydiamantanes limits its accuracy at maturities ≲1.35 %R o. Three lower Eagle Ford oils associated with Karnes Trough faults exhibit anomalous diamondoid distributions behavior that these reservoirs received secondary charges from a source other than lower Eagle Ford (likely Austin Chalk). Evidence for a secondary charge was not apparent from the study of the saturated and aromatic biomarkers. In summary, established diamondoid maturity and source indices based on compound ratios should be used with caution to characterize unconventional oils/condensates while quantitative diamondoid analysis can be used with greater confidence and can provide insights that are not apparent from other geochemical parameters provided that highly accurate determination of diamondoid concentrations can be obtained. In the case of the Eagle Ford oils and extracts, analyses must be accurate to less than 1 ppm. • The reliability of diamondoid indices was tested using lower Eagle Ford oils/condensates. • Diamondoid maturity parameters are influenced by source facies and are effective only ≳1.3 %R o. • Diamondoid source parameters are sensitive to facies but are not predictive. • QDA is diagnostic of the degree of thermal cracking at ≳1.1 %R o. • 1-+2-MA vs. 3-+4-DA identified Eagle Ford oils with a secondary Austin Chalk charge. [ABSTRACT FROM AUTHOR]

Fifty-five petroleum samples from unconventional wells in the self-sourced lower Eagle Ford Shale were analyzed using routine geochemical methods. The samples are broadly distributed, geographically and vertically, and range in maturity from mid-oil to wet gas. Their physical and chemical properties span most of the range observed in the entire play. Two source facies are identified: west of San Marcos Arch is a marine marl facies deposited under anoxic to euxinic conditions containing abundant type II/IIS kerogen and east of the Arch is a marine shale to marl facies deposited under mostly oxic to anoxic conditions that received an additional input of terrigenous organic matter. The unconventional oils are too mature to detect any subtle differences that could distinguish a marl from a pure carbonate source facies. Saturated and aromatic biomarkers rapidly decrease with depth and are at or near the limits of detection below ∼9,000 feet. Condensates >13,500 ft show evidence of advanced hydrocarbon cracking. All properties and molecular parameters that are dependent on thermal maturity for oils/condensates west of the San Marcos Arch exhibit two trends with true vertical depth (TVD). One is defined by samples between the Karnes Trough area and the Maverick Basin; the other trend defined by samples near the Karnes Trough is offset with equivalent maturity occurring at deeper depths. This ∼2,000 ft offset is likely due to differences in the amount of uplift and erosion experienced in the two regions after the source rocks achieved their maximum maturity. • Hydrocarbon composition was measured on lower Eagle Ford unconventional oils/condensates. • Two source facies, separated by the San Marcos Arch, are identified – carbonate-enriched mudstone and distal marine shale. • Nearly all compositional variance in the western oils is attributed to thermal maturation. • All maturity-sensitive properties and parameters show regional trends with depth. • The trend in the region near the Karnes Trough is offset by ∼2,000 ft compared to the region to the west. [ABSTRACT FROM AUTHOR]

Fifty-five oils and condensates produced from unconventional reservoirs in lower Eagle Ford Shale were characterized. Most of the samples are from the play area east of the Maverick Basin and west of the San Marcos Arch, while five samples are from wells east of the Arch. Crude assay measurements (API gravity, wt% sulfur, wt% nitrogen, viscosity at 25 and 40 °C, pour point, simulated distillation [SimDist] and C 15+ chemical group-type fractionation) were conducted on dead oil samples using standard methods. All bulk properties were found to correlate well with each other. Relationships between crude assay measurement and production depth suggest that thermal maturation accounts for most of the variance in composition; however, different depth trends are observed in oils from the Karnes Trough area compared to locations west of that region. Refinery valuation and process models rely heavily on the fractional composition of crude feedstock defined by boiling point distribution. We constructed a model using seven crude assay parameters (API gravity, % S, % N, viscosity at 40 °C, and % C 15+ saturates, % C 15+ aromatics and % C 15+ resins) as inputs for predicting SimDist boiling point curves. Using optimized parameters derived from this model, we found that SimDist curves can be modeled with nearly the same degree of accuracy using only API gravity and %S because of their strong correlation with the other bulk properties. This offers the prospect for refiners to identify wells producing specific grades of crude across the entire lower Eagle Ford play. The ability to construct a SimDist predictive model based only on the most basic assay measurements suggest that the compositional variations are due mostly to thermal maturity and the heterogeneity in source facies is insignificant in the lower Eagle Ford west of the San Marcos Arch. The SimDist predictive model is specific to the Eagle Ford shale oils and condensates, but the methodology could be used to construct formation specific models in other unconventional plays. • Basic crude assays were made on 55 oils and condensates produced from unconventional reservoirs of the lower Eagle Ford. • All bulk properties exhibit systematic trends attributed mostly to thermal maturation. • Correlations of bulk parameters with true vertical depth (TVD) differ regionally in the play. • SimDist can be accurately modeled using seven assay measurements (API gravity, %S, %N, viscosity, and SARA data) as input. • SimDist can be modeled at nearly the same accuracy using only API gravity, %S. [ABSTRACT FROM AUTHOR]

Maturity-dependent bulk properties and molecular compositions of oils and condensates produced from the lower Eagle Ford shales exhibit two distinct regional trends with production depth. Samples west of 98.6 West longitude form a trend that is offset upwardly by ∼2000 ft compared to samples near the Karnes Trough area. This offset is unlikely due to variations in source facies or regional heat flow. To test whether the offset is the result of different amounts of uplift and overburden removal, a psuedo 3D basin model was constructed for the Eagle Ford Formation using standard geologic methods and rock-calibrated 1D burial histories. Present-day thermal maturity was found to correlate with reconstructed maximum burial depth (MBD). When maturity-dependent geochemical parameters are plotted versus MBD, the trends show significantly greater fidelity than when plotted versus true vertical depth; however, the regional offsets are still evident, suggesting that the basin model could be refined. Petroleum samples can be used to calibrate basin models provided they reflect the current maturity of their source. This criterium may be met by unconventional fluids provided the producing strata is charged with the latest generated hydrocarbons from very limited, localized fetch area – conditions believed to be present in the lower Eagle Ford. API gravity from initial production, the only oil property reported for all wells, generally correlates with molecular maturity parameters but can be influenced by other processes. To compensate for these extraneous influences, trends of API gravity versus TVD were plotted for 0.2° longitudinal segments across the Eagle Ford play and used to model the relative amount of uplift and erosion needed to yield oil with the same API gravity and by inference the same maturity. Calculated MDB's from the API gravity oil-based model were found to agree well with those determined by the rock-based basin model and yielded more coherent depth trends with the measured maturity parameters. Both the rock-based and oil-based models find that the amount of Neogene uplift and overburden removal to be no more than ∼500 ft in the area near the San Marcos Arch and increases to the west, reaching ∼6500 ft in Maverick County. This finding strongly supports, if not proves, Cander's (2013) model for petroleum retention/production in the Eagle Ford shales and that the produced petroleum is a near-instantaneous, rather than a cumulative charge, of the latest generated hydrocarbons. This implies that unconventional continuous source petroleum systems are suitable for oil-based calibration of basin models. In many ways, the Eagle Ford petroleum system is ideal in its simplicity for the application of type of calibration. • A rock-calibrated basin model was constructed for onshore Eagle Ford play. • Produced petroleum best matches that of the latest retained fluids generated at maximum burial depth. • Oil properties and molecular parameters reflect the maturity of their local source/reservoir rocks. • Regional trends of API gravity vs depth can be used to constrain Neogene tectonics. • Rock- and oil-calibrated models yield similar amounts of uplift and erosion ranging from ∼500 to ∼6500 ft. [ABSTRACT FROM AUTHOR]