Energy Resources Program
Wednesday, March 01, 2017
Monday, January 30, 2017
Outside Publication: Palaeo
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...
Monday, January 23, 2017
Wednesday, January 18, 2017
Wednesday, June 29, 2016
Monday, June 27, 2016
Monday, December 21, 2015
Outside Publication: Energy & Fuels
Evaluation of organic matter quality in petroleum source and reservoir rocks is vital for economic, drilling, and production decisions. However, current methods for assessing kerogen quality in shales and mudrocks are either time-intensive and undesirable from a health, safety, and waste-disposal standpoint or indirect measurements of the factors of greatest interest and utility
Monday, December 14, 2015
Geochemistry research has been conducted under the Petroleum Processes Research Project since 1995. The project objectives are to apply and provide cutting-edge research on processes related to petroleum (oil, gas, and asphalt) generation, migration, and entrapment, and the consequences of these processes on petroleum type, quantity, quality, and location. The research results strengthen the scientific credibility of realizing and assessing undiscovered conventional and unconventional petroleum resources at a national and global level and are critical to formulating a better understanding and strategic use of petroleum resources.
Major research topics include origins of petroleum, genetic petroleum correlations, natural gas studies, shale gas, sedimentary basin modeling, and microbial natural gas.
Figure 1. An illustration of a hydrous pyrolysis experimental method used to simulate natural petroleum generation in the laboratory.
Photo: A close-up photographic view of a hydrous pyrolysis experimental method used to
simulate natural petroleum generation in the laboratory.
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The petroleum industry now ranks basin modeling as the top leadership technology that increases exploration success and lowers finding costs. Over the last decade, three-dimensional (3D) imaging and modeling of the subsurface through time have co-evolved and emerged as a major research focus of the petroleum industry. Virtually all major oil companies have independently recognized the need for... [+]
Major application of 3D petroleum systems models can serve as evolving databases that provide surface and subsurface geologic information for various practical research needs. They allow users to figuratively look within the earth to examine data, appraise the reliability of geological concepts, models, or geochemical input, and extract needed information. Major applications of 3D geologic models include developing predictive exploration and reservoir models, integrating sequence stratigraphy and assessment units, predicting the extent and timing of petroleum generation in source rocks, structural deformation that disturbs basin architecture, migration pathways, and locations of potential traps and accumulations, and analysis of risk based on different geologic, geochemical, or fluid-flow assumptions. Thus, 3D petroleum system models can provide a basic geoscience framework to conduct and record a wide variety of applied and basic research.
As petroleum becomes more difficult to find and reserves become more difficult to replace, 3D petroleum systems modeling has grown because it better quantifies the generation, migration, and entrapment of the remaining resource. It also facilitates interpretation of the stratigraphic and sedimentologic processes that are important to develop a predictive sequence stratigraphic framework. Because of financial and time constraints, large oil companies typically conduct 3D modeling studies only at scales to suit their immediate needs. These studies commonly cover only the acreage held by each company and seldom cover the full extent of each petroleum system. This knowledge gap represents an opportunity for the USGS because many domestic and international companies are willing to supply data and expertise. Companies will benefit from USGS studies that extend 3D interpretations beyond immediate concession areas. For example, many oil companies exhaustively study “postage-stamp” areas within basins, but 3D modeling may not have been conducted over the entire area (e.g., Gulf of Mexico, San Joaquin, Permian, Los Angeles basins, North Caspian Basin).
3D petroleum systems modeling is rapidly growing as a tool to better understand subsurface migration, accumulation, and preservation. The approach is strong as a tool to predict the pod of active source rock, thermal maturity of the source rock, migration pathways, and the timing of petroleum generation. 3D modeling is currently less successful as a means to predict volumes of trapped petroleum, their detailed compositions, or the effects of secondary processes. However, solutions to these questions could have major impact on the domestic and world economy. 3D modeling is a tool that will continue to attract new users because of the potential for high-impact solutions to these problems with respect to exploration, development, and assessment.
Figure 1. Input geometry for a 3D North Slope, Alaska model. The study area polygon shows the position and surface shape of the 3D model (top). The 2D cross section along the key E-W wells (white vertical lines; bottom) was cut from the 3D input model. The 2D cross section was used to reconstruct the shape, current thickness, and eroded thickness of the prograding foresets in the Brookian section. The pre-erosional thickness (maximum burial depth) was determined using a linear extrapolation of measured vitrinite reflectance (Ro) on semilog scale for each well. Reconstructed lost overburden reaches up to ~4000 m in the western part of the section. This lost section controls the burial depth and thermal maturity of the source rock and geometry of the migration paths.
Figure 2. Simplified perspective view of a 3D North Slope model (note north arrow) is based on layered surfaces derived from well and seismic data. Rather than using a stratigraphic subdivision of the Brookian clinoform sequences, timelines of eastward prograding foresets were mapped to allow for a time-transgressive change of geometry. LCU = Lower Cretaceous unconformity.
Figure 3. Three-dimensional numerical models allow predictions of petroleum migration pathways and accumulations through time. Example shows predicted migration pathways and accumulations (green and red for liquid and vapor, respectively) on the North Slope above the Triassic Shublik Formation source rock (hatched gray) 14 million years ago based on a calibrated petroleum systems model created using PetroMod® software.
Determining genetic petroleum families and their correlation with source rocks are critical to defining petroleum systems and interpreting the processes that are controlling the generation, migration and accumulation of petroleum within sedimentary basins. Geochemical parameters based predominantly on biomarker technology have been established to genetically correlate crude oils and their sources... [+]
and aid in defining petroleum systems (see Peters et al., 2005). However, crude oil is not the only petroleum product exploited in sedimentary basin; condensates and gases are also significant. In order to more thoroughly and completely understand the dynamic petroleum processes operating within sedimentary basins, reliable and scientifically sound geochemical parameters are needed to perform (1) condensate-source rock and condensate-oil correlations, (2) gas-source correlations, and (3) identify and quantify mixing of genetically unrelated crude oils, natural gas and condensates. The absence of biomarkers in most condensates precludes the interpretation of the origin of condensates, correlation with sources and the identification of mixtures using established methods. Thus, new tools that integrate molecular and isotopic data to interpret source facies and mixing processes are required. Previous studies have attempted to decipher mixed petroleum systems (Peters and others, 1989; Jiang and Li, 2002; Chen and others, 2003) with some success. However, challenges remain due to the effects of maturity, source rock facies variation, secondary alteration, and migration fractionation. Currently, no established methodology exists to unequivocally differentiate these mixtures. The issue of differentiating crude oils that represent genetic end-members and varying mixtures is particularly important in determining total petroleum systems and their assessment units.
Gas-rich petroleum systems are receiving more attention, as natural gas becomes a more dominant component of our energy mix. Currently, characterizing natural gases is limited to molecular concentrations and stable isotopes of C1 to C5 hydrocarbons. Condensates commonly coexist with natural gases in many accumulations, but correlation of this type of petroleum with natural gases and crude oils to define petroleum systems and assessment units that are dominated by natural gas and condensate is in the early stages of development (Gurgey et al., 2005). Figure 1 (Gurgey et al. 2005) demonstrates how isotopic data can be used to correlate gases and condensates with oils. Integration of genetic molecular interpretations with this type of isotopic data will enhance petroleum system and process interpretation capabilities.
Figure 1: Correlation of condensates and gases with oils based on isotopic data (From Gurgey et al., 2005).
Migration distance/pathways, thermal maturity, and reservoir alteration can affect the geochemical parameters used to correlate natural gas, condensate, and crude oil to their source rock. A robust suite of geochemical parameter parameters that are not affected by these geological factors remains to be established to unequivocally determine the sources of genetically related natural gases, condensates, and crude oils of a petroleum system.
Determining genetic petroleum families and their correlation with source rocks are critical to defining petroleum systems and interpreting the processes that are controlling the generation, migration and accumulation of petroleum within sedimentary basins. Although a variety of geochemical parameters are currently available for correlating oils to oils and their source rocks, there is a definite need to establish geochemical parameters to correlate gas and condensate to one another and to their related oils and source rocks. Results from this research are essential in defining petroleum systems that are gas or oil dominated.
Natural gas generated from microbial activity in natural organic deposits (coal, black shale, petroleum) represents an increasingly important natural resource. In the past, producers have tended to ignore microbial-derived natural gas deposits because they were considered too small to be economic. However, the increasing demand for natural gas has encouraged producers to begin targeting these smaller... [+]
smaller microbial natural gas deposits. It is estimated that natural gas from microbial activity (methanogenesis) accounts for about 20% of the world's natural gas resource. Since this gas is biologically produced, it also represents a possible renewable resource. Examples of microbial-produced natural gas deposits include: the organic-rich Antrim shale deposits in northern Michigan, and the shallow eastern edge of the Powder River Basin coal in Wyoming. Significant coal-bed gas resources may also exist in subsurface Wilcox Group and younger (Paleocene-Eocene) coal beds found across much of the Gulf Coastal Plain, and preliminary geochemical and isotopic work by USGS and others has shown that Wilcox coal gas in north Louisiana originates from microbial methanogenesis.
Although a considerable body of research exists on the biology of methanogenesis, there is much less known about the microbial-mediated conversion of geopolymers such as coal, black shale, and petroleum to methane. Methanogenesis involves a large consortium of microorganisms in order to convert the geopolymers in fossil fuels to methane (Figure 1). Methanogenic archaea are the end producers of methane, but the consortia also includes fermenting bacteria that biodegrade geopolymers in the organic deposit to simpler molecules utilized by methanogenic archaea. The nature of the microorganisms, enzyme systems, and decomposition pathways involved in the production of microbial natural gas from organic deposits is actually poorly understood. This task will examine the process involved in microbial production of methane from organic deposits using both field studies and laboratory experiments.
Figure 1. Conceptual model of microbial conversion of geopolymeric carbon to methane.
Petroleum is a naturally occurring substance consisting of organic compounds in the form of gas, liquid, or semisolid. Organic compounds are carbon molecules that are bound to hydrogen (e.g., hydrocarbons) and to a lesser extent sulfur, oxygen, or nitrogen.
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As natural gas demand increases in the United States, gas exploration across North America is increasingly focused on “unconventional” reservoirs, including shales (a broad term herein meant to include mudstone, claystone, and other fine-grained rocks). Although shales have been studied extensively in their role as source rocks (the rocks from which oil and gas generate they have only recently become... [+]
important reservoir rocks in North America, so research on them as it bears on their reservoir characteristics is extremely limited. Because North America is a mature petroleum province, shale gas (gas produced from shale reservoirs) is rapidly becoming an important domestic exploration target and an increasingly significant source of natural gas produced in the US and Canada. A systematic study of shale gas reservoirs is thus necessary in order to more fully appreciate the volume of contained petroleum resources and the mechanisms acting to create and preserve these reservoirs through geologic time. Such a study was recently launched by the USGS because a cursory look at some shale gas reservoirs in North America suggests that there are fundamental differences between them, making it difficult to generalize about these important reservoirs. Furthermore, there is little known about the role, if any, of clay minerals (Fig. 1A), the dominant mineral component of shale, in localizing organic material (the source of oil and/or gas) and their role in influencing the concentration of specific types of organic matter (Fig. 1B).
Thus, scientists at the USGS are studying shales to address several fundamental questions concerning these important gas reservoirs such as, 1) what is the possible role of clay minerals in localizing and concentrating organic material in shale reservoirs? 2) what constitutes an effective shale gas source rock? and 3) can we define shale resources within a petroleum system framework? Addressing these questions will provide a greater understanding of the fundamental mechanisms responsible for shale gas accumulations and as such, construct a framework for future assessments of the undiscovered resources within these still enigmatic reservoirs.
Energy Resources Program - Geochemistry Laboratories
Energy Resources Program - Seismic Data Processing and Interpretation
Energy Resources Program - Coal Quality
Energy Resources Program - Organic Petrology
International Committee for Coal & Organic Petrology (ICCP)
The Society for Organic Petrology (TSOP)
Page Last Modified: Monday, June 27, 2016