Characterizing Charge Risk
Key questions in prospect evaluation include:
Has the trap received economic quantities of petroleum?
What types of hydrocarbons are likely to be present (oil and/or gas and in what relative proportion)?
What are the oil or gas properties (e.g., viscosity, API gravity, sulfur content, waxiness)?
Is reservoir compartmentalization an issue?
For a prospect to be charged with economic quantities of petroleum, a variety of physical and timing elements must occur in the basin. These elements collectively comprise a petroleum system. They include:
- Petroleum source rock (to generate the petroleum)
- Reservoir (to hold the petroleum)
- Seal (to preserve the accumulation)
- Overburden (to mature the source rock)
- Trap formation
- Oil generation
- Oil expulsion
- Oil migration
- Oil accumulation
- Relative timing of these events
Oil geochemistry (oil fingerprinting) can be used in conjunction with basin modeling to quantify risk associated with many of the components in the petroleum system. Although a comprehensive review of all applicable geochemical approaches to risk assessment cannot be provided in this article, we outline the OilTracers approach here and discuss some of the applications in detail.
Some of the most powerful oil fingerprinting tools we use are based on biomarkers, which are molecular fossils present in oils and rock extracts. The biomarker distribution in an oil can be used to infer characteristics of the source rock that generated the oil without examining the source rock itself. Specifically, biomarkers can reveal
- The relative amount of oil-prone vs. gas-prone organic matter in the source kerogen,
- The age of the source rock,
- The environment of deposition as marine, lacustrine, fluvio-deltaic or hypersaline,
- The lithology of the source rock (carbonate vs. shale vs. coal), and
- The thermal maturity of the source rock during generation (e.g., Peters and Moldowan, 1993). The biomarker Tables list examples of oil biomarker parameters and the information they provide about the oil source rock.
To characterize charge risk, these biomarker parameters can be used in a variety of innovative ways. For example, specific biomarker parameters can be calibrated against specific kerogen quality parameters in a given basin. Then, the biomarker ratios are measured in an oil sample from the basin, and the values are projected onto calibration curves to quantitatively predict characteristics of the source rock. This approach, pioneered by the founders of OilTracers, allows explorationists to assess whether an oil was generated primarily from an oil-prone or gas-prone organic facies (Dahl et al., 1994; McCaffrey et al., 1994). The information gained from oil biomarkers (source type, age, maturity, kerogen quality) when integrated into a basin model. This information has substantial economic impact because it provides early estimates of oil quantity and GOR for exploration targets in the area of interest.
Considered collectively, the geochemical and basin modeling evaluation of each element in a petroleum system results in an assessment of total charge risk for a given prospect. Charge risk refers not only to petroleum quantity, but also to petroleum quality (e.g., API gravity, viscosity, %S). Petroleum-system evaluation is intended to be an early decision-making tool, and OilTracers recommends using the charge risk considerations described below for the most effective use of time and money. For example, use of the approaches described here could lead you not to buy seismic data in an overcooked (post-mature) basin when you are looking for oil. Similarly, oil geochemistry could lead you not to evaluate reservoirs or map traps in an area that cannot possibly be charged with hydrocarbons. Below, our approach is described in more detail.
1. Has the trap received economic quantities of petroleum?
To evaluate the risk associated with trapping economic amounts of oil or gas, OilTracers recommends assigning projects to one of the following three categories:
If a significant petroleum charge exists in nearby accumulations, and there is a known hydrocarbon source rock in the basin, then a low to moderate charge risk usually exists. In this case, we suggest completing the following technical objectives (based on data availability) to insure the prospect is not in a high-risk sector the basin.
- Construct a diagram showing field-size distributions of oil, condensate, and gas reserves for each petroleum system in the basin
- Determine whether the source of the petroleum in the prospect is similar to oil in nearby fields using biomarker fingerprints of petroleum seeps, oil shows, and/or recovered oils/condensates (e.g., Peters and Moldowan, 1993). For gases, use composition and isotope data of gas seeps and discovered gases (e.g., Schoell, 1983, 1984).
- Identify whether the local sector contains an effective source rock (rock known to have generated and expelled oil) using basic source-rock screening tools such as %TOC analyses, Rock-Eval pyrolyses, and vitrinite-reflectance measurements (geochemical logging). Map regional source-rock richness, and complete isopach maps of the source-rock interval, which may be used to estimate lateral source variations to help calculate a regional Source Potential Index (SPI; Demaison and Huizinga, 1992).
- Construct a hydrocarbon kitchen map showing prospect fetch areas, and determine whether the local source rock maturity and timing are favorable (basin modeling) for the prospect. Make a timing-risk chart for each prospect or play.
- Assess whether the prospect may have been charged with a significant quantity of petroleum.
If the presence of a significant petroleum charge is supported by prolific, mature source rock, but no economically significant fields occur in the basin as analogs, then a moderate to high charge risk usually exists. In this case, evaluating risk involves applying all of the techniques described below based on sample availability.
- Determine the hydrocarbon source of any available nearby seeps, shows, or oil from non-commercial fields as described above.
- Identify whether the basin contains a quantitatively significant hydrocarbon source rock using basic source-rock screening analyses such as %TOC analysis, Rock-Eval pyrolysis, and vitrinite-reflectance measurements. Map regional source-rock richness, and complete isopach maps of the source-rock interval, which may be used to estimate lateral source variations to help calculate a regional Source Potential Index (SPI).
- Construct hydrocarbon kitchen map showing prospect fetch areas, and determine whether the local source maturity and timing are favorable (basin modeling) for the prospect. Make a timing-risk chart for each prospect or play.
- Assess whether the prospect may have been charged with a significant quantity of petroleum.
If the presence of significant petroleum charge is hypothesized only due to analogs in nearby basins, then a high to moderate charge risk usually exists. Evaluating risk in these circumstances involves demonstrating that a source-reservoir relationship exists which is similar to those in a nearby producing basin. Oil geochemistry (oil fingerprinting) and source rock/oil correlations are essential for such petroleum system determinations.
- For each petroleum system within the analog basin, construct a field size map showing oil, condensate, and gas reserves to show a link in basin history and source-reservoir stratigraphy between the frontier basin and producing basin.
- Confirm that the source of any hydrocarbon seeps or shows is genetically related to petroleum from fields in nearby prolific basins using biomarkers analyses for oils and gas composition and gas isotope data for gases.
- Complete basic source-rock screening analyses using %TOC analyses, Rock-Eval pyrolyses, and vitrinite-reflectance measurements to evaluate possible source rock of similar age to that within the analog basin. This is particularly important if the expected depositional model (e.g., restricted basin or upwelling zone) and geophysical data suggest the source facies may substantially improve in a sector where the source rock has not been penetrated.
- Determine whether the local source maturity and timing are favorable (basin modeling).
- Construct a hydrocarbon kitchen map of hypothetical source rock with prospect fetch areas delineated and a timing-risk chart for each prospect or play.
- Assess whether a quantitatively significant prospect charge may be expected, given the source rock thickness, analog source rock richness, and mapped mature source fetch area.
What types of hydrocarbons are likely to be present (oil and/or gas)?
- Examine the map showing oil, condensate, and gas distributions for each petroleum system to obtain an empirical view of what has been discovered to date.
- Complete source-rock evaluation and maturity assessment of the petroleum system to show the likelihood of oil vs. gas at the prospect level. These data should be augmented with basin modeling to assess the likelihood of oil displacement by late entry gas. These data will help reveal the types and relative amounts of hydrocarbons entering the trap.
- In a gas discovery case, evaluate by conducting a dewpoint analyses of the gas, and by determining through compositional and isotopic analyses.
- Evaluate what possible other factors could affect the preservation and/or retention of hydrocarbons in the trap (e.g., partial gas loss). This includes examining the possibility of evaporative fractionation of the low molecular weight hydrocarbons using 'Light Hydrocarbon Analysis' (Thompson, 1987) and looking for evidence of 'gas chimneys' from seismic and/or 'hydrocarbon-related diagenetic zones' (HRDZs).
What are the oil or gas properties (viscosity, API gravity, sulfur, waxiness)?
- Directly measure the bulk properties of oils from nearby fields or from the discovery well (e.g., , %S, pour point, oil viscosity) and perform gas chromatography analysis to allow characterization of post emplacement alteration history
- Directly measure basic gas properties of gas from nearby fields or from the discovery well. Gas composition data include abundance and distribution of hydrocarbon gases, inert gases such as CO2 or N2, unusual supplemental byproducts such as helium, and deleterious species such as H2S and mercury. In addition, commercial gas properties such as gas heating value in BTU/ft3, mixed LPG potential, and condensate yield should also be measured.
- Predict oil or gas properties indirectly from knowledge of source type, thermal maturity, and secondary alteration (e.g., biodegradation, water washing, and preferential gas loss) when fluid samples are not available for direct analysis.
4. Is reservoir compartmentalization an issue?
- Imagine possible reservoir compartmentalization issues that might be encountered given the reservoir distribution and trap style. Poor reservoir connectivity may economically break an exploration play, particularly in deep, offshore reservoirs or in structurally or stratigraphically complex reservoirs. Reservoir compartmentalization issues should be considered in initial screening economics, and again be addressed in the pre-drill exploration phase based on data available from nearby fields in the same type of play.
- Evaluate vertical reservoir continuity between reservoir zones if the initial well is a discovery. Integrate gas (composition and isotope) and oil (chromatography) data with geological and engineering information (e.g., wireline log information, RFT pressure data) to corroborate vertical compartmentalization.
- Evaluate lateral reservoir continuity in successful delineation wells using gas chromatography of oils or condensates and isotope analysis of gases. Integrate with other geological and engineering information (e.g., 3-D seismic interpretation, pressure data) to corroborate lateral compartmentalization.
- Evaluate vertical/lateral reservoir compartmentalization in inadequately constrained development projects. Simple models of reservoir connectivity are often not correct and lead to errors in reserve-size calculations and increased development and production costs. Many development projects carry as much risk (albeit different kinds) as exploration projects, yet the dollar stakes for development projects are much higher.
For more information on the techniques described here, or to discuss a specific project, e-mail us at email@example.com, or call us at U.S. (214) 584-9169
Dahl J. E., Moldowan J. M., Teerman S. C., McCaffrey M. A., Sundararaman P., Pena M. and Stelting C. E. (1994). Source rock quality determination from oil biomarkers I. - An example from the Aspen Shale, Scully's Gap, Wyoming. American Association of Petroleum Geologists Bulletin 78 (10), 1507-1526.
Demaison, G., and B. J. Huizinga (1991) Genetic classification of petroleum systems: American Association of Petroleum Geologists Bulletin, v. 75, p. 1626-1643.
McCaffrey M. A., Dahl J., Sundararaman P., Moldowan J. M. and Schoell M. (1994). Source rock quality determination from oil biomarkers II. - A case study using Tertiary-reservoired Beaufort Sea oils. American Association of Petroleum Geologists Bulletin 78 (10), 1527-1540.
Peters, K. E., and J. M. Moldowan (1993) The Biomarker Guide, Interpreting molecular fossils in petroleum and ancient sediments, Prentice Hall, 363 p.
Schoell, M. (1983) Genetic characterization of natural gases: American Association of Petroleum Geologists Bulletin, v. 67, p. 2225-2238.
Schoell, M. (1984) Stable isotopes in petroleum research, in J. Brooks, and D. H. Welte, eds., Advances in Petroleum Geochemistry, v. 1: London, Academic Press, p. 215-245.
Thompson, K. F. M. (1987) Fractionated aromatic petroleums and the generation of gas-condensates: Organic Geochemistry, v. 11, p. 573-590.
Thompson, K. F. M. (1988) Gas-condensate migration and oil fractionation in deltaic systems: Marine and Petroleum Geology, v. 5, p. 237-246.