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:
Physical components
- Petroleum source rock (to generate the petroleum)
- Reservoir (to hold the petroleum)
- Seal (to preserve the accumulation)
- Overburden (to mature the source rock)
Processes/Timing components
- 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 (1) the relative amount of
oil-prone vs. gas-prone organic matter in the source kerogen, (2)
the age of the source rock, (3) the environment of deposition as
marine, lacustrine, fluvio-deltaic or hypersaline, (4) the
lithology of the source rock (carbonate vs. shale vs. coal), and
(5) the thermal maturity of the source rock during generation
(e.g., Peters and Moldowan, 1993). The attached 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.
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:
Category (1)
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.
Category (2)
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.
Category (3)
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 down-dip oil potential
by conducting a dewpoint analyses of the gas, and by determining gas maturity and
origin 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., API gravity, %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.
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 info@oiltracers.com, or call
us at U.S. (214) 584-9169.
References
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.