Slentz, 1981
The oil geochemistry technique
for assessing reservoir continuity was first described by Slentz
(1981) who proposed that the composition of an oil or water is a
'fingerprint' characteristic of a specific reservoir. In that
paper, the author showed case histories from California and the
Middle East in which oil geochemistry was used successfully to
assess reservoir continuity. Slentz also showed a US Gulf Coast
case study in which water chemistry was used to pinpoint which of
10 stacked sands was the source of an anomalous water cut in a
well. This water-based application is analogous to the oil
geochemistry applications discussed here since it relied on the
fluid fingerprint to distinguish fluids from discrete
reservoirs.
Although Slentz (1981) was the first publication to describe
geochemical assessment of reservoir continuity, he noted that the
technique had already been in use for a long period within the
author's company (the Arabian American Oil Company, a joint venture
involving a predecessor of the modern ChevronTexaco). In fact,
Slentz (1981) noted that:
"Thousands of analyses of oils and formation water have
established the applicability of compositional data to such
problems as determining reservoir continuity, evaluating workovers,
and identifying extraneous production."
As noted later by Hwang and Baskin (1994), "For proprietary
reasons, Slentz didn't elaborate on the specifics of the oil
fingerprinting (gas chromatography) technique, but he clearly laid
the foundation for using the chemical composition of oil and/or
water to solve reservoir related-problems such as vertical and
lateral connectivity."
Kaufman et al., 1990; Lindberg et al., 1990
Kaufman et al. (1990), a paper authored by 3 Chevron
geochemists, provided details on the technique that Slentz (1981)
had first described (details such as are provided elsewhere
on this site). Furthermore, Kaufman et al. (1990) demonstrated
the effectiveness of oil fingerprinting for assessing reservoir
continuity by using a variety of case studies to carefully
illustrate key concepts:
- The authors demonstrated that oil fingerprint differences among
oils from a laterally continuous reservoir are smaller
than the differences among oils from, laterally
discontinuous accumulations. In other words, the
variations in oil fingerprints within one pool are much
smaller than the variation between laterally separated pools
reservoired in the same stratigraphic unit. Kaufman et al. (1990)
demonstrated this point using case studies of oils from the upper
Vermelha reservoir in the Takula and Numbi fields offshore Cabinda,
Angola.
- The authors then used data from the same Takula and Numbi
fields to show that vertically discontinuous reservoirs
within in each of these fields can easily be distinguished
with the same gas chromatographic data. Again, fingerprint
variation among oils from vertically connected reservoirs were
small compared to vertically disconnected reservoirs.
- The authors then showed how geochemistry can be used to
determine compartmentalization of structurally more complex fields
in a case study from the East Flank of Bay Marchand Field, Gulf of
Mexico. In that case history, geochemistry was successfully used to
determine that the highly faulted 7700 ft. sand actually contained
three fluid compartments, not two as had originally been mapped.
The geochemical interpretation of three compartments was confirmed
by production data and re-mapping of the field.
The same year as the Kaufman et al. (1990) publication, other
Chevron workers published an abstract in which they report that the
oil geochemistry technique was used
to successfully assess reservoir compartmentalization in the Safah
field in Oman (Lindberg et al., 1990). That abstract, provided few
details of that study. At the time, the operator of this field had
strong misgivings about the validity of oil fingerprinting results,
which indicated the field was more compartmentalized than
previously thought. Therefore, as a test, the operator sent Chevron
40 oils from this field in which the well names were coded, and
asked that oil fingerprinting analyses be completed on this blind
sample set. When the new results exactly matched previous results,
the field operator had an increased confidence in the oil
fingerprinting technology and strongly endorsed its use in the
future development of the field (personal communication - D. K.
Baskin).
Hwang and Baskin, 1994
Hwang and Baskin (1994) built on the earlier Slentz (1981) and
Kaufman et al. (1990) papers by using data from a very large Middle
Eastern field to demonstrate three key concepts:
- Oil fingerprinting can be used to assess reservoir continuity
even in one of the largest oil fields in the world. The field in
their study was "tens of kilometers long, several kilometers wide,
and the main reservoir averaged about 10 meters in thickness." Oil
fingerprinting indicated that the main reservoir was one
compartment, a conclusion confirmed by engineering and production
data during the field's 30+ year production history. This
conclusion was a key addition to the literature, since previously
published case studies had focused on relatively small-scale
reservoirs such as those in the US Gulf coast.
- Within a given reservoir compartment, even an extremely large
compartment, "molecular properties (gas chromatography, biomarkers,
etc.) have not significantly changed during 20+ years (1971-1992)
of production." This point was a key addition to the literature
because it showed that, even when samples are collected at
different times, as long as they are analyzed at the same time,
they can be compared to assess reservoir continuity, because the
fingerprint of oil produced from a given compartment will not
change significantly over time.
- Homogeneity of oil fingerprints within a single compartment is
probably due primarily to fluid mixing within the compartment over
time, and is probably not due to homogeneity of the
original oil generated by the source rock. This was suggested by
Hwang and Baskin (1994) comparison of oil from the large reservoir
mentioned above with oil from an adjacent underlying reservoir. The
fingerprints of the oils could be readily distinguished, but
biomarker (molecular fossil) data indicated that the oils were
derived from the same source rock and only differed in the thermal
maturity at which they were generated.
Hwang et al., 1994
Hwang et al. (1994) built on the three earlier Chevron
publications by adding a carefully documented case study from the
Unity field in Sudan. The field is characterized by a series of
stacked, vertically discontinuous pay zones in the Ghazal sands.
Hwang et al. (1994) found that the oil fingerprinting technique
described in section 3 of this report can readily distinguish oils
from these discrete reservoirs. Other lines of evidence, such as
separate oil/ water contacts, confirmed the vertical
discontinuity between these reservoirs in this field.
Hwang et al. (1994) also used oil fingerprinting to assess the
lateral continuity of three sands between two of the wells
in this field. The study found lateral continuity in one of the
sands, and lateral discontinuity in the other two sands. Other
lines of evidence, including oil/water contact depths and 3-D
seismic data, confirmed these conclusions.
This study is particularly noteworthy not only because of the
additional case study it provides, but also for two other
reasons:
- The study addressed a key question not fully addressed by the
previous publications: the causes of the geochemical
differences observed between oil from discrete reservoir
compartments. Using biomarker (molecular fossil) data for the Unity
field oils, the study found that the differences in composition
between oils from the discrete reservoirs were due entirely to
source facies and source maturity variations, and were constrained
primarily to the saturated hydrocarbon fraction of the oils. The
absence of significant variations in the aromatic and polar
fractions of the oils suggested that reservoir rock-oil
interactions were NOT a significant cause of the variations. These
findings were consistent with those of Hwang and Baskin (1994) that
the geochemical differences between two superimposed, vertically
discontinuous Middle Eastern fields are due to differences in the
thermal maturity at which the source rock originally generated the
oil that later migrated into those fields.
- The study also provided another piece of very useful, but
previously confidential, Chevron information. The authors noted
that:
"… a Chevron well in the Main Pass 299 of the [United
States] Gulf Coast has produced over 3 million barrels of oil in 20
years. The oil fingerprint did not change significantly during that
period of time."
This report by Hwang et al. (1994) is consistent with the
previously mentioned finding of Hwang and Baskin (1994), who
reported that oils produced from a Middle Eastern field over 21
years had essentially identical fingerprints. Collectively, these
data support the argument for uniform fingerprints of oils on the
reservoir scale, and these data represent a line of support for the
oil fingerprinting technique that is independent of the line of
support provided by the case studies presented in the papers
discussed here.
Sundararaman et al., 1995
Sundararaman et al. (1995) is not a full paper, but rather an
extended three page abstract. However, it is significant because it
provides a case study of the oil fingerprinting technique for
assessing of reservoir continuity which is drawn from a part of the
world (Nigeria) not covered by the previously mentioned case
studies. The case study is well summarized by this quote from the
paper:
"On the basis of available geological data, it was
originally interpreted that there is no fluid communication across
this fault and that the CD-01 reservoir is discontinuous. However,
chromatographic fingerprints of the oils from wells on either side
of the fault are identical indicating that there is fluid
communication between these wells. This conclusion was later
confirmed by additional drilling and RFT pressure
data."
Ross and Ames, 1988
The five Chevron papers discussed above were reviewed here as a
group because they show Chevron's effort over time to introduce
into the literature a specific oil
geochemistry technique for assessing reservoir continuity.
However, during the period spanned by those papers, Amoco workers
published a paper that also dealt with the use of geochemistry to
assess reservoir continuity. Ross and Ames (1988) was published six
years after Slentz (1981) and does not discuss the Chevron
technique for making detailed comparisons of GC data. Rather, Ross
and Ames (1988) use a much less detailed examination of the GC data
than that employed by the Chevron workers, but the conclusion that
they reach is the same: Ross and Ames (1988) found that in the
Columbus basin, offshore Trinidad, oils from individual pools in
the Teak, Samaan, and Poui fields could be distinguished by GC.
Although the technique they used was less sophisticated than the
Chevron approach, Ross and Ames (1988) is referenced here for the
sake of completeness, since it is one of the earliest papers that
interprets oil geochemistry data in terms of reservoir
continuity.
Nederlof et al., 1994, 1995
Nederlof et al. (1994) and Nederlof et al. (1995) were some of
the first papers published by a company OTHER THAN Chevron that
provided case studies illustrating the application of the detailed
oil geochemistry technique to
reservoir continuity assessment. These papers also reveal that at
the time those papers were written, oil geochemistry was already
used routinely within Shell Oil for reservoir studies.
Specifically, Nederlof et al. (1994) noteed that:
"In Petroleum Development Oman (PDO), molecular oil
compositions are now routinely studied to assess the continuity of
oil accumulations and to identify producing zones after well
completions."
Similarly, a year later, Nederlof et al. (1995) noted that:
"In Petroleum Development Oman (PDO), molecular oil
compositions are routinely studied to assess the continuity of oil
accumulations and to validate the field-wide projection of
oil-water contacts. In most accumulations, the oil composition is
completely homogenized. Abrupt, step-wise changes in composition
are thus interpreted in terms of reservoir discontinuities and
generally imply different oil-water contacts."
The papers describe successful applications of oil
fingerprinting for continuity assessment in the Fahud, Saih Rawl
and Barik Fields. The discussion of the Fahud field is especially
important because this field is the largest oil accumulation in
Oman (16 km long; originally over 6 billion bbls oil in place).
Nederlof et al. (1995) noted that:
"In April 1993, 20 wells were sampled for a reservoir
geochemistry study aimed at identifying possible reservoir
discontinuities. Analysis results showed that all oil have
identical molecular compositions, indicating complete mixing on a
vertical and lateral scale. Comparison of recent oil samples with
those taken in 1975 and 1978 indicate that the Fahud field today is
producing exactly the same oil as twenty years ago, despite the
application of a wide variety of production techniques during the
lifetime of the field. The uniform oil composition also indicates
that the Natih and Huqf oils have completely commingled since
Tertiary times and that, on a geologic time scale, no permeability
barriers exists within the field."
This quote is consistent with the previously mentioned finding
of Hwang et al. (1994) that samples of oil produced from a US Gulf
coast well over a twenty year period had constant fingerprints when
analyzed together. This finding is also consistent with the
conclusion of Hwang and Baskin (1994) that samples of oil collected
over a 21year period from a large Middle Eastern oil field had
identical fingerprints when analyzed as a group. Clearly,
homogeneity of the fingerprints of oils produced over time from
individual reservoir compartments is strongly supported by these
three unrelated case histories.
Westrich et al., 1996; 1999
Two additional Shell publications on the oil fingerprinting
technique are worth noting. Both deal with a very different part of
the world than the Shell publications by Nederlof et al. discussed
above. Westrich et al. (1996) and Westrich et al. (1999) discuss
the successful application of geochemical techniques to reservoir
continuity assessment in the stacked sands of the giant Bullwinkle
field in the northern Gulf of Mexico. Referring to reservoir
continuity assessment in general, the authors noted that:
"Whole oil HRGC [High Resolution Gas Chromatography]
and molecular and isotopic gas analyses have been found to be
widely applicable in the Gulf Coast area, and they are in Shell's
standard tool kit for the offshore Gulf of Mexico."
The authors also sound a theme that is present throughout the
literature on oil fingerprinting:
"The Bullwinkle case study clearly demonstrates that
optimum reservoir characterization results are obtained when
petroleum fingerprinting data are integrated with the results of
other tools and methods".
The authors specifically note the importance of recognizing
compositional gradients within continuous oil
columns when using the fingerprinting technique to assess reservoir
continuity. This point is discussed further elsewhere
on this site. Furthermore, as discussed elsewhere
on this site, it is important to note that "compositional
gradients" are NOT synonymous with "fingerprint gradients."
Noyau et al., 1997
Noyau et al. (1997) used the oil
geochemistry technique to understand the compartmentalization
of a complex reservoir in an onshore Jurassic basin in Yemen. Both
vertical and lateral flow barriers were identified with the
technique. The authors of the paper (who were Total employees)
processed their oil fingerprint data using software licensed from
Chevron. As a result, the technique employed by the Total workers
was similar to that used by the Chevron geochemists who had
published the papers discussed above.
Kaufman et al., 1997
Kaufman et al. (1997) used the oil fingerprinting technique to
help understand compartmentalization of the Greater Bergan field in
Kuwait (one of the largest oil fields in the world). The authors
found that:
"Distinct oil groups are present which correspond to
different reservoir units (Wara vs. Third Bergan) and different
field compartments (Bergan vs. Magwa). This supports other work
which shows the central graben fault complex is a barrier to fluid
flow."
Edman and Burk, 1999
Edman and Burk (1999) demonstrated the use of oil fingerprinting
for assessing reservoir continuity by another oil company (Marathon
Oil). In that study, geochemistry was used as a line of evidence
for successfully assessing reservoir continuity at Ewing Bank 873,
offshore Gulf of Mexico. The authors noted:
"Integration of seismic, well log, geochemical and
pressure data indicates these six turbidite lobes comprise three
compartments. All of the various data types give constraints on
different aspects of compartmentalization, but at the
stratigraphically complex Ewing Bank 873 field, geochemical
analyses provided key information unavailable through any other
means. These geochemical analyses were performed as individual
wells in the field went on production and immediately provided
information regarding fluid communication and reservoir
connectivity that was missing from earlier interpretations based
solely on seismic and log data."
Edman and Burk (1999) did NOT follow the rigorous inter-paraffin
peak/ star diagram process (described elsewhere
on this site) for interpreting their oil GC data. The oils from
each of their compartments were so distinct that they chose simply
to make a visual inspection of the chromatograms to identify oils
from each compartment
Smalley et al., 1992, 1994; England et al., 1995; Smalley and
Hale, 1996
Three papers published by British Petroleum (Smalley et al.,
1992, 1994, and England et al., 1995) used oil and water
geochemical data to successfully assess reservoir continuity in the
Forties Field, North Sea. Although none of those papers used the
oil "star diagram" approach discussed elsewhere
on this site, they did use "statistical analysis of GC peaks,
so-called oil fingerprinting" which is a very similar approach.
Those studies then went one step further by modeling how long it
would take to homogenize oil in a given reservoir by convection
and/or diffusion. They then compared the calculated time with the
amount of time that has elapsed since the reservoir was filled with
oil. The authors inferred compartment barriers to be present when
fingerprint differences existed between oils that should have been
mixed, given the time available since the reservoir was filled with
oil.
Smalley and Hale (1996) used oil fingerprinting, water
composition, several lines of geological evidence, and engineering
data to successfully assess reservoir continuity in the Ross oil
field, U.K. continental shelf.
Halpern, 1995
Halpern, 1995 (Saudi Aramco) used star diagrams constructed from
oil GC data to assess reservoir continuity in several Saudi Arabian
fields. In that study, however, the authors used only C7
compounds to construct the ratios that were plotted on their star
diagrams. Although this approach is a substantial departure from
the procedure described elsewhere on
this site, it is conceptually very similar to the method
described here in that both approaches use differences in oil
fingerprints to infer the presence of continuity barriers.
Additionally, because the C7 compounds generally elute
as single peaks and can be easily identified, Halpern was able to
use peak ratio differences not only to differentiate reservoirs,
but also as indicators of secondary alteration processes that
occurred in the reservoirs.
Additional Information
This article discusses published case studies that have used oil
geochemistry to assess reservoir continuity in an oil accumulation.
Similar geochemical techniques are available for assessing
continuity in a gas accumulation (e.g., Beeunas et al., 1999). Gas
applications are discussed further at the OilTracers LLC web site
devoted to gas geochemistry, www.gaschem.com.
To find additional case studies, or to look for other published
petroleum geochemistry references, search OilRef,
the OilTracers LLC database of almost 15,000 oil geochemistry
references.
For more information on reservoir continuity assessment, or to
discuss a specific project, e-mail us at info@oiltracers.com, or call
us at (214) 548-9169.
References
Beeunas, M. A., D. K. Baskin, and M. Schoell, 1999, Application
of gas geochemistry for reservoir continuity assessment and
identification of fault seal breakdown, South Marsh Island 61, Gulf
of Mexico - Abstract, AAPG Hedberg Research Conference "Natural Gas
Formation and Occurrence" June 6-10, 1999, Durango, Colorado.
Edman, J. D., and M. K. Burk, 1999, Geochemistry in an
Integrated Study of Reservoir Compartmentalization at Ewing Bank
873,Offshore Gulf of Mexico: SPE Paper No.57470.
England, W. A., A. H. Muggeridge, P. J. Clifford, and Z. Tang,
1995, Modelling density-driven mixing rates in petroleum reservoirs
on geological time-scales, with application to the detection of
barriers in the Forties Filed (UKCS), in J. M. Cubbit, and
W. A. England, eds., The Geochemistry of Reservoirs, Geological
Society Special Publication No. 86. The Geological Society of
London, U.K., p. 185-201.
Halpern, H. I., 1995, Development and Applications of
Light-Hydrocarbon-Based Star Diagrams: AAPG Bull., v. 79, p.
801-815.
Hwang, R. J., A. S. Ahmed, and J. M. Moldowan, 1994, Oil
composition variation and reservoir continuity: Unity Field, Sudan:
Org. Geochem., v. 21, p. 171-188.
Hwang R. J. and Baskin D. K. (1994). Reservoir connectivity and
oil homogeneity in a large-scale reservoir. Middle East Petroleum
Geoscience Geo94 2, 529-541.
Kaufman, R. L., A. S. Ahmed, and R. J. Elsinger, 1990, Gas
Chromatography as a development and production tool for
fingerprinting oils from individual reservoirs: applications in the
Gulf of Mexico, in D. Schumaker, and B. F. Perkins, eds.,
Proceedings of the 9th Annual Research Conference of the Society of
Economic Paleontologists and Mineralogists, October 1, 1990: New
Orleans, p. 263-282.
Kaufman, R. L., H. Dashti, C. S. Kabir, J. M. Pederson, M. S.
Moon, R. Quttainah, and H. Al-Wael, 1997, Characterizing the
greater Burgan Field: Use of geochemistry and oil fingerprinting:
SPE Paper No. 37803, p. 385-394.
Lindberg, F. A., A. S. Ahmed, and D. C. T. Bluhm, 1990, The role
of oil-to-oil correlation in the development of the Safah field
(abstract): AAPG Bulletin, v. 74, p. 705.
Nederlof, P. J., M. A. Gijsen, and M. A. Doyle, 1994,
Application of reservoir geochemistry to field appraisal, in M.
I.Al-Husseini, ed., The Middle East Petroleum Geosciences Geo '94,
vol.2.Gulf-Petrolink, Bahrain, p. 709-722.
Nederlof, P. J. R., F. M. van der Veen, and G. A. van den Bos,
1995, Application of reservoir geochemistry in Oman, in J.
O.Grimalt, and C. Dorronsoro, eds., Organic Geochemistry:
Developments and Applications to Energy, Climate, Environment and
Human History. Selected Papers from the 17th International Meeting
on Organic Geochemistry, Donostia-SanSebastián, The Basque Country,
Spain: San Sebastian, AIGOA, p. 329-331.
Noyau, A., P. Chavagnac, E. W. Tegelaar, and F. Daugas, 1997,
Reservoir Characterization Applying Geochemical Techniques: Case
Study From Yemen, Paper No. 37703: SPE.
Ross, L. M., and R. L. Ames, 1988, Stratification of oils in
Columbus basin off Trinidad: Oil & Gas J., Sept. 26 issue, p.
72-76.
Slentz L. W. (1981), Geochemistry of reservoir fluids as unique
approach to optimum reservoir management. SPE #9582. Presented at
Middle East Oil Technical Conference, Manama, Bahrain.
Smalley, P. C., and W. A. England, 1992, Assessing reservoir
compartmentalization during field appraisal: How geochemistry can
help: SPE Paper No. 25005, p. 423-431.
Smalley, P. C., and W. A. England, 1994, Reservoir
Compartmentalization Assessed with Fluid Compositional Data: SPE
Res. Eng., v. August, p. 175-180.
Smalley, P. C., and N. A. Hale, 1996, Early Identification of
Reservoir Compartmentalization by Combining a Range of Conventional
and Novel Data Types, SPE Paper No. 30533.
Sundararaman, P., B. A. Patterson, and O. T. Udo, 1995,
Reservoir geochemistry: applications and case studies in Nigeria,
in J. O. Grimalt, and C. Dorronsoro, eds., Organic Geochemistry:
Developments and Applications to Energy, Climate, Environment and
Human History. Selected Papers from the 17th International Meeting
on Organic Geochemistry, Donostia-SanSebastián, The Basque Country,
Spain: San Sebastian, AIGOA, p. 369-371.
Westrich, J. T., P. O. Knigge, A. N. Feux, and H. I. Halpern,
1996, Evaluating reservoir architecture in the northern Gulf of
Mexico using oil and gas chemistry: SPE Paper No. 36541, p.
513-519.
Westrich, J. T., A. M. Fuex, P. M. O'Neal, and H. I. Halpern,
1999, Evaluating Reservoir Architecture in the Northern Gulf of
Mexico With Oil and Gas Chemistry: SPE Paper No. 59518.