Case Studies in Reservoir Continuity Assessment

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Oil geochemistry can be used to assess reservoir continuity. Using oil fingerprinting methods or various similar approaches, published case studies have described how oil geochemistry can be used to assess reservoir continuity. Similar geochemical techniques are available for assessing continuity in a gas accumulation (e.g., Beeunas et al., 1999).

Some of the key studies are summarized below. The exact types of data used to assess reservoir continuity varied from study to study, but oil fingerprinting played a key role in each study.

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. 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, because 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) noted 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.

The key to evaluating reservoir compartmentalization

Oil geochemistry typically provides a very inexpensive key to interpreting ambiguous geological and/or engineering information. At OilTracers, we assess reservoir compartmentalization by integrating geochemical, geological, and engineering data to determine the sealing capacity of potential no-flow barriers.

For more information on the techniques described here, or to discuss a specific project, e-mail us at, or
call us at U.S. (214) 584-9169.


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