ENGINEERING PROPERTIES AND ALTERATION

Three aspects of the variability of reservoir fluid oils are described, firstly, the wide range of combinations of values which may be expressed in any pair of commonly measured engineering variables; secondly, the regional nature of the variability, that is, the coherence within, and differences between, geographic-stratigraphic sets; thirdly, that the coherence can be expressed in terms of variables which are construed here as the result of factors other than genetic nature and maturity.

Relationship of Gas Composition and Fluid Properties

Thompson (2006) showed that methane concentration exerts significant influence on important petroleum properties. The following equations were given:

Saturation Pressure (Pb, MPa) = 4.55 + 0.036(C1%) + 0.0083(C1%)^2, r = 0.91

and

Gas/Oil Ratio (m³/m³) = 4.53 + 3.13(C1%) + 0.0107(C1%)^2, r = 0.62, (read "C1% squared)".

Correlations of this type are expanded here, particularly the observed partial dependence of gas/oil ratio (GOR) and bubble point (saturation pressure, Pb) on the C1/C2 ratio in reservoir fluids, a fundamental variable in gas-liquid relationships. GOR and Pb depend differently and variously with separator conditions, upon C1/C2 in gas samples.

Figure 25 illustrates the distribution of paired values of GOR and Pb in the suite of 535 PVT analyses. Only a weak correlation exists but several lineaments are apparent, reflecting not only geographic-stratigraphic suites, but suites of closely similar oils in terms of at least one variable, the C1/C2 ratio. Examining the data geographically, several trends can be identified. Between the origin and locus “a” in Fig. 25 there occur low maturity oils from Saskatchewan with modal C1/C2 values between 2.0 and 2.75. The trend towards “b” includes P6 oils from both Palaeozoic and Cretaceous reservoirs in western Canada. Oils from the North Sea, examined in detail below, contribute to the trend towards “c”. Trend “d” represents oils from the U.S. Gulf of Mexico shelf and the Beaufort Sea, regions characterized by extreme fractionation and biodegradation.

A facsimile of Fig. 25 was created by selecting a subset from the suite of 525 PVT analyses comprising those possessing elevated values of nC5/iC5, in order to eliminate the effects of biodegradation. Compromising between sample size and ratio value, a subset of 86 cases representing the 83rd and higher percentile levels was culled at a value of nC5/iC5 equal to, or greater than, 1.50. The plot of GOR versus saturation pressure for these cases formed a virtual overlay (not illustrated) of Fig. 25, sparsely populated, but with a significant number of cases illustrating each of the trends "a" - "d" of Fig. 25. It is concluded that evaporative fractionation alone is sufficient to account for the variations in fluid properties reflected in the range of paired values of gas-oil ratio and saturation pressure illustrated in Fig. 25, substantially due to gas injection raising C1/C2 ratios and depleting the gasoline range. An illustration analogous to Fig. 25 was generated by England (2002) for gas-condensates, showing regional trends in a comparable fashion: liquid-rich gas-condensates in Alberta, intermediate types in the North Sea, and relatively dry fluids with high dew points in Louisiana. No compositional contrasts between these subsets were provided. It is suggested here that the progression of conditions ("Alberta" to "Louisiana" types) reflects the degree of evaporative fractionation operative on the average oils persisting in each basin, that is, the average extent of light end removal. The sequence is a reflection of progressive basin-wide petroleum evolution.

A series of curves representing the data of Fig. 25 are defined in Figure 26 , where the paired GOR-Pb values are subdivided into seven classes on the basis of the C1/C2 ratio of the fluid. The constants of the equations defining the illustrated regressions are given in Table 4.

Figure 27 illustrates the relationship of GOR and saturation pressure for oils possessing C1/C2 ratios in the modal range 3.5 - 4.0, subdivided by the maturity parameter SF(P15-P25). Level of maturity plays a secondary role in determining GOR and saturation pressure. Values overlap among the three illustrated classes, but within each, means and ranges of GOR and Pb increase with maturity. Numerous fluids in the highest maturity class, having API gravities averaging 41.7 degrees and slope factors greater than 1.140, are volatile oils, such as the labeled cases 382 and 383 (having values of (SF(P15-P25) of 1.219 and 1.230, respectively) representing Brassey field, Triassic, northwestern Alberta. Volatile oils are defined by their engineering characteristics, generally having API gravities greater than 45 and GOR’s over 360 m3/m3, existing close to the critical point of the mixture. In GOR-Pb curves based on C1/C2 ratios these oils occur at the apices of the curves at relatively high GOR and low Pb values for their C1/C2 ratios, often close to 4.0. Further characteristics in common are: P5/P6 ratios greater than the modal value of 0.79, and low concentrations of P30+, i.e., values close to 1% rather than close to the average, 3%, compatible with light end addition. It is possible that many are retrograde condensates or reflect the addition of gas-condensate to highly mature oils.

Regional Variation of Oil

Engineering studies of oils have, in the past, resulted in “correlations” whereby engineering properties commonly obtained only by laboratory PVT analysis can be estimated from field measurements (GOR, saturation pressure and gas gravity). There are many such correlations representing most of the major producing regions of the world, for example, those of Standing (1947, California), Glasø (1980, North Sea), and Al-Marhoun (1985, Middle East). As may be inferred from Fig. 25, most are regionally unique. The suite of 535 PVT analyses is evidently globally representative, as it fully reflects the range expressed in published data.

The literature shows that regional oil suites frequently exhibit well-defined curves possessing elevated correlation coefficients relating GOR and Pb. Such curves can be closely matched to those identified on the basis of C1/C2 ratios in Fig. 26. The phenomenon is evaluated in Figs. 28 and 29 by comparison of GOR-Pb data from two published suites with paired values making up two of the regressions of Fig. 26.

Figure 28 compares the relationships in oils from the United Arab Emirates (U.A.E. data of Dokla and Osman, 1992) and from the Middle East (data of Al Marhoun, 1985) with those in oils of the present study possessing C1/C2 ratios between 3.0 and 4.5 (Class 2, Fig. 26), randomly reduced in number by 50% for clarity. Although Class 2 principally represents both clastic and carbonate oils from western Canada, numerous cases are from Columbia, Indonesia, Venezuela, North Dakota and Alabama. It is inferred from the match of properties that the majority of oils from the Middle East and the United Arab Emirates possess C1/C2 ratios of 3.0 to 4.5 and are therefore largely unaffected by evaporative fractionation. U.A.E. oils having GOR’s greater than approximately 216 m3/m3 (1.2 mcf/bbl) are inferred to be of elevated maturity and/or possess admixed gas also of modal C1/C2 ratio.

Figure 29 compares the data of Glasø (1980) for North Sea oils with those of the present study having C1/C2 ratios of 6.5 to 9.0 (Class 5). Again, it is inferred that this range must approximate the (unknown) ratios expressed in Glasø’s North Sea oils. There are 34 PVT analyses from the Norwegian North Sea in the present study. The mean C1/C2 ratio is 6.89±3.64. Three additional analyses representing oils from Bruce field, not included in Fig. 28, exhibit a mean C1/C2 ratio of 6.39, possess secondary maxima at P8, and elevated E7 values. These observations confirm the inferences drawn from the match in properties illustrated in Fig. 28, that the majority of North Sea oils exhibit incipient to moderately well developed evaporative fractionation, gas-condensate advection and methane enrichment. Ther are numerous literature references to evaporative fractionation of oils in the Norwegian North Sea.

Oils in the suite of 535 cases which have C1/C2 ratios between 15 and 65 make up Class 7 in Fig. 26, illustrated by trend “d” in Fig. 25, those with the highest saturation pressures at the lowest GOR’s. Virtually all those illustrated derive from two regions, the lower values from the Beaufort Sea, mid-range and elevated values from the U.S. Gulf of Mexico continental shelf. In non-sterile reservoirs such as the majority of those on the Gulf of Mexico shelf it is suggested that evaporative fractionation and biodegradation have contributed to light end loss (Thompson and Kennicutt, 1990; Requeo and Halpern, 1990), similarly in the Beaufort Sea. It is possible that biogenic methane takes part as a fractionating gas (Thompson, 1987).

As shown by the isopach maps of Thompson et al. (1990), the Gulf Coast shelf area is located in the region of maximum depth of burial of the source rocks, expectably exhibiting the greatest gas drive. The basin axis is located immediately seaward of the Louisiana and adjacent Texas coast lines. Losh et al. (2002) showed that evaporative fractionation is almost universal the regional oils, evidenced by the carbon number of the secondary maximum and its degree of displacement. Both features progressively decrease seaward of the coast line, therefore, of the axis, compatible with decreasing gas drive. The Gulf Coast hosts a highly evolved petroleum basin with over 50,000 feet of burial of its Mesozoic sources in the axial region.

Regionally Consistent Petroleum Properties

GOR and Pb characteristics are broadly determined by maturity, substantially modified by the various processes involved in evaporative fractionation, further modified in cool, unsterilized, reservoirs by biodegradation. Evaporative fractionation is gas-driven. It is evident that oils in many petroleum provinces exhibit limited ranges of engineering properties and therefore possess compositional similarities. The latter are construed here as suggesting that progression through the series of conditions illustrated by the curves of Fig. 26 characterizes the evolution of oils in terms of gas migration and phase change. It is suggested that the extent of the progression depends upon the volume of gas expelled late in burial history from a source region, depending in turn upon the depth, quality and history of burial of the source sequence, gas principally following the migration paths taken earlier by oil. A cascading process is visualized, the most mature gases mixing with and displacing those of intermediate maturity up-dip, with progressive displacements of lower maturity gases towards the basin margins. This hypothesis is similar to that of Gussow (1954), but substitutes advection and fractionation for differential trapping. Extremely few of the oils examined suggest an unaltered nature, inferring that migration paths remain open for extended periods of geological time. An unaltered oil suggests that an early-filled reservoir shortly became isolated from the pathway by way of which it was charged.

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