Controls on the Gas-Oil Ratio in a Petroleum Accumulation

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Gas-Oil Ratios (GOR's) may vary substantially among petroleum accumulations in a basin due to a variety of factors. 

 

 


These factors fall into 3 categories:

1. Source-related factors

2. Migration-related factors

3. In-Reservoir Alteration

 

1. Source-related factors

Organic matter Type. Type III organic matter (derived primarily from higher plants) is more gas prone than Type II or Type I organic matter (derived primarily from algae). Therefore, differences in organic matter type across a basin can result in differences in the GOR of the various accumulations. This effect is commonly seen in deltas, for example, where the average GOR of petroleum accumulations sourced from a higher-plant-rich delta-plain facies is greater than the average GOR of accumulations sourced form more algal-rich pro-delta facies

Source rock maturity: As a source rock matures, the GOR of the expelled products rises. Differences in source maturity across a basin can therefore affect the GOR of the various overlying petroleum accumulations.

2. Migration-related factors:

The classic "Gussow" fill-spill migration sequence (Gussow, 1954): In a series of traps that have a fill-spill relationship away from the source kitchen (where traps spill from the bottom of one trap to the next up-dip trap, and then spill from the bottom of that trap to the next up-dip trap), traps closest to the kitchen would have a higher GOR (assuming a completely efficient gas and oil seal for all of the traps in the sequence).

Differences in seal efficiency between traps: The most efficient seals with respect to both oil and gas are evaporites (halite, anhydrite, etc.), mineralized shales, and igneous rocks. Other rock types (such as normally pressured shales) create less efficient seals. For such imperfect seals (which form the seals of most accumulations), an accumulation is most likely to leak where the column height is greatest (e.g., at the crest of a structure), since the capillary pressure is highest there. Since a gas phase, if present in the accumulation, is located at the top of the petroleum column, accumulations at bubble point will selectively lose gas if there is a sufficiently thick petroleum column (e.g., Sales, 1993). Therefore, a gas is more likely to be lost from an accumulation than is oil. As a result, differences in seal lithology between traps in a basin can result in differences in the GOR of the accumulations, even if the GOR at the time each trap was charged were the same among the various traps. Some points to note regarding the discussion above:

In all cases (except diffusion), the petroleum must be at bubble point for phase separation to occur.

The effect of the height of the column on capillary pressure has a much more important effect on seal leaking than does differences in the sealing capacity between gas and oil. In general, gas has higher surface tension and less wetability than oil, so at a given capillary pressure, a seal will more effectively hold back gas than oil. However, gas is less dense than oil, and, as a result, for a given column height, the added buoyancy of the gas (relative to a similar column height of oil) overcomes the higher surface tension of the gas relative to oil.

Exactly the same seal efficiency concept applies to fault seals. Faults may, or may not, be good seals (e.g., Brown, 2003): the sealing capacity of a fault depends on factors such as (i) what lithology is juxtaposed against what, and (ii) the composition of the fault gouge (e.g., Allan, 1989). Therefore, differences in seal lithology and fault characteristics between one trap and another plays an important role in determining the GOR of an accumulation (e.g., Watts, 1987). An accumulation is most likely to leak across a fault where the column height is greatest, since the capillary pressure is highest there. Since a gas phase, if present in the accumulation, is located at the top of the petroleum column, accumulations at bubble point will selectively lose gas across a fault if there is a sufficiently thick petroleum column. Therefore, a gas, if present, is more likely to be lost across a fault seal than is oil.

Evaporative fractionation: Sometimes called "Gas Washing", this is a geologic process in which (1) a charge of gas (generally dry) enters an existing oil accumulation, (2) the gas then equilibrates with the light components of the reservoired oil, and then (3) the gas leaks from the accumulation, taking with it dissolved components that originally were part of the oil accumulation. The migrating gas may then condense out a liquid (or "retrograde condensate") in a shallower reservoir at lower pressure. Therefore, this process is the cause of two new fluids: (1) High-gravity retrograde condensate in a shallower reservoir, and (2) Lower gravity, more aromatic residual oil (in the original reservoir) depleted in light paraffins and enriched in the other fractions. This process is common in deltaic stacked pay sands (e.g., Thompson, 1987, 1988).

3. In-Reservoir Alteration:

Cracking of oil in high temperature reservoirs (>140 °C when TSR is active; >150-170 °C when TSR is not active).

Bacterial gas formation: In shallow biodegraded accumulations (reservoir temperatures <80 °C), bacterial reduction of CO2 to form biogenic gas can raise the GOR of biodegraded accumulations (e.g., Larter et al., 2006).

Oil geochemistry and Gas Geochemistry can be used to evaluate which of the items above are responsible for differences in GOR between accumulations in a basin. For example, Gas Chromatography (GC) and biomarker analyses can indicate whether oils from different accumulations were generated from sources rocks with different organic matter type. Similarly, GC and biomarker analyses can indicate whether oils from different accumulations were generated from sources rocks of different maturity. The presence or absence of post-emplacement alteration can also be evaluated using oil geochemistry and gas geochemistry.

Migration modeling can be used to evaluate aspects of (2) above. Characterization of the trap and seal geology can help evaluate other aspects of (2) above.

In summary, a report that integrates oil geochemistry, gas geochemistry, migration modeling, and geology can lead to an improved understanding of the causes of GOR variations in a basin.

 

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

REFERENCES

Allan, U.S., 1989, Model for hydrocarbon migration and entrapment within faulted structures: AAPG Bulletin, v. 73, p. 803-811.

Brown, A., 2003, Capillary effects on fault-fill sealing: AAPG Bulletin, v. 87, p. 381-395.

Gussow, W. C., 1954, Differential entrapment of oil and gas: a fundamental principle: AAPG Bulletin, v. 38, p. 816-853.

Larter, S., H. Huang, J. Adams, B. Bennett, O. Jokanola, T. Oldenburg, M. Jones, I. Head, C. Riediger, and M. Fowler, 2006, The controls on the composition of biodegraded oils in the deep subsurface: Part II - Geological controls on subsurface biodegradation fluxes and constraints on reservoir-fluid property prediction: AAPG Bulletin, v. 90, p. 921-938.

Sales, A., 1993, Closure vs. seal capacity: a fundamental control on the distribution of oil and gas: in.: AAPG Hedberg Conference: Seals and Traps: a multidisciplinary approach: June 1993, Crested Butte, CO (Abstr.).

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.

Watts, N. L., 1987, Theoretical aspects of cap-rock and fault seals for single- and two-phase hydrocarbon columns: Marine and Petroleum Geology, v. 4, p. 274-307.


A report that integrates oil geochemistry, gas geochemistry, migration modeling, and geology can lead to an improved understanding of the causes of GOR variations in a basin.