INTRODUCTION

Both associated and nonassociated gases are produced from nonmarine sandstone reservoirs of Tertiary age in the Cook Inlet basin of southern Alaska. The nonassociated gas occurs in rocks of the Kenai Group, or specifically in the upper part of the Tyonek Formation and Beluga Formation of Miocene age and in the Sterling Formation of Miocene and Pliocene age. The associated gas is produced from oil fields whose reservoirs are in the West Foreland Formation of Paleocene age and in the Hemlock Conglomerate and lower part of the Tyonek Formation of Oligocene age. The names and locations of the nonassociated and associated gas fields are shown on Figure 1. The producing horizons of these fields are shown in Figure 2.

The stratigraphic and compositional separation of the two types of gas occurrences in Cook Inlet basin suggests different origins for these hydrocarbons: biogenic origin for the nonassociated gas fields and thermogenic origin for the oil-associated gas fields. Knowledge of the origin of these gases can affect exploration strategy and should increase discovery of new accumulations. Nonassociated reserves were placed at 1.85 × 10¹¹ m³ by Blasko (1974), and associated gas is estimated to be 1.13 × 10¹⁰ m³ using a gas-oil ratio of 196 m³/m³ as outlined on Table 1.

Sources of information for the Cook Inlet fields are available from the Alaska Geological Survey (1970), Blasko (1974), and Alaska Division of Oil and Gas Conservation (1977). The nonassociated gas fields in Cook Inlet are shut in, except for the Beluga River, North Cook Inlet, Kenai, and McArthur River gas fields.

Kelly (1963, 1968) discussed the origin of both gas and oil in the Cook Inlet. Origin of the oil has also been discussed by Osment et al (1967), Young et al (1977), and Magoon and Claypool (1979). Two possible sources of the oil are indicated: the Tertiary (Kelly, 1968; Young et al, 1977) and underlying Middle Jurassic rocks (Magoon and Claypool, 1979). In both examples the associated gas is thought to have been generated at the same time or after the oil.

Framework geology of the Cook Inlet basin has been described by Detterman and Hartsock (1966), Kirschner and Lyon (1973), Boss et al (1976), Magoon et al (1976), and Fisher and Magoon (1978).

Gas samples were analyzed by thermal-conductivity gas chromatography. Volume percent of the constituents methane (C₁), ethane (C₂), propane

End_Page 1131------------------------------

(C₃), butanes and pentanes (C₄₊), carbon dioxide (CO₂), and nitrogen and air (N₂ - air) are reported. The methane peak was quantitatively collected and converted to CO₂ in a vacuum combustion system (Threlkeld and Claypool, unpub. data). The stable carbon isotope ratio was measured on a Neir-McKinney mass spectrometer, and reported in the ^dgr-notation relative to the Pedee belemnite (PDB) marine carbonate standard:

[EQUATION]

RESULTS

Analyses of Cook Inlet natural gas occurrences are summarized in Tables 2 (nonassociated) and 3 (associated). The volume percentage of selected components is reported, together with the proportion of methane in the hydrocarbon fraction (C₁/C_1-5) and the stable carbon isotope ratio (^dgr¹³C) of the methane component. The proportion of methane in the hydrocarbon fraction is distinctly different for associated and nonassociated gases. Nonassociated gases are uniformly dry (C₁/C_1-5 >= 0.99), whereas associated gas (excluding those sampled after separation) contain appreciable

Fig. 1. Map showing location of oil (solid) and gas fields (stippled) in Cook Inlet region, Alaska. Modified from Alaska Geological Society (1970).

End_Page 1132------------------------------

contents of heavy hydrocarbons (0.69 <= C₁/C_1-5 <= 0.90). Associated gas from the Hemlock Conglomerate in the Swanson River field exceeds 95% methane because the sample was obtained at the separator after removal of heavy ends. Carbon dioxide contents of the gas samples are uniformly low, in the range of 0.1 to 0.3%. Exceptions are the associated gas samples from the Trading Bay field which have 0.8 and 1.1% CO₂. Crude oil in Trading Bay field is biodegraded (Magoon and Claypool, 1979), and higher CO₂ content in the gas may reflect bacterial oxidation of petroleum hydrocarbons. For most of the samples, the N₂-air component is probably pure nitrogen, which appears to increase with depth of burial over the range from 1 to 5%. amples with greater than 10% N₂-air are believed to reflect some atmospheric contamination, particularly in the Bowser Creek seep (19.08%) and the McArthur River G-14 separator samples

Fig. 2. Age and stratigraphic position of producing horizons for oil and gas fields of Cook Inlet region, Alaska. Stratigraphic position of gas samples indicated by sample numbers from Tables 2 and 3. Modified from Alaska Geological Society (1970).

End_Page 1133------------------------------

(57.49%).

The stable carbon isotope ratio (^dgr¹³C) of the methane component shows some overlap between associated and nonassociated gases. Most (12 of 15) dry, nonassociated gases are isotopically light in the range from -56 to -62 per mil (^dgr¹³C), and most (7 of 11) associated gases are isotopically heavy in the range from -44 to -49 per mil. Thus, associated and nonassociated gases are separated on the basis of chemical composition, methane ^dgr¹³C, and stratigraphic occurrence. The grouping of nonassociated and associated gases on the basis of methane ^dgr¹³C and hydrocarbon composition (C₁/C_1-5) is illustrated in Figure 3.

Gas from nonassociated pools in the Cook Inlet increases regularly in both C₁/C_1-5 and ^dgr¹³C with increasing depth of burial over the range from 600 to 2,800 m, as shown in Figures 4 and 5. The shallowest, driest, and isotopically lightest nonassociated gas is from Nicolai Creek field. With minor exception, samples from the Tyonek Formation at Kenai and Swanson River fields are the deepest, wettest, and isotopically heaviest nonassociated gas. Associated gases do not show a consistent depth relation for hydrocarbon composition or methane ^dgr¹³C.

Table 1. Status of Petroleum Resources

End_Page 1134------------------------------

Table 2. Chemical and Isotopic Composition of Nonassociated Natural Gas in Cook Inlet

End_Page 1135------------------------------

Table 3. Chemical and Isotopic Composition of Associated Natural Gas in Cook Inlet

End_Page 1136------------------------------

DISCUSSION

Geologic and geochemical evidence suggests that the two different types of natural gas in the Cook Inlet basin, nonassociated and associated, originated by different mechanisms. We believe that the shallow, nonassociated gas is accumulated marsh gas of low-temperature (< 70°C) biologic origin and is indigenous to the nonmarine Kenai Group. In most places, the associated gas originated with liquid hydrocarbons (oil) at higher temperatures, by nonbiologic, thermogenic processes. This gas has migrated with oil into lower Tertiary reservoir rocks from underlying marine source rocks of Middle Jurassic age (Magoon and Claypool, 1979).

Other possibilities can be suggested for the origin of the shallow Cook Inlet gas. One alternative might be that the shallow, dry gas has a common origin with the oil and is a product of separation-migration (Silverman, 1965). Colombo et al (1965) and Neglia (1979) proposed that migration results in chemical and isotopic fractionation so that resultant shallow gas is drier and isotopically lighter than gas in equilibrium with the deeper parent hydrocarbon deposit. This alternative is discounted for two reasons:

1. The Cook Inlet oils are undersaturated with gas to the extent that repressurization by gas or water injection into the reservoirs is common practice, whereas the separation-migration mechanism requires a gas-saturated liquid hydrocarbon system.

2. Gas migration has not been observed to produce a consistent, significant isotopic effect (Coleman et al, 1977).

A second possibility for the origin of the shallow Cook Inlet gas is generation by low-temperature thermogenic processes during early stages of coalification. This process contributes to Cook Inlet gas occurrence, and becomes increasingly more important with increasing depth of burial. However, the total contribution of thermogenic gas is probably minor. Significant thermogenic methane production from coal does not occur until the higher rank stages (88 to 93% carbon, ash-free) are reached (Juntgen and Klein, 1975). In addition, coalification gas generated in laboratory experiments is initially higher in wet-gas components than are the shallow Cook Inlet gases (Kim, 1974; Harwood, 1977).

Low-temperature, biogenic methane production is the mechanism we favor for the origin of the shallow, dry Cook Inlet gas. Abundant coal beds were deposited in Cook Inlet basin throughout the Tertiary. These coals are bituminous or lower in rank (70 to 75% carbon, ash-free), even where buried as much as 3.6 km (Castano and Sparks, 1974). A biologic mechanism of gas generation in Kenai Group rocks is consistent with both the apparent low-temperature history of the gas accumulations and the composition of gas which is isotopically light and chemically dry.

The oil and associated gas of the Cook Inlet basin is attributed to a Middle Jurassic source because Kenai Group rocks are thermally immature at all localities analyzed (Castano and Sparks, 1974; Magoon and Claypool, 1979). In contrast, Middle Jurassic rocks from the Iniskin Peninsula include thermally mature shales that have an extractable hydrocarbon assemblage identical in many respects to that of "typical" Cook Inlet oil (Magoon and Claypool, 1979). The methane ^dgr¹³C for most Cook Inlet associated gas is in the same range as associated gas derived from marine source rocks in other areas (Stahl, 1975; Fuex, 1977). This indicates a similar source for the deeper, smaller reserves of associated gas in the Cook Inlet basin.

Although nonassociated and associated gas occurrences generally have a distinct chemical and methane carbon isotopic composition, exceptions do exist. Isotopically light associated gas may reflect two different causes. Three of the four examples of wet associated gas with methane ^dgr¹³C values in the range of -53 to -59 per mil occur in the Tyonek and West Foreland Formations from the McArthur River and Beaver Creek fields. A

Fig. 3. Hydrocarbon composition and methane carbon isotope ratio, Cook Inlet natural gas.

End_Page 1137------------------------------

possible explanation for this gas is that crude oil undersaturated in thermogenic gas migrated into reservoirs at shallower depths (Magoon and Claypool, 1979) and that these reservoirs were partly occupied by dry gas of biogenic origin. Coal beds, which were favorable for biogenic methane production, are present in the lower part of the Tyonek Formation throughout the Cook Inlet basin, whereas coals are absent in the Hemlock Conglomerate. Coals are also present in the West Foreland Formation under the Middle Ground Shoal oil field (Boss et al, 1976). An artificial cause for the isotopically light associated gas may be more likely. Oil in the Hemlock zone of Swanson River field has been repressurized with isotopically light, dry gas from the Kenai field and from shallow gas zones in th Swanson River field. Compositional material-balance studies indicate that much of this gas has dissolved in the oil (F. Cordiner, 1979, personal commun.) and could have caused dilution of thermogenic methane, thereby raising the methane ^dgr¹³C from -47 to -54 per mil. In addition, Cook Inlet dry gas from shallower zones has been used to help gas lift oil production (T. Wilson, 1979, personal commun.). This is standard practice at Beaver Creek field, and has been used occasionally in McArthur River field.

Isotopically heavier (-48.4, -50.4 per mil) methane is produced from the lower part of the Tyonek Formation at Kenai and Swanson River fields. These deeper, heavier, nonassociated dry gases probably represent some combination of (a) cumulative, late-stage biogenic methane production from a dissolved bicarbonate reservoir depleted in ¹²C (^dgr¹³C = +15 per mil), and (b) increasing contribution of early thermogenic methane at greater depths. Addition of thermogenic methane is supported by the increase of both C₂+ constituents and methane ^dgr¹³C with depth (Figs. 4, 5). As shown in Figure 4, C₁/C_1-5 decreases from 0.999 to 0.997 with depth in nonassociated gas occurrences within the nonmarine Tertiary sequence. However, a dition of thermogenic methane in proportions indicated by the C₂-C₅ contents probably cannot account for the increase in methane ^dgr¹³C from -63 to -48 per mil. Alternatively, this deeper nonassociated gas could be dominantly of thermogenic origin, if gas produced during early stages of coalification is significantly drier in chemical composition than is indicated by experimental coalification studies (Kim, 1974; Harwood, 1977).

The possibility that this heavier dry gas has migrated from the underlying Hemlock zone, with chemical fractionation, has been eliminated because such chemical fractionation has not been documented for sizable gas accumulations. The dry gas with the heaviest methane (-43.7 per mil) was obtained at a depth of 1.3 km in the Tyonek Formation at the McArthur River field. The ^dgr¹³C value of this gas is anomalous for dry,

Fig. 4. Hydrocarbon composition of nonassociated gas versus depth of gas pool.

Fig. 5. Methane carbon isotope ratio of nonassociated gas versus depth of gas pool.

End_Page 1138------------------------------

nonassociated gas in immature sediments. The high N₂-air (undifferentiated) content in this sample makes its authenticity suspect, and it should be confirmed by resampling and analysis before trying to reconcile its composition with methanogenic processes in Cook Inlet sediments.