Controls on the Origin and Distribution of ... - ACS Publications

Chapter 24

Controls on the Origin and Distribution of Elemental Sulfur, H S, and C O in Paleozoic Hydrocarbon Reservoirs in Western Canada Downloaded by NORTH CAROLINA STATE UNIV on May 8, 2015 | http://pubs.acs.org Publication Date: May 5, 1995 | doi: 10.1021/bk-1995-0612.ch024

2

1

2

2

3

Ian Hutcheon , H. Roy Krouse , and Hugh J. Abercrombie 1

3

2

Department of Geology and Geophysics and Department of Physics and Astronomy, University of Calgary, Calgary, Alberta T2N 1N4, Canada The Institute of Sedimentary and Petroleum Geology, 3303 33rd Street, Northwest, Calgary, Alberta T2L 2A7, Canada H S and CO are observed in natural gas in the Western Canada Sedimentary Basin (WCSB) and concentrations increase with depth and temperature. Paleozoic waters are saline (70-250 g/L TDS) and approach equilibrium with anhydrite, the probable sulfur source for H S. The C composition of hydrocarbon gases associated with H S is consistent with hydrocarbon oxidation. Molar volumes of anhydrite and H S are similar at reservoir temperatures and pressures. Calculations show that 0.35 X H S could be formed by 1 volume % anhydrite. These observations are consistent with a closed-system origin for H S. Modeling of thermochemical sulfate reduction (TSR) shows that 75% of the porosity created by dissolution of anhydrite in a closed system is lost to calcite precipitation. Moving H S away from the site at which TSR takes place creates more porosity, however the isotopic data do not support an open system model. 2

2

13

2

2

2

2

2

2

Oil and gas reservoir rocks in the uplifted Western Canada Sedimentary Basin (WCSB) range in age from Cambrian to Tertiary. The basin can be divided broadly into a deeper Paleozoic section comprised of limestone and dolomite and a shallower, predominantly clastic, Mesozoic section. The Paleozoic section of the basin hosts numerous oil and gas pools and the stratigraphy, sedimentology and petroleum geology have been extensively studied. High H2S concentrations occur in hydrocarbon gas pools in this part of the basin, generally in deeper reservoirs. The origin of H2S, CO2 and native sulfur is the subject of this paper. We examined the H2S and CO2 content of natural gases and chemical and isotopic data published for formation waters and gases in the Alberta portion of the WCSB in order to recognize possible controls on the origin, distribution and amount of H2S. H2S has economic importance because it decreases the value of natural gas and may play a role in both the formation of dissolution porosity and destruction of porosity by cementation during diagenesis. H2S may originate by microbial or inorganic processes (7) and, as a reactive gas, the concentrations may be affected by reactions with enclosing rocks and associated waters, 0097-6156/95/0612-0426$12.00/0 © 1995 American Chemical Society In Geochemical Transformations of Sedimentary Sulfur; Vairavamurthy, M., et al.; ACS Symposium Series; American Chemical Society: Washington, DC, 1995.

Downloaded by NORTH CAROLINA STATE UNIV on May 8, 2015 | http://pubs.acs.org Publication Date: May 5, 1995 | doi: 10.1021/bk-1995-0612.ch024

24.

HUTCHEON ET AL.

Controls on the Origin of Elemental Sulfur

427

There are numerous compositional analyses of natural gas in the Western Canada Sedimentary Basin (WCSB) publicly available through the Alberta Energy and Utilities Board (AEUB, formerly the Alberta Energy Resources Conservation Board) pool average gas data base (2) and the CO2, H2S, N2 and He content is routinely reported. Isotopic analyses of hydrocarbon and non-hydrocarbon gas components in reservoirs are reported from various geological settings (3) and it has been suggested (4) that high H2S concentrations in Paleozoic reservoirs originate from thermal (abiological) sulfate reduction. Analyses of waters are abundant in the AEUB data, but most tend to be incomplete with Ca, Mg, Cl, SO4 and alkalinity measured directly and Na+K concentrations reported as the difference in charge balance between cations and anions. A few published studies (5-9) have reported high quality chemical and isotopic analyses of waters from the WCSB. These data are used in this paper to help define the possible origins of H2S in deeply buried carbonate reservoirs of Paleozoic age in the WCSB. Water and Gas Compositions in Western Canada General Trends in Gas Chemistry. The partial pressure of H2S and CO2 in both Paleozoic and Mesozoic reservoir rocks tends to increase with temperature and, therefore, depth. Figure 1 shows PH2S for Devonian and Mississippian age reservoirs and at temperatures from 50 to 150°C, PH2S tends to be higher in Devonian reservoirs. Devonian reservoirs tend to have lower pC02 than Mississippian reservoirs (Figure 2). The trend of increasing CO2 and H2S with temperature is consistent with the origin of both gases being related to devolatilizaton of minerals, such as calcite and anhydrite, or devolatilizaton of organic matter, which may contain up to llwt. % sulfur (70, 77). The concentrations of both CO2 and H2S could be affected by reaction of carbonate, sulfate and sulfide minerals. High CO2 contents occur in quartz-rich sandstone reservoirs in southeastern Alberta in the Mesozoic part of the section that overlies Paleozoic carbonates. The hydrodynamic regime and regional variations in water and gas chemical and isotopic compositions suggest that the CO2 in this area is the result of hydrocarbon oxidation that accompanies bacterial sulfate reduction (9, 72). Distribution of H2S and C O 2 . General trends in the distribution of H2S and CO2 were considered by preparing maps that divide the Paleozoic part of the stratigraphie section into Devonian and Mississippian units, similar to the broad divisions used by Hitchon (75-75) in his classic study of natural gas in western Canada. The H2S concentrations in Devonian reservoirs are highest near the disturbed belt along the foothills of the Rocky Mountains, ranging from 0.2 mole fraction (X) and 0.6 X with rarely observed occurrences up to 0.85 X, such as in the Bearberry pool. These extreme values occur in the deepest part of the section at present depths below surface that range from 2000-4000 m, reservoir temperatures in the range of 80-120°C, and reservoir pressures between 30 and 60 MPa. Due to uplift and erosion following the Laramide orogeny, maximum temperatures were higher because burial depths were probably more than 1900 m greater in the past (76). The distribution of CO2 parallels that of H2S, although concentrations are typically lower, with the highest values ranging from 0.05 to 0.10 X. The patterns of distribution of H2S and CO2 for reservoirs of Mississippian age are similar to those observed in Devonian reservoirs, with high H2S and CO2 near the more deeply buried part of the section in the foothills. H2S concentrations are lower in Mississippian reservoirs than in Devonian reservoirs, although locally variations may be large. General Trends in Water Chemistry. The processes that form H2S and CO2 almost certainly affect the formation waters and it is important to understand the distribution of variations in formation water chemistry. There are published studies of formation water chemical and isotopic compositions in the WCSB (5-9) in different areas in In Geochemical Transformations of Sedimentary Sulfur; Vairavamurthy, M., et al.; ACS Symposium Series; American Chemical Society: Washington, DC, 1995.


428

GEOCHEMICAL TRANSFORMATIONS OF SEDIMENTARY SULFUR

X

CL ο 50

75

100

125

150

175

Temperature (°C)

Figure 1. Correlation of partial pressure of H2S and temperature in reservoirs of Mississippian and Devonian age. PH2S tends to be higher in Devonian reservoirs as compared to Mississippian reservoirs.

2.0 (O

1.5

η 1-0 s ϋ

0 5

0.0

Ο) -0.5

ο

-1.5

ο Mississippian • Devonian • North Sea - Gulf Coast L

25

50

75

100

125

150

175

Temperature (°C)

Figure 2. Correlation of partial pressure of CO2 and temperature in reservoirs of Mississippian and Devonian age. At temperatures between 40 and 80°C in the WCSB, pC02 shows an increase of at least two orders of magnitude compared to the regular trend displayed by reservoirs in the North Sea and Gulf Coast (22).

In Geochemical Transformations of Sedimentary Sulfur; Vairavamurthy, M., et al.; ACS Symposium Series; American Chemical Society: Washington, DC, 1995.


24.

HUTCHEON ET AL.


429

units ranging in age from Cambrian to Tertiary. Waters in the WCSB tend to become more saline with age and depth, with waters in rocks that are Mesozoic and younger being less saline than waters in Paleozoic rocks and with a relatively continuous increase in salinity with increasing age. This difference in chemistry has persisted since uplift of the basin prior to the Eocene, suggesting that fluid flow that results from differences in topography, while recognized at depths up to 1 or 2 km (9, 12, 17), has not completely flushed the basin and erased compositional gradients. Paleozoic rocks in the WCSB are dominantly carbonates associated with evaporites, and the Mesozoic rocks are dominated by clastic rocks. The chemical composition of formation waters in Mesozoic and Paleozoic rocks is somewhat different with waters in Tertiary and Cretaceous rocks having relatively low salinity Na-Cl/HC03 waters in contrast to waters in Devonian and Mississippian age rocks that are relatively higher salinity Na/Ca-Cl waters. Published data (6) show that waters in Paleozoic rocks have sulfate concentrations that range from 0 to about 1300 mg/L. Origin of Sulfur, H S and C 0 2

2

Volume Considerations. The source of sulfur in reservoirs subjected to thermochemical sulfate reduction is interpreted to be anhydrite (4, 18), which is abundant in Paleozoic rocks in the WCSB. To determine if anhydrite is a feasible source of sulfur for thermochemical sulfate reduction, the solubility of anhydrite was calculated at temperatures from 25 to 125°C from published data (79). Figure 3 shows the product of the activities of the aqueous ions Ca and SO4 determined from water analyses from (6), compared to the solubility of anhydrite. Formation waters at temperatures greater than 80°C approach saturation with anhydrite, consistent with an anhydrite sulfate source. Accepting anhydrite as the sulfur source, an estimate of the volume of anhydrite required to form the observed H2S concentrations will show if H2S can be accounted for by a local reservoir scale source (closed system) or if transport (open system) is required. Calculations of H2S molar volumes were completed for temperatures from 60-120°C and pressures from 20 to 60 MPa (200-600 bars). This encompasses present day conditions in H2S bearing reservoirs in Alberta, although burial depths were at least 1900m deeper (77) and temperatures and pressures were higher in the past. The volume of H2S was calculated using PV = ZRT and the critical temperature (373.5 °K), critical pressure (8.937 MPa, or 89.37 bars) and compressibility (20). The effect of mixing H2S with methane and other gases on the volume of H2S has been ignored, but the non-ideal gas volume terms, estimated from critical properties are included. For the range of temperatures and pressures, volumes of H2S range from approximately 40 to 60 cm /mol (Figure 4). The molar volume of anhydrite is 45.94 cm /mol. One mole of anhydrite is required to form one mole of H2S and the similarity of molar volumes suggests a given volume of anhydrite will produce approximately an equivalent volume of H2S. Assuming a starting porosity of 5% before thermochemical sulfate reduction begins, the apparent volume fraction of H2S in the gas can be calculated from the molar volumes of CO2, H2S, CH4, C2H6 and C3H8 at the temperature and pressure of interest and the mole fractions of each gas. For 100 cm rock the porosity contains 0.05 χ 0.2295 cm = 1.14759 equivalent cm of H2S, which, divided by the volume per mole (89.3 cm /mol), gives 0.01285 moles of H2S. One mole of anhydrite (45.94 cm3/mol) is required to produce one mole of H2S, thus the volume of anhydrite required to produce 0.35 X H2S is approximately 0.59 cm , or 0.59 volume percent anhydrite in the rock. Because the volumes of all the gases change as a function of temperature, pressure and the gas composition, the relative volumes of anhydrite and H2S will vary slightly, but it is safe to assume that between 0.5 and 1.0 % anhydrite in a rock with 5% porosity is sufficient to produce up to 0.35 X H2S. 3

3

3

3

3

3

3


430



-3.5

Temperature (°C) Figure 3. Formation waters from Paleozoic rocks approach saturation with anhydrite at temperatures in the range of 80°C. The equilibrium constant for anhydrite is shown by the curved line, the open circles are ion activity products for water compositions from (6).

10

30 50 Pressure ( M P a )

70

Figure 4. The volume of H2S as a function of temperature and pressure. Volume of anhydrite shown for comparison.


24.

HUTCHEON ET AL.


431


This simple calculation suggests that H2S can be derived from local sources of anhydrite and, although long distances of migration of H2S or sulfate are not precluded, they are not necessary. In the West Hackberry Dome of the Louisiana Gulf Coast transport offluidsover an area of about 1.5 by 1.5 km has been suggested (27), however this study examined sandstones with no internal source of anhydrite. Anhydrite is present in WCSB Paleozoic carbonate rocks as nodules and pore fillings and dissolution of anhydrite is observed in some places (4, 18). The importance of local derivation, as opposed to long distance migration, depends on the abundance of anhydrite before sulfate reduction; a question that can only be resolved by a systematic, detailed, pétrographie study of H2S bearing intervals and careful comparison to non-H2S bearing intervals, which is beyond the scope of this paper. H2S and C O 2 . There is a linear trend of log pCQ2 with temperature in the U.S. Gulf Coast and North Sea (22), but pCU2 concentrations observed in WCSB reservoirs are higher (Figure 2). It has been suggested (23) that pCU2 is controlled by claycarbonate buffering during diagenesis of lithoclastic rocks and the high values imply there is no pH buffering assemblage in Mississippian and Devonian carbonates of the WCSB. High CO2 values (9) in the WCSB occur in quartz sandstones with no buffer assemblage. As can be seen from reaction (1), sulfate reduction can be expected to result in increased CO2. The ratio of CO2 to H2S during sulfate reduction is dependent on the composition of the oxidized hydrocarbon and, as reaction (2) shows, the ratio increases as the C:H ratio of the hydrocarbon increases. CH

4

^C H 2

+ 2H+ + SO4" 6

+ 2H+ + Sof

H S + C0 2

^

2

HS + |C0 2

+ 2H 0

(1)

2

2

+ yH 0 2

(2)

C-H bonds for alkanes become weaker as the C:H ratio increases, and it is expected that longer chain alkanes would be more easily oxidized than short chain alkanes. Detailed examination of the chemical and isotopic composition of natural gas in the WCSB associated with high H2S concentrations (4) supports the oxidation of higher carbon number alkanes in preference to methane. It has been noted (24) that TSR results in increased H2S and CO2 in the gas and depletion in the amount of saturated hydrocarbons in condensate liquids. If hydrocarbons are oxidized during TSR, it would be expected that during sulfate reduction, CO2 concentration would tend to increase as the amount of H2S increases. Present day gas compositions may not always show this relationship, nor do they necessarily reflect the composition of the oxidized hydrocarbon, for several reasons. The oxidized hydrocarbon is unlikely to be a single compound with a fixed C:H ratio. Further, both CO2 and H2S will participate in water-rock interactions, such as precipitation and dissolution of sulfur, carbonate, sulfide, and sulfate minerals, and this will affect the concentrations. Finally, both CO2 and H2S can form, or be removed, by other processes unrelated to reduction of sulfate and oxidation of hydrocarbons. Sulfur. The volumetrically most significant sulfur compounds observed in hydrocarbon reservoirs in which TSR is interpreted to have occurred are H2S gas, anhydrite (CaSCU), solid or liquid sulfur, and dissolved sulfate. Sulfur is observed to be associated with H2S (4, 18, 25). Sulfur has an intermediate oxidation state between H2S and sulfate, but whether native sulfur is formed by oxidation of H2S after TSR, or during the TSR reaction is not known. Thermodynamic data for liquid sulfur are not available, so the stability of sulfur relative to the other minerals noted above was calculated in reaction (3) using solid sulfur. Because most gases associated with H2S-bearing reservoirs contain CO2, and anhydrite and calcite are commonly associated with TSR, it is possible to construct equation (4), which shows the oxidation of H2S to solid sulfur in the presence of calcite and anhydrite.


432


H 0

+ |S

CaC0

3

2

2 ( S

)

HS 2

+ 3H 0 + 2

2S

2(S)

+ ^0 ( ) 2

(3)

g

CaS0

4

+

C0

2

+ 3H S

(4)

2

Assuming unit activity of water, and that anhydrite and calcite are pure minerals, the stability of pure solid sulfur can be calculated from the reservoir gas composition and the equilibrium constant for reaction (4) which can be expressed as (fC0 )*(fH S)3. K(4) was calculated using SUPCRT92 (79) and thermodynamic data for sulfur (26). The gas compositions for H S-bearing reservoirs were obtained from the AEUB and the fugacity coefficients of C 0 and H S were assumed to be unity. Figure 5 shows the results for Mississippian and Devonian rocks. Values of (fC0 )*(fH S)3 are mostly greater than the value for equilibrium between calcite+sulfur and anhydrite (K(4)) and lie within the calcite-sulfur stability field. 2

2

2


2

2

2

2

Isotopic Data H and C isotopic compositions of hydrocarbon gases from natural gases associated with H S in Devonian and Mississippian age reservoirs shows a systematic change in 8 C values of light hydrocarbon gas as a function of an extent of reaction parameter (4), with C and higher compounds oxidized in preference to C i . Calcite has 8 C values as low as -30%c, due to incorporation of carbon from hydrocarbon oxidation. The separation of isotopic values ( A Q of light hydrocarbon gases may be an indicator of the degree of organic maturity of the source matter from which gas is generated (27). At low levels of organic maturity the maximum separation between C i and C is given as about \6%c A*3c, however hydrocarbon gases associated with high H S (4) show separations ranging up to 18%o 5 C , greater than predicted, especially since the gases were probably generated at high levels of organic maturity. The maximum A C would be expected to be at low levels of maturation, and the difference would be expected to decrease as maturation increased, thus increasing pH S should be accompanied by decreasing A C . Figures 6 and 7 show A C for various gas pairs plotted versus PH2S for Mississippian and Devonian reservoirs. There are no trends in the data and A C for most gas samples is far greater than would be predicted, suggesting that some other process, possibly oxidation, has influenced the carbon isotopic composition of the gas components. We are not aware of any method by which the relative effect on A C from maturation of the source material can be quantitatively separated from the effect of oxidation. Since C-C bonds would be expected to be weaker for gas components of higher carbon number, oxidation would preferentially attack the higher carbon number gases and would break C bonds preferentially, leading to a relatively higher rate of increase in C for the unreacted higher carbon number gases. Maturation and oxidation change A C in the same way, and it is not obvious how the relative influence of such effects on A C can be discerned. Figure 8 shows the variation of 5 0 with sulfate concentration for WCSB waters in rocks of various ages. Waters with low sulfate and negative δ 0 are found in Cretaceous rocks, consistent with the suggestion that an influx of meteoric water is responsible for promoting bacterial sulfate reduction (9, 72). Waters that have low sulfate (and high pH2S, not shown), but have positive δ 0 are found in Devonian or Mississippian age rocks and are interpreted to have experienced waterrock interaction during thermochemical sulfate reduction. 2

13

13

2

1 3

2

13

2

1 3

1 3

1 3

2

i 3

1 3

1 2

1 3

1 3

1 3

18

1 8

1 8

Reaction Path Modeling The volume comparison (Figure 4) suggests that anhydrite and H S can "trade places" and that only small volumes of anhydrite are required to produce relatively high H S 2

2




HUTCHEON ET AL.

0

25

50 75 100 125 Temperature (°C)

150 175

Figure 5. The stability of calcite+sulfur versus anhydrite. Gases in Mississippian and Devonian reservoir tend to be in chemical equilibrium with calcite+sulfur, rather than anhydrite.

20 ο» οοο c 15 CPO ο Ο Ο Ο 0 °° CO 10 to

0 0

Ο

ο C2-C1

5

• C4-C3

+

c Ο 0

CO

to -5 •10

10

pH2S 13

15 20 (bars)

25

13

Figure 6. The difference in 5 C (A C) between light hydrocarbon gases in reservoirs in Mississippian rocks versus the partial pressure of H2S. There is no obvious dependence between A C and PH2S. 1 3


433


434


ί

J* «

;

. " \ v

CO

• C2-C1 1

-5

• C4-C3

-10

25

50

75 100 125 150 175

PH2S (bars) 13

13

Figure 7. The difference in 5 C (A C) between light hydrocarbon gases in reservoirs in Devonian rocks versus the partial pressure of H2S. At higher values of PH2S, A C for C2-C1 decreases as PH2S increases. 1 3

1500 1250 ^ 1000 & 750

• Cretaceous • Jurassic Mississippian α Devonian

-

Ο 500 ω 250 -25

π

-20

-15 -10 -5 0 0180°/oo(SMOW)

5

a 10

1 8

Figure 8. δ 0 (SMOW) versus sulfate for WCSB waters. Low sulfate waters enriched in 0 compared to SMOW and interpreted to reflect waterrock interactions are observed in Devonian rocks. Low sulfate waters depleted in 0 compared to SMOW are observed in Cretaceous rocks. 1 8

1 8



24.

HUTCHEON ET AL.

435


in gases at reservoir conditions. Anhydrite, in addition to providing a volumetrically appealing source for H2S, has the potential for generation of porosity by dissolution. However, CO2 is released in the proposed TSR reactions, Ca must be released if anhydrite dissolves as a sulfur source (reaction 4), and the reduction of sulfate to H2S is likely to be a strong pH buffer, implying that TSR will be accompanied by calcite and dolomite precipitation. Saddle dolomite has been suggested to form during TSR (28). Isotopic data show that petrographically late calcite contains CO2 from hydrocarbon oxidation (4). A reaction path model including anhydrite and dolomite was used (29) to examine the reduction of sulfate in a treatment of Mississippi Valley type (MVT) ore deposits, but did not include calcite as a potential product. It was concluded that the precipitation of sparry dolomite via a reaction similar to (5) is a possible result of sulfate reduction in the presence of anhydrite, organic matter and dolomite. Similar model calculations focused on gas compositions have been performed (Nicholson and Goldhaber, personal communication). 2

2 C H + CaS0 + Mg + CaMg(C0 )2 + C a 4

4

3

2+

+2H 0 +2H S 2

(5)

2

Reaction (2) is a strong pH buffer and calcite should be precipitated as anhydrite is dissolved during the reduction of sulfate. Some of the porosity gained by anhydrite dissolution potentially is thus lost to calcite precipitation. The relative changes in volume of calcite, anhydrite and porosity during the progress of reaction (6) was calculated at 100°C (Figure 9) using EQ3/6 (30, 31): C H 4 + CaS0

4

CaC0 + H 0 + H S 3

2

(6)

2

As a rough number, for every four volumes of anhydrite converted to H2S, three volumes of calcite are precipitated, leaving only one volume as porosity. The ratio of volume gained by anhydrite dissolution to volume lost by calcite precipitation requires that a large volume of anhydrite, approximately five times the amount required to generate the observed H2S, be dissolved in order to produce more than 1% porosity increase by TSR. If H2S gas rises into a zone in which it can be re-oxidized, the H stored in H2S during sulfate reduction is released (29) and can be an effective agent of dissolution. Examining reaction (2) we see that the introduction of H2S which is then allowed to re-oxidize to sulfate, away from the site at which it was generated, releases H . The amount of dolomite dissolution that could result from migration of H2S can be considered by a calculation in which H2S is allowed to react with dolomite. The results of such a calculation are shown in Figure 10 which simulates the release, but not the oxidation, of H2S. Porosity gain can be 1-2% by volume since no calcite forms. The amount of H2S involved in the chemical model is more than four times the amount of C H allowed to react in the simulation used to construct Figure 9. In other words, the demand for anhydrite and organic matter to produce significant dissolution is very high and some mechanism of focusing the H2S is required. It is possible that H2S produced by TSR may be transported into reservoirs of the WCSB by fluid flow, moving H2S away from the site of generation and allowing porosity to be produced without the loss of porosity due to calcite precipitation. However all the evidence suggests that hydrocarbons in the reservoir are oxidized during TSR and that these reservoirs approach closed system behavior. It is possible that a complex cycling of fluids on a reservoir scale is involved during TSR and that some zones of a reservoir develop higher porosity than others. +

+

4

Summary and Conclusions The concentrations of H2S and CO2 in natural gas accumulations in Paleozoic carbonate rocks in the WCSB increase with increasing depth and temperature. H2S



436


4

0.00

0.02 0.04 0.06 CH4 Used (moles)

0.08

Figure 9. The changes in volume of anhydrite, calcite and porosity during TSR, calculated using EQ3/6 (30, 31).

8

4 I

0

.

,

.

•

.

,

1 2 3 Moles H2S added

.

1

4

Figure 10. The dissolution of dolomite by H2S modeled using EQ3/6.



24. HUTCHEON ET AL.


437

concentrations in reservoirs in Devonian age rocks tend to be higher than in reservoirs in Mississippian age rocks and in both groups, H2S concentrations are highest in the deeper westernmost parts of the basin. CO2 concentrations parallel H2S concentrations, except in the more shallow Mesozoic rocks in the eastern and southern parts of the WCSB where CO2 results from bacterial processes. Waters in Paleozoic rocks are more saline than waters in Mesozoic rocks and have higher sulfate concentrations. The waters in Paleozoic age rocks tend to be in chemical equilibrium with anhydrite above 80°C and anhydrite is the probable sulfur source for H2S in Paleozoic reservoirs. The volumes of anhydrite and H2S are similar in the temperature range from 80-120°C and pressures from 30-60 MPa, suggesting that the production of H2S in the WCSB could be a relatively closed system process, although an open system process is not precluded. To produce concentrations up to 35% H2S in reservoir rocks with initially 5% porosity would only require an initial volume of anhydrite between 0.5 and 1%. Reservoir gas compositions suggest that, within the limits of the thermodynamic data, the gases are in equilibrium with calcite and sulfur and that anhydrite should not be stable in the gas zone. The C isotopic composition of hydrocarbon gases associated with H2S is consistent with the oxidation of these gases during the thermochemical reduction of sulfate (4). The compositions of waters in Paleozoic rocks show that high H2S and low sulfate concentrations are correlated with relatively 0-enriched waters, suggesting extensive water-rock interaction during thermochemical sulfate reduction. The reduction of sulfate from anhydrite during the oxidation of hydrocarbons should result in precipitation of calcite as anhydrite dissolves. Closed system modeling of such a reaction shows that porosity increases created by the dissolution of anhydrite are compensated for by volume decreases caused by calcite precipitation. If more open system conditions exist, and H2S can migrate into rocks away from the site at which TSR takes place, more porosity can be created, however the isotopic data for calcite cements and hydrocarbon gases do not strongly support an open system model. At the reservoir scale, it is possible that some cycling occurs and that zones of high porosity are developed as TSR progresses. 18

Acknowledgments The maps of the distribution of H2S and CO2 in this paper were produced by John Cody and we thank him for his assistance. The isotopic data for hydrocarbon gases were obtained with the support of Shell Canada Resources, particularly C. A. Viau, and their assistance and permission to use the data are much appreciated. Hutcheon and Krouse received financial assistance from the Natural Sciences and Engineering Research Council (NSERC) of Canada and Hutcheon received support from the Petroleum Research Fund. Acknowledgment is made to the donors of the Petroleum Research Fund, administered by the American Chemical Society, for partial support of this research. Some of the work reported in this paper was completed while the first author was on an NSERC Senior Industrial Fellowship sponsored by Shell Canada, The University of Calgary, and NSERC. Hans Machel and an anonymous reviewer provided comments that substantially improved this manuscript. Literature Cited 1. 2. 3.

Orr, W.L. Am. Assoc. Petrol. Geol. Bull. 1974, 58, 2295-2318. Alberta Energy and Utilities Board (AEUB) Alberta Resources of Gas; , (5 volumes), Calgary, AB, Energy Resources Conservation Board Report ST8735. 1987. Krouse, H. R. Stable Isotope Research in Support of More Effective Utilization of Gas Fields in Alberta, Alberta - Canada Energy Resource Research Fund, Agreement U-30, 1983, December.


438 4. 5. 6. 7. 8.


9.

10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20. 21. 22. 23. 24. 25. 26. 27. 28. 29. 30.

31.


Krouse, H.R.; Viau, C.A.; Eliuk, L.S.; Ueda, Α.; Halas, S. Nature 1988, 333, 415-419. Hitchon, B.; Friedman, I. Geochim. Cosmochim. Acta 1969, 33, 1321-1349. Hitchon, B.; Billings, G.K.; Klovan, J.E. Geochim. Cosmochim. Acta, 1971, 35, 567-598. Connolly, C.A.; Walter, L.M.; Baadsgaard, H.; Longstaffe, F.J. App. Geochem. 1990, 5, 375-396. Connolly, C.A.; Walter, L.M.; Baadsgaard, H.; Longstaffe, F.J. App. Geochem. 1990, 5, 397-414. Cody, J. Geochemistry of formationfluidsin the Mannville Group (Lwr. Cret.), Southern Alberta: Sources, controls and water-rock interaction of carbon dioxide richfluids.Unpublished MSc thesis, Department of Geology and Geophysics, University of Calgary, Calgary, AB, 1993, 129 p. Orr, W. L. Org. Geochem. 1986, 10, 499-516. Orr, W. L. and Damste, J. S., In Geochemistry of sulfur in petroleum systems; Orr, W. L. and White, C. M. Eds.; 1990, ACS Symposium Series 429, p. 2-19. Cody, J.C.; Hutcheon, I. Bull. Can. Petrol. Geol. 1994, 42, 15 pp. Hitchon, B. Jour. Can. Petrol. Tech. 1963, 2, 60-76. Hitchon, B. Jour. Can. Petrol. Tech. 1963, 2, 100-116. Hitchon, B. Jour. Can. Petrol. Tech. 1963, 2, 165-174. Nurkowski, J.R. Am. Assoc. Petrol. Geol. Bull. 1984, 68, 285-295. Toth, J. and Corbet, T., In Fluid Flow in Sedimentary Basins and Aquifers; Goff, J.C. and Williams B.J.P. Ed.; Geological Society Special Publication, 1987, Vol. 34, p. 45-56. Machel, H.G., In Diagenesis of Sedimentary Sequences; Marshall, J.D. Ed.; Geological Society Special Publication, 1987, Vol. 36; p. 15-38. Johnson, J.W.; Oelkers, E.H.; Helgeson, H.C. Comp. Geosci. 1992. 18, 899947. Weber, H.C. and Meissner, H.P., Thermodynamics for Chemical Engineers; John Wiley and Sons, New York, NY, 1959, 507 p. McManus, K.M.; Hanor, J.S. Geology 1993, 21, 727-730. Smith, J.T.; Ehrenberg, S.N. Mar. Petrol. Geol. 1989, 6, 129-135. Hutcheon, I. Shevalier, M.; Abercrombie, H.J. Geochim. Cosmochim. Acta 1993, 57, 1017-1027. Claypool, G.E.; Mancini, E.A. Am. Assoc. Petrol. Geol. Bull. 1989, 73, 904924. Heydari, E.; Moore, C.H. Geology 1989, 17, 1080-1084. Robie, R.A.; Hemmingway, B.S.; Fischer, J.R. Thermodynamic properties of minerals and related substances at 298.15 Κ and 1 bar pressure and at high temperature. United States Geological Survey Bulletin 1452, 1978, 456 pp. James, A.T. Am. Assoc. Petrol. Geol. Bull. 1983, 67, 1176-1191. Machel, H.G. Geology 1987, 15, 936-940. Anderson, G.M.; Garven, G. Econ. Geol. 1987, 82, 482-488. Wolery, T.J. EQ3NR, A computer program for geochemical aqueous speciation-solubility calculations: Theoretical manual, user's guide, and related documentation (version 7.0). Lawrence Livermore National Laboratory, UCRL-MA-110662 PTIII. 1992, 246 p. Wolery, T.J.; Davelar, S.A. EQ6, A computer program for reaction path modeling of aqueous systems: Theoretical manual, User's guide, and related documentation (Version 7.0). UCRL-MA-110662 PTIV. 1992, 338 p.

RECEIVED June 20, 1995


Controls on the Origin and Distribution of ... - ACS Publications

Recommend Documents