Comparison of natural gases accumulated in Oligocene strata with hydrous pyrolysis gases from Menilite Shales of the Polish Outer Carpathians

Organic Geochemistry 40 (2009) 769–783

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Comparison of natural gases accumulated in Oligocene strata with hydrous pyrolysis gases from Menilite Shales of the Polish Outer Carpathians M.J. Kotarba a,*, J.B. Curtis b, M.D. Lewan c a

Faculty of Geology, AGH University of Science and Technology, Al. Mickiewicza 30, 30-059 Krakow, Poland Department of Geology and Geological Engineering, Colorado School of Mines, Golden, CO 80401, USA c US Geological Survey, P.O. Box 25046, MS 977, Federal Center, Denver, CO 80225, USA b

a r t i c l e

i n f o

Article history: Received 16 January 2009 Received in revised form 10 April 2009 Accepted 18 April 2009 Available online 3 May 2009

a b s t r a c t This study examined the molecular and isotopic compositions of gases generated from different kerogen types (i.e., Types I/II, II, IIS and III) in Menilite Shales by sequential hydrous pyrolysis experiments. The experiments were designed to simulate gas generation from source rocks at pre-oil-cracking thermal maturities. Initially, rock samples were heated in the presence of liquid water at 330 °C for 72 h to simulate early gas generation dominated by the overall reaction of kerogen decomposition to bitumen. Generated gas and oil were quantitatively collected at the completion of the experiments and the reactor with its rock and water was resealed and heated at 355 °C for 72 h. This condition simulates late petroleum generation in which the dominant overall reaction is bitumen decomposition to oil. This final heating equates to a cumulative thermal maturity of 1.6% Rr, which represents pre-oil-cracking conditions. In addition to the generated gases from these two experiments being characterized individually, they are also summed to characterize a cumulative gas product. These results are compared with natural gases produced from sandstone reservoirs within or directly overlying the Menilite Shales. The experimentally generated gases show no molecular compositions that are distinct for the different kerogen types, but on a total organic carbon (TOC) basis, oil prone kerogens (i.e., Types I/II, II and IIS) generate more hydrocarbon gas than gas prone Type III kerogen. Although the proportionality of methane to ethane in the experimental gases is lower than that observed in the natural gases, the proportionality of ethane to propane and i-butane to n-butane are similar to those observed for the natural gases. d13C values of the experimentally generated methane, ethane and propane show distinctions among the kerogen types. This distinction is related to the d13C of the original kerogen, with 13C enriched kerogen generating more 13C enriched hydrocarbon gases than kerogen less enriched in 13C. The typically assumed linear trend for d13C of methane, ethane and propane versus their reciprocal carbon number for a single sourced natural gas is not observed in the experimental gases. Instead, the so-called ‘‘dogleg” trend, exemplified by relatively 13C depleted methane and enriched propane as compared to ethane, is observed for all the kerogen types and at both experimental conditions. Three of the natural gases from the same thrust unit had similar ‘‘dogleg” trends indicative of Menilite source rocks with Type III kerogen. These natural gases also contained varying amounts of a microbial gas component that was approximated using the Dd13C for methane and propane determined from the experiments. These approximations gave microbial methane components that ranged from 13–84%. The high input of microbial gas was reflected in the higher gas:oil ratios for Outer Carpathian production (115–1568 Nm3/t) compared with those determined from the experiments (65–302 Nm3/t). Two natural gas samples in the far western part of the study area had more linear trends that suggest a different organic facies of the Menilite Shales or a completely different source. This situation emphasizes the importance of conducting hydrous pyrolysis on samples representing the complete stratigraphic and lateral extent of potential source rocks in determining specific genetic gas correlations. Ó 2009 Elsevier Ltd. All rights reserved.

1. Introduction The Outer (flysch) Carpathians of Central Europe comprise a structurally complex area which consists of folded and thrusted * Corresponding author. Tel./fax: +48 12 617 2431. E-mail address: [email protected] (M.J. Kotarba). 0146-6380/$ - see front matter Ó 2009 Elsevier Ltd. All rights reserved. doi:10.1016/j.orggeochem.2009.04.007

strata of Cretaceous to late Miocene age. A series of imbricate nappe-thrust sheets extends north to northeast over strata of late Oligocene to Sarmatian age. Fig. 1 shows the location of the major nappe-thrust sheets that are referred to as ‘‘units” and are named from south to north as the Magura, Dukla and its Grybów Subunit, _ Sub-Silesian, Silesian, Skole, Stebnik and Zgłobice (Ksia˛zkiewicz, 1977; Połtowicz, 1985; Oszczypko, 1997). The northern most

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Fig. 1. Generalized geological map of the eastern part of the Polish Outer Carpathians showing location of sampled Menilite Shales outcrops and sampled gas wells. _ Geological boundaries after Ksia˛zkiewicz (1977), Połtowicz (1985) and Oszczypko (1997).

thrust boundaries denote the beginning of the Carpathian Foredeep. Variations in thickness and sedimentary facies of the flysch strata within and among the major nappe-thrust sheets indicate that sub-basins existed during deposition of the Menilite Shales prior to late Miocene thrusting (Kus´mierek, 1990). The sub-basins may have been separated by shallow or emergent paleo highs developed during late Cretaceous to Paleocene Laramide activity. A total of 67 oil deposits and 16 gas deposits have been discovered in the Polish Outer Carpathians (Karnkowski, 1999; Kotarba and Koltun, 2006). Most reserves (71.4% of oil and 95.6% of gas) are in sandstone reservoirs in the Silesian Unit. The Skole Unit contains 14.8% of the oil and 1.5% of the total gas and the Sub-Silesian Unit contains 9.88% of the oil and 2.35% of the total gas (Table 1). Source rocks in the Oligocene Menilite Shales are mainly responsible for these petroleum accumulations in the Outer (flysch) Carpathians of Poland (e.g., ten Haven et al., 1993; Kotarba and Koltun, 2006). Within the sub-basins of the Skole, Silesian and Dukla units of the Outer Carpathians, four organic facies of Menilite source rocks containing different types and concentrations of organic matter have been recognized through the study of outcrop samples (Curtis et al., 2004). This variation most likely reflects a change in the organic matter source input of the Menilite Shales

(Curtis et al., 2004). Samples of the high sulfur organic facies are found in outcrops of the western part of the Skole Unit (Fig. 1), where the exposed lower Menilite Shales source rocks have less clastic input and a greater dominance of diatomaceous shale, diatomite and chert (Kotlarczyk and Les´niak, 1990; Kus´mierek, 1990). Kerogen isolated from samples in this part of the section is Type IIS (Curtis et al., 2004). Samples of the low sulfur organic facies (Type II kerogen) are found in the Silesian Unit (Fig. 1), where the exposed Menilite Shales source rocks have a greater clastic input characterized by argillaceous shale with interbedded sandstone. Type III kerogen occurs in the eastern portion of the Skole Unit, while a Type I/II kerogen was identified from a single outcrop in the Dukla Unit (Curtis et al., 2004). Natural gas accumulations occur in Oligocene Kliwa and Magdalena Sandstones within the Menilite Shales and in Krosno Beds overlying the Menilite Shales in the eastern section of the Polish Outer Carpathians between Nowy Sa˛cz and Przemys´l (Fig. 1). These reservoir units contain associated and non-associated natural gas that is most probably genetically connected with the Menilite Shales (Kotarba, 1987, 1992, 1993; Kotarba and Koltun, 2006; Kotarba and Nagao, 2008). Previous analysis of oils generated by hydrous pyrolysis of the Menilite Shales correlated with natural

Table 1 Occurrence of associated and non-associated gas and gas:oil ratios in tectonic units of the flysch Carpathians. Tectonic unit

Number of oil depositsa

Oilb

Gasc

GORd 3

(t)

(bbl)

(Nm )

(scf)

(Nm3/t)

(scf/bbl)

% of total oil

% of total gas

Skole Silesian Sub-Silesian Magurae Dukla

10 46 (14) 2 (1) 7 (1) 2

1,850,270 8,887,590 1,154,350 321,670 243,000

13,562,492 65,146,035 8,461,385 2,357,841 1,781,190

219,730,000 13,934,488,379 343,000,000 56,925,127 37,870,000

7,761,522,790 490,939,894,570 12,084,576,000 1,300,946,090 1,337,682,010

118.8 1567.9 297.1 114.8 155.8

572.3 7536.0 1428.2 551.8 751

14.8 71.4 9.3 2.6 1.9

1.5 95.6 2.4 0.2 0.3

Total

67 (16)

12,456,880

91,308,930

14,572,013,506

513,424,621,460

1169.8

5622.9

100.0

100.0

One metric ton (tonne) oil is equal to 7.33 barrels – average value for Carpathian region from www.spe.org; Nm3, normal cubic meter at temperature of 20 °C (293.15 K) and pressure of 101.3 kPa; scf, standard cubic feet at temperature 60 °F (288.65 K) and pressure 14.73 psi (101.3 kPa). a Number of gas deposits in parentheses. b Oil = sum of oil production and reserves up to 1999 by Karnkowski (1999). c Gas = sum of associated and non-associated (free) gas production and reserves up to 1999 by Karnkowski (1999). d GOR = Gas:oil ratio. e Oil and gas deposits discovered in Grybów Subunit included in Magura Unit by Karnkowski (1999).

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crude oils reservoired in the flysch strata (Curtis et al., 2004), but no work on the generated gases has been reported and compared to natural gases. Therefore, the objectives of this study are to determine whether distinct compositional or d13C signatures of gases generated by hydrous pyrolysis of representative Oligocene Menilite source rocks containing Types I/II, II, IIS and III kerogens exist, and whether these laboratory results can be used to evaluate kerogen types and thermal maturities responsible for the natural gas accumulations in the intercalated Kliwa and Magdalena Sandstones and the overlying Krosno Beds.

by Kotarba and Lewan (2002). This subset was chosen because the experiments have complete composition and d13C analyses on four rock samples containing thermally immature to marginally mature Types I/II, II, IIS and III kerogens. Table 2 gives the initial organic geochemical attributes of the samples and Figs. 1 and 2 show their location within the various thrust sheets of the Polish Outer Carpathians. Sample TY-31 is from the Dukla Unit and contains Type I/II kerogen. Sample RG-28 is from the Silesian Unit and contains Type II kerogen. Sample NI-2 is from the western portion of the Skole Unit and contains Type IIS kerogen. Sample KN-62 is from the eastern portion of the Skole Unit and contains Type III kerogen. At every outcrop, the outer fissile and platy shale zones (up to 35 cm) were removed and a fresh slabby to blocky 5–10 kg sample with no saprolite rinds was collected in accordance with sampling criteria established by Lewan (1980). Specific details were presented by Curtis et al. (2004).

2. Sample description 2.1. Rock outcrop samples This study is based on a subset of eight experiments on four rock samples from 23 experiments on 12 rock samples reported

Table 2 Stable carbon isotope composition, atomic elemental ratios of kerogen and Rock-Eval data for original unheated and hydrous pyrolysis (355 °C, 72 h) samples from Curtis et al. (2004). Sample code

Temperature (°C)

d13C kerogen (‰)

Kerogen atomic ratios

Rock-Eval

H/C

O/C

Sorg/C

TOC (wt.%)

Tmax (°C)

PI

HI

OI

Type I/II kerogen TY-31 TY-31

Un. 355

28.8 27.9

1.35 0.63

0.04 0.05

0.008 0.026

5.7 3.7

434 448

0.02 0.3

681 191

13 4

Type IIS kerogen NI-2 NI-2

Un. 355

27.0 26.8

1.25 0.59

0.15 0.14

0.048 0.001

9.5 6.2

410 442

0.06 0.34

447 90

41 11

Type II kerogen RG-28 RG-28

Un. 355

26.5 26.7

1.19 0.66

0.12 0.06

0.016 0.016

6.1 3.7

420 447

0.06 0.31

444 85

35 2

Type III kerogen KN-62 KN-62

Un. 355

25.2 25.1

0.92 0.59

0.19 0.22

0.032 0.001

7.2 4.8

419 449

0.02 0.39

267 79

23 9

un., original unheated; TOC, total organic carbon; PI, production index (S1/[S1+S2]); HI, hydrogen index (mg S2/g TOC); OI, oxygen index (mg CO2/g TOC); n.a., not analyzed.

Fig. 2. Schematic stratigraphic columns of the Oligocene in the major Outer Carpathian units of SE Poland after Curtis et al. (2004). Rock outcrop and gas sample sites keyed to Fig. 1 and Tables 2 and 3. Dia = intercalated diatomites, Ss = sandstones.

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2.2. Natural gas samples Oligocene reservoirs sampled for this study are associated with thickly bedded sandstone complexes within the Menilite Shales. The Kliwa Sandstones in the Skole Unit have the best petroleum reservoir characteristics, with porosity of up to 30% and permeability as high as 100 mD. The Magdalena Sandstones, the equivalent of Kliwa Sandstones in the Silesian Unit, have porosity of up to 25% and permeability as high as 560 mD. The youngest sandstone horizons within the Upper Oligocene Krosno Beds have lower porosity (average 7%) and permeability of only a few mD (S´la˛czka, 1996). Eight natural gas samples were collected for this study as described in Table 3 and shown in Figs. 1 and 2. All gas samples were taken from producing wells. Free gases were collected directly at the well head and associated gases dissolved in oils were collected from separators. Samples Lo-93, Rn-111 and Jo-I are associated gases from the Kliwa Sandstone in the Skole Unit. Samples from the Silesian Unit include Be-12 and By-4 from the Kliwa Sandstones and Iz-4 from the Magdalena Sandstones. Samples Sl-3 and Sl-24 are from the Krosno Beds in the Dukla (Grybów Subunit) Unit. 3. Experimental and analytical procedures 3.1. Hydrous pyrolysis Hydrous pyrolysis (HP) experiments were conducted in 1 l (autoclave) reactors composed of stainless steel 316 and Hastelloy C276 (Parr Instrument Company, Illinois, USA). The four Menilite rock samples were crushed to gravel size (5–20 mm) with no prior extraction or drying before the experiments and were heated isothermally in the presence of liquid water. In each experiment, 350 g of crushed Menilite rock was loaded into the reactor. The reactor was closed and evacuated for several minutes before 375 g of distilled water was injected into the reactor. This loading procedure was used to minimize the presence of pre-existing gas (i.e., air and methane) in the rock pores and to maximize the contact between water and the rock pore surfaces. The amounts of water and rock used in these experiments were in compliance with guidelines suggested by Lewan (1993) to ensure that the rock was submerged in liquid water throughout the experiments and that volume expansion of water and products would not exceed the safety limits of the reactors. The loaded reactors were then purged with 6.9 MPa of helium, which was vented off until only 241 kPa of

He remained in the reactor head space. Gas, liquid and solid products generated during the pyrolysis procedure were collected. Thermally immature rocks were subjected to hydrous pyrolysis in a sequential (stepwise) fashion, because HP is a time intensive procedure and sample quantities were limited. In this sequential procedure, generated gases and expelled oils (Curtis et al., 2004; Lewan et al., 2006) were collected at the end of a 330 °C/72 h run. Previous work had shown that under these conditions, expelled oil can be generated in which thermal degradation of biomarkers is not complete (Lewan et al., 1986; Peters et al., 1990). The autoclave was air cooled to ambient temperature before sampling. Gas samples were collected in stainless steel 30 ml cylinders. After collection of generated gas and expelled oil, the pyrolyzed rock sample and water were then re-sealed in the reactor and heated for an additional 72 h at 355 °C. This latter heating allowed determination of the amount of gas that could be generated from the source rock near maximum oil generation (Lewan and Ruble, 2002). A sequential hydrous pyrolysis experiment set was run on Wilcox lignite (0.34% Rr; Behar et al., 2003) to determine the vitrinite reflectance level obtained at 330 °C for 72 h and after the subsequent heating of the same sample at 355 °C for 72 h. The initial heating gave a vitrinite reflectance of 1.28% Rr and the subsequent heating gave a vitrinite reflectance of 1.60% Rr. These values equate to pre-oil-cracking thermal maturities (>1.7% Rr, Roberts et al., 2004), based on hydrous pyrolysis kinetics for the cracking of the saturate fraction of crude oils (Tsuzuki et al., 1999). 3.2. Analytical procedure Molecular compositions of the hydrous pyrolysis gases (C1–C6 saturated and unsaturated hydrocarbons, H2S, CO2, O2, H2, N2, He and Ar) were analyzed by a set of columns on a Hewlett Packard 6890 gas chromatograph configured by Wasson Ece Instrumentation. Mole percentages determined by this analysis were converted to moles with the ideal gas law and the recorded collection volumes, pressures and temperatures. These analyses showed that of the original He placed in the reactor (42.9–44.9 mmole), the amount of He analyzed in the collected samples had a mean recovery of 0.8 ± 2.4 mole%. The generated gas analyses reported represent only the headspace gas and do not include dissolved gas in the water or generated oils. The quantities of gas are presented in units of mmole/g TOC. Molecular compositions of the natural gases were analyzed with Hewlett Packard 5890 Series II and

Table 3 Location of analyzed natural gases reservoired in Oligocene flysch strata of the Polish Carpathians. Well name

Sample code

Deposit name

Surface (m a.s.l.)

Depth (m)

Reservoir rocka

Type of accum.

Skole Unit Łodyna-93 Ropienka-111 Jajko-I

Lo-93 Rn-111 Jo-I

Łodyna Wan´kowa Wan´kowa

536 485 513

627–640 244–298 900–1000

Kliwa Ss Kliwa Ss Kliwa Ss

Silesian Unit Bednarka Iwonicz-4 Bystra-4

Be-12 Iz-4 By-4

Bednarka Bóbrka-R. Szalowa

404 411 386

783–758 1742–1770 428–451

Dukla Unit Słopnice-3 Słopnice-24

Sl-3 Sl-24

Słopnice Słopnice

465 477

1655–1905 1560–1650

GOR (gas:oil ratio)b

Dr. date

F. GOR date

D. disc. date

846 (1851) 61 (177) 14369 (62,512)

1984 1937 1932

1985 1989 1967

1889 1885 1885

– 78 (78) –

– 374 (374) –

1992 1972 1987

1997

1853

– –

– –

1974 1989

(Nm3/t)

(scf/bbl)

Assoc. Assoc. Assoc.

175 (385) 125 (37) 2983 (10,936)

Krosno B. Magd. Ss Krosno B.

n-Assoc. Assoc. n-Assoc.

Krosno B. Krosno B.

n-Assoc. n-Assoc.

1973 1973

R., Rogi; Ss, sandstones; Magd., Magdalena – equivalent of Kliwa Ss; accum., accumulation; assoc., associated; n-assoc., non-associated; Dr., drilling; F., first; GOR, gas:oil ratio; D. disc., deposit discovery; Nm3, normal cubic meter at temperature 20 °C (293.15 K) and pressure 101.3 kPa; scf, standard cubic feet at temperature 60 °F (288.65 K) and pressure 101.3 kPa; 1 metric ton (tonne) oil is equal to 7.33 barrels – average value for Carpathian region from www.spe.org. a Local lithostratigraphic nomenclature. b Calculated value based on first reliable data after well drilling, value obtained during 2005 gas sampling shown in parentheses.

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Chrom 5 gas chromatographs equipped with flame ionization (FID) and thermal conductivity (TCD) detectors. These analyses are given in mole% and include the naturally occurring He. Stable isotope analyses were performed using Finnigan Delta Plus and Micromass VG Optima mass spectrometers. The stable carbon and hydrogen isotope data are presented in the notation relative to V-PDB and V-SMOW standards (Coplen, 1995), respectively. Analytical precision is estimated to be ±0.2‰ and ±3‰, respectively. The result of stable nitrogen isotope analysis of the single Rn-111 sample is presented in the notation relative to the air nitrogen standard. Analytical precision is estimated to be ±0.4‰. Methane, ethane, propane and carbon dioxide were separated chromatographically for stable carbon isotope analyses. They were combusted over hot copper oxide (850 °C) and the carbon dioxide produced by the online system was transmitted to a mass spectrometer. Water resulting from the combustion of methane for stable hydrogen isotope analyses was reduced to gaseous hydrogen with zinc (Florkowski, 1985). Gaseous nitrogen was separated chromatographically for stable nitrogen isotope analysis and was transmitted to the mass spectrometer via the online system. For this paper, the results of Rock-Eval, elemental analyses of organic matter and stable carbon isotope composition of kerogen in Menilite Shales (Table 2) previously published by Curtis et al. (2004) were used. Analytical methods are presented in that paper. 4. Results and discussion 4.1. Gas generated by hydrous pyrolysis Although the amount of oil and gas generated under hydrous pyrolysis at specific time and temperature conditions varies with kerogen type (Lewan and Ruble, 2002), the sequential conditions at 330 and 355 °C for 72 h generally represent early and late petroleum generation stages, respectively. At 330 °C for 72 h, kerogen to bitumen generation dominates with lesser amounts (<50%) of bitumen to oil generation occurring. At 355 °C for 72 h in non-sequential experiments, bitumen to oil generation is at or near 100% completion (Lewan and Ruble, 2002). Therefore, in a sequential experiment where conditions of 355 °C for 72 h are imposed on a rock sample that has already been subjected to 330 °C for 72 h, the amount of bitumen to oil generation is at or near 100% complete. As reported by Curtis et al. (2004), the recovered rock from the experiments at 355 °C for 72 h have kerogen atomic H/C ratios from 0.56 to 0.66 and Rock-Eval hydrogen indices from 79–191 mg S2/g TOC. 4.1.1. Hydrocarbon molecular composition The gaseous hydrocarbons generated for 72 h at 330 °C and 355 °C and their cumulative totals are variable in their molecular composition and gas indices as shown in Table 4. Cumulative yields of methane, ethane, propane and total hydrocarbon gas (C1–C4) increase with increasing atomic H/C ratio of the kerogen isolated from the original unheated rock (Fig. 3), but these relationships are not observed for the yields from the individual 330 °C and 355 °C experiments (Table 4). With the exception of sample TY-31 with Type I/II kerogen, the total C1–C4 gas yield is greater in the 330 °C experiments than in the sequential 355 °C experiments (Table 4). The greater total hydrocarbon gas yields in the 355 °C experiment for the TY-31 sample may be related to the higher thermal maturities required for oil generation from Type I kerogen (Ruble et al., 2001) being also the case for gas generation. Similarly, the greater total C1–C4 gas yield in the 330 °C experiment for sample NI-2 with Type IIS kerogen may be related to the lower thermal maturities required for oil generation from Type IIS kerogen (Lewan et al., 2006) being also the case for gas generation.

773

Fig. 3. Cumulative hydrocarbon gas yields from sequential hydrous pyrolysis experiments plotted against the atomic H/C ratio of the original kerogen. Kerogen designation given above data points for total CH4–C4H10.

The relative molecular composition changes of the generated hydrocarbon gases (C1/C2, C2/C3, C3/C4 and i-C4/n-C4) also show variability with kerogen types and experimental conditions (Table 4). Although the dryness of a gas, as measured here by the C1/C2 ratio, is generally considered to increase with thermal maturity of a source rock, Whiticar (1994) notes that this prescribed trend for Types I and II kerogen is not well established for Type III kerogen. A more pressing issue is the greater dryness observed in natural gases relative to pyrolysis gases generated in the laboratory (Mango, 1992). Price and Schoell (1995) contend that this dryness discrepancy between natural and pyrolysis gases is a result of the former being preferentially enriched in methane during secondary migration after expulsion from a source rock. Results from this study do not resolve this issue, but suggest that dryness of thermogenic gas may not change significantly with increasing maturity of the Menilite source rock at least during oil generation. Although the proportionality of methane to ethane in natural gas is not simulated in the thermogenic gases generated by hydrous pyrolysis, the distribution of ethane, propane and butanes in natural gases is similar to thermogenic gases generated by hydrous pyrolysis. The typical range of C2/C3 ratios for natural gases is from 1.5–5.0 (Nikonov, 1972). As given in Table 4, the thermogenic gases generated by hydrous pyrolysis occur within this range with a mean C2/C3 ratio of 1.7 ± 0.2. Similarly, the C3/C4+ ratio of the thermogenic gases generated by hydrous pyrolysis (Table 4; 1.4 ± 0.4) occurs within the 1–3 range observed in natural gases (Nikonov, 1972). The i-C4/n-C4 ratios of the generated gases (Table 4) generally conform to the prescribed maturity trend by Oudin (1993, Tables 2–7, p. 271) which predicts this ratio to be <1 for thermogenic gases generated during catagenesis. Therefore, with the exception of the proportionality of methane to the other hydrocarbon gases, hydrous pyrolysis is a reasonable approach to simulating natural generation of thermogenic gas. No significant differences are observed between the relative gaseous hydrocarbon compositions of the 330 and 355 °C experiments, with the exception of sample KN-62 with Type III kerogen. Results on this sample show significant decreases in the C3/C4 and i-C4/n-C4 ratios from the 330 °C experiment to the 355 °C experiment (Table 4). 4.1.2. Hydrocarbon stable isotopes d13C values of the generated hydrocarbon gases are given in Table 5 and shown in a reciprocal carbon number plot in Fig. 4. In this plot, all of the generated gases show ‘‘dogleg” trends, which are different from the more linear trends reported by Chung et al. (1988) for gases generated by different kerogen types at 330 °C for

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Table 4 Yields of gas and expelled oil generated by hydrous pyrolysis at 330 and 355 °C for 72 h and their cumulative total (Cum). Kerogen type Sample code

I/II TY-31

II RG-28

II-S NI-2

III KN-62

Gases (mmole/gTOC)

330 °C

355 °C

Cum

330 °C

355 °C

Cum

330 °C

355 °C

Cum

330 °C

355 °C

Cum

Methane Ethane Propane n-Butane i-Butane Total C1–C4 CO2 H2 H2S

502.5 166.9 98.2 34.6 21.0 823.2 708.9 327.4 135.9

601.6 229.5 129.5 43.0 21.8 1025.4 294.0 530.8 235.4

1104.1 396.4 227.7 77.6 42.8 1848.6 1002.9 858.2 371.2

415.2 143.0 88.6 32.7 27.9 707.4 2081.6 158.7 163.4

368.5 147.0 95.7 31.3 20.6 663.1 383.8 124.0 490.4

783.7 290.0 184.3 64.0 48.5 1370.5 2465.3 282.7 653.8

579.2 193.5 114.9 31.5 28.4 947.5 2375.4 0.0 627.9

327.9 124.7 74.2 25.5 15.3 567.6 384.0 357.1 443.1

907.1 318.3 189.1 56.9 43.7 1515.1 2759.4 357.1 1071.1

446.4 133.7 79.6 0.17 15.0 674.8 3584 119.1 282.3

332.3 123.0 76.2 22.4 18.9 572.8 503.1 218.3 449.9

778.7 256.7 155.8 22.5 33.9 1247.6 4087.2 337.3 732.2

Gas ratios CHC C1/C2 C2/C3 C3/C4 iC4/nC4 CDMIa CDHIb HSHIc Expelled oil (t/t TOC)d

1.90 3.01 1.70 1.77 0.61 58.5 46.9 14.2 0.2720

1.67 2.62 1.77 2.00 0.51 32.8 22.7 18.7 0.4440

1.77 2.79 1.74 1.89 0.55 47.6 35.7 16.7 0.7160

1.79 2.90 1.61 1.46 0.85 83.4 75.4 18.8 0.2365

1.52 2.51 1.54 1.84 0.66 51.0 37.4 42.5 0.1659

1.65 2.70 1.57 1.64 0.76 75.9 65.1 32.3 0.4024

1.88 2.99 1.68 1.92 0.90 80.4 72.1 39.9 0.2589

1.51 2.63 1.68 1.82 0.60 53.9 41.0 43.8 0.1065

1.79 2.85 1.68 1.88 0.77 75.3 65.2 41.4 0.3654

2.09 3.34 1.68 5.26 87.0 88.9 84.5 29.5 0.1145

1.67 2.70 1.61 1.85 0.85 60.2 47.6 44.0 0.0711

1.89 3.033 1.648 2.76 1.504 84 77.1 36.98 0.1856

Gas:oil ratio (GOR) Nm3/te scf/bblf

76 366

58 279

65 312

75 361

100 481

95 457

92 442

133 643

93 448

152 734

201.97 973

302 1452

CHC = CH4/(C2H6 + C3H8). a Carbon dioxide/methane index = (CO2/[CO2 + CH4])  100 (%). b Carbon dioxide/hydrocarbon index = (CO2/[CO2 + C1 + C2 + C3 + C4])  100 (%). c Hydrogen sulfide/hydrocarbon index = (H2S/[H2S + C1 + C2 + C3 + C4])  100 (%). d Calculated in metric tons per ton of TOC from Curtis et al. (2004). e Normal cubic meters at 20 °C and 101.3 kPa. f Standard cubic feet at 60 °F and 101.3 kPa, and 1 metric ton of oil = 7.33 bbls.

72 h, gases generated from cracked oil at 300 °C for durations over 2000 h and two natural associated gases. The trends for each kerogen type at both experimental temperatures maintain a distinct isotopic signature with the exception of the Types II and IIS kerogens, which do show overlap and which is explained by the similar isotopic signatures of their original kerogens relative to the other two kerogen types (Table 2, Fig. 5). This suggests that the precursors for the Types II and IIS kerogen in the two different organic facies of the Menilite Shales were similar and that the incorporation of sulfur into the Type IIS kerogen had no significant affect on its d13C signature. Fig. 5 also shows that the smallest difference in d13C between the generated gases and their initial kerogen is for sample KN-62 with Type III kerogen. It is noteworthy that the methane d13C values from this sample are within the range of 36.6 to 33.5‰ reported for methane generated by hydrous pyrolysis at 360 °C for 72 h from Polish Carboniferous coals varying in rank from sub-bituminous to semi-anthracite (Kotarba and Lewan, 2004). An implication here is that irrespective of thermal maturity, methane generated from humic coals will have d13C values between 37 and 33‰. However, this does not appear to be true for the ethane and propane d13C values of these previously reported experiments, which yielded more depleted 13C values by a few per mil than those in this study. This difference may be a result of the Type III kerogen in sample KN-62 having a slightly more 12C enriched aliphatic component due to its more marine depositional setting than true humic coals. Overall, these results support the view that the original kerogen has a major influence on the d13C values of thermogenic hydrocarbon gases it generates. An important implication of these experimental results is that a linear relationship of methane, ethane and propane carbon isotopes with their reciprocal carbon number is not an exclusive indicator of a natural gas from a single source as sometimes assumed (e.g., Chung et al., 1988; Rooney et al., 1995). Zou et al.

(2007) suggest that a ‘‘dogleg” trend, exemplified by relatively 13 C depleted methane and enriched propane as compared to ethane, in this type of plot is a result of a natural gas that was not generated from a single source rock or that underwent post generation alteration (e.g., secondary gas cracking, microbial oxidation, thermochemical sulfate reduction). However, results from the hydrous pyrolysis experiments show that a ‘‘dogleg” trend can be generated from a single source and that it is irrespective of kerogen type. Fig. 6 shows plots of d13C of ethane versus methane and propane along with the empirical maturity trends proposed by Berner and Faber (1996). These maturity trends as proposed by Berner and Faber (1996) take into account the d13C of the original kerogen from which

Fig. 4. d13C of methane, ethane and propane generated from hydrous pyrolysis experiments versus the reciprocal of their carbon number.

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Fig. 5. d13C for hydrous pyrolysis gases generated from the Menilite Shales versus the d13C of their original kerogen. Dashed unity line shown for reference.

a gas is generated. These kerogen values are given in Table 2. The Type II/IIS trend is based on the average d13C value ( 26.75‰) of samples Nl-2 and RG-28. As shown in Fig. 6, none of the experimental results agree with the empirical maturity trends. The d13C of methane and ethane generated from samples with Types I/II, II and IIS kerogen occur below their calculated empirical maturity trends for Type I/II and Type II/IIS kerogens (Fig. 6a). Conversely, the d13C of propane and ethane generated from samples with Types I/II, II and IIS kerogen occur above their calculated empirical maturity trends for Type I/II and Type II/IIS kerogens (6b). Calibration of these sequential hydrous pyrolysis experiments with lignite gives vitrinite reflectance values of 1.28% Rr for the experiment at 330 °C after 72 h and 1.60% Rr for the subsequent experiment at 355 °C after 72 h. These vitrinite reflectance values are significantly higher than those prescribed by the empirical maturity trends, which indicate the recovered rocks should have vitrinite reflectance values at or less than 1.1% Rr (Fig. 6). This discrepancy can be explained in part by significant differences in the kinetics for recombination/condensation reactions responsible for vitrinite reflectance and the wide variation in kinetics for free radical cracking reactions responsible for petroleum generation (Lewan, 1985). As a result, unique vitrinite reflectance values for stages of oil and gas generation from source rocks with oil prone kerogen are not likely as prescribed by the empirical maturity trends. However, even sample KN-62 with Type III kerogen, on which vitrinite reflectance measurements are made, does not agree with the lower % Rr values prescribed by the empirical maturity tends (Rr 6 0.6%; Fig. 6). One explanation for this discrepancy may be a result of the non-hydrous open system used in modeling the empirical maturity trends (Berner et al., 1995). Boreham

et al. (1998) reported some differences in d13C values for hydrocarbon gases generated from Australian coals between open system pyrolysis and non-hydrous closed system pyrolysis. In addition, notable differences in hydrocarbon gas yields generated from source rocks with Types III and II kerogen under non-hydrous and hydrous closed system pyrolysis have also been reported by Behar et al. (2003) and Lewan (1998), respectively. The issue that emerges is: which pyrolysis method best simulates natural gas generation. Liquid water is ubiquitous in the subsurface and has been shown to play an important role in simulating natural oil generation and expulsion (Lewan, 1998). The openness of natural gas generation in comparison to open and closed system pyrolysis is less apparent. The rapid heating of powdered source rocks or their isolated kerogen to temperatures in excess of 500 °C at 5–10 °C/ min in open system pyrolysis is not really comparable to the slower heating rates of 1–10 °C/my experienced in nature by low porosity (<5%) source rocks at pressures that are orders of magnitude higher (70–150 MPa). Although more comparative studies are needed to resolve this issue, hydrous pyrolysis with its lower temperatures, longer experimental times, use of gravel sized rock and higher pressures offers the closest simulation to natural oil and gas generation from source rocks. dD values for methane generated by hydrous pyrolysis from the various kerogen types vary from 318 to 264‰ (Table 5). As previously discussed by Kotarba and Lewan (2004), D depleted methane can be explained by the D depleted distilled waters used in the experiments, which are also reflected in the recovered waters (Table 5). The ability of water to be a source of hydrogen during the thermal cracking of hydrocarbons has been shown experimentally (Hoering, 1984; Lewan, 1997; Schimmelmann et al., 1999, 2001) and advocated in natural methane generation (Smith et al., 1982; Schoell, 1988). Therefore, unlike the importance of kerogen influencing the d13C values for generated hydrocarbon gases, dD values of hydrocarbon gases can be influenced by the formation waters present in a source rock during their generation. Based on the dD values for the recovered waters from the hydrous pyrolysis experiments (Table 5), the mean difference in dD of recovered water and methane is 190 ± 17‰ (DdDwater–methane). The dD value of the diagenetic waters within the CretaceousOligocene strata of the Outer Carpathians averages 25‰ (Oszczypko and Zuber, 2002), and ocean and marine waters should not have significantly changed in isotopic composition during geological history (0‰; Hoefs, 2004). Therefore, calculating dD values for methane with waters having isotopic compositions between 25 and 0‰ and a mean DdDwater–methane of 190‰, gives dD values for methane ( 215 to 190‰) within the prescribed field for thermogenic gas values. These observations have two important implications. First, the lack of significant changes in

Table 5 Stable isotopes of gases generated by hydrous pyrolysis. Kerogen type and sample code

Experimental conditions (°C/h)

Stable isotopes (‰) d13C (CH4)

d13C (C2H6)

d13C (C3H8)

d13C (CO2)

dD (CH4)

Type I/II kerogen TY-31 TY-31

330/72 355/72

41.8 41.9

35.4 34.4

34.7 34.0

27.7 24.8

286 n.a.

Type IIS kerogen NI-2 NI-2

330/72 355/72

39.7 38.7

32.4 31.4

32.0 31.0

24.1 25.3

318 315

Type II kerogen RG-28 RG-28

330/72 355/72

39.7 39.0

32.4 30.9

32.0 31.0

26.5 26.3

n.a. 294

Type III kerogen KN-62 KN-62

330/72 355/72

36.4 36.0

29.5 27.6

28.9 27.9

14.2 9.9

314 264

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Fig. 6. d13C of ethane versus: (a) methane and (b) propane for hydrous pyrolysis gases generated from different kerogen types of Menilite Shales. Open symbols represent values for gases generated at 330 °C for 72 h and solid symbols represent values for gases generated in sequential experiments at 355 °C for 72 h. Vitrinite reflectance trend lines are based on equations reported by Berner and Faber (1996) for different kerogen types based on their measured d13C values given in Table 2.

the dD values of thermogenic methane with increasing organic matter maturation makes this parameter a poor maturity indicator, and secondly, the strong influence formation waters have on dD values of thermogenic methane make this parameter more difficult to use in source correlation compared to d13C values. These implications suggest, however, that dD may be used to characterize thermogenic methane with respect to the water in Menilite Shales of different depositional systems (i.e., estuarine and marine) or the influx of meteoric waters into the Menilite Shales in different parts of a basin. 4.1.3. Hydrocarbon gas:oil ratios The gas:oil ratio (GOR) for the generated hydrocarbon gases and expelled oils from the Menilite source rocks containing different types of kerogen are given in Table 4. GORs for the 330 °C experiments and the cumulative gas totals are plotted with their expelled oil in Fig. 7. The trends among the source rocks with oil prone kerogens (i.e., Types I/II, II and IIS) are within the same range of GORs (65–95 Nm3/t). Sample TY-31 with Type I/II kerogen generates the most cumulative oil and shows a slight decrease in GORs from the 330 °C experiment to the cumulative. Sample NI-2 with Type IIS kerogen shows essentially no change in the GORs and Sample RG-28 with Type II kerogen shows a moderate increase (Fig. 7). The source rock with gas prone Type III kerogen has a distinctly different trend that increases significantly from 152–302 Nm3/t (Fig. 7). The implication is that GORs are not significantly different to distinguish petroleum accumulations that were generated from source rocks with oil prone kerogen, but petroleum accumulations generated from source rocks with gas prone kerogen will have distinguishing GORs. 4.1.4. Non-hydrocarbon gases The non-hydrocarbon gases H2, CO2 and H2S are the dominant gaseous products from hydrous pyrolysis. Concentration of these gases, gas indices and stable isotope composition of carbon dioxide are shown in Table 4. The unusually large yields of CO2, H2 and H2S generated in hydrous pyrolysis, compared to a natural system, may be explained in part by the high temperatures of hydrous pyrolysis that result in increasing fugacities for each gas component (Cooles et al., 1987). Additionally, in the natural system, these highly soluble and reactive gases may be lost by dissolution and migration processes (e.g., Hunt, 1996). A common feature of the hydrous pyrolysis experiments is the production of large quantities of carbon dioxide (Andresen et al., 1994; Lewan, 1997). During our hydrous pyrolysis experiments, between 709 and 3584 mmole/kg TOC were generated at 330 °C

(Table 4) and 294 and 503 mmole/kg TOC were generated at 355 °C (Table 4). The consistently lower values in the 355 °C experiments compared to the 330 °C experiments indicate that CO2 generation occurs during the early stages of petroleum generation. This is due to the weaker C–O bond strength compared to the C–C bond (Galimov, 1985; Kotarba, 1988; Hunt, 1996). The dominance of CO2 in the 330 °C experiments is shown in Fig. 8a, which also shows that the quantity of CO2 generated is proportional to the amount of oxygen in the original kerogen (i.e., atomic O/C ratio). Some of the oxygen in the CO2 generated by hydrous pyrolysis has been shown to be derived from water interacting with the organic matter (Stalker et al., 1994; Lewan, 1997; Seewald et al., 1998). As a result, the amount of CO2 generated is not limited to the oxygen or carboxyl content of the original kerogen. d13C values of the carbon dioxide generated in the 330 °C and 355 °C experiments vary from 27.7 to 14.2‰ and from 26.3 to 9.9‰, respectively (Table 5). Their 12C enrichment is indicative of an organic source, although dissolution of carbonate minerals in the original samples may have contributed some 13C enriched CO2 to these values. However, some of these values fall within the thermogenic gas range ( 28 to 27‰) as defined by Kotarba and Rice (2001). Differences between 13C of the generated CO2 and the original kerogen change up to 4‰ for the source rocks with oil prone kerogen and up to 15.3‰ for the source rock with Type III kerogen (Tables 2 and 5). Galimov (1985) stated that in the thermal destruction of humic organic matter the kinetic isotope effect is insignificant and isotope fractionation undergoes thermodynamic

Fig. 7. Gas:oil ratio (GOR) versus yield of expelled oil from hydrous pyrolysis experiments at 330 °C for 72 h and cumulative (Cum) summation.

M.J. Kotarba et al. / Organic Geochemistry 40 (2009) 769–783

effect. Carbon dioxide generated during this process is enriched in 13 C from 12–28‰ as compared to humic source matter. During maturation of sedimentary organic matter large amounts of hydrogen sulfide are generated (Orr, 1977; Ivanov, 1983; Anissimov, 1995; Song et al., 2005), especially for Type IIS kerogen (Lewan, 1998; Amrani et al., 2005). H2S yields (Table 4) are proportional to the atomic Sorg/C ratio of the original kerogen (Fig. 8b). As expected, sample NI-2 with the high sulfur Type IIS kerogen generates the most H2S. Its greater yield in the 330 °C experiment indicates thermally more labile organic sulfur moieties, like thiols and sulfides are the source of the H2S. Conversely, the lower sulfur Types II and I/II kerogens generate most of their H2S in the 355 °C experiments, which suggests more thermally resilient sulfur moieties, like thiolanes or thianes are the source of the H2S. The intermediate H2S yields from sample KN-62 with the Type III (Fig. 8b) suggest an intermediate mix of thermally labile and resilient organic sulfur moieties as the precursor sources. It is noteworthy that Type III kerogen with moderate sulfur contents, yield comparable quantities of H2S as Type II kerogen. The dual source of H2 from water and organic matter and its participation with early H2S generation and later oil formation makes its behavior complex to interpret from the limited experi-

Fig. 8. Plots of non-hydrocarbon gas yields versus the atomic ratios of their original kerogen: (a) carbon dioxide versus atomic O/C ratio; (b) hydrogen sulfide versus atomic Sorg/C; and (c) molecular hydrogen versus atomic H/C ratio.

777

ments in this study. However, cumulative H2 yields and those from the 355 °C experiments for the oil prone kerogens are proportional to the atomic H/C ratio of the original kerogens (Fig. 8c). This is not the case for the 330 °C experiments, which show no H2 generation for sample NI-2 with Type IIS kerogen (Fig. 8c). The cause of this lack of H2 remains to be determined, but one explanation is that the early H2 generated is scavenged to make H2S, which forms early and in high quantities from Type IIS kerogen in the 330 °C experiment (Fig. 8b). It is also noteworthy that H2 cumulative and 355 °C yields for sample KN-62 with Type III kerogen are higher than those for sample RG-28 with Type II kerogen. This may be explained in part by the scavenging of H2 in the formation of oil, which is generated in greater quantities from Type II kerogen than that generated from Type III kerogen (Table 4). 4.2. Comparisons with natural gases Results and discussion in the previous section indicate that there exist distinct d13C signatures but non-distinct molecular compositions of gases generated by hydrous pyrolysis of representative Menilite source rocks containing Types I/II, II, IIS and III kerogens. The remaining objective is to determine whether these laboratory results can be used to evaluate kerogen types and thermal maturities responsible for the natural gas accumulations in the intercalated Kliwa and Magdalena Sandstones, and the overlying Krosno Beds of the Menilite Shales. However, it cannot be excluded that at least part of isotopically light methane was generated during late (young) microbial processes similar to that observed in the Upper Devonian Antrim shale in the Michigan basin (Martini et al., 1996). The analyzed natural gases accumulated in Oligocene reservoirs in the study area are variable in both their molecular and isotopic compositions (Table 6). Using the traditional plot of gas dryness (C1/[C2+C3]) versus d13C of methane (Fig. 9), the natural gases include thermogenic gas and varying mixtures of thermogenic and microbial gases. This range of natural gases is consistent with a larger data set of natural gases from Polish and Ukrainian Carpathian Oligocene reservoirs reported by Kotarba et al. (2007) and Kotarba and Nagao (2008). Sedimentation and tectonic histories of the Krosno Beds and Magdalena and Kliwa Sandstones of these units were very favorable for generation and preservation of microbial methane (Kotarba, 1992). The presence of both microbial and thermogenic gases in the same accumulations suggest the traps formed early enough to entrap the early formed microbial methane. These traps remained coherent with subsequent burial and thermal maturation to accommodate the thermogenic gas and oils generated from the Menilite Shales. 4.2.1. Hydrocarbon molecular composition Molecular compositions of the hydrocarbon gases generated by hydrous pyrolysis do not provide indices that differentiate kerogen type sources or thermal maturity of natural gases. Data shown in Table 4 indicate that relative to the natural gases (Table 6) the dryness index (C1/[C2+C3]) is low and essentially the same for the gases generated from all of the kerogen types. As previously discussed, this remains enigmatic for hydrocarbon gases generated from source rocks under open and closed conditions (Boreham et al., 1998) and from source rocks with high transition metal contents (Lewan et al., 2008). Although indices that include methane are not useful in comparing natural and pyrolysis gases, indices involving the heavier hydrocarbon gases (C2–C4) show more promise. Fig. 10a shows that although the ethane/propane index of the experimental gases remains essentially constant irrespective of kerogen type or maturity, the values do fall within the range of those of the natural gases. The propane/butanes index of the experimental gases shows a greater variability, also within the range of

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Table 6 Molecular and isotopic composition of natural gases produced from Oligocene flysch strata of the Polish Carpathians. Thrust Unit

Skole

Silesian

Sample code

Lo-93

Rn-111

Jo-I

Be-12

Iz-4

By-4

Sl-3

Sl-24

Gases (mole%)e Methane Ethane Propane n-Butane i-Butane C5a C6–C7b CO2 H2 N2 He

71.7 7.94 7.91 3.39 1.48 2.01 1.05 4.41 tr. 0.08 Tr.

38 4.77 7.73 5.06 2.72 3.48 1.15 20.91 0.33 15.5 0

91.8 3.79 1.47 0.42 0.34 0.37 0.22 0.05 0 1.5 Tr.

98 0.69 0.37 0.14 0.1 0.13 0.05 0.04 0 0.48 0.002

82.1 5.77 5.74 2.68 0.82 1.58 1.01 0.11 0.001 0.19 0.003

94.2 2.96 1.34 0.31 0.31 0.15 0.05 0.05 0.05 0.55 0.004

87.1 6.21 2.82 0.91 0.65 0.73 0.76 0.24 0.008 0.55 0.003

91.4 4.75 1.35 0.16 0.15 0.1 0.01 0.01 0.03 2 0.003

Gas ratios CHC C1/C2 C2/C3 C3/C4 iC4/nC4 CDMIc CDHId

4.5 9.03 1.00 1.62 0.44 5.79 4.55

3.0 7.97 0.62 0.99 0.54 35.49 26.40

17.5 24.22 2.58 1.93 0.81 0.05 0.05

92.5 142.03 1.86 1.54 0.71 0.04 0.04

7.1 14.23 1.01 1.64 0.31 0.13 0.11

21.9 31.82 2.21 2.16 1.00 0.05 0.05

9.7 14.03 2.20 1.81 0.71 0.27 0.25

15.0 19.24 3.52 4.35 0.94 0.01 0.01

Stable isotopes (‰) d13C (CH4) d13C (C2H6) d13C (C3H8) d13C (CO2) dD (CH4)

51.6 31.7 29.0 5.3 205

42.2 26.1 27.4 3.8 212

37.4 25.8 25.5 18.0 153

58.6 35.7 31.4 10.7 198

45.3 28.8 24.2 n.a. 188

39.0 28.2 25.6 11.4 151

37.2 27.4 24.8 n.a. 151

61.8 37.5 29.7 14.0 184

Dukla (Grybów)

Description of sample locations given in Table 1 and Fig. 1. a C5 = nC5H12 + iC5H12 + neoC5H12. b C6–C7 = C6H14 + C7H16; tr., traces. CHC = CH4/(C2H6+C3H8). c Carbon dioxide/methane index = (CO2/[CO2+CH4])  100 (%). d Carbon dioxide/hydrocarbon index = (CO2/[CO2+C1+C2+C3+C4])  100 (%). e H2S is below detection level (0.0001 mole%).

the natural gases, but no distinction of kerogen type or maturity can be discerned (Fig. 10a). Similarly, the i-butane/n-butane index of the experimental gases shows a notable variability within the range of the natural gases, but again no distinction of kerogen type or maturity can be discerned (Fig. 10b). It has long been recognized (e.g., Schoell, 1983) that in addition to variations in kerogen source and thermal maturity, natural gas migration through and accumulations within a wide range of temperature/pressure regimes with varying amounts of liquid hydrocarbons (i.e., oil or condensates) makes the utility of genetically correlating gases based solely on molecular compositions highly unlikely. The results from these experiments with well constrained kerogen types and thermal maturities indicate that molecular composition of thermogenic gases in the simplest of geological situations is not a viable genetic correlation parameter.

Fig. 9. Plot of d13C of methane versus hydrocarbon index CHC (i.e., CH4/[C2H6+C3H8]) for natural gases from Oligocene strata of the Polish Outer Carpathians. Compositional fields are from Whiticar (1994).

4.2.2. Hydrocarbon stable isotopes The d13C values of the hydrocarbon gases in the natural gas samples are given in Table 6. A plot of these values versus their reciprocal carbon number shows similar ‘‘dogleg” trends for the associated gases in the intercalated Kliwa Sandstones of the Skole Unit (Fig. 11a). These ‘‘dogleg” trends are similar to a different degree to those observed for the experimental gases. Samples Jo-1 and Rn-111 show the most pronounced ‘‘dogleg” trends and their d13C of the propane and ethane suggest Type III kerogen as a source. Their slightly heavier d13C values compared to sample KN-62 with Type III kerogen can be explained by their original Type III kerogen having a slightly heavier d13C value by 2–3‰ (i.e., d13CKerogen = 23.2 to 22.2‰). This explanation is reasonable in that Type III kerogens have been shown to have d13C values that extend into this range between 26.5 and 22‰ (Lewan, 1980, p. 24). The slightly greater 12C enrichment of the methane in these two gases relative to the experimental trends for Type III kerogen suggests that they may contain a microbial methane component. Using the difference of 7.5‰ between propane and methane for the Type III kerogen (Fig. 5) for the 330 °C experiment, an approximate microbial methane component of 13 and 36 mole% is calculated for Jo-1 and Rn-111, respectively. This approximation assumes a d13C end member for microbial methane of 66.5‰, which is the mean (±2.3‰) of 58 microbial methane accumulations in Miocene strata of the Carpathian Foredeep (Kotarba, 1998). The methane of sample Lo-93 in the Skole Unit has a 12C enrichment suggesting a greater microbial methane component. Like the other two gases from the Skole Unit, it has a notable but less pronounced ‘‘dogleg” trend in the plot of 13C versus reciprocal carbon number (Fig. 11a). Its propane d13C value also indicates a source with Type III kerogen similar to the other two gases in the Skole Unit (Jo-1 and Rn-111; Fig. 11a). Using the same input previously described

M.J. Kotarba et al. / Organic Geochemistry 40 (2009) 769–783

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Fig. 11. Plots of d13C of methane, ethane and propane versus the reciprocal of their carbon number for natural gases from: (a) Skole Unit with hydrous pyrolysis gases in gray with the same symbol designation as given in Fig. 4 and (b) Silesian and Dukla (Grybów) Units.

Fig. 10. Comparison of hydrocarbon gas ratios: (a) ethane/propane and (b) i-butane/n-butane versus propane/butanes of natural gases and gases generated by hydrous pyrolysis at 330 °C for 72 h (open symbols) and subsequent heating at 355 °C for 72 h (solid symbols).

for methane from Type III kerogen and microbial methane, sample Lo-93 has approximately a 50% microbial methane component. Natural gas samples Sl-3 and Sl-24 have a more linear trend on the plot of d13C versus reciprocal carbon number (Fig. 11b). This is similar to the linear trend reported by Chung et al. (1988) for gases generated from a Wyoming coal by hydrous pyrolysis after 72 h at 330 °C. The Sl-3 and Sl-24 gases are from the far western part of the study area in the Dukla (Grybów) Unit where no source rocks from the Menilite were subjected to hydrous pyrolysis (Fig. 1). Therefore, it is possible that a change in organic facies within the Menilite Shales to the west may contain organic matter that yields a more linear d13C trend, rather than the ‘‘dogleg” trends generated by the eastern samples used in this study. This possibility emphasizes the importance of obtaining a broad regional distribution of source rocks when using hydrous pyrolysis to evaluate sources of natural gas. Although the lack of results from pyrolyzed samples in this western area limit detailed interpretation of these gas sources, some comments can be made on the available data. Specifically, the 12C depletion of the hydrocarbon gases and the limited change with thermal maturation prior to oil cracking suggests that gas samples Sl-3 and Sl-24 were generated from source rocks containing Type III kerogen. Similar to the Sl-3 and Sl-24 gases, gas samples Be-12, Iz-4 and By-4 from the Silesian Unit have linear trends on the reciprocal carbon number plot (Fig. 11b), but their trends have 12C enriched methane and ethane, which suggests a large component of microbial gas (Table 6 and Fig. 11b). Microbial ethane with 12C enrichment ( 61.2 to 52.5‰) has been reported in producing microbial gas accumulations (Lillis, 2007). Although microbial propane has been reported in some deep marine sediments (Hinrichs et al., 2006), its extremely low concentrations allows it to be assumed negligible in approximating a microbial methane component of samples Be-12, Iz-4 and By-4. The 330 °C experi-

mental data in Fig. 11b indicates the d13C value for propane in samples Be-12 and By-4 are from a Type III kerogen and sample Iz-4 is from a Type II or IIS kerogen. Using the 7.5‰ and 7.7‰ difference between propane and methane for the Type III and Type II or IIS kerogen, respectively (Fig. 5, Table 5), an approximate microbial methane component of 84, 71 and 39% is calculated for Be-12, Iz-4 and By-4, respectively. As with previous approximations, the d13C end member for microbial methane in the calculations is 66.5‰ (Kotarba, 1998). The relative differences in the % of microbial methane component in these Silesian Unit reservoirs show no apparent correlation with their depths (Tables 3 and 6) or geographic locations (Fig. 1). Although these percentages are only approximations, they provide a relative and consistent method of calculating microbial methane components in natural gases based on experimental result. dD values of the natural gas samples with a notable microbial methane component indicate that methanogenesis involved CO2 reduction as opposed to fermentation (Fig. 12). Water present during microbial CO2 reduction is a major source of the methane hydrogen (Whiticar et al., 1986). As a result the dD of the available water will have a significant influence on the dD of the microbial methane. Whiticar et al. (1986) report a DdDwater–methane for microbial methane from CO2 reduction of 180 ± 20‰, which overlaps with the range for thermogenic methane generation measured in the hydrous pyrolysis experiments (DdDwater–methane 181 ± 26‰; Table 5). The implication is that dD of methane may be useful in differentiating microbial methane from CO2 reduction and fermentation (Whiticar et al., 1986), but it cannot readily differentiate between thermogenic and microbial methane when mixtures of the two coexist in an accumulation. 4.2.3. Hydrocarbon gas:oil ratios Calculated GOR values based on the sum of oil and gas reserves and production from 1853–1998 (Karnkowski, 1999) for individual tectonic units in the Polish Outer Carpathians vary from 115 Nm3/t (552 scf/bbl) in the Magura and Grybów units to 1568 Nm3/t (7536 scf/bbl) in the Silesian Unit (Table 1, Fig. 13). The cumulative GORs for the hydrous pyrolysis experiments of the different kerogen types are extended across Fig. 13 for comparison. The experimental GORs are lower than those for the overall production in the thrust units. This is particularly the case for the Silesian Unit, which accounts for 71% of the gas production and 96% of the oil

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production in the Polish Outer Carpathians. This higher GOR value in the Silesian Unit is due to the fact that almost all deposits of free (non-associated) gas (14 of 16 deposits) occur in this thrust unit and that a significant portion of the gas has a microbial gas component. The two non-associated gases (Be-12 and By-4) analyzed from the Silesian Unit contained approximately 39–84% microbial methane. The associated gas sample (Iz-4) from this unit contained approximately 74% microbial methane (see Section 4.2.2). Considering the input of microbial gas, hydrous pyrolysis experiments provide reasonable GORs for the oil and thermogenic gas generated from Menilite source rocks. 4.2.4. Non-hydrocarbon gases Although hydrogen sulfide was generated in large volumes from the Menilite Shales during the HP experiments, no traces of it are found in natural gas accumulations within the flysch strata of the Carpathians (Table 6 and Kotarba, 1987, 1992, 1993; Karnkowski, 1999; Kotarba et al., 2007; Kotarba and Nagao, 2008). This absence of hydrogen sulfide as a free gas is attributed to its high solubility in formation waters and its high reactivity with Fe and other transition metals (i.e., Cu, Pb and Zn) during gas migration and entrapment (e.g., Orr, 1977; Suleimenov and Krupp, 1994). The major removal process of H2S in clastic and claystone–sandstone complexes of the flysch strata appears to be due to formation of pyrite and other metal sulfides. The notably high N2 in the Rn-111 sample is attributed to secondary recovery methods in the 1980s in which atmospheric air was injected into the Wan´kowa deposit (E. Szewczyk and J. Polit, personal communication). The 15 N(N2) measured on this gas sample was 0.9‰, which is indicative of atmospheric air. This gas sample also contains significant percentages of H2 and CO2 relative to the other gas samples. These higher percentages may be attributed to sequential secondary microbial oxidation and fermentation in the reservoir by microbes that were injected with the atmospheric air. The 13C enriched CO2 from this well and that from Lo-93 indicate that thermal degradation of organic matter in the source rocks is not a dominant source (Fig. 14). CO2 generated in the hydrous pyrolysis experiments was 13C depleted for all kerogen types (Table 5). The 13C depleted CO2 from the other natural samples (i.e., Jo-1, Be-12, Iz-4 and Sl-3) suggest they contain a significant thermogenic organic component. Stable carbon isotope analyses of gaseous carbon dioxide associated with CO2 charged waters in the Polish Outer Carpathians (Les´niak, 1998) indicate that it is predominantly derived from the thermal decomposition of carbonate and silicate rocks deeper in the Earth’s crust. 13 C(CO2)(g) values change during H2O–CO2 flow to the surface (Hałas et al., 1997; Les´niak, 1998; Les´niak and Zawidzki, 2006). Therefore, it cannot be excluded that at least some inorganic CO2 migrated along deep seated faults and mixed with thermogenic

Fig. 12. Methane d13C versus dD for natural gases from Oligocene strata of the Polish Outer Carpathians. Compositional fields are from Whiticar (1994).

CO2. However, we do not find the presence of a crustal component of CO2 in the studied gases. Similar to H2S, the lower CO2 contents in six of the eight natural gas samples compared to its high content in the experiments is attributed to its high aqueous solubility in vast quantities of subsurface formation waters and its diagenetic reactivity with subsurface strata. It has been observed that partial pressures of carbon dioxide increase systematically with increasing temperature in petroleum basins (Smith and Ehrenberg, 1989). In addition, this effect can be buffered by feldspars, clay minerals, or carbonates and suggests that organically derived carbon dioxide may be removed from natural gas by mineral precipitation (Smith and Ehrenberg, 1989; Hutcheon and Abercrombie, 1990; Seewald, 2003). The experiments showed that the major portion of CO2 generation occurred during early petroleum generation (330 °C for 72 h), which provides ample time for its removal from natural gas by these various processes during the evolution of a sedimentary basin. Hydrogen was also generated in notable quantities from Menilite Shales during the hydrous pyrolysis experiments, but only traces of it have been found in natural gas accumulations within the flysch strata of the Carpathians (Table 6 and Karnkowski, 1999; Kotarba, 1987, 1992, 1993). Natural hydrogen is generated in the course of various biogenic and abiogenic processes: microbial fermentation of sedimentary organic matter, thermal decomposition of sedimentary organic matter, hydrolysis, water radiolysis (dissociation of water molecules bombarded by alpha particles) and natural nuclear reactions (Zobell, 1947; Zinger, 1962; Hawkes, 1972; Dubessy et al., 1988; Sherwood Lollar et al., 1993; Savary and Pagel, 1997). Hydrogen is very reactive and mobile, so its retention in petroleum traps is ephemeral. Its presence thus indicates that it is either being actively generated from recent secondary reactions in the reservoir or in adjacent source beds, or is diffusing up from deep seated sources (Hunt, 1996). 5. Conclusions Sequential hydrous pyrolysis as used in this study can facilitate genetic correlations between source rocks and thermogenic gases generated prior to oil cracking thermal maturities (Rr < 1.7%). Although molecular compositions of the experimentally generated gases are not helpful in this application, the d13C of the hydrocarbon gases are. In particular, the trend between d13C of methane,

Fig. 13. Gas:oil ratio (GOR) for produced natural gases from each thrust unit of the Polish Outer Carpathians. Values given above each bar represent the percentages of oil and gas produced from each thrust unit (Table 1). Horizontal lines represent the GORs of the cumulative gases generated by hydrous pyrolysis at 330 °C and 355 °C for 72 h for each kerogen type as labeled.

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Fig. 14. d13C(CH4) versus d13C(CO2) for natural gases from Oligocene strata of the Polish Outer Carpathians. Compositional fields modified from Gutsalo and Plotnikov (1981), Kotarba (1988) and Kotarba and Rice (2001).

ethane and propane and their reciprocal carbon number is not always linear as prescribed by some investigators. Instead, a ‘‘dogleg” trend may exist and shift in d13C with the d13C of the source rock kerogen. Experimentally determining this trend and how it changes from early to late petroleum generation provides a correlation parameter that can help in assessing thermogenic gas end members and microbial gas input in natural gases. This approach cannot account for the isotopic changes a natural gas may incur during migration and in-reservoir alterations, but it does provide an isotopic signature of the primary gas generated from a source rock at pre-oil-cracking thermal maturities. Because this approach requires source rocks, it is imperative to obtain samples representing potential source rocks over the geographic and stratigraphic extent of a study area. Sequential hydrous pyrolysis also provides new insights on interpreting stable isotopes of natural gases that are not always considered in existing empirical and theoretical interpretive schemes. This especially pertains to evaluating the thermal maturity at which a gas is generated. The experimental results from this study show that d13C of the hydrocarbon gases become 13C enriched from early to late petroleum generation (Rr < 1.7%), but the several per mil change observed does not compare with the tens of per mil changes currently advocated by interpretive schemes based on open system non-hydrous pyrolysis (Berner and Faber, 1996) at temperatures typically in excess of 400 °C. With respect to methane, the experiments indicate that water derived hydrogen contributes to its dD signature with a DdDwater–methane (181 ± 26‰) similar to that for microbial methane generated by CO2 reduction (180 ± 20‰). The implication is that unlike d13C, dD of methane will be more influenced by the formation waters present during its generation than by the kerogen precursors. The high mobility of generated gas within the vastness of sedimentary basins makes laboratory pyrolysis an essential effort in understanding generation and correlation of natural gases. When experimental results do not agree with prevailing paradigms, the critical issue to resolve is whether the results are an artifact of the experimental method or are they providing new insights that were not previously considered. Although this study only involves the results of a few source rocks from a given locale, its results emphasize the need to do more studies using rocks under pyrolysis conditions that more closely simulate natural gas generation in the subsurface. The results of this study also indicate that empirical schemes used to interpret kerogen sources and thermal maturity of natural gases based on their d13C values need to be reevaluated.

The research was undertaken as part of an American-Polish geochemical research project for studies of organic matter and oils in the Polish Carpathians, financed by the Joint Maria SkłodowskaCurie II Fund (Grant MEN/USGS-97-319). The research has also been financially supported by the Polish Ministry of Science and High Education Grant No. 5 T12B 017 25 (18.25.140.105) (AGH University of Science and Technology). We appreciate and thank M. Pawlewicz for his vitrinite reflectance measurements on the Wilcox lignite, which was used to calibrate levels of thermal maturity in the sequential hydrous pyrolysis experiments. C. Boreham from Geoscience Australia and second anonymous reviewer gave very constructive remarks and comments that greatly improved the discussion and the possible consequences of the hypotheses presented in the manuscript. Review comments and suggestions by L. Stalker were very helpful. Analytical work by D. Wie˛cław and T. Kowalski from the AGH University of Science and Technology and by A. Warden from the US Geological Survey is gratefully acknowledged. We are very grateful to E. Szewczyk and J. Polit from the Polish Oil and Gas Company, Branch Office in Sanok for supplying production data. Associate Editor—Simon George References Amrani, A., Lewan, M.D., Aizenshtat, Z., 2005. Stable sulfur isotope partitioning during simulated petroleum formation as determined by hydrous pyrolysis of Ghareb Limestone, Israel. Geochimica et Cosmochimica Acta 69, 5317–5331. Andresen, B., Throndsen, T., Barth, T., Bolstad, J., 1994. Thermal generation of carbon dioxide and organic acids from different source rocks. Organic Geochemistry 21, 1229–1242. Anissimov, L., 1995. Origin of H2S in natural gases: identification of geochemical processes. In: Grimalt, J.O., Dorronsoro C. (Eds.), Organic Geochemistry: Developments and Applications to Energy, Climate, Environment and Human History. Selected Papers from the 17th International Meeting on Organic Geochemistry Donostia-San Sebastian, pp. 1113–1114. Behar, F., Lewan, M.D., Lorant, F., Vandenbroucke, M., 2003. Comparison of artificial maturation of lignite in hydrous and nonhydrous conditions. Organic Geochemistry 34, 575–600. Berner, U., Faber, E., 1996. Empirical carbon isotope/maturity relationships for gases from algal kerogens and terrigenous organic matter, based on dry, open-system pyrolysis. Organic Geochemistry 24, 947–955. Berner, U., Faber, E., Scheeder, G., Panten, D., 1995. Primary cracking of algal and landplant kerogens: kinetic models of isotope variations in methane, ethane and propane. Chemical Geology 126, 235–245. Boreham, C.J., Golding, S.D., Glikson, M., 1998. Factors controlling the origin of gas in Australian Bowen basin coals. Organic Geochemistry 29, 347–362. Chung, H.M., Gormly, J.R., Squires, R.M., 1988. Origin of gaseous hydrocarbons in subsurface environments: theoretical considerations of carbon isotope distribution. Chemical Geology 71, 91–103. Coplen, T.B., 1995. Reporting of stable carbon, hydrogen, and oxygen isotopic abundances. In: Reference and Intercomparision Materials for Stable Isotopes of Light Elements. Proceedings of a Consultants Meeting Held in Vienna, 1–3 December 1993. International Atomic Energy Agency, Vienna, pp. 31–34. Cooles, G.P., Mackenzie, A.S., Parkes, R.J., 1987. Non-hydrocarbons of significance in petroleum exploration: volatile fatty acids and non-hydrocarbon gases. Mineralogical Magazine 51, 483–493. Curtis, J.B., Kotarba, M.J., Lewan, M.D., Wie˛cław, D., 2004. Oil/source rock correlations in the Polish Flysch Carpathians and Mesozoic basement and organic facies of the Oligocene Menilite Shales: insights from hydrous pyrolysis experiments. Organic Geochemistry 35, 1573–1596. Dubessy, J., Pagel, M., Beny, J.M., Christensen, H., Hickel, B., Kosztolanyi, C., Poty, B., 1988. Radiolysis evidenced by H2–O2 and H2-bearing fluid inclusions in three uranium deposits. Geochimica et Cosmochimica Acta 52, 1155–1167. Florkowski, T., 1985. Sample preparation for hydrogen isotope analysis by mass spectrometry. International Journal of Applied Radiation and Isotopes 36, 991– 992. Galimov, E.M., 1985. The Biological Fractionation of Isotopes. Academic Press, London. Gutsalo, L.K., Plotnikov, A.M., 1981. Carbon isotopic composition in the CH4–CO2 system as a criterion for the origin of methane and carbon dioxide in earth natural gases. Doklady Akademyi Nauk SSSR 259, 470–473 (in Russian). Hałas, S., Szaran, J., Niezgoda, H., 1997. Experimental isotopic fractionation during the CO2 exchange between dissolved carbonate and carbon dioxide. Geochimica et Cosmochimica Acta 52, 2169–2175.

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