1. Enrichment of nitrogen and 13
C of methane in natural gases
from the Khuff Formation, Saudi Arabia, caused by thermochemical
sulfate reduction
Peter D. Jenden a,⇑
, Paul A. Titley b
, Richard H. Worden c,1
a
Saudi Aramco EXPEC Advanced Research Center, Room GA-221, Building 2291, Dhahran 31311, Saudi Arabia
b
Saudi Aramco Eastern Area Exploration Department, Room R-E-3580, Engineering Bldg (728A), Dhahran 31311, Saudi Arabia
c
Department of Earth, Ocean and Ecological Sciences, University of Liverpool, 4 Brownlow Street, Liverpool L69 3GP, United Kingdom
a r t i c l e i n f o
Article history:
Received 19 August 2014
Received in revised form 2 February 2015
Accepted 23 February 2015
Available online 5 March 2015
Keywords:
Natural gas
Nitrogen
Hydrogen sulfide
Sulfate
Methane oxidation
Stable isotope
a b s t r a c t
Permian Khuff reservoirs along the east coast of Saudi Arabia and in the Arabian Gulf produce dry sour gas
with highly variable nitrogen concentrations. Rough correlations between N2/CH4, CO2/CH4 and H2S/CH4
suggest that non-hydrocarbon gas abundances are controlled by thermochemical sulfate reduction (TSR).
In Khuff gases judged to be unaltered by TSR, methane d13
C generally falls between À40‰ and À35‰
VPDB and carbon dioxide d13
C between À3‰ and 0‰ VPDB. As H2S/CH4 increases, methane d13
C
increases to as much as À3‰ and carbon dioxide d13
C decreases to as little as À28‰. These changes
are interpreted to reflect the oxidation of methane to carbon dioxide.
Khuff reservoir temperatures, which locally exceed 150 °C, appear high enough to drive the reduction
of sulfate by methane. Anhydrite is abundant in the Khuff and fine grained nodules are commonly
rimmed with secondary calcite cement. Some cores contain abundant pyrite, sphalerite and galena.
Assuming that nitrogen is inert, loss of methane by TSR should increase N2/CH4 of the residual gas and
leave d15
N unaltered. d15
N of Paleozoic gases in Saudi Arabia varies from À7‰ to 1‰ vs. air and supports
the TSR hypothesis. N2/CH4 in gases from stacked Khuff reservoirs varies by a factor of 19 yet the varia-
tion in d15
N (0.3–0.5‰) is trivial.
Because the relative abundance of hydrogen sulfide is not a fully reliable extent of reaction parameter,
we have attempted to assess the extent of TSR using plots of methane d13
C versus log(N2/CH4). Observed
variations in these parameters can be fitted using simple Rayleigh models with kinetic carbon isotope
fractionation factors between 0.98 and 0.99. We calculate that TSR may have destroyed more than 90%
of the original methane charge in the most extreme instance. The possibility that methane may be
completely destroyed by TSR has important implications for deep gas exploration and the origin of gases
rich in nitrogen as well as hydrogen sulfide.
Ó 2015 Elsevier Ltd. All rights reserved.
1. Introduction
Although most commercial natural gases contain only a few
percent nitrogen, fields producing 20% or more are relatively
common (Jenden et al., 1988; Krooss et al., 1995). High nitrogen
contents decrease the commercial value of natural gas deposits
and can increase production costs if treatment is required to meet
commercial standards (Kuo et al., 2012). Nitrogen in natural gas
may have a variety of sources including volcanic and geothermal
activity, burial alteration of organic rich sedimentary rocks,
devolatilization of metasedimentary ‘‘basement’’ rocks and air
dissolved in recharging surface water (Jenden et al., 1988; Krooss
et al., 1995; Littke et al., 1995; Zhu et al., 2000; Ballentine and
Sherwood-Lollar, 2002; Mingram et al., 2005). Importantly, nitro-
gen contamination can be introduced during sampling due to addi-
tion of air or the use of nitrogen as a lift gas in exploration wells to
stimulate flow from damaged or low permeability reservoirs.
1.1. Nitrogen from high maturity sedimentary and metasedimentary
rocks
In the absence of elevated heat flows or geothermal activity,
nitrogen in commercial gases is most likely to be derived from
http://dx.doi.org/10.1016/j.orggeochem.2015.02.008
0146-6380/Ó 2015 Elsevier Ltd. All rights reserved.
⇑ Corresponding author at: P.O. Box 12642, Dhahran 31311, Saudi Arabia. Tel.:
+966 13 872 3862.
E-mail addresses: peter.jenden@aramco.com (P.D. Jenden), R.Worden@liverpool.
ac.uk (R.H. Worden).
1
Tel.: +44 151 794 5184.
Organic Geochemistry 82 (2015) 54–68
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2. sedimentary or metasedimentary sources. Deep, high maturity
sedimentary rocks are regarded as a major source of nitrogen in
Upper Carboniferous to Triassic natural gases from the Central
European Basin. Rotliegend reservoirs overlying Westphalian coal
beds with > 3% vitrinite reflectance produce gases with > 50% nitro-
gen (Littke et al., 1995). Pyrolysis experiments (Krooss et al., 1995,
2006; Jurisch et al., 2012) show that gases evolved at high tem-
peratures from coal and shale may be enriched in nitrogen relative
to methane. High N2/CH4 may therefore indicate fractional entrap-
ment of late thermogenic gas (Krooss et al., 1995; Battani et al.,
2000). Liu et al. (2008) have suggested that N2/CH4 be used as a
maturity indicator for gases generated by coal sourced natural
gases. Natural gases produced from Rotliegend reservoirs in north-
ern Germany are characterized by d15
N between À3‰ and 19‰,
methane d13
C up to À20‰ and crustal (radiogenic) helium (Littke
et al., 1995; Gerling et al., 1997). Likely sources of Rotliegend nitro-
gen include organic nitrogen in Westphalian coal beds and ammo-
nium in underlying Namurian shales (Krooss et al., 1995, 2006;
Mingram et al., 2005).
Liberation of nitrogen during the metamorphism of pelitic rocks
is indicated by a decrease in bulk nitrogen concentrations from
1000 ppm or more in shales to less than 50 ppm in high grade
gneisses (Mingram et al., 2005; Jia, 2006). However, establishing
a link between nitrogen in commercial gas fields and nitrogen in
metamorphic rocks has proved to be difficult. One example may
be the giant Hugoton–Panhandle complex of the central United
States, which produces gas with 5–75% nitrogen from shallow
Permian reservoirs (< 1000 m). Ballentine and Sherwood-Lollar
(2002) used noble gas measurements to argue that Hugoton–
Panhandle nitrogen originated by mixing of low grade metamor-
phic volatiles, characterized by d15
N = À3‰ and traces of mantle
helium, with sedimentary nitrogen characterized by d15
N = 13‰
and no resolvable helium component. Metamorphic nitrogen
may also be present in the Great Valley of California where dry
gas fields with up to 87% nitrogen and d15
N between 1‰ and 4‰
are trapped in Cretaceous reservoirs at < 3000 m (Jenden et al.,
1988; Bebout and Fogel, 1992). Nitrogen concentration increases
with proximity to basement, methane d13
C ranges up to À15‰
and the gas fields contain mantle derived helium, suggesting the
involvement of metasedimentary rocks subducted beneath the
western margin of North America.
1.2. Nitrogen enriched by thermochemical sulfate reduction?
Thermochemical sulfate reduction (TSR) is well known in both
oil and gas reservoirs (Orr, 1977; Machel et al., 1995). Although
the reaction preferentially attacks oil and gas condensate, at tem-
peratures exceeding 140 °C even methane may be oxidized
(Worden et al., 1995; Worden and Smalley, 1996, 2004; Cai et al.,
2004, 2013). Assuming that methane is the primary hydrocarbon
involved, the net reaction would be:
CaSO4ðanhydriteÞ þ CH4 ! CaCO3ðcalciteÞ þ H2S þ H2O:
As hydrocarbons are depleted in 12
C relative to marine carbon-
ates, secondary calcite cements formed by TSR can have strongly
negative d13
C (Krouse et al., 1988; Heydari and Moore, 1989;
Worden and Smalley, 1996). Other products include elemental sul-
fur, solid bitumen and carbon dioxide. Carbon dioxide may be
formed by the reaction of sulfate with trace amounts of C2+ gases,
condensate liquids or solid bitumen. Carbon dioxide can also be
formed by the decomposition of carbonate minerals, for example
by the reaction of hydrogen sulfide with siderite or ferroan calcite
(Liu et al., 2013) or with dissolved base metals, releasing protons
and leaching calcite or dolomite.
Machel (1998, 2001) and others have disputed whether
methane in oil and gas fields is significantly altered by TSR.
Although reaction of sulfate with methane is thermodynamically
favorable (Worden and Smalley, 1996), rupture of S–O bonds in
sulfate has a high activation energy and methane is the most resis-
tant of all hydrocarbons (Xia et al., 2014). Most TSR experiments
have been carried out with higher molecular weight compounds
and at temperatures of 300 °C and above. Yuan et al. (2013)
recently demonstrated TSR of methane at temperatures as low as
250 °C but speculated that reaction rates at geological time scales
would be prohibitively slow at temperatures below 200 °C.
Because the higher hydrocarbons are more reactive, we suggest
that extensive reaction of methane is unlikely in TSR altered fields
producing oil, condensate liquids or abundant C2+ gases, such as
those studied by Krouse et al. (1988), Cai et al. (2001) and
Mankiewicz et al. (2009). Evidence that sulfate and methane may
react at temperatures below 200 °C is provided by methane d13
C
measurements of TSR altered, dry gas fields in Abu Dhabi and the
eastern Sichuan Basin, China. Field data and experiments have
established that thermochemical oxidation of the light hydrocar-
bon gases is accompanied by 13
C enrichment of the unreacted
residue (Krouse et al., 1988; Kiyosu et al., 1990; Pan et al., 2006;
Hao et al., 2008; Mankiewicz et al., 2009). Using a petrographic
parameter to estimate the extent of reaction, Worden and
Smalley (1996) concluded that TSR has increased methane d13
C
of Abu Dhabi gases by as much as 10‰. Cai et al. (2013) used a
reaction proxy based on H2S abundance and showed that TSR
may have increased methane d13
C in Sichuan Basin gases up to
6‰. Under appropriate conditions, we suspect that methane can
be almost completely destroyed. In the Mississippi Salt Basin, for
example, Heydari (1997) reported on a carbonate reservoir at over
200 °C that tested gas with 78% hydrogen sulfide, 20% carbon diox-
ide and 2% methane. Late stage calcite cement with d13
C as low as
À16‰ confirms that TSR occurred in situ (Heydari and Moore,
1989).
As TSR of a dry gas yields one mole of hydrogen sulfide for every
mole of methane consumed, the mole fraction of nitrogen and
other inert components in an altered gas cannot increase unless
hydrogen sulfide is lost from the gas phase. This could occur by
dissolution of hydrogen sulfide in an active water leg or by reaction
with dissolved sulfate to form elemental sulfur. If Fe or base metals
such as Pb and Zn are available, hydrogen sulfide could be precipi-
tated as pyrite, galena or sphalerite. Regardless of the fate of the
hydrogen sulfide produced, extensive TSR must increase the ratio
of nitrogen to methane. d15
N of the remaining nitrogen should
retain the signature of the natural gas that charged the Khuff prior
to TSR alteration.
Enrichment of nitrogen in dry natural gases subjected to
extensive TSR has not been explicitly reported in the geochemical
literature. Khuff Formation gases from Abu Dhabi reported by
Worden et al. (1995) show a weak positive correlation between
N2/CH4 and H2S/CH4. In contrast, enrichment of nitrogen by TSR
is not apparent in data for dry, sour gases in Carboniferous-
Triassic reservoirs from the eastern Sichuan Basin (Cai et al., 2013).
Impetus for this study was provided by a deep delineation well
targeting the Khuff Formation on the east coast of Saudi Arabia.
This well tested sour dry gas at high flow rates from two reservoirs
separated by a vertical distance of < 100 m. The lower (Khuff C) gas
contained 19% nitrogen whereas analyses of samples collected on
different days confirmed that the upper (Khuff B) gas contained
74% nitrogen. To assess the origin of these gases, we measured
carbon isotope ratios of methane, ethane, propane and carbon
dioxide and nitrogen isotope ratios of nitrogen gas.
The results we present here pose several questions relevant to
the assessment of gas exploration risk and deep gas resources. In
particular, what process or collection of processes can be used to
explain extreme chemical and stable isotope variations in gas
reservoirs at similar depths in the same field? How reliable are
P.D. Jenden et al. / Organic Geochemistry 82 (2015) 54–68 55

3. extent of reaction parameters based on hydrogen sulfide
abundance? Can nitrogen and nitrogen isotopes help us under-
stand the fate of hydrogen sulfide formed by TSR? What is the
range of carbon isotope fractionation factors associated with TSR
of methane? Finally, does the formation of base metal sulfides
influence the rate or extent of TSR?
2. Paleozoic natural gas in eastern Saudi Arabia
The Paleozoic stratigraphy and petroleum geology of Saudi
Arabia have been reviewed by Sharland et al. (2001), Pollastro
(2003) and Cantrell et al. (2014). The primary source rock lies at
the base of the Qusaiba Member of the Early Silurian Qalibah
Formation (Fig. 1). High gamma black marine shales of the
Qusaiba Member range up to 50 m in thickness and contain Type
II to Type III (oxidized marine) kerogen (Jones and Stump, 1999).
Total organic carbon in the source rock averages 3–5% by weight
but can reach up to 20%. Maturity modeling suggests that oil
generation began as early as the Late Permian, wet gas was gener-
ated from the Late Jurassic to Cretaceous and dry gas during the
Tertiary (Pollastro, 2003; Cantrell et al., 2014).
The principal Paleozoic reservoirs along the east coast of Saudi
Arabia and in the offshore occur in Late Permian to Early Triassic
shallow marine carbonates of the Khuff Formation (Fig. 1). Gas is
also found in transgressive sandstones of the Basal Khuff Clastics,
in glacio-fluvial and aeolian sandstones of the Late Carboniferous
to Early Permian Unayzah Formation and in fluvial to marginal
marine sandstones of the Devonian Jauf and Jubah formations. In
the western part of the study area, more than 1500 m of
Devonian and Silurian rocks have been eroded over a broad
north-trending mid-Carboniferous high known as the Al-Batin
Arch (Faqira et al., 2009). As Unayzah Formation rocks are absent
in the same region, the arch may have remained topographically
high well into the Permian.
Large volumes of Paleozoic gas are trapped over north-trending
basement highs that developed during the mid-Carboniferous.
Mid-Carboniferous uplift may have been related to collision of
Gondwana and Eurasia (the Hercynian Orogeny of Europe) or to
accelerated subduction beneath the volcanic arc that had devel-
oped northeast of the Arabian plate (Sharland et al., 2001;
Cantrell et al., 2014). Trap development for the Khuff Formation
occurred primarily during the Late Cretaceous when rapid opening
of the Atlantic Ocean induced plate-wide compressional folding
and ophiolite obduction along the NeoTethys margin (Sharland
et al., 2001). Further structuring took place in the Early Miocene
when the NeoTethys Sea closed along the Zagros suture. At sites
where the Infracambrian Hormuz salt was thick enough to flow,
traps formed over salt pillows. The Paleozoic section is generally
well sealed by shales of the Early Triassic Sudair Formation.
Bedded anhydrites represent important intraformational seals
within the Khuff and isolate the Khuff from the underlying section.
Sandstone reservoirs of the Unayzah, Jauf and Jubah formations are
sealed by interbedded shales and siltstones.
3. Samples and analytical methods
The present study addresses data from just over 50 natural gas
samples collected from exploration or delineation wells drilled
between 1997 and 2013 (Fig. 2). Reservoir depths and tempera-
tures range from 3000 m to > 5200 m and from 100 °C to
> 150 °C. Most samples are from Khuff reservoirs but pre-Khuff
(Jauf, Jubah and Unayzah; Fig. 1) reservoirs are also represented.
Samples are all non-associated gas (i.e., no oil phase present in
the reservoir). Condensate/gas ratios do not exceed 10 bbl/MMscf
(5.6 Â 10À5
m3
/m3
).
Natural gases were collected primarily from test separators and
sampled directly into evacuated steel or titanium vessels. Sampling
pressures and temperatures ranged from 0.02–8.3 MPa (gauge)
and 3–56 °C.
3.1. Gas compositions
Chemical compositions were normally analyzed within days of
collection. C1–C10 hydrocarbons, carbon dioxide and hydrogen sul-
fide were measured on an HP 5890 Series II gas chromatograph
equipped with a 0.5 ml sample loop maintained at 150 °C, a
9.1 m  3.18 mm (30 ft  1/8 in) stainless steel column packed
with 30% DC200 on 80/100 mesh Chromosorb PAW and thermal
conductivity and flame ionization detectors placed in series.
Helium carrier gas was maintained at a flow rate of 30 ml/min
and oven temperature programmed from 40–180 °C. Oxygen,
nitrogen and methane were analyzed on a second HP 5890 Series
II gas chromatograph equipped with a 0.5 ml sample loop main-
tained at 150 °C, a 0.53 m  3.18 mm (21 in  1/8 in) stainless
steel column packed with 45/60 mesh 13X molecular sieve and a
thermal conductivity detector. Helium carrier gas was supplied at
20 ml/min and oven temperature was held isothermal at 40 °C.
Fig. 1. Paleozoic stratigraphic column showing the Qusaiba ‘‘hot shale’’ source rock
(flag) and principal gas reservoirs of the Saudi Arabian Gulf coast (circles with teeth;
simplified from Cantrell et al., 2014).
56 P.D. Jenden et al. / Organic Geochemistry 82 (2015) 54–68

4. Nitrogen was corrected for the presence of traces of oxygen
using the area ratio of nitrogen to oxygen peaks measured on air.
One or more standards were used to convert peak areas to molar
quantities. Where samples were collected in titanium vessels,
molar abundances of each species were normalized to 100%.
Where samples were collected in steel vessels, hydrogen sulfide
was set equal to the value measured in the field (using Tutwiler
titration, gas adsorption tubes, or at ppm concentrations, gas moni-
tors) and the remaining components normalized to 100 – %H2S.
3.2. Carbon isotope ratios
Individual gas components were separated on an Agilent 6890
gas chromatograph equipped with a 100 ll sample loop (operated
at room temperature and pressures from 0 to 200 kPa absolute), a
split injector maintained at 250 °C, a 30 m  0.32 mm Agilent GSQ
PLOT column, temperature programming from 35–240 °C and He
carrier gas at a constant flow of 2.6 ml/min. The effluent was
passed to a Finnigan GCC III combustion interface (CuO–Ni–Pt
Fig. 2. Location of gas wells sampled in this study (solid circles). Most wells were tested from Permian Khuff reservoirs but gases from older Unayzah, Jubah and Jauf
reservoirs were also collected. Mesozoic oil fields are shown for reference.
P.D. Jenden et al. / Organic Geochemistry 82 (2015) 54–68 57

5. furnace at 1000 °C; Cu furnace at 650 °C) coupled to a Finnigan
MAT Delta Plus or Thermo Scientific Delta V Advantage isotope
ratio mass spectrometer.
13
C/12
C measurements were scaled by analyzing pulses of
reference carbon dioxide calibrated against the NBS-19 and
LSVEC carbonate standards and are reported in delta notation rela-
tive to the VPDB international reporting standard. To minimize
accuracy problems, data were compiled only for components
within 3 V of the reference gas peak height measured on the m/z
44 cup. Any slight dependence of d13
C on signal intensity was
removed by applying a linearity correction determined for each
compound using data for replicate analyses compiled over several
months. Short term reproducibilities of ± 0.2‰ for the hydrocarbon
gases and ± 0.2–0.4‰ for carbon dioxide have been estimated by
pooling the standard deviations of multiple analyses. Analyses of
a natural gas working standard in use since 1998 suggest that
the long term reproducibility for the hydrocarbon gases is ± 0.5‰
(1 standard deviation).
3.3. Nitrogen isotope ratios
Nitrogen isotope ratios of nitrogen gas were obtained using the
equipment described above for carbon isotopes. To increase
separation between nitrogen and methane, liquid nitrogen was
used to drop the initial oven temperature to À30 °C. The combus-
tion and reduction ovens were maintained at 1000 °C and 650 °C
and a liquid nitrogen trap was placed between the GCC III and
the mass spectrometer to remove traces of carbon dioxide that
would give an interfering peak at mass 28.
15
N/14
N measurements are reported in delta notation relative to
atmospheric nitrogen and were calibrated using a standard of
Dhahran air diluted to 7% in ultrapure He. Data were compiled only
for runs with nitrogen peak heights within 3 V of the reference gas
peak height as measured on the m/z 28 cup. Corrections were
applied to remove a slight dependence of d15
N on peak height
and for a small air blank. Pooled standard deviations of replicate
runs indicate a short-term reproducibility of ± 0.12‰ (> 200
degrees of freedom). Analyses of check standards in use for the last
five years suggest a long term reproducibility of ± 0.25‰ (1
standard deviation).
3.4. Petrology
Core samples for petrographic examination were impregnated
with blue resin and then made into polished thin section.
Mineralogy and primary and diagenetic fabrics were determined
for each sample using a Meiji 9000 microscope fitted with an
Infinity 1.5 camera. SEM examination was undertaken on carbon
coated polished sections using a Philips XL 30 SEM with
tungsten filament at an accelerating voltage of 20 kV, and 8 nA
beam current for backscattered electron microscopy (BSEM).
Energy dispersive secondary X-ray analysis (EDAX) provided
quantitative compositional analysis of carbonate, sulfate and
sulfide minerals.
Table 1
Chemical and stable isotopic compositions of selected gases.
Sample Field Well Reservoird
N2 CO2 H2S C1 C2 C3 C4+ d13
C (‰, VPDB) d15
N (‰, air)
Mole% CH4 C2H6 C3H8 CO2 N2
1a
A 1b
KHFB 74.13 4.15 6.22 15.50 0.00 0.00 0.00 À3.0 À14.4 0.4
2 A 1b
KHFB 73.81 4.15 6.48 15.56 0.00 0.00 0.00 À2.8 À14.3 0.5
3a
A 1 KHFC 18.98 3.17 12.23 65.32 0.30 0.00 0.00 À33.9 À29.0 À17.9 0.3
4 A 2 KHFB 28.98 27.35 21.41 21.44 0.11 0.06 0.65 À26.1 À14.2
5 A 2 KHFC 25.14 20.88 41.98 12.00 0.00 0.00 0.00 À17.6 À2.1
6 B 1c
KFAB 25.37 8.68 13.60 52.35 0.00 0.00 0.00 À21.6 À22.2 À2.2
7 B 1c
KFAB 24.93 8.83 14.00 52.24 0.00 0.00 0.00 À22.0 À21.8 À2.1
8 B 1c
KFAB 24.89 8.94 14.00 52.17 0.00 0.00 0.00 À21.9 À22.2
9 C 1 KHFB 33.79 5.74 2.80 57.58 0.09 0.00 0.00 À30.9 À29.0 À11.2 0.3
10 D 1 PKFF 26.98 6.90 0.00 65.76 0.34 0.02 0.00 À31.8 À36.2 À19.1
11 D 1 KHFB 42.86 2.05 10.69 42.85 0.94 0.25 0.36 À33.5 À30.0 À26.7 À12.0
12 E 1 KHFB 10.48 7.02 28.22 49.99 2.51 0.61 1.17 À39.2 À32.9 À30.7 À21.0 À0.9
a
Splits of samples 1 and 3 were charged into isotubes and analyzed by Weatherford Laboratories, Dammam, on 14 September 2013. Sample 1 was reported to have
methane d13
C = À2.8 ‰ (VPDB) and methane dD = À97‰ (VSMOW). Sample 3 was reported to have methane d13
C = À33.9 ‰ (VPDB), ethane d13
C = À29.0‰ (VPDB) and
methane dD = À126‰ (VSMOW).
b
Collected from the same test on different days.
c
Collected from different tests of the same interval over the space of two weeks.
d
KHFB and KHFC refer to the Khuff B and C reservoirs, KFAB to the combined Khuff A and Khuff B reservoirs and PKFF to a pre-Khuff reservoir.
Fig. 3. Methane d13
C plotted against the ratio of C2+ hydrocarbons to methane.
Letter labels distinguish samples collected from different fields. Samples collected
from different wells in the same field are distinguished numerically. Regions for
microbial and thermogenic gases are adapted from Clayton (1991) assuming a d13
C
value of À28‰ for the source rock kerogen. The stippled area illustrates the
distribution of typical Paleozoic gases from northwestern, central and eastern Saudi
Arabia. BKFC = Basal Khuff Clastics.
58 P.D. Jenden et al. / Organic Geochemistry 82 (2015) 54–68

6. 4. Results
Gas fields in this study are distinguished by capital letters and,
where necessary, samples collected from different wells in the
same field are indicated with a numerical suffix. Chemical and
stable isotopic compositions for selected gases from fields A to E
are listed in Table 1. Data for gases from fields F to M are only
illustrated in figures.
4.1. Hydrocarbon gases
Fig. 3, a plot of methane d13
C against the molar ratio of C2+
hydrocarbons to methane, shows that the geochemistry of the
hydrocarbons is consistent with a non-associated thermogenic ori-
gin. Methane d13
C ranges from À40‰ to À29‰, with a few higher
measurements from Khuff reservoirs at fields A and B. C2+/CH4 is
6 0.1. As shown by the stippled area, Paleozoic gases elsewhere
in Saudi Arabia can have methane d13
C as low as À48‰ and C2+/
CH4 as high as 0.4. The relatively high methane d13
C and low C2+
hydrocarbon abundance observed for coastal and offshore
Paleozoic gases is attributed to their advanced maturities.
Because of their low abundances, comparatively few d13
C
measurements were made on the C2+ hydrocarbons. Ethane and
propane d13
C range from À38.9‰ to À23.4‰ and À35.2‰ to
À23.5‰, respectively, and increase with increasing C1/C2 and C1/
C3 (Fig. 4). At similar C1/C2 and C1/C3 abundance ratios, gases from
Basal Khuff Clastics and pre-Khuff reservoirs have more negative
d13
C values than gases from Khuff reservoirs. This is unexpected
because Khuff gases are widely assumed to have migrated from
the pre-Khuff. The difference in Fig. 4 suggests that the composi-
tions of the Khuff and pre-Khuff gases may have been altered
following charging of the Khuff. TSR has affected the chemistry of
many of the Khuff gases, as discussed below, and pre-Khuff reser-
voirs could have received a late charge of high maturity Qusaiba
gas.
4.2. Non-hydrocarbon gases
Non-hydrocarbon components are abundant. Carbon dioxide
concentrations range from below detection to 27% and may be
elevated in both Khuff Formation and pre-Khuff reservoirs.
Hydrogen sulfide concentrations do not exceed 0.7% in Basal
Khuff Clastics and older reservoirs but are typically much higher
in the Khuff. Hydrogen sulfide concentrations as high as 42% have
been measured in the Khuff C at Field A-Well 2 (Table 1, sample 5).
Elevated nitrogen concentrations have been measured not only in
sour Khuff gases (e.g., 74% at Field A; Table 1, samples 1 and 2)
but also in sweet pre-Khuff gases such as the Jauf at Field D
(27%; Table 1, sample 10).
The concentrations of the non-hydrocarbon gases are positively
correlated. In Fig. 5, non-hydrocarbon gas concentrations have
been normalized to methane and plotted on a logarithmic scale
so as to emphasize the relationships over a wide range of concen-
trations. For reference, gases with no detectable H2S have been
Fig. 4. Plots showing relationships between the carbon isotopic compositions and
relative abundances of ethane and propane. BKFC = Basal Khuff Clastics.
Fig. 5. Positive correlations among the non-hydrocarbon components of Khuff
gases suggest that their abundance is controlled by thermochemical sulfate
reduction. Samples with no detectable H2S are plotted along the vertical axis
(H2S/CH4 = 0.001). BKFC = Basal Khuff Clastics.
P.D. Jenden et al. / Organic Geochemistry 82 (2015) 54–68 59

7. plotted along the vertical axis (H2S/CH4 = 0.001). On average, Khuff
reservoirs (solid points) contain higher abundances of non-
hydrocarbon gases than Basal Khuff Clastics and pre-Khuff
reservoirs (half-filled and open points).
As shown in Fig. 6, increasing log(H2S/CH4) in Khuff reservoirs is
accompanied by a decrease in carbon dioxide d13
C from 0‰ to
À28‰. Khuff carbonate rocks typically have d13
C values between
À3‰ and +5‰ (unpublished Saudi Aramco data) so d13
C as low
as À28‰ provides strong evidence for addition of carbon dioxide
derived from TSR of gas and liquid hydrocarbons. Whole oil d13
C
values of Paleozoic oils and gas condensates average À29.2‰ and
generally fall between À31‰ and À27‰ (Abu Ali et al., 1991;
Carrigan et al., 1998; unpublished Saudi Aramco data). Khuff C
gas at Field A-Well 2 (solid circle labeled ‘‘A-2 KHFC’’) and
Unayzah gas from Field J (open circle labeled ‘‘J’’) are conspicuous
outliers discussed in more detail below.
In addition to carbon dioxide d13
C, log(H2S/CH4) shows an
interesting relationship with methane d13
C. Fig. 7 indicates that,
for samples with H2S/CH4 > 0.1, methane d13
C increases with
increasing H2S/CH4. Khuff B gas at Field A-Well 1 (solid circle
labeled ‘‘A-1 KHFB’’), has by far the most 13
C enriched methane
but comparatively modest H2S/CH4. As the reservoir contains
abundant secondary sphalerite and galena, H2S/CH4 may once have
been significantly higher.
4.3. Nitrogen isotope ratios
Fig. 8 shows that d15
N of gases in this study varies from À6‰ to
1‰. Data fall within the range measured for Paleozoic gases
throughout northwestern, central and eastern Saudi Arabia
although the latter show a maximum between À1.5‰ and
À1.0‰ that is absent in the coastal and offshore dataset. Gases
with high nitrogen concentration in Saudi Arabia tend to be
enriched in 15
N but correlations between nitrogen isotope ratios
and nitrogen concentration or N2/CH4 are poor.
4.4. Petrological evidence for TSR in the Khuff Formation of Saudi
Arabia
In the area of study, the Khuff Formation is strongly dolomitized
and characterized by an abundance of anhydrite in a variety of
forms including discrete beds, fracture-fills and coarsely and finely
crystalline, mm to cm sized nodules (Fig. 9A). The nodules,
especially, are partially replaced by calcite which grows as a rim
on the outer edges of anhydrite nodules (Fig. 9B). The replacive
TSR calcite grows as a reaction front into the body of the nodule,
leaving partially corroded fragments of anhydrite within the calcite
(Fig. 9C). The replacive TSR calcite can, in some circumstances,
serve to isolate the remaining anhydrite from the reactive petro-
leum fluid (Bildstein et al., 2001) and thus limit the extent of the
hydrogen sulfide generating reaction. In some wells, sphalerite
Fig. 6. d13
C of carbon dioxide becomes more negative as H2S/CH4 increases, as
would be expected for addition of carbon dioxide from the oxidation of hydrocar-
bons by sulfate. Samples with no detectable H2S are plotted along the vertical axis
(H2S/CH4 = 0.001). In contrast to Paleozoic hydrocarbons, for which d13
C 6 À27‰,
Khuff carbonates typically have À3‰ 6 d13
C 6 5‰. The anomalous A-2 Khuff C
sample was taken very close to the gas–water contact and the test recovered large
volumes of formation water. BKFC = Basal Khuff Clastics.
Fig. 7. d13
C of Khuff methane increases with increasing H2S/CH4. Samples with no
detectable H2S are plotted along the vertical axis (H2S/CH4 = 0.001). BKFC = Basal
Khuff Clastics.
Fig. 8. Histogram of d15
N for gases in this study (heavy stipple) and other Paleozoic
natural gases from northwest, central and eastern Saudi Arabia (light stipple).
60 P.D. Jenden et al. / Organic Geochemistry 82 (2015) 54–68

8. (ZnS; Fig. 9D), galena (PbS) and pyrite (FeS2) are present within the
corroded anhydrite nodules. These minerals grew after the start of
anhydrite replacement by calcite presumably with the sulfide sup-
plied by TSR. Fluorite and quartz are also associated with base
metal sulfide mineralization in fields E, G and K which thus overall
represent a Mississippi Valley Type deposit (Sverjensky, 1986) pre-
sumably localized by the presence of TSR related hydrogen sulfide.
5. Discussion
5.1. Source rock maturities
Gases from Field E are among the lowest maturity samples in
this study (Figs. 3 and 4; Table 1, sample 12). The Khuff B in
Field E produces sour gas with small amounts of condensate.
C2+/CH4 ranges up to 0.1, methane d13
C values cluster between
À40‰ and À39‰ and d13
C values of ethane (À35‰ to À33‰)
and propane (À32‰ to À30‰) are the most negative measured.
The highest maturity gases are more difficult to identify as the
abundance of C2+ hydrocarbons and d13
C of methane, ethane and
propane may have been altered by TSR. Sour Khuff gases with
methane d13
C >À30‰ and extremely low abundances of C2+
hydrocarbons are particularly suspect. If it is assumed that pre-
Khuff reservoirs have been less significantly affected by TSR, then
the most mature thermogenic gases may be from the Jauf
Formation at Field D. These have C2+/CH4 6 0.007, methane d13
C
between À32.0‰ and À31.0‰ and ethane d13
C between À36.2‰
and À36.1‰ (Figs. 3 and 4; Table 1, sample 10).
According to Cantrell et al. (2014; their Figs. 7 and 8), depths to
the base of the Qusaiba Member in the area of study locally exceed
7 km and modeled present day maturities range from a minimum
of 1.7% to more than 3.0% vitrinite reflectance. To place our data
into a maturity context, we have applied the empirical model of
Faber (1987; cf. Whiticar, 1994), which uses d13
C of the C1–C3 gases
from oil prone kerogens to estimate source rock vitrinite reflec-
tance. Fig. 10 shows that ethane and propane data pairs (plotted
as triangles) fit the Faber relationship reasonably well although
the inferred maturities, which range from 0.5% to just under 2% vit-
rinite reflectance, are lower than expected. Ethane and methane
data pairs (plotted as circles) tend to fall above the maturity line
Faber proposed for these gases. Maturities estimated from
methane d13
C range from 1.2% to more than 3% vitrinite reflec-
tance, more in line with expectations.
Why maturities estimated from methane are typically much
higher than those estimated from ethane and propane is unclear.
TSR is an unlikely explanation as several gases with inconsistent
maturity estimates are from Basal Khuff Clastics or pre-Khuff
reservoirs (half-filled or open symbols; Fig. 10). Pre-Khuff reser-
voirs lack anhydrite and are unlikely to have been significantly
altered by TSR. The most extreme examples are Jauf gases from
Field D, noted above, which yield maturities > 3% vitrinite reflec-
tance for methane and 0.7–0.8% vitrinite reflectance for ethane.
Inconsistent maturity estimates could be caused by isotopic roll-
over of ethane and propane as documented in unconventional
shale gases from the U.S. Midcontinent and tight conventional
reservoirs from the Rocky Mountain foothills in Canada
(Zumberge et al., 2012; Tilley and Muehlenbachs, 2013).
‘‘Rollover’’, which refers to the shift from 13
C enrichment to 13
C
depletion as shale gases mature beyond a threshold of roughly
1.5% vitrinite reflectance, might explain why d13
C of ethane and
propane tends to be more negative in pre-Khuff than in Khuff
reservoirs (Fig. 4). Inconsistent maturity estimates might also be
explained if many coastal and offshore Arabian Gulf reservoirs
were originally charged with oil or wet gas and then, sometime
later, with a large volume of high maturity methane.
5.2. TSR altered Khuff gases
Thermochemical sulfate reduction in Khuff gas reservoirs has
been documented in numerous proprietary Saudi Aramco reports
in addition to the published literature (Worden et al., 1995, 2000,
2004; Worden and Smalley, 1996; Ahmed et al., 2008).
SaudiAramco:Public
1 cm5 mm
500 µm 500 µm
Dolomite matrix
ParƟally-replaced
anhydrite nodules
Sulfur
Dolomite matrix
Remaining anhydrite
TSR calcite
Dolomite and
calcite matrix
Remaining
anhydrite
TSR calcite
and parƟally
replaced
anhydrite
A B
C D
Dolomite
matrix
TSR calcite
and parƟally
replaced
anhydrite
Sphalerite
(ZnS)
Fig. 9. Petrology of TSR and related fabrics, Khuff Formation, Saudi Arabia. (A) Image of slabbed core showing the abundance of tiny anhydrite nodules, in this case partially
replaced by TSR calcite, and elemental sulfur. (B) Image of polished rock sample showing TSR calcite replacement rim surrounding remaining anhydrite nodule. (C)
Backscattered electron microscope image of details of TSR calcite reaction front. TSR calcite contains numerous corroded relics of the original anhydrite. (D) Backscattered
electron microscope image of details of base metal mineralization that post-dated the onset of TSR with sphalerite (zinc sulfide) present within a corroded anhydrite nodule.
Galena (lead sulfide) and pyrite are also commonly associated with mineralisation, as well as fluorite and quartz.
P.D. Jenden et al. / Organic Geochemistry 82 (2015) 54–68 61

9. Correlations between log(CO2/CH4) log(N2/CH4) and log(H2S/CH4),
noted in Fig. 5, suggest that non-hydrocarbon gas abundances are
controlled by TSR. Carbon dioxide d13
C decreases as H2S/CH4
increases, consistent with hydrocarbon oxidation by TSR (Fig. 6).
That methane is an important reactant is suggested by the increase
in methane d13
C for H2S/CH4 above 0.1 (Fig. 7). Petrographic
evidence from Saudi Aramco fields includes the replacement of
anhydrite by secondary calcite (Fig. 9C), and the presence of
secondary sulfide minerals, most commonly pyrite but, in Khuff
reservoirs at fields A, E, G and K, also sphalerite (Fig. 9D) and
galena. Secondary calcite has d13
C as low as À20‰ (unpublished
Saudi Aramco data), indicating oxidation of natural gas or
hydrocarbon liquids. In addition, the sulfur isotope composition
of the hydrogen sulfide and secondary sulfides is commonly only
a few permil lighter than Permo-Triassic sulfate (Carrigan et al.,
1998; unpublished Saudi Aramco data).
Data from fields A and B (Table 1, samples 1–8) are particularly
noteworthy. Khuff reservoirs in these fields contain abundant
anhydrite. Temperatures estimated from downhole sampling tools
and drill stem tests range from 151 °C to 157 °C, well in excess of
the 140 °C minimum reported to be required for TSR of dry gases
(Worden et al., 1995). Methane d13
C values range from À33.9‰
to À2.8‰. In 95% of the gases we have analyzed from Paleozoic
reservoirs in northwestern, central and eastern Saudi Arabia,
methane d13
C is less than À35‰. Methane d13
C generally increases
with increasing source rock maturity so dry gases generated at
high maturities may slightly exceed this range. With methane
d13
C as high as À2.8‰, Khuff B gas from Field A-Well 1 is clearly
anomalous.
Stable carbon isotope compositions of natural gases can, in
some circumstances, be altered by cylinder leakage and bacterial
oxidation. Problems with cylinder leakage have been encountered
very infrequently in our laboratory but in one instance we
observed a 20‰ increase in methane d13
C when a cylinder sampled
at 0.35 MPa (gauge) dropped to atmospheric pressure over the
course of six weeks. Welhan (1988) reported d13
C of À0.6‰ for
methane recovered from a warm geothermal spring in the Salton
Sea, California, and attributed the unusual 13
C enrichment to bac-
terial oxidation. Bacteria might oxidize a commercial gas sample
if it were heavily contaminated by air.
Neither of these processes can explain the Khuff B data.
Significant atmospheric contamination is unlikely as the Khuff B
gas flowed at a high test rate and samples were collected from a
field separator at 2.5 MPa. Leakage is unlikely as we analyzed
two samples collected on different days and their methane d13
C
values are within 0.2‰ (Table 1, samples 1 and 2). Most impor-
tantly, the d13
C values we report for Khuff B and Khuff C gases from
Field A-Well 1 have been verified by an independent laboratory
(Table 1, footnote ‘‘a’’).
We interpret the Khuff B gas from Field A-Well 1 to be exten-
sively TSR altered. Khuff B and Khuff C gases from Field A-Well 2
and Khuff A/B gases from Field B have methane d13
C values
between À26.1‰ and À17.6‰ (Table 1, samples 4–8) and appear
less strongly altered. With d13
C = À33.9‰, methane from the
Khuff C reservoir at Field A-Well 1 is only marginally higher than
expected for normal thermogenic gas. The Khuff C gas at Field A-
Well 1 could be either a very high maturity thermogenic gas or a
normal thermogenic gas subjected to modest levels of TSR.
5.3. Nitrogen isotope ratios
d15
N of Saudi Arabian Paleozoic gases varies from À7‰ to +1‰,
a relatively small range compared to that reported for natural
gases elsewhere in the world (À20‰ to 30‰; Prasolov et al.,
1991; Sohns et al., 1994; Gerling et al., 1997; Zhu et al., 2000;
Ballentine and Sherwood-Lollar, 2002; Liu et al., 2012). Late
Permian and younger sedimentary rocks in northwestern, central
and eastern Saudi Arabia were deposited in either passive margin
or foreland basins, so mantle nitrogen (ranging widely but gener-
ally À5‰ ± 4‰; Marty and Zimmerman, 1999; Cartigny, 2005)
and volcanic nitrogen (which may be more enriched in 15
N due
to incorporation of sedimentary volatiles; e.g., Halldórsson et al.,
2013) can be excluded with reasonable confidence. Although
d15
N values are more negative than nitrogen in sedimentary rocks
(generally À3‰ to 12‰; Ader et al., 2006) a sedimentary or
metasedimentary origin seems likely.
Fractionation of nitrogen isotopes during the formation of natu-
ral gas is poorly understood. During burial alteration, organic nitro-
gen is liberated primarily as ammonia and this reportedly occurs
with little or no shift in d15
N (Boudou et al., 2008). However, nitro-
gen can be stored as an ammonium ion substituting for potassium
in clays, micas and feldspars, and substantial equilibrium isotope
fractionations have been established between NH4
+
, NH3 and N2
(Jia, 2006). In addition, recent experiments have demonstrated that
the decomposition of NH3 to N2 may be accompanied by a large
kinetic isotope fractionation (Li et al., 2009). As a result, nitrogen
liberated from sedimentary and metasedimentary rocks is
expected to be depleted in 15
N relative to its organic and mineral
precursors. Consistent with this finding, studies of natural gases
and sedimentary rocks have suggested that d15
N of nitrogen gas
increases with increasing thermal stress (Gerling et al., 1997;
Zhu et al., 2000).
Fig. 11 plots nitrogen d15
N versus methane d13
C for gases in this
study. Notwithstanding the expectation that both parameters are
influenced by thermal stress, no correlation is apparent. Samples
collected more than seven years ago were not analyzed for d15
N
and the absence of data for Field A-Well 2 is particularly regret-
table. The distribution of data for pre-Khuff gases from
-50
-46
-42
-38
-34
-30
-26
-22
-18
-42 -38 -34 -30 -26 -22
13CMethane,Propane(‰,VPDB)
13C Ethane (‰, VPDB)
0.5% Ro
1.0
1.5
2.0
3.0
2.5
0.7
1.3
0.5% Ro
1.0
1.5
2.0
3.0
2.5
0.7
1.3
C1-C2
C2-C3
G
D
B
H
H
E
E D
A-2
KHFC
C
M
L
E
L
L
K K
K
K
G
F
F
Khuff
BKFC
Pre-Khuff
Fig. 10. Plot of methane d13
C (circles) and propane d13
C (triangles) against ethane
d13
C showing the empirical source rock maturity scale of Faber (1987) for Paleozoic
oil prone organic matter. Stippled areas illustrate the distribution of most Saudi
Arabian Paleozoic gases. BKFC = Basal Khuff Clastics. Many gases cannot be plotted
because d13
C of ethane or propane are not available.
62 P.D. Jenden et al. / Organic Geochemistry 82 (2015) 54–68

10. northwestern, central and eastern Saudi Arabia, shown in stipple,
indicates the natural range of d15
N and d13
C values for unaltered
Silurian Qusaiba sourced gas that may have initially charged the
Khuff.
Saudi Arabian gases with unusually high methane d13
C plot well
to the right of the stippled region in Fig. 11 and as indicated by thin
horizontal arrows appear to be altered by TSR. Differences in the
degree of TSR alteration seem particularly plausible for the gases
from fields A and C. These fields are in close proximity and,
notwithstanding large variations in nitrogen content, d15
N values
are quite similar (0.3–0.5‰; Table 1, samples 1–3 and 9). The simi-
larity in d15
N for TSR altered gases from fields B and M is presum-
ably coincidental as these wells are located 100 km apart. Despite
its occurrence in a clastic reservoir where access to sulfate is lim-
ited, Unayzah gas from Field J may be slightly altered by TSR. This
is suggested not only by unexpectedly high methane d13
C
(À34.0‰) but by a very low abundance of higher hydrocarbons
(C2+/CH4 = 0.0004) and the presence of 0.4% hydrogen sulfide and
8% carbon dioxide, the latter with d13
C = À28‰ (Fig. 6).
5.4. Modeling the effects of TSR
The chemical and stable isotope evolution of a dry gas being
altered by TSR has been modeled. Where f is the fraction of initial
methane destroyed, N refers to the molar N2/CH4 ratio and the sub-
script o refers to original conditions prior to TSR,
N ¼ No=ð1 À fÞ: ð1Þ
The stable carbon isotope composition of the remaining
methane, d, can be calculated from the Rayleigh distillation equa-
tion for any value of f (e.g., Whiticar, 1994). Given an original stable
isotope composition, do, and the stable isotope fractionation factor
(a) associated with methane destruction,
d ¼ ð1000 þ doÞð1 À fÞ
aÀ1
À 1000: ð2Þ
Fig. 12 shows model calculations for an original gas with N2/CH4
of 0.05–0.50 (4.8–33% nitrogen on an acid-gas-free basis) and
methane d13
C equal to -37‰. Reaction progress, represented by f,
is plotted on the abscissa. Panel A shows that as the extent of reac-
tion increases, so does d13
C of the methane remaining in the
reservoir. The rate of increase in d13
C is dependent upon the instan-
taneous isotope fractionation factor associated with methane
removal,
a ¼ ½1000 þ d13
CðCH4 removedÞŠ=½1000 þ d13
CðCH4 residualÞŠ:
Values for a here have been broadly constrained by published
experimental data and field measurements. Kiyosu et al. (1990)
carried out open system experiments with methane and solid cal-
cium sulfate or calcium sulfate-hematite mixtures at 600–900 °C
and calculated 0.983 6 a 6 0.988. Significant reaction rates could
not be obtained below 600 °C, however, and scatter prevents
extrapolation of their results to lower temperatures. Pan et al.
(2006) investigated the reaction of wet natural gas and magnesium
sulfate at 350 °C in the presence of water. They could not calculate
a for methane because methane was generated in their experi-
ments by TSR of the C2 to C5 hydrocarbons, but they determined
a = 0.988–0.989 for ethane. As the isotopic discrimination for
methane is expected to be greater than ethane, a = 0.989 may be
a good upper limit for TSR of methane. The lower limit is difficult
to determine from the data of Pan et al. (2006) as temperatures
of commercial reservoirs are all well below 350 °C and a typically
decreases as temperature declines. Using a completely different
approach, Cai et al. (2013) estimated a for methane from published
data for dry, sour natural gases from the Sichuan Basin, China.
Plotting methane d13
C against an extent of reaction parameter
based on H2S abundance, they fitted a = 0.984.
To illustrate a wide range of possible results, Panel A of Fig. 12
shows model calculations for 0.98 6 a 6 0.99. An increase in
methane d13
C from À37‰ to values near À3‰, as observed in
the Khuff B at Field A-Well 1, would require the removal of 82–
97% of the original methane. Fig. 12, Panel B shows that removal
of methane by TSR is accompanied by an increase in the molar
ratio of nitrogen to methane. Given a starting gas with 0.05 < N2/
CH4 < 0.50, TSR alteration to N2/CH4 = 4.8, similar to the Khuff B
at Field A-Well 1, would require the removal of 90–99% of the
original methane. Unless the reservoir is recharged with fresh
hydrocarbon gas, extensive TSR will produce a substantial loss of
reserves (Fig. 12, Panel C). For reference, on an acid-gas-free basis,
the reserves remaining at f = 1 consist entirely of nitrogen gas.
5.5. Application to coastal and offshore gases
To apply the TSR model to Khuff gases from the east coast of
Saudi Arabia, a proxy variable is required to replace the extent of
reaction parameter f. The most obvious candidate is the ‘‘Gas
Souring Index’’, or GSI, defined by Worden et al. (1995) as H2S/
(H2S + CH4). If the precursor gas is sweet, one mole of hydrogen
sulfide is produced for every mole of methane consumed, and no
hydrogen sulfide is removed from the gas phase, then GSI and
the extent of reaction, f, are equal.2
Hydrogen sulfide is highly reac-
tive gas, however, and GSI is unsuitable as an extent of reaction
parameter in fields where extensive sulfide mineralization has been
observed. As an alternative, we have investigated the molar ratio of
nitrogen to methane. Unlike hydrogen sulfide, nitrogen is inert.
Given the ratio of the precursor gas, N2/CH4 can be used to calculate
the extent of methane reaction. In addition, our TSR model predicts
that when methane d13
C is plotted against log(N2/CH4), samples that
have the same thermogenic precursor and differ only in the extent of
TSR will plot along a nearly straight line with a slope proportional to
1 À a.
A plot of methane d13
C against log(N2/CH4) is shown Fig. 13.
Most samples fall within the stippled area defined by more than
Fig. 11. Cross plot of nitrogen d15
N versus methane d13
C. Stippled area indicates the
distribution of pre-Khuff gases from northwest, central and eastern Saudi Arabia.
Removal of methane by TSR would cause methane d13
C of the residual gas to
increase without affecting nitrogen d15
N.
2
If we begin with n moles of methane, then after TSR has consumed fraction f
(0 6 f 6 1), n*(1 À f) moles of methane remain and n*f moles of hydrogen sulfide have
been produced. GSI = H2S/[H2S + CH4] = n*f/[n*f + n*(1 À f)] = f.
P.D. Jenden et al. / Organic Geochemistry 82 (2015) 54–68 63

11. 300 pre-Khuff gases from central, northwestern and eastern Saudi
Arabia. Because of limited sulfate availability, pre-Khuff gases are
unlikely to have experienced extensive thermochemical sulfate
reduction. Pre-Khuff gases generally have methane d13
C < À35‰,
and none have N2/CH4 > 0.5. Pre-Khuff gases show a very rough
positive correlation between methane d13
C and N2/CH4. This could
reflect either increasing Qusaiba source rock maturity or possibly
addition of nitrogen-rich volatiles from metasedimentary base-
ment rocks. The most extreme pre-Khuff gas compositions are
observed at Field D. Evidence for TSR is lacking in pre-Khuff sam-
ples from Field D yet methane d13
C falls between À32‰ and
À31‰ and N2/CH4 between 0.41 and 0.44.
Khuff C gas from Field A-Well 1, which may be slightly altered
by TSR, plots within the stippled pre-Khuff area in Fig. 13. The
remaining gases from fields A and B have been interpreted as
extensively TSR altered. They plot well outside the stippled area
and are anomalously enriched in both 13
C (À26.1‰ 6 methane
d13
C 6 À2.8‰) and nitrogen (0.47 6 N2/CH4 6 4.7). Khuff gases
from fields C, D, G and M plot outside the stippled area but are less
enriched in 13
C (À33.5‰ 6 methane d13
C 6 À29.4‰) and nitrogen
(0.07 6 N2/CH4 6 1.00). They could be altered but, if so, TSR cannot
have progressed as far.
5.5.1. TSR at Field A
Fig. 13 presents three hypothetical TSR models constructed to
fit the average of the Khuff B points from Field A-Well 1 (‘‘A-1
KHFB’’; Table 1, samples 1 and 2). The slopes of the reaction vectors
reflect the use of different fractionation factors. Possible precursor
gases are indicated by open diamonds.
Model 1 is summarized schematically in Fig. 14. The Khuff B and
Khuff C reservoirs in Field A-Well 1 are separated vertically by
< 100 m so the model assumes that they were charged with the
same thermogenic gas precursor and differ only in the extent of
TSR. Forcing the Model 1 reaction vector to pass through the point
labeled ‘‘A-1 KHFC’’ (Table 1, sample 3) fixes a = 0.989, at the high
end of the range illustrated in Fig. 12. As abundant metal sulfides
are not recognized in the Khuff C reservoir, the extent of reaction
in the Khuff C gas was set equal to its GSI of 0.158 (15.8% methane
destruction). From this, we calculated N2/CH4 = 0.245 and methane
d13
C = À35.8‰ for the unaltered thermogenic precursor. In order to
generate a gas with N2/CH4 = 4.76 and methane d13
C = À2.9‰, the
average of the Khuff B samples, 94.9% of the methane in the precur-
sor would have to be destroyed. There is a large discrepancy
between our modeled GSI of 0.949 and the measured GSI of
0.290. As noted earlier, however, the Khuff B reservoir contains
Fig. 12. Modeled changes in the chemical and stable isotope composition of a dry natural gas undergoing TSR. Calculations assume an original gas with methane d13
C = À37‰
and 0.05 6 N2/CH4 6 0.50. a is the instantaneous isotope fractionation factor (see text).
64 P.D. Jenden et al. / Organic Geochemistry 82 (2015) 54–68

12. abundant sphalerite and galena. The GSI discrepancy can be recon-
ciled if we assume that 98% of the Khuff B hydrogen sulfide was
precipitated as sulfide minerals.
Model 2 assumes that the reaction vector passes through the
Khuff B point from Field C (‘‘C-1’’; Table 1, sample 9). This is a
plausible alternative to Model 1 because, as discussed in connec-
tion with Fig. 11, fields A and C are in close proximity and their
gases have very similar nitrogen isotope compositions.
Constraining the reaction vector to pass through point ‘‘C-1’’ yields
a = 0.986. As the Khuff B reservoir at Field C is not known to host
abundant secondary sulfides, we assumed f = GSI = 0.046 and cal-
culated an unaltered precursor with N2/CH4 = 0.560 and methane
d13
C = À31.5‰. According to Model 2, gas similar to the Khuff B
at Field A-Well 1 would require 88% methane destruction. As
before, the discrepancy between the calculated extent of reaction
and the GSI of the Khuff B gas from Field A-Well 1 may be recon-
ciled by assuming that a large proportion of the H2S produced by
TSR was removed by precipitation of sphalerite and galena.
Model 3 uses a fractionation factor of 0.980, the low end of the
range illustrated in Fig. 12. Precursor methane d13
C is assumed to
be À37‰, near the average of coastal and offshore gases plotting
within the stippled area of Fig. 13. This fixes N2/CH4 = 0.836.
According to Model 3, just over 82% methane destruction would
be required to generate Khuff B gas at Field A-Well 1.
Calculations are not particularly sensitive to the composition of
the precursor gas. Varying the precursor methane d13
C from
À31‰ to À40‰, the maximum and minimum values measured
for pre-Khuff gases in this study, shifts the estimate of methane
destruction from 76–85%.
Khuff B and Khuff C gases from Field A-Well 2 (Table 1, samples
4 and 5) plot close to the reaction vector for Model 3 but their
chemical compositions may not be representative. Recovered from
a flank location, Well 2 gases flowed at low rates, were sampled at
pressures of 0.15–0.20 MPa and were accompanied by large vol-
umes of formation water. Khuff C gas is extremely dry but Khuff
B gas contained traces of C6–C7 hydrocarbons, suggesting minor
contamination. Based on their methane d13
C values (À26.1‰ and
À17.6‰), Model 3 predicts between 43% and 63% methane
destruction. The corresponding GSI values (0.50 and 0.78) suggest
slightly higher extents of reaction but, as hydrogen sulfide is more
soluble than methane (Cai et al., 2013), GSI may have been influ-
enced by gas exsolving from co-produced formation water.
Fig. 13. Plot of methane d13
C against N2/CH4. Stippled area indicates the
distribution of pre-Khuff gases from northwest, central and eastern Saudi Arabia.
The numbered arrows illustrate hypothetical TSR alteration pathways passing
through Khuff B gas from Field A-Well 1 (points labeled ‘‘A-1 KHFB’’) or Khuff A/B
gas from Field B. Thermogenic precursor gases are indicated by open diamonds. For
each reaction pathway, a twofold increase in N2/CH4 corresponds to 50% methane
destruction and a ten-fold increase to 90% methane destruction. Fractionation
factors for pathways 1–5 are 0.989, 0.986, 0.980, 0.990 and 0.980, respectively.
BKFC = Basal Khuff Clastics.
Fig. 14. Schematic of TSR Model 1. Model 1 assumes that the Khuff B and Khuff C reservoirs in Field A-Well 1 were charged with the same sweet dry gas and differ only in the
extent of subsequent TSR. The steps in the development of the model are as follows. (1) Set the extent of reaction for the Khuff C gas equal to its gas souring index (no Khuff C
sulfide mineralization). (2) Use Eq. (1) to calculate N2/CH4 for the original gas charge (No = 0.245) and the extent of reaction for the Khuff B gas (fKHFB = 1 À No/NKHFB = 0.949).
(3) Rearrange Eq. (2) and use the extents of reaction and isotopic compositions for the Khuff B and Khuff C gases to obtain a = 0.989. (4) From Eq. (2), the extent of reaction and
methane carbon isotope ratio for either the Khuff B or Khuff C gas, and a, calculate the isotopic composition of the original gas charge (do = À35.8‰). (5) Calculate p, the
fraction of Khuff B H2S precipitated as sulfide minerals. Where G is the gas souring index, p = (1 À GKHFB/fKHFB)/(1 À GKHFB) = 0.978.
P.D. Jenden et al. / Organic Geochemistry 82 (2015) 54–68 65

13. Exsolution of carbon dioxide and hydrogen sulfide from formation
water may explain why Khuff C gas from Field A-Well 2 is a con-
spicuous outlier on our plot of carbon dioxide d13
C vs. log(H2S/
CH4) (Fig. 6).
5.5.2. TSR at Field B
The Khuff A/B reservoir at Field B flowed gas at high test rates
and was sampled three times over the space of two weeks at pres-
sures of 2–5 MPa. Methane d13
C and N2/CH4 for the samples fall
within remarkably narrow ranges of À22.0‰ to À21.6‰ and
0.477 to 0.485 (Table 1, samples 6–8). Models 4 and 5, fitted to
the average Field B gas composition in Fig. 13, assume a between
0.990 and 0.980 and a precursor methane d13
C of À37‰
(0.100 6 precursor N2/CH4 6 0.219). According to these models,
generating a gas similar to that tested from the Khuff A/B reservoir
at Field B would require the destruction of 54–79% of the precursor
methane. The calculated extents of reaction are considerably
higher than suggested by GSI values of the Field B gases, which
cluster tightly about an average of 0.210.
Why model calculations and measured GSI values disagree for
the Field B gases is not clear. If we assume that the GSI values
reflect the true extent of reaction and 0.980 6 a 6 0.990, then the
precursor methane d13
C would have to fall between À26‰ and
À24‰. This is 5–7‰ higher than the most 13
C enriched pre-Khuff
gas in Saudi Arabia. An alternative explanation is that we have
underestimated the fractionation factor. If we assume that the
extent of reaction is equal to the average GSI and that the precursor
methane d13
C was À31.0‰ (the highest known pre-Khuff value),
then a would be 0.960. This is at least twice the fractionation we
believe to be justified by field data and laboratory experiments. A
third possibility is that GSI underestimates the extent of reaction
because hydrogen sulfide has been lost from the system.
Although the Khuff A/B reservoir is not known to host abundant
secondary sulfide minerals, H2S might have dissolved in the water
leg or reacted to form species of intermediate oxidation state such
as elemental sulfur or polysulfides.
5.5.3. Origin of Khuff gas at Field D
Khuff gases from Field D and the precursor gas used in TSR
Model 3 are interesting because although N2/CH4 is comparatively
high, methane is not particularly enriched in 13
C. Khuff gases from
Field D were collected from two wells that flowed gas at high rates
and have 0.8 6 N2/CH4 6 1.0 and methane d13
C = -33.5‰ (e.g.,
Table 1, sample 11). The fact that they plot near the origin of the
Model 3 reaction vector in Fig. 13 is coincidental as fields D and
A are located roughly 80 km apart and do not share a common
migration pathway. TSR cannot have destroyed significant
amounts of methane in the Khuff reservoir at Field D because
methane d13
C falls within the range of pre-Khuff gases. In addition,
whereas fields A and B are extremely dry, C2+ hydrocarbons in the
Khuff at Field D are comparatively abundant (0.034 < C2+/
C1 < 0.037).
It is possible that the stippled pre-Khuff region in Fig. 13 under-
estimates the range of N2/CH4 in gases unaltered by TSR.
Alternatively, gases with elevated nitrogen abundances and little
or no 13
C enrichment might be produced by mixing of TSR altered
and unaltered gases. Fig. 15 illustrates mixing lines constructed for
TSR altered Khuff B gas from Field A-Well 1 and low nitrogen end
members similar to Basal Khuff Clastics and pre-Khuff gases from
fields G and H. The mixing lines are concave upward and bound
Khuff data with the most negative methane d13
C values. Mixing
could be caused either by addition of pre-Khuff gas to a TSR altered
Khuff accumulation or by updip migration of TSR altered gas into a
shallower, unaltered Khuff accumulation. Fig. 15 suggests that
mixing could be important not only at Field D but in other fields
such E and F.
5.6. Differences between Khuff B and Khuff C gases at Field A-Well 1
Why TSR appears to have altered Khuff B gas in Well 1 far more
extensively than Khuff C gas in Well 1 is puzzling. Among the most
important factors controlling TSR are temperature and the abun-
dance and crystal size of anhydrite in the reservoir rock. As noted
earlier, Khuff B and Khuff C reservoir temperatures exceed the
threshold thought necessary for TSR of methane. They differ by
no more than 3–4 °C, however, and the Khuff B, which is more
extensively altered, is cooler. Anhydrite occurs as pore-filling
cements and nodules and ranges from 0–20% by volume in both
reservoirs. Petrographic data from the Khuff Formation in Abu
Dhabi indicate that fine, 10–30 lm, anhydrite crystals react much
more readily than coarse, 50–200 lm crystals (Worden et al.,
2000). Large, poikilotopic anhydrite crystals have been reported
in the Khuff C, but whether finely crystalline anhydrite is more
abundant in the Khuff B is unknown. Other factors known to
influence TSR rates are hydrogen sulfide abundance, which may
catalyze the reaction by forming elemental sulfur or low molecular
weight organic sulfides and the abundance of Mg in the formation
water (Zhang et al., 2008; Ma et al., 2008; Lu et al., 2011). Whether
either of these might favor the Khuff B over the Khuff C is not clear.
We offer three explanations for the differing extent of reaction.
5.6.1. Early oil charge in the Khuff B
Faint hydrocarbon staining, odor and fluorescence have been
reported in the Khuff B but not in the Khuff C. Pyrolysis
experiments show that sulfate reduction is enhanced by the pres-
ence of organic sulfides, such as 1-pentanethiol, which can form by
reaction of light hydrocarbons with hydrogen sulfide (Amrani
et al., 2008; Zhang et al., 2008). Although Khuff B gas is now extre-
mely dry, the reservoir may originally have been charged with oil
or gas-condensate. If so, TSR could have begun earlier than in the
Khuff C and the rate of methane oxidation possibly enhanced.
5.6.2. Sulfide mineralization in the Khuff B
As noted earlier, extensive sulfide mineralization is observed in
the Khuff B but not in the Khuff C (R.F. Lindsay, personal
Fig. 15. Plot of methane d13
C against N2/CH4 illustrating the effects of mixing
between Khuff B gas from Field A-Well 1, and low nitrogen, unaltered end members
similar to those in pre-Khuff reservoirs from fields G and H. Dotted tie lines indicate
mixing proportions. BKFC = Basal Khuff Clastics.
66 P.D. Jenden et al. / Organic Geochemistry 82 (2015) 54–68

14. communication, 30 April 2011). Invasion of hot mineralizing fluids
may have produced a transient increase in reservoir temperature.
Alternatively, precipitation of sulfides may have enhanced TSR by
removing an important reaction product and increasing the
relative concentration of methane in the residual gas. Porosity in
the Khuff B appears to be enhanced by grain dissolution that could
be associated with sulfide mineralization.
5.6.3. Mixing with fresh gas in the Khuff C
The apparent extent of TSR in the Khuff C may have been dimin-
ished by mixing with unaltered methane rich gas (Fig. 15). Because
on-going TSR would destroy evidence for mixing, recharging must
have been very recent or the rate of TSR must be considerably
slower now than in the past. Basin models suggest that reservoir
temperatures in Field A reached a maximum around 35 Ma and
have cooled by approximately 5 °C since then. Such a small change
seems unlikely to have produced an appreciable effect on reaction
rates. Another possibility is that TSR has been shut down by the
development of calcite reaction rims around fine grained anhydrite
nodules (Worden et al., 2000).
6. Conclusions
Deep, dry Khuff gas reservoirs from eastern Saudi Arabia are
characterized by 0.06 < N2/CH4 < 4.8, À39.6‰ < methane d13
C <
À2.8‰ and À28.4‰ < carbon dioxide d13
C < À0.1‰. Broad cor-
relations between each of these parameters and H2S/CH4 suggest
that methane has been destroyed by thermochemical sulfate
reduction. Chemical compositions and methane carbon isotope
compositions have been fitted with simple Rayleigh fractionation
models using initial N2/CH4 between 0.10 and 0.84, initial methane
d13
C between À40‰ and À31‰ and constant isotopic fractionation
factors between 0.98 and 0.99. According to these models, the
highest measured N2/CH4 and methane d13
C values require the
destruction of 76–95% of the original methane charge.
Data from Field A in our study indicate that the extent of TSR
may differ markedly in Khuff reservoirs at similar depths and pre-
sent day temperatures. The reason for these differences is unclear.
The Khuff B reservoir at Field A apparently received an early charge
of liquids, which could have enhanced reaction rates. It has also
suffered extensive sulfide mineralization. Mineralization may have
promoted TSR either by the invasion of hot mineralizing fluids or
by the precipitation of hydrogen sulfide, which would increase
the relative abundance of methane in the residual gas. Lastly, the
apparent extent of reaction in the Khuff C reservoir may have been
diminished by mixing with fresh, unaltered gas.
Acknowledgments
The authors would like to thank the Hydrocarbon Phase
Behavior Unit at the Saudi Aramco EXPEC Advanced Research
Center for carrying out field sampling and providing chemical
analyses for all gas samples analyzed in this study. We are
indebted to William J. Carrigan and Peter J. Jones, whose propri-
etary studies contributed so much to our understanding of TSR in
Saudi Arabian oil fields and to Owaidh S. Al-Harthi, who measured
the stable isotope ratios reported here. Detailed recommendations
from two anonymous reviewers improved the organization, con-
tent and clarity of this paper. Special thanks go to Saudi Arabian
Oil company (Saudi Aramco) and the Ministry of Petroleum and
Mineral Resources for permission to publish this study.
Associate Editor—Andrew Murray
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