Impacts of Thermochemical Sulfate Reduction, Oil Cracking, and Gas

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Impacts of TSR, oil cracking and gas mixing on petroleum fluid phase in the Tazhong area, Tarim Basin, China Zhiyao Zhang, Yijie Zhang, Guangyou Zhu, Linxian Chi, and Jianfa Han Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.8b03931 • Publication Date (Web): 22 Jan 2019 Downloaded from http://pubs.acs.org on January 28, 2019

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Energy & Fuels

Impacts of TSR, oil cracking and gas mixing on petroleum fluid phase in the Tazhong area, Tarim Basin, China

Zhiyao Zhanga Yijie Zhanga Guangyou Zhua,* Linxian Chia Jianfa Hanb

a

Research Institute of Petroleum Exploration and Development, PetroChina, Beijing 100083,

China b

Research Institute of Petroleum Exploration and Development, Tarim Oilfield Company,

PetroChina, Korla 841000, China

* Corresponding author. Tel.: +86 10 8359 2318;

+86 18601309981

E-mail address: [email protected] (G.Y. Zhu)

ACS Paragon Plus Environment

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1

Abstract: Petroleum fluids in the deep Ordovician reservoirs of the Tarim Basin vary in

2

phase and molecular composition. An improved understanding of the secondary geochemical

3

alteration processes is critical for successful exploration and fluid property prediction. Three

4

oil samples from the Ordovician condensate and oil reservoirs were analyzed using

5

comprehensive 2D gas chromatography/time of flight mass spectrometry (GC×GC-TOFMS).

6

Molecular signatures revealed varying levels of diamondoids and organosulfur compounds

7

(OSCs) that were preferentially enriched in the condensate and a gas saturated oil, however,

8

these molecular signatures were not generated through in-reservoir oil cracking or

9

thermochemical sulfate reduction (TSR) as favorable thermal and medium conditions were

10

not available. Severe cracking and TSR occurred in deeper Cambrian source-reservoirs and

11

generated secondary geochemical products including diamondoids, OSCs and H2S. Such

12

secondary products were carried by dry gases derived for oil cracking that migrated upward

13

through fault system and filled shallower Ordovician oil reservoirs. The differential secondary

14

gas charge can account for the variable fluid composition and varying phase behavior, i.e. the

15

transition from unsaturated oil to gas saturated oil and then to condensate. Condensates were

16

formed from the dissolution of primary oils due to extra gas mixing.

17

Keywords: Diamondoids; Organosulfur Compounds (OSCs); Oil Cracking; Thermochemical

18

Sulfate Reduction (TSR); Gas Mixing; Fluid Phase; Tarim Basin

19

1. Introduction

20

Phases of reservoir fluids are controlled by their geochemical compositions and the 1,2.

21

subsurface temperature-pressure conditions

With the extension of exploration into deep

22

strata (generally deeper than 6,000 m or the formation temperature over 160 oC), petroleums 2


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in deep strata can be geochemically altered by secondary process such as thermal cracking

24

and thermochemical sulfate reduction (TSR), resulting in the changes in geochemical

25

compositions and subsequently the phases

26

geochemical alteration on petroleums is crucial for effective phase prediction and exploration.

27

Under high temperature and pressure conditions in deep strata, thermal cracking of deep

3–5.

Therefore, unraveling the effects of secondary

2,6–13.

28

oils may take place and eventually results in the complete conversion of oil to gas

29

Diamondoids, caged hydrocarbons similar in structure to diamond, may be continuously

30

generated and enriched during the cracking of oils 14–16, and thus they are generally abundant

31

in high-maturity oils. Therefore, proxies based on diamondoids have been proposed to

32

evaluate the extent of oil thermal cracking

33

sedimentary basins worldwide, in which petroleum hydrocarbons are oxidized by inorganic

34

sulfates in formations at high temperatures (generally above 140 oC), ultimately yielding

35

hydrogen sulfide (H2S) and carbon dioxide (CO2) 21–26. Enriched H2S in natural gas may exert

36

harmful impacts on pipelines and cause health problems if they are not correctly handled 27.

37

Molecular signatures indicative of TSR are generated during the organic-inorganic

38

interactions, i.e. various organosulfur compounds (OSCs) including thiadiamondoids

28–33,

39

thiols, tetrahydrothiophenes, alkyl-benzothiophenes and alkyl-dibenzothiophenes

34–38.

TSR

40

exerts significant impact on natural gas, leading to evident changes in the alkane gas contents

41

and compound-specific carbon isotopic values 39–42.

17–20.

TSR has been well documented in many

42

The Tarim Basin is undergoing active exploration of deep strata. It is an ancient

43

petroliferous cratonic basin with complex hydrocarbon accumulation process due to the deep

44

burial, geologic ages and multi-cyclic alterations

43–46,

which complicates the character and

3


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phase of subsurface fluids and brings challenges in hydrocarbon prediction and exploration.

46

This is especially true for the Ordovician strata in the Tazhong uplift, an important

47

hydrocarbon-rich tectonic zone in the basin, where reservoirs with various phase states were

48

discovered, i.e. gas, condensate and oil reservoirs laterally co-exist within a small distribution

49

range

50

chromatography/time of flight mass spectrometry (GC×GC-TOFMS) on several condensate

51

and oil samples from the Tazhong uplift. When used in combination with gas geochemistry

52

and PVT analysis, the impacts of secondary geochemical alterations on deep petroleums and

53

their phase behavior can be elucidated.

54

2. Materials and Methods

55

2.1 Samples

47,48.

Here we report the application of high-resolution comprehensive 2D gas

56

Tazhong uplift is in the central of the Tarim Basin, where the petroleum reservoirs are in

57

the Ordovician system at burial depth ranging from 5,500 to 6,500 m, with corresponding

58

reservoir temperature between 125 and 145 oC. The main reservoir rock is limestone sealed

59

by tight mudstone and muddy limestone. Fault systems were well-developed and extended

60

into the basement and serve as major source conduits. Reservoir fluids in Tazhong area are

61

complex in phase and composition, showing the co-existence of gas, condensate and oil.

62

In this study, oil and gas samples from three adjacent petroleum reservoirs, including one

63

condensate (from well A) and two oil (from well B and C) reservoirs, were collected at the

64

well head after the separator. For each well, three oil samples and their associated gas samples

65

were collected during different production periods. Oil samples were collected using sample

66

vials. Gas samples were collected using high-pressure steel vessels with interior Teflon 4


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coating layer which can avoid the reaction of steel with H2S. The steel vessels could

68

withstand a maximum pressure of 21.5 MPa.

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2.2 Methods

70

2.2.1 Chemical fractionation and physical property

71

The bulk oil composition was measured on Iatroscan TLC-FID calibrated by using

72

standards based on separated crude oil fraction from the Tarim Basin to determine SARA

73

(saturates, aromatics, resins and asphaltenes) proportions. Oil viscosity was measured using a

74

standard viscometer fitted with a rheometer. The sulfur content of oil samples was measured

75

following ASTM 5185 method using ICP-AE. Wax content in oil was determined by the

76

ASTM D97-66 method.

77

2.2.2 GC×GC-TOFMS for oil

78

A PONA column (50 m × 0.2 mm × 0.5 μm) was used as the first dimension (1D)

79

chromatographic column for GC×GC-TOFMS analysis. The temperature program was set to

80

start from 35 °C (hold for 5 min), heat to 280 °C at 2 °C/min (hold for 20 min). The second

81

dimension (2D) separation was performed using a Rxi-17 column (2 m × 0.1 mm × 0.1 μm).

82

The 2D and modulator ovens were operated with the same temperature gradient but with a

83

temperature offset of 5 °C and 20 °C higher than the 1D oven, respectively. The samples (1

84

μL) were injected into a heated (300 °C) split injector (split ratio 50:1). Helium was used as

85

the carrier gas, with a constant flow rate of 1.5 mL/min. The modulation period was 4 s, with

86

a 0.8 s hot-pulse duration. The MS transfer line and ion-source temperature were 280 °C and

87

250 °C, respectively. The acquisition rate was 100 spectra/s with a collected mass range of

88

40–500 amu, and the acquisition delay was 2 min. The group compositions of the compounds 5


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89

were quantified by peak area normalization. D16-adamantane (using CH2Cl2 as a solvent) was

90

placed in the oil samples, and the quantitative results of diamondoids, thiaadamantanes and

91

other products in the condensate were obtained using the internal standard method.

92

2.2.3 Carbon isotope analysis for gas

93

Compound specific carbon isotopic analysis was conducted on the recovered gases. A

94

Thermo Trace GC Ultra gas chromatograph with a 60 m J&W fused silica DB-1MS capillary

95

column (30 × 0.25 mm i.d.; 0.25 μm film thickness of 100% methylsilicone) was used to

96

fractionate the components, and the temperature was initially held at 33 oC, programmed to 80

97

oC

98

for 20 min. GC Combustion III was the transfer interface and the temperature of the oxidation

99

oven was kept at 980 oC and that of the reducing oven was 640 oC. A Delta V Advantage

100

Isotope-Ratio Mass Spectrometry (IRMS) was used to acquire mass spectral data from the GC

101

by using 3.07 kV electron impact ionization. Stable carbon isotopic values were reported in

102

parts per thousand relative to the Vienna Peedee Belemnite (VPDB).

103

2.2.4 PVT tests

at the rate of 8 oC/min and finally programmed to 250 oC at 5 oC/min and held isothermally

104

Dead oil and gas samples were acquired and recombined to reconstitute the live oil

105

before starting the PVT tests. The PVT tests were conducted according to the established

106

procedure for the constant composition expansion and compression, differential liberation and

107

flash liberation. All these tests were carried out in a visual PVT cell that could withstand the

108

maximum pressure and temperature of 100 MPa and 200 oC, respectively. The pressure, total

109

volume, and temperature values were automatically collected and shown on a control panel.

110

Further details of the experimental procedures for the PVT tests of recombined oils can be 6


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found elsewhere 49,50.

112

3. Results and discussion

113

3.1 Reservoir fluid properties

114

3.1.1 Phase types of reservoir fluids

115

PVT analysis was conducted in each well to precisely identify the reservoir fluid phases.

116

The condensate (sample A) has the lowest critical temperature and highest critical pressure

117

(-57.2 oC and 46.48MPa, respectively, Table 1), and its test PVT point locates to the right of

118

the critical point and away from the dew point line, indicating an unsaturated condensate in

119

single gas phase in the reservoir condition (Fig. 1-a). The saturated oil (sample B) and

120

unsaturated oil (sample C) have higher critical temperatures and lower critical pressures

121

(393.0 and 448.5 oC, 14.39 and 9.15 MPa, respectively, Table 1), and their test points both

122

locate at the left side of the critical point. The test point of well B falls on the bubble point

123

line, which means the pore pressure of well B equals to the saturation pressure, indicating

124

typical saturated oil phase (Fig. 1-b). However, the pore pressure of well C is larger than the

125

saturation pressure, and thus it is typical of unsaturated oil phase (Fig. 1-c).

126

The compositional ternary plot with pseudo-components of C1+N2, C2-C6 +CO2 and C7+

127

as three end members can also provide evidence for the identification of fluid phases (Fig.

128

1-d). According to the relative content of the pseudo-components of each sample, well A

129

locates in the gas-condensate area (to the right of C7+ = 11% line), while well B and C are

130

both classified as oils (to the left of C7+ = 32% line), which are correlated well with the PVT

131

results. The original GOR (gas-to-oil ratio) of each well varies accordingly (Table 1), with the

132

largest GOR in condensate (well A, 1,324 m3/m3), followed by saturated oil (well B, 202 7


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m3/m3) and unsaturated oil (well C, 40 m3/m3).

134

Fig. 1

135

Table 1

136

3.1.2 Physical properties of oil and gas

137

The oils in the Tazhong area show small range variation of measured density at 20 oC

138

from 0.800 to 0.823 g/m3. The measured dynamic viscosity at 50 oC ranges from 1.71 to 2.65

139

mPa·s, showing subtle variation as well. The relative contents of resin, asphaltene and sulfur

140

are 0.16-1.87%, 0.03-0.60% and 0-0.30%, respectively. The condensate and oils are

141

characterized by low sulfur and polar contents. The density of studied condensates is slightly

142

higher than that of oils, which likely correlates with the variance in wax content, showing an

143

overall decreasing values from condensates (6.8-12.4%) to oils (3.4-6.1%; Table 2).

144

Condensates with higher wax content are likely formed as a result of gas invasion alteration

145

which generally causes the loss of lighter fractions.

146

Table 2

147

Natural gases in the Tazhong area consist of 66.5-89.5% hydrocarbons, 0-18.8% of H2S,

148

1.73-13.32% of N2 and 2.10-7.75% of CO2. The abnormally high N2 contents may be

149

attributed to air contamination during the acid fracturing of the reservoirs. The H2S contents

150

and gas dryness (C1/C1-4) show apparent variation in different gas types. Condensate gases

151

show the highest H2S content and gas dryness, while unsaturated-oil associated gases are wet

152

gas with null H2S (Table 3).

153 154

Table 3 3.2 Genetic origin of diamondoids and OSCs 8


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Energy & Fuels

Recent studies have unraveled that most of the petroleum in the Tazhong area were from

156

Cambrian marl/shale source rocks

33,51,52,

and accumulated in the Ordovician carbonates

157

during the Late Hercynian orogeny

4,47,48.

Therefore, the oils and condensates oil presently

158

analyzed share the same genesis and origin, and thus the similar molecular composition can

159

be speculated. However, clear differences were observed from GC×GC-TOFMS data,

160

especially the concentrations and distributions of diamondoids and OSCs.

161

3.2.1 Bulk composition

162

GC×GC-TOFMS analysis has detected 3,350, 3,162 and 2601 compounds with

163

signal-to-noise ratios >100 from gas condensate (well A) and oils (wells B and C),

164

respectively. Their 2D color contour chromatograms and corresponding 3D peak plots are

165

shown in Figs. 2 & S1. Hydrocarbons (C6 to C30) including several distinctive groups of

166

aliphatics (n-alkanes and cycloalkanes), aromatics (benzenes, naphthalenes, phenanthrenes,

167

etc.), diamondoids (adamantanes, diamantanes and triamantanes), OSCs (diamondoids,

168

thiophenes, benzothiophenes, dibenzothiophenes, thiols) and terpanes were detected using

169

specific extracted ion chromatograms (EICs; Fig. 2). A terpane series is detected in sample C,

170

indicating an oil with moderate maturity. Diamondoids and OSCs are preferentially enriched

171

in samples A and B.

172

Fig. 2

173

The relative abundance of each compound is characterized by the peak area (area

174

underneath individual peak using a defined baseline) in the Fig. S1. This figure also shows the

175

similar distribution range of aliphatics in the samples. Generally, typical thermal condensates

176

generated in high-maturity stages consist of mainly light fractions (< C10). All the studied 9


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samples are featured with full range of n-alkanes (C6 to > C25), indicating that they are typical

178

secondary condensates (Fig. S1).

179

3.2.2 Diamondoids

180

Several series of alkylated adamantanes, diamantanes and triamantanes were identified.

181

Diamondoids with different cage numbers are illustrated in the chromatograms (Fig. 3).

182

Generally, adamantanes have higher concentrations than diamantanes in each sample, and

183

only trace amount of triamantanes were detected in condensate A. Concentrations of

184

diamondoid hydrocarbons generally decrease with increasing molecular weight (Fig. 3-a,

185

Table 4).

186

Fig. 3

187

Table 4

188



189

(Fig. S2, S3) and distinct linear GC×GC profiles are observed in different compound

190

homologues. At least 38, 24 and 13 alkylated adamantanes were identified from the

191

studied samples using EICs of m/z 135, 136, 149, 163, 177, 191 and 205, respectively

192

(Fig. S2, Table 4), and their summed concentrations were 1316.5, 700.8 and 98.2 ppm,

193

respectively.

194



195

using EICs of m/z 187, 188, 201, 202, 215, 216, 230 and 244, respectively, and their

196

summed concentration were 70.0 and 47.8 ppm, whilst only 4-methyldiamantane was

197

detected in sample C with low concentration (Fig. S3, Table 4).

198

Diamondoids show significant variance in types and abundances in different samples.

Adamantanes: alkylated diamondoid series align with variable carbon substitutions

Diamantanes: 10 and 8 alkylated diamantanes were detected from samples A and B

10


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They are enriched in the condensate (sample A) and saturated oil (sample B) and depleted in

200

the unsaturated oil (sample C). Diamondoids are generally formed by the thermal cracking of

201

polycycloalkane C-C bonds, which is related to oil cracking

202

4-+3-methyldiamantane is useful in determining the oil cracking extent, however, oils derived

203

from different sources have varying baseline of this methyldiamantane concentration

204

(generally 2~10 ppm)

205

4-+3-methyldiamantane (2.64 ppm) represented a well-preserved oil without significant oil

206

cracking, while the much higher concentrations in sample A and B (29.5 and 21.3 ppm,

207

respectively) could be attributed to oil cracking.

208

3.2.3 Organosulfur compounds (OSCs)

15.

15,17,18.

The concentration of

The oil sample C with relatively low concentration of

209

OSCs were identified using EICs of m/z 101, 147, 161, 175, 184, 198, 212, 234 and 248,

210

respectively. Distributions and abundances of OSCs show great variances in the studied

211

samples. Only some benzothiophenes and dibenzothiophenes are detected in sample C, while

212

much

213

thiaadamantanes, are found in sample A (Fig. S4). For instance, five thiaadamantanes have

214

been identified from sample A, one (1,5-dimethylthiaadamantane) from sample B and null

215

from sample C (Table 4). OSCs in petroleum samples may be derived from kerogen, original

216

organic matter and bitumen 53, as the petroleum fluids in the study site were all sourced from

217

the same Lower Cambrian source rocks 54, the differences in organic matter input should be

218

minimized. The varying concentration of OSCs in the present samples is more likely

219

attributed to TSR, the secondary alteration in which petroleum compounds were reacted with

220

sulfates at high temperature conditions

broader

distributions

including

24,35.

thiophenes,

tetrahydrothiophenes,

thiols,

Condensate A and oil B with more enriched 11


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OSCs, especially thiaadamantanes, were likely impacted by TSR alteration while oil C was

222

relatively unaltered.

223

3.2.4 Origin and source of diamondoids and OSCs

224

The Tarim Basin was in a stage of continuous subsidence with constantly low

225

geothermal gradient (~2.0 oC/100 m) since the Late Permian

226

depth can be regarded as the maximum burial depth in the geologic history. The current

227

reservoir temperatures are generally less than 145 oC (6,500 m), at which petroleums have not

228

reached the threshold of thermal cracking

229

carbonate reservoirs with tight mudstones and limestones as seals. Relatively low temperature

230

and the lack of sulfate hinders the onset of in-reservoir TSR. Therefore, the high abundance of

231

diamondoids and OSCs detected in samples A and B are indications of TSR-altered migrated

232

fluid rather than local alteration.

45,57.

55,56,

and the current reservoir

The Ordovician strata mainly consists of

233

A favorable source-reservoir-seal assemblage for TSR occurrence exists in the deep

234

Cambrian sub-salt strata in the Tazhong area 54,58, which is composed of marl/shale sources in

235

the Lower Cambrian Yuertusi Formation, carbonate reservoirs in the overlying Lower

236

Cambrian Xiao'erbulake Formation, and evaporite rock seals in the Middle Cambrian strata.

237

The current Cambrian reservoir temperatures ranging from 185 to 240 oC at the depth of

238

8,500 to 12,000 m, coupled with well-developed evaporite rocks, facilitated thermal cracking

239

and TSR alterations of the Cambrian petroleums resulting in the generation of secondary

240

geochemical products. Therefore, the diamondoids and OSCs as well as the H2S enriched in

241

the oil and gas samples under study are believed to have been generated from deeper

242

Cambrian petroleums. 12


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3.3 Gas mixing and formation of secondary condensate

244

3.3.1 Impacts of gas mixing on fluid compositions

245

Molecular concentration profiles of reservoir fluids, obtained through PVT analysis, can

246

be used to unravel the accumulation and alteration history of fluids. Based on the exponential

247

progression of the C7+ n-alkane concentration observed in unaltered oils 59, two slope factors

248

(SF) were proposed to define the exponential decrease in concentration of gas (C3-n-C5) and

249

liquid (P10+) fractions with increasing carbon number 60,61. The exponential progression of the

250

component concentration was modelled as equation:

251

y = Ae(-an) (Eq. 1)

252

thus, the slope factor can be obtained through equation:

253

SF = ea (Eq. 2)

254

Generally, a covariant increase of SF(C3-n-C5) and SF(P10+) exists during the thermal

255

maturation, but the former is much more vulnerable to secondary modification such as the

256

mixing of allochthonous gas, which may lead to the increase of SF(C3-n-C5) 60. PVT analysis

257

of petroleum samples from each well revealed full suite of n-alkanes (C1 to n-C29; Fig. 4).

258

Similar compositional characters in the liquid fractions reflected by slight differences in

259

SF(P10+) values (1.20, 1.25 and 1.26), indicate similar maturity level of the samples. However,

260

SF(C3-n-C5) values in condensate and saturated oil (1.58 and 1.43, respectively) are higher

261

than the unsaturated oil (1.07) and the ratios of C1/C2 increase from sample C to B and to A

262

consequently. Elevated values in samples A and B can be attributed to dry gas mixing into oil

263

resulting in changes in the gas fractions.

264

A hump of n-alkanes in the liquid fractions (> n-C10) around n-C20 has been observed in 13


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the samples A and B (labeled in Fig. 4 as hump A and hump B), while sample C shows a

266

relatively linear variation. This may be attributed to the combined effects of two processes: 1)

267

the mixing of gas into oil in a relatively closed system mainly impacts the gas fractions

268

meanwhile it may also cause slight loss of lighter liquid fractions (likely < n-C20 in sample A

269

and B), and thus the exponential relationship deviates slightly from perfectly linear; 2) the

270

crystallization of heavy n-alkanes may cause the depletion of heavy liquid fractions (likely >

271

n-C25 in sample A and B)

272

Therefore, the slight humps A and B were possibly formed under the combined effects of gas

273

mixing and n-alkane crystallization as they may cause slight depletion of both light and heavy

274

liquid fractions. In addition, it is noticed that hump A starts at heavier n-alkane (n-C21) than

275

hump B (n-C18), possibly indicating that sample A has suffered more intensive alteration than

276

B. In contrast, sample C was exempted from alteration.

277 278

59,

60,61,

especially in closed system that undergoes gas mixing

62.

Fig. 4 3.3.2 Origin of gas and formation of secondary condensate

279

The carbon isotopic values of methane, ethane, propane and normal butane in the studied

280

gas samples are in the range of -52.7 to -51.0‰, -39.2 to -35.0‰, -34.2 to -29.7‰, and -33.1

281

to -28.8‰, respectively (Table 3). A positive isotopic profile with more enriched

282

increased carbon number suggests a typical thermogenic gas origin

283

depleted δ13C2 values (carbon isotopic value of ethane; evidently less than -28‰) pinpoints

284

the analyzed gas samples as oil associated gas 67,68.

63–66.

13C

in

The relatively

285

Based on pyrolysis simulations, the diagram of δ13C2-3 (the difference of isotopic values

286

between ethane and propane) versus the ratio of C2/C3 can be applied to identify gas genetic 14


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Energy & Fuels

287

origins 69,70. Gas from well C can be classified as primary cracking gas, gas from well A show

288

a typical oil-cracking gas, and gases from well B are in the transitional area of these two types

289

(Fig. 5-a). Thus, a trend from primary gas to oil-cracking gas has been observed. The plot of

290

ln(C1/C2) versus ln(C2/C3) can also be used to discriminate kerogen-cracking and oil-cracking

291

gases with increasing %Ro values 71. Results show that unsaturated-oil associated gases from

292

well C are mainly located on the kerogen-cracking gas curve with an overall maturity below

293

1.0%Ro (Fig. 5-b); however, those gas condensates from well A mainly appear on the

294

oil-cracking gas curve with the maturity range of > 1.5%Ro. Saturated-oil associated gases

295

from well B are mainly located in the transitional area between samples A and C.

296

The variation in maturity and genetic origin of gas samples show good correlation with

297

GOR and gas dryness. The unsaturated oil reservoir (well C) is featured with the lowest GOR,

298

gas dryness and H2S content (40 m3/m3, 0.71-0.75, null, respectively), while saturated oil

299

reservoir (well B) has elevated values (202 m3/m3, 0.81-0.89, 0.74-4.83%, respectively) and

300

condensate reservoir (well A) the highest (1324 m3/m3, 0.90-0.95, 5.76-18.8%, respectively).

301

The apparent differences are most likely caused by the mixing of dry gas migrated from deep

302

reservoir oil thermal cracking into the primary oil reservoirs. As the gas mixing extent

303

increased, unsaturated oil reservoir gradually shifted into saturated oil reservoir. Once the gas

304

volume was far exceeded that of oil, the dissolution of oil into gas would take place and

305

subsequently lead to the transition of saturated oil into secondary condensate. The mixing of

306

methane-dominated dry gas also exerted impact on the compositions of primary associated

307

gas, leading to the elevated gas dryness and H2S content.

308

Notably, the concentration of molecular signatures also follows the trend observed in 15


Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

309

gases, i.e. condensate oil has the most enriched diamondoids and OSCs while only

310

diamondoid baseline and very few OSCs were detected in the unsaturated oil, which indicates

311

the allochthonous source of such molecular signatures. They were likely carried by the dry

312

gas in solution and migrated into the current reservoirs. Phase transition from unsaturated oils

313

to secondary condensates and the evident changes in fluid quality would occur due to

314

extensive gas intrusion into primary oil reservoirs.

315

Fig. 5

316

3.4 Impacts of secondary alteration on petroleums

317

The complex characters and phases of the present studied reservoir fluids are attributed

318

to the impacts of secondary geochemical alterations. The accumulation and alteration process

319

of such complex reservoir fluids are briefly summarized in the cartoon illustration (Fig. 6).

320

(1) High-quality fracture-cave reservoirs were formed due to the regional exposure and

321

erosion of the Ordovician carbonates and the fault activities, and thus oils from the

322

deep Cambrian assemblages migrated through faults and subsequently accumulated

323

in these reservoirs (Fig. 6-a). The primary oil reservoirs are featured as unsaturated

324

oil reservoir with low GOR, gas dryness and H2S content (similar to sample C).

325

(2) The region entered a stable stage of constant subsidence under low geothermal

326

gradient, and therefore the oil reservoirs were well-preserved due to moderately low

327

temperature (< 145 oC). Meanwhile, oil thermal cracking and TSR take place in the

328

Cambrian strata as a result of the high temperature (> 185 oC) and sulfates in

329

evaporite rocks. Petroleums in the Cambrian reservoirs were impacted and

330

destructed by secondary alterations, forming dry gases and condensates with 16


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Energy & Fuels

331

considerable amounts of secondary products (diamondoids, OSCs and H2S) in

332

solution (Fig. 6-b).

333

(3) Gases in the Cambrian reservoirs migrated upward through major faults and mixed

334

with oils in the Ordovician reservoirs, resulting in the changes in reservoir fluids.

335

Primary gases became drier and richer in H2S while the reservoir GOR and

336

concentration of secondary products in oils increase accordingly. Reservoirs closer

337

to source faults were impacted more severely by gas intrusion, and thus with the

338

increasing extent of gas mixing, primary unsaturated oils were gradually transitioned

339

into saturated oils. Once the gas volume was far exceeded to that of oil, oil would

340

dissolve into the gas and subsequently formed secondary condensates (Fig. 6-c). Fig. 6

341 342

The marked variation in fluid composition and phase in the Ordovician reservoir fluids

343

could be attributed to the mixing of deep Cambrian sourced gases with shallower oils. Such

344

process can be demonstrated by the detection of diamondoids and OSCs in condensate and

345

some oils, and oil cracking originated, dry and H2S bearing gases. Large quantity of

346

petroleum resources, mainly dry gas, might be still well-preserved in stable structural highs in

347

the deep Cambrian sub-salt strata.

348

4. Conclusion

349

Reservoir fluids in deep strata are frequently impacted by secondary geochemical

350

alterations, leading to severe changes in fluid composition and phase. Improved

351

understanding of secondary geochemical influences on the subsurface fluids is crucial for

352

petroleum exploration and prediction. 17


Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

353

GC×GC-TOFMS analysis showed varying concentrations of secondary products

354

including diamondoids and OSCs in condensate, saturated and unsaturated oil samples. Such

355

products were preferentially enriched in condensate and saturated oil samples. However, the

356

moderately low temperature (< 145 oC) and lack of sulfates in the Ordovician reservoirs

357

suggested that they were not generated in reservoir.

358

The associated gas geochemistry and PVT analysis indicated the gas mixing event in

359

reservoir fluids. The Cambrian sub-salt strata are favorable for the onset of oil cracking and

360

TSR due to the high temperature (> 185 oC) and developed evaporite rocks. Therefore, the

361

enriched diamondoids and OSCs in oils and the variation in GOR, gas dryness and H2S

362

content were attributed to the mixing of deep Cambrian gases migrating into Ordovician oil

363

reservoirs.

364

The increasing extent of deep sourced gases mixed with shallow reservoired oils

365

gradually impacted fluid compositions, leading to the transition from unsaturated oil to

366

saturated oil and then to condensate. The combined impacts of TSR, oil cracking and gas

367

mixing change the composition and phase of petroleum fluids. Meanwhile, dry gas resources

368

may still be well preserved in stable paleo highs in the deep strata.

369

Acknowledgements

370

We acknowledge Tarim Oilfield Company, PetroChina for data contribution and sample

371

collection. We thank Shengbao Shi from China University of Petroleum (Beijing), Ying

372

Zhang and Na Weng from Research Institute of Petroleum Exploration and Development,

373

PetroChina for assistance with the GC×GC-TOFMS analysis. This work was financially

374

supported by National Science and Technology Major Project (Item No. 2016ZX05004-004). 18


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Reference (1) Danesh, A. PVT and phase behavior of petroleum reservoir fluids; Elsevier: Amsterdam, Netherland, 1998. (2) Hunt, J. H. Petroleum geology and geochemistry, second ed.; W.H. Freeman and Company: New York, 1996. (3) Zhang, S.; Su, J.; Wang, X.; Zhu, G.; Yang, H.; Liu, K.; Li, Z. Org. Geochem. 2011, 42 (11), 1394–1410. (4) Zhu, G.; Weng, N.; Wang, H.; Yang, H.; Zhang, S.; Su, J.; Liao, F.; Zhang, B.; Ji, Y. Mar. Pet. Geol. 2015, 62, 14–27. (5) Huang, H.; Zhang, S.; Gu, Y.; Su, J. Org. Geochem. 2017, 112, 158–169. (6) Behar, F.; Kressmann, S.; Rudkiewicz, J. L.; Vandenbroucke, M. Org. Geochem. 1992, 19 (1–3), 173–189. (7) Dieckmann, V.; Schenk, H. J.; Horsfield, B.; Welte, D. H. Fuel 1998, 77 (112), 23–31. (8) Waples, D. W. Org. Geochem. 2000, 31 (6), 553–575. (9) Prinzhofer, A. A.; Huc, A. Y. Chem. Geol. 1995, 126 (3–4), 281–290. (10) Horsfield, B.; Schenk, H. J.; Mills, N.; Welte, D. H. Org. Geochem. 1992, 19 (1–3), 191–204. (11) Hill, R. J.; Tang, Y.; Kaplan, I. R. Org. Geochem. 2003, 34 (12), 1651–1672. (12) Behar, F.; Vandenbroucke, M. Energy & Fuels 1996, 10 (96), 932–940. (13) Hill, R. J.; Tang, Y.; Kaplan, I. R.; Jenden, P. D. Energy & Fuels 1996, 10 (4), 873– 882. (14) Wei, Z.; Moldowan, J. M.; Paytan, A. Org. Geochem. 2006, 37 (8), 891–911. (15) Dahl, J. E.; Moldowan, J. M.; Peters, K. E.; Claypool, G. E.; Rooney, M. A.; Michael, G. E.; Mello, M. R.; Kohnen, M. L. Nature 1999, 399 (6731), 54–57. (16) Dahl, J. E. P.; Moldowan, J. M.; Wei, Z.; Lipton, P. A.; Denisevich, P.; Gat, R.; Liu, S.; Schreiner, P. R.; Carlson, R. M. K. Angew. Chemie - Int. Ed. 2010, 49 (51), 9881– 9885. (17) Wei, Z.; Moldowan, J. M.; Zhang, S.; Hill, R.; Jarvie, D. M.; Wang, H.; Song, F.; Fago, F. Org. Geochem. 2007, 38 (2), 227–249. (18) Chen, J.; Fu, J.; Sheng, G.; Liu, D.; Zhang, J. Org. Geochem. 1996, 25 (3–4), 179–190. (19) Moldowan, J. M.; Dahl, J.; Zinniker, D.; Barbanti, S. M. J. Pet. Sci. Eng. 2015, 126, 87–96. (20) Fang, C.; Xiong, Y.; Li, Y.; Chen, Y.; Liu, J.; Zhang, H.; Adedosu, T. A.; Peng, P. Geochim. Cosmochim. Acta 2013, 120, 109–120. (21) Orr, W. L. Geologic and geochemical controls on the distribution of hydrogen sulfide in natural gas, Advances i.; Campos, R., Goni, J., Eds.; Enadimsa: Madrid, 1977. (22) Machel, H. G.; Krouse, H. R.; Sassen, R. Appl. Geochemistry 1995, 10 (4), 373–389. (23) Worden, R. H. H.; Smalley, P. C. C.; Cross, M. M.; Cross, A. M. M. J. Sediment. Res. 2000, 70 (5), 1210–1221. (24) Wei, Z.; Walters, C. C.; Michael Moldowan, J.; Mankiewicz, P. J.; Pottorf, R. J.; Xiao, Y.; Maze, W.; Nguyen, P. T. H.; Madincea, M. E.; Phan, N. T.; Peters, K. E. Org. Geochem. 2012, 44, 53–70. (25) Hao, F.; Zhang, X.; Wang, C.; Li, P.; Guo, T.; Zou, H.; Zhu, Y.; Liu, J.; Cai, Z. Earth-Science Rev. 2015, 141, 154–177. 19


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Huang, H.; Zhang, S.; Su, J. Org. Geochem. 2016, 94, 32–46. Peters, K. E.; Walters, C. C.; Moldowan, J. M. The Biomarker Guide, Volume 2: Biomarkers and Isotopes in the Petroleum Exploration and Earth History The Biomarker Guide, Volume 2: Biomarkers and Isotopes in the Petroleum Exploration and Earth History; 2005; Vol. 2. Zhu, G.; Chen, F.; Wang, M.; Zhang, Z.; Ren, R.; Wu, L. Am. Assoc. Pet. Geol. Bull. 2018, 102 (10), 2123–2151. Qiu, N.; Chang, J.; Zuo, Y.; Wang, J.; Li, H. Am. Assoc. Pet. Geol. Bull. 2012, 96 (5), 789–821. Li, M.; Wang, T.; Chen, J.; He, F.; Yun, L.; Akbar, S.; Zhang, W. J. Asian Earth Sci. 2010, 37 (1), 52–66. Zhu, G.; Milkov, A. V.; Chen, F.; Weng, N.; Zhang, Z.; Yang, H.; Liu, K.; Zhu, Y. Mar. Pet. Geol. 2018, 89, 252–262. Zhu, G.; Huang, H.; Wang, H. Energy and Fuels 2015, 29 (3), 1332–1344. Kissin, Y. V. Geochim. Cosmochim. Acta 1987, 51 (9), 2445–2457. Thompson, K. F. M. Geol. Soc. London, Spec. Publ. 2004, 237 (1), 7–26. Thompson, K. F. M. Org. Geochem. 2016, 93, 32–50. Li, B.; Huang, G.; Xu, Y.; Tang, X.; Han, J. Bull. Mineral. Petrol. Geochemistry 2011, 30, 97–103. Chung, H. M.; Gormly, J. R.; Squires, R. M. Chem. Geol. 1988, 71 (1–3), 97–104. James, A. T. Am. Assoc. Pet. Geol. Bull. 1983, 67 (7), 1176–1191. Dai, J.; Zou, C.; Qin, S.; Tao, S.; Ding, W.; Liu, Q.; Hu, A. Mar. Pet. Geol. 2008, 25 (4–5), 320–334. Abrams, M. Geosciences 2017, 7 (2), 35. Galimov, E. M. Chem. Geol. 1988, 71 (1–3), 77–95. Wang, S. Nat. Gas Ind. 1994, 14, 1–5. Lorant, F.; Prinzhofer, A.; Behar, F.; Huc, A. Y. Chem. Geol. 1998, 147 (3–4), 249– 264. Prinzhofer, A.; Dos Santos Neto, E. V.; Battani, A. Mar. Pet. Geol. 2010, 27 (6), 1273– 1284. Li, J.; Xie, Z.; Wei, G.; Li, Z.; Wang, W. The 15th National Meeting on Organic Geochemistry in China: Qingdao, 2015.

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Figure captions Fig. 1 Phase curves and compositional ternary plot for reservoir fluids in the Tazhong area. Fig. 2 GC×GC-TOFMS color contour chromatograms of condensate and oil samples. Distinctive groups of aliphatic hydrocarbons, aromatic hydrocarbons, diamondoids, OSCs and terpanes are marked with circles. Fig. 3 GC×GC-TOFMS color contour chromatograms showing the distribution of diamondoids in the condensate and oil samples. Distinctive groups of adamantanes, diamantanes and triamantanes are marked with circles. Fig. 4 Compositional features of Tazhong oil and condensate samples. Cond. = condensate from well A; S.O. = saturated oil from well B; U.O. = unsaturated oil from well C; C1/C2 = volume ratio of methane to ethane. Fig. 5 Plots to discriminate the genetic origin of natural gases. The plot of C2/C3 versus δ13C2-3 is modified after references

69,70;

the plot of ln(C1/C2) versus ln(C2/C3) is modified

after reference 71. Fig. 6 Accumulation and alteration process of complex reservoir fluids in the Tazhong area. U.O. = unsaturated oil; S.O. = saturated oil; Cond. = condensate; D = Devonian; S = Silurian; O = Ordovician; ∈ = Cambrian. (a) High-quality carbonate reservoirs in the Ordovician formation captured oils from the deep Cambrian to form paleo oil reservoirs; (b) Ordovician oils were preserved due to moderate thermal conditions, whilst oil cracking and TSR destructed Cambrian oils to form dry gases and condensates with abundant secondary products (diamondoids, OSCs and H2S) in solution; (c) Cambrian gases mixed into Ordovician oils through faults and thus resulted in the changes in fluid compositions and phases. Reservoirs closer to source faults were impacted more severely. As the gas mixing extent increased, unsaturated oils transitioned into saturated oils and then into secondary condensates.

22


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Energy & Fuels

Figure 1

23


Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Figure 2

24


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Energy & Fuels

Figure 3

25


Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Figure 4

26


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Energy & Fuels

Figure 5

27


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Figure 6 28


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Energy & Fuels

Tables Table 1. PVT data of reservoir fluids in the Tazhong area. GOR = gas-to-oil ratio; cond. = condensate. Table 2. Physical properties of condensates and oils in the Tazhong area. Table 3. Compositional and isotopic features of gases in the Tazhong area. Table 4. Identification of diamondoids in analyzed gas condensate and oils.

29


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Page 30 of 34

Table 1 Well

A

B

C

Reservoir phase

Condensate

Saturated Oil

Unsaturated Oil

Depth (m)

6003-6210

6010-6195

6125-6253

Subsurface Phase State

Single cond. phase

Single oil phase

Single oil phase

Pressure (MPa)

64.39

33.11

71.26

Temperature

(oC)

137.21

140.77

141.30

Saturated Pressure (MPa)

51.85

33.11

14.35

Critical Pressure (MPa)

46.48

14.39

9.15

Critical Temperature (oC)

-57.2

393.0

448.5

Cricondenbar (MPa)

59.96

33.13

14.96

(oC)

376.4

411.9

497.9

1324

202

40

Cricondentherm GOR

(m3/m3)

30


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Energy & Fuels

Table 2 Density (g/m3, 20oC)

Viscosity (mPa s, 50oC)

Wax (%)

Resin (%)

Asphaltene (%)

Sulfur (%)

Condensate

0.814

2.44

7.7

0.62

0.38

0.28

6003-6210

Condensate

0.823

2.65

12.4

0.16

0.60

0.25

A

6003-6210

Condensate

0.811

2.27

6.8

1.87

0.09

0

B

6010-6192

Saturated Oil

0.822

2.59

4.4

1.16

0.16

0.30

B

6010-6192

Saturated Oil

0.809

2.15

6.0

0.32

0.03

0.16

B

6010-6192

Saturated Oil

0.806

2.00

6.1

0.40

0.15

0.22

C

6125-6253

Unsaturated Oil

0.805

1.71

5.6

1.64

0.28

0.28

C

6125-6253

Unsaturated Oil

0.800

1.85

5.4

0.71

0.13

0.28

C

6125-6253

Unsaturated Oil

0.802

1.89

3.4

0.40

0.12

0.16

Well

Depth (m)

Reservoir Phase

A

6003-6210

A

31


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Page 32 of 34

Table 3 Depth

Reservoir

(m)

Phase

A

6003-6210

Condensate

A

6003-6210

Condensate

A

6003-6210

B B B

Well

C1/C1-4

Gas components (%)

Carbon isotopic values (‰)

CH4

C2H6

C3H8

nC4H10

iC4H10

0.95

78.3

2.86

0.86

0.34

0.94

69.4

2.74

0.97

0.41

Condensate

0.90

60.1

2.31

1.23

6010-6192

Saturated Oil

0.89

78.3

6.28

6010-6192

Saturated Oil

0.81

72.2

10.07

6010-6192

Saturated Oil

0.87

75.1

0.72

C

6125-6253

C

6125-6253

C

6125-6253

Unsaturated Oil Unsaturated Oil Unsaturated Oil

H2S

N2

CO2

CH4

C2H6

C3H8

C4H10

0.18

5.76

3.74

7.58

-51.0

-35.0

-29.7

-28.8

0.23

18.80

1.73

5.60

2.10

0.74

12.30

13.10

7.75

3.05

0.24

0.13

2.29

7.05

2.10

-52.7

-35.9

-30.1

-29.7

4.67

1.69

0.86

0.74

4.78

3.45

-52.2

-39.2

-34.2

-33.1

6.38

2.74

1.27

0.62

4.83

4.73

3.81

59.8

11.40

8.43

1.98

1.17

0

12.48

3.09

-52.3

-37.5

-32.1

-31.1

0.71

58.9

13.53

6.35

2.65

1.17

0

13.32

3.58

0.75

61.9

12.92

6.92

0.83

0.50

0

12.73

3.66

32


Page 33 of 34 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

Table 4

Adamantanes

No.

Compound

1

Concentration (μg/g) A

B

C

Adamantane

42.39

24.84

-

2

1-Methyladamantane

205.71

134.52

26.53

3

2-Methyladamantane

61.04

44.38

8.84

4

1,3-Dimethyladamantane

131.61

88.81

5.1

5

1,4-Dimethyladamantane(trans)

54.2

36.54

7.94

6

1,4-Dimethyladamantane(cis)

56.9

39.28

8.22

7

1,2-Dimethyladamantane

71.04

47.09

9.13

8

2-Ethyladamantane

34.49

20.5

4.43

9

C2-Adamantane

13.34

10.29

-

10

C2-Adamantane

18.84

13.66

2.53

11

C2-Adamantane

41.19

20.88

2.02

12

1,3,5-Trimethyladamantane

37.37

-

3.96

13

1,3,6-Trimethyladamantane

38.11

22.93

4.72

14

1,3,4-Trimethyladamantane(trans)

40.42

22.16

-

15

1,3,4-Trimethyladamantane(cis)

40.93

22.29

3.52

16


44.27

24

3.98

17

C3-Adamantane

10.11

4.92

-

18

C3-Adamantane

21.44

4.14

-

19

C3-Adamantane)

22.14

-

-

20

1-Ethyl-3-Methyladamantane

24.66

11.15

-

21

C3-Adamantane

21.35

15.27

-

22

1-Ethyl-3,5-Diamethyl-adamantane

8

-

-

23

C3-Adamantane

5.74

4.41

-

24

C3-Adamantane

28.96

5.54

-

25

C3-Adamantane

13.73

-

-

26

C3-Adamantane

12.33

-

-

27

1,2,5,7-Tetramethyladamantane

21.11

12.65

-

28


5.59

-

-

29

C4-Adamantane

21.19

-

1.5

30

C4-Adamantane

16.67

-

-

31

C5-Adamantane

7.34

-

-

32


8.66

-

-

33

C4 -Adamantane

6.96

-

-

34

C4-Adamantane

12.35

-

-

35


6.68

-

-

36

C6-Adamantane

7

-

-

37

C3-Adamantane

5.39

-

-

38

C3-Adamantane

4.2

-

-

39

C4-Adamantane

12.88

-

-

40

C3-Adamantane

-

21.59

3.12

33


Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Diamantanes

1

Diamantane

11.5373

8.1624

-

2

4-Methyldiamantane

17.8201

14.6946

2.64

3

1- Methyldiamantane

10.0457

5.4948

-

4

3- Methyldiamantane

11.6955

6.5664

-

5

4,9-Dimethyldiamantane

3.6612

-

-

6

1,4+2,4-Dimethyldiamantane

3.0171

2.9982

-

7


3.2318

3.2262

-

8


3.4465

3.0894

-

9

C2-Dimethyldiamantane

3.4465

3.5454

-

10

C3-Trimethyldiamanatane

2.1357

-

-

Triamantane

2.95

-

-

1

5-Methyl-2-Thiaadamantane

1.13

-

-

2

1-Methyl-2-Thiaadamantane

0.61

-

-

3

1,5-Dimethyl-2-Thiaadamantane

4.13

1.15

-

4

1,3-Dimethyl-2-Thiaadamantane

0.64

-

-

5

C3-2-Thiaadamantane

0.64

-

-

Triamantanes

Thiaadamantanes

Page 34 of 34

34


Impacts of Thermochemical Sulfate Reduction, Oil Cracking, and Gas

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