Geochemical evaluation of hydrocarbons and their potential sources in the western South Caspian depression, Republic of Azerbaijan

Marine and Petroleum Geology, Vol. 14, No. 4, pp. 451468, 1997 0 1997 Published by Elsevier Science Ltd

All rights reserved. Printed in Great Britain

PII: s0294-9172(97)9991

0264-8172/97 $17.00+0.00

l-l

Geochemical evaluation of hydrocarbons and their potential sources in the western. South Caspian depression, Republic of Azerbaijan Michael A. Abrams Exxon

Ventures

(CIS), Inc., P.O. Box 4480, Houston,

TX 77210-4480,

USA

Akif A. Narimanov SOCAR, Neftchilar

Received

Avenue

5 September

73, Baku 370004, Republic

1996; revised

6 December

of Azerbaijan

1996; accepted

23 December

1996

The western South Caspian depression, located in offshore Azerbaijan, contains significant accumulations of oil and gas in Upper Tertiary fluvial-deltaic sediments. The active Tertiary hydrocarbon system is a product of unique paleogeographic and tectonic events that led to Paleogene deposition of organic-rich source rocks, rapid Pliocene subsidence concurrent with voluminous supply of elastic sediments, and development of anticlinal traps with abundant shale diapirs. Molecular characterization of selected oil samples indicates most of the oils are sourced from similar organic facies. The molecular characteristics are consistent with oils sourced from a Tertiary, slightly calcareous, marine elastic facies. Examination of oil molecular characteristics, oil-oil correlations, molecular characteristics of selected source rock samples, maturation models, and potential migration pathways suggests the oil is not syngenetic, but most likely sourced from deeper Miocene and older marine shales. Most of the oils have lowto moderate organic maturities (VRE 0.75485) relative to conventional peak generation windows. Significant variations in oil gravity and whole oil gas chromatogram character suggest post-emplacement bacterial and fractionation alteration. Several oils display characteristics consistent with multiple phases of trap charging. The bulk of reservoired gases examined in this study have been sourced from mixed terrestrial-marine kerogen generated at organic maturities of VRE 0.80-1.00 with some biogenic-low maturity mixing. None of the gases examined were sourced from the thermal destruction of liquid hydrocarbons. We postulate multi-stage hydrocarbon emplacement into evolving structural traps. The first phase of emplacement occurred in the Middle Pliocene when tectonic movement and increased subsidence initiated early trap/reservoir formation, hydrocarbon generation, and migration. Late rapid subsidencefrom Quaternarytectonicactivityproduced additional hydrocarbonsto replenish older, depleted traps and charge newly formed traps. This late tectonic activity also extensively redistributed hydrocarbon accumulations, degassed some that were breached by faults, and destroyed other oil pools. Thermal disequilibrium from the rapid subsidence delayed hydrocarbon generation and increased the minimum depth required for the onset of liquid hydrocarbon generation. 0 1997. Published by Elsevier Science Ltd. Keywords: Azerbaijan;

geochemistry;

hydrocarbon

systems; South Caspian

The South Caspian depression is a Tertiary back-arc basin located in the offshore Republic of Azerbaijan. Azerbaijan is located in the Caucasus region, bordering Russia, Georgia, Armenia, Turkey, Iran, and the Caspian Sea (Figure la) with approximately 86 600 km2 of land area and a population of 7 million. It is one of the oldest known oil producing regions in the world with a rich and colorful petroleum exploration and production history dating back to Alexander the Great. The soldiers of Alexander the Great utilized these rich oil resources during campaigns in the IV century BC from shallow hand dug wells. The first oil well was drilled in Azerbaijan by a Russian engineer, Semyenov, in the Bibi-Eibat area in 1848, 11 years prior to Colonel Drake’s oil well in Pennsylvania (Narimanov and Palaz, 1995). By 1913,

Azerbaijan produced 83% of the oil within the former USSR (Narimanov and Palaz, 1995). Most recently there has been increased interest in the area with the signing of several multi-billion dollar production sharing agreements including the Megastructure (Chirag, Azeri, and deepwater Guneshli) (Figure Ib). The South Caspian depression contains significant accumulations of oil and gas with discovered reserves estimated to be 20 plus GOEB (billion oil equivalent barrels) and an additional 20 plus GOEB undiscovered reserves making the South Caspian depression a world class petroleum system. It is estimated there are up to 25 km of sediments in the basin center (Nadirov, 1990). The relatively low geothermal gradients (around 1.5”C lOOm_‘) from rapid burial provide favorable thermal

451

452

Geochemical evaluation of hydrocarbons:

Michael A. Abrams and Akif A. Narimanov

‘ERBAIJAN

IRA

TURKMENISTAN

km 250

O0

150 miles

-

cYsPLAN

SE4

.

Legend

8

+

A

BAKHAR

SABAIL

FIELD NAME

GAS

+ Figure 1 (a) Index map of study area, Republic

+

of Azerbaijan.

i

(b) Map of fields with oil, gas and rock samples,

conditions for the preservation of hydrocarbons at relatively great depths (up to lO+ km) (Nadirov, 1990). Known hydrocarbon accumulations within the Azerbaijan offshore areas are contained in Pliocene siliciclastic reservoirs within structural traps. Structural styles range from anticlinal folds to monoclines with various degrees

Republic

of Azerbaijan.

of reverse faulting and fracturing. Many structures are penetrated by mud diapirs and mud volcanoes. Most of the structures occur along clearly identifiable trends associated with underlying deep seated faults which were inherited from the Mesozoic and reactivated during the Cenozoic. The majority of the accumulations are in

Geochemical evaluation of hydrocarbons: fluvialdeltaic Middle Pliocene sediments (Productive series). The present study focuses on the hydrocarbon accumulations located in the onshore and near shore western South Caspian depression (Figure Ib). Subsurface oil, gas and rock samples were collected throughout the onshore and offshore western South Caspian depression to identify oil and gas groups, and to correlate these hydrocarbons to stratigraphic units which sourced them, based upon molecular characteristics. The purpose is to gain a better understanding of factors that influence hydrocarbon generation, migration, and entrapment in the western South Caspian depression.

Regional geology The South Caspian depression is located on the Greater Caucasus-Kopet Dag portion of the Alpine-Himalayan fold belt. It is situated on thinned continental crust and Lower Jurassic oceanic crust formed by back-arc spreading after Triassic amalgamation of Iranian and Turan blocks. From the mid-Jurassic into the Neogene, the South Caspian was a depression on the shelf of Southern Eurasia where episodic marine restriction led to the deposition of organic-rich calcareous and diatomaceous black shales (middle Eocene Kuma, upper Oligocene-lower Miocene Maikop, and middle-upper Miocene Diatomaceous). The collision of Arabia with Tuarides and Pontide-Iranian blocks began to close the Caucasus Ocean in the Miocene. A series of horsts and grabens developed in response to extension forming many of the early structural trends. By late Miocene-Pliocene, this collision was accompanied by regional uplift of the colliding terranes and subsidence of the South Caspian oceanic crust loading up to 10 km of deltaic and lacustrine elastics in the basin. This event lead to the development of key reservoir facies, increased burial for maturation, iiquification of basinal shales forming numerous shale diapirs, and re-structuring of traps as well as the creation of new structures (Figure 2). The traps consist primarily of anticlines formed along pre-existing fault trends along which reverse faulting or inversion of earlier normal faults occurs (Figure 3). The anticlinal trends are very large both in aerial extent and vertical amplitude. Many of these anticlines are associated with mud diapirs which culminate in mud volcanoes with active hydrocarbon seepage (Guliev and Feizullayev, 1996). The mud volcanoes can be extremely large with relief up to 400m and diameters of several kilometers. The bulk of the oil reserves are found in the Middle Pliocene Productive series (Figure 2). The Productive series can be sub-divided into two distinct groups (Ruehlman et al., 1995). The early Productive series is dominated by quartz and minor sedimentary rock fragments typical of the Paleo-Volga provenance to the north. The late Productive series contains less quartz, more feldspar, and fragments of both sedimentary and volcanic rock fragments more typical of sediments fed by the Paleo-Kura in the west (Ruehlman et al., 1995). Oil is also found in the Miocene Chokrak elastics and fractured Oligocene-Miocene Maikopian shales (Klosterman et al., 1997).

Oil group Based on physical properties, gas chromatography, chromatography, and gas chromatography-mass

liquid spec-

Michael A. Abrams and Akif A. Narimanov

453

trometry (GC-MS) all but one of the 73 onshore and offshore western South Caspian depression oil samples appear to belong to a single oil group (Abrams and Narimanov, 1994) (Figure 4). Only the oil from Sangachal-deniz # 551 well is sourced from a significantly different organic facies (Figure 5). We define an ‘oil group’ as a series of oils generated from a similar organic facies. This differs from an ‘oil family’ which defines a group of oils generated in and expelled from a single, stratigraphically defined source rock (Allan and Creaney, 199 1). Limited source rock data prevent the oils from being separated into true oil families. The definition of an oil group excludes variations due to maturity or post expulsion alteration processes, such as biodegradation and phase segregation. Many of the oil samples appear to have lost a significant amount of volatiles, based on examination of whole-oil gas chromatograms (Figure 6). The single oil group is characterized by low sulfur, medium to low API gravity, whole-oil gas chromatograms missing all or part of volatile fraction (C,C,,,), abundant methylcylcohexane (MCH) and toluene associated with volatile loss, pristane to phytane ratios 1.4-1.6, pristane to n-C,, ratios l&4.35, and relatively high saturate to aromatic ratios (ranging 1.5-2.5) (Figure 4). The saturate biomarkers are characterized by low diasterane to regular sterane ratios, low hopane to sterane ratios, CZ7steranes more abundant than CZ9steranes, low 20S/(20R + 20s) ratios, low tricyclic to pentacyclic ratios, CZ9hopane much less than CXOhopane, moretane peaks present, C3.&, homohopane ratios less than 1.0, Cs4 tetracyclic much less than C,, tricyclic, oleanane present (in relatively small concentrations), and Ts to Tm ratios less than one (Figure 4). GC-MS-MS fragmentograms from selected oil samples display C3,, regular steranes which confirms input of marine algal matter (Figure 7). The Co regular steranes are often confused with CjO 4methyl steranes which are abundant in algal-rich lacustrine-sourced oils. Although this single oil group has very similar molecular characteristics, there are differences in isotopic composition of the saturate and aromatic fraction. Oils reservoired in Pliocene and younger rocks are isotopically heavier by 14 per mil (less negative) than oils reservoired in Miocene and older rocks (Figure 8). This observation was first noted by Guliev and Feizullayev (1996). Guliev and Feizullayev believe the isotopic shift reflects varying contributions from different age source rocks of similar organic facies; Middle-Lower Pliocene versus MioceneOligocene sources (Guliev and Feizullayev, 1996). Although, we agree the isotopic shift is due to varying contributions from different age source rocks of similar organic facies, our study indicates the key sources are located in the Miocene-Oligocene and possibly as young as Upper-Middle Miocene (see discussion in later section for details). Secondary alterations, variations in organic source facies, and differences in the level of organic maturity could also cause an isotopic shift. We interpret these oils to be sourced from a Tertiary, slightly calcareous, marine anoxic elastic facies. Most of these oils appear to have been generated prior to conventional peak rate of generation (estimated to be VRE 0.95 for Type II marine source rocks, Tissot and Welte, 1984) based on API gravity, hydrocarbon composition, pristane to n-C,, ratio relative to phytane to n-C,, ratio, sterane isomerization %CZ9 20S/(20S+20R), Ts to Tm ratio, relative amounts of moretane, and methyl-

454

Geochemical evaluation of hydrocarbons:

Michael A. Abrams and Akif A. Narimanov

STRATIGRAPHY SOUTHWEST A(

CASPIAN

BASIN

LOWER

TECTONIC

KURA &

SW CASPIAN

HISTORY

AGE

STAGE

SHELF

LITHOLOGY

$

-

2

;

‘.:.

-

2

f 2

-----_

--T

‘.

RESERVOIRS

.

-

-

‘.-

.

PRODUCING

FIELDS

?? KYURSANGYA

.

KIROVDAG KYURSANGYA KALMAS

60 ’ , i

0

0

60

HISHOVDAG KALMAS PIRSAGAT DASHGIL

1

1 1

DUVANNY DASHGIL KYURSANGYA GARASU SULLA-DEN12

a

BACK-ARC

EXTENSION .

PRODUCTIVE SOURCE

A

RESERVOIR

INTERVAL

SAND,

SANDSTONE

CLAY,

CLAYSTONE,

I=I

MARL, CALCAREOUS MUDSTONE

IVV’I

VOLCANIC

m

TUFF

ROCKS

140 I7

ARGILLITE,

SHALE

FRACTURED

ARG.

CARBONATE

160 -

Figure 2 Stratigraphic column for western South Caspian depression

phenanthrene index. The sterane isomerization values are exceptionally low for most of the samples analyzed (Figure 9). This observation is not uncommon for Tertiary oils from rapidly depositing basins where insufficient time is present for complete sterane isomerization (Grantham, 1986). This single oil group is found in reservoirs as old as Miocene and as young as Upper Pliocene in the western South Caspian depression. The anomalous oil is from a Miocene elastic reservoir tested in the Sangachal-deniz # 551 well. This Sangachaldeniz # 55 1 oil is characterized by pristane to phytane ratios less than one, higher sulfur, increased C,,, normal alkanes (waxy), lower saturate hydrocarbon fraction, and severe volatile loss (missing C,-C,3) (Figure 5). This oil was sourced from a more restricted marine source facies containing some terrigenous input. The Sangachal-deniz # 55 1 oil was also generated prior to peak rate of generation (estimated to be VRE 0.95 for Type II marine source rocks) based on hydrocarbon composition, pristane to n-Cl7 ratio relative to phytane to n-Cl8 ratio, sterane isomerization %CZ9 20S/(20S+20R), Ts to Tm

ratio, relative amounts of moretane, and methylphenanthrene index (Figure 5). We believe this oil sample most likely represents a relatively unique localized source facies-reservoir relationship based on the evaluation of oils from many different fields and age reservoirs. All the oils sampled have relatively low sulfur contents, generally less than 0.50%. Marine source rocks are typically enriched in organic sulfur generating oils with sulfur contents in excess of 0.75%. An ‘excess’ amount of iron during deposition of the South Caspian depression source rock facies, which precluded sulfur incorporation into the organic matter, could account for the very low sulfur content in all the South Caspian basin oils. Or, possibly a more restricted landlocked setting where less SOd2- was present, as was salinity. Secondary alteration Biodegradation

Biodegradation is the alteration of petroleum by microorganisms (primarily bacteria) usually in association with

Geochemical evaluation of hydrocarbons:

Michael A. Abrams and Akif A. Narimanov

AZERBAIJAN

KURA BASIN

TURKMENISTAN

I

-----+-

semi

CASPIAN SEA

455

!CASPIAN BASIN

L

I

IO

VE: 10X

INDEX MAP

LEGEND

Scum Facie8 II - Marine, on Prone III - Terresttial.Gas Prone

?? OU(6 Condensate,or Gas) Field Figure 3 Cross-section

across Southwest

Caspian depression.

meteoric, sodium-sulfate-rich waters at temperatures below 80-90°C. Biodegradation is evidenced by a number of progressive effects including loss of normal paraffins and the development of a large unresolved hump on the whole oil gas chromatogram (Tissot and Welte, 1984). The near total loss of n-alkanes represents a relatively minor degree of biodegradation at a geochemical scale but has a huge impact on oil quality. Biodegradation is commonly associated with water washing which removes the more soluble hydrocarbons (chiefly the aromatics, benzene, and toluene and possibly the light paraffinic hydrocarbons) while fresh water flows through the reservoir . Several fields display biodegradation effects (up to and including near total loss of normal paraffins) including: Kalmas, Dashgil, Duvanny, Umbaki, and Adzhiveli Vost. Oil samples with partial loss of light-end n-paraffins and therefore more obvious concentrations of methylcyclohexane (MCH) and toluene, are also the result of early biodegradation (Figure IO). The microorganisms have begun to destroy the light-end n-paraffins, but not the more resistant aromatic compounds such as toluene, and MCH. Fields which show this partial biodegradation include Pirsagat, Kalmas, Garabag, Kyursangya, Bulladeniz, and Duvanny-deniz. Reservoir temperatures for offshore fields Bakhar (37-55”C), Bulla-deniz (S@-SYC), Duvanny-deniz (27-55”C), and Garasu (5 1“C) indicate reservoir temperatures for these fields are generally less than the 70-75°C bacterial cut-off and thus bacterial

activity could be ongoing today. No water analyses were available to determine present day in situ water compositions. Fractionation Fractionation is the separation of distinct hydrocarbon phases in the reservoir due to pressure reduction from erosion or fault movement, or the introduction of a gas charge (Thompson, 1987). Residual oils exhibit significant loss of the volatile fraction (C,-C,), with the remaining light hydrocarbons enriched in the higher boiling point light aromatic and naphthenic compounds. Several whole-oils display gas chromatogram traces with characteristics consistent with the residual fraction: Pirsagat, Bulla-deniz, and Garasu (Figure 6). The higher amounts of cyclohexane and other aromatic compounds in many of the western Southwest Caspian depression crude oil samples are believed to be due to evaporative loss or phase transformation, not a source facies with increased plant material. Multiple charge Several oil samples display characteristics consistent with more than a single charge event. The resulting reservoired oil displays a whole oil gas chromatogram indicating two or more separate and distinct times of hydrocarbon emplacement.

456

Geochemical evaluation of hydrocarbons:

Michael A. Abrams and Akif A. Narimanov

DUVANNY #516 MIDDLE PLIOCENE

RESERVOIR:

VIII SAND

24.36

16.41

12.46

.56

!

I

I

I

10.00

0.00

I

I

20.00

I

I

1 40.00

30.00

100000 STERANES

IL

20

30

100000 PENTACYCLIC TERPANES

80000

ti

80000

f s

60000

: 4

40000

60000 I 40000

20000

-

TRICYCLICS

II-

E 20000

-

20

30

40 TIME

Figure 4 Whole-oil gas chromatogram

60

60

70

SO

and 191 and 217 m/z ion fragmentograms

A Umbaki Field oil collected from the Miocene reservoir appears to result from an early charge of normal oil which was subsequently biodegraded (napthenic hump), followed by a second hydrocarbon charge of nondegraded crude (Figure Ila). The relatively large napthenic/unresolved hump, loss of high molecular weight alkanes, and degraded isoprenoids suggest a relatively high level of biodegradation (level 4, Alexander et al., 1983) yet the lower boiling point normal alkanes, which are normally the first compounds to be degraded, are present. The lower boiling point normal alkanes should not be present at this stage of biodegradation suggesting these hydrocarbons came after the initial biodegradation. The identification of more than one charge is usually very difficult. The most recent charge must be in small enough volumes as to not overwhelm the previous charges. The Umbaki oil is located onshore within a Miocene reservoir where later charges from younger sources would be limited. A Kyursanga Field sample oil collected from the Middle Pliocene reservoir suggests a low maturity oil mixed with a higher gravity oil (Figure Ilb). The high molecular weight compounds; high pristane to n-C,,, high phytane to n-C,,, and hopanes/sterane signature on whole-oil gas chromatogram, indicate a low maturity oil whereas the low molecular weight compounds indicate a higher temperature or different source facies contribution. The two different signatures would suggest a two phase charge. A similar signature could also be the result

40 TIME

(min.)

50

60

(min.)

for major oil group, western South Caspian depression.

of fractional condensation, phase separation migration to the trap then recombination.

during

Gas evaluation Mud volcano and hydrate gases

Dadashev and Guliev (1989) examined gas composition and isotopic ratios of methane (C,) and carbon dioxide (CO,) from several onshore mud volcanoes. Their results indicate the hydrocarbon gases are sometimes thermal in origin and sometimes biogenic. They can be divided into three distinct groups on the basis of methane and carbon dioxide stable carbon isotope ratios. The first group (Group I) includes Abikha, Uchtepe, Akhtarma, and Karadag volcanoes (Xl3 - 35.9 to -41.5%0); the second group (Group II) includes Shorbulak, Gekmaly, Bozdag, Kobiisk, and other volcanoes (6C” -44.6 to -46.6%0); and the third group (Group III) includes the Bog-boga and Kirmaku volcanoes (6C” - 55 to - 60%0). The first two groups of mud volcano gases have been interpreted by Guliev and Feizullayev (1996) to be thermal in origin based on the isotopic ratios of methane and carbon dioxide, and the amounts of ethane (C,) to butane (C,) relative to methane (C,). The Group I gases appear to have a higher temperature origin than Group II gases based on the isotopic ratios of methane. The heavier isotopic ratios of the Group I gases could also be due to differences in the isotopic ratios of original source organic matter and/or secondary alterations (bacterial alteration). The Group

Geochemical evaluation of hydrocarbons:

457

Michael A. Abrams and Akif A. Narimanov

SANGACHAL RESERVOIR:

DEN12 #!%I MIOCENE

12.09

9.42

1.42

;

I

I

0.00

I

10.00

I

I

I

I

I

20.00

40.00

30.00

120000 140000 s z 2

100000

f

60000

80000

PENTACYCLIC TERPANES

STERANES & DIASTERANES

60000 i

s 20000 0 20

30

40 TIME

Figure 5 Whole-oil

50

60

70

30

20

80

gas chromatogram

and 191 and 217 m/z ion fragmentograms

III data show that the gases formed biogenically or at the very earliest stages of burial. Ginsberg et al. (1992) collected submarine hydrates in the South Caspian Sea. They concluded waters associated with mud volcanoes played a key role in hydrate formation. The hydrates are postulated by them to be due to the discharge of gas-saturated formation waters and gases at sites exposed by erosion. The hydrate gases are enriched in ethane (C,) to butane (C,) homologs relative to onshore mud volcanoes gases. The high abundance of these heavier homologs (12.2% and greater), isotopic ratios of methane 6C13as heavy as -44.8%0, and association with oil seepage suggest the gas is of thermal origin.

60

(min.)

#551 oil sample.

Some isotopic ratios of methane as light as W3 - 57.3%0 could be the result of thermogenic gases mixing with shallow bacterial gas from the biodegradation of oil seepage. Reservoired gases Natural gases occur in a variety of environments. Bacterial processes form gases in continental swamps and marine sediments. Such gases are almost exclusively methane, which is isotopically light, and not associated with oils. In deeper strata, natural gases are formed by

EVAPORATIVE

SAMPLING LOSS

BULLA DFSHDRE 14 ADB MID. PLIDCENE V

for Sangachal-deniz

50

40 TIME

(min.)

FRACTIONATION

8.28

AOE: “ID. PLIDCENE VII

7.77

VOLATILE

10.23

6.25

4.74

3.23

i

1.72 i 0.W

Rgure 6 Differentiation

between volatile loss caused by sampling/storage

,

, 5.M)

,

, 10.00

(a) and evaporative

I 15.0

I

I 20.M)

I

fractionation

I I 25.02

(b).

I 2mO

I

I, 35.00

40.00

458

Geochemical evaluation of hydrocarbons:

Michael A. Abrams and Akif A. Narimanov

Geochemical evaluation of h ydrocarbons: Michael A. Abrams and Akif A. Narimanov

459

EXAMINATION OF ISOTOPIC COMPOSITION OF RESERVOIRED CRUDE OILS Isotopic -28.5

-28

Composition -27.5

-27

of Aromatic

-28.5

-26

-25.5

Fraction -25

-24.5

m

- ..-_.._ .___. _..__.._

I

rorcmmirad

Dlinrmnl~

nils

-23.5

A Miocene & older reservoired oils

0" P. z

-24.5

-25.5

s D E: I. =t 0 J

0 G -26.5

z 2 ip"

n -27.5

2 Z

0 Lower Maikop -28.5

Figure 8 Cross plot isotopic composition and aromatic fraction data.

of saturate and aromatic fraction for oils with rock extract isotopic composition

processes of thermal alteration of organic matter in source rocks and/or the thermal destruction of petroleum. Gases formed by thermal processes have a greater amount of wet components (C,,) and are isotopically heavier. Secondary processes can radically alter the original molecular composition as well as the isotopic composition (James, 1990). The gas samples analyzed in this study are predominantly hydrocarbon gas with less than 1.0% nonhydrocarbon gas (CO, and N2). No H&S was detected. The hydrocarbon portion (air free basis) ranges 91.C~ 98.0% for methane, 0.4&4.20% for ethane, 0.20-1.60% BIOMARKER

for propane, 0.02-0.40% for normal-butane, O.OO-0.30% for normal-pentane, and [email protected]% for hexane plus hydrocarbons. The wetness index [(C,-C&-C,) x 1001 ranges from less than 1.0% to 7.20%. The isotopic composition of methane ranges from 6C” - 55.0 to 36.3%0. Using the various published gas interpretation schemes by James (1983, 1990), Schoell (1983) and Stahl (1977) we believe the bulk of reservoired gases examined in this study have been sourced from mixed terrestrial-marine kerogen (Type III-II) generated at VRE 0.80-1.00 with some notable exceptions (Figure Z2). Several samples may have been generated at slightly higher temperatures and

MATURATION

CROSS

PLOT

:-^-I 0.3 -

.

.

F 0.2 -

. . .

. . 0

i 0

Figure 9 Biomarker maturation

??? ?? ?

? ?? ?

.

.

0.1 -

.

I

I

I

I

I

I

0.1

0.2

0.3

0.4

0.5

0.6

cross plot (TAS, tri-aromatic

of saturate

STERANE 20s/20r steranes, versus sterane 2OS/2OR).

I

0.7

460

Geochemical

evaluation

of hydrocarbons:

Michael

A. Abrams

and Akif A. Narimanov

3.00

lJHBAKl~21 YAIKOP

MAIKOP 0.65

t

6.71 3

6.67

4.42

2.26

;

I

0.00

I 10.00

I

I

I

20.00

10.97

I

I

30.00

40.0

SANGACHAL DEN12 381 MID. PLIOCENE Y

9.10

7.23

5.36

3.49

I.661

1.63 30.00

20.00

10.00

0.00

9.06

MID.

DASHOIL PLIOCENE

,

15 VII I

6.63

5.13

4.69

4.56

3.76

3.20

2.61

;

0.00

I

I 10.00

Figure 10 Biodegraded

I

I 20.00

I

I 30.00

1.67

I 40.00

I

I

I

10.00

I

I

20.00

I

I

30.00

40.00

6.67

7.59

1.73

{

0.00

IO

4(

;

0.00

I

I 10.00

I

I 20.00

I

I 30.00

I 40.00

oils, western South Caspian depression.

a single gas sample from a Sabail exploration test possibly reflects a low maturity and bacterial gas mix (Abrams and Narimanov, 1994). The isotopic and compositional data provided in this study do not support thermal cracking of marine sourced oils into gas. In addition, the data do not support a significant biogenic-low temperature or high temperature contribution, although there is evidence of some limited bacterial and low temperature contribution.

Geochemical evaluation of potential source rocks Rock samples were collected from onshore and offshore conventional core subsamples and outcrops to identify key source facies present in the western South Caspian depression. The rock samples range in age from Upper Cretaceous to Middle Pliocene. These rock samples do not properly represent all probable organic facies due to poor core recovery and limited penetrations below the Pliocene preventing extensive sampling of most older facies.

Eocene and Upper Cretaceous

The Upper Cretaceous is believed to be a deep marine facies composed of mottled elastic and detrital-carbonate flysch deposits (Clarke, 1993). None of the Upper Cretaceous rock samples contained total organic carbon greater than 1.O%. Bailey et al. (1996) identified potential source rocks in the Late Cretaceous which may be related to several surface oil seeps. Several Eocene core samples from onshore Lower Kura area did contain sufficient total organic carbon and elevated hydrogen indices to be classified as a potential source rock (Figure 13). The molecular characteristics of Eocene rock extracts are consistent with a low-maturity siliclastic algal-bacterial mix deposited in an anaerobic marine environment: high saturate to aromatic ratio, low sulfur content, pristane greater than phytane, high pristane to n-C,, and phytane to n-C,, ratios, low tricylic terpanes, C,, tetracyclic terpane greater than C,, tricyclic, high C,, to C,, homohopane ratio, diasterane to regular sterane ratio greater than one, C,, hopane much less than the CzOhopane, hopane to sterane ratio between 2 and 3, moretane present, oleanane present, Cl7 slightly less than

Geochemical evaluation of hydrocarbons:

26.16

Michael A. Abrams and Akif A. Narimanov

rich algal source rock (Clarke, 1993). Published source rock data, as well as the rock samples collected in this study, all demonstrate the Oligocene to Early Miocene (Maikopian) fine grain rocks from the onshore Lower Kura contain sufficient total organic carbon content and elevated hydrogen indices to be classified as good oilprone source rocks (Figure 13) (Piggott et al., 1996; Javadova et al., 1996; Bailey et al., 1996). Geochemical characteristics of selected organic rich immature Oligocene-Early Miocene core samples indicate a low-maturity siliclastic algal-bacterial mixture deposited in a reducing marine environment. Extracts display the following molecular characteristics: sulfur content greater than l.O%, low normal paraffins, high isoprenoid compounds, pristane greater than phytane, pristane and phytane much greater than n-C,, and nC8, low tricylic terpanes, high C,,/C,, homohopane, low diasteranes to regular steranes, Cz9 hopane much less than the Co hopane, high concentrations of moretane, low hopane to sterane ratios, oleanane present, isotopic composition of saturate fraction 6C13 - 28.0 to - 29.0%, and isotopic composition of aromatic fraction 6C3 -27.0 to -28.0%0 (Figure 14). In addition, pyrolysates for selected Oligocene-Early Miocene rock samples have relatively high concentrations of paraffinic compounds which decrease rapidly with increasing carbon number, alkene/alkane doublets up to Co, lower concentrations of aromatic compounds such as toluene, xylenes, and naphthalenes, and lower concentrations of polar compounds (phenols, creasols . etc.) indicating these source rock samples will yield large volumes of liquid hydrocarbons and little gas. Activation energies for selected organic-rich immature Oligocene-Early Miocene rock samples range between 47 and 64 kCa1 mol-’ with sample medians between 53 and 57 kCa1 mol-‘. A single Muradkhanaly well sample did contain slightly different energy activation distribution (5664 kCa1 mol-‘). This higher value is most likely due to the elevated organic maturity (VRE 0.680.78; estimated from T,,,). Hydrocarbon generation cal-

I

LOW

MATURITY

OIL

16.02

.76 20.00

10.00

0.00

30.00

40.00

Figure 11 Examples of multiple charge oils: (a) Umbaki Field and (b) Kyursangya

Field.

Cz9sterane, isotopic ratio of saturate fraction 6C” - 28.0 to -29.0, and isotopic ratio of aromatic fraction 6C13 -27.0 to -28.0%0 (Figure 24). Oligocene-Early

Miocene

(Maikopian)

During the Oligocene to Early Miocene further collisions of micro continents with Eurasia resulted in the formation of a restricted back-arc basin with stagnant conditions conducive for the accumulation of an organic-

CROSS-PLOT OF DELTA ETHANElPROPANE 81WETNESS VRE:0.65*

VFtE=1.25*

LOW MATURITY

MOREALGAL t

t

J.

+

?

LESS ALGAL (MORE HUM/C)

.

1.

I -

. .

.

. . .

. I. .

. +. ??

.s

9

----.

-6

-4

461

-3

Delta Elhane and Ropsne IkotopicCampMon

Figure 12 Organic maturity and source facies evaluation for selected gas samples.

ViETNESSCP'%

462

Geochemical evaluation of hydrocarbons:

Michael A. Abrams and Akif A. Narimanov

FOR ROCKS WITH TOC> 0.75% 1000

s

,

800 -

L

2

s

3

500

?? 400

-

soURoCE

POOR SOURCE

0

Q

@

00 300 -

Q

A g $

f

GOOD

-

P zi 8

EXCELLENT SOURCE

600 -

??Diatom Suite-Upper

4 200 -

@

Miocene

Upper Maikoplan

@I Mlddle Malkopian

&

0

NON SOURCE

POOR

0

0

Early Maikoplan

;

h&c.pianUnd,,,e,entiated

A

Eocene

(Oligocene-Miocene)

SOURCE

_

MEASURE&OTAL NOTE: Pm PIIoEme *.ctbm penetr.tell I” Df‘*hOm lwJ”

not ama.

Figure 13 Cross plot total organic carbon and hydrogen

0 Rock

orgmlc

ORGANIC CARBON (WT%)

Maturity

index for samples

culated from kinetic measurements on these OligoceneEarly Miocene rock samples is similar to typical Type II marine source rocks (Tissot and Welte, 1984). This would indicate the Maikopian source rocks do not generate hydrocarbons at lower levels of thermal maturity. Middle and Late Miocene By Late Miocene, the South Caspian was an enclosed seaway semi-isolated from marine influences. The sedimentation consisted of alternating marine and non-marine deltaic, turbidites and flysch/molasse (Clarke, 1993). Several Middle and Late Miocene core samples analyzed in this study contain total organic carbon and hydrogen indices indicating good source potential as well as poor source potential (Figure 13). Recent studies by Piggott et al. (1996), Rinaldi (1996) Bailey et al. (1996) and Javadova et al. (1996) have reported similar results. The molecular characteristics of the higher quality Middle and Late Miocene rock extracts are similar to the Late OligoceneeEarly Miocene rock extracts except in the isotopic composition of saturate aromatic fractions. The Middle and Late Miocene rock extract saturate and aromatic carbon isotopes are less enriched in carbon 13 relative to carbon 12 by approximately 24 per mil (Figure 9). Pyrolysates from a single Diatomaceous Suite rock sample have relatively high concentrations of paraffinic compounds, lower concentrations of aromatic compounds, and lower concentrations of polar compounds indicating good potential to yield liquid hydrocarbons. The relative amount of paraffinic compounds to aromatic and polar compounds shifts slightly indicating a less reducing environment and therefore slightly more gas prone character. Pliocene to Pleistocene The Pliocene to Pleistocene sediments are represented by flysch/molasse and marginal marine to non-marine deltaic sediments (Clarke, 1993). All of the Pliocene (Middle) core samples collected for this joint study con-

Less

Than

YRE

0.55

with total organic

carbon greater than 0.75%.

tained total organic carbon (TOC) less than 1.O%. These low TOC values are consistent with the interpreted paleofacies (marginal to non-marine). Pyrochromatographic studies by Narimanov (1986, 1993) also indicated that the Pliocene contains limited source potential. Narimanov (1986, 1993) did note a slight increase in organic content in Lower Pliocene samples, but not a sufficient increase for the rocks to be classified as a good liquid prone source (1 .O% of total organic carbon).

Maturation evaluation Maturation measurements Estimates of organic maturity for core samples are based on T,,, and mean random vitrinite reflectance (R,). T,,,, is the temperature corresponding to maximum hydrocarbon generation during pyrolysis (S2 peak, Tissot and Welte, 1984). T,,,,, provides crude estimates of maturity for immature to mature samples, but not for overmature samples. T,,,,, for low TOC samples nearly always provides unreliable maturation estimates. Mean random reflectance values in oil (R,) measures the amount of incident light which is reflected from the surface of the coal maceral vitrinite. Histograms for multiple vitrinite reflectance measurements on individual macerals are examined to estimate the true in situ reflectance versus reworked populations. T,,,,, and R, data from three onshore wells indicate that the Miocene and younger section (less than 5000m) is immature at these ‘on-structure’ onshore locations (Figure 15). Peak hydrocarbon generation (R,, = 0.95, for a typical Type II marine source rock) probably occurs between 5000 and 5500m in the onshore areas. Insufficient maturation measurements are available to determine depths for peak oil generation in the offshore areas. Maturation data published by Korchagina et ul. (1988) for selected wellbores, outcrops, and mud volcanoes indicate that sufficient maturation for significant hydrocarbon generation will occur deeper than 700& 8000 m.

Geochemical

evaluation

of hydrocarbons:

Michael

A. Abrams

OLIGO-MIOCENE

EOCENE CORE Field / Well: Age: TOC: % S: HI: EOM:

r

and Akif A. Narimanov

Field I Well: TOC: % s: HI: EOM:

Muradkhanly 35 (4,495-4,500 m) U. Eocene 1.29% 0.26% 276 m g/gm 715 ppm

Ion 191.30

463

CORE

Muradkhanly 3 (2,760 m) 2.11% 1.12% 344 m g/gm 1705 ppm

Ion 191.30

30H

Pentacyclic Terpaner

Time (min.)

Time (min.)

I

Ion 217.30

20

30

40

50

60

Time (min.) Figure 14 Whole-bitumen Miocene core.

Maturation

gas chromatograms

Ion 217.30

Time (min.) and 191 and 217 m/z ion fragmentograms

models

The great depths to peak hydrocarbon generation and delayed timing of hydrocarbon generation in the offshore areas estimated by thermal models are due to non steadystate thermal conditions which result from rapid sedimentation (Abrams, 1996; Crews et ul., 1996). Burial

for core extracts: Eocene and Oligocene-

histories based on stratigraphic input from wells and seismic profiles for several sites demonstrate the rapid subsidence as well as complex histories (Figure 16). Sedimentation rates have been estimated to be as high as 2.9m per 1000 years in the South Caspian depression Upper Tertiary section (Groves et al., 1996). The Eocene to Middle Pliocene period displayed relatively constant

464

Geochemical evaluation of hydrocarbons:

Michael A. Abrams and Akif A. Narimanov TOTAL VITRINITE REFLECTANCE HISTOGRAMS

Iax

431 442 449 4% 0.5 1.0 1.5

1

I

DEPTH (m)

I

I

WELL: KERZEG KVLLVTEPE NO. 293 DEPTH: 2420-2425 METERS AGE: MIOCENE

.

.

VITRINITE REFLECTANCE

. WELL: KARADAG No. 352 DEPTH: 3198-3195 METERS AGE: MIOCENE

VITRINITE REFLECTANCE

WELL: KARADAG No. 391 DEPTH: 3200-3210 METERS AGE: PLIOCENE

VlTRlNlTE REFLECTANCE

Figure 15 Maturation profile, vitrinite reflectance (I?,,) and T,,,,.

sedimentationsubsidence, while subsidence increased in the Late Miocene to early Pliocene, followed by localized brief periods of uplift and erosion. Subsidence re-initiated in Middle Pliocene, with a dramatic increase in sedimentation rate, again followed by a brief period of uplift and erosion. Minimal subsidence and sedimentation in the Upper Pliocene and Early Quaternary was followed by a dramatic increase in subsidence and very late localized uplift and erosion. We used the Platte River Associates basin modeling program BasinMod to estimate current subsurface maturation and temperatures in areas where well penetrations are not sufficient to characterize the deeper Upper Oli-

BURIAL

HISTORY

gocene (lower Maikopian) source rocks. The estimated timing of hydrocarbon generation for an Upper Oligocene (lower Maikopian), Type II marine source was based on a 1-D basin model. We utilized a variable heat flow model with a slightly higher background heat flow prior to 8 my. The present day heat flow was calibrated to measured sub-surface temperatures, or estimated when no temperature information was available. Present day basal heat flow ranged 33.537.7mW m-* (0.8s 0.90HFU). In this paper we show results at two onstructure locations, Pirsagat located just onshore, and Bakhar located offshore. The maximum present level of organic maturation for

- PIRSAGAT Fm

0

Qaps 1wO f 2000

300

8

N2

4Do9

F P P

5000

Nl :I

DIATOM MAIKOP

EOCENE

60

50

40

30

TIME (Ma) Figure 16 Example of burial history, Pirsagat site.

20

10

0

Geochemical

evaluation

of h ydrocarbons:

Michael

A. Abrams

RATE OF HYDROCARBON

and Akif A. Narimanov

465

GENERATION

PIRSAGAT

BAKHAR 54 100 90

0.5 6 ,

: I

I

llllllllllllllll” 35

30

25

20

TIME

15

10

5

g

40

z2

40

70

50

%

.

3 5

308

iz c

5

80

I

30

d 8

20

v

10

5

e z

i?

0

(Ma)

I---

Figure 17 Rate of hydrocarbon

generation: (a) Pirsgat and (b) Bakhar.

the proposed Upper Oligocene source rock at the Pirsagat location is 0.75 VRE (Figure 17~). This corresponds to early, pre-peak oil generation for a Type II marine source rock. The Pirsagat modeling site shows two major pulses of hydrocarbon generation, one at 6 my, and the other at 2my. These two pulses result from burial, uplift, and subsequent reburial. The oil sample from the Pirsagat field also appears to display characteristics of a multiple charge although the mixture of hydrocarbons may be due to generation from two separate age source rocks and not a single source rock which is heated in two separate pulses of burial. Note that the discrete pulses of hydrocarbon generation found in our models may be an artifact of the inability of most thermal modeling programs to handle extreme burial rates-thermal transient effects and not actual separate phases of generation. The maximum present level of organic maturation for the proposed Upper Oligocene source rock at the Bakhar location is also 0.75 VRE (Figure 17b). This again corresponds to early, pre-peak oil generation for a Type II marine source rock. The Bakhar modeling site shows only a single pulse of hydrocarbon generation, as do the oil samples from this field. Off-structure maturation modeling sites, in the basinal deeps away from the uplifts, display suppressed (lower) temperatures when compared to similar depths on the corresponding on-structure site. We believe this is a consequence of non-steady state conditions. The sedimentation rates are extremely high in the off-structure areas relative to the on-structure sites. The rapidly deposited sediments do not have sufficient time to thermally equilibrate. Measured temperatures are much lower than those expected if equilibrium conditions were present (Figure 18). This difference between steady state and transient conditions requires greater depths off-structure before sufficient temperatures for hydrocarbon generation and delays the peak rate of generation, as compared to on-structure sites. This also allows liquid hydrocarbons to be generated and thermally preserved at much greater depths than would normally be expected.

COMPARISON OF STEADY STATE AND TRANSIENT TEMPERATURES BAKHAR 54 ON-STRUCTURE

20

40

TEMPERATURE 80 80 ml

BAKHAR

54

0

50

160

180

200

OFF-STRUCTURE

TEMPERATURE 2000

(DEG C) 120 140

100

(DEG 150

C) 200

250

4000

Figure 18 Differences surface temperatures.

between

steady state and transient

sub-

Hydrocarbon source evaluation There is much uncertainty about the key source or sources which generated the large volumes of oil and

466

Geochemicai

evaluation

of hydrocarbons:

gas currently reservoired in the western South Caspian depression. The limited number of organic-rich rock samples, similarity of organic facies from different age rocks, and lack of penetration beyond the Pliocene from offshore wells, preclude a conclusive hydrocarbon to source correlation. Early studies assumed the majority of hydrocarbons were sourced from the surrounding Middle Pliocene marginal marine and non-marine shales even though the concentration of organic matter is low due to the high sedimentation rates (Narimanov, 1986). It is our belief the western South Caspian depression oils have been sourced from a series of Oligocene to Miocene organic-rich marine shales. The onshore Miocene and older reservoired oils are most likely sourced from the early Maikopian organic-rich sections whereas the younger Middle Pliocene reservoirs are most likely sourced from the Middle-Upper Maikopian and possibly younger Diatomaceous organic-rich sections. The reservoired gases most likely have been sourced from a slightly more oxygenated organic-rich Middle to Late Miocene to possibly Early Pliocene marginal marine organic-rich shales. These conclusions are based on the following observations: 1. Oil source facies versus paleogeography: Oils are sourted from basinal restricted marine source facies (sapropelic). This restricted marine source facies existed throughout the Eocene to Middle Miocene and possibly as late as the early part of the Late Miocene, but not in the very Late Miocene to Early Pliocene and younger section. 2. Multiple source rocks within Lower Tertiary: Isotopic differences between Pliocene and Miocene and older reservoired oils reflect stratigraphically different source rocks with similar source facies characteristics. Oils within the onshore Umbaki 3. Oil to oil correlations: field, reservoired in Middle Miocene Chokrak rocks, have similar molecular characteristics and isotopic signatures as oils reservoired in the older Oligocene to Early Miocene Maikopian rocks. A Middle Pliocene sourced oil could not have migrated into both the Chokrak and Maikopian reservoirs, given our current understanding of the structural history. The bulk of 4. Gas source facies versus paleogeography: the gas has been derived from mixed marine organicrich source facies (more humic and less anoxic). Such a source facies with sufficient and correct type of organic matter only exists in the Middle to Late Miocene and Early Pliocene. 5. Middle Pliocene organic maturity: The level of organic maturity for the western South Caspian depression Middle Pliocene and younger section is insufficient to generate large volumes of hydrocarbons based on organic maturation measurements and thermal models. organic maturity: The level 6. Late OligoceneeMiocene of organic maturity for the western South Caspian depression Miocene and older section is sufficient to generate large volumes of hydrocarbons within the current hydrocarbon field drainage areas based on thermal models.

A. Abrams

and Akif A. Narimanov

discovery of significant hydrocarbon accumulations, is the product of unique paleogeographic and tectonic events. Paleogene deposition of organic-rich source rocks, rapid Pliocene subsidence, voluminous supply of elastic sediments for high quality reservoirs, and development of anticlinal traps form an active Tertiary hydrocarbon The system. multi-stage hydrocarbon emplacement from several different age organic-rich source rocks can be seen in the geochemical characteristics and hydrocarbon distribution and phase. Most of the oils examined in this study display similar organic source facies based on molecular characteristics. but also display a distinctive isotopic separation of the saturate and aromatic hydrocarbon fractions by reservoir age. A similar isotopic separation of the saturate and aromatic hydrocarbon fractions can be seen within the organicrich potential source rocks from the Lower, Middle, and Upper Maikopian and Diatomaceous suite rocks. This isotopic separation is most likely due to the varying contributions of oils from different age sources of similar organic facies. In addition. the bulk of the reservoired gases have been sourced from an organic facies different from the liquid hydrocarbons. These gases are not from the thermal destruction of the oils, but generated from a younger more gas prone source facies at conventional generating temperatures. Several of the oil samples display characteristics consistent with multiple phases of hydrocarbon charges. These different phases of hydrocarbon charge could have been the result of complex subsidence and uplifts noted in the burial histories, or charging from different source rocks as they undergo deeper burial and generation. The biodegradation of an initial oil charge and fractionation from later reservoir pressure depletion or the introduction of a gas phase provides additional evidence of the complex burial histories. The source rocks for the oils are postulated to be Oligocene to Miocene marine elastic shales based on oilsource correlations as well as our understanding of the paleogeography and geologic setting. The oil maturity appears to be lower than the conventional oil window. This lower than normal maturity could be the result of rapid expulsion from strong hydrodynamic forces and not lower than normal source rock activation energies, but also could be due to anomalously high heating rates. The bulk of the reservoired gas is believed to be sourced from Middle to Late Miocene mixed marine shales. There is some evidence of limited mixing with early formed gas (biogenic-low maturity). But we did not see any evidence of thermal cracking of liquids into high temperature gas. The three key events critical in the formation of hydrocarbon accumulations in the western South Caspian depression are as follows; first the deposition of excellent source rocks in the Late Oligocene to Late Miocene, second the Middle Pliocene increased subsidence which drives the early maturation-hydrocarbon charge, structuring, and deposition of the major reservoir system, and lastly, the Late Quaternary increased subsidence which drives the late hydrocarbon charge and re-distribution of hydrocarbons.

Acknowledgements

Conclusions The South Caspian carbon accumulations

Michael

Basin with its world class hydroand great potential for the future

The authors thank Exxon Exploration Company, Ventures (CIS) Inc., and SOCAR for permission

Exxon to pub-

Geochemical

evaluation

of hydrocarbons:

lish this study. The authors also thank Bernie Vining, James Siegmann, Mary Jo Klosterman, Fikret Dadashev, Nadir Giyasov, Kyamran Agaev, and John Ruehlman who assisted with sample collection and geological discussions. Quentin Ballard, Nadia Patent, Greg Berg, Glenda Farris, and especially Ted McReynolds provided technical support. Conventional oil and rock analyses were preformed at Core Laboratories. Special analyses and gas compositional/isotopic composition were performed at Exxon Production Research Company. Glenn Hieshema (EPR) did the GC-MS-MS and Dave Curry (EPR) the kinetics/P-GC analysis. Allen (W.A.) Young, K. 0. Stanley, and Jim Allan provided technical consultations. We would like to thank BP for providing several rock samples. The manuscript was reviewed by W. A. Young, G. M. Gaskins, George Ramsayer, and Steve Creaney. We would also like to thank the Marine and Petroleum Geology reviewers, Neil Piggott and Barry Katz, and editor, D. G. Roberts for providing excellent editorial assistance.

References Abrams, M. A. (1996) Geochemical artifacts of rapidly-subsiding basins: example western part of the South Caspian Sea. In AAPG/ASPG Research Conference, Oil and Gas Petroleum Systemsin Rapid/y-Subsiding Basins, Baku, Azerbaijan, October 6-9, 1996. Abrams, M. A. and Narimanov, A. A. (1994) Petroleum systems of the Southwest Caspian Basin. In AAPG/AMGP Research Conference, Geological Aspects of Hydrocarbon Systems, Mexico City, Mexico, October 2-6, 1994. Alexander, R., Kagi R. I., Woodhouse G. W. and Volkman J. K. (1983) The geochemistry of some biodegraded Australian Petroleum Exploration Association Journal oils. Australian 23,53-63. Allan, J. and Creaney, S. (1991) Oil families of the Western Canada Basin. Bulletin of Canadian Petroleum Geology 39(2), 107-122. Bailey, N. J., Guliyev, I. and Feizullayev, A. A. (1996) Source rocks of the South Caspian. In AAPG/ASPG Research Conference, Basins, Oil and Gas Petroleum Systems in Rapid/y-Subsiding Baku, Azerbaijan, October 6-9, 1996. Clarke, J. W. (1993) Observations on the geology of Azerbaijan. international Geology 35, 1089-1092. Crews, S. G., Bulling, T. P., Corrigan, J., Franks, S. G., Gordon, S. A., Greenberg, M. L., He, Z. and Nedland, D. E. (1996) Geohistory, thermal, and hydrocarbon generation modeling in rapidly subsiding basins: examples from the South Caspian Basin and China Seas, southern California, Gulf of Mexico, and Cook Inlet. In AAPG/ASPG Research Conference, Oil and Gas Petroleum Systems in Rapid/y-Subsiding Basins, Baku, Azerbaijan, October 6-9, 1996. Dadashev, A. A. and Guliev, I. S. (1989) Isotopic composition of carbon in methane from mud volcanoes as an indicator of the conditions of formation and the preservation of gases at depth in the South Caspian Basin. In lzvestiya Akademii Nauk Azerbaidzhanskoi SSR. Ser. Nauk o Zemle 1, pp. 7-12. Ginsberg, G. D., Guseynov, R. A., Dadashev, A. A., Ivanova, G. A., Kazantsev, S. A., Solov’yev, V. A., Telepnev, E. V., Ye Askeri-Nasirov, R., Yesikov, A. D., Mal’tseva, V. I., Mashirov, Yu. G., Shabayeva, I. Yu. (1992) Gas hydrates of the South Caspian. International Geology Review 34(8), 765-782. Grantham, P. J. (1986) Sterane isomerization and moretane/ hopane ratios in crude oils derived from Tertiary source rocks. Organic Geochemistry9,293-304. Groves, J. R., Stein, J. A., Babazade, A., Koshkarly, R. 0. and Mamedova, D. N. (1996) Biostratigraphic and isotopic evidence for determining rates of rock accumulation within the Productive Series of Eastern Azerbaiian. In AAPG/ASPG Research Conference, Oil and Gas Petroleum Systems /n Rapidly-subsiding Basins, Baku, Azerbaijan, October 6-9, 1996. Guliev, I. S. and Feizullayev, A. A. (1996) Geochemistry of hydrocarbon seepages in Azerbaijan. In Near Surface Expression

Michael

A. Abrams

and Akif A. Narimanov

467

of Hydrocarbon Migration, eds. Schumacher and Abrams, AAPG Memoir 66,63-70. James, A. T. (1983) Correlation of natural gas by use of carbon isotopic distribution between hydrocarbon components. Bulletin of the American Association of Petroleum Geologists 59, 986-996. James, A. T. (1990) Correlation of reservoired gases using the carbon isotopic compositions of wet gas components. Bulletin of the American Association of Petroleum Geologists 74, 1441-1458. Javadova, A., Rinaldi, G. and Narimanov, A. A. (1996) Petroleum geochemistry of offshore western South Caspian. In AAPG/ ASPG Research Conference, Oil and Gas Petroleum Systems in Rapid/y-Subsiding Basins, Baku, Azerbaijan, October 6-9, 1996. Klosterman, M. J., Abrams, M. A., Aleskerov, E., Abdullayev, E., Guseinov, A. N. and Narimonov, A. A. (1997) Hydrocarbon Systems of the Evlak-Agdzhabedi Depression, Azerbaijan. Azerbaijan Society of Petroleum Geologist Bulletin 1,89-l 18. Korchagina, Yu I., Guliev, I. S. and Zeinalova, K. S. (1988) Hydrocarbon source potential of deeply buried Mesozoic and Cenozoic deposits of the South Caspian Basin. In Problems in the Oil and Gas Content of the Caucasus, Nauka. UDC 553.98f470.24). Nadirov, R. S. (1990) Criteria of zonal forecast of oil content in deep depths of the Western Part of South Caspian oil and gas basin. In Criteria and Methods for Predicting Oil Content in Great Depths. USSR Ministry of Geology Research Institute of Oil Prospecting (VNIGRI), Leningrad (in Russian). Narimanov. A. A. (1986) Time of formation of oil and gas pools in the South Caspian Region. international Geology Review, pp. 69-73. Narimanov, A. A. (1993) The petroleum systems of the South Caspian Basin. In Basin Modeling: Advances and Applications, eds. Dore et a/. NPF Special Publication 3, pp. 599608. Narimanov, A. A. and Palaz, I. (1995) Oil history, potential converge in Azerbaijan. Oil and Gas Journal, May 22, 1995, pp. 32-39. Piggott, N., Smith, M. S., Simmons, M. D., Sharland, P. and Bar-wise, A. G. (1996) Petroleum Systems in the South Caspian. In AAPG/ASPG Research Conference, Oil and Gas PetBaku, in Rapid/y-Subsiding Basins, roleum Systems Azerbaijan, October 6-9, 1996. Rinaldi, G. (1996) Evolution of organic source facies during the development of divergent margins and its significance to petroleum exploration. In AAPG/ASPG Research Conference, Oil and Gas Petroleum Systems in Rapid/y-Subsiding Basins, Baku, Azerbaijan, October 69, 1996. Ruehlman, J. F., Abrams, M. A. and Narimanov, A. A. (1995) The oetroleum svstems of the West South Casoian Basin. In AAPG ‘Convention Abstracts, Houston, Texas, March, 1995. Schoell, M. (1983) Genetic characterization of natural gases. Bulletin of the American Association of Petroleum Geologists 67(12), 2225-2238. Stahl, W. J. (1977) Carbon and nitrogen isotopes in hydrocarbon research and exploration. Chemical Geology20, 121-149. Tissot, B. P. and Welte, D. H. (1984) Petroleum Formation and Occurrence. Springer, New York, p. 699. Thompson, K. F. M. (1987) Fractionated aromatic petroleums and the generation of gas-condensates. Organic Geochemistry 11.573-590.

Analytical program Oil analysis

The State Oil Company of Azerbaijan Republic (SOCAR) provided crude oil samples collected from exploration wells and stored in bottles until sub-sampled. Many of the oil samples display deterioration which may have occurred during sampling, handling, or storage. Insufficient data are available to determine the extent or exact cause of volatile loss. Whole oil gas chromatograms were run on a Varian 3400 using a temperature program of 12°C min’ from 0

468

Geochemical

evaluation

of hydrocarbons:

to 350°C. Another aliquot of each crude oil was evaporated at 40°C under nitrogen. The asphaltenes were precipitated with pentane then refrigerated and centrifuged. The de-asphalted portion was dried at 40°C. The column was prepared using a 10&200 mesh silica gel grade 923 under ambient pressure and temperature utilizing a gravimetric procedure. The isolated saturate and aromatic hydrocarbon fractions were analyzed by gas chromatography-mass spectrometry on a HP 5971 MSD/5890 II GC using a temperature program of 100°C held for 20s 20”C/min to 170°C 1.5”C min-’ to 290°C 2°C min’ to 340°C and 5min hold. For the aliphatic steranes, ions were monitored at m/z 217, 218, and 259 while m/z 177, 191, and 205 ions were monitored for tricyclic and pentacyclic triterpanes. Known standards were used to identify and quantify key compounds. Gas analysis

Gas samples were collected from the production wellhead using 300-cm3 seamless stainless cylinders at or near well-head pressures. Individual gas components were separated and analyzed at Exxon Production Research Company using conventional gas chromatography methods. The stable isotopic composition of individual components were analyzed using a VG903 massspectrometer. Rock analysis

SOCAR provided subsamples of conventional core samples. Each rock sample was analyzed for total organic

Michael

A. Abrams

and Akif A. Narimanov

carbon (TOC) with a LECO analyzer. Rock-Eva1 pyrolysis was then run on samples with TOC greater than 1.O%. Rock samples with sufficient quantity and quality of organic material were extracted for the study of soluble organic matter (SOM). Approximately 5&100 g of powdered rock material was placed in a pre-extracted thimble and extracted using methylene chloride for a period of 24 h. The extracts were then analyzed by the same procedures enumerated above for the oils using gas chromatography (GC), high pressure liquid chromatography (HPLC), 6C3 saturate and aromatic fractions (isotopic composition), and gas chromatography-mass spectrometry (GC-MS and GC-MS-MS). Selected samples were chosen for hydrocarbon generation kinetics evaluation. Kinetic analysis was performed on a temperature calibrated Pyromat II. Splits of each sample were pyrolyzed at five linear heating rates between 1 and 50°C min-‘. Resulting pyrolysis data were then analyzed using the Lawrence Livermore National Laboratory computer program, ‘KINETICS’ to determine the kinetic parameters most consistent with the data. Calculated kinetic parameters include the distribution of activation energies and a single frequency factor (A factor). Pyrolysis-gas chromatography (PGC), the analysis of volatile products from thermally decomposed organic-rich rock samples was also performed on a portion of the sample suite. The pyrolytic products are trapped and their compositions analyzed using conventional gas chromatography to separate and identify compounds.