abd el gawad-shushan

191Journal of Petroleum Geology, Vol. 31(2), April 2008, pp 191-212

© 2008 The Authors. Journal compilation © 2008 Scientific Press Ltd

GEOCHEMICAL CHARACTERIZATION OF POTENTIALJURASSIC / CRETACEOUS SOURCE ROCKS IN THESHUSHAN BASIN, NORTHERN WESTERN DESERT,EGYPT

A. S. Alsharhan* and E. A. Abd El-Gawad*+

Some 180 core and cuttings samples of shales and limestones from the Middle Jurassic – LateCretaceous succession (Khatatba, Masajid, Alam El-Bueib, Alamein, Kharita, Bahariya and AbuRoash Formations) were collected from wells Ja 27-2, Tarek–1 and Jb 26-1 in the central, structurally-low part of the Shushan Basin and from well Lotus-1 in the structurally-elevated western part ofthe basin. All samples were screened for total organic carbon (TOC) content. Selected sampleswere then analyzed by Rock-Eval pyrolysis, and extracted for biomarker analyses. Visual kerogenanalysis and vitrinite reflectance measurements were also undertaken and oil - source rockcorrelations were attempted. The results indicate that the thermal maturity of the samples can becorrelated closely with burial depth. Samples from the central part of the basin are more maturethan those from the west. Samples from the central part of the basin (except those from theAlbian Kharita Formation) have reached thermal maturities sufficient to generate and expel crudeoils. Extracts from the Middle Jurasic Khatatba and Early Cretaceous Alam El-Bueib Formationscan be correlated with a crude oil sample from well Ja 27-2.

In well Lotus-1 in the west of the basin, four distinct organic facies can be recognized in theJurassic-Cretaceous interval. One of the facies (“facies 4”) has a sufficiently high TOC content toact as a source rock. Thermal maturities range from immature to peak oil generation, and the topof the oil window occurs at approximately 8000 ft.

* Geology Department, Faculty of Science, UAEUniversity, Al-Ain, PO Box 17551, UAE.+ author for correspondence, email:

[email protected]: Jurassic/Cretaceous, source rocks, ShushanBasin, Western Desert, Egypt.

INTRODUCTION

Perhaps 90% of undiscovered oil reserves and 80%of undiscovered gas reserves in Egypt are located inthe Western Desert (Zein El-Din et al., 2001). Recenthydrocarbon discoveries have been made in the AbuGharadiq Basin (Fig. 1), and the Shushan Basin tothe NW is also thought to have significant explorationpotential although many areas are virtually untestedby the drill. Exploration here began in 1967 whenWestern Egypt Petroleum Company (WEPCO) drilledwell Minqar-1, since when numerous wells have beencompleted.

The NE-SW trending Shushan Basin is locatedwithin the so-called “Unstable Shelf” (c.f. Said, 1962).The basin is bounded to the north by the Umbarka

Platform and to the south by the Qattara Ridge, andsubsided in the Late Jurassic and Early Cretaceous inresponse to the opening of Neo-Tethys. Subsidenceand sediment deposition took place throughout mostof the Cretaceous and up to 7000 ft of UpperCretaceous strata were deposited. The Shushan Basinappears to be one of a group of similar extensionalbasins but may be related to a pre-existing rift; it maytherefore be a composite pull-apart basin (SSI, 1990).

The source rock potential of the Shushan Basin islargely unexplored since the deepest wells havegenerally reached only 10,000 ft, and the pre- MiddleJurassic section is therefore poorly known. However,the Middle Jurassic Khatatba Formation includes bothsandy reservoir intervals and organic-rich shales withsource rock potential. Potential seals include themassive carbonates of the Upper Jurassic MasajidFormation (EGPC, 1992).

192 Potential Jurassic/Cretaceous source rocks in the Shushan Basin, NW Egypt

Geological setting and stratigraphySultan and Abdel Halim (1988) proposed that theMesozoic-Cenozoic succession in the northernWestern Desert (including the area of study) can bedivided into four unconformity-bound cycles (Fig. 2),each terminated by a marine transgression. The earliestcycle consists of Early Jurassic non-marinesiliciclastics (Ras Qattara Formation) which restunconformably on the Silurian basement and whichare overlain by the mid-Jurassic Wadi Natrun andKhatatba Formations. The Khatatba Formation iscomposed mainly of shales and sandstones with coalseams and minor limestones which become moreabundant northwards. These sediments are interpretedto have been deposited in a deltaic environment.During the Late Callovian, shallow-marine carbonatesof the Masajid Formation were deposited andrepresent the maximum Jurassic transgression. TheMasajid Formation was either eroded from, or wasnot deposited on, parts of the north Qattara Ridge andUmbarka Platform although continuous marinesedimentation occurred in the Matrah sub-basin andthe Sidi Birrani area.

A major unconformity separates the MasajidFormation from the overlying Alam El BueibFormation at the base of the second cycle, whose basalinterval is composed of Early Cretaceous shallow-marine sandstones and carbonates (Units 6 and 5).These are followed by a marine shale (Unit 4) and asuccession of massive fluviatile sandstones (Unit 3:Neocomian). Individual sandbodies are separated bymarine shales. The sands are overlain by thealternating sands, shales and shelfal carbonates ofUnits 2 and 1, culminating in the Alamein Dolomiteassociated with the Aptian transgression. The DahabShale marks the end of this cycle.

An unconformity separates the Dahab Shale fromthe Kharita Formation at the base of the third cycle,which extends from the Middle Albian to the latest

Cretaceous. The continental and shoreline sandstonesof the Kharita Formation are overlain by the shallow-marine and nearshore deposits of the BahariyaFormation (Early Cenomanian). A marked deepeningof depositional conditions is indicated by thedeposition of the Abu Roash “G” (Late Cenomanian).Widespread transgression occurred during theSenonian with deposition of the Abu Roash “F” to“A” (predominantly carbonates). The unconformably-overlying Khoman Chalk Formation was depositedin the northern Western Desert. The cycle is terminatedby an unconformity above which lies the EoceneApollonia Formation above which are the Dabaa andMoghra Formations (marine clastics) which arecapped by the Marmarica Limestone (Zein El-Din etal., 2001).

Structurally, the Shushan Basin is dominated byextensional and strike slip faults, mostly of Jurassicand Cretaceous age, which overprint the pre-existingnorth-south trending Palaeozoic framework. Mesozoicregional extension, associated with periods of dextraland sinistral shearing, resulted in the formation of aseries of block-faulted horsts and half-grabens as aresult of which the Jurassic to Turonian sectiongenerally dips and thickens to the north and east (Fig.3). The section is therefore structurally elevated inthe SW of the basin, whereas the north and east forma structural low.

The purpose of the present paper is to integratesubsurface data from the Shushan Basin with theresults of bitumen and kerogen analyses in order toidentify organic-rich intervals which may have sourcerock potential.

MATERIALS AND METHODS

Geochemical analyses were performed on 180samples (cores and cuttings) of shales and limestonesfrom the Khatatba, Masajid, Alam El-Bueib, Alamein,

100 km

SiwaOasis

BahariyaOasis

BirqetQarun

NileDelta

MatruhSTUDY

AREA

WESTERN DESERT

A Y

B I LT

P Y

G E

W E S T E R N D E S E R T

Abu Gharadig Basin

Natrun Basin

Gindi Basin

InteraB-sin

Alamein BasinShushan Basin

Matruh Basin

Ghazalat Basin

Faghur Plateau

Inter-Basin

A Y

B I L26o 28o 30o

30o

28o

Nile DeltaM E D I T E R R A N E A N S E A

Siwa Basin

T P

Y G E

MEDITERRANEAN SEA

INDEX MAP

QattaraDepression

Fig. 1. Location map ofbasins in the northernWestern Desert, Egypt(EGPC, 1992) includingthe Shushan Basin, thefocus of this paper.

193A. S. Alsharhan and E. A. Abd El-Gawad

Kharita, Bahariya and Abu Roash Formationscollected from four wells in the Shushan Basin. Thewells were (Fig. 3a) Ja 27-2, Tarek–1 and Jb 26-1,located in the central (structurally low) part of thebasin; and Lotus-1 located in the structurally elevatedpart of the basin to the west. These wells were selectedin order to investigate the effects of differential burialon the maturity of potential source rocks in theformations studied.

Analyses were performed by geochemicalcompanies including Gearhart (TOC and Pyrolysis),Exlog (visual examination) and Stratochem (GC andGC/MS) using standard techniques. All samples werescreened for total organic carbon (TOC) content.Samples with a TOC greater than 0.4% were analyzedby Rock-Eval pyrolysis. Twelve of the samples from

well Lotus-1 were selected for visual kerogen analysisand vitrinite reflectance measurements. A furthertwelve samples were extracted for bitumen analysisand biomarker studies.

Source rock characterization was as follows. About50 grams of each rock sample was crushed and passedthrough a 20-micron sieve, accurately weighed, andSoxhlet extracted for 16 hours with dichloromethane.The solvent was evaporated and the residue weighedto obtain the total organic extract. Asphaltenes wereprecipitated with hexane and the soluble fraction wasseparated into saturates, aromatics and resins (NSOcompounds) on a silica-alumina column by successiveelutions with hexane, benzene and benzene-methanol.The solvents were evaporated and the weight-percentof each component was determined. The saturate

M i o c e n e

O l i g o c e n e

E o c e n e

P a l e o c e n e

S e n o n i a n

C e n o m a n i a n

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U p p e r

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h s a o R

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A l a m E l B u e i b

M a s a j i d

K h a t a t b a

RasQattara

K o h l a

B a s e m e n t

BahreinNatrun

s u o e c a t e r

C e t a L

s u o e c a t e r

C y l r a Ec i s s a r

u J

Pre-Cambrian

PALEOZOIC

C I

O

Z

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M

C I O Z

O N E

C

ERA A G E FORMATION LITHOLOGY OIL/GASSHOWS

SOURCEROCK

+ + + + + + + + + + + + ++ + + + + + + + + + + +

Fig. 2. Composite stratigraphic column for the northern Western Desert, Egypt (EGPC, 1992).


Fig. 3. Structural setting of the Shushan Basin, Western Desert (structure contours at top-KhatatbaFormation). Fault pattern is inferred from seismic data.


Fig.4. Plot of HI versus Tmax for well Jb26-1, central Shushan Basin. Open circles: Abu Roash G, Bahariya andKharita Formations, 5130-5910 ft; black circles: Abu Roash G, Bahariya and Kharita Formations, 5970-6910 ft;open triangles: Upper Alam El-Bueib Formation, 8920-9430 ft; black triangles: Upper Alam El-BueibFormation, 9490-10,510 ft; open diamonds: Lower Alam El-Bueib Formation, 11,260-11,740 ft; black diamonds,Lower Alam El-Bueib Formation, 11770-11950 ft; + Upper Khatatba Formation, 12,160-13,050 ft).

Fig. 5. Burial history profile for well Tarek-1, central Shushan Basin.


fraction was analyzed with a gas chromatograph fittedwith a fused silica capillary column. Analytical datawere processed with a Nelson Analytical model 3000chromatograph data system. Standard calculationswere made including pristane / phytane ratio, carbonpreference index and other key parameters.

Computerized gas chromatography/massspectrometry (GC/MS) or biomarker analysis isutilized to evaluate biologically derived compoundsin oils or rock extracts (Peters and Moldowan, 1993).The saturate and aromatic fractions separated by liquidchromatography from whole oils or source rockextracts were injected into an HP5890 gaschromatograph coupled to an HP5971A MSD. TheSelected Ion Monitoring (SIM) capabilities of the dataacquisition system permitted specific ions to bemonitored, such as tricyclic terpanes and hopanes (m/z = 191) and steranes (m/z = 217) (Abd El-Gawad etal., 1996).

GEOCHEMICAL RESULTS

In the following section, results of geochemicalanalyses for samples from wells in the central,structurally low part of the basin are presentedseparately from results from well Lotus-1 in thestructurally elevated western part of the basin. Dataare presented in Tables 1-6 (pp 210-212).

Central Shushan BasinThe TOC of the Albian Kharita Formation ranges from0.17-2.13% and 1.98-5.5% for the Early CretaceousAlam El Buieb Formation. TOC for the MiddleJurassic Khatatba Formation ranges from 0.11-3.5 %.

Vitrinite reflectance in the basal unit of the AbuRoash Formation (Abu Roash “G” Member) was 0.4%.Ro for the Kharita Formation is 0.7-0.6%, indicatingthat it is early mature for oil generation; in theunderlying Alam El Bueib Formation, Ro ranges from0.7 to 1.3%, indicating that the formation is in the oilwindow. The Middle Jurassic Khatatba Formation hasa maximum Ro of 1.45% indicating that it is in thegas generation window.

Rock-Eval S2 values for the Kharita Formationwere 0.28 -5.2 mg HC/g rock; for the Alam El BueibFormation, S2 was 0.5-2.5 mg HC/g rock; and it was3.26 to 43.26 mg HC/g rock for the KhatatbaFormation.

The Cenomanian Bahariya Formation has a Rock-Eval Tmax of 425°C, the Kharita Formation has a Tmaxof 450 °C, while Tmax for the Alam El Bueib Formationranges from 440 to 478 °C. These data indicate thatthe Cretaceous section in general ranges from matureto post-mature in terms of oil generation (c.f. Hunt,1996). Tmax in the Middle Jurassic Khatatba Formationranges from 440 to 490 °C.

Fig. 4a and b are plots of Tmax versus HydrogenIndex (HI) for various formations at well Jb26-1 inthe central part of the basin. The plots show that TypeI/II kerogen is present in the upper part of the KhatatbaFormation and that Type II/III kerogen occurs in theKharita and Alam EI-Bueib Formations and possiblyin the topmost part of the Khatatba Formation. TypeIII kerogen is present in the remaining samplesincluding the coaly shales and thin coals in theKhatatba Formation. Type IV kerogen was recordedin parts of the Alam EI-Bueib Formation.

HI values range between 36 and 766 mg HC/gTOC, and most of the analyzed samples lie withinthe oil zone (Khatatba and Alam EI-BueibFormations). Some samples plot within the gas zone(Khatatba and Alam EI-Bueib Formations), and othersplot at the margin between the mature oil zone andthe immature zone (Kharita Formation). Theremainder of the samples (Bahariya and Abu RoashFormations) are immature.

The S2/S3 ratio further indicates that a variety ofkerogen types are present. Thus the Abu RoashFormation has an S2/S3 of <2.3 indicating thepresence of gas-prone kerogen, whereas S2/S3 in theBahariya, Alam El-Bueib and Khatatba Formationsis <2.3 to >5.0 indicating that both oil- and gas-pronekerogen is present (c.f. Espitalie et al., 1985).

Burial historyBurial history curves (Fig. 5) indicate that theKhatatba Formation appears to have reached the gasgeneration window (Ro values >1.3) during theOligocene. The Lower Alam El-Bueib Formationentered the late mature stage in the Early Miocene.The Upper Alam El-Bueib Formation is currently atthe mid-mature stage (defined by 0.7-1.0% Ro). TheKhatatba Formation may have reached the mid-maturestage (0.7-1.0% Ro) as early as the Cenomanian.

B. Well Lotus-1, Western Shushan BasinAt this location, four lithofacies are present and canbe distinguished in terms of the quantity, quality andmaturity of the component organic matter. Facies 1comprises the sandstones and shales in the Bahariya,Kharita, and Alam El Bueib Formations, whose TOCsare generally 0.4%-1.0 %. Rock-Eval pyrolysis results(S2: generally less than 2 mg HC/g rock; HydrogenIndices: 100-150 mg HC/g TOC) indicate that thelithofacies has little capacity to generate gas. Facies2 (dolomites in the Alamein Formation) and facies 3(limestones in the Masajid Formation likewise havelow TOC contents (< 0.5%), indicating low source-rock potential.

Facies 4 comprises organic-rich intervals in theMiddle Jurassic Khatatba Formation, in which TOCvalues are up to 6.4% (generally 1-2%). Rock-Eval


S2 ranges from 10.1 to 12.6 mg/g. Hydrogen Indicesare relatively low (generally 100-200) but indicate thatthere is some remaining potential to generate gas. Therocks are approximately at the stage of peak oilgeneration (Fig. 6) and therefore some of their originalgenerating capacity has been exhausted. As pyrolysisyields prior to maturation are likely to have been higher(with Hydrogen Indices of the richest samples possiblyas high as 300), the organic matter was probably capableof generating oil as well as gas (c.f. Berglund et al.,1994). Visual examination (Plate 1) shows that kerogenis composed predominantly of amorphous material (80-90%), with minor vitrinite (10-15%) and exinite (up to5%). Much of the amorphous material is probablydegraded vitrinite together with alginite and liptinite.The occasional high S1 values recorded are interpreted

to reflect hydrocarbons generated in situ and notmigrated oil. Analyses of bitumen extracts indicatethe compositional differences between theseindigenous hydrocarbons and the migrated oilpresent in facies 1 and 3.

Maturity AssessmentAssessment of the maturity of the studied intervalcomprising the Khatatba, Masajid, Alam El-Bueib,Alamein, Kharita, Bahariya and Abu RoashFormations at the Lotus-1 location was made usingkerogen-related parameters such as vitrinitereflectance, TAI and pyrolysis Tmax, together withindicators related to C15+ bitumen extracts. Basedon the high quality of the vitrinite histograms (>50particles for each reading), comparison with the Tmax

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Very High

HYDROGENINDEX

S2/S3S2 (mg/g)T.O.C. (Wt%)

SOURCE BED POTENTIAL

LITHOLOGYFORMATION

).tf(HT

PED

MATURITY HYDROCARBONINDICATION

S1S1+S2

S1(mg/g)

Good-Very Good

410 440 470 500

1 2 3 4 5 10 20 30 2.5 5.0 7.5 100 300 5001 2 3 4 0.3 0.6 1.0 1.4 3.0

1 2 0.2 0.6 1.0

BAHARIYA

KHARITA

ALAMEIN

ALAMEL BUEIB

MASAJID

KHATATBA

13000

12500

12000

11500

11000

10500

10000

9500

9000

8500

8000

7500

7000

6500

6000

Sandstone

Coal

Shale and Siltstone

Limestone

Dolomite

Chert

Halite

S1: Free hydrocarbons present in rock

S2: Hydrocarbons from kerogen pyrolysis

S3: CO from kerogen pyrolysis

Hydrogen index=S2/TOC

2

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...............

................ . . . . . .

. . . . . . . .

...............

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EG

AS

UOE

CAT

ER

CCI SS

AR

UJ

Fig. 6. Geochemical log of well Lotus-1, western Shushan Basin.


data and the high level of maturity indicated by thebitumen extracts in the deepest section of the well,the Ro data are considered to be more reliable thanthe TAI data (Khalid, 1991; 1999).

In the deeper parts of the section, amorphouskerogen is fluorescent, consistent with most of thepenetrated section being at maturity levels below 1.0%Ro. At deeper levels, samples show only tracefluorescence as a result of increased maturation. InFig. 7, Ro values between 6160 ft and 12,550 ft rangefrom 0.53% to 0.88%, and the oil window (definedby an Ro value of 0.6%) is entered at approximately8000 ft. Measured Ro values do not increasesignificantly below 10,350 ft, and the level of maturitymay be slightly higher between 10,350 and 13,000 ft

than as indicated by Ro values.Pyrolysis Tmax values are reasonably consistent

with Ro data. Tmax values of 450-455oC in the deepestpart of the section are equivalent to Ro values of about0.8-0.9%. Between 6160 and 10,650 ft, TAI values of2.0 to 2.4 are in general in agreement with Ro andTmax values. At 12,550 ft, the agreement between theseparameters is good but at depths of 11,090 and 11,788ft, the TAI value of 2.2 implies lower maturities thanthe Ro values (Halim et al., 1996).

Vitrinite-reflectance histograms (Fig. 7) confirmthe reliability of these data. Ro values in the sectionbelow 10,350 ft show little increase with depth. TheRo value of 0.51% at 12,950 ft is too low accuratelyto reflect the maturity of the rocks at this depth. This

0.0 0.00.5 0.51.0 1.01.5 1.5

Reflectance (%Ro)

100

80

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0

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yc

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ale

RBahariya FormationSample No. 1Depth : 6160 ftPop. N Mean Ro(1) 37 0.53(2) 23 0.73

Alam El-BueibFormationSample No. 9Depth : 10350 ftPop. N Mean Ro(1) 6 0.51(2) 54 0.79*

Kharita FormationSample No. 3Depth : 6810 ftPop. N Mean Ro(1) 60 0.55*

Alam El-BueibFormationSample No. 10Depth : 10650 ftPop. N Mean Ro(1) 60 0.82*

Kharita FormationSample No. 4Depth : 7260 ftPop. N Mean Ro(1) 55 0.59*(2) 5 0.79

Alam El-BueibFormationSample No. 11Depth : 11090 ftPop. N Mean Ro(1) 10 0.50(2) 50 0.82*

11% 10%

17% 11%

15% 10%

Masajid FormationSample No. 13Depth : 11788 ftPop. N Mean Ro(1) 11 0.75* (?)

KhatatbaFormationSample No. 15Depth : 12550 ftPop. N Mean Ro(1) 58 0.88*(2) 2 1.17

Khatatba FormationSample No. 17Depth : 12950 ftPop. N Mean Ro(1) 60 0.51

N/A

10%

14%

Alam El-BueibFormationSample No. 6Depth : 8450 ftPop. N Mean Ro(1) 58 0.64*(2) 2 0.86

Alam El-BueibFormationSample No. 7Depth : 8950 ftPop. N Mean Ro(1) 60 0.63*

Alam El-BueibFormationSample No. 8Depth : 6160 ftPop. N Mean Ro(1) 37 0.53(2) 23 0.73

13%

10%

15%

Denotes vitrinite population interpreted as indigenousDenotes vitrinite population interpreted as migrated

Fig. 7.Vitrinite reflectance histograms for the studied source rocks, well Lotus-1, western Shushan Basin.


Plate 1. Photomicrographs (A-F) showing organic matter in the Khatatba Formation from well Lotus-1,western Shushan Basin. The kerogen present is composed of cuticles, and plant tissues range in colourfrom dark brown to orange, and in size from very fine to coarse; palynomorphs are represented by pollengrains.

may due to post-deformation changes in maturity(Pittion and Gouadain, 1985) or to Ro suppression(e.g. Price and Barker, 1985).

Maturities in the well sections in Fig. 7 range fromimmature at approximately 6000 ft to levelsapproaching peak oil generation below 11,000-12,000ft. The oil window is entered at approximately 8000ft. Bitumen extract data from below 12,000 ft furtherindicate that maturity levels necessary for substantialgeneration of hydrocarbons have been reached.

Two Lopatin-type burial-history reconstructionswere made for well Lotus-1 (Figs. 8a and 8b).Applying the present-day geothermal gradient for theMeleiha area (0.93oC/100 ft: Parker, 1982) to the

period from the Middle Jurassic to the present day,the calculated maturities are much higher than thoseindicated by the measured data (Fig. 9a). Since therocks are not at the high levels of maturity predictedby the modelling, the simple model must be modified,for example to take account of the fact that the present-day geothermal gradient in the Meleiha area is higherthan the regional gradient in the Western Desert(Mosca and Aboul Gadayel, 1992; Abdel Aziz, 1994).

In order to find a better fit between measured andcalculated maturities, a lower geothermal gradient inthe past was assumed and a second burial-historyreconstruction was made (Fig. 9b). The present-daygeothermal gradient of 0.93oC/ 100 ft was used for


only the past 3 million years; before this, a gradientof 0.64oC/100 ft was used. This model results in abetter agreement between measured and calculatedmaturities (Fig. 8b). Using this revised model, thematuration plot shows that oil generation in thepotential source rocks of the Khatatba Formationprobably began at about 40-55 Ma and has continuedto the present day.

Extract characterizationi. Kharita extractsExtracts from the Kharita Formation have greaterquantities of C25+ n-alkane waxy component thanextracts from the Khatatba and Alam El-Bueib

Formations. Pristane /nC17 is higher than phytane/nC18(Fig. 9), which suggests a predominantly terrestrialorganic matter input and low thermal maturities(samples 6, 9, and 10 are shifted towards the top-rightof the plot). There are strong odd carbon numberpreferences between nC25 and nC35, and the CarbonPreference Index (CPI) values are high (1.47–2.05)which also indicate a high input of terrestrial organicmatter and low thermal maturities (Bray and Evans,1961).

In the terpane distribution (m/z 191) of the Kharitaextracts, the low tricyclic indices (= tricyclics / 17α-hopanes), the high to very high C19/C23 tricyclicterpane ratios, the very high Tm/Ts ratios and C30

30 Co

40 Co

50 Co

60 Co

70 Co

80 Co

90 Co

100 Co

110 Co

120 Co

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

11000

12000

13000

14000

15000

Immature Oil Gas150 100 50

TTI GradientData GradientR %TTAIOil Window

o

max

Geothermal Gradients0 MYBP: surface temperature = 25 C, dT/dZ = 0.93 C/100 ft3

o o

MYBP: surface temperature = 25 C dT/dZ = 0.93 C 100 ft3 MYBP: surface temperature = 25 C dT/dZ = 0.64 C 100 ft170 MYBP: surface temperature = 25 C dT/dZ = 0.64 C/100 ft

o , o /

o , o /

o , o

30 Co

40 Co

50 Co

60 Co

70 Co

80 Co

90 Co

100 Co

110 Co

120 Co

130 Co

140 Co

150 Co

160 Co

1000

2000

3000

4000

5000

6000

7000

8000

9000

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Immature Oil Gas

THERMAL MATURITY

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150 100 50

TTI GradientData GradientR %TTAIOil Window

o

max

R %o

R %o

Tmax

Tmax

TTI

TTI

TAI

TAI

)tf(

HTPE

D)

tf(HT

PED

Geothermal Gradients0 MYBP: surface temperature = 25 C, dT/dZ = 0.93 C/100 ft170

o o

MYBP: surface temperature = 25 C dT/dZ = 0.93 C 100 fto , o /

Fig. 8. Burial history curves and maturation plot for well Lotus-1, (A) using the present-day geothermalgradient; (B) assuming a lower geothermal gradient in the past (see text for details).


moretane /C30 hopane ratios, and the very low C23tricyclic/C30 hopane ratios all indicate predominantlybacterial and terrestrial organic matter with minoralgal material (Peters and Moldowan, 1991). The veryhigh Tm/Ts and C30 moretane /C30 hopane ratios arealso consistent with low thermal maturities. The lowC35 homohopane indices suggest mildly anoxic orslightly oxic conditions. The sterane distribution (m/z 217) of the studied samples shows much higherconcentrations of C29 ααα (20R) steranes than C27aaa (20R) steranes, indicating a high terrestrial organicmatter contribution relative to algal material (Petersand Moldowan, 1993). On a plot of 20S/ (20S+20R)versus the ratio ββ/(ββ+αα) for C29 steranes, theKharita samples plot in the immature to low maturityfields (Fig. 10).

Alam El-Bueib Formation extractsExtracts from the Alam El Bueib Members 3 and 5 ingeneral have similar n-alkane distributions to KhatatbaFormation extract (see below), except for samplesfrom the 4437-4440 m depth interval in well Jb26-1.The two Alam El-Bueib extracts have lower maturitiesthan the Khatatba extracts as indicated by biomarker-derived maturity indices (Fig.10). The two Alam ElBueib extracts show minor differences; the Member5 extract from well Ja 27-2 appears to be more mature,and perhaps has a more terrestrial character, than theMember 3 extract from well Jb 26-1. Hopane andsterane isomerisation ratios (Tables 1-6) for theMember 5 sample from well Ja 27-2 (Figs. 11 and

12) indicate maturity close to peak oil generation(0.80%Ro) (Mackenzie and Maxwell, 1981).

Khatatba Formation extractsExcept for samples from the interval 4437–4440 m inwell Jb 26-1 (sample 5), Khatatba extracts showgeneral similarities in terms of C16+ n-alkane (nC16-nC35) contents and isoprenoid distributions. C25+ n-alkanes are present in significant proportions relativeto C<25 n-alkanes. Pristane/phytane ratios are moderateto high (1.4-2.2) indicating oxidizing conditions. Aplot of pristane/nCl7 versus phytane/nCl8 suggests amixed organic facies and highly mature extracts (Fig.9) (Shanmugam, 1985).

The sample from the 4437–4440 m depth intervalin well Jb 26-1 has a low extract quality and a lowpristane/phytane ratio (0.7). This suggests a relativelyhigher algal and lower terrestrial organic mattercontribution and more anoxic conditions comparedto the other samples. This is also indicated in theterpane distribution by the very high tricyclic index(892), low C19 tricyclic/C23 tricylic terpane ratio (0.53),and high C23 tricyclic/C24 tetracyclic terpane ratio(6.5).

In terms of sterane distribution, the sample fromthe interval 4437–4440 m in well Jb 26-1 well alsohas the highest C27 (20R)/C29 (20R) sterane ratio (0.94)of the samples analyzed. Hopanes /steranes ratio is3.73, which indicates a greater bacterial contributioncompared to terrestrial plus algal matter (Peters andMoldowan, 1993).

4.0

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ion

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grada

tion

Terrestr

ai l OrganicMatte

r

Peat-Coal Enviro

nments

Mixed OrganicSource

s

Marine Organic

Matter (A

lagal-Reducin

g)

Ph / n-C18

C-n / r

P71

Oxidation

Reducing10

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1

9

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4

32,18

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1215

14,16,17

1 Alam El-Bueib #3 Mbr.11 Alam El-Bueib #5 Mbr.6,9,10 Kharita Formation2-5, 7,8 Khatatba Formation12-18 Oil Samples

Fig. 9. Plot of pristane /nC17versus phytane/nC18 for thestudied samples:1: Alam El-Bueib #3Member;I1: Alam El-Bueib #5Member;6, 9 &10: KharitaFormation;2-5, 7,8: KhatatbaFormation;12-18: oil samples.


Samples from 4237–4240 m, 4297–4300 m and4357–4360 m in well Jb 26-1 can be grouped into adistinct source facies containing mixed organic matter.Within the terpane distribution (Fig. 12), the tricyclicindices (82-383) and the C19 tricyclic /C23 tricyclicterpane ratios (0.40-2.45) are moderate to high. TheTm/Ts ratios (1.20-3.88) and the C30 moretane/C30hopane ratios are moderate, which distinguishes thesesamples from the Kharita samples. In the steranedistribution (Fig. 12), these extracts show C27 ααα(20R)/ C29 ααα (20R) sterane ratios between 0.55and 0.84 which suggests a higher contribution ofterrestrial organic matter than algal organic matter.Hopane / sterane (TT/ST) ratios are 2.63-6.99, whichindicate that input of bacterial OM was greater thanthat of terrestrial plus algal OM.

The Khatatba samples from 4257-4260 m and4304.2 m in well Ja 27-2 have low to moderatebiomarker concentrations and indicate a source facieswith mixed organic matter (Fig. 12). Compared to theother Khatatba extracts, the source facies of samplesfrom well Ja 27-2 indicate less bacterial, moreterrestrial and less algal organic matter. In the terpanedistribution, the tricyclic indices are very high (1076-1176) due to very high C19 and C20 tricyclic terpanes.The C19 tricyclic/C23 tricyclic terpane ratios are 2.88-16.53. The Tm/Ts ratios are 0.89-1.46, while the C30

moretane/C30 hopane ratios are 0.21-0.27. Theseratios are comparable to those in the other Khatatbaextracts and are lower than those in Kharita samples.The C35 homohopane indices are zero.

In the sterane distribution (Fig. 12), Khatatbaextracts from Ja 27-2 have C27 ααα (20R)/C29 ααα(20R) sterane ratios of 0.30-0.33, which are higherthan those in the Kharita samples but lower than thosein the other Khatatba extracts. Hopane / sterane (TT/ST) ratios of the two Khatatba extracts from well Ja27-2 are the lowest (1.71-1.79) of all the samples,indicating the smallest contribution of bacterialorganic matter relative to terrestrial plus algal material.On a plot of 20S / (20S+20R) C29 steranes versus ββ/(ββ + αα) C29 steranes, all the Khatatba extracts plotin the mature field (Fig. 10)

ii. Well Lotus-1, Western Shushan BasinC15+ bitumen extracts from the Masajid-Bahariyasection to a depth of 11,350 ft (Fig. 6) are of littlevalue as maturity indicators, as they are notindigenous. By contrast, the two extracts from theKhatatba Formation from 12,000 and 12,650 ft providevaluable information for assessing maturities at thisdepth. The gas chromatograms of these extracts(Fig.13) are typical of mature extracts and indicatethere has been substantial hydrocarbon generation.

0

0

C29 βββ / ( ββ + αα ) (%)

C9

2)

%( )R

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Mature

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8117

34

51

1 Alam El-Bueib #3 Mbr.11 Alam El-Bueib #5 Mbr.6,9,10 Kharita Formation2-5, 7,8 Khatatba Formation12-18 Oil Samples

Fig.10. Correlation of thermal maturity parametersbased on isomerisation of asymmetric centres inthe C29 steranes:1: Alam El-Bueib #3 Member;1I: Alam El-Bueib #5 Member;6, 9 and 10: Kharita Formation;2-5, 7,8: Khatatba Formation;12-18: oil samples.


The chromatograms show a smooth distribution of n-alkanes with a predominance of low molecular-weightcompounds, the waxy alkanes (C25-C31) have almostcompletely lost their odd-carbon preference (hencehave low CPI values), and isoprenoid/n-alkane ratiosare very low.

The six bitumen extracts analysed may be dividedinto two groups. The four extracts of “Group A” comefrom Organic Facies 3 and 1, and probably representpetroleum that has migrated into the rocks. The secondgroup of extracts (“Group B”) from the KhatatbaFormation have a different character and are thoughtto be indigenous.

Group A extracts contain high absolute quantitiesof extractable bitumen (4567-13,457 ppm) and theirhigh extract/TOC ratios (42-70%) indicate thathydrocarbons are not indigenous and probably

comprise migrated oil. Liquid-chromatography dataindicate that the extractable material is composedlargely of hydrocarbons (68-75%) whose high saturatecontents (46-55%) are typical of mature migrated oils.

Gas chromatograms of the four extracts are almostidentical and are characterized by a smooth n-alkanedistribution with a predominance of low-molecular-weight compounds, and low quantities of terrestrially-derived waxy n-alkanes. This distribution, togetherwith Pr/Ph ratios close to 1.0, suggest that themigrated material is a marine-sourced oil with littleterrestrial contribution.

The two Group B extracts have high absolutequantities of extractable bitumen (3803-5160 ppm).The moderate extract/TOC ratios (10-18%), however,suggest that the extracts are indigenous and that somegeneration of hydrocarbons has taken place. The

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C82

senaretsai d

C27 diasteranesC

92senaretsa id

HC

92senaretsaid

C82

se naretsaid

C28 C29

Fig. 11. Triterpanes and sterane fingerprints of the saturate fraction from an extract sample from the Alam El-Bueib Member 5 (sample 11, well Ja 27-2, depth 3588.9 m).


extractable material in both samples is composed ofhydrocarbons comprising 16-17% saturates, 29%aromatics and 36% asphaltene.

The gas chromatograms display a smooth n-alkaneprofile with a predominance of low molecular weightcompounds. They differ from the Group A extracts inthat they also show a moderate amount of terrestrially-derived longer-chain n-alkanes (C25-C31), have higherPr/Ph ratios (1.69-1.78), and much lower isoprenoid/n-alkane ratios. The Pr/Ph ratios and presence of somewaxy n-alkanes suggest a normal oxidizingenvironment with significant terrestrial contribution.The low isoprenoid/n-alkane ratios, low CPI valuesand predominance of low molecular weightcompounds are a result of maturation.

The GC/MS data further differentiate the extractsfrom Groups A and B, and provide additional supportfor the Group A extracts represent the same migratedmaterial.

The m/z 217 sterane mass chromatograms (Fig.14) of the Group A extracts are closely similar,particularly in terms of the C27 diasteranes and theC27 and C29 regular steranes. The two Group B extractsshow lower quantities of steranes, but differ slightlyin their relative abundances of various compounds.For example, the sample from 12,650 ft is dominatedby C29 diasteranes and regular steranes, consistent withthe greater influence of terrestrial material in thissample.

The triterpane distributions of the two groups arerelatively similar; however, the m/z 191 masschromatograms display a number of differences whichcan be used to distinguish between the two groups.The Group A extracts show substantial amounts ofthe C23 and C24 tricyclics, whereas in the Group Bextracts, the C26 tricyclic is more evident. Also presentin Group B extracts is a peak eluting at approximately39.3 mins (C30 17α (H) diahopane) which is absent

R e t e n t i o n T i m e

e s n o p s e

R

M/Z = 217

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1000

64 66 68 70 72 74 76 78 80 82 84 86

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Fig. 12

Formation: Alam El-Bueib#3Well: Jb 26-1 Sample: 1Depth: 3237-3240 m

62


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M/Z = 217Formation: KhatatbaWell: Ja 27-2 Sample: 7Depth: 4257-4260m

Formation: KhatatbaWell: Jb 26-1 Sample: 4Depth: 4357-4360 m

Formation: Alam El-Bueib#3Well: Jb 26-1 Sample: 1Depth: 3237-3240 m

Formation: KhatatbaWell: Jb 26-1 Sample: 4Depth: 4357-4360 m

Fig. 12. Triterpane and sterane fingerprints of extracts from wells Jb 26-1 and Ja 27-2, central Shushan Basin.


Fig. 13. Gas chromatographs of C15+ saturated hydrocarbons in extracts from well Lotus-1, western ShushanBasin.


Fig. 14. Sterane fingerprints of extracts from well Lotus-1.


Fig. 15. Triterpane fingerprints of extracts from well Lotus-1.


from Group A extracts. This peak is evident on the m/z 191 mass chromatogram (Fig. 15) of the sample from12,650 ft, and confirms the high terrestrial input tothat sample (c.f. Peters and Moldowan, 1993).

Although the two groups of extracts are verysimilar compositionally, the Group A extracts showminor differences in peak abundances related tomaturity. The m/z 191 mass chromatogram of thesample from 6650 ft shows significant amounts of theC29 and C30 moretanes, compounds usually absent inmature samples. Another sign of relative immaturityin this sample is the dominance of the 14α form ofthe C29 regular sterane 20R over the 14β form (see m/z 217 mass chromatogram). By comparison, apredominance of the 14β form of the C29 regularsteranes and lesser amounts of moretanes indicate thatthe other samples in Group A are more mature. Thus,this sample may be influenced by immature indigenousmaterial.

The same biomarker maturity parameters can beused to illustrate the advanced state of maturity ofGroup B extracts. Moretanes are present in only veryminor amounts and the 14β forms of the C29 regularsteranes are dominant over the 14α forms.

CONCLUSIONS

This paper reports on the organic geochemicalcharacteristics and source rock potential of Jurassic-Cretaceous units in the Shushan Basin, NorthernWestern Desert, Egypt. Main conclusions are asfollows:

1. In general, the thermal maturity of the potentialsource rocks analysed can be correlated with burialdepth. Source rocks in the central structurally-low partof the Shushan Basin were more mature than those inthe western (structurally elevated) part.

2. With the exception of the Albian KharitaFormation, the source rocks from the central part ofthe Shushan Basin have the potential to generate liquidhydrocarbons where they have reached sufficientthermal maturities. However, only the Middle JurassicKhatatba Formation had a high enough TOC contentto serve as a potential rock in the western part of thebasin.

3. Gas chromatography and GC/MS data indicatesthat the Khatatba Formation is not the source for themigrated material in the upper part of the studiedsection, and therefore a second, more marine-influenced source rock is assumed to be present.

4. With the exception of the extracts from theMiddle Jurassic Khatatba Formation from the depthinterval 4437–4440 m in well Jb 26-1 in the west ofthe Shushan Basin, all the source rock extractsanalysed in general have a “terrestrial” signature to

varying degrees. Extracts from the Kharita Foramationappear to be the most terrestrially dominated. Extractsfrom the Alam El Bueib Formation can be groupedwith extracts from the Khatatba Formation from wellJb 26-1 and are probably the least terrestriallydominated source rocks in the central part of the basin.

5. Extracts from the Khatatba Formation from wellJa 27-2 appear to be the most mature and contain moreterrestrial organic matter than the other Khatatbaextracts. However, the Khatatba extract from theinterval 4437–4440 m in well Jb 26-1 appears torepresent a unique source facies with the lowestcontribution of terrestrial organic matter.

ACKNOWLEDGEMENTS

The authors thank the Egyptian General PetroleumCorporation for providing the raw data upon whichthe present work is based. Reviews by S. Luning andan anonymous referee on a previous version of themanuscript are acknowledged with thanks.

REFERENCES

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HALIM, M.A., SAID, M. and EL AZHARY, T., 1996. Thegeochemical characteristics of the Mesozoic and Tertiaryhydrocarbons in the Western Desert and Nile Delta basins,Egypt. EGPC 13th Petrol. Expl. and Prod. Conf., Cairo, 401-416.

HUNT, J.M., 1996. Petroleum geochemistry and geology, 2ndedition. W.H. Freeman and Co., New York, 743 p.

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Sample No. Well Name Interval (m RKB) Formation API Pr/Ph Pr/nCl8 Ph / nC18

1 Ja 28 - I DST #1 4420.6-4426.6 Khatatba 38 3.1 0.26 0.092 Ja 28 - I DST #l 4420.6-4426.6 Khatatba 39.5 3 0.31 0.13 Ja 28 - 1 DST #2 4396.7-4415.7 Khatatba 50 4.4 0.28 0.064 li 28 - 1 DST #2 4290.5-4297.0 Khatatba 43 4.2 0.21 0.055 Jb 26 - 1 DST #1 4448.9-4456.9 Khatatba 50.2 3.4 0.28 0.086 Jb 26 - I DST #3 4171.1-4185.1 Khatatba 46 3.5 0.28 0.087 Ja27-2 DST #1 Khatatba 50 1.4 0.16 0.07

BIOMARKER(m/z 217}

Regular steranes TOTAL % TOTAL %C27 27.83 26.66C28 14.29 10.65C29 18.44 22.1

Total 60.56 59.41Diasteranes

C27 18.78 13.1C28 11.53 8.7C29 9.14 18.79

Total 39.44 40.59Normalized %C27 40.67 50.37C28 35.75 0C29 23.58 49.63Normalized %

C27 40.72 30.72C28 25.02 14.43C29 34.25 54.85

RatioDiasterane Index 92.5 101.58

Diasterane / regular steranes n/a 0.68C27 C29 1.73 1.01C27 29 C 1.95 0.81C29 29 1.45 0.87

20S / (20S + 20R) C29 66.13 44.8127 sterane (%) 46.87 48.97

27 sterane (%) n/a 76.31Hopanes / Steranes (TT / ST) 2.55 0.37

(Steranes+Diasteranes) / C27-C30 hopanes n/a 3.1

Ja 28-1 DST#1

Jb 26-1 DST#3

ααα (20R)ααα (20R)ααα (20R)

ααα sterane %

ααα (20R) /ααα (20S) /

αββ / (ααα + αββ)

αββ (20R) /

αββ (ααα + αββ)

ααα (20R)ααα (20R)ααα (20R)

ααα (20R + 20S)ααα (20R + 20S)

ααα (20R + 20S)

C

CC

BIOMARKER Ja 28-1 Jb26-1(m/z 191) DST#1 DST#3

Tricyclic Terpanes TOTAL % TOTAL %C19-C29 63.97 31.74C30-C36 2.05 0

Pentacvclic TerpanesHopanes 26.8 51.64

Non-Hopanes 2.82 0RATIO

Tricyclic Index 1209.49 498.8C19 Tricyclic / C23 Tricyclic n/a 0

C23 Tricyclic / C24 Tetracyclic 4.09 0.76Tm/Ts 0.69 0.72

C28 Hopane / C29 Hopane 0.17 0C28 Hopane / C30 Hopane 0.19 0

C28 Hopane/ (C28 + C30 Hopane) n/a 0

C29 Hopane / C30 Hopane 1.11 1.01C30 Moretane / C30 Hopane 0 1.06C30 Oleanane / C30 Hopane 0.53 0

Gammacerane Index 0 0

22S/ (22S+22R) C31Hopane (%) n/a n/a

22S / (22S+22R) C32 Hopane (%) 61.77 n/a

C35 / C34 Extended Hopanes n/a n/aTricyclic / 17aH - Hopane Ratio n/a 0

C35-Homohopane Index. (%) 6.02 n/a

Table 3. Results of biomarker analyses for the studied oils, wells Ja 28-1 and Jb 26-1, central Shushan Basin.

Table 2. Results of GC whole oil analyses, Khatatba Formation, Central Shushan Basin.

WellName

1 Jb 26 - I 3237-3240 AEB # 3 642 2.20' 0.48 0.25 1.162 Jb 26 - 1 4237-4240 Khalatba 721 1.4 0.15 0.1 13 Jb 26 - 1 4297-4300 Khatatba 860 1.7 0.17 0.11 0.974 Jb 26 - 1 4357-4360 Khalatba 716 1.9 0.2 0.13 1.015 Jb 26 - 1 4437-4440 Khatatba 516 0.7 0.36 0.42 1.056 Jb 26 - 1 2397-2400 Kharita 1128 3 1.2 0.41 2.057 Ja27-2 4257-4260 Khatatba 4714 1.8 0.07 0.04 1.018 Ja 27- 2 4304.2 Khatatba 2938 2.1 0.04 0.02 0.999 Ja 27 - 2 2297-2300 Kharita 1400 2.6 0.99 0.41 1.47

10 Ja27-2 2477-2480 Kharita 3765 5.6 3.17 0.76 1.7611 Ja27-2 Core Extract 3588.9 AEB # 5 443 2.6 0.31 0.12 1.1

Pr / Ph Pr/nC17 Ph / nC18 CPISample No. Interval (m) Formation Extract

(ppm)

Table 1. Results of bitumen analyses for the studied source rocks, wells JB 26-1 and Ja 27-2, central Shushan Basin.


Jb26-1 2397-2400 m

Ja27 Ja27-24304.2m

Ja27-2297-2300m m

Ja27-2477-2480 m

Jb26-1 3237-3240m

Jb26-1 4237-4240m

Jb26-1 4297-4300m

Jb26-1 4357-4360m

Jb26-1 4437-4440mBiomarker / well 4257-4260m

Tricyclic Terpanes TOTAL% COMPOSITION

C19-C29 17.16 68.38 69.72 3.73 12.37 18.21 45.99 13.47 42.69 61.9

C30-C36 0.52 0 0 0.48 0.5 1.33 2.01 11.7 3.32 0.52Pentacyclic Terpanes

Hopanes 81.29 28.65 27.72 95.03 86.25 77 .47 48.1 69.85 50.74 35.11Non-Hopanes 0.15 0 0 0 0 0 0.46 3.66 1.08 0.41

RATIOTricyclic Index 127.63 1075.81 1158.5 25.92 95.14 121.95 490.97 82.33 382.81 892.22C19 Tricyclic / C23 Tricyclic 6.08 2.88 16.53 1.05 13.16 2.45 0.54 0.4 1.04 0.53C23 Tricyclic / C24 Tetracyclic 1.34 2.76 1.15 0.72 0.45 0.9 2.93 1.39 3.42 6.5Tm /Ts 35.45 0.89 1.46 46.68 53.88 3.88 1.2 1.49 1.35 1.85C28 Hopane / C29 Hopane 0.06 0 0 0.03 0.03 0.05 0.11 0.22 0.13 0.09C28 Hopane / C30 Hopane 0.05 0 0 0.03 0.03 0.05 0.09 0.14 0.11 0.08C28 Hopane /(C28 + C30 Hopanes) 0.05 0 0 0.02 0.03 0.05 0.09 0.13 0.1 0.07

C29 Hopane / C30 Hopane 0.87 0.81 0.75 0.96 1 1.09 0.87 0.67 0.78 0.88C30 Moretane / C30 Hopane 0.65 0.21 0.27 0.63 0.53 0.27 0.19 0.21 0.17 0.19C30 Oleanane / C30 Hopane 0.01 0 0 0 0 0 0.05 0.22 0.1 0.06Gammacerane Index 0 0 0 0 0 0 0 0 0 022S/(22S + 22R) C31 Hopane (%) 57.75 47.73 56.79 58.81 58.08 60.1 48.6 55.19 52.08 53.82

22S/(22S + 22R)C32 Hopane (%) 51.08 57.48 59.9 52.15 54.12 59.32 62.91 59.71 60.06 61.12C35 / C34 Extended Hopanes 0.53 n/a n/a 0.49 0.42 0.64 0.71 0.76 0.96 0.91Tricyclic / 17aH - Hopane Ratio 0.03 0.21 0.15 0.01 0.01 0.02 0.25 0.11 0.15 0.12C35-Homohopane Index (%) 1.89 0 0 1.22 1.53 4.82 7.01 7.54 8.71 7.87

Regular steranesC27 26.16 27.53 23.49 26.4 28.7 18.88 18.13 15.34 15.66 15.21C28 12.71 16.77 13.2 14.43 15.43 12.52 22.65 23.79 23.87 17.97C29 27.83 24.83 22.52 27.64 22.83 44.06 32.59 30.68 39.5 48.39Total 66.7 69.13 59.21 68.47 66.97 75.47 73.37 69.81 79.02 81.56

Rearranged (diasteranes)C27 13.27 15.9 18.1 12.7 16.64 4.34 7.33 12.95 6.24 3.75C28 9.19 7.65 11.56 9.75 6.25 6.54 10.68 10.13 7.75 2.2C29 10.84 7.32 11.13 9.08 10.13 13.65 8.62 7.12 6.99 12.49Total 33.3 30.87 40.79 31.53 33.03 24.53 26.63 30.19 20.98 18.44

NORMALIZED %C27 ααα (20R) 27.09 31.05 31.37 41.21 34.86 8.85 15.51 16.77 10.68 5.39C28 ααα (20R) 24.1 26.97 30.61 9.94 27.87 19.79 37.15 27.82 35.67 20.24C29 ααα (20R) 48.82 41.98 38.02 48.85 37.27 71.36 47.35 55.42 53.65 74.37

NORMALIZED %C27 ααα (20R + 20S) 30.75 34.52 34.49 38.16 38.54 11.93 18.58 15.63 14.15 7.73C28 ααα (20R + 20S) 18.46 22.16 22.31 14.29 22.47 17.82 32.91 37.83 31.58 17.42C29 ααα (20R + 20S) 50.79 43.32. 43.2 47.55 38.99 70.25 48.51 46.55 54.27 74.85

RATIODiasterane index 102.58 140.92 66.45 92.91 102.58 44.56 90 128.47 52.87 70.62

Diasteranes / regular steranes 0.5 0.45 0.69 0.46 0.49 0.33 0.36 0.43 0.27 0.23C27ααα(20R) / C29ααα(20R) 0.55 0.74 0.83 0.84 0.94 0.12 0.33 0.3 0.2 0.07

C29 ααα (20S) / C29 ααα (20R) 0.87 0.87 1.06 1.09 0.87 0.23 1.03 0.97 0.3 0.36C29 α ß ß (20R) / C29 ααα (20R) 0. 85 0.98 1.16 1.21 0.81 0.02 1.19 1.04 0.2 0.17

20S/(20S+20R)C29ααα sterane(%) 46.55 46.55 51.57 52.13 46.58 18.48 50.69 49.3 23.37 26.63αßß / (ααα+α ß ß) C29 sterane (%) 45.64 50.21 50.51 51.79 46.68 22.01 52.58 51.3 26.58 27.47αßß / (ααα +αßß) C27 sterane (%) 65 64.2 62.12 59.5 58.07 69.09 67.35 67.31 51.7 76.15

Hopanes/Steranes.(TT/ST) 6.99 2.63 3.68 3.31 3.73 9.96 1.71 1.79 32.43 12.36

(Steranes+Diasteranes)/C27-C30hop. 0.26 0.73 0.48 0.55 0.5 0.2 0.93 0.86 0.07 0.17

Table 4. Results of biomarker analyses for the studied source rocks, central Shushan Basin.


Pr/ Ph/nC17 nC18

SAT. ARO.12000 18.3 1.14 1.69 0.25 0.16 27.4 24.8

12600-12650 10.45 1.1 1.78 0.24 0.15 26.2 24.39400 41.92 1.12 1.16 0.6 0.55 27.3 26

11240-11350 51.78 1.09 1 0.64 0.66 27.5 26.8Lotus-1 (MD-1X Khar. 7400-7450 70.46 1.11 1.07 0.67 0.62 26.9 26.5

Lotus-1 (MD-1X Baha. 6600-6650 47.32 1.1 1.17 0.64 0.58 27.3 26.3

Lotus-1 (MD-1X AEB

CPI Pr/Ph CIR

Lotus-1 (MD-1X) Khat.

WELL Fm. DEPTH EXTRACT /TOC%

Table 5. Results of GC analyses for the studied source rock extracts, well Lotus-1, western Shushan Basin.

Table 6. Results of GC/MS analyses for the studied source rock extracts, well Lotus-1, western Shushan Basin.

12990-13020 0.62 44.4 12.3 14.1 42 59 42 22 36

13020-13040 0.64 50.3 10.3 12 42 60 41 22 37

13280-13320 0.47 51.8 12.2 10 41 58 41 20 39

12000 0.66 39.3 10.9 9.5 45 57 41 27 3212600-12650 1.08 26.4 11.3 10.3 47 58 33 26 42

9400 0.7 32.6 16.8 19.3 45 59 46 22 3211240-11350 0.85 32 12.2 17.6 45 56 47 21 32

Lotus-1 (MD-1X) Khar. 7400-7450 0.88 32.8 13.2 15.3 45 57 40 24 26

Lotus-1 (MD-1X) Baha. 6600-6650 0.66 34.5 18.7 15.4 34 50 40 24 36

Lotus-1 (MD-1X) AEB

WELL Fm.

% C

29

Ster

ane



DEPTH

% 2

0S C

29

Ster

ane

% B

B C

29

Ster

ane

% C

27

Ster

ane

% C

28

Ster

ane

Ts /

Tm

% H

opan

e

% C

30M

% T

ri

abd el gawad-shushan

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