source rock potential, eithopia

389Journal of Petroleum Geology, Vol. 30(4), October 2007, pp 389-402

© 2007 The Authors. Journal compilation © 2007 Scientific Press Ltd

SOURCE ROCK POTENTIAL OF THEBLUE NILE (ABAY) BASIN, ETHIOPIA

A. Wolela*

The Blue Nile Basin, a Late Palaeozoic – Mesozoic NW-SE trending rift basin in central Ethiopia,is filled by up to 3000 m of marine deposits (carbonates, evaporites, black shales and mudstones)and continental siliciclastics. Within this fill, perhaps the most significant source rock potential isassociated with the Oxfordian-Kimmeridgian Upper Hamanlei (Antalo) Limestone Formation whichhas a TOC of up to 7%. Pyrolysis data indicate that black shales and mudstones in this formationhave HI and S2 values up to 613 mgHC/gCorg and 37.4 gHC/kg, respectively. In the Dejen-Gohatsion area in the centre of the basin, these black shales and mudstones are immature for thegeneration of oil due to insufficient burial. However, in the Were Ilu area in the NE of the basin, theformation is locally buried to depths of more than 1,500 m beneath Cretaceous sedimentaryrocks and Tertiary volcanics. Production index, Tmax, hydrogen index and vitrinite reflectancemeasurements for shale and mudstone samples from this areas indicate that they are mature foroil generation. Burial history reconstruction and Lopatin modelling indicate that hydrocarbons havebeen generated in this area from 10Ma to the present day.

The presence of an oil seepage at Were Ilu points to the presence of an active petroleumsystem. Seepage oil samples were analysed using gas chromatography and results indicate thatsource rock OM was dominated by marine material with some land-derived organic matter. ThePr/Ph ratio of the seepage oil is less than 1, suggesting a marine depositional environment. n-alkanes are absent but steranes and triterpanes are present; pentacyclic triterpanes are moreabundant than steranes. The black shales and mudstones of the Upper Hamanlei LimestoneFormation are inferred to be the source of the seepage oil.

Of other formations whose source rock potential was investigated, a sample of the PermianKarroo Group shale was found to be overmature for oil generation; whereas algal-laminatedgypsum samples from the Middle Hamanlei Limestone Formation were organic lean and had littlesource potential

*Department of Petroleum Operations, Ministry of Minesand Energy, PO Box 486, Addis Ababa, Ethiopia.email: [email protected]

INTRODUCTION

The NW-SE trending Blue Nile (or Abay) Basin is aLate Palaeozoic - Mesozoic intracratonic rift basincovering an area of about 120, 000 sq. km in centraland NW Ethiopia (Fig. 1). The sedimentary successionin the basin reaches a maximum thickness of 3,000m. In previous studies, the Oxfordian-KimmeridgianUpper Hamanlei (Antalo) Limestone Formation hasbeen investigated as a potential source rock (Wolela,

1997; 2002; 2004). Oil seepages occur in the bed ofthe Mechela River near Were Ilu in the NE of thebasin (Fig. 2), indicating the presence there of anactive petroleum system. However, little informationis available regarding potential source rocks orgeochemical characteristics of the Were Ilu seepageoil.

This paper reports on the hydrocarbon potentialof the Blue Nile Basin, focussing in particular onpotential source rocks (black shales and mudstones)in the Upper Hamanlei Limestone Formation. Thegeochemical characteristics of the Were Ilu seepageoil are also briefly reviewed.

Key Words: Blue Nile Basin, source rocks, Upper HamanleiLimestone Formation, Ethiopia, Were Ilu, oil seepage.

390 Source rock potential of the Blue Nile Basin, Ethiopia

Previous studies of the Blue Nile Basin includeGetaneh (1980, 1981, 1991) who described the claymineralogy and lithostratigrapy of the MiddleHamanlei (Gohatsion) Formation and the EarlyCretaceous Mugher Mudstone and overlying DebreLibanose Sandstone Formations. Assefa and Wolela(1986) reported on coal occurrences in the Getema(Arjo) area in the SW (Fig. 2). Mohr (1962) andSerawit and Tamrat (1995, 1996) investigated thegeology of the Jimma River and Gundo Meskel-Ejereareas, while Tamrat and Tibebe (1997) studied theGendeberet-Jeldu and Amuru-Jarty areas. Wolela(1997, 2002, 2004) investigated aspects of theevolution and hydrocarbon potential of the Blue NileBasin.

GEOLOGICAL BACKGROUND

Stratigraphy (Fig. 3)Basement rocks in the Blue Nile Basin consist ofPrecambrian basic to acidic rocks (Kazmin, 1975).These are overlain unconformably by a Permo-Triassic“Karroo” succession around 450 m thick, generally

interpreted to have been deposited in alluvial fan andfluviatile settings (Wolela, 1997). In contrast to theKarroo succession in the Ogaden Basin (Tamrat andAstin, 1992), up to 200 m of Karroo rocks may havebeen erosively removed in the Blue Nile Basin(Wolela, 1997). The Karroo succession isunconformably overlain by the up to 850 m thick,fluviatile-dominated Triassic-Liassic AdigratSandstone Formation, composed of conglomerates,sandstones, siltstones and mudstones. The formationis 450 m thick at Dejen-Gohatsion, 850 m thick atAmuru Jarty, 750 m thick at Fincha River, 200 m thickin the Getema (Arjo) area, and 150 m thick in Ejeraarea (Assefa and Wolela, 1986; Serawit and Tamrat,1996; Tamrat and Tibebe, 1997). The upper part ofthe formation is composed of alternating carbonaceousmudstones, carbonaceous siltstones and sapropeliccoals (Assefa and Wolela, 1986; Wolela, 1991). Coal-bearing sediments are interpreted to have beendeposited in lacustrine depositional environments.Palynomorphs include Corollina spp., Caamosporatender, Dictyophyllidites mortonii and Exesipollenitestumulus. Overlying the Adigrat Sandstone is a 50 m

36 38 40 42 44 46 48

16

14

12

10

8

6

4

°

°

°

°

°

°

°°°

°

BlueNile Basin

E T H I O P I AOgadenBasin

SOMALIA

KENYA

SUDAN

SUDAN

ERITREA

RED SEA

GULF OF ADEN

°°°°

MainEthiopianRift

Gambellabasin

Legend

Miocene and later rift

Blue Nile Basin

SAUDIARABIA

WhiteNile Rift

YEMENMekele Basin

Fig. 1. Location map of theBlue Nile Basin, central-NWEthiopia.

391A. Wolela

GendebertFincha

Dejen

Addis Ababa

Weliso

AmboNekemte

Arjo

Finc

ha R

iver

36° 38° 39° 40°

9°

10°

11° 11°

10°

9°

37°

Abay River

Abay River

Jimma RiverGohatsion

DebreMarkose

36° 37° 38° 39° 40°

0 50 100km

Tilli

Debre Birhan

Were Ilu

Legend

Bichena

Precambrian basement rocksPalaeozoic- sedimentary rocks

Mesozoic

Volcanic rocks

FaultOil seepageSampled areas

N

Contact

Weleka River

C E

N O

Z O

I C

Terti

ary

Quaternary

Pal

aeog

ene

Alluvium and volcanic

Palaeocene-Miocene1100

Volcanic

M E

S O

Z O

I C

Cre

tace

ous

Low

erU

p

Aptian-Cenomanian Debre LibanoseSandstone 240

Portlandian-Aptian Muger Mudstone 320

Jura

ssic

Low

erM

iddl

eU

pper

Portlandian Transitional Facies 30

Oxfordian-KimmeridgianUpper Hamanlei Limestone 720

Bathonian-Oxfordian Middle Hamanlei (Gohatsion) Limestone

350

Lias Transitional Facies 50

Tria

ssic U

pper

Mid

.Lo

wer

Lower Triassic-Lias AdigratSandstone 850

Lower Triassic to

UpperPaleozoic

-Upper Permian450

Basement rocks

Era Period Epoch Formation

P R E C A M B R I A N

Neo

gene

Miocene-Pliocene Volcanic

Lith-ology

Hydrocarbon system components

Seal

Lithology and environment

Fluviatile sandstonelwith intercalation of siltstone

Fluviatile mudstone with intercalation of siltstone and sandstone

Fluviatile and marine faciesShelf marine limestone with intercalation of shales

Tidal flat and fluvatilegypsum,mudstone siltstone, and limestone

Flvial and marinefacies

Alluvial fan and fluviatile sandy conglomerate, sandstone and siltstone

Fluviatile sandstone and shales

Reservoir

Reservoir

Source

Seal

Reservoir

Reservoir/source (?)

g

Maximum Thickness in (m)

Karroosediments

Palae-ozoic

Basalt, trachyte,rhyolite with beds of tuff

Fig. 2. Geological map of theBlue Nile Basin (simplifiedafter Kazmin, 1972).

Fig. 3. Chrono- andlithostratigraphy of theBlue Nile Basin.


thick Transitional Zone with shales, limestones,sandstones, dolostones and evaporites (Fig. 3).

This is overlain by the transgressive Middle andUpper Hamanlei Limestone Formations which reach amaximum thickness of 1,140 m, thickening towardsthe north and NE. The Bathonian-Oxfordian MiddleHamanlei Limestone Formation (420 m thick) iscomposed of dolostones, gypsum, mudstones, marlsand shales, with common algal stromatolites, greenalgae, foraminifera, gastropods and bivalves. TheUpper Hamanlei Limestone Formation (Oxfordian –Kimmeridgian), up to 720 m thick in the Blue NileBasin, was deposited during a major regionaltransgression which covered the whole of East Africa(cf. Bosellini, 1989; Russo et al., 1994). The formationis composed of limestones (skeletal packstone-wackestones, oolitic-skeletal packstones) alternatingwith black mudstones and black shales. Bioclastsinclude brachiopods, corals, algae, gastropods andechinoids. Intervals at least 30-50 m thick, composedof alternating beds of black mudstones, black shalesand limestones are exposed at Dejen and Jimma River,respectively (locations in Fig. 2). The black mudstones,shales and limestones are equivalent to the Agula Shaleof the Mekele Outlier (basin) in northern Ethiopia (Fig.1: Beyth, 1972), and to the Urandab Formation in theOgaden Basin (Raaben et al., 1979; Hunegnaw et al.,1998).

Overlying the Upper Hamanlei Limestone is theLower Cretaceous Muger Mudstone Formation (320m thick), and the Aptian-Cenomanian Debre LibanoseSandstone Formation (420 m thick) (Getaneh, 1991)(Fig. 3). Some 50 m of section is assumed to have beenerosively removed before the onset of Tertiary volcanicflows and trap volcanism dated at 49 Ma (Grasty etal., 1963).

Structural historyNE Africa has undergone several phases of riftingduring the Phanerozoic. A “Karroo” phase (LateCarboniferous to Triassic) led to the formation of north-south, NW-SE and NE-SW oriented rift basinsincluding the Ogaden and Blue Nile Basins (Raaben,1979; Tamrat and Astin, 1992; Gebre Yohanse, 1989;Hunegnaw et al., 1998). Associated basinal depositsare known as the Karroo Group. The Blue Nile Basinis interpreted as a NW-SE trending failed arm of theKarroo rift system (Russo et al., 1994; Korme et al.,2004) (Fig. 1). A second phase of rifting occurred inthe Early to Middle Jurassic. A coeval marinetransgression resulted in the deposition of marinesediments in the Ogaden, Blue Nile, Southern Red Seaand Mandwa areas including carbonates, evaporitesand siliciclastics (Wolela, 1997; Hunegnaw et al., 1998;Bunter et al., 1998). During the Miocene, normal faultblocks developed, possibly reactivated along NW-SE

trending Karroo Rift trends. These are exposed inthe Bichena, Fincha, Dejen-Gohatsion and AbayRiver areas (Fig. 2).

Beginning at the end of the Cretaceous, riftingbegan in the Gulf of Aden area and ultimately resultedin the formation of the Red Sea and the MainEthiopian Rift (McConnel, 1972; Kent, 1974; Bunteret al., 1998; Korme et al., 2004) (Fig. 1). The Karroorift system is thus dissected by the Main EthiopianRift which separates the Blue Nile Basin from theOgaden Basin. The NE-SW and north-south to NNE-SSW trending fault systems of the Main EthiopianRift are exposed in the western rift escarpment inthe eastern part of the Blue Nile Basin (Fig. 2).

MATERIALS AND METHODS

Thirty one samples of potential source rocks werecollected from the Karroo Group, Adigrat SandstoneFormation, Middle Hamanlei Limestone Formationand Upper Hamanlei Limestone Formation. Thesamples came from the Dejen, Gohatsion, GendeBeret, Fincha, Weleka, Jimma and Arjo areas (Table1) and comprised (i) dark grey Karroo shale (onesample), (ii) lacustrine sapropelic coals from theupper part of the Adigrat Sandstone Formation (twosamples); (iii) algal-rich gypsum from the MiddleHamanlei Limestone Formation (three samples); and(iv) limestones and black shales and mudstones fromthe upper part of the Upper Hamanlei LimestoneFormation (25 samples). All samples were collectedfrom outcrop exposures as there are no wells in thebasin.

The samples were cleaned in an ultrasonic waterbath. Crushed black shale and mudstone sampleswere placed in a crucible and pyrolyzed at 300°C for3 min, followed by programmed pyrolysis at 25°C/minute to an optimum temperature of 600°C in ahelium atmosphere. Standard S1, S2, S3 and Tmaxmeasurements were recorded with a Rock-Eval IIinstrument, as were the hydrogen index (HI) andoxygen index (OI). The production index (PI),defined as the ratio S1/(S1+ S2) (Peters, 1986), wasalso determined.

Gold-coated black mudstones from the UpperHamanlei Limestone Formation were examinedunder a JEOL 6400 scanning electron microscopeequipped with an energy dispersive X-ray analysis(EDX) system with accelerating voltage 10 to 15 kV,to study the mineral composition and distribution ofauthigenic minerals. Other samples were mountedon aluminium pin stubs and polished to 0.5 μm forvisual analysis. A Nicrphot-Fxa reflectancemicroscope attached to a Fiber optic light source,light collecting Pi, monochromatic filter, oilimmersion lenses (10x, 20x, 40x, 60x), and oil

393A. Wolela

refractive index 1.56 were used for vitrinite reflectancestudies.

Samples of seepage oil were collected from theWere Ilu locality (Fig. 2) and were analysed by (i)liquid chromatography to determine the saturate,aromatic, NSO and asphaltene fractions; (ii) gaschromatography of the saturate and aromatichydrocarbon fractions and (iii) GC-MS biomarkeranalysis of the saturate fractions. Steranes weremonitored at m/z 217 (regular steranes), m/z 218 (αββsteranes), and m/z 259 (diasteranes) and m/z 191(terpanes). Carbon isotope ratios of the whole-oilsaturate and aromatic hydrocarbon fractions were alsodetermined.

Lopatin (1971, in Waples, 1980) described a simplemethod to estimate the effect of time and temperatureon source rock maturation. For this study, burialhistory curves and thermal maturities were constructedusing a modified Lopatin-type software programmedeveloped at the Queen’s University of Belfast(Monson, 1995). Inputs included the age and thicknessof the formation; the geothermal gradient (assumedto be 27oC/km by analogy with similar rift basins);and the erosional history of the basin. Using this data,the programme reconstructed the burial history ofspecific formations and determines the Lopatin timeand temperature index (TTI). The software alsoindicates the peak time and duration of oil and wetgas generation, and the time of dry gas generation.

RESULTS

TOC and kerogen type (Table 1, Fig. 4)The shale sample from the Karroo Group had a TOCof 0.13%. Sapropelic coal samples from the AdigratSandstone Formation had TOCs between 1 and 6%,and contained Type II kerogen. Algal-rich gypsumintervals in the Middle Hamanlei LimestoneFormation had low TOC contents (0.04-0.1%) andcontained Type II kerogen. TOC values for limestonesfrom the Upper Hamanlei Limestone Formationranged from 0.03 to 0.11%, whereas black mudstonesand shales from this formation had TOCs ranging from0.7 to 7.2% with Type II kerogen.

Rock-Eval pyrolysisThe shale sample from the Karroo Group had Tmaxand S2 values of 474°C and 0.03 gHC/kg rock,respectively. For coal samples from the AdigratSandstone Formation, S2 ranges from 7 to 30 gHC/kgrock, while Tmax and HI values are 421-426 °C, and501-508 mgHC/gCorg, respectively. Algal-richgypsum samples from the Middle HamanleiLimestone Formation had Tmax and S2 values of 438-440°C and 0.08-0.25 gHC/kg, respectively.

Limestones from the Upper Hamanlei LimestoneFormation had Tmax values of 427-445°C, and S2 valuesof 0.09 to 1.4 gHC/kg rock, indicating poor sourcerock potential. Black shales and mudstones from the

Immature Mature Supermature

420 440 460 480 500 520

150

300

450

600

750

Tmax °C

Hyd

rog

en

ind

ex

(mg

/gTO

C)

Type III

Type II

Type I0.5

1.3

1.3 isoreflectance

Limestone, Upper Hamanlei Limestone Formation

Shale, Upper Hamanlei Limestone Formation

Algal-rich gypsum, Middle Hamanlei Limestone Formation

Legend

Coal, Adigrat Sandstone Formation

Shale, Karroo sediment

Fig. 4. Cross-plot of hydrogen index versusTmax for 22 shale and limestone samples fromthe Upper Hamanlei Limestone Formation,together with samples from the MiddleHamanlei Limestone Formation, AdigratSandstone and Karroo Group (see data inTable 1).


Are

aS

ampl

e Ty

peFo

rmat

ion

Age

Sam

ple

No

TOC

in %

S1H

Cg/

kgS2

HC

g/kg

S3H

Cg/

kgPI

HIm

gHC

/gC

org

OIm

gCO

2/g

Tmax

in

o C

Vitri

nite

re

flect

ance

(R

o) in

%S

hale

UH

FW

A-2

4.2

2.86

25.2

31.

240.

160

029

.542

60.

5Li

mes

tone

UH

FW

A-57

0.04

0.08

0.12

0.23

0.4

300

575

442

0.1

Lim

esto

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WA-

320.

040.

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090.

20.

4422

565

042

80.

2G

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mM

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onia

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0.03

0.05

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0.14

0.33

333

467

434

0.2

Sha

leU

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6.8

1.5

35.2

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518

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hale

UH

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-24.

71

30.6

1.1

0.03

417

1644

10.

5S

hale

UH

FB

NS

-31.

90.

26

0.8

0.03

613

1943

60.

3M

udst

one

UH

FB

NS

-45.

22

24.3

10.

0646

529

445

0.7

Sha

leU

HF

BN

S-6

2.82

0.13

16.3

50.

90.

0157

931

424

0.5

Sha

leU

HF

BN

S-7

6.8

1.6

35.2

1.1

0.04

518

742

60.

5M

udst

one

UH

FB

NS

-83.

30.

616

.91

0.03

520

742

40.

4S

hale

UH

FB

NS

-90.

70.

054.

10.

60.

0158

09

424

0.3

Sha

leU

HF

BN

S-1

06.

680.

2737

.38

0.2

0.01

560

425

0.4

Sha

leU

HF

BN

S-1

17.

112.

938

0.66

0.07

535

944

10.

4M

udst

one

UH

FB

NS

-12

2.55

0.06

12.9

90.

0256

043

90.

6S

hale

UH

FB

NS

-13

1.86

1.09

8.12

0.6

0.02

436

3343

10.

5Li

mes

tone

UH

FW

A-41

0.11

0.16

0.22

0.17

0.42

200

155

427

0.7

Lim

esto

neU

HF

WA-

470.

050.

070.

090.

220.

4418

044

044

30.

1S

hale

UH

FB

NS

-55.

40.

616

0.7

0.03

573

1844

50.

7G

ypsu

mM

HF

Bath

onia

nW

A-63

0.03

0.06

0.08

0.06

0.43

260

200

440

0.7

Mud

ston

eU

HF

Oxf

ordi

an-

Kim

mer

idgi

anW

E-02

10.2

1.6

10.1

1.2

0.14

420

1044

00.

9

Sha

leU

HF

Oxf

ordi

an-

Kim

mer

idgi

anW

E-01

6.7

2.1

1.2

1.6

0.15

320

944

50.

89

Gen

de

Bere

tS

hale

UH

FO

xfor

d.-K

imm

.G

B-1

9.11

4.02

603.

520.

0666

038

426

0.6

Gyp

sum

MH

FBa

thon

ian

JM-4

0.16

0.15

0.25

0.13

0.4

330

280

438

0.2

Jim

ma

Blac

k lim

esto

neU

HF

Oxf

ordi

an-

Kim

mer

idgi

anJM

-50.

20.

61.

40.

420.

0332

144

143

80.

5

Sha

leU

HF

JM-1

0.87

1.13

4.27

0.42

0.2

425

3044

60.

8S

hale

UH

FJM

-27.

221.

115.

131.

20.

1842

516

431

0.9

Sha

leU

HF

JM-3

1.95

1.07

8.82

0.27

0.11

438

1845

21.

1C

oal

AS

FAR

-11.

330.

036.

750.

20.

0150

816

426

0.3

Coa

lA

SF

AR-2

5.96

0.17

29.8

30.

40.

0150

119

421

1Fi

ncha

aS

hale

KSPe

rmia

nFS

-10.

130.

010.

030.

70.

2515

474

L. T

riass

ic

Oxf

ordi

an-

Kim

mer

idgi

an

Oxf

ordi

an-

Kim

mer

idgi

an

Oxf

ordi

an-

Kim

mer

idgi

an

Oxf

ordi

an-

Kim

mer

idgi

an

Arjo

Goh

atsi

on

Sect

ion

Dej

en

Sect

ion

Wel

eka

Sect

ion

Tabl

e 1.

Pyr

olys

is a

nd v

itri

nite

ref

lect

ance

ana

lyse

s fo

r sa

mpl

es fr

om t

he B

lue

Nile

Bas

in. U

HF:

Upp

er H

aman

lei F

orm

atio

n; M

HF:

Mid

dle

Ham

anle

i For

mat

ion;

ASF

L A

digr

at S

ands

tone

For

mat

ion;

KS:

Kar

roo

sam

ple.

395A. Wolela

formation have Tmax values generally ranging from 424to 445º C (Fig. 4). S2 yields are up to 37.3 gHC/kg, andthe HI ranges between 465 and 660 mgHC/gCorg.Production index and vitrinite reflectance values for theblack mudstones and shales of the Upper HamanleiLimestone Formation are low in terms of oil generationin the Dejen-Gohatsion area; however, they aresufficiently high for oil generation to occur for samplesfrom the Jimma and Weleka areas (Table 1).

Vitrinite reflectance (Table 1)Black shales from the Karroo succession had vitrinitereflectance (Ro) of 1.1%. The Ro of sapropelic coals fromthe Adigrat Sandstone Formation ranged from 0.3 to0.4%. The black shales and mudstones from the UpperHamanlei Limestone Formation had Ro values of 0.2-0.9%.

SEM studiesScanning electron microscope (SEM) studies showedthat the black mudstones and shales from the UpperHamanlei Limestone Formation from Dejen includedpyrite crystals, plant remains, algal bodies, thin organic-rich laminae and authigenic clay minerals such assmectite. The presence of pyrite crystals in the blackmudstones and shales is an indicator of a marinedepositional environment (Curtis, 1978) or of a latermarine transgression which diagenetically influenced theunderlying sediments.

TTI modellingData used for the reconstruction of burial historycurves for the Dejen-Gohatsion and Were Ilu areasare given in Tables 2 and 3. Burial historyreconstruction and TTI modelling indicate that theUpper Hamanlei Limestone Formation has notentered the oil window in the Dejen-Gohatsion area(Table 2, Fig. 5). Here, the Upper HamanleiLimestone Formation is overlain by a 300 m thickvolcanic succession but burial is not sufficient foroil generation to occur.

At Were Ilu, the Upper Hamanlei LimestoneFormation is overlain by a 560 m thick Mesozoicsedimentary succession and 1100 m of Tertiaryvolcanic rocks. The formation is modelled to haveentered the oil window and to have generated oilfrom 10 Ma to the present day (Table 3, Fig. 6).

GEOCHEMICAL CHARACTERISTICSOF THE WERE ILU SEEPAGE OIL

The occurrence of an oil seep at Were Ilu is possiblyrelated to the presence of near-vertical NW-SE, NE-SW and north-south trending fractures presentwithin alkali olivine basalts on the bed of theMechela River. These deep-seated fractures mayhave allowed the upward migration of hydrocarbonsto the surface. The seepage oil takes the form of ablack, sticky tar (Fig. 7a,b), Geochemical studiesof the Were Ilu seepage oil indicated that the

Formation Time in million years

Thickness in metres

Depth in metres

Geothermal gradient

Erosion in metres

Volcanics 49 300 300 27°C / kmUpper Sandstone (Mugher

Mudstone and Debre Libanose Sandstone)

110 560 860 27°C / km 50

Upper Hamanlei Limestone 150 420 1280 27°C / kmMiddle Hamanlei Limestone 180 350 1630 27°C / km

Adigrat Sandstone 230 450 2080 27°C / kmKarroo 280 450 2530 27°C / km 200

Formation Time in million years

Thickness in m

Depth in m

Geothermal gradient in

Erosion in m

Volcanics 49 1100 1100 27°C / kmUpper Sandstone (Mugher

Mudstone and Debre Libanose Sandstone)

110 560 1660 27°C / km 50

Upper Hamanlei Limestone 150 720 2380 27°C / kmMiddle Hamanlei Limestone 180 350 2730 27°C / km

Adigrat Sandstone 230 850 3580 27°C / kmKarroo 280 450 4030 27°C / km 200

Table 2. Data used for reconstruction of the burial history curves in the Dejen-Gohatsion area.Geothermal gradient value is based on that in similar intercratonic rift basins.

Table 3. Data used for reconstruction of the burial history curves in the Were Ilu area.Geothermal gradient is based upon that in similar intercratonic rift basins.


aromatic hydrocarbon content is 53%, saturates 26%,asphaltenes 17% and NSO compounds 6%. Dominanthydrocarbons include C27 to C29 steranes (Figs. 8,9,10).The m/z 191 chromatogram indicates an abundanceof terpanes (Fig. 11) as well as C17 and higher hopanes(C31+). The relatively low abundance of tricyclicterpanes probably reflects the effects of microbialdegradation. The oil has a relatively low sulphurcontent (total sulphur: 0.5%). The m/z 217chromatogram indicates that C29 steranes areapproximately equal to C27 steranes. The Pr/Ph ratioof the seepage oil is 0.90 (Fig. 9).

The seepage oil has probably undergone moderatebiodegradation and water washing, removing water-

soluble hydrocarbons such as benzene and toluene(Palmer, 1991). Biodegraded oils are in generalidentified by their low contents of n-paraffins relativeto branched hydrocarbons (e.g. C19 and C20isoprenoids, pristane and phytane) and cyclichydrocarbons (naphthenes and aromatic hydrocarbon)(Williams et al., 1986).

DISCUSSION AND INTERPRETATION

Tmax values below 435º C are associated with rockswhich are thermally immature with respect of oilgeneration, while values in the range of 435-460 ºCindicate peak maturities (Tissot and Welte, 1984;

Palaezoic Mesozoic CenozoicPermian Triassic Jurassic Cretaceous PalaeogeneNeog

1km

2km

Karroo sediment

Adigrat sandstone

Middle Hamanlei

Upper Hamanlei

Upper Sandstone

Volcanic rocks

Formation

Depth

Age scale

CenozoicPalaeogene Neog.CretaceousJurassicTriassic

MesozoicPalaeozoicPermian

Karroo sediments

Adigrat Sandstone

Middle Hamanlei

Upper Hamanlei

Upper Sandstone

Trap volcanics

1km

2km

3km

4km

Legend

FORMATION

Oil window

2kmDepth

Age scale

Peak of oil generation

Fig. 5. Burial history reconstruction for the Dejen-Gohatsion area, Blue Nile Basin.

Fig. 6. Burial history reconstruction for the Were Ilu area, Blue Nile Basin. The estimated time of peak oilgeneration in the Upper Hamanlei Limestone Formation is indicated.

397A. Wolela

Fig. 7. Outcrop photos from the Were Ilu area:(a) bitumen (Bt) veins and limestone clast (C );30cm hammer for scale.(b) bitumen in veins (Bt) and geoids (Btg), andweathered volcanic ash (A); 15cm pencil for scale.

Fig. 8. GCMS 217 ion chromatogram showing compounds of steranes, Were Ilu oil seepage sample (GAX96223.D), Blue Nile Basin. Peak identification:

A 13β, 17α-diacholestane (20S); B 13β, 17α-diacholestane (20R);C 13α, 17β-diacholestane (20S); D 13α, 17β-diacholestane (20R);E 24-methyl-13β, 17α-diacholestane (20S); F 24-methyl-13β, 17α-diacholestane (20R);G 24-methyl-13α, 17β-diacholestane (20S) +14α, 17α-cholestane (20S);H 24-ethyl-13β, 17α-diacholestane (20S) +14β,17β-cholestane (20R);I 14β, 17β-cholestane (20S) +24-methyl-13α, 17β-diacholestane (20R);J 14α, 17α-cholestane (20R); K 24-ethyl-13β, 17α-diacholestane (20R);L 24-ethyl-13α, 17β-diacholestane (20R); M 24-methyl-14α, 17α-cholestane (20S);N 24-methyl-14,β 17β-cholestane (20R) + 24-ethyl-13α, 17β-diacholestane (20R);O 24-methyl-14B, 17β-cholestane (20S); P 24-methyl-14α, 17α-cholestane (20R);Q 24-ethyl-14α, 17α-cholestane (20S); R 24-ethyl-14β, 17β-cholestane (20R);S 24-ethyl-14β, 17β-cholestane (20S); T 24-ethyl-14α, 17α-cholestane (20R).


Fig. 9. Gas chromatogram result showing saturates, steranes and triterpanes. Prominent C19, C20 isoprenoidalkanes, pristane and phytane are labelled, Were Ilu oil seepage sample (GAX 96223.D), Blue Nile Basin.

Fig. 10. GC MS 218 ion chromatogram showing steranes compound, Were Ilu oil seepage sample (GAX96223.D), Blue Nile Basin. Labels referring to clusters of peaks.

Peters, 1986; Peters and Cassa, 1994). Pyrolysisresults of the Karroo Group sample indicated that itis overmature, whereas the coal samples from theAdigrat Sandstone Formation are oil-prone butimmature (Fig. 4). Algal-rich gypsum in the MiddleHamanlei Limestone Formation and the limestonesfrom the Upper Hamanlei Limestone Formation haveTOC and S2 values too low for significant hydrocarbongeneration (Table 1).

The hydrogen index of the black shales andmudstones in the Upper Hamanlei Limestone

Formation was between 465 and 660 mgHC/gCorg,indicating good source rock potential (c.f. Peters,1986; Peters and Cassa, 1994). Vitrinite reflectanceresults for these black shales and mudstones are up to0.9%, consistent with peak oil generation (cf. Senftleand Landis, 1991). A plot of (S1+S2) versus TOC forthe black mudstones and shales (Fig. 12) indicatesType II kerogen with good source potential.

The Were Ilu seepage oil sample had a Pr/Ph ratioof 0.90 (Fig. 9) and C29 steranes equal to C27 steranes,suggesting derivation from a marine carbonate-

399A. Wolela

Fig. 11. Gas chromatogram 191 ion showing pentacyclic triterpanes, Were Ilu oil seepage sample (GAX96223.D), Blue Nile Basin. Pead identification:

Maturity Source Maturity/sourceST1 = 0.42 ST5 = 35, 24, 41 ST =0.94ST2 = 0.48 ST7 = 0.34 TT1= 0.40ST3 = *** TT6 = *** TT5 = ***ST4 = *** TT7 = *** TT10 = ***MP1 = *** TT8 = *** TT11 = ***MP2 = *** TT9 = ***TT2 = 0.11TT3 = 0.13TT4 = 60%

dominated source rock. The sterane and terpanedistributions indicated that the source rock includedterrestrial material. The distribution of αββ steranes(m/z 218) indicated that the contribution by terrestrialterrigenous materials was significant. The distributionof diasteranes (peaks A, B, H and K in Fig. 8) indicatescatalysis of steranes resulting from interactions withclay minerals within the source rocks.

Within a source rock, the ratio of C29 ααα20S toααα20R steranes (ST1) varies according to the

diagenetic history. ST1 and ST2 values of 0.42 and0.48, respectively (Table 4) indicate that the seepageoil was generated by an early to mid- mature sourcerock. This is consistent with a Ts/Tm value of 0.40,also indicating early to mid oil window maturity.

Carbon isotope ratiosPrevious studies of the seepage oil resulted in carbonisotope compositions (δ13C) of -25.91 for aromatics,-26.9 for saturates and -26.1 for oil. The canonical

Table 4. Biomarker data for the Were Ilu seepage oil sample (GAX 96223.D).

1 18α(H)-22, 29, 30-trisnorhopane (Ts); 2 17α (H)-22, 29, 30-trisnorhopane (Tm);3 17α (H)-28, 30-bisnorhopane; 4 17α (H)-norhopane;5 17β-normoretane; 6 17α-hopane;7 17β-moretane; 8 C31 homohopane (22S);9 C31 homohopane (22R) 10 C32 bishomohopane (22S);11 C32 bishomohopane (22R); 12 C33 trishomohopane (22S);13 C33 trishomohopane (22R); 14 C34 tetrakishomohopane (22S);15 C34 tetrakishomohopane (22R); 16 C35 pentakishomohopane (22S);17 C35 pentakishomohopane (22R).


value (- 2.53 (δ13Csats) + 2.22 (δ13Carom) -11.65) is -1.15(Geochemical Service, 1990). The canonical value(CV) can be used to differentiate algal (marine or non-marine) sourced oils from oil generated from terrestrialorganic matter. Algal-sourced oils tend to producecanonical values < 0.47, whereas terrestrial-sourcedoils give values > 0.47 (Sofer, 1991). In general, oilsthat are isotopically heavy (less negative) areconsidered to have a marine origin, whereasisotopically light (more negative) oils are thought tobe derived from terrestrial sources (Scalan andMorgan, 1970). The canonical value of the seepageoil was -1.15 suggesting that it was derived from amarine shale dominated source rock.

SUMMARY AND CONCLUSIONS

(1) Black mudstones and shales within the UpperHamanlei Limestone Formation in the Blue Nile Basinhave significant source rock potential. Burial historyreconstruction and TTI modelling suggest that theformation is within the oil window in the northernpart of the basin. A seepage oil here was analysedand was found to have been generated by an early tomid oil window source rock.

(2) Pyrolysis of a shale sample from the Permian-Triassic Karroo Group indicated that it is overmature,

whereas samples of sapropelic coals from the AdigratSandstone Formations are oil-prone but immature.Algal-rich gypsum in the Middle Hamanlei LimestoneFormation and limestones in the Upper HamanleiLimestone Formation have little source rock potential.

Black mudstones and shales in the UpperHamanlei Limestone Formation have TOC values upto 7.2%, with Ro of 0.3-0.9%. A plot of (S1+S2) versus(TOC) indicated Type II kerogen; HI was 465-660mgHC/gCorg. The black shales and mudstones areimmature in the Dejen-Gohatsion area due to shallowburial; they are more deeply buried in the Jimma andWeleka areas and are sufficiently mature here togenerate oil.

(3) Lopatin modelling indicates that the blackmudstones and shales in the Upper HamanleiLimestone Formation entered the oil window at 10Ma and continue to generate oil at the present day.

(4) An oil seepage at Were Ilu in the northern partof the basin indicates the presence of an activepetroleum system. Gas and liquid chromatography,GC-MS biomarker analysis of the saturate fractionsand carbon isotope data indicate that the seepage oilwas derived from a marine source rock with an influxof terrestrial organic matter. The seepage oil ismoderately biodegraded, which resulted in the lossof normal alkanes and aromatic hydrocarbons

Poo

rFa

irG

oo

dEx

ce

llent

Poor Good Excellent

TOTAL ORGANIC CARBON (%)

TOTAL HYDROCARBONGENERATION POTENTIAL(mg HC/g rock)

0.1 1 10 TOC

1

10

100

0.1

g

S +S1 2

Black limestone, Upper Hamanlei Limestone Formation

LegendBlack shale and mudstone

Algal-rich gypsum, Middle Hamanlei Limestone Formation

Fig. 12. Cross-plot of TOC versus(S1+S2) for black shales andmudstones from the Upper HamanleiLimestone Formation, and for othersamples analysed.

401A. Wolela

(benzene and toluene), whereas iso-alkanes, tetracyclicalkanes and pentacyclic alkanes are preserved. ThePr/Ph ratio of the oil seepage is less than 1, suggestingmarine shelf sediment. Carbon isotope datacorroborates the biomarker data suggesting a marinedepositional environment. The abundant distributionof steranes indicating mixed type of organic materials(marine and terrestrial) for the oil generation.Pentacyclic triterpanes are more abundant thansteranes. Higher hopanes are well developed. Thepresence of diasteranes indicates a high clay contentin the parent source rocks.

ACKNOWLEDGEMENTS

This paper uses data from the author’s Ph.D thesis(Wolela, 1997). Previous drafts of the manuscript wereread by John Parnell whose comments are gratefullyacknowledged. E. Geirlowski-Kordesch, A. Ruffel andA. Hunegnaw are also thanked for constructive andvaluable reviews. A previous version of the manuscriptbenefited from journal review by M. Pearson and M.Russell. Most of the laboratory work was carried outat the Queen’s University of Belfast whose staff areacknowledged for their support and help. The researchwas financially supported by the Ministry of Minesand Energy, Ethiopia and the School of Geosciences,Queen’s University of Belfast.

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