Petroleum geochemistry of the Midyan and Jaizan basins of the Red Sea, Saudi Arabia

Marine and Petroleum Geology, Vol. 12, No. 6, pp. 597-614, 1995 Copyright © 1995 Elsevier Science Ltd Printed in Great Britain. All rights reserved 0264-8172/95 $10.00 + 0.00

r~UTTERWORTH I"~'IE 1 N E M A N N

Petroleum geochemistry of the Midyan and Jaizan basins of the Red Sea, Saudi Arabia Gary A. Cole*, Mahdi A. Abu-Ali, Edwin L. Coiling, Henry I. Halpern, William J. Carrigan, G. Richard Savage, Reggie J. Scolaro and Saleh H. AI-Sharidi The Saudi Arabian Oil Company (Saudi Aramco), Box 62, Dhahran 31311, Saudi Arabia Received 3 August 1994;revised 24 October 1994; accepted 1November 1994 During the 1960s, petroleum exploration activities in the offshore Red Sea areas of Saudi Arabia tested gas and condensate reservoired in the Miocene sands immediately below the Mansiyah evaporites in the offshore Midyan basin. Recent onshore exploration activity in the Red Sea has resulted in the discovery of accumulations of oil, gas and condensate in the Lower Miocene Maqna Group in the Midyan and Jaizan basins. As a result of this exploration success, an effort to understand the origin of these hydrocarbons was initiated. The two basins were assessed geochemically by addressing: (1) the potential source rocks; (2) the extent of the hydrocarbon kitchens; and (3) characterization of the hydrocarbons. The potential source rocks for the reservoired hydrocarbons are: (1) the organic-rich, oil-prone shales of the predominantly evaporitic Mansiyah Formation; (2) the variable quality shales and carbonates of the Maqna Group; and (3) the moderately organic-rich shales of the Burqan and Tayran Groups. The reservoired hydrocarbons were characterized by carbon isotopes, gas chromatography-mass spectrometry and gas chromatography and compared with the potential source rocks. The results showed an acceptable match to the Maqna and Burqan organic-rich units. Detailed burial history/thermal modelling projects were undertaken to assess the hydrocarbon kitchens of both basins. Results for the Midyan basin indicated that over large areas Tayran and Burqan sediments are oil to gas mature and may be sources for the gas and/or condensate accumulations, whereas the limited area of mature Maqna sediments may be responsible for sourcing the black oil accumulations. In the Jaizan basin, the Maqna and Burqan sediments range from high oil maturity to thermally spent due to high geothermal conditions and excessive burial. The burial of the source rocks increases fairly rapidly from east to west in the Jaizan basin. Keywords: Tertiary Red Sea; biomarkers; source rocks; thermal maturity

Evaluation of the petroleum potential of a sedimentary basin requires (1) the identification of possible source rocks, (2) the determination of the hydrocarbon generative potential of those source rocks, (3) the correlation of reservoired hydrocarbons and shows to the potential source rocks, (4) an assessment of their thermal maturity and (5) the establishment of migration pathways as they relate to the trapping of hydrocarbons. Source rocks containing sufficient organic material with hydrogen indices high enough to have the potential to generate oil can be identified using petroleum geochemical techniques such as total organic carbon and Rock-Eval pyrolysis (Hunt, 1979; Burtner and Warner, 1984; Tissot and Welte, 1984; Peters, 1986; Brooks et al., 1987; Peters and Moldowan, 1993). After expulsion, hydrocarbons

* Correspondence to D r G. A. Cole at: Westport Technology Center International, l i T R e s e a r c h Institute, 6700 Portwest Drive, H o u s t o n , T X 77024, U S A

follow focused migration pathways until they encounter either structural or stratigraphic traps. A primary facet of the petroleum assessment of a basin, if not the most important, is determining when hydrocarbon generation and expulsion from the source rocks occurred within a basin. The assessment of the thermal maturity of a source rock is important in determining the degree to which hydrocarbon generation has proceeded in the source rock. More importantly, the timing of hydrocarbon generation and expulsion in relation to trap development is critical to the evaluation of the petroleum potential within a basin. This requires the construction of burial history and thermal maturity models which are used to develop maturity maps for geologically significant periods. These maps are then used to determine (a) where the oil kitchen is located, (b) when expulsion occurred and (c) which traps are most likely to be filled along the major migration pathways. Construction of burial history models requires time-stratigraphic data, which can be obtained from:

Marine and Petroleum Geology 1995 Volume 12 Number 6

597

Petroleum geochemistry of the Midyan and Jaizan basins: G. A. Cole et al. (1) formation and ages derived from well information; (2) seismic data, especially if seismic reflectors can be tied to well data; and (3) estimates made f r o m thicknesses of nearby exposed sections. In most instances a geological reconstruction of the sedimentary basin must also be performed to determine significant geological events such as rifting, burial, uplift and erosion. Once a geological model is established, the thermal history, maturation and hydrocarbon generation of the basin can be modelled

using the time temperature index (TTI) method (Roydon et al., 1980; Waples, 1980; Middleton, 1982; Issler, 1984; Dykstra, 1987; Wood, 1988; Morrow and Issler, 1993) or more accurate kinetic models based on the Lawrence Livermore National Laboratories (LLNL) methods (Burnham and Sweeney, 1989; 1991; Sweeney, 1990; Sweeney and Burnham, 1990). These models must then be calibrated against measured maturity data and bottom-hole temperatures to yield the most realistic results (Waples et al., 1992).

o 3 Kilometers

C.I.= 500m(frommsl)

%

JORDAN

IRAQ O~ Rahfa %-... SAUDI ARABIA • AI-Jawf

• Tabuk

////.,,.t / / ~% %%% % %.%/%/ % "'-~ "" % " "k•Ur1% ,2%/%s' %%1%,~% /%/% /%/%,~%/%/%% / ~ ~ /%/%e,%, %~% /%/%/% .~/%/% ,~%/%.~%/%/ / % % %/%/%~

- - ~ r-'

/

~/%~/sSHIELD %/%~/%~

% % %/% % % %/% % % %/%/%/%/%/%/ %/%~%/%~%/%/%/%~%/ ~ % %/%/%/%~%/ /~///

SUDAN SEA

' ~ :"/.." ~" ..~ I / t I J ETHIORA

~I ~ _ JAIZA RAQ,

%/

I

; Mansiyah Well and 3 pseudowellsto north

%

0 ~ 5 I0 Kilometers Contour Interval = 500 meters • Well • Pseudowell

~ _ _ ~ ~ ,YEMEN

,/ '

0

100

200

Kilometers

%

\

I

~.:.~.:.'::.s:~.~:~i~:.;¢=,,k~r~.

Jaizan North-1 &-3 Jaizan North-2

RED SEA Jaizan South-1 Jaizan Southeast-1 -

Figure I Map of the Red Sea showing the location of the Jaizan and Midyan basins. More detailed basin maps are inset. These maps show the structural configuration and sampling sites in each respective basin. The map of the Midyan basin uses a 500 m contour and the well sites are identified by squares. The Jaizan basin structural contour interval is 500 m and the well sites are identified by closed circles. * Denotes the models illustrated in Figures 9 and 10

598

Marine and Petroleum G e o l o g y 1995 V o l u m e 12 N u m b e r 6

Petroleum geochemistry of the Midyan and Jaizan basins: G. A. Cole et al. The objectives of this paper are to: (1) present a regional interpretation and assessment of the source rock potential in the Midyan and Jaizan basins of the Red Sea (Figure I); (2) determine the most likely sources of the oils and condensates reservoired in the Midyan and Jaizan basins; and (3) map the hydrocarbon maturity kitchens to determine the timing of hydrocarbon generation and expulsion using one-dimensional burial history/thermal models. Figure 1 places the Midyan and Jaizan basins of the Red Sea in a regional perspective. The Midyan basin is located at the nothernmost part of the Red Sea at the juncture between the Red Sea and the Gulf of Aqaba, whereas the Jaizan basin is located in the southern Red Sea immediately to the north of Yemen. The regional geology for both of these basins is remarkably similar. Both basins formed as a result of late Oligocene to early Miocene rifting (Ahmed, 1972; Tewfik and Ayyad, 1982; Beydoun, 1989; Savoyat et al., 1989; Crossley et al., 1992; Mitchell et al., 1992). Following rifting, the Red Sea basins were filled with a series of coarse- to fine-grained clastic sediments, but some periods of carbonate and evaporite deposition also occurred. Figure 2 shows the chronostratigraphic diagram for the Midyan and Jaizan basins, and also lists Gulf of Suez and Sudan formation equivalents and the petroleum system events (source rock, reservoir and seal). Drilling success in the Midyan and Jaizan basins have been mixed, with the Midyan basin seeing the greater success. Six wells have tested two large structures in the Midyan basin. Three wells in the late 1960s tested the Burqan structure and encountered commercial amounts of condensate and gas with black oil shows. Saudi Aramco renewed drilling in 1992 with the drilling of the Midyan structure. Three wells tested commercial amounts of condensate, wet gas and sweet (black) oil (Oil and Gas Journal, 1994). In the Jaizan basin, six deep wells have been drilled with minor success. In the late 1960s the Mansiyah well was drilled and was completed as a dry hole (plugged and abandoned). However, this well did contain an oil show immediately above the Mansiyah evaporites. Three wells in the Jaizan north area tested 42 ° API gravity, waxy, paraffinic crude oil and dry gas. Two wells to the south encountered no significant hydrocarbons, and were completed as dry holes.

Source rock analyses Methods Neogene-age samples were obtained from wells drilled in the Midyan and Jaizan basins (Figure 1). Selected core and drill cuttings samples were analysed for total organic carbon (%TOC), Rock-Eval pyrolysis ($2 peak indicates potential productivity in immature rocks), total soluble extract (TSE) and kerogen ~ 3 C isotopic composition. Oils and extracts were characterized for ~ a C isotopic composition, biomarkers and gas chromatography. To determine the source rock potential in a basin, the organic richness, the pyrolytic yields (or productivity), the hydrocarbon proneness or type and the maturity of the sedimentary section must be known.

~=~ ~

-~~=

~"~Z

Eustatic

[ i i

a

c~ Eg.u=

i i

-~ •

.~

i

I

~g

© [] Limestone [] Anhydrite [] Mixed Clastics

[] Salt • Oil & Gas Source [] Shale [] Gas Source [] Sandstone []Volcanics

Figure 2 Lithostratigraphic column for the Red Sea basins of Saudi Arabia showing the Saudi Arabian nomenclature and its equivalents in other parts of the Red Sea. Petroleum system events are plotted for source rocks, reservoirs and seals

Each of these parameters is critical when assessing the geochemical risk in a basin. The interpretive guidelines used here are modified from Hunt (1979), Tissot and Welte (1984), Burtner and Warner (1984), Peters (1986), Brooks et al. (1987) and Peters and Moldowan (1993) and are shown in Table 1. Given the above guidelines, a total of 313 shales (and occasional carbonates) from the Jaizan basin and 895 shales and carbonates from the Midyan basin have been analysed for their source rock quality. Because of the similarity between the two basins, the total of 1208 samples can be divided to evaluate each of the major Miocene sedimentary groups of rocks: the Ghawwas Formation, Mansiyah Formation, Maqna Group, Burqan Formation, Tayran Group and the pre-rift basement sediments. Figure 3 shows frequency histograms of TOC and $2 pyrolytic yields for each respective group. Based on these frequency histograms and the data summarized in Table 2, the Miocene

Marine and Petroleum G e o l o g y 1995 V o l u m e 12 N u m b e r 6

599

Petroleum geochemistry of the Midyan and Jaizan basins: G. A. Cole et al. Table 1 Source rock interpretation guide Poor

Moderate

Good

Very good

Excellent

Total organic carbon (in wt. %)

<1.0

1.0-2.0

2.0-3.0

3.0-4.0

>4

$2 pyrolysis yield (in mg HC/g rock)

<2.0

2 . 0 - 5.0

5.0-10.0

10.0-20.0

>20.0

Inert

Poor

Moderate

Good

V. good-excellent

Patterns used in Figures 5 and 6

rii ii ii iil

I

I

Gas-prone

Mixed

Oil-prone

Very oil-prone

Hydrogen index (HI) (in mg HC/g TOC)

<50

50-200

200-400

400-600

>600

Maturity

Immature

Early mature

Oil-expulsion

Oil preservation

Gas mature

Tmax (°C) from pyrolysis

<430

430-438

438-450

450-465

>465

Production index Sl/(Sl + $2)

<0.1

0.1-0.2

0.2-0.4

>0.4

na

Hydrocarbon type

Inert

Note: Both $2 pyrolysis yield and HI are influenced by maturity. As maturity increases, the $2 pyrolysis yield will decrease and, therefore, HI will become more gas-prone. At gas maturity, HI appears inert Geological units that contain >2% TOC and >5 $2 yield when immature are considered good source rocks if regionally extensive. These units are capable of expelling large amounts of hydrocarbons when sufficient maturity is attained

Mldyan Basin Source Rock Histograms 70 ~

~J ~ rd r~ V.'J

6O 1 -I

~ I ~ I~ ~ ~

Jaizan Basin Source Rock Histograms

I • GhawwasFormalion I [] MansiyahFormation I • MaqnaGroup I [] SurqanFormation I [] TayranGroup [1~1 Pre-Rift/BasementSediments

50

50

,, o~

40

II II

40

30

30

20

/

~

I

o

I

I

0

I

0

I

o

0

otal Or 80T-~ m 70t i :1 II

6o-:j II so ~] II

-

nic Car

I~ r~ F~ [~

N ~

P.I

r] II II

I ,5

o ~ d

n (wt.

I [ ] Ghawwas Fro. t==1 Mansiyah Fm. [ ] Maqna Group I [ ] Burqan Formation

I

I

o ,5 ,-:

I

o

I ~-~ o

I Boi n

c5 05

^

6 o~

Total Organic Carbon (wt. %) 70

• GhawwasFormation I [] MansiyahFormation I R Maqr~Group I I;:'] SurqanF. . . . tion l0 TaytanGroup l a P , e - . , ~ , s ~ , Sediments

., I~

I [] GhawwasFro. [ ] Mansiyah Fm. [ ] Maqna Group

II

I []

Burqan Formation

~

u

60

50

p

40 40 .e

u.

30

u.

11

30

10 o

S 2 Yield (mg HC/g rock) ~

S 2 Yield (mg HC/g rock)

Figure 3 Histograms s h o w i n g the distribution of total organic carbon (%TOC) and Rock-Eval pyrolytic yields (S2 yield in mg hydrocarbons per rock) for each of the s e d i m e n t a r y sequences in the M i d y a n and Jaizan basins

600

Marine and Petroleum Geology 1995 Volume 12 Number 6

Petroleum geochemistry of the Midyan and Jaizan basins: G. A. Cole et al. sedimentary sequences in the two basins can be summarized as follows: 1. Middle to Upper Miocene Ghawwas F o r m a t i o n primarily a non-source rock unit, but contains some minor gas-prone zones. 2. Middle Miocene Mansiyah Formation - - most of the sediments have poor source rock quality, but some thin shale and carbonate interbeds are present that have excellent organic richness and oil-prone potential. 3: Middle to Lower Miocene Maqna Group - - most shales and carbonates have poor to moderate source rock quality, but some zones possess excellent organic richness and oil-prone potential. The Maqna shales comprise the thickest oil-prone source rock unit observed on the Saudi Arabian side of the Red Sea. To illustrate the source rock distribution from the Midyan basin, Figure 4 shows a cross-plot between %TOC, $2 pyrolytic yield and hydrogen index versus depth for the Miocene sequence. As clearly shown, this representative well sequence contains numerous thin calcareous shale and limestone beds that have excellent source rock potential, as depicted by the 3 - 5 % TOC values and oil-prone hydrogen indices within this interval. However, the net thickness is estimated to be only about 20-30 m due to the thin nature of the beds. The best source rock observed in the Jaizan basin was also within the Maqna Group, but the thickness was ~<2 m. 4. Lower Miocene Burqan Formation - - most samples have moderate to good organic richness with mixed source rock quality in the Midyan basin, whereas the Burqan Formation in the Jaizan basin contains samples with poor to moderate source rock quality. 5. Lower Miocene Tayran Group - - most samples have poor to moderate organic richness and quality in both basins, but some Tayran shales in the Midyan basin have excellent organic richness and oil-prone potential.

Source rock discussion From the 1208 geochemical analyses of Miocene sediments, no regionally extensive or thick, oil-prone source rock units were identified or proved within the Jaizan and Midyan basins, except within the Maqna Group in the Midyan basin. However, some thin shale and carbonate units interbedded throughout the Lower to Middle Miocene sedimentary sequence of both basins may develop into thicker source rock packages distally. To better evaluate the potential of these thin organic-rich interbeds, a series of $2 yield versus %TOC cross-plots (Langford and Blanc-Valleron, 1990) were compiled for each sedimentary group. Figures 5 and 6 illustrate these cross-plots for the Ghawwas Formation, Mansiyah Formation, Maqna Group, Burqan Formation, Tayran Group and pre-rift sediments. The effects of maturity on the Sz yield versus %TOC cross-plots is not a serious issue, as the majority of data are from immature (<~0.5% VRe) to early mature (0.5-0.7% VRe) sedimentary units. Figure 7a and 7b illustrates cross-plots between Rock-Eval Tmax and Sz yield and production index and $2 yield and hydrogen index for the Jaizan basin; Figure 7c and 7d shows cross-plots between Rock-Eval Tmax and Sz yield and hydrogen index for the Midyan basin. As clearly shown, most samples from the Jaizan basin are immature or within the oil generation and expulsion window. For the most part, these samples represent the true potential of the shales, especially because about 95% of the samples contain < 2.0% TOC and would be considered non-source rocks by our criteria (Table 1). The Midyan basin samples are mostly immature to early mature as shown in Figure 7c and 7d, where about 95% of the samples have Tmax temperatures of < 440°C. The S 2 yield versus %TOC cross-plots shown in Figures 5 (Midyan basin) and 6 (Jaizan basin) show that all of the Miocene sedimentary packages contain organic-rich horizons that consist of heterogeneous kerogen. These heterogeneous kerogens result in the

20 l- i II l!il ,,ooooo "1"I"- !'ii•io"! i", i j ,,,,' -400 i

ee

•

,~oo,

....

0

, ....

5P

•

OO

, ....

o~TOC0

'

lS

' " " ' " "

0 4S28y.~C11620

o O0

~04'04'04~04"0v0

Hydrogen Index

Tmnx (°C)

°°~

Figure 4 Cross-plot between %TOC, S2 yield, hydrogen index and Tmax versus depth for the Miocene sedimentary sequence in a representative well in the Midyan basin. As shown by the analyses of core and cuttings samples, the most likely source rocks are the organic-rich, oil-prone, thin calcareous shales belonging to the Maqna Group

Marine and Petroleum Geology 1995 Volume 12 Number 6

601

Petroleum geochemistry of the Midyan and Jaizan basins: G. A. Cole et al. Table 2 Source rock summary table for the Jaizan and Midyan basins Ghawwas Formation

Mansiyah Formation

Maqna Group

Burqan Formation

Tayran Group

Pre-Rift

Midyan basin Total organic carbon (%) Average Maximum Minimum No. of measurements

1.07 2.84 0.22 19

3.62 26.27 0.26 46

1.71 13.97 0.03 220

1.29 4.73 0.12 228

0.84 4.61 0.10 54

0.40 1.17 0.10 19

S2 pyrolytic yield Average Maximum Minimum No. of measurements

1.90 5.97 0.04 19

17.40 143.78 0.14 46

5.80 85.21 0.00 220

2.66 21.13 0.01 228

2.25 30.96 0.00 54

0.18 0.50 0.00 19

322 696 40 39

282 640 10 172

195 536 39 222

Hydrogen index Average Maximum Minimum No. of measurements

205 481 37 12

192 744 10 33

55 158 0 19

Jaizan basin Total organic carbon (%) Average Maximum Minimum No. of measurements

1.99 2.43 1.55 2

1.28 6.96 0.20 43

0.95 7.48 0.02 65

0.62 2.68 0.10 53

0.48 8.08 0,03 146

nm nm nm nm

S2 pyrolytic yield Average Maximum Minimum No. of measurements

0.05 0.05 0.04 2

1.69 8.90 0.02 43

1.78 16.16 0.04 69

0.79 3.48 0.04 53

0.25 1,83 0.00 146

nm nm nm nm

Hydrogen index Average Maximum Minimum No. of measurements

3 3 2 2

55 221 0 132

nm nm nm nm

130 421 3 35

182 688 7 55

100 283 13 32

nm= Not measured

large amount of 'scatter' in each respective plot. However, within some of the sedimentary packages, potential source rocks may exist. If cut-offs of 2% TOC and 5 mg HC/g rock $2 yield are used, then some observations can be made. 1. The Ghawwas Formation (Figures 5A and 6A) remains a non-source rock unit. 2. The Mansiyah Formation (Figures 5B and 6A) contains some limited oil-prone potential in both basins (Midyan has the better source rock potential) as shown by those data points that fall along the 400 HI trend. These data are in line with published comments. As shown in Figure 2, the Mansiyah Formation is the equivalent of the South Gharib of Hughes and Beydoun (1992) and Mitchell et al. (1992). As discussed in Beydoun (1989), Barnard et al. (1992), Crossley et al. (1992) and Mitchell et al. (1992), these equivalents of the Mansiyah Formation throughout the Red Sea contain marine to saline lacustrine source rock beds, or at least show the likelihood that adequate conditions existed during this time period for source rock development. Barnard et al. (1992) quote oil-prone units having TOC values around 1%, but with some as high as 30% from the South Gharib Formation in Egypt. Other data from Barnard et al. (1992) suggest that thin beds are present in other parts of

602

the Red Sea which contain good organic richness and gas to mixed oil/gas potential but, overall, the net source rock thickness observed in the Mansiyah Formation is probably not enough to qualify as a significant source. A similar generalization was made by Mitchell et al. (1992), where they stated that the South Gharib contained thin, high-quality source beds, but the thickness was small. . The Maqna Group samples (Figure 5C) in the Midyan basin mostly follow the oil-prone trend (HI = 400). Based on well log descriptions, the net oil-prone source rock thickness may reach 20 m. These samples contain up to 14% TOC and 85.3 $2 yield. In the Jaizan basin, most Maqna samples (Figure 6B) are of poor source rock quality, but several organic-rich samples (>2.0% TOC) fall along the oil-prone trend (HI = 400), where the source rock richness and potential were excellent. Unfortunately, these samples represent a net source rock thickness (proved) of ~<2 m and the regional extent is uncertain. The Maqna Group is the equivalent of the Belayim (Globigerinal Zone) and Kareem Formations of Hughes and Beydoun (1992) and Mitchell et al. (1992). As discussed in Ahmed (1972), Barakat (1982), Beydoun (1989), Savoyat et al. (1989), Crossley et al. (1992), Barnard et al. (1992) and Mitchell et al. (1992), these equivalents of the Maqna Group throughout the Red Sea

Marine and Petroleum Geology 1995 Volume 12 Number 6

Petroleum geochemistry of the Midyan and Jaizan basins: G. A. Cole et al. (A) - Ghawwaa Formation

(B) - Maneiyah Formation 1O0 90-

A J¢

(C) - Maqna Group

excludes 6~e points above

15*/* TOC and 1CO$2 ~eld

35

14% TOC and 85.3 S2 yield

•

80-

'~

30

~

25

•

70-

-l-

60-

j t

-r 50 "

-o Q

HI = 4 ~

40"

•

30"

~.

20-

~

I~"

j

j-

~

.I. ~

•

~' 20 15-]

•

HI = 200 "~"

P"

•

". "~

• •

f

• HI =400

• *

/

t"-I

5

,0.

1

2

0

4

3

n, i , , , i , , , i , , , i , , , i , , , i , , , i , , , 1 2 3 4 5 6 7

Moderate Source Quality m

(D) - Burqan Formation

25 A

Poor to Marginal Source Quality ~

~

:t

-r

>-

as t

F

2s]

l.s-~. j,~ •

15.

V. Good to Excellent Source Quality

2.0 (F)- Pre-Rifl and/or Basement Sediments

20-"•

/ f "'=

J

1 2 3 4 5 Total Organic Carbon (wt. %)

Good Source Quality ~

(1:) - Tayran Group

2O

C

Total Organic Carbon (wt. %)

Total Organic Carbon (wt. %)

Inert Source Quality

i,,,i,,,I,,, i,,,I,,, i,.,i,,, 8 9 10 11 12 13 14 15

HI = 400

1.0~t

/--

,0_ >-

0

1

2

3

4

Total Organic Carborm (wt, %)

fi

. . . . . . . . . . . . . . . 1

2

~- ; . . . 3

4

Total Organic Carbon (wt. %)

0.0q 0.0

0.5

1.0

1.5

2,0

Tolal Organic Carbon (wt, %)

MIDYAN BASIN Figure 5 $2 yield versus %TOC cross-plots for each of the sedimentary sequences in the Midyan basin

contain source rocks deposited under marine to saline lacustrine(?) conditions, or at least the likelihood that adequate conditions existed during this time period for source rock development. Source rock data from Barakat (1982), Beydoun (1989), Savoyat et al. (1989), Barnard et al. (1992) and Mitchell et al. (1992) suggest that these units contain organic carbon that is variable in both quality and richness in various Red Sea basins. The TOC values are generally around 1%, but as high as 5% have been reported (Mitchell et al., 1992). Quality ranges from gas-prone to oil-prone and lateral variations in quality have also been noted (Beydoun, 1989). The source rock data given here for the Maqna Group in the Jaizan basin are in line with these reports. The Maqna source rocks are generally thin and rarely exceed a gross thickness of 2 - 3 m, but these thin beds contain good organic richness with mixed oil/gas- to oil-prone potential. 4. The Burqan Formation samples in both basins (Figures 5 D and 6C) are mostly of variable organic richness and pyrolytic yields. Taken as a whole, the Burqan samples contain a heterogeneous kerogen assemblage ranging from inert to oil-prone kerogens with most samples containing < 2 % TOC and < 5 mg HC/g rock $2 yield. Overall, the Burqan Formation appears to contain shales which have only moderate source richness and mixed oil- to gas-prone potential. Given the thickness of these shales (1>100 m), however, the Burqan Formation marine shales may

be the most likely source rock for the wet to dry gases reservoired in the lower to middle Miocene sands in the Jaizan wells and the limestones in the Midyan basin. This interpretation is also in line with published work on lateral equivalents• The Burqan Formation is the equivalent of the Rudeis Formation of Hughes and Beydoun (1992) and Mitchell et al. (1992). As discussed in Ahmed (1972), Barakat (1982), Barakat and Miller (1984), Beydoun (1989), Savoyat et al. (1989), Crossley et al. (1992), Barnard et al. (1992) and Mitchell et al. (1992), the Rudeis Formation is considered as one of the primary potential source rock sequences in the Red Sea and Gulf of Suez regions. Most source rock data suggest that organic richness and the potential productivity of the Burqan is less than that of the Maqna Group. The TOC values are generally no more than 1 - 2 % and consist of gas-prone kerogen assemblages. However, source rock thickness exceeds tens of metres and is present on a regional scale. . The Tayran Group samples (Figures 5 E and 6D) consist of poor to marginal quality source rocks in both basins, except for three samples in the Midyan basin that have very good organic richness with oil-prone potential. Again, this interpretation does not vary significantly from the published data on lateral equivalents (Crossley et al., 1992; Barnard et al., 1992; Mitchell et al., 1992). Pre-rift and/or basement samples from the Midyan basin (Figure 5F) also have poor source rock quality.

Marine and Petroleum G e o l o g y 1995 V o l u m e 12 N u m b e r 6

603

Petroleum geochemistry of the Midyan and Jaizan basins: G. A. Cole e t 10 ~ 9 B

(A) - Ghawwaa and Mansiyah Formations / ~ ~ //

18

~

16

l ~

l

~

// HI ?200

7

•

al.

(B) - Maqna Group

HI =~00 I"

14

//

o

£

12

//

10 .

=o

.:_. . . . . . . .

,2:1[~-~..'~

v "o

HJ=5o

¢N U)

!:~ii i'll ii~!~!}ii!!

1 o,..-.,.~., 0

1

:::~!:~! .... , ..., .... ,...., .... , .... 2

3

4

5

6

i0o

]

fJJ

4

HI= 50: ~)?:::

2 ...............

0

7

~

Hd.= //'/

6

0

1

2

3

4

ili;ii;i::iyili:

5

6

7

8

Total Organic Carbon (wt. %)

Total Organic Carbon (wt. %) Inert Source Quality

• ///

/ ,,

8 ,,.., "o

jff //

Poor to Marginal Source Quality

Good Source Quality

~

~

Moderate Source Quality

V. Good to Excellent Source Quality

(C) - Burqan Formation

(D) - Tayran Group

2.0

J¢ O £

1.5

ff

"II~ 1.0 E

._o

0.5 0.0

0.0

0.5

1.0

1.5

2.0

2.5

Total Organic Carbon (wt. %)

3,0

0.0

0.5

] JAIZAN BASIN ]

1.0

1.5

2.0

Total Organic Carbon (wt. %)

Figure 6 $2 yield versus %TOC cross-plots for each of the sedimentary sequences in the Jaizan basin

Because there are large variabilities in source rock quality and other geochemical parameters (carbon isotopic compositions and biomarkers; discussed later), this suggests to us that the oils are derived from localized pods of source rocks deposited in different depositional settings under fluctuating environmental conditions. Figure 8 illustrates a schematic block diagram for the Maqna Group depositional setting which can be applied to both the Midyan and Jaizan basins. The diagram shows that the Maqna includes many different depositional packages distributed over short lateral and vertical distances. The Maqna contains environments ranging from open marine to nearshore marine to nearshore restricted marine to saline lacustrine to lacustrine and even deltaic. Because source rocks can be deposited in all of these settings, it is possible that localized source rock pods were formed that have different geochemical signatures. Drilling in different locations in these basins, it could be proved that the same time-stratigraphic horizon may have been deposited, for example, under saline lacustrine conditions at one site which would have its own geochemical characteristics but, 20 km away, this same unit may have been deposited under marine

604

Marine

and Petroleum

Geology

1995 Volume

conditions with an entirely different set of geochemical characteristics. These different settings would probably generate and expel different families or subfamilies of oils. This block diagram is also applicable to the Tayran Group and Burqan Formations, but these sedimentary sequences are comprised of coarser clastic sediments and the block diagram should be modified accordingly. Potential source rocks from these two sequences are likely to be thin, more gas-prone and less organically rich than the source rocks from the Maqna Group.

Basin maturity patterns

Burial history/thermal models were constructed to map the hydrocarbon source rock kitchens in the Jaizan and Midyan basins. Both basins began as segments of the major Red Sea rift during Tertiary (Palaeogene) time with the last phase of rifting ending around the end of the Miocene (Crossley et al., 1992); Mitchell et al., 1992). The history of deposition of the sedimentary sequences within the two basins can be briefly summarized as follows:

12 N u m b e r

6

Petroleum geochemistry of the Midyan and Jaizan basins: G. A. Cole et al.

460 t •

0.8

•

o.8

0.7 450T-~lao---•--

• ".

1%;

o,xpo,s,onW,odow

440

0.6

• ~

0.6 '

04-~,

,°

05

#0

•

t~.-?

.

.

•

.

.

.

.

.

.

420t~ I

Immature to Early Mature

i

O.

•

0.3 I <

°

o

2oo

_

.. o ~

II"

•

tle~

o.2I~.&...~

•

-

4 3 0 ] ~ ' •''

"

~,l

~=_

II~_o ••

0.2 ~I•,,M.•

400

8oo

8oo

Hydrogen Index

. ~o ~

==

•

0.1 ~ ~ 2- - --~ . . . . . O0 ~ . 4 ! : : : , . . . . . . . . Im?at.ur? . . . . . . . :... 4101 • • • , . . . . . . . 0 2 4

, ........ ---, ........ ••• 6 8 10 12 14 16 18

2

0

4

"~"

450

2 440"

";;

D.

ii

>

8

I:i: E

•

I

,'77'--.:. 430'

e

I

•

. .- .. : I e l .- .

.

}.'." """ .: 2 . .-.

~:"..."

:

g£

..

," •

~-I ~ =";"

420' ::.::-. x

O

I

Ii~.

•

430"

E

i

14

16

18

i'm,,Ni

•

era

I

l

J

i

•

i

•

mien

•

. . . . l

l

I

•

I l l

II

•

•

• • • I

•

• I

•'

" • "." • -

•

.

-

II

•'.'.

"• ;-%--~ - ~

420"

el i•

.% . . ' ' - _ ' - . . ' :

"" "00o.''-"

Immature to Early Mature ~

I"

•

i I m l • i II

I

o

.....

...

12

• it Expulsion Window

.

• -. °.. • • Oe .'r-'. ,"

440"

I

10

450"

e> ,

Oil Expulsion Window .,i

8

$2 Yield (mg HC/g rock)

S2 Yield (mg HC/g rock)

•~

6

ej

.'•

Immature Mature

• to E a r l y

Jl

•o

•

m

)-E

E

410

'~n• .

0

: I 0

. . . .

, 20

. . . .

, 30

. . . .

, 40

P"

. . . . 50

$2 Yield (mg HO/g rock)

410 0

100

200

300

400

Hydrogen

500

600

Index

700

800 F

Figure 7 (a, b) Cross-plots b e t w e e n R o c k - E v a l Tm,x and $2 yield, p r o d u c t i o n i n d e x and S2 yield, and p r o d u c t i o n i n d e x and h y d r o g e n i n d e x (inset) for the Jaizan basin. (c, d) Cross-plots b e t w e e n R o c k - E v a l Tr~a× and $2 yield and h y d r o g e n i n d e x for t h e M i d y a n basin. Based on these cross-plots, m o s t s a m p l e s f r o m the Jaizan basin are i m m a t u r e or w i t h i n the oil generation and e x p u l s i o n w i n d o w , w h e r e a s the M i d y a n basin s a m p l e s are m o s t l y i m m a t u r e to early mature

1. Initial fill began with dominantly coarse clastic sediments belonging to the Tayran Group. 2. Following Tayran deposition, basin-fill continued with the marine shales/sands of the Burqan Formation. A regional unconformity separates the Tayran Group from the Burqan and sub-regional unconformities have affected the deposition and preservation of some sediments. 3. By the later part of Early Miocene to Middle Miocene time, the Maqna Group was deposited. This unit is characterized by interbedded carbonates, some clastic sediments and evaporites. It contains some of the best mixed oil/gas- to oil-prone source units analysed in the Saudi Arabian sector of the Red Sea. 4. Following Maqna sedimentation, the Mansiyah evaporites were deposited and these form the regional seal in both basins. The Marts•yah is characterized by thick salt and anhydrite beds, but there are some thin interbedded carbonate mudstones that contain good source potential. 5. The deposition of the sand-dominated Ghawwas Formation completed the Miocene sedimentation. No source rocks are present in proximal positions, but the likelihood for development of sources distally is ~ood. After the Miocene, sedimentation

continued with the deposition of the PlioPleistocene Lisan clastic sediments and Lisan carbonates. After the geological history was defined and a tectonic/thermal model constructed, the burial histories required calibration. A heat flow model based on the tectonic/structural history of the basins was constructed and used to determine the timing of hydrocarbon generation and expulsion for each pseudo-well and well burial history. This heat flow model was calibrated to the bottom-hole temperatures observed in the deep well control points in both basins and applied to the pseudowells constructed from regional seismic interpretations. The model assumed higher heat flows at the onset of rifting and then cooling to present-day levels to match the geothermal gradients observed in the wells. The calibration of the geological and thermal history model was conducted by comparing measured versus calculated results. The 'hard' data used for calibration purposes were measured bottom-hole temperatures and measured vitrinite reflectance and equivalents (TAI, bitumen %R, fluorescence). Unfortunately, most of the 'hard' data (the measured maturity values such as %VR) occurred where the sections were immature. Because

Marine and Petroleum Geology 1995 Volume 12 Number 6

605

Petroleum geochemistry of the Midyan and Jaizan basins: G. A. Cole et al.

•

Delta Plain

l~l

Freshwater Lake ~ ~

Coastal Marsh

~

Saline Lake

:~1

Marine Clastics

Deltaic Muds

~

Sands

~

Igneous Basement

Evaporites

Figure 8 Schematic block diagram illustrating the various possible source rock environments for the Maqna Group in the Jaizan and

Midyan basins

of the lack of good measured maturity profiles in most of the wells, calibration relied mostly on the bottomhole temperatures with some modification using the limited measured maturity values from vitrinite reflectance, TAI and chemical parameters. Bottom-hole temperatures resulted in a present day geothermal gradient range of 39.0 to 46.2°C/km for the Jaizan basin, whereas the wells in the Midyan basin had geothermal gradients ranging from 29.5 to 33.6°C/km. These temperatures represent present day heat flows of 78-90 mW/m 2 for the Jaizan basin and 60-70 mW/m 2 for Midyan baSin, if we assume a silty clastic sequence for most of the stratigraphic sequences in both basins. These geothermal gradients and heat flows generally agree with those published for the margins of the Red Sea (Girdler, 1970; Girdler and Evans, 1977; Tewfik and Ayyad, 1982; Robert, 1988; Markris and Rihm, 1991; Barnard et al., 1992; Bott et al., 1992; Mitchell et al., 1992). Figures 9 and 10 illustrate representative burial history/thermal models and the heat flow histories for the Jaizan and Midyan basins, respectively, with the locations of these models shown in Figure 1. The maturity windows used throughout this paper are listed in Table 3.

From the modelling results (sites are shown in Figure 1), regional maps were constructed which show the extent of the hydrocarbon kitchens. Figure 11 shows the regional maturity patterns drawn at the top of the Burqan Formation for the Jaizan basin, whereas Figure 12 shows the trends drawn at the top of the Tayran Group in the Midyan basin. In the Jaizan basin, westerly increasing maturation of the Maqna through Tayran section occurs due to increased burial in line with the structural configuration of the basin (Figures 1 and 11). The extra burial results in large gas-mature kitchens in the west (particularly offshore Jaizan basin), but smaller and narrower oil kitchens. Dominance of wet to dry gas is more likely in the Jaizan basin assuming a Maqna or Burqan source, with any oil pools being small. This appears proved by the accumulation of natural gas with minor associated oil (Oil and Gas Journal, 1994). In the Midyan basin, maturation again follows the structural configuration of the basin, but burial of the Maqna Group is significantly less than at Jaizan. Because burial of the Maqna Group resulted in only a small hydrocarbon kitchen, large amounts of expelled oils are unlikely. Therefore, only small accumulations

Table 3 Maturity ranges used to define the generation and expulsion windows used here

Maturity Immature Early mature Expulsion mature Oil preservation Gas mature

606

Vitrinite reflectance range (% VRe) ~<0.5 0.5-0.70 0.70-1.0 1.0-1.3 >1.3

Hydrocarbon generation and expulsion

No generation or expulsion Initial to significant generation; initial expulsion Main phase oil expulsion with completion by 1.0% VRe Light products/gas generation begins Gas generation and expulsion of drier gases

Marine and Petroleum Geology 1995 Volume 12 Number 6

Petroleum geochemistry of the Midyan and Jaizan basins: G. A. Cole et al. FM Lisan Carbonates Lisan Clastics

100

"

200 Ghawwas 300

K ¢'~

Mansiyah Maqna Burqan

400

Tayran 500

25,0

20.0

15.0

10.0

5.0

Time (Ma) 25,0 ~! ~, '~

130 120 110 100

~:

90

20,0

15.0

10.0

5.0

80

Figure 9 Burial history/thermal model for a representative pseudo-well located in the Jaizan basin. The primary oil source, the Maqna Group, has attained wet gas maturity at this site. The Burqan Formation is wet to dry gas mature. The location of this modelling site is shown in Figure 1

of oil are predicted for this basin unless the more mature Burqan and Tayran Group source rocks improve or thicken distally from the rift margin. However, the larger hydrocarbon kitchens of the gasprone Burqan Formation should result in moderately large volumes of expelled condensates and gases. This appears to be proved by the accumulations in the Midyan and Burqan structures. The burial history/thermal models also indicate that oil expulsion occurred from the last Miocene to the present, and gas expulsion within Plio-Pleistocene times in both basins. In almost all instances, the timing of generation and expulsion occurred contemporaneously or after trap development.

Oil-source and oil-oil correlations As discussed in the source rock section of this paper, the most likely source rock units from which the Miocene oils of the Jaizan and Midyan basins were derived belong to the marine shales and marls of the Early to Middle Miocene Maqna Group. The Maqna source rock unit is assumed to be regionally extensive, contains good to very good organic richness and mixed oil/gas- to oil-prone kerogen, but does not attain a thickness great enough or mature enough (in the Midyan basin) to expel large accumulations of oils. A second possibility in sourcing the hydrocarbons is from the Burqan Formation.

Oil-oil and oil-source correlations were conducted by characterizing selected source rock extracts and oils using gas chromatography-mass spectrometry ( G C - M S ) and carbon isotopes (~13C). The primary intent of this correlation exercise is to show the gross oil family and source rock extract characteristics, not to define the sub-families that occur from source rock facies changes and maturity. These variations are recognized as being present and can be observed in some of the figures presented here, but because of the paucity of data, a detailed study of these anomalies is beyond the scope of this paper.

Biomarkers ( G C - M S ) Gas chromatography-mass spectrometry m/z 191 (tricyclics and hopanes) and m/z 217 (steranes) were used to conduct detailed characterization of the oils and extracts. Representative m/z 191 fragmentograms are shown in Figure 13 for representative extracts and oils from the Jaizan basin and in Figure 14 for the Midyan basin. For the purpose of this paper, only the m/z 191 fragmentograms will be discussed because this mass contains the most diagnostic biomarkers for correlation purposes. A sterane ternary diagram shown as Figure 15 (using C27-29 e~0ce~20Rpeaks) will be used to define sterane relationships.

Jaizan Basin. As can be observed from the m/z 191 fragmentograms (Figure 13), the JZNR-1, -2 and -3 oils are relatively similar to each other, but are different

Marine and Petroleum Geology 1995 Volume 12 Number 6

607

Petroleum geochemistry of the Midyan and Jaizan basins: G. A. Cole et al. FM Lisan Carbonates

Lisan Clastics

Ghawwas

E e,

Mansiyah Maqna Burqan Tayran

16

20

12

8

Age (Ma)

2O

16

12

8

I

I

I

110 1 ..~ ~

~

~

908070 60

Figure 10 Burial history/thermal model for a representative pseudo-well located in the Midyan basin. The primary oil source, the Maqna Group, has attained wet gas maturity at this site. The Burqan Formation is wet to dry gas mature. The location of this modelling site is shown in Figure I

~ Mansiyah Well and 3 pseudowellsto north

~ - I Immature

[

Oil Window

(<0.5%VRe) (0.5-1.0%VRe) ] O i l Preservation/ ~:~ Wet Gas Window [ DryGas to Onset Gas Generation ~ (1.3-1.8%VRe) Thermally Spent (1,0-1.3%VRe) (>1.8%VRe) Figure 11 Map of Jaizan basin showing the maturity trends drawn on the top of the Burqan Formation

608

Figure 12 Map of Midyan basin showing the maturity trends drawn on the top of the Tayran Group

M a r i n e and P e t r o l e u m G e o l o g y 1995 V o l u m e 12 N u m b e r 6

Petroleum geochemistry of the Midyan and Jaizan basins: G. A. Cole et al, JZSE-S1 Oil m/z 191

JZNR-1 Maqna Group Source Rock Extract m/z 191 Z T$

C31 22R + Gamrnacerane

-E

J

~

Extended Hopanes

~

ITrn I Oil

~1~ I~ L~

OI ~ Oleanane = 17c¢(H)-diahopane JZNR-3 Oil m/z 191

g I 2~ 3= ~, z ~ ~ ExtendedHopanes oarnrnncerane

/

JZNR-1 = Manaiyah Formation / Extract of Bitumen Stringer in Shale }:~ m/z 191 ¢=

JZNR-1 Sand Extract m/z 191

~ =~" ~

~ ~ c= ~z o ExtendedHopanes ~~, ~" I ¢0 1C31

~

=

.~

\

,_o

C32

~ ~'

~

c~

JZSE-S1

== ~

Maqna Group Source Rock Extract mlz 191

oK ~Mor~ane ~o / "

c30 Hopane

JZNR-1 Oil

o

z

mlz 191

~

~

Extended Hopanes

k

1 .... _ I l l _ l ~

JZNR-2 Oil Show m/z 191

JZNR-1 Maneiyah Fm. Source Rock Extract m/z 191

o ;5

F-'-'-

c30 Hopane

z

E I

Extended Hopanes C31 I C32

I

I -~;~

Mo,elane

iJL

~ %-

Figure 13 m/z 191 (hopanes + tricyclics) f r a g m e n t o g r a m s for selected oils and source rock extracts from the Jaizan basin

from the JZSE-S1 oil. The characteristic hopane and tricyclic biomarkers show: 1. These oils are derived from a post-oil expulsion mature source rock as shown by only trace to low amounts of moretane and normoretane, full

equilibration of the C31_33 homohopanes, and high Ts/Tm ratios. These observations suggest that these oils were expelled from a source rock with a maturity around 0 . 8 - 0 . 9 % VRe. However, the extended homohopanes are truncated by C34 , which indicates that the depositional conditions were

Marine and Petroleum Geology 1995 Volume 12 Number 6

609

Petroleum geochemistry of the Midyan and Jaizan basins: G. A. Cole et probably dysoxic (Peters and Moldowan, 1993). 2. The three JZNR samples contain similar tricyclic distributions, including the presence of extended tricyclics. The C24 tetracyclic compound is less than the C25 or C26 tricyclic. C23 and C24 tricyclics have about the same ratio in each oil, and Ca8 and C29 tricyclics are present in all four oils with approximately the same abundances. Tdcyclics

Midyan-2 Well

Reservoired Condensate rn/z 191 Hopanes + Tricyclics

.

al.

All samples have C29 norhopane < C3o hopane and contain abundant C29Ts. In fact, the JZNR-3 oil and the sand extract have C29Ts>C29norhopane. C29Ts [19o~(H)-30-norneohopane] and the peak labelled '~' [170¢(H)-diahopane] are indicative of source rocks deposited in clay-rich environments under oxic to dysoxic conditions (Peters and Moldowan, 1993). Gammacerane is present in three of the JZNR oils,

Midyan-I Well Maqna Gp. Source Rock Extract m/z 191 Hopanes + Tricyclice

~ IC30 Hopane

® ~,C30 Hopane

=5

¢

:-

.

o /

o

.~

I

~-

o

~®1 • zo~| l

Tricyclics

Ic3122R+

Z I

I Gammacerane

o

//~

e~,l

~ / 031229.

~ TI

Tm

oJ

G~ocmr~

I I I

Tm Ts

Midyan-2 Well Volcaniclastic Basement Test m/z 191 Hopanes + Tricyclics

~ ~ o

I C31 22R + i Gammacerane

,

Midyan-1 Well Maqna Gp. Source Rock Extract nYz 191 Hopanes + Tncyclics

I ~'~

~

i!1,

o

T

o ......

L___

Midyan-3 Well Maqna Limestone Reservoir Oil m/z 191 Hopanes + Tricyclics

~J C31 22R + _~ r~-iGammacerane

~"

c

~° Tricyclicso ~'~

Burqan-1 Well Burqan Fm. Extract rtYz 191 Hopanes + Tricy¢lics

C30 Hopane

o~

I ,

~ IC30 Hopane ~ I ~ ~_l

o

C29 Norhopane

0

= ~z "~ j Gamrn=cetane

;.5 ~"

$;

"= ¢=

Midyan-1 Well Mansiyah Fro. Source Rock Extract nYz 191 Hopanes + Tricyclice

t~ C31 22R + Gammacerane

Burqan-1 Well Burqan Fm. Source Rock Extract m/z 191 Hopanes + Tricyclics

Garnmaoerane -l-

o Tricyclics Tricyclics o

~. ~ oq

o~

.2

z

~

Z q o

~-.~

.o

,~= l

1....

o

jj..~_J. ,~. . . . . .

Figure 14 m/z 191 (hopanes + tricyclics) fragmentograms for selected oils and source rock extracts from the Midyan basin

610

M a r i n e and P e t r o l e u m G e o l o g y 1995 V o l u m e 12 N u m b e r 6

Petroleum geochemistry of the Midyan and Jaizan basins: G. A. Cole et al. but is absent from the JZNR-2 oil. Gammacerane is believed to be a hypersalinity indicator (Peters and Moldowan, 1993) and is now believed to be representative of restricted evaporite and saline lacustrine environments (Moldowan et al., 1985; 1992; Mello et al.,1988; Waples and Machihara, 1991). Oleanane, which is believed to be derived from angiosperms (a terrestrial marker; ten Haven and Rullkotter, 1988), is present in low to abundant amounts and probably indicates a nearshore marine to terrestrial setting for the source rock. 4. The JZSE-S1 oil gave a poor m/z 191 fragmentogram, but some similarities exist between this oil and the JZNR oils. The JZSE-S1 oil has C29 norhopane
C28 a(xcc 20R Steranes ~, /" ~, cv 0,8 ~ ' ~ "

/ \ / \

n~ /

C27 ac~c~ z 20R Steranes

~//

V

V

0,8

0.6

~"

\( 0.4

_ I • MansiyahFm.Extracts I-~ aaqnaGp. Extracts I • BurqanGp. Extracts MidyanBasinOils I • JaizanBasinOils

I"

~( 0.2

xc29~ 20R Steranes

Figure 15 Ternary diagram s h o w i n g the distribution of the C27 through C2a oaxcx20R steranes from the oils and extracts in the Midyan and Jaizan basins

Midyan Basin. As can be observed from the m/z 191 fragmentograms (Figure 14), the Midyan oils and condensates are rather different. The characteristic hopane and tricyclic biomarkers show: 1. The condensates contain C29 norhopane
Carbon isotopes (~13C). Carbon isotopes (•13C) were determined for the oils, source rock bitumens and isolated kerogens from the Mansiyah and Maqna Formations. Results are shown in Figure 16, which plots the 613C type curves for the selected oils and source rocks (Galimov, 1973; Stahl, 1978). The oil type curves shown in Figure 16 for the Jaizan

Marine and Petroleum Geology 1995 Volume 12 Number 6 611

Petroleum geochemistry of the Midyan and Jaizan basins: G. A. Cole et

al.

Saturates Reservoired Oils and Shows • ---v----- -- x • 4, ---*--D _~

Whole Oil -

Aromatics --

MDYN-1 MDYN-2 MDYN-3 m JZNR-1 JZNR-2 JZSE-1 JZSE-1 JZN R-3

Resins Jaizan

Kerogen -

Midyan

Jaizan Midyan

Bitumen -

Ja}zan

Jaizan v

I

I

I

I

I

I

I

I

I

I

O) OO I~ r,D t.O ~- £O Od

a

• •

MansiyahFormation

* •

MaqnaGroup

Midyan

I

I a

Carbon Isotopic Composition (81 3C)

Figure 16 Carbon isotopic (~13C) t y p e curves f o r the M a q n a reservoired oils and selected source rock extract f r o m the M i d y a n and Jaizan basins. Kerogen and b i t u m e n extract ranges f o r the Mansi yah and M a q n a source rocks f r o m the Jaizan and M i d y a n basins are also shown. The m o s t likely candidate source rocks f o r the oils are the o i l - p r o n e source units within the M a q n a G r o u p

and Midyan basin oils show highly variable isotopic compositions, as do the primary source rock intervals of the Mansiyah Formation and Maqna Group. However, some acceptable correlations can be made if the carbon isotopic and biomarkers data are used together. The two oil type curves from the Jaizan north area (JZNR-1 and JZNR-3) follow the same trend with very little variation. When these oils are compared with the isotopic composition of the shale unit immediately below and juxtaposed to the reservoir sands for these oils, an acceptable match is observed between the carbon isotopes of ~<0.5%o, and the biomarkers m/z 191 patterns are nearly identical. Therefore, the thin, organic-rich Maqna Group source intervals are the best candidate source rock for these waxy crude oils. The JZNR-2 oil show matched the northerly Jaizan area oils in GC and G C - M S characteristics, but was isotopically heavier. This is perhaps attributed to a shift in isotopic composition due to depositional variations in the source rock as discussed in the following. Comparison of the two southerly Jaizan oils (JZSE-1 oils) shows poor correlation with both JZNR area oils and with the Maqna and Mansiyah source rocks. Basically, these two oils lie between the two source rock ranges, but match more closely the lower part of the Maqna range, especially when including the biomarker data. The Midyan basin oils and condensates do not favourably correlate isotopically with either the Mansiyah Formation or Maqna Group source rock intervals. As shown in Figure 16, the oils and condensates generally fall in-between the carbon isotope ranges for the two source rock units, However,

612

Marine and Petroleum Geology 1995 Volume

based on maturity considerations, a weak match between the m/z 191 and m/z 217 biomarker data, and the variable quality of the source rocks (i.e. deposited under variable and fluctuating conditions), suggest that t h e better correlation is with the Maqna Group. As discussed earlier, the Maqna Group was deposited under variable depositional environments which have their own respective geochemical signatures (Figure 8). These different source rock characteristics from different environments within the Maqna Group can account for the variations observed in the gas chromatograms, the G C - M S fragmentograms and in the i513C ranges. It can also explain why some source rocks and oils have similar biomarkers and GC characteristics, but may have different 513C values. The ~13C values can differ due to environmental conditions, where more nearshore or restricted settings of the same stratigraphic unit have different ~13C values from open marine settings as measured on carbonates (Kolodny, 1980; Heydari and Wade, 1993). Similar associations are observed in the organic matter assemblages (Sofer, 1984). Because it is possible that the Maqna contains nearshore marine kerogen assemblages deposited under both restricted and fluctuating conditions, it is possible that the same organic-rich, stratigraphic unit could generate oils that have oleanane, have variable amounts of gammacerane, were deposited under dysoxic to anoxic conditions resulting in different homohopane signatures and have radically different isotopic values. This could account for the differences between the source rock and the oil families in Jaizan and Midyan basins, all of which are found in the Maqna or Lower Mansiyah sequences in both basins.

12 N u m b e r

6

P e t r o l e u m g e o c h e m i s t r y o f the M i d y a n a n d Jaizan b a s i n s : G. A. Cole et al.

Conclusions

Acknowledgements

The presence of major, thick, oil-prone source rock units on a regional scale in the Midyan and Jaizan basins has yet to be established. Based on the analysis of 895 selected core and cuttings samples from the Midyan basin, two sedimentary packages may contain source rock potential. The Maqna Group may contain up to 20-30 m of net source rock thickness which has mixed oil/gas- to oil-prone quality. These units have good to excellent organic richness and enough pyrolytic yields to expel black oils if sufficient maturity is attained within the basin. Based on maturity modelling, the Maqna Group, however, is only buried deep enough to form a relatively small expulsion kitchen, Thicker, but less organic-rich, source rock units are found within the Burqan Formation. These shales contain moderate to good organic richness, are mixed oil/gas- to gas-prone and may exceed 100 m in thickness. Additionally, these shales attain post-oil-expulsion maturity and could have expelled large volumes of light oils and gases. Other very thin, but organically rich and oil-prone source rock intervals, have been identified within the Mansiyah Formation, but these are immature throughout most of the Midyan basin. Based on the analysis of 313 selected core and cuttings samples from the Jaizan basin, no thick, organic-rich, oil-prone or mixed oil/gas-prone source rocks have been identified in any of the sedimentary sequences in the basin. However, thin, organic-rich, mixed oil-gas to oil-prone source rocks have been identified within the Maqna marine to restricted sedimentary sequence and thin organic-rich, mixed oil/gas to oil-prone units have been identified near the base and near the top of the Mansiyah evaporite sequence. These source rock sequences are neither thick enough, nor have they been proved to be regionally extensive enough, to generate and expel large volumes of oil. Probable sizes of fields derived from these source rocks will be small, tens of millions of barrels equivalent, unless the sources thicken dramatically distally. The offshore areas remain undrilled, so any thickening of source rocks is unknown. Timing and maturation of the oil-prone or mixed oil/gas-prone source rock units within the Maqna are controlled by the Late Miocene and Plio-Pleistocene burial across both basins (0-10 Ma depending on burial). The Jaizan North area oils are conclusively correlated with the thin Maqna organic-rich, mixed oil/gas to oil-prone source unit that is immediately below the Maqna sand reservoir in the Jaizan North-1 and -3 wells. The biomarkers, GC and carbon isotopes in the oils indicate an excellent match with the potential source rocks. Variations between the Jaizan North oils and the JZSE-1 oil and the JZNR-2 oil show were attributed to source rock depositional variations that caused a shift in the carbon isotope signatures. No good correlation could be made between the Midyan basin oils and potential source rocks. However, the best correlation for the oils was to the Maqna Group.

A significant part of this paper can be attributed to those seldom recognized analytical technicians of the Geochemistry Unit at Saudi Aramco. Without their analytical support, papers such as these cannot be written. We also thank J. M. AI-Dubaisi and F. M. Bo-Khamsin of the Geochemistry Unit, as well as the exploration staff at Saudi Aramco. We thank the anonymous reviewers of the manuscript. Lastly, we appreciate and thank the Saudi Arabian Ministry of Petroleum and Mineral Resources, and the Saudi Arabian Oil Company (Saudi Aramco) for permission to publish this paper.

References Ahmed, S. S. (1972) Geology and petroleum prospects in eastern Red Sea Am. Assoc. Petrol GeoL Bull. 56, 707-719 Barakat, H. (1982) Geochemical criteria for source rock, Gulf of Suez Proceedings, Sixth EGPC Exploration Seminar, 224-251 Barakat, H. and Miller, P. (1984) Geology and petroleum exploration, Safaga Concession, northern Red Sea, Egypt Proceedings, Sevenlh EGPC Exploration Seminar, 191 - 198 Barnard, P. C., Thompson, S., Bastow, M. A., Ducreux, C. and Mathurin, G. (1992) Thermal maturity development and source-rock occurrence in the Red Sea and Gulf of Aden J. Petrol GeoL 15, 173-186 Beydoun, Z. R. (1989)The hydrocarbon prospects of the Red Sea - - G u l f of Aden: a review J. Petrol GeoL 12, 125-144 Bott, W. F., Smith, B. A., Oakes, G., Sikander, A. H. and Ibraham, A. I. (1992) The tectonic framework and regional hydrocarbon prospectivity of the Gulf of Aden J. Petrol GeoL 15, 210-243 Brooks, J., Cornford, C. and Archer, R. (1987) The role of hydrocarbon source rocks in petroleum exploration. In: Marine Petroleum Source Rocks (Eds J. Brooks and A. J. Fleet), GeoL Soc. Spec, PubL London No. 26, 17-46 Burtner, R. L. and Warner, M. A. (1984) Hydrocarbon generation in Lower Cretaceous Mowry and Skull Creek shales of the northern Rocky Mountain area. In: Hydrocarbon Source Rocks of the Greater Rocky Mountain Region (Eds J. Woodward, F. F. Meissner and J. L. Clayton), Rocky Mountain Assoc. GeoL, 449-467 Burnham, A. K. and Sweeney, J. J. (1989) A chemical kinetic model of vitrinite maturation and reflectance Geochim. Cosmochim. Acta 53, 2649-2657 Burnham, A. K. and Sweeney, J. J. (1991) Modeling the maturation and migration of petroleum. In: Source and Migration Processes and Evaluation Techniques (Ed. R. K. Merril), Am. Assoc. Petrol GeoL Treatise Petrol GeoL, 55-64 Crossley, R., Watkins, C., Raven, M., Cripps, D., Carnell, A. and Williams, D. (1992) Sedimentary evolution of the Red Sea and Gulf of Aden J. Petrol GeoL 16, 157-172 Dykstra, J. (1987) Compaction correction for burial history curves: application to Lopatin's method for source rock maturation determination Geobyte 2, 16-23 Galimov, E. M. (1973) Carbon Isotopes in Oil and Gas Geology, NASA, Washington, 384pp [translation from 'lzotopy ugleroda v neftgazovoy geologic', Nedra, Moscow] Girdler, R. W. (1970) A review of Red Sea heat flow Phil. Trans. Roy. Soc. London, 267, 191-203 Girdler, R. W. and Evans, T. R. (1977) Red Sea heat flow Roy. Astron. Soc. Geophys. J. 51,245-252 ten Haven, H. L. and Rutlkotter, J. (1988) The diagenetic fate of taraxer-14-ene and oleanane isomers Geochim. Cosmochim. Acta 62, 2543-2548 Heydari, E. and Wade, W. J. (1993) Sedimentology and geochemistry of the Lower Mudstone Member of the Smackover Formation, US Gulf Coast: implications for Late Jurassic seawater composition, paleo-oceanography, and anoxic events Abstracts, Carboniferous to Jurassic Pangea, Canadian Society of Petroleum Geologists Annual Meeting, 138

Marine and Petroleum Geology 1995 Volume

12 N u m b e r

6

613

Petroleum geochemistry of the Midyan and Jaizan basins: G. A. Cole et al. Hughes, G. W. and Beydoun, Z. R. (1992) The Red Sea-Gulf of Aden: biostratigraphy, lithostratigraphy, and paleoenvironments J. Petrol GeoL 15. 135-156 Hunt, J. M. (1979) Petroleum Geochemistry and Geology, Freeman, San Francisco, 617 pp Issler, D. R. (1984) Calculation of organic maturation levels for offshore eastern Canada - - implications for general application of Lopatin's method Can. J. Earth Sci. 21, 477-488 Kolodny, Y. (1980) Carbon isotopes and depositional environment of a high productivity sedimentary sequence - - the case of the Mishash-Ghareb Formations, Israel Israel J. Earth Sci. 29, 147-156 Langford, F. F. and Blanc-Valleron, M. M. (1990) Interpreting Rock-Eval pyrolysis data using graphs of pyrolyzable hydrocarbons vs. total organic carbon Am. Assoc. Petrol GeoL Bull. 74, 799-804 Makris, J. and Rihm, R. (1991) Shear-controlled evolution of the Red Sea: pull apart model Tectonophysics 198, 441-466 Mello, M. R., Gaglianone, P. C., Brassell, S. C. and Maxwell, J. R. (1988) Geochemical and biological marker assessment of depositional environments using Brazilian offshore oils Mar. Petrol GeoL 5, 205-223 Middleton, M. F. (1982) Tectonic history from vitrinite reflectance Geophys. J. Roy. Astron. Soc. 62, 121-132 Mitchell, D. J., Allen, R. B., Salama, W. and Abouzakm, A. (1992) Tectonostratigraphic framework and hydrocarbon potential of the Red Sea J. Petrol. GeoL 15, 187-210 Moldowan, J. M., Seifert, W. K. and Gallegos, E. J. (1985) Relationship between petroleum composition and depositional environment of petroleum source rocks Am. Assoc. Petrol GeoL Bull. 69, 1255-1268 Moldowan, J. M., Sundararaman, P., Salvatori, T., Alajbeg, A., Gjukic, B., Lee, C. Y. and Demaison, G. J. (1992) Source correlation and maturity assessment of select oils and rocks from the central Adriatic basin (Italy and Yugoslavia). In: Biological Markers in Sediments and Petroleum (Eds J. M. Moldowan, P. Albrecht and R. P. Philp), Prentice Hall, Englewood Cliffs, 370-401 Morrow, D. W. and Issler, D. R. (1993) Calculation of vitrinite reflectance from thermal histories: a comparison of some methods Am. Assoc. Petrol GeoL Bull. 77, 610-624 Oil and Gas Journal (1994) Saudi production capacity climbing to 10 million b/d Oil GasJ. 92, 44-47 Peters, K. E. (1986) Guidelines for evaluating petroleum source rocks using programmed pyrolysis Am. Assoc. Petrol., GeoL Bull. 70, 318-329

614

Marine and Petroleum

Geology

1995 V o l u m e

Peters, K. E. and Moldowan, J. M. (1993) The Biomarker Guide - - Interpreting Molecular Fossils in Petroleum and Ancient Sediments, Prentice Hall, Englewood Cliffs, 585 pp Peters, K. E., Moldowan, J. M. and Sundararaman, P. (1990) Effects of hydrous pyrolysis in biomarker thermal maturity parameters: Monterey Phosphatic and Siliceous Members Org. Geochem. 15, 249-265 Robert, P. (1988) Organic Metamorphism and Geothermal History: Microscopic Study of Organic Matter and Thermal Evolution of Sedimentary Basins, EIf-Acquitaine and D. Reidel, Boston, 311 pp Roydon, L. C., Sclater, J. G. and von Herzen, R. P. (1980) Continental margin subsidence and heat flow: important parameters in formation of petroleum hydrocarbons Am. Assoc. Petrol GeoL Bull. 64, 173-187 Savoyat, E., Shiferaw, A. and Balcha, T. (1989) Petroleum exploration in the Ethiopian Red Sea J. Petrol. GeoL 12, 187- 204 Sofer, Z. (1984) Stable carbon isotope compositions of crude oils: application to source depositional environments and petroleum alteration Am. Assoc. Petrol GeoL Bull. 68, 31-49 Stahl, W. J. (1978) Source rock-crude oil correlation by isotopic type curves Geochim. Cosmochim. Acta 42, 1573-1578 Sweeney, J. J. (1990) BASlNMAT, a FORTRAN program to calculate oil and gas generation using a distribution of discrete activation energies Geobyte 5 (2), 37-43 Sweeney, J. J. and Burnham, A. K. (1990) Evaluation of a simple model of vitrinite reflectance based on chemical kinetics Am. Assoc. Petrol Geol. Bull. 74, 1559-1570 Tewfik, N. and Ayyad, M. (1982) Petroleum exploration in the Red Sea shelf of Egypt Proceedings, Sixth EGPC Exploration Seminar, 159-180 Tissot, B. P. and Welte, D. H. (1984) Petroleum Formation and Occurrence, Springer-Verlag, Berlin, 538 pp Waples, D. (1980) Time and temperature in petroleum formation: application of Lopatin's method to petroleum exploration Am. Assoc. Petrol. Geol. Bull. 64, 916-926 Waples, D. W. and Machihara, T. (1991) Biomarkers for Geologists - - A Practical Guide to the Application of Steranes and Triterpanes in Petroleum Geology, Am. Assoc. Petrol Geol. Methods ExpL No. 9, 91 pp Waples, D. W., Kamata, H. and Suiza, M. (1992) The art of maturity modeling. Part 1: finding a satisfactory geologic model Am. Assoc. Petrol Geol. Bull. 76, 31-46 Wood, D. A. (1988) Relationship between thermal maturity indices calculated using Arrhenius equation and Lopatin method: implications for petroleum exploration Am. Assoc. Petrol Geol. Bull. 72, 115-134

12 N u m b e r

6