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ORIGINAL PAPER

Modeling of gas generation from the Alam El-Bueib formationin the Shoushan Basin, northern Western Desert of Egypt

Mohamed Ragab Shalaby • Mohammed Hail Hakimi •

Wan Hasiah Abdullah

Received: 24 October 2011 / Accepted: 20 May 2012

� Springer-Verlag 2012

Abstract The Shoushan Basin is an important hydro-

carbon province in the northern Western Desert, Egypt, but

the burial/thermal histories for most of the source rocks in

the basin have not been assigned yet. In this study, sub-

surface samples from selected wells were collected to

characterize the source rocks of Alam El-Bueib Formation

and to study thermal history in the Shoushan Basin. The

Lower Cretaceous Alam El-Bueib Formation is widespread

in the Shoushan Basin, which is composed mainly of shales

and sandstones with minor carbonate rocks deposited in a

marine environment. The gas generative potential of the

Lower Cretaceous Alam El-Bueib Formation in the Shou-

shan Basin was evaluated by Rock–Eval pyrolysis. Most

samples contain sufficient type III organic matter to be

considered gas prone. Vitrinite reflectance was measured at

eight stratigraphic levels (Jurassic–Cretaceous). Vitrinite

reflectance profiles show a general increase of vitrinite

reflectance with depth. Vitrinite reflectance values of Alam

El-Bueib Formation range between 0.70 and 0.87 VRr %,

indicating a thermal maturity level sufficient for hydro-

carbon generation. Thermal maturity and burial histories

models predict that the Alam El-Bueib source rock entered

the mid-mature stage for hydrocarbon generation in the

Tertiary. These models indicate that the onset of gas gen-

eration from the Alam El-Bueib source rock began in the

Paleocene (60 Ma), and the maximum volume of gas

generation occurred during the Pliocene (3–2 Ma).

Keywords Source rock � Alam El-Bueib formation � Gas

generation � Shoushan Basin

Introduction

The study area for this paper lies in the Shoushan Basin

in the northern Western Desert of Egypt focusing on

the Salam filed, which is the most productive gas field in

the Shoushan Basin (Fig. 1). The Shoushan Basin in the

northern Western Desert of Egypt (Fig. 1) still has signif-

icant hydrocarbon potential as recent oil, and gas discov-

eries have suggested (Dolson et al. 2001; Zein El-Din et al.

2001). However, published data related to the geochemical

characteristics of likely source rocks, their thermal and

burial histories, and the timing of hydrocarbon generation

are limited (e.g., Shalaby et al. 2011). The Shoushan Basin

contains sediments of Jurassic and younger age. The

hydrocarbons (oil and gas) accumulated in the Jurassic to

Cretaceous formations, where source rocks are found in the

Jurassic and Cretaceous successions (Fig. 2) (El Ayouty

1990; El-Nadi et al. 2003; Sharaf 2003; Alsharhan and Abd

El-Gawad 2008). Sandstones of the Middle Jurassic Kha-

tatba Formation contain some of the largest gas resources

in the northern Western Desert region. The gas is thought

to be sourced mostly from the Jurassic and Lower Creta-

ceous formations (Fig. 2). This work provides a compre-

hensive study on the source rock characteristics of the

Lower Cretaceous Alam El-Bueib Formation, including

organic richness (quantity), potential type of hydrocarbons,

M. R. Shalaby

Petroleum Geoscience Department, Faculty of Science,

University Brunei Darussalam, Bandar Seri Begawan, Brunei

M. H. Hakimi (&) � W. H. Abdullah

Department of Geology, University of Malaya,

50603 Kuala Lumpur, Malaysia

e-mail: [email protected]

M. H. Hakimi

Geology Department, Faculty of Applied Science,

Taiz University, 6803 Taiz, Yemen

123

Int J Earth Sci (Geol Rundsch)

DOI 10.1007/s00531-012-0793-0

and thermal maturity and then to construct basin models in

order to determine the timing of hydrocarbon generation.

Burial histories, thermal maturity, and timing of hydro-

carbon generation were modeled for the Alam El-Bueib

source rock for two exploration wells (Fig. 1) and used

one-dimensional numerical modeling software, calibrated

using available maturity data.

Stratigraphic setting

The stratigraphic and structural evaluation of the northern

Western Desert of Egypt subject to considerable research

(e.g., El Shazly 1977; Mesherf et al. 1980; Barakat et al.

1987; El Ayouty 1990; Hantar 1990 Carlos et al. 2001;

Zein El-Din et al. 2001; Abdou et al. 2009; Kerdany and

Cherif 1990). Therefore, only a very brief summary will be

given here. The northern Western Desert consists of a

number of sedimentary basins that received a thick suc-

cession of Mesozoic sediments (Zein El-Din et al. 2001).

The Shoushan basin, which is the largest of the coastal

basins, is a half-graben system with a maximum thickness

of 7.5 km of Jurassic, Cretaceous and Paleogene sediments

(El Shazly 1977; Hantar 1990). The stratigraphic section in

the northern Western Desert (including Shoushan Basin)

ranges in age from Paleozoic to Tertiary and is summarized

in Fig. 2. The stratigraphy can be divided into four

unconformity-bound cycles as proposed by Sultan and

Abdulhalim (1988) ‘‘personal communication’’. The earli-

est cycle consists of non-marine siliciclastics (Ras Qattara

Formation, Early Jurassic), which rest unconformably on

the Paleozoic Nubian sandstone, and is overlain by the

Middle Jurassic Khatatba Formation (Fig. 2). The Khatatba

Formation is composed mainly of shales and sandstones

with coal seams. These sediments were deposited in a

deltaic to shallow-marine environments. In the Shoushan

Fig. 1 Location map of Mesozoic basins in the northern Western Desert of Egypt, showing Shoushan Basin including studied wells in the Shams

Field


123

Basin, the Khatatba occurs in the subsurface and has been

informally subdivided into lower and upper parts. The

lower part of the Khatatba Formation is formed by mean-

derbelt facies, which are composed of an interval of brai-

ded-stream sandstones (Carlos et al. 2001) interbedded

with coals and carboniferous shales. These sandstones are

oil and gas reservoirs in some fields in the Shoushan Basin

(Fig. 1), whereas the coaly shale and shale facies represent

the main hydrocarbon source rocks of the basin (Taher

et al. 1988; Keeley et al. 1990; Bagge and Keeley 1994).

The upper part of the Khatatba Formation is formed by

shallow-marine sandstones and shales, grading upwards

into a thin-bedded sequence of shale and limestone, which

is a transitional unit toward the carbonates of the Masajid

Formation. The shallow-marine carbonates of the Masajid

Formation represent the maximum Jurassic transgression.

This formation is capped by the Cimmerian unconformity,

which records a period of uplift, tilting, partial erosion, and

karstification of the Jurassic succession (Keeley et al. 1990;

Keeley and Wallis 1991). A major unconformity separates

the Masajid Formation from the overlying Alam El-Bueib

Formation at the base of the next cycle, whose basal

interval is composed of Early Cretaceous shallow-marine

sandstones and carbonates (Units 6 and 5) of Alam El-

Bueib Formation. These are followed by marine shale (Unit

4) and a succession of massive fluvial sandstones (Units 3;

Neocomian). Individual sand bodies are separated by

marine shale. The sands are overlain by the alternating

sands, shales, and shelf carbonates of Units 2 and 1, cul-

minating in the Alamein dolomite associated with the

Aptian transgression (Fig. 2). The Dahab Shale marks the

end of this cycle. The continental and shoreline sandstones

of the Kharita Formation are overlain by the shallow-

marine and nearshore deposits of the Bahariya Formation

(Lower Cenomanian). A marked deepening of depositional

conditions is indicated by the deposition of the Abu Roash

(G) (Upper Cenomanian). Widespread transgression

occurred during the Senonian with deposition of the Abu

Fig. 2 Regional stratigraphic

nomenclature, northern Western

Desert including Shoushan

Basin, Egypt


123

Roash (F) to (A) (predominantly carbonates). The uncon-

formably overlying Khoman Chalk Formation was depos-

ited only in the northern Western Desert. The cycle is

terminated by an unconformity, above which the Eocene

Apollonia Formation was deposited. The Dabaa and

Moghra Formations (marine clastics) above the Apollonia

Formation are capped by the Marmarica Limestone (Zein

El-Din et al. 2001).

Samples and methods

Samples from two wells (Shams NE-1 and Shams 2X-1)

were used to determine vitrinite reflectance and Rock–Eval

pyrolysis analysis. Pyrolysis was conducted using a Rock–

Eval II instrument with a total organic carbon module.

Parameters measured include TOC, S1, S2, S3, and tem-

perature of maximum pyrolysis yield (Tmax). Hydrogen

index (HI), oxygen index (OI), and production index (PI)

were calculated as described by Espitalie et al. (1977) and

Peters and Cassa (1994). Following Rock–Eval and TOC

analysis, samples were selected for further vitrinite reflec-

tance measurements. Whole rock samples for vitrinite

reflectance were crushed to less than minus-20 mesh size

and then made by mounting whole rock fragments in slow-

setting polyester (Serifix) resin mixed with resin hardener

and allowed to set, then ground flat on a diamond lap and

subsequently polished on silicon carbide paper of different

grades using isopropyl-alcohol as a lubricant for shales.

Finally, the samples were polished to a highly reflecting

surface using progressively finer alumina powder (5/20,

3/50 and Gamma). Vitrinite reflectance (VRr %) was

measured and conducted on the selected samples using a

microscope with white light source, photometer, and oil

immersion objectives. Typically, 25 measurements were

made for each sample, and standard deviation is in the

range of 0.05–0.08. However, low organic content limited

the number of points counted in some samples.

Two exploration wells (Shams NE-1 and Shams 2X-1;

Fig. 1) were chosen a location within the Shams Filed,

which is close to the major fields of hydrocarbon accu-

mulation in the Shoushan Basin, as representative sites to

model the timing of hydrocarbon generation. The burial

history was established using the stratigraphic record of the

region.

To assess the maturation history of potential source

rocks, 1D basin modeling software (PetroMod from Sch-

lumberger) has been used to calculate the levels of thermal

maturity and timing of hydrocarbon generation based on

calibration of measured vitrinite reflectance (Ro) against

modeled (EASY%Ro, Sweeney and Burnham 1990). Basin

modeling has been successfully applied to some important

petroliferous basins in different locations, such as the

Masila Basin in Yemen by Hakimi et al. (2010), Shoushan

Basin in Egypt by Shalaby et al. (2011), the Jeanne D’Arc

Basin, offshore Newfoundland by Baur et al. (2011).

Results and discussion

Vitrinite reflectance values (VRr %)

Vitrinite reflectance (% Ro) is widely accepted by explo-

ration geologists as a technique for measuring the thermal

maturity of sedimentary sequences. A variety of physical

and chemical methods have been used for the evaluation of

organic matter thermal maturity and for the interpretation

of coal and source rock thermal history, with vitrinite

reflectance (VRr %) as the most widely used tool (Tissot

and Welte 1984; Bustin 1987; Lerche 1990; Zhao and

Lerche 1993; Hunt 1996). Vitrinite reflectance values

between 0.5 and 1.3 % suggest samples are within the oil

generation window, while samples with values less than

0.5 % are considered thermally immature. Vitrinite

reflectance greater than 1.3 % indicates gas window

maturity (Tissot and Welte 1984). In this study, vitrinite

reflectance was measured on whole rock polished samples

at 8 stratigraphic levels (Jurassic–Cretaceous) in each well

(Shams NE-1 and Shams 2X-1) to create a vitrinite

reflectance profile (Fig. 3). The vitrinite reflectance profiles

show a general increase in vitrinite reflectance with depth

(Fig. 3). Mean vitrinite reflectance values range from 0.50

to 1.08 %. These values correspond to early mature to late

mature for hydrocarbon generation. The lowest Ro values

are from near the bottom of Abu Roash Formation and are

thermally early mature with respect to the hydrocarbon

generation. The highest values are from the Khatatba and

Ras Qattara Formations and are near the value associated

with peak oil window. Vitrinite reflectance profiles from

two wells show ranges of reflectance values (Fig. 3).

Source rock characteristics

Based on the statistical summary of 26 samples from Shams

NE-1 and Shams 2X-1, the Lower Cretaceous Alam El-Bueib

Formation has been identified as good potential source rock

because of its great thickness (756–837 m; Fig. 2), basin

wide distribution, and total organic carbon (TOC) content

(0.51–2.52 wt %) (Table 1), which meets the standard as a

source with fair to good hydrocarbon-generative potential

(Peters and Cassa 1994) as shown in Fig. 4. Kerogen type

was characterized by Rock–Eval pyrolysis analysis. The

kerogen typically has a low hydrogen index (HI), ranging

from 65 to 200 mg HC/g TOC, and relatively high oxygen

index, ranging from 10 to 186 mg CO2/g TOC, suggesting

predominantly Type III kerogen (Fig. 5). According to


123

petrographic examination, most of the Lower Cretaceous

Alam El-Bueib samples have vitrinite reflectance values in

the range 0.70 to 0.87 %, indicating that they are thermally

mature (Table 1). Tmax values range from 431 to 442 �C,

which are in reasonably good agreement with vitrinite

reflectance data, indicating that the Alam El-Bueib samples

have entered the oil window stage. The hydrocarbons appear

indigenous to the source rock as indicate by the production

index (PI) and Tmax values (Fig. 6). The Alam El-Bueib

Formation, therefore, contains an effective gas-prone source

rock that has good source potential within the Shoushan

Basin based on thermal maturity, TOC content, thickness,

and widespread distribution.

Basin modeling

Basin modeling is widely used in studies of burial and

thermal histories (Burrus et al. 1991; Hermanrud 1993;

Fig. 3 Vitrinite reflectance data

versus depth of nine

stratigraphic levels; a Shams

2X-1 well and b Shams NE-1

well


123

Littke et al. 1994; Lopatin 1971; Waples 1988, 1994; Welte

and Yukler 1981; Yalcin et al. 1997). The aim of the

numerical modeling here is to reconstruct the thermal

history and the timing of hydrocarbon generation of Alam

El-Bueib Formation in the Shoushan Basin. The modeling

inputs included the events (e.g., deposition, erosion, hiatus,

or non-deposition); present-day and original thicknesses;

lithology of strata; and present-day depth (Table 2). The

models were calibrated against both the present-day tem-

peratures, and the measured reflectance profile for each

well by adjusting heat flow until a match is observed. The

study also included the prediction of gas generation by

incorporating gas generation kinetics (Burnham 1989) into

the calibrated thermal history models.

Burial history

Using the basin-modeling procedures described previously,

predictions on timing of hydrocarbon generation were

made. To describe the resulting models clearly, we review

Table 1 Bulk geochemical results of rock–eval/TOC analysis with calculated parameters and vitrinite reflectance of the Alam El-Bueib

formation samples

Wells Depth (m) TOC

Wt %

Rock–eval pyrolysis Ro (%)

S1 (mg/g) S2 (mg/g) S3 (mg/g) S2/S3 (mg/g) S1 ? S2 (mg/g) Tmax (�C) HI OI PI

Shams NE-1

well

2,670 0.62 0.15 0.79 1.05 0.63 0.94 431 127 170 0.16 0.70

2,734 0.51 0.14 0.69 0.95 0.73 0.83 435 135 186 0.17 –

2,826 6.83 1.16 13.66 0.70 27.3 20.25 433 200 10 0.06 0.71

2,899 0.75 0.18 0.76 1.28 0.48 0.94 432 101 170 0.19 –

2,926 1.06 0.18 0.84 1.49 0.56 1.02 437 79 141 0.18 –

2,938 1.02 0.18 1.00 1.42 0.70 1.18 438 98 139 0.15 –

2,960 2.52 0.33 4.14 1.39 2.98 4.47 435 164 55 0.07 0.75

3,032 0.69 0.17 0.62 1.17 0.26 0.79 436 90 175 0.22 –

3,051 0.60 0.17 0.52 0.75 0.69 0.69 436 87 125 0.25 –

3,368 0.74 0.15 0.84 1.19 0.70 0.99 431 114 161 0.15 0.85

3,429 0.65 0.20 0.58 0.70 0.83 0.78 433 89 108 0.26 –

3,432 0.83 0.25 0.77 1.03 0.75 1.02 434 93 124 0.25 –

3,450 0.74 0.14 0.56 0.49 1.14 0.70 432 76 66 0.20 0.87

Shams 2X-1

well

2,755 0.58 0.11 0.45 0.47 0.96 0.56 436 78 81 0.20 0.70

2,758 0.57 0.11 0.52 0.45 1.16 0.63 435 91 79 0.17 –

2,911 0.88 0.16 0.99 0.31 3.20 1.15 437 113 35 0.14 –

2,914 1.04 0.15 1.04 0.35 2.97 1.19 437 100 34 0.13 0.75

3,008 0.66 0.17 0.61 0.36 1.69 0.78 437 92 55 0.22 –

3,036 0.90 0.19 0.79 0.33 2.40 0.98 440 88 37 0.19 –

3,039 0.76 0.13 0.61 0.29 2.10 0.74 440 80 38 0.18 –

3,042 0.84 0.18 0.69 0.54 1.28 0.87 437 82 64 0.21 0.83

3,045 0.72 0.17 0.51 0.75 0.68 0.68 437 71 104 0.25 –

3,280 0.52 0.14 0.34 0.94 0.30 0.48 442 65 180 0.29 –

3,310 0.65 0.13 0.63 1.12 0.41 0.76 440 97 172 0.17 0.84

3,331 0.53 0.13 0.48 0.89 0.39 0.61 440 91 168 0.21 –

3,402 0.55 0.16 0.45 0.54 0.83 0.61 440 82 98 0.26 0.86

TOC Total organic Carbon, wt. %

S1 Volatile hydrocarbon (HC) content, mg HC/g rock

S2 Remaining HC generative potential, mg HC/g rock

S3 Carbon dioxide content, mg CO2/g rock

HI Hydrogen index = S2x 100/TOC, mg HC/g TOC

OI Oxygen index = S3x 100/TOC, mg CO2/g TOC

PI Production index = S1/(S1 ? S2)

PY Potential yield = S1 ? S2 (mg/g)

R (%) Vitrinite reflectance


123

first the results of our reconstruction of the burial and

thermal histories.

Based on well profiles (see Table 2), sedimentation rate

can be estimated using the depositional age and thickness

(the present thickness) for the formations, which are pen-

etrated by the studied wells (Table 2). The burial history of

the studied wells is very similar, and an example is shown

in Fig. 7. During the Jurassic (198–144 Ma), Ras Qattara,

Khatatba, and Masajid Formations, sedimentation was

characterized by relatively low burial rates of about 9.8 m

per million years leading to a present thickness of about

645 m. Subsidence and sedimentation resumed in the

Lower Cretaceous (144–104 Ma), when the subsidence rate

increased to about 32.9 m per million years leading to

a present thickness of about 1,283 m. However, the Alam

El-Bueib Formation during that time was not buried dee-

ply, and the temperatures were too low for petroleum

generation.

The Alam El-Bueib Formation underwent continuous

burial as the Late Cretaceous–Tertiary sediments accu-

mulated, and the Alam El-Bueib source rock reached

maximum burial depth during Middle Miocene. The Late

Cretaceous (104–66 Ma) was characterized by higher

burial rates of about 34.7 m per million years leading to

a present thicknesses of about 1,354 m. The overlying

Tertiary was characterized by relatively low average sub-

sidence rates of about 12.5 m per million years. A total

thickness of 830 m of sediment was deposited during

Tertiary time.

Thermal history and palaeo-temperature data

The thermal history of a sedimentary basin depends not

only on the deposition and erosion history but also on the

heat-flow evolution (Allen and Allen 1990; Lachenbruch

1970). In this study, analysis of the influence of the tectonic

evolution in the basin on the heat-flow distribution through

time was made using 1D modeling. To obtain the thermal

history calibration, our model uses the present-day heat

flow as one of the input factors.

To estimate the heat-flow history, thermal conductivity

and geothermal gradient need to be determined. In this

study, the proportions of different lithologies for each

Fig. 4 Rock–Eval pyrolysis S2 versus total organic carbon (TOC),

showing generative source rock potential of Alam El-Bueib samples

Fig. 5 Plot of Oxygen index (OI) versus Hydrogen index (HI) for the

Alam El-Bueib samples

Fig. 6 Plot of Tmax versus production index (PI), showing the

maturation and nature of the hydrocarbon products of the Alam

El-Bueib samples analyzed


123

formation were calculated using borehole data. An average

thermal conductivity for each lithology was used in the

modeling. The present-day geothermal gradient of each

borehole location was calculated using bottom-hole tem-

peratures that were corrected for the circulation of drilling

fluids. The values increase systematically with depth from

a surface temperature.

The studied wells reached maximum temperatures at

Neogene time (Fig. 7).

Heat flow is a vital input parameter in basin modeling,

but it is commonly difficult to define this value for the

geological past. Therefore, the reconstruction of the ther-

mal history of the basin is always simplified and is usually

calibrated against profiles of maturity (e.g., vitrinite

reflectance) and temperature. In this study, the heat-flow

values during the tectonic development were estimated and

calibrated using measured vitrinite reflectance (VRr %)

data from the Cretaceous and Jurassic sediments. The

calibration curves for the studied wells are presented in

Fig. 8, which shows plots of vitrinite reflectance data and

corrected bottom-hole temperature versus depths. Matching

the calculated with measured vitrinite reflectance (VRr %)

Table 2 Input data used for burial and thermal histories models in the studied wells

Formation Deposition age Lithology Shams 2X-1 well Shams NE-1 well

From (Ma) To (Ma) Top (m) Bottom (m) Thick (m) Top (m) Bottom (m) Thick (m)

Sediments surface – – – 0.0 12.19 12.19 0.0 9.14 9.14

Marmarica 15.60 8.40 Limestone 12.19 185.93 173.74 9.14 193.60 184.46

Moghra 28.60 15.60 Shale 185.93 519.69 333.76 193.60 524.30 330.70

Dabaa 49.60 28.60 Sandstone 519.69 754.10 234.41 524.30 760.50 236.20

Apollonin 57.60 49.60 Lime & Dolo 754.10 830.88 76.78 760.50 839.50 79.00

Khoman 68.05 57.60 Sandstone 830.88 1,184.15 353.27 839.50 1,150.30 310.80

Abu Roash 89.35 68.05 Lime & Shale 1,184.15 1,904.40 720.25 1,150.30 1,861.11 710.81

Baharyia 97.65 89.35 Sandstone 1,904.40 2,185.11 280.71 1,861.11 2,127.50 266.39

Kharita 110.31 97.65 Sandstone 2,185.11 2,613.36 428.25 2,127.50 2,561.50 434.00

Alamen 113.26 110.31 Lime & Dolo 2,613.36 2,713.33 99.97 2,561.50 2,647.19 85.69

Alam El-Bueib 135.60 113.26 Limestone 2,713.33 3,468.93 755.60 2,647.19 3,484.50 837.31

Masajid 141.13 135.60 Shale & Lim 3,468.93 3,524.71 55.78 3,484.50 3,587.50 103.00

Khatatab 176.65 141.13 Limestone 3,524.71 3,883.15 358.44 3,587.50 3,871.00 283.50

Ras Qattara 199.60 176.65 Sandstone 3,883.15 4,114.80 231.65 3,871.00 4,108.70 237.70

Fig. 7 Burial history curves

with palaeo-temperature zones

in studied well Shams 2X-1,

Shams Field in the Shoushan

Basin (Bold lines for Alam

El-Bueib Formation)


123

data enabled the burial, temperature, and maturation his-

tory curves to be obtained for each well. The heat-flow

histories used in the calculations are also plotted in Fig. 8.

In the studied wells, heat-flow values range between 40 and

73 mW/m2. The studied wells reach maximum burial and

maximum temperature at the Neogene time. Therefore, the

heat flow can only be calibrated for the Tertiary years.

Jurassic heat flows were kept at 40 mW/m2 and increased

to 73 mW/m2 during the late Cretaceous–Early Tertiary. The

applied heat-flow values lead to a good match between opti-

cally measured (symbols) and calculated (lines) vitrinite

reflectance (Fig. 8). The corrected bottom-hole temperatures

can be matched with the present-day heat-flow values.

Different heat flows at the studied wells were required to

achieve a good fit between corrected measured bottom-hole

temperatures and calculated temperatures. However, these

variations are not required to match the measured vitrinite

reflectance values. In general, the fit of the calculated

maturity profile with the measured vitrinite reflectance

(%Ro) data supports the thermal maturity patterns resulting

from maximum burial and normal heat flow similar to

the modern-day values. Thus, Alam El-Bueib Formation

reached mature–late mature stages of hydrocarbon gener-

ation during the Tertiary (Fig. 9).

Fig. 8 Plots of calculated (lines) and measured (symbols) vitrinite reflectance values and corrected bottom-hole temperatures versus depths for

studied wells; the lower diagrams for each well show the assumed heat-flow history as used for the calculation


123

Prediction of gas generation of the Alam El-Bueib

formation

The timing of gas generation from the Lower Cretaceous

Alam El-Bueib Formation in the studied wells was assessed

based on burial and thermal histories. Gas generation

stages were calculated assuming mainly Type III kerogen

and using a reaction kinetic data set based on Burnham

(1989). The modeled gas generation of the studied wells is

shown in Fig. 10. This model shows that the onset of the

gas generation of the Lower Cretaceous Alam El-Bueib

source rock was during early Tertiary (Paleocene) at a

depth range of 2,750–2,790 m (Fig. 10). Accordingly,

hydrocarbon generation (gas) started in the Paleocene

(60 Ma), and peak gas generation occurred during the end

of Tertiary (Figs. 10, 11).

The amount of gas generated within this area was cal-

culated using geochemical data. The volume of gas gen-

erated from a unit volume of source rock is related to the

amount, type, and maturity of its kerogen. The maturity of

kerogen can be expressed by its ‘‘transformation ratio’’,

which is defined as the ratio of the amount of hydrocarbons

generated to the total amount of hydrocarbons that the

kerogen is capable of generating. The gas generation

curves (Fig. 11) for the studied wells show that the trans-

formation ratio reaches 10 % during the Paleocene (60 Ma

age), with first significant amount of gas generation from

the Lower Cretaceous Alam El-Bueib sediments. The

maximum transformation ratio (65–68 %) was reached

during the Pliocene (3–2 Ma; Fig. 11). Hydrocarbons

generated from the Alam El-Bueib sediments are mainly

gas (Fig. 11). In the study area, the thickness of the Alam

El-Bueib Formation in borehole sections varies from 280 to

360 m (930–1,176 ft). The Alam El-Bueib sediments have

a good hydrocarbon potential with mainly gas generation

potential. Therefore, the Alam El-Bueib Formation is an

effective gas-prone source rock within the Shoushan Basin

based on thermal maturity, TOC content, kerogen type,

thickness, and widespread distribution. This is in agree-

ment with the gas production from the studied field

(Fig. 1), and there are more accumulations to be found.

Conclusions

Investigation Lower Cretaceous Alam El-Bueib Formation

indicates that most shales and carbonate rocks of this for-

mation have a good potential as gas-prone source rocks in

the Shoushan Basin, northern Western Desert of Egypt.

Kerogen type and total organic carbon data from Rock–

Eval pyrolysis indicate that most shale and carbonate units

of Alam El-Bueib Formation contain mainly type III

kerogen (gas prone) with low hydrogen index values

(65–200 mg HC/g TOC) and high oxygen index values

ranging between 10 and 186 mg CO2/g. Vitrinite reflec-

tance was measured for eight stratigraphic levels (Jurassic–

Cretaceous) in two wells to create vitrinite reflectance

profiles. The vitrinite reflectance profiles show a general

increase in vitrinite reflectance with depth and indicate that

most units have attained sufficient burial depth and thermal

maturity for significant hydrocarbon generation. Vitrinite

reflectance data show that the Alam El-Bueib sediments

Fig. 9 Burial history curves

with thermal maturity zones in

studied well Shams SE-1 in the

Shams Field, Shoushan Basin


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Fig. 10 Burial history curves with gas generation zone for the Alam El-Bueib Formation in the studied wells, Shams Field, Shoushan Basin


123

Fig. 11 Transformation ratios and gas generation from Alam El-Bueib source rock in the studied wells


123

have reached the mid-mature stage for hydrocarbon gen-

eration, consistent with Rock–Eval pyrolysis Tmax values.

Numerical modeling of two wells cross in the Shoushan

Basin indicates that the Alam El-Bueib source rock entered

the mid-mature stage for significant of hydrocarbon gen-

eration during Tertiary age. The onset of gas generation

phase started during the Paleocene, and maximum rates of

gas generation were reached during the end of Tertiary

(Pliocene).

Overall, the Alam El-Bueib sediments are an effective

source rocks for gas in the Shoushan Basin, and there are

more gas accumulations to be found in the basin.

Acknowledgments The authors would like to thank Khalda Oil

Company, Egypt, for providing the data and samples for this study.

The authors are grateful to the Department of Geology, University of

Malaya for providing facilities to complete this research. Schlum-

berger (Slb) is acknowledged for providing the PetroMod Basin

Modeling software. Special thanks are offered to Mr. Peter Abolins

for his helpful comments on the basin modeling. Reviews by Peter

Abolins and anonymous referees improved the paper and are pro-

foundly acknowledged.

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