Structural Style and Hydrocarbon Potential Evaluation of ... Badin block is located in the Lower...

Available on: www.bahria.edu.pk/bukc/burjes2016 Bahria University Research Journal of Earth Sciences Vol. 2, Issue 1, June 2017

ISSN 2415-2234 © BURJES Page 30

Structural Style and Hydrocarbon Potential Evaluation of Badin Block,

Lower Indus Basin, Pakistan

Muhammad Fahad Mahmood, Urooj Shakir, M. Raiees Amjad, Asad Taimur

Department of Earth and Environmental Sciences, Bahria University, Islamabad Campus, Pakistan.

Corresponding Author Email: [email protected]

Abstract - Badin area is located in the southwestern

periphery of the Indian plate, in lower Indus basin. The

research is carried out to delineate the subsurface geometry of

the area with the help of seismic data in order to understand its

petroleum system. Main emphasize is to analyze reservoir

formations and sealing characteristics. Time and depth contour

maps are generated to reveal the subsurface structural

geometry along with petrophysical analysis for formation

evaluation and reserves estimation to calculate the

hydrocarbon potential. Interpretation results show extensional

regime, dominated by horst and graben structures. Grabens are

of immense exploratory importance in research area as they are

believed to be the kitchen area of hydrocarbon generation. The

faults show different aspects, of which the foremost is trap

formation and their role to facilitate the hydrocarbon migration

from source to reservoir. Study area holds all the major

elements of petroleum system considering risk and volumetric

analysis results.

Keywords – Seismic data, Petrophysical analysis,

Formation evaluation, Reserves estimation

INTRODUCTION

The Badin block is located in the Lower Indus Basin,

southern portion of the Sindh, Pakistan, approximately 160

km east to the Karachi city (Figure 1). The total area of the

concessions is 7,650 km2. The location of Badin South block

lies between 68゜11’ E to 68゜47’ E longitude and 24゜06’

N to 25゜02’ N latitude as shown in Figure 1. The Badin

South block covering an area of 1265.3 km2, bounded on the

north by Hyderabad district, on the east by Tharparkar

districts, while Thatta district is present on its west side and

Arabian Sea on its southern side Ahmad et al., (2003).

In this research seismic data is used to investigate the

structural styles, tectonic setting and hydrocarbon potential

of the Badin Block. For future exploration strategies, the

seismic lines used for seismic data interpretation are shown

in Figure 2.

Fig. 1 Geological map showing location of the study area

not drawn to scale (modified after Kazmi et al., 1979).

TECTONICS AND STRATIGRAPHY

Badin is part of the Lower Indus basin. The Lower Indus

Basin stretches north-south along the Indus River and south

of Khairpur-Jacobabad High towards Arabian Sea. The

Nagar Parker Granite in the extreme southeastern corner of

Pakistan is the exposed part of the Indian craton. The areas

located to the west and northwest of Nagar Parker are the

Tharparkar slope that dips westward and northwestward and

where Indus basin is most prospective for hydrocarbon

exploration (Mozaffar et al., 2002). The Badin Rift (Figure

1) is characterized by a series of horst and graben structures

present below the base Paleocene unconformity. These

horsts and graben structures were formed as a result of rifting

between India and Seychelles during the Late Cretaceous

(Khan et al., 2013).

Fig. 2 Basemap of study area showing the orientation of

seismic lines and wells locations

The oldest formation penetrated in Badin is the Jurassic

Chiltan Limestone (Mozaffar et al., 2002), which overlies

Triassic strata within the Badin Block (Khan et al., 2013).

Whereas, Chiltan Formation (Figure 3) overlain by the

Lower Cretaceous marine sand-shale sequence of the

Sembar and Goru Formations (Wasimuddin et al., 2005).

The lower most Sembar Formation of the Early Cretaceous

sequence is composed of organic rich shale. The Lower Goru

sequence overlies the Sembar Formation. The Lower Goru

horizon is divided into five members based on predominant



lithologies. The Upper Goru unconformably overlies the

Lower Goru Formation, which consists of mainly marl and

calcareous claystone (Figure 3) occasionally with interbeds

of silt and limestone (Mozaffar et al., 2002).

Fig. 3 Stratigraphic column of Badin Area (modified

after Mozaffar et al., 2002).

METHODOLOGY AND RESULTS

A) Seismic Data Interpretation and Mapping

Before carrying out seismic interpretation of study area

the seismic to well tie was performed. For this purpose

synthetic seismogram was generated using Forward

Modeling Technique (figure 4). Synthetic seismograms were

generated at well Keyhole-1 and Doti-1 by using acoustic

and density log (Figures 5 & 6). The well logs were also used

throughout the correlation process

Fig. 4 Synthetic seismogram generated at

Keyhole-01 well

Red line in Figure 4 denotes the velocity curves derived

from the sonic log. Blue line is the density curve, while green

curve denotes the acoustic impedance. Extracted Ricker

wavelet is also shown in Figure 4. The final trace is displayed

in the right part in Figure 4. On the basis of all above sonic,

density, acoustic impedance, and the GR log response is

observed for Formations Lower Goru and its sub divisions.

Fig. 5 Formation tops from Doti-1 overlain

on seismic section

Seismic data is interpreted and many favorable spots for

oil and gas accumulation were identified as shown in Figure

7, and with integrated geological and geophysical data

Fig. 6 Formation tops from Keyhole-1 overlain

on seismic section

The data quality is from average to good due to which

horizons and major faults were easily sorted out. All the

major faults were marked and assigned a specified color in

order for fault correlation to create fault polygons in Two

Way Time and subsequently Depth Mapping. Minor faults

indicated on single lines were unassigned and were left in

their natural black color scheme. Interpretation below


ISSN 2415-2234 © BURJES 2

Khadro indicated tilted fault blocks, normal faults with

north-south trend and a significant throw, as well as horst and

graben structures. All this interpretation correlate with the

regional geology of the area (Jadoon et al., 2016) which

indicates the confidence of the interpretation as shown in

Figure 7.

Fig. 7 Interpreted Seismic Line PK92-1682

Fig. 8 Two Way Time contour map at TLG

As per the seismic reflection data interpretation, two

way time maps were generated on all levels described above.

Faults polygons were prepared for all assigned and

unassigned faults and were associated to the grid of the

specified horizon. These grids were subjected to certain

calculations after which the two way time contours were

generated. Initially regional maps were generated and

analyzed carefully before any depth conversion. Various

structural closures were identified on all four levels as shown

in figure 8.

Velocities for depth conversion were determined by a

velocity-time curve utilizing the data of Doti and Keyhole

wells. The velocities determined from the curve were utilized

in the preparation of ‘Depth Structure’ Maps. While the maps

on TLG were prepared using variable velocity method as

shown in figure 9.

Fig. 9 Depth contour map at TLG

The contour maps of top Lower Goru indicate that

formation is deepening in the western side on contrary to

Ranikot formation. This change of dipping indicates the

change in basin tilt at the later stage. The contour maps of

TLG, show horst and graben geometry in which major faults

are running from northwest to southeast direction. Faults are

dipping towards west and east. The red color indicates the

prominent highs whereas the deep blue color shows the

graben structure. One high is present in the eastern side, as

the leading structure. The high present in the center where

well Doti-01 was drilled is the prominent structure (Figures

8 & 9).

B) Petrophysical Evaluation

Digital LAS files of Doti-01 and Keyhole-01 were

loaded in Kingdom software for petrophysical analysis. The

petrophysical techniques were used to calculate the Shale

Volume, Average Porosity, Effective Porosity and Water

Saturation. Details of the petrophysical methodology

adopted and derivation of petrophysical parameters used

therein are described as following. Interpretation is carried

out at Cretaceous Lower Goru Sands (figure 10). Volume of

shale, average and effective porosities, and water saturation

are calculated. The results of the calculation at Top Lower

Goru level in Doti-01 well are given below:

Vsh calculated is 32%. PHIA calculated is 14% which

indicates good average porosity. PHIE calculated is 9%

which indicates fair effective porosity. SW calculated is 71%

which indicates that despite having fair to good porosity, the

well turned out to be water wet. Most of the hydrocarbon

accumulation in Badin is in ‘A’ and ‘B’ sands. The ‘C’ sand

is either wet or has shown strong water support to

hydrocarbon accumulations. This leads to a conclusion that

Doti has not encountered ‘A’ and ‘B’ sands. Either the well

was drilled inside the fault due to which it missed the ‘A’ and



‘B’ sands. Another reason is inferred that ‘A’ and ‘B’ sands

may not be present in this part of the block.

Fig. 10 Petrophysical Interpretation at Lower

Goru Level (Doti-01 well)

Fig. 11 Petrophysical Evaluation at Top Lower

Goru (Keyhole-01 well)

Keyhole-01 well logs were also interpreted on the same

footing as of Doti-01 well (Figure 11). The results of the

interpretation at Top Lower Goru are VSH calculated is 10%.

PHIA calculated is 10% which indicates fair average

porosity. PHIE calculated is 8% which indicates fair

effective porosity. Sw calculated is 84% which indicates that

despite having fair porosity, the well turned out to be water

wet.

C) Risk Analysis

Risk assessment is an analysis of the reliability of

occurrence of the geological models relevant to the prospect

under evaluation. It assigns a probability of success to each

of the four elements of the play concept, so prospect is

ranked on the basis of risk assessment (Robert et al., 2004).

The major elements of play concept are given as:

Probability of hydrocarbon charge include Source Rock

and Migration. Probability of reservoir include Porosity and

Permeability, while Probability of trap include closure and

seal. In order to fulfill this criterion, The GCOS (geological

chances of success) is calculated which is an estimate of the

chance of all the elements of a petroleum system working,

described as a probability. If probability of success is equal

to or greater than 0.50, this is the typical probability of

success of a step out or delineation well, or of an adjoining

structure. If probability of success is between 0.20 - 0.30, this

is the typical range of probability of success of exploration,

in an area with many similar plays and structures and for

exploration well which is in such a structure not too far from

existing discoveries. If probability of success is between 0.10

- 0.20, this is the typical range of probability of success of

exploration, in a well explored area with a variety of different

plays and on a new location. If probability of success is

between 0.02 - 0.05, this is the typical range of probability of

success of exploration, in a poorly explored area or a new

geological basin in which previously no wells have been

drilled or only dry holes have been drilled. Badin being study

area supports a proven petroleum system with all the above

mentioned geological factors present. This confirms that the

leads identified in Badin structure are valid when it comes to

geological factors. Taking in considerations the conclusions

derived from the petrophysical interpretation, the lead

present at Top Lower Goru Formation is evaluated as

prospects (table 1).

Table 1 GCOS of Top Lower Goru Formation

SOURCE 1

SEAL 1

RESERVOIR 0.7

TRAP 0.6

MIGRATION 0.6

GEOLOGICAL CHANCE OF SUCCESS 0.26

After carrying out risk analysis the GCOS of Top Lower

Goru Formation comes out to be 26%.

D) Volumetric Assessment

Volumetric estimation expresses uncertainty in a

distribution of possible hydrocarbon volumes for the

prospect. Utilizing volumetric analysis hydrocarbon in place

and recoverable reserves are calculated. ‘Oil in place’ is the



total hydrocarbon content of an oil reservoir and is often

abbreviated STOIIP for ‘Stock Tank Oil Initially in Place’.

The amount of oil in a subsurface reservoir is called ‘oil in

place’. Only a fraction of this oil can be recovered from a

reservoir. This fraction is called the ‘recovery factor’.

The portion that can be recovered is considered to be a

reserve. The portion that is not recoverable is not included

unless and until methods are implemented to produce it

(Table 2).

Table 2 Volumetric Analysis for Top

Lower Goru Formation

Recovery factor for oil is 5-15% for natural depletion,

15-30% for effective water drive method and 30-65% using

pressure maintenance methods (Rogner, 1997). The

volumetric analysis is carried out at Top Lower Goru

Formation in which the hydrocarbon volume, reserve in

place and recoverable reserves were calculated (Table 2).

The recoverable reserves comes out to be 46 million barrel

of oil for Top Lower Goru Formation

DISCUSSION AND CONCLUSIONS

Despite being actively producing for the past 20 years,

Badin still has potential to produce hydrocarbons Seismic

interpretation on a sparse grid indicated structures which

means that with a finer grid we can map these structures with

better control. The structures were in conformity with the

tectonics of Badin, that is, extensional tectonics with tilted

fault blocks and horst and graben structures. The picks were

confirmed by two different methods (Forward Modeling and

Well Top Correlation Method) yielding similar results and

enhanced the confidence on the horizon picks. Petrophysical

analysis revealed that the reservoir part of the upper sand is

truncating as we go towards East. This included detailed

petrophysical interpretation of Keyhole-01 and Doti-01 well.

Doti-01 well was used as a reference well for future

prospects for Top Lower Goru Formation. While carrying

out risk analysis at Top Lower Goru Formation, the GCOS

are fruitful in Badin area. Similarly volumetric analysis for

Top Lower Goru Formation, the recoverable reserves comes

out to be 46 MMBO, which are sufficient reserves to perform

future exploration at TLG level.

REFERENCES

[1] Ahmed, A., Alam, S. and Ejaz, M., (2003). Source rock

potential of Tertiary Coal and associated sediments from Thar

Coal field, Lower Indus Basin, Pakistan: PAPG-SPE Annual

Technical Conference, 1-18.

[2] Jadoon, S.U.R.K, Mehmood, M.F, Shafiq, Z., and Jadoon, I.

A. K., (2016). Structural Style and Petroleum Potential of

Miano Block, Central Indus Basin, Pakistan. International

Journal of Geosciences, 7, 1145 – 1155.

[3] Kazmi, A.H., (1979). Active Fault Systems in Pakistan,

Geodynamics of Pakistan, Geological Survey of Pakistan.

285p.

[4] Khan, M.R., Iqbal, M., Ahmad, A., Murtaza, G., and Khan,

W.A., (2013). An Integrated Approach for Assessment of

Lower Goru Reservoir Quality in Western Part of Badin Area,

Lower Indus Basin, Pakistan. PAPG/SPE Annual Technical

Conference 2013, Islamabad, Pakistan. This publication is

only available in digital format provided to the participants

only.

[5] Mozzaffar, S.M., Wasimuddin, M. and Sayeed, S.M., (2002).

“Zaur Structure, A Complex Trap In A Poor Seismic Data

Area”. British Petroleum Pakistan, SPE. 2004, no. 2-8.

[6] Robert, M.O., Schneidermann, N., (2004). A Process for

Evaluating Exploration Prospects. Journal of Petroleum

Science and Engineering, Volume 44, Issues 1-2, 1-9.

[7] Wasimuddin, M., Jadoon, I.A.K., Weihua, W., Akhtar, S.,

Ebdon, C.C., (2005). Integration of Image Logs in the

Structural Analysis of the Zaur Field, Lower Indus Basin,

Pakistan. PAPG/SPE Annual Technical Conference 2005,

Islamabad, Pakistan.

[8] Yilmaz, O., (2001). Seismic data analysis and processing,

inversion and analysis of seismic data, Society of Exploration

Geophysics, Tulsa. 2027p.

Conversion Factor 7758

GRV 485439.49 acres

Gross Thickness 177 feet

Net Pay 120 feet

Net to Gross Ratio 120/177 0.6

Porosity 0.11

Sw 0.25

So (1-Sw) 0.75

Bo 1.2

STOIIP = N = 7758 * GRV * N/G * ф *So*1/Bo

STOIIP = 7758 * 485439.49 * 0.6 * 0.11 * 0.75/1.2 = 155349133.51

Oil in Place (OIP) = 155 MMBO

Recoverable Reserves = STOIIP * 0.30 (Recovery Factor for Oil)

Recoverable Reserves = 155349133.51 * 0.30 = 46604740.053

Recoverable Reserves = 46 MMBO

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