Prediction of pore pressure and fracture pressure in Cauvery and Krishna-Godavari basins, India

Accepted Manuscript Prediction of pore pressure and fracture pressure in Cauvery and Krishna-Godavari basins, India Sumangal Dasgupta, Rima Chatterjee, Sarada Prasad Mohanty PII:

S0264-8172(16)30342-7

DOI:

10.1016/j.marpetgeo.2016.10.004

Reference:

JMPG 2697

To appear in:

Marine and Petroleum Geology

Received Date: 25 March 2016 Revised Date:

19 September 2016

Accepted Date: 3 October 2016

Please cite this article as: Dasgupta, S., Chatterjee, R., Mohanty, S.P., Prediction of pore pressure and fracture pressure in Cauvery and Krishna-Godavari basins, India, Marine and Petroleum Geology (2016), doi: 10.1016/j.marpetgeo.2016.10.004. This is a PDF file of an unedited manuscript that has been accepted for publication. As a service to our customers we are providing this early version of the manuscript. The manuscript will undergo copyediting, typesetting, and review of the resulting proof before it is published in its final form. Please note that during the production process errors may be discovered which could affect the content, and all legal disclaimers that apply to the journal pertain.

ACCEPTED MANUSCRIPT 1

Prediction of pore pressure and fracture pressure in Cauvery and Krishna-Godavari

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Basins, India

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Sumangal Dasgupta1, Rima Chatterjee2 and Sarada Prasad Mohanty3

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Department of Applied Geology, Indian School of Mines, Dhanbad 826004, India

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Department of Applied Geophysics, Indian School of Mines, Dhanbad 826004, India Email: [email protected]; [email protected]; [email protected]

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Abstract

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Geoscientific data from several wells drilled in onshore and offshore parts of the Cauvery and

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Krishna-Godavari basins, two main hydrocarbon producing basins located in the east coast of

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India, have been used to determine pore pressures and fracture pressures in the subsurface

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formations. We have estimated pore pressure based on Zhang’s porosity model. Variations of

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normal compaction curves across the basins are demonstrated here. This study also proposes

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simple relationships among the parameters used in Eaton’s equation for estimating the

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fracture pressure. Relations established based on the available data in this current study are

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compressional and shear sonic velocities against bulk density, Poisson’s ratio against depth,

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and the overburden stress against depth. These empirical relationships can be used to predict

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fracture gradient for the future drilling locations in these basins. The pore pressure in

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Cauvery basin is shown to be almost hydrostatic in nature, which is due to normal

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sedimentation rate. High sedimentation rate in the Miocene section of the KG basin is found

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to be the main reason for overpressure development.

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Keywords: Pore pressure; Sonic velocity; Bulk density; Compaction curve; Poisson’s ratio;

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Petroleum System

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ACCEPTED MANUSCRIPT 1. Introduction

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Pore pressure (the fluid pressure in the pore spaces of the subsurface formation) and fracture

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gradient are two important aspects to be considered in hydrocarbon exploration and

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development scenarios for safety, cost effectiveness and the efficiency of the overall drilling

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programme (Jayasinghe et al., 2014). Hydrostatic pressure (normal pore pressure) exerted by

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a static column of fluid varies according to the density of the fluid (Osborne and Swarbrick,

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1997). Pore pressure above or below the hydrostatic pressure is considered to be abnormal

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pressure. Abnormally high pore pressure may result in a drilling hazard if the precautionary

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measures are not taken care. Prediction of pore pressure is essential in well planning,

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selection of casing point, drilling cost, safety, drilling procedures, and completions (Law and

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Spencer, 1998; Ruth et al., 2002). The most reliable and direct pressure measurement can be

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obtained mainly from the drill stem test (DST), modular dynamic test (MDT), and repeat

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formation test (RFT).. Mud weight (MW) can be used as a proxy for the pore pressure where

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direct pressure measurement data is not available (Law and Spencer, 1998; Ruth et al., 2002).

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Fracture pressure is defined as the optimum pressure at which new fractures develop in a rock

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formation. Fracture gradient is calculated by dividing the fracture pressure by true vertical

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depth (Zhang, 2011). Fracture pressure can be obtained directly from leak-off test (LOT).

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Knowledge of fracture gradient is essential in mud designing, cementing, matrix and fracture

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acidizing, hydraulic fracturing, and fluid injection in secondary recovery (Eaton, 1969).

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Drilling induced fractures happen when the pressure due to the mud weight exceeds the

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fracture pressure at a given depth and results into mud loss from the well bore into the

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induced fractures (Zhang, 2011; Kankanamge, 2013). Lost circulation during drilling is a

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troublesome and expensive problem (Eaton, 1969).

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The main objectives of the study are: (a) to demonstrate the occurrences and magnitudes of

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overpressures in several stratigraphic formations across the Cauvery and Krishna Godavari

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ACCEPTED MANUSCRIPT (KG) basins, east coast of India, (b) to show the effect of pore pressure on the porosity and to

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suggest calibrated normal compaction trends, (c) to identify the top of overpressure zones and

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its variation across the basins and (d) to establish empirical relationships to estimate the

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vertical stress and the minimum horizontal stress for these basins.

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It is a common phenomenon that porosity decreases exponentially with increase in depth in

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any sedimentary sequence in case of normal compaction. The results of under-compaction are

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higher pore pressure and more porosity than that of normally compacted sediments (Zhang,

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2011). The starting depth of the porosity reversal is known as top of overpressure zone or top

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of the under-compaction. Several pore pressure prediction models available (cf. Heppard et

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al., 1998; Flemings et al., 2002; Holbrook et al., 2005) consider porosity-dependent effective

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stress relationship. Porosity model (Zhang, 2011) is applied here to estimate the pore pressure

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(described in section 5.1). This model also proposes porosity as a function of effective stress

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and pore pressure, particularly for the overpressure generated by under-compaction and

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hydrocarbon-cracking (Zhang, 2011).

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Formation will fracture when the pressure in the borehole exceeds the minimum in-situ stress

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within the rock. The fracture will propagate in a direction perpendicular to the minimum

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principal stress. Minimum stress refers to the minimum principal in-situ stress and generally

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equal to the fracture closure pressure. Thus, it measures the lower bound of the fracture

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gradient. Therefore, the minimum stress method (Zhang, 2011) is applied here for estimating

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the fracture gradient using the wireline log data.

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Besides pore pressure, other parameters needed to estimate the fracture gradient are Poisson’s

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ratio and overburden stress (described in section 5.2). Density, compressional and shear sonic

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logs from drilled wells are required to estimate Poisson’s ratio and overburden stress. This

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work attempts to generate basinwide empirical relations so that the above parameters can be

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ACCEPTED MANUSCRIPT estimated even there where the full set of data is not available. Therefore, these relations can

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be used as predictive tools to estimate the fracture pressures in these basins.

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We have analysed 26 exploratory wells (10 wells from the Cauvery and 16 wells from the

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KG Basins) to estimate pore pressure and fracture pressure, and correlate these parameters

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with the observed values acquired during the well operations. These wells are distributed

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across the basins (Fig. 1 and 2) and many of them terminated in the basement. These data

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provide opportunity to analyse both lateral and vertical variations in petrophysical properties

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of rocks in these two basins. Geoscientific and engineering data, such as wireline log suite,

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litholog, LOT, DST, MDT, and MW maintained during drilling, were used during the course

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of this study. All the analyses were carried out for the two basins separately. The results

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presented here provide acceptable estimates from the available data in a short time.

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2. Tectonics and sedimentation

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The Cauvery and KG basins are located in the east coast of India (Fig. 1 and 2). These are

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well known as prolific oil and gas producers. The gneiss and granites of Archaean age form

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the basement of the sedimentary rocks in both the basins. These basins developed during the

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separation of Antarctica from India at the time of break-up of the Gondwanaland. The

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histories of evolution of these basins are quite similar. However, the sedimentation patterns

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over time differ from each other.

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2.1 The Cauvery basin

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The Cauvery basin is the southernmost basin in east coast of India. This basin covers an area

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of about 25000 sq km onland and 30000 sq km in the offshore area (Phaye et al., 2011). This

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basin is classified as pericratonic rift basin (Sastri et al., 1981; Biswas et al., 1993; Chari et

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al., 1995; Biswas, 2012), formed due to the fragmentation of Gondwanaland during Late

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Jurassic / Early Cretaceous period (Jafer, 1996; Phaye et al., 2011). Cauvery basin has 6

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ACCEPTED MANUSCRIPT major sub-basins namely Ariyalur-Pondicherry, Tranqueber, Nagapattinam, Tanjore,

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Ramnad-Palk bay and Gulf of Mannar (Fig. 1). Gulf of Mannar is the southernmost part of

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the Cauvery basin and is outside the map area. The major horsts, which separate these sub-

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basins, are Kumbakonam-Madanam-Portonovo high, Pattukottai-Mannargudi-Vedaranyam-

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Karaikal high and Mandapam-Delft high (Phaye et al., 2011). NE-SW trending major horsts

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and grabens formed during the rifting phase. Total sediment fill is about 5 – 6 km in the

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Cauvery basin (Srikant and Shanmugam, 2014).

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Sedimentation during the early rifting stage in the Cauvery basin is marked by the deposition

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of fluvial coarser clastics in Late Jurassic / Early Cretaceous period. Marine influence

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increased during the late syn-rift stage with the deposition of finer clastics (Paranjape et al.,

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2014). Middle to late Cretaceous post-rift marine mixed siliciclastic and carbonate sequences

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are recorded in the basin (Paranjape et al., 2014). Rate of sedimentation during the rifting

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period is reported to be about 50 m/m.y. (Ramani et al., 2000).

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2.2 The KG Basin

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The KG basin is located in the central part of the east coast of India. This basin covers an area

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of approximately 100,000 sq km (Bastia, 2004) spanning in both onshore and offshore.

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Around 5-7 km of sediment column ranging in age from Permo-Carboniferous to Recent, is

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identified in the KG basin. This basin was a major intracratonic rift within Gondwanaland

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until Early Jurassic (Husain et al., 2000; Rao, 2001). The oldest sedimentary sequence in this

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basin is classified as pre-rift fill which is Permo-Carboniferous in age. Late Jurassic to Early

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Cretaceous period marks the syn-rift phase of the basin (Prasad et al., 2008; Padhy et al.,

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2013). During this time the NE-SW trending horsts and graben systems (Fig. 2) formed due

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to extensional faulting (Prasad et al., 2008). Syn-rift system is mainly characterized by fluvio-

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lacustrine depositional environment. The first definite marine transgression occurred during

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ACCEPTED MANUSCRIPT Aptian (Husain et al., 2000). The post rift and drift phase commenced from Late Cretaceous

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(Prasad et al., 2008). Indian plate moved rapidly towards north with a counter clockwise

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rotation and collided with the Eurasian plate during Late Eocene (Srivastava and Chowhan,

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1987). Major delta progradation started due to the uplift of the hinterland. During Miocene,

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hard collision of India-Eurasia forming the Himalayan Orogen resulted in rapid

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sedimentation in the basin. Rate of sedimentation during Upper Cretaceous to Miocene is

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reported as 70 – 125 m/m.y. in the KG basin (Rao and Mani, 1993; Raju et al., 1994; Anitha

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et al., 2014).

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3. Petroleum system

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Oil and gas are being produced from number of fields, both onshore and offshore, in the

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Cauvery and KG basins. Several source and reservoir rocks of various geological ages are

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proven in these basins.

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3.1 The Cauvery basin

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Multiple petroleum systems of both Cretaceous and Tertiary ages are proven in onland and

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offshore parts of the Cauvery basin. Albian-Aptian shale deposited during syn-rift stage

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under mixed environment of both continental as well as marine is considered to be the main

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source rock in the Cauvery basin (Husain et al., 2000). Post rift shales deposited during Late

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Cretaceous act as secondary sources. The main reservoir, Upper Cretaceous Nannilam sands

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(Husain et al., 2000), were deposited under marine environment (Avadhani et al., 2006;

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Srikant and Shanmugam, 2014). Campanian fans in offshore part of the basin are also proven

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to be hydrocarbon producing reservoir (Hardy, 2010). Early Upper Cretaceous Bhuvanagiri

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(Phaye et al., 2011) and Early Cretaceous syn-rift Andimadam sands are the other two

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Cretaceous reservoirs in the basin. Fluvio-deltaic Kamalapuram sands of Eocene – Paleocene

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age and Oligocene Niravi sands are two major proven Tertiary reservoirs in Cauvery basin

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ACCEPTED MANUSCRIPT (Avadhani et al., 2006). Hydrocarbon is also discovered in fractured basement in offshore

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part of the basin (Sircar, 2004; Chandrasekhar et al., 2015).

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3.2 The KG Basin

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Several petroleum systems have been proven in the KG basin. Pre-rift Permo-Carboniferous

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petroleum system is dominated by gas and condensates. Permian coal and carbonaceous shale

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are proven to be the source rock for this petroleum system (Prasad et al., 2008). Mainly

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fluvial sandstones are the proven reservoirs in this petroleum system. Discoveries from the

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Late Jurassic – Early Cretaceous syn-rift sequences proved gas, condensates as well as oil in

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onland and offshore areas in the basin. Early Cretaceous syn-rift shales are oil prone source

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rocks (Rao, 2001).

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Late Cretaceous Petroleum system has a proven source rock of Cenomanian to Campania age

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transgressive shale which is a mix of type-II and III kerogens (Husain et al., 2000; Prasad et

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al., 2008). Transgressive and high stand sands are the main reservoirs in this petroleum

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system. Paleocene shale, rich in type-III kerogen and Late Eocene/Early Miocene shales, a

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mix of type-III and II kerogens are the main source rocks in Tertiary petroleum system

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(Venkanna et al., 2000). Clastic reservoirs of fluvial, deltaic, shoreface, lowstand fans etc

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ranging in age from Eocene to Pliocene are the proven reservoirs in this petroleum system.

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Plio-Pleistocene in the deeper water is the youngest petroleum system in the KG basin. Huge

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volume of biogenic gas is reported from this petroleum system.

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4. Pore Pressure

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The terms overpressure and underpressure refer to the absolute values above and below the

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hydrostatic pressure respectively, at the depth of investigation (Barker, 1972; Bradley, 1975;

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Fertl, 1976; Carstens and Dypvik, 1981; Walls et al., 1982; Mudford, 1988; Hunt, 1990).

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Abnormal pore pressures are observed in many sedimentary basins around the globe

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ACCEPTED MANUSCRIPT (Osborne and Swarbrick, 1997; Xie et al., 2001; Zahid and Uddin, 2005; Tingay et al, 2009).

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Globally magnitudes of overpressures are classified as mild (11.5-14.0 MPa/km), moderate

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(14.0-17.0 MPa/km) and high (>17.0 MPa/km) (Tingay et al., 2013). High rate of

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sedimentation is considered to be one of the main reasons for generation of overpressure as it

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does not allow efficient expulsion of the pore fluid with burial and compaction (Swarbrick

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and Osborne, 1998). Overpressure commonly occurs where sedimentation rate exceeds 100

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m/m.y. with mudstone (low permeable fine grained sediments) content more than 85%, such

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as Cenozoic Gulf of Mexico, and Baram Delta of Brunei (Bethke, 1986).

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The patterns / characters of pore pressure in the Cauvery and KG basins are quite different

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from each other. Mild to high - a wide range of pore pressure are reported in both onshore

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and offshore wells in the KG basin (Kumar et al., 2006; Chatterjee et al., 2011, 2015; Singha

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and Chatterjee, 2014). These overpressures create huge challenges in drilling the wells. Many

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reasons like disequilibrium compaction, gas expansion are attributed to such abnormal

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pressures in KG basin (Dasgupta et al., 2016). Pore pressures are quite normal in Cauvery

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basin as reported by authors (Advanced Resources International Inc, 2013; Srikant and

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Shanmugam, 2014). Rather mild sub-hydrostatic pressures are also reported in few wells

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which resulted in minor mud loss.

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4.1 The Cauvery basin

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Pore pressure study on the Ramnad sub-basin demonstrate normal pressure regime. D-

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exponent, sigma logs with shale compaction models using resistivity and sonic logs – all infer

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a normal pore pressure gradient in this region (Srikant and Shanmugam, 2014). Normal

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hydrostatic pressure regime is reported in a recent assessment of shale gas and oil resource of

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the Cauvery basin (Advanced Resources International Inc., 2013).

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ACCEPTED MANUSCRIPT The current dataset demonstrate a pore pressure range up to 11 MPa/km. Relatively slow rate

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of sedimentation may be the main reason for the absence of overpressure in this region.

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Sedimentation rate during the rifting period is reported to be about 50 m/m.y. (Ramani et al.,

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2000).

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4.2 The KG Basin

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Overpressures of different magnitudes and nature are observed in different stratigraphic

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levels like Lower Cretaceous, Upper Cretaceous, Paleocene, Eocene and Miocene sequences

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(Rao and Mani, 1993; Kumar et al., 2006). The disequilibrium compaction due to fast rate of

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sedimentation is attributed to the main reason for such overpressure generation (Rao and

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Mani, 1993; Singha et al., 2014). The rate of sedimentation in KG basin is estimated to vary

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between 70 and 125 m/m.y. (Rao and Mani, 1993). Sedimentation rate was maximum during

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Eocene to Miocene time (100 – 125 m/m.y.) due to the upliftment of hinterland for the

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Himalayan orogeny and subsequent erosion.

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The observed pore pressure gradient in the wells based on the current dataset varies from 11

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MPa/km to nearly 18 MPa/km. The top of overpressure zones demonstrate a large variation

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in depth from 2200 to 3000m.

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5. Methodology

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The methodology applied here aims to suggest new empirical relationships for normal

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compaction trends, vertical or overburden stress, Poisson’s ratio, compressional and shear

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wave velocities against bulk density and minimum horizontal stress in the Cauvery and KG

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basins, so that it will be helpful in future exploration activities. An attempt has been made to

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estimate both pore pressure and fracture pressure, and to show the variation of magnitudes of

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overpressure in different stratigraphic formations across these basins. The methodology

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followed is described in detail in this section.

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ACCEPTED MANUSCRIPT 5.1 Estimation of pore pressure

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As discussed previously, under-compaction results in higher pore pressure and more porosity

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than that of normally compacted sediments. The current study attempted porosity model

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(Zhang, 2011) for estimating the pore pressure using the equation:

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Pp = σv – (σv – pn) [(ln ϕ0 – ln ϕ) / (Cn Z)]

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where Pp is the pore pressure at depth z, σv is the overburden stress, pn is normal pressure or

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hydrostatic pressure, ϕ0 is the porosity in the sea floor or ground surface, ϕ is the porosity in

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shale at depth Z and Cn is the normal compaction constant which can be obtained from trend

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line of normal compaction porosity of shale.

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Porosity decreases exponentially with increase in depth under the normal compaction

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condition (Zhang, 2013). The general relationship of normal compaction trend of porosity is

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expressed in the following equation (Athy, 1930; Mondol et al., 2007):

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ϕn = ϕ0 e-Cn Z

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The above relationship (eq. 2) is used for determining the normal compaction curve in the

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current study. The value of compaction constant “Cn” and porosity at the surface “ϕ0” are

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proposed and calibrated as per the current dataset in the basins. ϕn is the porosity under

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normal compaction condition.

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Standard value of 10 MPa/km is considered for the hydrostatic pressure gradient. Thus Pn is

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calculated by multiplying the gradient with vertical depth. σv is estimated using a method

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described by Plumb (1991) (cf. equation 17).

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Volume of shale (Vsh) is calculated from gamma ray log (GR) using the equation:

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Vsh = (GRlog – GRmin) / (GRmax – GRmin)

(2)

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(3)

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ACCEPTED MANUSCRIPT where GRlog is obtained from well log, GRmin and GRmax are the minimum and maximum GR

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in a stratigraphic sequence obtained from the log data. Lithology and cutting sample data are

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also used to calibrate the calculated Vsh. High cut off (≥80%) of Vsh is applied to wells logs to

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extract only the shales to minimize the effect of lithology changes.

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Porosity is calculated from the compressional sonic (DTCO) data acquired in the well using

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the equation:

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ϕ = (DTlog – DTma) / (DTf – DTma)

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where ϕ is the porosity, DTlog is sonic value measured from the well log, DTma and DTf are

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the sonic values of the matrix and fluid respectively. Sonic porosity must be calibrated to

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approximate the density derived shale porosity in normally pressured sediments to compare

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the sonic and density log response to overpressure (Tingay et al., 2009). DTma is obtained

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from the cross plot of DTCO for the normal pressured shale and the corresponding porosity

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obtained from density data.

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10 wells are used to estimate the pore pressure in Cauvery basin in the current study. Porosity

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is calculated from the normal pressured shales in wells W19, 24 and 26. DTma is obtained as

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about 70 µs/ft by the extrapolated sonic transit time against zero porosity of shale (method

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from Hansen, 1996). Standard value of 189 µs/ft for the freshwater mud system was used for

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DTf (Schlumberger, 1989). The normal compaction trend (Fig. 3) is established using this

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shale compaction curve and the relationship is obtained as follows:

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ϕn = 0.9 e-0.0008 Z

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Comparing equation 5 with the normal compaction trend of equation 2, the compaction

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constant Cn is correlated as 0.0008 and the porosity at the surface as 0.9. Equation 1 is used to

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estimate the pore pressure at the nearby wells as demonstrated as an example in Fig. 4 for

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drilled location W-23.

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(5)

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ACCEPTED MANUSCRIPT 16 wells spanning in both onland and shallow offshore with maximum stratigraphic

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penetration are used to estimate the pore pressure in the KG basin. As discussed earlier, wide

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variation of pore pressure is experienced in various parts of the KG basin. Different normal

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compaction trends are, therefore, constructed using nearby wells. Broadly 3 different normal

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compaction trends are proposed based on the current dataset. These exponential normal

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porosity trends are used to analyse the overpressure zones in Lower Cretaceous, Upper

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Cretaceous and Miocene sequences.

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Porosity is calculated from the normal pressured shales in wells W-11, 14, 15 to define the

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normal compaction trend for Lower Cretaceous sequence in eastern part of the KG basin.

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DTma is obtained as 78 µs/ft. Standard value of 189 µs/ft was used for DTf (Dasgupta et al.,

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2016). The normal compaction trend (Fig. 5) is obtained from the sonic porosity against

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depth plot as follows:

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ϕn = 0.8 e-0.0008 Z

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The exponential relation from the best fit line resembles Athy’s (1930) compaction trend as

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described in eq. 2. Therefore, the compaction constant c is estimated as 0.0008 and the

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porosity at the sea bed is obtained as 0.8.

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Equation 1 is used to estimate the pore pressure at the nearby wells as demonstrated as an

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example in Fig. 6 for drilled location W-16.

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Similarly, another normal compaction curve (Fig.7) is obtained considering nearby onland

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wells W-1, 3 and 6 for the Upper Cretaceous sequence. The relationship is established as

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follows:

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ϕn = 0.7 e-0.0009 Z

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ACCEPTED MANUSCRIPT Equation 1 is used to estimate the pore pressure at other nearby onland wells as demonstrated

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in Fig. 8 for drilled location W-6.

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A normal compaction trend (Fig. 9) for Miocene is obtained using wells W-8, 9 and 10 in the

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offshore part of the basin (Fig.1).

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ϕn = 0.9 e-0.0005 Z

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Pore pressure is estimated (Fig. 10) using equation 1 with Cn as 0.0005 and ϕ0 as 0.9 for well

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W-10.

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5.2 Estimation of fracture pressure

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The current study was undertaken to estimate fracture pressures in the Cauvery and KG

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basins. Drilled well data from the basins were used in this purpose.

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The minimum stress method (Zhang, 2011), similar to the methods proposed by Hubbert and

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Willis (1957), Eaton (1969) and Daines (1982) is applied here for estimating the fracture

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gradient.

1−

σv −

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where σmin is the minimum in-situ stress, ϑ is the Poisson’s ratio, σv is the overburden stress

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and ρ is the pore pressure.

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Poisson’s ratio (ϑ) is calculated using the compressional (Vp) and shear (Vs) velocities

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acquired in the individual well using the following equation:

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1 Vp⁄Vs 2 − 1 2 = 10 Vp⁄Vs 2 − 1 301

However, the Poisson’s ratio calculated from Vp and Vs could not be calibrated to core

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derived Poisson’s ratio as core data was not available. Compressional sonic DTCO (Vp) log 13

ACCEPTED MANUSCRIPT was available in 14 wells of the KG basin and 9 wells of the Cauvery Basin in the current

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dataset. However, shear velocity log DTS (Vs) was acquired in 6 wells of the basin and 4

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wells of the Cauvery basin in the dataset of current study.

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Poisson’s ratio data are plotted against vertical depth (m) separately for the two basins and

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relations are analysed (Fig. 11a and 11b). The effect of water column is removed by

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subtracting the water depth from the true vertical depths in case of the deep water wells. The

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relation obtained between the Poisson’s ratio and depth is as follows:

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ϑ = 0.233 * (z) 0.053 for the Cauvery basin

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ϑ = 1.33 * (z)-0.176 for the KG basin

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where z is the true vertical depth in meters below sea level. The coefficient of determination

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R2 for the above two equations are found to be 0.56 and 0.62, respectively.

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Moreover, Vp (m/sec) of all the wells of the Cauvery and KG basins were sampled

315

considering average value in every 5 m interval plotted against the density log RHOB (g/cc)

316

with same sampling interval and the following relationship were obtained (Fig. 12a and 12b):

317

Vp = 412.64 (RHOB) 2.4386 for the Cauvery basin

(13), and

318

Vp = 525.68 (RHOB) 1.993 for the KG basin

(14).

319

The coefficient of determination R2 for the above two equations are obtained as 0.55 and

320

0.58, respectively.

321

Similarly, Vs (m/sec) of all the wells of the Cauvery and KG basins were sampled

322

considering average value in every 5 m interval plotted against the density log RHOB (g/cc)

323

with same sampling interval and the following relationship were obtained (Fig. 13a and 13b):

324

Vs = 110.51 (RHOB)3.0991 for the Cauvery basin

(15), and

325

Vs = 63.646 (RHOB)3.555 for the KG basin

(16).

(11), and (12),

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ACCEPTED MANUSCRIPT The coefficient of determination R2 for the above two equations are obtained as 0.52 and

327

0.66, respectively.

328

Poisson’s ratio is estimated using these above relations also. Minor difference in Poisson’s

329

ratio is observed between the estimation from the depth relation (equations 11 and 12) and

330

the estimation from bulk density (RHOB) relationship (equations 13 to 16). This will be

331

shown later in Table 2.

332

The pore pressures of individual wells were taken from the measured data such as DST and

333

wireline formation test (WFT) like MDT. Estimated pore pressure is used in case where no

334

direct measurement of pore pressure available. Minor overbalanced mud was used in most of

335

the wells. Therefore, mud weight is also considered to be equal to the pore pressure in

336

absence of any direct measurement. Mud weight is commonly used as a proxy for pore

337

pressure because mud weight is commonly kept slightly in excess of pore pressure to prevent

338

an influx of formation fluids into the wellbore while maximizing the rate of penetration

339

(Mouchet and Mitchell, 1989).

340

Vertical stress or overburden stress (σv) is the combined weight of the overlying rock and the

341

fluids at a specific depth. The most reliable estimation of the overburden stress can be done

342

using density log. The vertical stress or overburden stress (σv) at a specific depth is calculated

343

integrating the density log (Plumb et al., 1991):

344

σv =

345

where ρz is the bulk density of the overlying rock column at a given vertical depth z, and g is

346

acceleration due to gravity.

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(17),

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ACCEPTED MANUSCRIPT 347

The following two relations for the overburden gradient are established from the current set

348

of data for both the basins. The data plots are shown in Fig. 14a and 14b for the Cauvery and

349

KG basins, respectively.

350

σv = 0.0052 (z) 1.1948 for the Cauvery basin

351

σv = 0.0093 (z) 1.1216 for the KG basin

352

where σv is the overburden stress in MPa, z is the true vertical depth in meters below sea

353

level. Both the equations have a R2 value of 0.99.

354

6. Results

355

The current dataset of Cauvery basin does not show any development of overpressure zones.

356

The pore pressure gradient is observed to be in the range of 10-11 MPa/km, which suggests

357

the hydrostatic pressure regime. Therefore, only one general normal compaction curve (eq. 5)

358

is proposed for this basin. On the other hand, wide variability in pore pressure, both in terms

359

of magnitude and stratigraphy, are observed in the KG basin. The Lower Cretaceous syn-rift

360

section from the wells of the eastern part of the basin shows the very high pore pressure

361

development. The pore pressure gradient is observed as high as 18 MPa/km. The Upper

362

Cretaceous formations from the onland wells show a mild development of pore pressure with

363

a maximum gradient of 13.4 MPa/km. The Miocene formation from the offshore wells

364

located in the SE corner of the KG basin suggests a moderate overpressure development of

365

14.3 MPa/km. In order to capture this variation, 3 different normal compaction trends (eq. 6,

366

7 and 8) are obtained for Lower Cretaceous, Upper Cretaceous and Miocene sequences in the

367

basin based on 16 well data in this basin.

368

A reasonably good fit is obtained between the estimated and the observed pore pressures in

369

the drilled wells. The current database contains measured pore pressure data of 3 wells in

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ACCEPTED MANUSCRIPT Cauvery and 5 wells in KG basin. The detail data of these 8 wells together are demonstrated

371

in Table 1.

372

Fracture pressures were estimated using equation 9 for each well separately and compared

373

with the observed LOT data recorded in the respective well. The Poisson’s ratio was

374

calculated in two ways. First, Vp and Vs directly taken from the compressional and shear

375

sonic logs were used for calculations in each well using equation 9. The general background

376

trend was established between the Poisson’s ratio and depth for shales (equations 11 and 12).

377

Second, general trends were established between density logs and compressional and shear

378

sonic logs separately for all available wells (equations 13 to 16). Equations 18 and 19 were

379

used for estimating the overburden stress; pore pressure was considered from the observed

380

data of the individual well wherever available. Otherwise, estimated pore pressure was used

381

in case of absence of any direct measurement. LOT pressures obtained from both the

382

processes are found to be quite similar and comparable to the actual LOT obtained from the

383

wells. LOT data is available for 3 out of 10 wells in Cauvery and another 3 out of 16 wells in

384

KG basin. Data of these 6 representative wells from both the basins are summarised in Table-

385

2.

386

Use of the above mentioned general relationships and the pore pressure were used to estimate

387

the fracture pressure which was found to be similar to the actual LOT data of the

388

corresponding wells. The fracture gradient in Cauvery basin is found to be in the range of

389

about 12 – 18 MPa/km between depths of 190 – 3042.3m. The fracture gradient in the KG

390

basin shows a range of about 16 – 20 MPa/km within a depth range of 1685 – 4011m. These

391

ranges suggest, the fracture gradient is around 75% of the overburden gradient or principal

392

vertical stress in the Cauvery basin and ranges from 70% – 88% of the overburden gradient in

393

the KG basin, depending on the magnitude of overpressure. Statistical analysis was carried

394

out to determine the error range between the estimated and the observed LOT pressures. The

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17

ACCEPTED MANUSCRIPT data and the outcome are presented in Table-3. The prior idea of pore pressures and fracture

396

gradients in different stratigraphic sections in the Cauvery and KG basins, will not only help

397

in strategizing the future drilling activities, but also be useful in future exploration studies of

398

modelling the hydrocarbon column height, top seal integrity, fault seal, and migration of

399

hydrocarbon.

400

7. Summary

401

Practical geoscientific approach has been attempted to estimate pore pressure and minimum

402

fracture pressure using drilled wells, separately for the Cauvery and the KG basins in east

403

coast of India. The methodologies applied here, are aimed to establish simple generalised

404

relations between geoscientific data such as depth, normal porosity trend, Poisson’s ratio,

405

compressional and shear sonic velocities, and bulk density, so that the estimations of pore

406

pressure and fracture pressure can be done quickly within a fair range of accuracy. One

407

normal compaction trend in the Cauvery basin and three normal compaction trends in the KG

408

basin are proposed based on the current dataset. Other relations established in this study are

409

compressional and shear sonic velocities against bulk density, Poisson’s ratio against depth

410

and lastly the overburden stress as a function of depth.

411

The error analysis of the estimated values of pore pressures and fracture pressures in this

412

study are within low and narrow ranges. The standard deviation of the errors calculated for

413

the estimation of pore pressures in the Cauvery basin is around 0.47, and in the KG basin is

414

0.98 (Table 1). The standard deviation of the errors of fracture pressures in the Cauvery basin

415

is 0.67 to 1.38, and in the KG basin is 0.99 to 1.01.

416

The KG and Cauvery basins show conspicuous differences between them in terms of the

417

nature and general trends of the petrophysical properties like velocity, the Poisson’s ratio,

418

overburden gradient, and observed pore pressures. These differences may be due to the

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18

ACCEPTED MANUSCRIPT combined effects of differences in patterns of sedimentation, tectonics, generation and/or

420

accumulation of hydrocarbons.

421

Only 26 well data were available for this current study. More drilled well data including

422

conventional core data can be incorporated in future to make the estimation more robust and

423

also to increase the accuracy of the outcome.

424

Acknowledgements

425

Authors are thankful to ONGC and GSPC for providing us the well log data and geologic

426

information. Ministry of Earth Science is acknowledged for funding the project (MoES/P.O.

427

(Seismo)/1(138) 2011 dated 9.11.12) to carry out this work.

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428 429

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596

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basins. Well

W-24

Cauvery

W-23

W-19

W-6

W-15

Predicted pore pressure (MPa) (A)

Measured pore pressure (MPa) (B)

1227.00

12.40

12.52

MW

2062.00

22.06

22.02

MW

1960.80

20.30

20.16

MDT

2272.73

22.90

22.88

MDT

2354.12

23.55

23.64

MDT

1513.27

15.50

16.74

2706.27

29.90

30.21 24.23

W-9

601

-0.04

-0.14

-0.02

0.47

0.09

MW

1.24

MW

0.31

MDT

-0.77

30.35

30.70

MDT

0.35

2711.11

36.23

35.49

MDT

-0.74

3443.60

60.90

59.93

MDT

-0.97

3524.82

63.07

62.19

MDT

-0.88

3681.78

65.07

64.95

MDT

-0.12

2721.70

36.74

36.27

MDT

-0.47

3248.87

47.80

45.99

MDT

-1.81

3394.98

49.70

48.06

MDT

-1.64

4017.59

65.06

65.00

MDT

-0.06

4427.08

77.40

78.47

MDT

1.07

4498.90

78.37

79.43

MDT

1.06

4852.21

78.83

79.95

MDT

1.12

1300.00

12.10

12.80

MW

0.70

2865.00

28.51

29.90

MW

1.39

3000.00

31.74

32.20

MDT

0.46

3800.00

54.77

54.16

MDT

-0.61

1970.00

21.20

22.00

MW

0.80

27

Standard deviation of error

0.12

25.00

AC C

W-10

Error (B-A)

2183.33

EP

KG

Source of pore pressure data

2500.00

TE D

W-16

Depth (m)

RI PT

Basin

SC

600

Table 1. Predicted and measured pore pressures in the drilled wells in Cauvery and KG

M AN U

599

0.98

ACCEPTED MANUSCRIPT

Table 2. Detail information of modelled and actual LOT pressures obtained from few wells of the Cauvery and KG basins.

KG

Vp (m/s)

Vs (m/s)

PR estimated from RHOB-Vp and RHOB-Vs relation

PR estimated from Depth-PR relation

190.0

N.A

N.A

N.A

N.A

0.31

W-25

1227.0

2.35

3314.8

1560.9

0.37

0.34

W-23

1289.6

2.30

3145.4

1460.3

0.36

W-23

2470.7

2.40

3489.4

1666.2

0.35

W-18

1677.0

N.A

N.A

N.A

N.A

W-18

3042.3

2.47

3742.8

1821.4

0.34

W-16

2177.0

2.42

3060

1473.1

0.35

W-16

4011.0

2.63

3612

1980.2

W-6

1763.0

2.35

2886

1327.1

W-6

2002.7

2.38

2960

1388.4

W-6

2324.0

2.56

3423

1799.1

W-10

1685.0

2.03

2156

W-10

2690.0

2.33

2837

Pore pressure gradient (MPa/km)

Process 1: Estimation of FG and FP using PR derived from RHOB-Vp and RHOB-Vs relations Modelled Modelled FG FP (MPa) (MPa/km)

Process 2: Estimation of FG and FP using PR derived from Depth-PR relations Modelled Modelled FG FP (MPa) (MPa/km)

14.1

10.0

N.A

N.A

11.8

2.25

20.1

10.0

15.6

19.16

15.2

18.64

M AN U

W-25

OBG (MPa/km)

RI PT

RHOB (g/cc)

SC

Depth (m)

0.34

20.3

10.0

15.8

20.44

15.3

19.74

0.35

22.9

10.0

17.0

42.10

17.1

42.12

0.35

21.3

10.0

N.A

N.A

16.0

26.78

0.36

23.9

11.0

17.8

54.07

18.1

55.15

0.34

23.7

11.0

17.8

38.75

17.6

38.41

0.29

0.31

25.5

16.0

19.8

79.38

20.2

81.21

0.37

0.36

23.1

10.5

17.8

31.31

17.5

30.82

0.36

0.35

23.4

11.0

18.0

35.98

17.7

35.38

0.31

0.34

23.9

11.0

16.8

38.94

17.6

41.97

788.7

0.42

0.39

18

10.5

16.0

26.95

15.2

25.62

1287.4

0.37

0.34

20.8

11.0

16.8

45.16

16.2

43.53

TE D

Cauvery

Well name

EP

Basin

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W-10 3600.0 2.46 3161 1561.5 0.34 0.32 22.4 14.0 18.3 65.94 18.0 64.95 RHOB = Bulk density; PR= Poisson’s ratio; OBG= Overburden gradient; FG= Fracture gradient; FP = Fracture pressure; OBG calculated considering the correction for the water depth of 550m in W-10.

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Table 3. Estimation of accuracy of the modelled fracture pressure with respect to the measured data obtained from the drilled well.

Modelled FP (MPa) (b)

W-25 W-25 W-23 W-23

N.A 19.16 20.44 42.10

2.25 18.64 19.74 42.12

2.3 18.0 19.1 42.3

W-18 W-18

N.A 54.07

26.78 55.15

25.5 55.7

1.63

-1.28 0.55

W-16 W-16 W-6

38.75 79.38 31.31

38.41 81.21 30.82

38.0 80.2 30.0

-0.75 0.82 -1.31

-0.41 -1.01 -0.82

W-6 W-6 W-10 W-10 W-10

35.98 38.94 26.95 45.16 65.94

35.8 40.5 25.8 45.5 66.0

-0.18 1.56 -1.15 0.34 0.06

35.38 40.97 25.62 43.53 64.95

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Process 1

RI PT

SC

M AN U

Well name

TE D

KG

Modelled FP (MPa) (a)

Actual LOT pressure from well data (MPa) (c)

EP

Cauvery

Process-2: PR estimated from Depth-PR relation

AC C

Basin

Process-1: PR estimated from RHOB-Sonic relations

Observed error (c-a)

-1.16 -1.34 0.20

Standard deviation of error

1.38

0.99

Process 2 Observed error (c-b) 0.05 -0.64 -0.64 0.18

0.42 -0.47 0.18 1.97 1.05

Standard deviation of error

0.67

1.01

ACCEPTED MANUSCRIPT Figure Captions Fig. 1. Location map of the Cauvery basin showing regional trend of major tectonic features along with the locations of the drilled wells used for analysis. Inset: Location in the outline map of India. (modified after GCA, 2008; DGH, 2009)

RI PT

Fig. 2. Location map of the KG basin showing regional trend of major tectonic features along with the locations of the drilled wells used for analysis. Inset: Location in the outline map of India. (modified after Murthy et al., 2011; Kamaraju et al., 2008)

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Fig. 3. Normal compaction curve using wells W-19, 24 and 26. Fig. 4. Estimated pore pressure at W-23

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Fig. 5. Normal compaction curve using wells W-11, 14, and 15. Fig. 6. Estimated pore pressure at W-16.

Fig. 7. Normal compaction curve using wells W-1, 3, 6. Fig. 8. Estimated pore pressure at W-6.

TE D

Fig. 9. Normal compaction curve using wells W-8, 9 and 10. Fig. 10. Estimated pore pressure at W-10.

Fig. 11a. Poisson’s ratio vs. depth plot for the Cauvery Basin

EP

Fig. 11b. Poisson’s ratio vs. depth plot for the KG basin

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Fig. 12a. Bulk density (RHOB) vs. compressional sonic velocity (Vp) for the Cauvery basin Fig. 12b. Bulk density (RHOB) vs. compressional sonic velocity (Vp) for the KG basin Fig. 13a. Bulk density (RHOB) vs. shear sonic velocity (Vs) for the Cauvery basin Fig. 13b. Bulk density (RHOB) vs. shear sonic velocity (Vs) for the KG basin Fig. 14a. Overburden stress vs. depth plot for the Cauvery basin Fig. 14b. Overburden stress vs. depth plot for the KG basin

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ACCEPTED MANUSCRIPT Research Highlights

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M AN U

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Nature and variabilities of pore pressure in the east coast of India is analysed. The pore pressure in Cauvery basin is shown to be almost hydrostatic in nature. High sedimentation rate in KG basin is the main reason for overpressure development.

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