Petrophysical and mechanical properties of cretaceous ... · Petrophysical and mechanical properties of cretaceous ... studied for their mechanical and petrophysical properties. ...

Petrophysical and mechanical properties of cretaceous sedimentary rocks of Cauvery basin, Eastern Continental

Margin of IndiaRima Chatterjee1, K. Manoharan2, and Manoj Mukhopadhyay3

1Department of Applied Geophysics, Indian School of Mines, Dhanbad-826 004, India2Great Eastern Energy Corporation Limited, Mannargudi CBM Project, Thanjavur, Tamil Nadu

3Department of Geology & Geophysics, King Saud University, P.O. Box 2455, Riyadh 11451, Kingdom of Saudi Arabia1E-mail: [email protected]

ABSTRACTThe Cauvery Basin (CB) is one of the largest petroliferous basins developed at the Eastern Continental Margin of India (ECMI) where the sediments thicken to as much as 8,000 m. Hydrocarbon bearing formations in the basin belong to Cretaceous age. Both microscopic and macroscopic heterogeneities for the cored rocks corresponding to depths of 2169–2669 m are studied for their mechanical and petrophysical properties. The petrophysical and mechanical properties of the samples tested have been correlated with a fair degree of fit. Further, it is observed that the Vp/Vs, the ratio of compressional wave velocity (Vp) to shear wave velocity (Vs) has been found to decrease with the increase of effective porosity of the core samples. The best fit regression may be used for estimation of porosity from the Vp/Vs values as well as from the density values for the Cretaceous sediments of Cauvery basin.

INTRODUCTION

The Cauvery Basin (CB) is located both onshore and offshore under the Eastern Continental Margin of India (ECMI); together they constitute conjugal parts of a pericratonic rift basin; it covers an area of 25000 sq km on-land and shallow offshore of 30,000 sq km. In addition, there is about 95,000 sq km of deep-water offshore areas. The basin contains sediments ranging in age from Jurassic to the Recent and the aggregate sediment thickness is about 8000 m. Here the reservoir rocks are the Early Cretaceous to Oligocene sandstones; the source rocks are the Early to Late Cretaceous shale, while, the cap rocks being the intra-formational shale (Chaudhuri et al., 2009). The CB is an active site for hydrocarbon exploration and drilling, with identified fields or resultant discoveries where hydrocarbons are mostly confined to the Cretaceous formations (Figure 1). Developed by extensional block faulting, an alignment of NE-SW elongated horsts and sub-basins are dominating the basin namely; Ariyalur-Pondicherry sub-basin, Kumbakonam-Madanam horst, Tanjore-Tranquebar sub-basin, Karaikal horst, Nagapattinam sub-basin, Patmkottai-Mannargudi horst, Ramnad-Palk Bay

sub-basin, Mandapam Delft horst and Mannar sub-basin. The Vedaranniyam 'high' is located to the east of the Nagapattinam sub-basin and is aligned in N-S direction (Sastri et al., 1973).

Most promising prospects in the Offshore CB are the PY-3 Field and CY-OS/2 (Hardy, 2008; and New Exploration Licensing Policy, 2007). Wells namely; D, E, F are located at the flank of Tranquebar sub-basin whereas the other three wells such as: A, B and C are located in the Ramnad- Palk Bay sub-basin. The hydrocarbon bearing formations in the CB are the Andimadam and Bhuvanagiri (Figure 2). The core samples from these well were dominantly sandstone and siltstone. The sandstone samples varied in grain size from course to fine with poor to moderately sorted. The main minerals identified were quartz, feldspar, muscovite, biotite, pyrite chlorite, glauconite and garnet with ferruginous cement (Table 1).

Petrophysics remains a vital component to many facets of the petroleum industry, from quantification of hydrocarbon reserves, developmental strategies to real-time decision making for reservoir navigation etc. Diversity of petrophysical information is important when considering rock failures, drilling of wells and problems dealing with borehole stability, hydraulic

J. Ind. Geophys. Union ( October 2013 )v.17,no.4,pp:349-359

Rima Chatterjee, K. Manoharan, and Manoj Mukhopadhyay

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fracturing, production etc., (Tiab and Donaldson, 2004; Boyle et al., 2000; and Worthington, 1991). In hydraulic fracturing this study involves innovative application such as drill cutting injection, acid fracturing, and thermal induced fracturing related to

water injection (Charlez, 1977). Petrophysical properties of reservoir rocks

are best understood by studying the degree of variation in heterogeneity that usually extends over a rather broad spectrum, such as; microscopic,

Figure 1. Showing locations of Wells A through F within the Cauvery Basin from which core samples belonging to Cretaceous age were collected. Details of core recovery depths are provided in Table 1. The wells A through C are located at the southern part of Ramnad sub-basin whereas the wells D through F are located at the northern part Tranquebar sub-basin (after Hardy, 2008, DGH, 2009-10 and NELP, 2007).

Petrophysical and mechanical properties of cretaceous sedimentary rocks of Cauvery basin, Eastern Continental Margin of India

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macroscopic, mesoscopic, megascopic and gigascopic heterogeneities (Tiab and Donaldson, 2004). Of these; the microscopic scale of heterogeneity is represented in the scale volume at which the properties of rocks such as porosity (Φ) and permeability (k) are governed by: (i) grain size and shape; (ii) pore size and shape; (iii) grain, pore size and pore throat distribution; (iv) packing arrangements; (v) pore wall roughness and (vi) clay lining of pore throats etc., whereas, studies on macroscopic heterogeneity are done by laboratory measurement of Φ and k, fluid saturation, capillary pressure etc. on the cored rocks. Here we present some basic results on petrophysical properties to investigate both microscopic and macroscopic heterogeneities for nearly 500 m vertical section of the Cretaceous reservoir rocks at depths exceeding 2 km from two deeper sub-basins in CB that are separated by more than 220 km distance. Two other important elastic properties that relate stress and strain for reservoir rocks’ namely, uniaxial compressive strength (UCS) and Poisson’s ratio (σ)

are also estimated based on laboratory measuremens for the Cretaceous sediments in CB.

Petrographic and petrophysical studies on cored rocks

The cored samples from the wells A through C are collected from the Ramnad sub-basin while the wells D through F are from the Kutalam field at the flank of Tranquebar sub-basin in CB (Figure 1) (Hardy, 2008; and Roy Moulik and Prasad, 2007); the samples belong to the Andimadam and Bhuvanagiri formations (Govindan et al., 1996; and Watkinson, 2007). The sample recovery depths are given in Table 1.

Petrographic Description of Cored Rocks

Eleven thin sections were made from the rock cores that were obtained from the drill holes in CB. The properties examined for each core collected from the

Figure 1. Showing Cretaceous lithostratigraphic framework integrated with subsurface litho units, paleo-bathymetric curves and geochemical parameter (after Govindan et al., 1996).


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wells in respect of the core recovery depths in CB are summarized in Table 1.

Determination of Dry density, Porosity and Permeability

Dry density (ρ) is the ratio of grain mass (Ms) in gm to the bulk volume (V) of the sample in cm3. It was determined according to International Society of Rock Mechanics (ISRM, 1977a) specification on the prepared cored samples (Franklin, 1979). The porosity (Φ) provides a measure of apparent pore volume and is determined as the excess of bulk

volume over the grain volume and occluded pore volume. Φ was determined by adopting saturation and caliper technique as specified by Franklin, 1979. Laboratory measurement provides the total porosity of core sample.

The porosity (Φ) was obtained by weighing the saturated (Msat) and dry (Mdry) samples,

Φ = (Msat – Mdry)/ (V ρw), where ρw is water density

Permeability characterizes the ability of reservoir rocks to allow the circulation of fluids contained in the pores (Monicard, 1980). Permeability to air is determined by employing the Ruska Gas

Table – 1. Detail information of cores drilled in Cretaceous rock from the wells in the Cauvery basin together with petrographic analysis results.

WN SNCore Recovery

Depth (m)Rock type

FormationMineralogical Character

CementationMGS(mm)

Degree of sorting

RoundnessFrame work Matrix

A M1 2206.0-2215.0 F.Gr.Sst. BhuvanagiriQtz., Fels., Mus.,

Bio., Py., RfQtz., Fels.,

Mic.Ferruginous 0.125 Poor.Sort. Angular

A M2 2505.0-2509.0 M.Gr.Sst. BhuvanagiriQtz., Fels., Mus.,

Bio., RfQtz., Fels.,

Bio.Ferruginous 0.250 Poor.Sort. Angular

B M3 2169.0-2178.0 C.Gr.Sst. BhuvanagiriQtz., Fels., Mus.,

Bio., Py., RfQtz., Fels.,

RfFerruginous 0.550 Mod.Sort. Sub-angular

B M11 2340.0-2342.3 F.Gr.Sst. BhuvanagiriQtz., Fels., Mus.,Py., Sh. matter, Rf

Qtz., Fels., Grt.

Ferruginous 0.200 Mod.Sort. Sub-angular

C M4 2384.0-2390.5 C.Gr.Sst. BhuvanagiriQtz., Fels., Chl.,Py., Grt., Bio., Rf

Qtz., Fels., Mus.

Ferruginous 0.625 Poor.Sort. Sub-angular

D M5 2240.0-2243.5 F.G.Sst. BhuvanagiriQtz., Fels., Chl.,

Bio., Grt.Qtz., Fels.,

Bio.Ferruginous 0.130 Poor.Sort. Angular

D M6 2342.0-2351.0 M.Gr.Sst. AndimadamQtz., Fels. Mus.,

Bio., RfQtz., Fels. Ferruginous 0.260 Poor.Sort. Sub-rounded

D M7 2661.0-2669.0 M.Siltst. AndimadamQtz., Fels., Mus.,

Chl., RfClay, Qtz.,

Mic.Ferruginous 0.025 Poor.Sort. Sub-angular

E M8 2437.0-2446.0 C.Gr.Sst. AndimadamQtz., Fels., Bio.,

Grt., RfQtz., Fels.,

Bio., RfFerruginous 0.600 Poor.Sort. Sub-rounded

F M9 2334.0-2338.0F.Gr.Slt.

Sst.Bhuvanagiri

Qtz., Fels., Bio., Rf

Qtz., Fels., Bio.

Ferruginous 0.015 Mod.Sort. Sub-angular

F M10 2371.0-2379.0 M.Gr.Sst. AndimadamQtz., Fels, Mus.,Bio., Grt., Glauc.

Qtz., Fels., Mic.

Ferruginous 0.260 Mod.Sort. Sub-rounded

WN = Well Name; SN = Sample Number; MGS = Mean Grain Size; F. = Fine; M. = Medium; C. = Coarse; Gr. = Grained; Sst. = Sandstone; Qtz. = Quartz; Fels. = Feldspar; Mus. = Muscovite; Bio. = Biotite; Grt. = Garnet; Py. = Pyrite; Glauc. = Glauconite; Chl. = Chlorite; Sh. = Shale; Siltst. = Siltstone; Slt. = Silty; Mic. = Mica; Rf = Rock fragments; Poor. = Poorly; Mod. = Moderately; Sort. = Sorted


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Permeameter (Ruska Instruments Corporation, Houston); this involves in the passage of air through the inlet. Flow of air depends on the pressure and k. The values of ρ, Φ and permeability of the core samples in correspondence to their recovery depths are given in Table 2. Figure 3a indicates the best fit linear relationship between porosity and dry density

of the core samples with excellent goodness of fit (R2 = 0.94). With the increase of density, porosity decreases. The plot between porosity and permeability is displayed in Figure 3b. The best fit regression equation with satisfactory goodness of fit (R2 = 0.59) shows exponential relation between porosity and permeability of core samples.

Table – 1. Reservoir petrophysical properties of cores drilled in Cretaceous rock in the Cauvery basin.

WN SNCore Recovery

Depth (m)ρ (g/cc)

Φ (%)Perm. (md)

Vp (Km/s)

Vs (Km/s)

σUCS

(MPa)E (GPa)

A M1 2206.0-2215.0 2.21 11.80 0.90 2.43 1.56 0.148 49.90 6.0

A M2 2505.0-2509.0 2.49 - - 3.40 2.16 0.159 66.50 8.0

B M3 2169.0-2178.0 1.94 18.50 66.00 1.05 0.68 0.143 4.44 2.2

B M11 2340.0-2342.3 2.33 8.90 - 2.79 1.79 0.149 45.20 4.1

C M4 2384.0-2390.5 2.17 13.60 23.00 2.36 1.53 0.140 23.60 2.7

D M5 2240.0-2243.5 2.03 - - 2.41 1.54 0.158 29.26 2.8

D M6 2342.0-2351.0 2.22 - - 1.79 1.15 0.151 30.03 4.5

D M7 2661.0-2669.0 2.83 3.10 - 2.66 1.65 0.186 69.20 5.4

E M8 2437.0-2446.0 2.14 14.20 5.40 2.02 1.29 0.153 22.56 2.8

F M9 2334.0-2338.0 2.26 11.60 - 2.81 1.82 0.137 70.70 6.5

F M10 2371.0-2379.0 2.22 10.20 - 2.00 1.30 0.134 29.75 3.4

WN = Well Name; SN = Sample Number; ρ = Density; Φ = Porosity; Perm. = Permeability; Vp = Sonic velocity for P-wave; Vs = Sonic velocity for S-wave; σ = Poisson’s ratio; UCS = Uniaxial Compressive Strength; E = Young’s modulus

Figure 3. Showing relationship between (a) porosity and dry density, and (b) porosity and permeability..


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Determination of Elastic Wave Velocity and Poisson’s ratio

Measurements of Vp and Vs on the core specimens were performed using Sonic Viewer-170 (model-5228), following ISRM specification (ISRM, 1977b, Rummel and Van Heerden, 1978). An ultrasonic digital indicator consist a pulse generator unit, transmitter and receiver transducers are used for sonic pulse velocity measurement. The transmitter and the receiver are positioned at the ends of cylindrical specimen and the pulse wave travel time is measured. The velocity is calculated from dividing the length of rock sample by wave travel time. The measured Vp and Vs data further used to calculate Poisson’s ratio (σ); the relevant values for the cores are also listed in Table 2.

σ = 0.5 [{(Vp/Vs)2 – 2}/{(Vp/Vs)2 - 1}]

The plot of Figure 4a and 4b illustrates the variation of Vp and Vs with dry density of core samples tested. The linear regression analysis yielded a satisfactory relation (R2 = 0.67). Figure 5 indicates the variation of Vp/Vs with the porosity of core samples. The best fit power relation between Vp/Vs and porosity indicates good R2 (0.72) value. The ratio of Vp to Vs decreases with the increase of porosity of the core samples. The best fit regression can be used for estimation of porosity from the ratio of Vp and Vs values as well as density values for

similar type of rocks in the Cretaceous sediments of Cauvery basin.

Measurement of Mechanical Properties

The conventional core samples of 4 inch diameter were obtained from the Oil and Natural Gas Corporation Ltd., Cauvery Basin. Test samples were made as right circular cylinder having a length to diameter ratio of 2.5 for conducting UCS, E, and VP

and Vs determinations. The ends of the specimen were flattened and made parallel to each other that were perpendicular to the axis of the specimen. The specimens were smooth and free of any abrupt irregularities and straight over the full length of the specimen; the regular shaped cylindrical samples were prepared.

The method of test intended to determine stress-strain curves, Young’s modulus (E) and Poisson’s ratio (σ) in uniaxial compression of a rock specimen of regular geometry The test is mainly intended for classification and characterization of intact rock. During the test, the pressure on the core sample is applied continuously to produce an approximately constant rate of load (0.5 MPa/sec) or deformation such that failure occurs within 5 to 15 minutes of initiation of loading. The load is imposed and the axial as well as diametric or circumferential strains are measured frequently at evenly spaced load intervals during the testing of 11 core samples for Young’s modulus measurements and the axial

Figure 4. Showing relationship between (a) dry density and P-wave velocity (Vp), and (b) dry density and S-wave velocity (Vs).


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stress-strain curves are also determined for 11 core samples. So, the Young’s modulus (E) is calculated from the following equation,

E = Incremental Stress / Incremental Strain

Young’s modulus (in GPa) was determined according to American Society for Testing Materials, (American Society for Testing Materials, 1998a) by secant modulus method which is usually measured from zero stress to some fixed percentage of the ultimate strength, generally at 50%. Table 2 lists the experimental results of Young’s modulus (E) for the core samples. UCS of a core sample having length to diameter ratio of 2.5 was determined according to American society for testing and materials method (American Society for Testing Materials, 1998b). Material Testing System (MTS) machine of 100 tonnes capacity was used for applying and measuring axial load to the specimens. All the tests were conducted in an MTS, servo-controlled hydraulic testing frame. Constant displacement rate was controlled when conducting the tests. The specimens were loaded in compression to failure within 5-10 minutes. Load was measured using a load cell. Displacement was measured using an linear variable differential transformer in the MTS. Application of compressive stress at constant rate when specimen is placed between the discs leads to breaking of the samples. The breaking load is directly displayed and obtained digitally on the MTS monitor. Load versus

yield characteristics of the core samples reveal that the UCS values vary over a rather wide range: from 4.44 to 70.7 MPa (Table 2). This variation is best represented by grouping them into Low and High UCS zones in Figure 6. The variation of UCS with density in Figure 7a indicates a poor correlation (R2 = 0.33) value between density and UCS (Figure 7a). In this scattered plot, the low strength rocks are regarded to have values of < 25 MPa. Based on such characteristics, it is possible to demarcate the low and high UCS zones having variable yield characteristics as detailed below.

UCS bears a linear relationship with ρ (Figure 7a) where the density increases with the strength of the rocks. The scatter plot (Figure 7b) between E and UCS also indicates low and high strength UCS zones. Depending on the low and high strength UCS zones, two plots are made to show the variation of E with UCS values of weak rocks (Figure 7c) and relatively strong rocks (Figure 7d). The Young’s modulus value ranges from 2.8 to 22 GPa. Figures 7c and 7d show good to very good correlation between E and UCS (R2 values varying from 0.74 to 0.82). The best fit linear equation expresses the increase of E with the increase of UCS values. It may be noted that variation of E values are more in weak rocks compared to the relatively strong rocks. An inverse linear relationship is seen between UCS with Φ (Figure 7e). The linear relation also holds good for UCS with Vp and Vs (Figures 7f and 7g). Relation between UCS and σ illustrates an interdependent positive trend with poor

Figure 5. Showing relationship between Vp/Vs and porosity.


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R2 value; where, an increase in the values of UCS reflects an increase in σ (Figure 7h). Several workers have reported the similar types of relation of UCS with the elastic modulus and porosity (Smordinov et al., 1970; Chatterjee and Mukhopadhyay, 2002 and Chang et al., 2006).

Values of σ and E for the cored samples range respectively from 0.134 - 0.186 and 2.7 - 9.2 GPa (Table 2). Vp and Vs values determined for the cored samples vary rather widely between 1.05 to 3.40 km/s and 0.68 to 2.16 km/s (Table 2). Both Vp and Vs values for the Cretaceous sediments maintain a positive linear trend with ρ (Figure 4), but, as expected, the trend reverses for Φ (Figure 5).

The porosity (Φ) values of the Cretaceous sediments in CB range from 3.1 to 18.5% and that of permeability ranges between 0.9 to 66 md (Table 2). Φ values for the Cretaceous sediments in CB as determined in our earlier work illustrate a variation from 4 to 25% (Chatterjee and Mukhopadhyay, 2001 and Chatterjee and Mukhopadhyay, 2002). It can be seen from Table 2 that the values of permeability (k) demonstrate a rather large variation for the basinal sediments. Usually, the sediments are categorized according to the values of k: k<1, poor; 1<k<10, fair; 10<k<50, moderate; 50<k<250, good (Tiab and Donaldson, 2004). Effective porosity has a satisfactory positive exponential relationship with permeability (Figure 3) which shows that all those sediments having higher porosity have higher permeability. However, this relationship does not hold

good for sample no. M1, though it has an porosity of 11.6%, having an abnormally low permeability (of less than 0.9 md).

Estimation of Flow Zone Indicator

Flow Zone Indicator (FZI) has been obtained from the combined use of the porosity and permeability measurement of core samples for these six wells under the CB. Flow Zone Indicator is a unique and useful value to quantify the flow character of a reservoir and one that offers a relationship between petrophysical properties at small-scale, such as core plugs, and large-scale, such as well bore level. In addition, the term of FZI provides the representation of the flow zones based on the surface area and tortuosity. It is mathematically represented as (Al-Dhafeeri and Nasr-El-Din, 2007).

FZI = {(0.0314(k/Φe)0.5} / {Φe / (1- Φe)} … (1) where Φe is the effective porosity.

The ratio of pore volume to grain volume can be written as Φz = Φe/(1- Φe) … (2)

Reservoir quality index (RQI)=0.0314 (k/Φe)0.5… (3)

FZI = RQI/( Φz) … (4)

The values for Φz, RQI and FZI in µm, are

Figure 6. Showing relationship between the load (in tonnes) and displacement (in mm) as obtained from present study. M1 through M11 are indicating sample numbers.


357

Figure 7. Plots showing relationships between experimentally determined values of (a) Uniaxial compressive strength and dry density, (b) uniaxial compressive strength and Young’s modulus of total high and low strength core samples, (c) uniaxial compressive strength and Young’s modulus of weak core samples, (d) uniaxial compressive strength and Young’s modulus of relatively strong core samples,(e) uniaxial compressive strength and porosity, (f) uniaxial compressive strength and Vp, (g) uniaxial compressive strength and Vs, and (h) uniaxial compressive strength and Poisson’s ratio. Poisson’s ratio is obtained from Vp/Vs values.


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computed on the basis of Table 2 data are enlisted in Table 3. Due to lack of Φe from well log data, we have used the laboratory measured porosity values in equations 2,3 4 for computation of Φz, RQI and FZI. The FZI value ranges from 0.648 µm to 2.613 µm. The FZI values are less because all the core samples belong to non reservoir section.

CONCLUSIONS

A combined analysis of petrographic, petrophysical and mechanical properties of the Cretaceous rocks cored from six wells in the CB are presented and discussed in the present study for reservoir petrophysical characterization. Petrophysical properties studied are: dry density (ρ), porosity (Φ), permeability (k), elastic wave velocities (Vp and Vs), uniaxial compressive strength (UCS), Young’s modulus (E) and Poisson’s ratio (σ). These results and the results given by us in our previous work would help in establishing the basic relationships between the various laboratory-determined properties for the reservoir rocks at depths between 2169–2669 m. Such petrophysical characterization may be useful in hydrocarbon exploration activities like: 3D- reservoir modeling, strategic planning for a drilling program etc. which depends upon selection of parameters used in drilling based on their petrophysical properties. Finally, it is

observed that accuracy in the estimation of any one petrophysical property using the interrelationships will always require large data volume. It could only be obtained by performing such experiments with larger number of core samples.

ACKNOWLEDGEMENTS

Laboratory work of this study was carried out at Indian School of Mines, Dhanbad (India), where, the first and last authors are affiliated to the Department of Applied Geophysics. The authors are thankful to the Oil and Natural Gas Corporation Ltd. (India) for providing the core samples.

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Table – 3. Reservoir Quality Index (RQI) and Flow Zone Indicator (FZI) in Cretaceous sediments of the Cauvery Basin

WN SNCore Recovery

Depth (m)Ratio of pore volume to

grain volumeReservoir Quality

IndexFlow Zone

Indicator (µm)

A M1 2206.0-2215.0 0.133 0.086 0.648

A M2 2505.0-2509.0 - - -

B M3 2169.0-2178.0 0.227 0.593 2.613

B M11 2340.0-2342.3 0.097 -

C M4 2384.0-2390.5 0.149 0.408 2.594

D M5 2240.0-2243.5 - - -

D M6 2342.0-2351.0 - - -

D M7 2661.0-2669.0 0.003 - -

E M8 2437.0-2446.0 0.165 0.193 1.169

F M9 2334.0-2338.0 0.131 - -

F M10 2371.0-2379.0 0.113 - -


359

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Manuscript received: March, 2013, accepted: April, 2013

Petrophysical and mechanical properties of cretaceous ... · Petrophysical and mechanical properties of cretaceous ... studied for their mechanical and petrophysical properties. ...

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