8/12/2019 IPTC-17235-MS (1)

1/12

IPTC 17235

Shale-Fluid Interactions and Drilling Fluid DesignsWenwu He, Sandra L. Gomez, Russell S. Leonard, and David T. Li, M-I SWACO, a Schlumberger company

Copyright 2014, International Petroleum Technology Conference

This paper was prepared for presentation at the International Petroleum Technology Conference held in Doha, Qatar, 2022 January 2014.

This paper was selected for presentation by an IPTC Programme Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, aspresented, have not been reviewed by the International Petroleum Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarilyreflect any position of the International Petroleum Technology Conference, its officers, or members. Papers presented at IPTC are subject to publication review by Sponsor SocietyCommittees of IPTC. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the International Petroleum TechnologyConference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuousacknowledgment of where and by whom the paper was presented. Write Librarian, IPTC, P.O. Box 833836, Richardson, TX 75083 -3836, U.S.A., fax +1-972-952-9435

AbstractDrilling of shale has long been a challenge due to the strong sensitivity of shale to drilling fluids. Improper selection of

drilling fluid may cause strong shale-fluid interaction and, consequently, wellbore instability. It is critical to design drilling

fluids so as to minimize the shale-fluid interaction.

Shale can possess different behaviors when in contact with fluid (e.g., fracturing, swelling, and dispersion). The

differences in shale-fluid interaction are mainly related to its clay minerals, structure, bedding and thin laminae, and pre-

existing fractures. The rate and strength of interaction vary for different shales. While strong fracturing or dispersion could

happen in just a few minutes for some shales, other shales exhibit only very weak fracturing after days in contact with the

same fluid. Confining pressure can significantly reduce the propagation of fractures, but pre-existing fractures can be

enlarged or extended due to fluid invasion.

Due to the variations of shale and the resulting differences in shale-fluid interactions, the shale behavior of fluid in one

area or formation cannot always be extrapolated to another area or formation. For a specific shale formation, the

understanding of diagenesis, bedding and thin laminae, pre-existing fractures, and abundance and distribution of reactive

clays such as smectite, helps predict the potential shale instability. For example, if shale with high smectite content has not

experienced substantial compaction and thermal alteration, it may show a strong tendency for dispersion. Alternatively, if

high-smectite shale has experienced strong compaction and thermal alteration and shows laminated structures, fracturingalong bedding planes or laminae could be the dominant deformation mechanism in fluids. Our laboratory tests indicate that

even for highly reactive shale, proper inhibition can be achieved if the composition and concentration of chemical additives

in drilling fluids are selected appropriately.

IntroductionDrilling of shale has long been a challenge due to its strong potential for wellbore instability, which is mainly caused by the

imbalance of in-situ stresses and/or interactions between drilling fluid and shale (Lai 1999; van Oort 2003). The mechanical

failure of shale related to stress status can be minimized or prevented by the adjustment of mud weight and changing the

drilling trajectory. Nevertheless, chemical interactions have to be minimized through the selection of proper drilling fluid

chemistry.

Wellbore stability is not an issue for most shale formations with oil-based and synthetic-based drilling fluid, or

mud. However, high costs and environmental restrictions have largely limited the use of oil-based drilling fluid. For water-

based drilling fluid (WBM), the chemical interaction between rock and fluids due to both water and ionic species fluxes fromand into the rock could cause wellbore instability. Therefore, design of WBMs with appropriate chemical additives is critical

to the success of drilling practices both economically and environmentally (Simpson et al. 1995; Ewy and Morton 2008;

Gomez and He 2006, 2012).

This paper will focus on the chemical interactions between shale and water-based drilling fluids. The paper will first

explore the behavior of shale in fluids and investigate the relationship between the interaction behavior and rock properties.

Then laboratory test results are presented that indicate shale-fluid interactions are strongly dependent on fluid chemistry.

Even for highly reactive shale, appropriate composition and concentration of chemical additives can effectively reduce its

interaction with fluids.

Behaviors of Shale in Fluids and Relationship with Rock PropertiesShale is a fine-grained, siliciclastic sedimentary rock. Although shale has many common properties, each shale formation has

specific features in mineral composition, rock structures, and deformation properties. When shale is exposed to fluids, it

8/12/2019 IPTC-17235-MS (1)

2/12

2 IPTC 17235

exhibits different behaviors, which include fracturing, swelling, dispersion, etc. The difference in shale-fluid interaction is

strongly related to its clay minerals, structure, bedding and thin laminae, and pre-existing fractures.

Dispersion. Dispersion is the act of breaking up large particles into smaller ones. It produces wellbore instability and

enlarges the well. Most dispersive shales are relatively soft; this may indicate the shales have not experienced substantial

compaction and thermal alteration during burial. Table 1 shows the X-ray diffraction (XRD) mineral compositions of three

rocks with strong dispersion. These rocks start to disperse immediately after exposure to fresh water. The common feature

with these dispersive shales is their high smectite content (19 23%). Quartz, illite, and calcite vary widely. Chlorite contentis negligible or low. Fig. 1 shows the Malaysia shale behavior in fresh water. The shale displayed substantial dispersion after

5 minutes of exposure to fresh water. The most dramatic dispersion for this shale occurred during the first hour of water

exposure.

Table 1. XRD Results of Mexico, Norway, and Malaysia shalesMexico Norway Malaysia

Smectite (%) 23 22 19

Illite (%) 8 31 13

Calcite (%) 33 4 -

Quartz (%) 29 15 55

Feldspars (%) 4 12 9

Kaolinite (%) 3 14 2

Chlorite (%) - - 2

Hematite (%) - 2 -

Fig. 1Dispersion of Malaysia shale after exposure to fresh water at ambient conditions.

Fracturing or Breaking Along Laminae. Laminated beddings (laminae) that display internal laminations (fissility) parallel

to bedding planes are important structures in shale (Figure 2). The individual laminae may range from a few grains in

diameter to as much as a few millimeters in thickness. Although the lamination of the shale is mostly ascribed to sedimentary

processes, compaction and diagenesis may have enhanced the lamination structures.

5 minInitial

1 hr 24 hr

8/12/2019 IPTC-17235-MS (1)

3/12

IPTC 17235 3

Fig. 2Thin-section photomicrography showing laminated structure of shale.

When shale has both a high content of smectite and strong laminated structures, dispersion may not become the dominant

mechanism of the shale-fluid interactions. Instead, the swelling of smectite could result in fracture propagation along laminae

planes or bedding planes. Fig. 3 shows the Barbados shale and its behavior in 10.8-lb/gal CaCl2brine. This shale contains

34% of smectite (Table 2), but strong lamination and a high amount of chlorite (7%), both of which were probably related tocompaction and thermal alteration. Significant breaking occurred along the laminae after the shale was exposed to the CaCl2

brine. Major interactions were exhibited at the first 2 hours of fluid exposure with no evident changes observed after that. The

New Mexico shale has similar rock composition to the Barbados and exhibits the similar strong tendency to break along the

laminae (Fig.4). Tests also indicated that its dispersion was weak. Even in fresh water, the recovery of the shale was ~95%.

Fig. 3 - Barbados shale after exposure to 10.8-lb/gal CaCl2brine for 24 hours at ambient conditions.

Initial 10 min

2 hr 24 hr

8/12/2019 IPTC-17235-MS (1)

4/12

4 IPTC 17235

Table 2. XRD results of Barbados and New Mexico ShalesBarbados New Mexico

Smectite (%) 34 25

Illite (%) 13 20

Quartz (%) 35 31

Feldspar (%) 2 1

Calcite (%) 1 -

Siderite (%) 2 1Pyrite (%) 1 2

Chlorite (%) 7 10

Kaolinite (%) 5 10

Fig. 4New Mexico shale showing strong breaking along bedding planes and laminae.

Table 3 shows the XRD analytical results of the Bahrain shale formation. These results reveal that smectite and the total

clay content are high. The ~36% illite content may suggest a strong thermal alteration during burial. Thin section observation

indicates that the shale shows strong lamination while calcite acts as cementation. Tests indicate that this shale shows only

slight dispersion while fracturing along bedding planes and laminae appears to be the dominant deformation mechanism in

fresh water (Fig. 5).

Table 3. XRD results of Bahrain ShalesDepth (ft) ~2193 ~2194 ~2194.1

Smectite (%) 25 21 29

Illite (%) 36 6 21

Calcite (%) 3 48 3

Quartz (%) 19 16 27

Kaolinite (%) 16 8 19

Pyrite (%) 1 1 1

CEC (meq/100 g) 20 17 23

Fig. 5 - Bahrain shale after exposure to fresh water for 24 hours at ambient conditions.

Initial 24 hr

8/12/2019 IPTC-17235-MS (1)

5/12

IPTC 17235 5

Fracturing in Low-Smectite Shales. Shales with little expandable smectite may reflect thermal alteration during burial

diagenesis (Boggs 2003). In these low-smectite shales, illite is relatively high and significant amount of pyrite and/or chlorite

may be observed. Carbonate minerals (calcite or dolomite) vary. Mechanically, these shales are relatively brittle compared to

other shales. Table 4 shows the XRD mineralogical results for low-smectite shales.

Table 4. XRD Results of Different Shales withFracturing as the Dominant Mechanisms of Fluid-Rock Interactions

Marcellus Haynesville Morrow Eagle Ford Woodford WolfcampSmectite (%) 6 11 13 5 3 10

Illite (%) 24 29 45 5 10 14

Calcite (%) 2 14 - 63 - -

Dolomite (%) - 2 - - 24 -

Quartz (%) 48 32 33 23 52 64

Feldspars (%) 5 4 2 2 8 7

Kaolinite (%) 4 5 6 - - 3

Pyrite (%) 5 3 1 2 3 2

Chlorite (%) 6 - - - - -

Although low-smectite shales are rather unreactive in fluids, fractures can be produced along bedding planes, laminae, or

enlarged by extending or separation along the pre-existing fractures (Fig. 6). These fractures could cause wellbore instability.

Fig. 6Marcellus shale (right) original sample and (left) sample after exposure to fresh water for 10 days at 150F.

Rocks can be fractured even when the average clay amount is relatively low and reactive clays are in trivial amounts for thebulk rocks. Interbedded shale and siltstone or localized assemblage of reactive clay can give rise to fractures. In those cases,

fracturing is mainly related to the shaly bedding or localized assemblage of reactive clays in silty or sandy rocks (Fig. 7).

Fractures can also form and grow along the boundary of two different rock types when the rocks are in contact with drilling

fluid.

Fig. 7Thin-section photomicrography showing fracture development along shaly bedding or clay-rich bedding after exposure todrilling fluids.

Initial 10 days

8/12/2019 IPTC-17235-MS (1)

6/12

6 IPTC 17235

Shale-Fluid Interactions at Wellbore Temperature and Pressure Conditions. Consideration must be given to how

wellbore temperature conditions, confining and differential pressure affect the behavior of shale-fluid interactions, especially

how deep fractures can develop and extend into the shale formation. To address these issues, the authors conducted an

experiment that simulated the wellbore temperature and pressure conditions. Confining pressure was applied isotropically to

a cylindrical sample. The test core (~2-in. length x 1.5-in. diameter) was cut using nitrogen gas to avoid any contact with

fluid during the core plug preparation. The test was then conducted at a temperature of 150F. Confining pressure was

applied to 500 psi, with a differential pressure between wellbore and formation of 750 psi. The shale on the wellbore side was

exposed to water for 48 hours, where the water was refreshed periodically. The formation side was not exposed to freshwater. After 48 hours of fresh water exposure, the core was removed from the system and examined.

There was a clear difference between the water-exposed core end and the one not directly exposed to water (Fig. 8).

Abundant fractures were observed at the water-exposed core end. These fractures developed mainly along bedding planes.

The core end without direct water exposure was still dry and no visible fractures were created, indicating the depth of fluid

invasion from wellbore size was less than the core length of 1.98 in.

Fig. 8 - (a) original core end at wellbore side (to be exposed to fresh water), (b) post-test core end at wellbore side, (c) original coreat formation side (not directly exposed to water), (d) post-test core at formation side. Note the wet fluid on the d photo which is

the confiningpressure fluid (oil) from inadvertently contacting core surface during removal of the sample from the cell.

Thin sections were made at four different depths from wellbore side to the formation side in order to evaluate the shale-

fluid interactions and fracture development (Fig. 9). Fractures or breaking-off can be clearly identified in thin sections by

injecting blue-dyed epoxy. Thin section observations indicated that direct fresh water exposure created abundant fracturesand breaking at the wellbore side, but no visible fractures were created at the core end without water exposure. Note that the

fracture extended deep into the third thin section (~1.2-in. depth) along bedding planes was pre-existing, but visual

comparison suggests that it appears to be further opened due to fluid exposure. Most fractures observed in the fluid-exposed

side do not reach the depth of thin section b, which is 0.6in.

8/12/2019 IPTC-17235-MS (1)

7/12

IPTC 17235 7

Fig. 9 - Thin sections of post-test core: (a) water exposed end, (b) 0.6 in. to the top, (c) 1.2 in. to top, and (d) dry end.

The fluid exposure test was also conducted at ambient condition without confining pressure to evaluate the impact of

confining pressure. Both tests illustrated fracturing as the dominant deformation mechanism (Fig. 10); however, the test at

ambient condition without confining pressure maximizes this change.

a b

Fig. 10 - Test comparison between ambient condition and wellbore conditions: (a) ambient condition, exposed to fresh water for 1hour, and (b) wellbore condition, exposed to fresh water for 48 hours.

Shale Stability Tests with Drilling FluidsShale has a high potential for fluid-rock interactions, but the interactions can be minimized if appropriate chemical inhibitors

are used. Here we will present two examples to show the impact of chemical additives on the interaction of fluid-rock

interactions. The first shale has a large propensity for dispersion. For the second shale, dispersion is weak, but fracturing

along bedding planes or laminae is the dominant behavior in the fluid.

a b

c d

8/12/2019 IPTC-17235-MS (1)

8/12

8 IPTC 17235

Uganda Sample. Uganda shale is siltstone or silty shale. Smectite is one of the main clay minerals. The rock is soft without

evident lamination. This shale has a very strong tendency for dispersion. Laboratory tests were conducted to evaluate the

interaction of the shale with polymer systems containing different chemical additives for inhibition and shale stability

control. Both dispersion (Fig. 11) and bulk hardness tests (Fig. 12) showed that the addition of inhibitive additives

significantly improved the inhibition performance of the systems as compared with the base polymer system. Both high-

performance amine (HPA) and the KCl showed effective inhibition.

Fig. 11Dispersion test result for Uganda shale.

Fig. 12Bulk hardness test result for Uganda shale.

The efficiency of the chemical additives was further evaluated by immersion tests which can directly showed the

interaction between the fluid and shale (Fig. 13). Exposure to both KCl brines and K-acetate were evaluated. Both fresh water

and mineral oil were also tested as references. The tests revealed that KCl showed better inhibition than K-acetate. The

increment of the KCl concentration helped reduce the fracturing of the rock. In 10% KCl brine, fractures can develop, but

both the amount of fractures and fracture length can be significantly reduced or inhibited. It is worth mentioning that the core

material used for testing was not preserved. Multiple cracks exist in the sample, most likely due to the drying process in

ambient conditions. Therefore the immersion test result might represent the worst case for these cores.

27.40

75.40

84.25

90.65

90.60

0 10 20 30 40 50 60 70 80 90 100

Freshwater

Polymer system

K-Acetate /Polymer system

HPA/Polymer system

7% KCl/Polymer system

% Recovery

0

50

100

150

200

250

0 2 4 6 8 10 12 14 16 18 20

Torque(

inch-

lb)

Number of Turns

Polymer system HPA/Polymer system

KCl/Polymer K-Acetate/Polymer system

8/12/2019 IPTC-17235-MS (1)

9/12

IPTC 17235 9

Initial 24-hr Fluid Exposure

Fresh Water

K- Acetate

7% KCl

10% KCl

Base Oil

Fig. 13Uganda shale exposed to different fluids

8/12/2019 IPTC-17235-MS (1)

10/12

10 IPTC 17235

Wyoming Shale. The Wyoming shale has strong laminations and is very consolidated. It consists of 18-23% of smectite.

Other clay minerals include illite (10-17%) and kaolinite (3-7%). Dispersion tests (Fig. 14) showed a low dispersion tendency

in fluids. The recoveries with all the tested drilling fluids were >96%. Even in water, recovery was ~93%.

Fig. 14Dispersion test result for Wyoming shale.

Dispersion, along with bulk hardness and swelling tests, is not always effective in assessing the stability of shale with

drilling fluids. One of the main reasons is that these traditional test methods do not reflect the effects of shale structure on

fracture development and rock failure. The sample preparation in traditional methods usually involves grinding the rock

material into pieces smaller than 3 mm, which partially or completely destroys the natural fabric of the rock. This process

largely removes the impact of the rock structure and spatial distribution of clay minerals on fracture development.

Immersion tests were conducted to evaluate the interaction of fluid with the Wyoming shale (Fig. 15). These tests showed

that fracturing along the bedding planes or laminae was the dominant behavior when the Wyoming shale was exposed to

aqueous fluids. Compared to the oil-based drilling fluid systems, water-based fluids caused fracturing, either by the

development of new fractures or the enlargement and extension of pre-existing fractures. Among the tested water-based

fluids, the fluid with amine inhibitor showed the best performance. When rocks were exposed to non-inhibited WBM and

WBM with a polymeric inhibitor, they became fragile along the fractures and multiple rock fragments broke off.

93.25

96.60

97.65

96.80

96.40

0 10 20 30 40 50 60 70 80 90 100

Freshwater

No-inhibited WBM

WBM with Amine Inhibitor

OBM

WBM with Polymeric Inhibitor

% Recovery

8/12/2019 IPTC-17235-MS (1)

11/12

IPTC 17235 11

Initial 7 Days of Fluid Exposure

Fresh Water

Non-Inhibitive WBM

WBM with Polymeric Inhibitor

WBM with Amine Inhibitor

Oil-Based System

Fig. 15Wyoming shale exposed to different fluids.

8/12/2019 IPTC-17235-MS (1)

12/12

12 IPTC 17235

ConclusionsThe shale behaviors in fluids are mainly related to its clay minerals, structure, bedding and thin laminae, and pre-existing

fractures. If shale with high smectite content has not experienced substantial compaction and thermal alteration, it may show

a strong tendency for dispersion. Alternatively, if high-smectite shale has experienced strong compaction and thermal

alteration and shows laminated structures, fracturing along bedding planes or laminae could be the dominant deformation

mechanism in fluids. Rocks can be fractured even if the average clay amount is relatively low and reactive clays are in trivial

amounts for bulk rocks. This is especially the case if the rocks show interbedded shale and siltstone or there is localized

assemblage of reactive clay. Confining pressure can significantly reduce the propagation of fractures, but pre-existingfractures can be enlarged or extended due to fluid invasion along the pre-existing fractures. Even for highly reactive shale,

proper inhibition can be achieved if the composition and concentration of chemical additives are selected appropriately.

AcknowledgmentsThe authors thank the management of M-I SWACO, a Schlumberger company, for permission to publish this paper.

ReferencesBoggs, S., Jr. 2003.Petrology of Sedimentary Rocks. Cladwell, New Jersey: The Blackburn Press.

Ewy, R.T. and Morton, E.K. 2008. Wellbore Stability Performance of Water Based Mud Additives. SPE 116139, SPE Annual Technical

Conference, Denver, September 21-24. http://doi.org/10.2118/116139-MS.Gomez, S. and He, W. 2006. Laboratory Method to Evaluate the Fracture Development in Hard Shale Formations Exposed to Drilling

Fluids. AADE-06-DF-HO-38, AADE Fluid Conference, Houston, April 11-12.

Gomez, S. and He, W. 2012. Fighting Wellbore Instability: Customizing Drilling Fluids Based on Laboratory Studies of Shale-Fluid

Interactions. SPE-155536, IADC/SPE Asia Pacific Drilling Technology Conference, Tianjin, China, July 911.http://doi.org/10.2118/155536-MS.

Lal, M. 1999. Shale Stability: Drilling Fluid Interaction and Shale Strength . SPE 54356, SPE Latin American and Caribbean Petroleum

Engineering Conference, Caracas, April 21-23, 1999. http://doi.org/10.2118/54356-MS.Simpson, J.P., Walker, T.O. and Jiang, G.Z. 1995. Environmentally Acceptable Water Based Muds can Prevent Shale Hydration and

Maintain Wellbore Stability. SPE Drilling & Completion, vol 10, no. 4 (Dec) 242-249.http://doi.org/10.2118/27496-PA.van Oort, E.2003. On the Physical and Chemical Stability of Shales.Journal of Petroleum Science and Engineering, Vol. 38, no. 3-4,

(June) 213-235.http://dx.doi.org/10.1016/S0920-4105(03)00034-2.

http://doi.org/10.2118/116139-MShttp://doi.org/10.2118/116139-MShttp://doi.org/10.2118/155536-MShttp://doi.org/10.2118/155536-MShttp://doi.org/10.2118/54356-MShttp://doi.org/10.2118/54356-MShttp://doi.org/10.2118/27496-PAhttp://doi.org/10.2118/27496-PAhttp://doi.org/10.2118/27496-PAhttp://dx.doi.org/10.1016/S0920-4105(03)00034-2http://dx.doi.org/10.1016/S0920-4105(03)00034-2http://doi.org/10.2118/27496-PAhttp://doi.org/10.2118/54356-MShttp://doi.org/10.2118/155536-MShttp://doi.org/10.2118/116139-MS