The Influence of Clays

on the Production

Hydrocarbons

Clays are present in a majorit3, of

hydrocarbon bearing formations and their

presence can cause many problems in the

production of oil and gas. The difficulties that

are so encountered are complicated by the fact

that clay composition and its location in the rock

permeability can vary extensively. In reality, the

presence of clays along any part of the drilled

hole can present a variety of problems in all

phases of the life of the wel!. There are shales

that show a high degree of deterioration when

contacted by the common ~’pes of water base

drilling fluids. Fluid loss from cement slurries

and certain water base stimulation fluids is

another source of potential damage to

permeability.

Clays may be found in almost all types of

rock. Such rocks have been called water sensitive

and may be defined as a formation where a

reduction in effective permeabilky is noted when

a foreign water invades the formation. Normally,

sandstone formations exhibit the greatest degree

of water sensitivity. Clays may also be present in

carbonate rocks but are frequently encapsulated

in the rock matrix. Thus, they are not in a

position to be contacted by the invading fluids.

PermeabiliD" damage is primarily caused by

migration of clays and other fines with fluid

flow. Subsequent bridging of particles at flow

restrictions in the rock flow channels causes a

plugging action which results in a permeabiiity

reduction. This overall effect primarily occurs

during the flow of water.

CLAYS FOUND

IN FORMATIONS

Part I

The clays most frequently found in

hydrocarbon producing formations are smectite

(formerly called montmorillonite or bentonite),

itlite (which can include gtauconite and some

micas), mkxed laver (primarily iilite-smectite),

kaolinite, and chlorite. Their presence in

formation samples and approximate concentrations are usually determined by x-ray

diffraction analysis. However, the position of

clays in the rock matrix and their localized

concentra,5on in any area are also very important.

This is ve~- difficult to resolve by x-ray

techniques but can be quickly determined by the

use of dves. Cer:ain dyes~’ ~ and other chemicals

exhibit characteristic colors when they are

adsorbed by the different days. A subsequent

examination of the trea~ed rock surface with low

power magnification by one experienced in this

art can be quite revealing.

More recently, the Scanning Electron

Microscope (SEM) b, as been used to examine

HESI300340
formation samples. It has been veW useful in the

identification~of the various clays and minerals as

welt as showing where clays are located in the

rock matrix.

CLAY DISTRIBUTION

Part 2

Some correlation has been developed as to

the type of clay that may be present at various

depths along the Gulf Coast. Weaver~ reported

smectite to predominate to 7,000 ft with some

mixed layer clay and discrete smectite being

detected in the 7,000 to 12,000 ft depth. With

deeper burial, discrete smectite decreased to

essentially zero to 17,000 ft with mixed layer clay

concentration increasing. PenT and Hower4

extensively studied the composition of shales

obtained from wells drilled in the Galveston area

of Texas and offshore Louisiana. Shale samples

were investigated from 3,364 to 17,000 ft in the

Galveston area. Generally, the predominant day

found was smectite-illite mixed layer with the

smectite component (up to 85 percent) being the

predominant fraction at the shallower depths.

The percentage of the smectite component

decreased reguIarly in the mixed layer clay with

depth until only 20 percent smectite was present

in the 10,300 to 17,000 ft shales. Small amounts

of kaolinite and chlorite were usually present at

all depths. However, content of both of these

clays and discrete illite increased at depths below

9,200 ft.

The clay content of the offshore Louisiana

shales (410 to 18,400 ft) was verb." similar to the

above except that smectite content of the mixed

layer clay was greater at equivalent sub-sea

depths. For example, mixed layer clay contained

35 percent smectite at I5,500 ft and did not

reach the 20 percent level until i8,000 ft. This

difference can be explained by a greater

temperature gradient for the Texas wells as

higher temperature favors the development of

illite under the environment present in these

areas.

If the clay content in sand bodies is similar

to the adiacent shales, predictions as to the clays

that may be expected at various depths in the

sands can be made.

Formation samples from other areas have

also been examined with the same general clay

distribution as described above being noted.

However, concentra.fions of discrete illite and

smectite were generally lower than in the Gulf

Coast area. Kaolinite was almost always the

predominant clay dete~ed, regardless of depth of

burial.

The reIativelv small number of carbonam

samples evaluated showed zero to moderate

amounts of the~e clays to be pr~ent. Kaolinite,

i!lite, and mixed laver ctay were the predominant

clars found.

DESCRIPTION OF CLAYS

Parr 3

AII of the claws noted here are fiat crystals.

They exist as thin ptateiets teat are normally

stacked like a deck of cards or writing paper to

form packets. Stacking is not necessarily even as

platelets can overlap in the packets. These

packets are distributed throughout a sand in

many ways. Quite frequently they are

concentrated at iunctions of sand grains and are

more concentrated in the sand near shale lenses.

Kaolinite is usually concentrated in isolated

spots, smectite in smears throughout the area

where it is present, illite in streaks close to shale

lenses,and mixed layer cIav in irreguIar streaks

throughout the sand. Va.ria:ions of the above will

occ-ar which will primarily depend on

concentration of ~he clay in t~e sand. Detection

of the position of these clays ha sandstones was

accomplished bv ~he use of tee dye staining

procedure.

Cation Exchange

All clays are negatively chaNed. With

smeaite, :hose charges are predominant on the

faces of the clay crystal wkile the edges of the

cr?..’szal are positively charged. The density of the

negative charges can be measured by determining

the number of positive charges required to

neutralize the crystal. This is k~qown as the cation

exchange capaciD" (CEC) of ~e clay and is i,.

expressed in mitl.ieeuival~ts, :_~ME~ for 100 grams

of c!ay. Fig. I lists the CEC of several clays.

HESI300341
Clay Range of Cation

Smectite 80

lllite 10

Kaolinite 3

Chlorite 10

Sand (2 to 62 microns)

Exchange Capacity

to 150

to 40

to 15

to 40

0.6

Fi,a 1--. Cation Excbsnae~ Cap.~.,ly~ o~’ Seiec~ea Clays

The replacement of one cation by another

on any clay is governed mainly by the law of

mass action and the valence of the cation.

Generally, where mono- and divalent cations are

present in the same concentration, the divalent

cation will be preferentially attracted to the clay.

If a water solution containing only one cation is

brought in contact with a day, it will tend to

replace another cation, regardless of its valence.

Among monovatent cations, it has been found

that potassium and ammonium are more effective

than sodium in replacing divalent calcium on

smectite.

Water Adsorption by Clays

The clays under consideration may be

classified as swelling and non-swelling. Smectite

is the only clay that swells by absorbing ordered

water layers be~’een clay co’stals. Mixed layer

clay, which contains smectite, will also swell with

water but the illite portion of this clay is

relatively nonwater swelling. Kaolinite and

chlorite, as well as illite, may be classed as

nonwater swelling clays. They do not build

viscosi~’ in water as effectively as smectite since

their crystals tend to remain as packets instead of

being dispersed as do the smectite crystals.

However, one must not ignore the fact that these

so-called nonwater swelling clays do adsorb some

water. Routsons, et. al., reported that some water

is adsorbed in illite crystal packets. Aylmore~,

et.al., examined ka6linite under a varie~, of

conditions and found that water is associated

with this clay and that the cation attracted to the

clay and its concentration have little effect on the

water content. Thus, all clays do adsorb water

with smectffe adsorbing the most.

and Sand

Water Adsorption by Smectite

Water adsorption or layering between

smectite cD’sta!s is due to hydration of the cation

attracted to the clay and hydrogen bonding.

Degree of swelling depends on the cation

associated with the clay and the amount of

dissolved salts in the water in contact with the

clay. The hydration numbers suggest the number

of molecules of water that may be carried to the

clay surface by the cation. These water molecules

act as a nucleous for the development of water

layers on the clay surface. Fig. 2 lists the ionic

diameters and hydration numbers of several

cations. A range in hydration number,

representing data from various investigations, is

noted for each cation.

X-ray diffraction can be used to determine

the number of Iayers of water between smectite

crystals. The thickness of an absolutely dry

smectite crystal is generally accepted to be 9.5 ~

and a layer of water is approximately 3~ thick.

(A is the abbreviation for Angstrom units. One

Angstrom equals 10-7 millimeters or 4 × 10-~ in.).

Thus, if x-ray indicates the clay-water system to

be 15.5~, thick, then t~o layers of water are

present. The first three to four layers of adsorbed

water are ve~- ordered and have an average

density of 1.2. Some authors have called this

crystalline water since its general configuration is

different from bulk water. Where only one layer

of water exists between smectite c~’stats, its

density is close to 1.4 and it is very difficult to

remove. As a result, the d~" bentonite normally

used for drilling mud has one layer of water

between the clay crystals which is equivalent to

about 9 percent of the total weight of the clay.

HESI300342
Cation Ionic Diameter Hydration Number

Sodium 1.90~ 5 to 11

Potassium 2,66,~ 1 to 4

Ammonium 2.86,~ 2 to 4

Calcium 1,98~ 10 to 22

Magnesium 1.30,~ 12 to 33

A range in hydration numbers is given which represents data from several sources, The

variation in values is due to the method of obtaining the data and the concentration of the

various salts in solution,

Fig 2 --. Ionic Diame’.ers and Hydralicn Numbers Of Several Cations

The surface of the smectite crystal is a series

of oxygen atoms formed in repeating hexagonal

rings. There is a cavity inside each ring that is

approximately 2.8A in diameter and 2.4A deep.

When the cation attracted to the clay has a small

hydration number and ionic diameter, it is

entirely possible for the cation to fit into the

cavity and be relatively difficult to remove.

Potassium has an ionic diameter of 2.66/~

and a small hydration number which fits the

above requirements quite well. However, a cation

that has a large hydration number would not be

able to fit into the cavity even if it had a

relatively small ionic diameter. Fig. 3 lists the

effect of different salts on the amount of water

held between smec~ite c~’stals under atmospheric

pressure conditions,

Salt Sodium Potassium Calcium

Concentration* Clay Clay Clay

Distilled Water 32 27 4

0,4 percent 14 2 4

2 percent 3 2 4

8.5 percent 2 2 3 to 4

10 percent 2 1 to 2 3

13 percent N,D, t 3

t6 percent N,D. 1 2

N.D. - Not Determined

*The salt concentration shown is used to express the percentage of sodium chloride with

sodium smectite, potassium chloride with potassium smectite and calcium chloride with

calcium smectite.

Fic~ 3 Eflecl of Sa!: Co,,ce,.ra,~o. on the Number o! Wate~ Layers iS~,,,ei! ng! Between Mo’-:m.or, io~te Cr,,sla’s

HESI300343
Permeability Damage by Clays

As stated previously, the major permeability

damage that can occur in a rock that contains

ctaFs is due to the migration of the clays and

subsequent bridging of these particles in pore

channe! restrictions. With smectite, the

adsorption of additional water bet~’een crystals

forces them farther apart and enhances their

possibility of breaking loose and migrating. This

clay can migrate as single crystats or small

packets. Smectite can then be seen as the weak

points in mixed layer day structures. Here,

packets of illite can break loose and migrate and

these larger particles, combined with the

individual smectite crystals, could be more

damaging than smectite by itself. Kaolinite, illite,

and chlorite will also migrate as packets when

their natural equilibrium is disturbed by a

foreign water invading their environment,

SOURCE OF

DAMAGING FLUIDS

Part 4

Many sources of foreign water can cause

permeability damage. Most common are fluids

lost from mud and cement slurries, workover

fluids, and stimulation fluids. Some of these

fluids remain in the rock for long periods of time

and penetrate the rock to different depths. Such

water can also affect the hardness of many sand

formations. The dissolving of only a smal!

amount of minerals that were acting as

cementing agents for the rock could release clays

and feldspars from their original positions. Hig~h

pH solutions that contain very little dissolved

salts will act to disperse clays, thus compounding

the problem of clay migration.

Testing for Water Sensitivity

 ̄

..............

Hewitt7 has developed a series of tests that

define the degree of water sensitMty of

formations. His system includes mineral and day

identification, swelling tests, microscopic

examination, and flow tests. The complete

program requires specialized equipment,

expertise in. this area, and considerable time, but

the data, so obtained, can be of considerable

value.

Tests that may be performed with formation

samples cannot always be made with the greatest

degree of confidence. When a core is removed

from a weI!, it may be contaminated with drilling

fluid. In add.ition, there is a significant pressure

change which could cause alteration of the

physical cendition of the clays. In many

instances, the cores have not been preserved and

are completely dr?., before any test is initiated.

This condition can develop a strain in the clay

packets which is rapidIy released when the rock

is rewet for flow tests. The drying-wetting

procedure is certainly one that would enhance

the migration of days, resulting in an indicated

permeability damage more severe than would

occur in the formation.

On the other hand, it must be recognized

that permeabilities normally determined in the

laboratory may be significantly greater than those

that exist in the format.ion. ThomasS, et. al.,

found that, wizh cores zhat contained very little

clay, an overburden pressure of 3,000 psi

reduced surface gas permeability values by 62 to

90 percent. At 6,000 psi, permeability reduction

was in the range of 73 to 99 percent. Thus,

permeability damage as determined in the

laboratory with formation samples does not

necessarily reflect the same degree of damage

that could occur in the formation.

Pressure and Salt Effects

ConfinLng pressure has an effect on the

amount of water that wilI be held bet~,een

smectite crystals. Handy~, et. al., have used a

consolidomerer and x-ray to determine the

degree of water expulsion from between smectite

crystals at pressures to 44,500 psi. Their results

are summarized in Figs. 4 and 5 which represent

conditions where no salts were in the water. It

may be seen that sodium smecfite retains more

water than caldum smectite under similar

pressures.

Unfortunately, there is no published data on

the effect of both pressure and salt concentration

on the amount of water that is retained between

smectire c~stals. However, a study of Figs. 3, 4,

and 5 indicates that, for most well conditions,

two layers of water will be retained between

smectite crystals under naturally occurring

HESI300344
Pressure, X-ray Approximate Number

psi Spacing of Water Layers

392 20.6.~, 4

1,020 20.1,~ 4

2,825 18.7,~. 3

9,020 17.0~, 2 to 3

17,980 15.9,~ 2

44,500 13.6~. 1 to 2

Fi,~. 4 -- The Ef’,ecl of Pressure on the Wa[er Retention of Sodium Srneclite (Ref 9i

Pressure, X-ray Approximate Number

psi Spacing of Water Layers

1,365 17.8.~ 3

2,730 16.5,~ 2 to 3

9,110 15.5.&. 2

18,220 14.7,~ 2

27,500 14.0.~ 1 to 2

The x-ray spacings recorded in Figs. 4 and 5 are composite values. In most instances, two

values were obtained at each pressure indicating a mixed water layering between clay crystals.

For example: sodium smectite at 392 psi showed x-ray peaks at 20.1,g, and 23.2,~ with the

peak being stronger. A composite value of 20.6/~ was then determined.

Fig 5 -- The Effect of Pressure on the Water Relention of Calcium Smectite (Ref, 9)

conditions. This conclusion is based on the

normal salts and their concentration found in

most brines combined with the effect of

overburden pressure. Therefore, to minimize the

possibility of clay crystals or packets of crystals

breaking loose and migrating, any water that may

penetrate a clay containing rock should contain a

chemical that wilt not alter the natural water

retention of the clay. This can be accomplished

with the potassium cation.

The use~° of potassium chloride in water for

fracturing procedures constituted the first

successful application of this chemical. Potassium

chloride~l, 12 also has been used in drilling fluids

to stabilize water sensitive shales. In addition,

potassium chloride is being used in cement

slurries to minimize damage that could be caused

by the high pH cement filtrate.

The ammonium ion has also shown a great

deal of promise for this use. Salts of this ion are

more expensive than potassium salts which has

limited their use in the oil industry. However,

ammonium chloride has been used successfully

in a few areas in conjunction with hydrofluoric

acid treatments and water base fracturing fluids.

It must be kept in mind that the potassium

and ammonium cations are used to maintain the

"status quo" of clays to minimize permeability

HES1300345
reduction due to c!ay migration during a

particular phase in the life of a well. They are

very effective for this use but are not

recommended for conditions where a relatively

dilute brine will be flowing continuously through

the sand or where severe water conning develops.

PERMANENT

CLAY CONTROL

Part 5

Clay migration can be effectively controlled

permanently by two processes. One uses the

hydroxy-aluminum ion which is strongly

adsorbed by clay, Subsequent polymerization of

this ion develops an inorganic coating on the day

surfaces which minimizes clay migration. Its use

is well estabIished in several types of field

applications. However, a treated formation

should not be acidized as the polymer will be

removed from the clay.

The other process utilizes an organic

polymer that is effectively adsorbed by clay.

Again, the polymer coating minimizes the

possibility of clay migration. Its use has been

field proven in acid treatments to help maintain a

high level of production for a longer period of

time and in preflushes in fracturing. In addition,

the organic polymer coating appears to be stable

to most hydrochloric acid solutions and other

well fluids.

ORGANIC

CHEMICAL ADSORPTION

Part 6

Many organic chemicals are used by the oil

industry during the life of a wetl. They can be

present in muds, cement slurries, and stimulation

fluids. These chemicals are polar and can be

adsorbed on all rock surfaces. All silicate (sand,

clays, and feldspars) carry a negative charge and

would naturally strongly attract any organic

chemical that carries a positive charge. In

addition, relatively large anionic (negatively

charged) and nonionic organic molecules are

adsorbed by silicates through hydrogen bonding

and van der Wools’ forces. The amount of

chemical that wiit be adsorbed by a silicate

surface is directly proportional to the available

surface area. Dispersed smectite may have a

surface area as great as 750 square meters per

gram. However, where the clay cD, steds are in

packets and not thoroughly dispersed, only a

small portion of this area is available for

adsorption. Even then, the surface area of this

clay available for organic adsorption would be

significantly greater than sand (150 ro 200 square

centimeters per gram).

Surfactants

Surfactants are frequently used with

stimulation fluids to prevent emulsions and aid

in the recover)’ of water from the rock. With

smectite, it has been shown~* that up to 0.55

grams of some surfactants can be adsorbed by

one gram of this clay. Cationic surfactants are

vet)’ strongly adsorbed and are essentially

impossible to remove with water. Nonionic

surfactants are also strongly adsorbed and are

partially removed by water. Anionic surfactants

are adsorbed but are readity removed by wa:er.

The degree of surfactant adsorption by iliite and

kaolinite is, on the average, about 5 percent of

that adsorbed by smectite while adsorption by

sand is even less.

The wettabitiD- of the rock can be altered

from water wet to oil wet by the adsorption of

cationic surfactants and by certain nonionic

surfactants. This change in wetrability can cause

a severe decrease in the permeabilit3, of the rock

to oil. Flow tests with cores having a wide range

in permeability have indicated the greatest

percentage decrease in flow due to oil wetting to

occur where the original permeability was quite

low.

The use of a cationic surfactant in water

fracturing procedures can present problems in

more than one area. Water lost to rock may

become trapped in the smal! flow channels due

to oil wetting, thus limiting the production of

hydrocarbons, it has also been reportedIs that

oil-wet sand used as the propping agent reduced

fracture flow capaciD- a significant amount.

An oil-wetting surfactant had been used

with water to fracture several wells in a certain

area. Water recovery was almost niI, and the

resulting oil production was ve~" disappointing.

A change to a water-wetting anionic surfa~ant

resulte~l in a fast water recover?.., and a good

increase in oil production.

Some oil-base and invert emulsion muds

HESI300346
contain surfactants that oil wet sandstone

formations. Tt-. resulting permeability damage

frequently masks the true potential of the well

during initial testing. This condition can be, at

best, partially remedied by treating the formation

with a fluid containing a strong water-wetting

surfactant. However, complete contact of all the

damage area with this treatment cannot always

be assured.

CONCLUSIONS

Part 7

I. It must be recognized that clay problems

are numerous and varied and that no one

approach can be the answer for all conditions.

2. Al! available information concerning the

productive zone should be correlated before the

formation is penetrated by the bit.

3. One should plan all phases of drilling and

completing of the well to fit the formation and

utilize all available technolo~’ to the utmost.

4. it is easier to prevent permeabili~-

damage due to clavs than to remedy a damaged

condition.

Miocene South Louisiana showing

smectite and mixed layer clay in pore.

Mag.-10,500X.

Formation,

Norphlet Formation, Mississippi showing fibrous

illite in pore.

M ag.- 1,000X.

Douglas Formation showing illite and kaolinite

around pore.

Mag.-2,000X.

Tusca!oosa Forma:ion showing iron rich chlorite

coating sand grains.

Mag.-!,000X.

?ig. 6 ~ Scan~ r~g Eiect<on M;croscope Photographs

HESI300347
References

Dodd, C.G.: "Dye Adsorption as a Method

of Identifying Clays," Clays and Clay

Technology., Bull. 169, Division of Mines,

California (I955) 105-I11.

Mielenz, R.C. and King, M.E.:

"Identification of Clay Minerals by Staining

Tests," Am. Soc. for Testing Materials

Proc., (!951), V. 51, 1213-1233.

Weaver, C.E.: "The Clay Petrology of

Sediments," Clays and Clay Minerals, (i957)

V. 6, 154-187.

Perry, E. and Hower, John: "Burial

Diagenesis in Gulf Coast Sediments," Clays

and Clay Minerals, (1970) V. 18, 165-177.

Routson, R.C.; Kittrick, J.A.; and Hope,

E.H.: "Interlayer Hydration and the

Broadening of the 10 ~. X-ray Peak in

Iilite," Soil Science, (1972) V. I13, No. 3,

167-174.

Aylmore, L.A.G. and Quirk, J.P.:

"Adsorption of Water and Electrolyte

Solutions by Kaolin Clay Systems," Soil

Sdence, (1966) V. 102, No. 5, 339-345.

Hewett, C.H.: "Analytical Technique for

Recognizing Water-Sensitive Reservoir

Rocks," J. Pet. Tech., (August, 1963) 813-

818.

Thomas, R.D. and Ward, D.C.: "Effect of

Overburden Pressure and Water Saturation

on Gas Permeability, of Tight Sandstone

Cores,"J. Pet. Tech., (Feb., 1972) I20-t24.

10,

11.

t2.

13.

14.

15.

16.

Handy, R.L.; Demirel, T.; Ruenkrairergsa, T.;

and Olson, T.: "Adsorption Energies and

Swelling Pressures of Montmori!lonite," ERI

Project 987~S (1973), Engineering Research

Institute, Iowa State University, Ames, Iowa.

Black, H.N. and Hower, W.F.:

"Advantageous Use of Potassium Chloride

Water for Fracturing Water Sensitive

Formations," API Paper No. 851-39-F

presented at Wichita, Kansas, April 3, 1965.

O’Brien, D.E. and Chenevert, M.E.:

"Stabilizing Sensitive Shales with Inhibi:ed,

Potassium-Based Drilling Fluids," J. Per.

Tech., (Sept., 1973) I089-1t00.

Scheuerman, R.F.: "Drilling Process Using

a Shale Protecting Polymer Drilling Fluid

System," U.S.P. 3,738,437.

Coppel, C.P.; Jennings, H.Y.; and Reed,

M.G.: "Field Results from Wells Treated

with Hydroxy-Aluminum,"ff. Pet. Tech.,

(Sept., 1973) 1108-11 I2.

Hower, W.F.: "Adsorption of Surfactants

by Montmorillonite," Clays and Clay

Minerals, (t970) V. 18, 97-105.

Graham, J.W.; Monaghan, P.H.; and

Osoba, J.S.: "Influence of Propping Sand

WettabiliW on Productivity of Hydraulicaily

Fractured Oil Wells," ft. Per. Tech., ~ov.,

1959) 324-329.

McLauglin, H.C.; Elphingstone, E.A.;

Remington, R.E.; and Coates, Sam.: "Clay

Stabilizing Agent Can Correct Formation

Damage," World Oil, (May, t977) 58-60.

Appendix

A. Structure of Clays

Clay minerals consist of two relatively

simple building units which are the silica

tetrahedral sheet and the alumina or magnesia

octahedral ;heet. The silica tetrahedral sheet is

composed of repeating units of silicon atoms that

are surrounded by four oxygen atoms to form

tetrahedrons. The alumina octahedral sheet is

composed of repeating units of aluminum atoms

surrounded by six hydroxyl groups to form an

octahedron. These structures are illustrated in

Figs. A-1 and A-2.

0 and Q) : Oxygens

0 and 0 = Silicons

HES1300348
O and (.]~ = Hydroxyls (OH)

tlAluminums, magnesiums, iron

Fig. A-2 -- Octahedrat Sheet

A three layer, or 2: l, clay would have one

alumina octahedral sheet with tetrahedral sheets

bonded to it at each side. A crystal of this type is

known as the mineral pyrophytlite. If the

octahedral sheet contains all magnesium, the

three layer mineral would be talc. Where some of

the aluminum in the octahedral sheet is

substituted with magnesium and a small amount

of silicon in the tetrahedral sheet is substituted

with aluminum, the clay mineral smectite is

formed. These substitutions develop a charge

deficiency in the crystal lattice which is

represented by a net negative charge shown at

the faces of the clay crystal.

This clay has been known by different

names due to local usage or dictates by certain

mineralogical groups. So far it has been called

bentonite, gel, montmorittonite, and now the

name "smecfite" is preferred.

1. Illite

Illite is similar to smectite in structure

but has a greater degree of substitution,

particularly in the silica tetrahedral layer.

This develops more negative charges in

the iilite crystal than in smectite. Where

an excess of potassium was present

during clay development, the potassium

was attracted to the clay at the cation

exchange sites. With the help of pressure,

all water was squeezed from the stacks of

crystals and the potassium became

"fixed" between the illite platelets. It is

very difficult for water to separate illite

crystal stacl~s. With most of the

p6tassium ions being obscured in the

stacks, illite exhibits a lower cation

exchange capacity than smecfite although

its charge densiu° is greater. Its main

cause of permeability damage is due to

clumps of cthy breaking loose, migrating,

and then bridging at flow restrictions in

the rock matrix.

Kaolinite

Kaolinite is a two-layer clay in that it

consists of one silica tetrahedral sheet and

one alumina octahedral sheet. There is

essentially no substitution in the cD’stal

lattice and its cation exhange capacity

comes from broken bonds on the edge of

the crystals.

Chlorites

Chlorites are a family of c!ay~ minerals

that consist of stacked mica-like (similar

to illite) and brucite [Mg3(OH)6]layers

with t~.o layers of each vype forming a

unit cell. They are not found in

hydrocarbon formations as often as the

other clays and usually exhibit no

swelling properties in water. However,

they have been known to cause

permeability damage by migrating and

bridging at flow restrictions.

4. Mixed-Layer Clays

Mixed-layer clays may be any

combination of clays where the individual

clay crystals are stacked on each other to

form an irregular arrangement. A

stacking where t~vo cla.~ are regularly

alternated is seidom encountered. The

most frequent mixed-layer clay found in

hydrocarbon producing formations is the

iltite-smectite combination. Another, but

less frequentIy detected, mixed-layer clay

is the chtorite-smectite stack. Thus, the

degree of swelling that would be detected

primarily depends on the amount of

smectite that is present in the mixedlayer stacks. These clays can cause

considerable permeability damage

through migration and bridging actions.

B. X-ray Diffraction Analysis

X-ray diffraction analysis can determine the

distance between one plane of a clay crystal and

the same plane of the adjacent crystal. The

thickness of a completely dR’ smectite crystal is

generally accepted to be 9.5~. (~ is the

HESI300349
abbreviation for Angstrom units. One Angstrom

is equal tO t0-7 mm or 4 x t0-9 in.). Since one

w~ater layer is approximately 3 A thick, the

ntamber of water layers can be determined by

subtracting 9.5fl~ from the x-ray values

determined for a clay-water system. For example,

a 15.5~k x-ray response would represent two

layers of water.

X-ray diffraction is also a recognized

method of identi~,ing crystalline materials and

has been used extensi~’ely for the analysis of

formation samples. Quantitative determination of

highly crysralli~e materials, such as sand,

carbonate rocks and even feldspars can be so

obtained. However, the c~,stallinity of clays will

vaD, extensively which limits the accuracy of the

quantitative determination of clays in formation

samples. Generally, the amount of clay is

estimated in general terms as folIows:

Trace - less than 1 percent

Small - ! to 5 percent

Moderate - 5 to 10 percent

Large - 10 to 20 percent

HESI300350
SPE 63238 P. HARRIS, H. WALTERS 5

18,000 3OO

16,000

10,000

8,000

6,000

4,000

2,000

Temperature

//

Model 50 Viscous / /

~ Viscosity Settling

400 cp Ref Viscosity ~ ~ ~ ~ ~

Elastic Sand Transport ~ ~" .~"

~ Onset of Sand Settling Sand Transport

Test time (hr)

25O

2OO

150

1 O0

50

Fig. 5--Sand transport and couette viscosity. Typical data comparison using crosslinked gel with breaker.

16,000

14,000

12,000

10,000

8,000

6,000

4,000

2,000

0

Temperature

B

50 100 150 200 250

Time (rain)

Fig. 6--Sand transport test. Varying breaker concentration in 25-1bm/Mgal crosslinked gel with

12-1bm/Mgal 20/40-mesh sand.

300

250

200

150

1 oo

50

o

3OO

HESI300377
6 REAL-TIME CONTROL OF LOW-POLYMER FRACTURING FLUIDS SPE 63238

data acquisition are vital elements for accomplishing this task

in real time.

A computer model for fluid temperature in the wellbore and

in the fracture has been incorporated in a fracture simulator.7

Heat transfer is modeled in the axial direction in the wellbore and

radial direction in the reservoir. Heat transfer is also modeled

down the length of the fracture and perpendicular to the face of

the fracture in the reservoir. The simulator is calibrated so that

bottomhole gauge data is obtained through a memory gauge

placed on a hanger in the casing above the perforations. This

position exposes the gauge to injection, shut-in, and flowback.

Flowing back the fluid after job completion helps validate the

temperature model of the fracture. The model is primarily

adjustedby changes to the heat-transfer coefficients between the

fluid and the wellbore, and between the fluid and fracture. As

shownin Fig. 7, the matchbetweenthe model and the gauge data

is quite good. The temperature recovered to about 75% of the

bottomhole static temperature (BHST) within about 1 hour, but

total recovery took about 17 hours.

Fluid Optimizer Software

If fluid element temperatures and shear history are known, fluid

segments can be selected with viscosity profiles and chemical

formulations that match the simulator requirements. A generic

file interface has been developed for returning the time, temperature, shear rate, and position of every fluid element pumped into

both the wellbore and the fracture. The interface allows for other

fracture simulators to be added in the future.

Optimizing fracturing fluid requires an accurate model of

fluid viscosity. Without it, any optimization is meaningless. We

have developed a kinetic reaction rheology model that includes

the effects of time, temperature, shear, and fluid formulation.

Iv] b] ..........

The viscosity is represented by a combination of several

modules shown in Eq. 1. The descriptions for these modules are

given in the Nomenclature section.

The fluid optimizer software consists of four main sections:

 ̄ a plot of the bottomhole conditions inside the tubulars

(Fig. 8, Page 7)

 ̄ plots of temperature, shear rate, and viscosity vs. time for a

stage average and the leading, middle, and trailing sub stage s

(Fig. 9, Page 8)

 ̄ a simulation section

 ̄ an optimization section

The first two sections primarily report the simulator output

in a format that is understandable to the user. The last two

sections are the essence of the optimizer.

The simulation section allows the user to specify the fluid

formulation and additives and receive a plot of viscosity vs.

dimensionless fracture half-length at different points in time

during the job (such as shut-in or closure) as shown in Fig. 10

(Page 8).

250

225

200

175

150

125

100

75

50

25

0

12:00

/ Gauge

Slurry rate ~ " ......................

 ̄

! ~’~ ~ Simulated

il~.1!

. , . . . I, , , , ,

14:00 16:00 18:00 20:00 22:00 00:00

Time

Fig. 7--Validation of temperature simulator with bottomhole gauge data.

25

0

02:00

2o

HESI300378
SPE 63238 P. HARRIS, H. WALTERS 7

22O

200

180

16O

140

120

100

8O

Shear rate .=

ti 1 t~’" Temperatureiii

Ii~li il~

0 100 200 300 400 500 600 700 800 900

Time (rain)

6OO

5OO

Fig. 8--Bottomhole conditions.

400

300

o

200

lOO

4000

3500

3000

2500

2000

1500

1000

5OO

The optimization section is the most advanced. Here, the

user specifies a desired viscosity curve along the fracture at one

or more times during the job. The user also specifies a range of

fluid formulations and additive concentrations. Upon execution,

the optimizer determines the fluid formulation and additive

concentrations that best match the desired viscosity curve(s) as

shownin Fig. 11 (Page 9). After performing the optimization, the

user can override the suggested schedule and adjust it while

viewing the simulated viscosity curve.

The optimumviscosity distribution inthe fracture is not well

understood, primarily because there has never been a tool to

describe it in a graphical, easy-to-use manner. As we gain

experience with this tool, we anticipate beginning to understand

the shape and magnitude of viscosity curve that will give us the

best production. This approach to fracture design represents a

paradigm shift in our thinking and level of service provided.

Real-Time Operation

The fracture simulator and fluid optimizer canbe used in a design

mode or in a real-time mode. In the design mode, they are run

with anticipated rates and temperatures. Simulations canbe run

inthe office or onlocation; however there are no real-time inputs.

In real-time mode, the fracture simulator is taking in data in real

time and the operator is adjusting the reservoir and fluid parameters (if needed) to match the predicted and observed net pressure. The fluid optimizer is then executed to give a new pumping

schedule of fluid parameters and additive concentrations. This

process is most often performed between the minifrac and main

job stages. This schedule is then sent electronically to the

equipment-control computers on location. After approval by the

on-location engineer, the schedule is executed. With the datacommunication technologies available, the engineer who redesigns the fracture simulator and fluid optimizer can be in the

office or at a remote location.

Conclusions

Low-polymer fluids used at high temperatures are operating on

the edge of their capability and require a higher degree of control

to stay within their limits of performance. Low-polymer fracturing fluids should be characterized with methods that use realistic

shear-rate history and heating rates. These physical factors

influence viscous fluid properties as much as chemical formulation, and determine the fluid’ s ability to generate fracture geometry, transport proppant, and flowback from the reservoir.

Faster computing power allows stimulation redesign during

a treatment in real time, with more detailed modeling of well

parameters, including temperature in the wellbore and fracture.

The ability to make informed decisions about parameter adjustments during the treatment relies upon this greater knowledge of

fluid properties as well as the ability to adjust and control fluid

formulation. Use of these new tools, in addition to real-time

feedback from the well, will undoubtedly result in paradigm

shifts as we discover in how to best use fracturing fluids for

maximizing productivity.

HESI300379
8 REAL-TIME CONTROL OF LOW-POLYMER FRACTURING FLUIDS SPE 63238

235-

215-

195-

175-

155-

135-

115-

75

i13

100 200 300 400

Time (min)

Fig. 9--Stage average temperature.

Stage--Wellbore/Fractu re (rain)

0--5.93/1.89

1--1.32/0.91

3--1.35/1.24

4--1.07/1.12

5--1.01/1.05

6--0.94/1.14

7--1.92/1.42

8--1.94/3.49

9--3.42/0.00

10~4.81/2.83

11 4.15/2.07

12-- -0.07/0.00

1,3~0.09/0.00

Cycle Times

[] Start--1 2.48

[] Shut In--1 13.88

[] Start--2 46.12

[] Shut In--2 233.40

3OO

25O

200

150

lOO

50

0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8

Dimensionless Fracture Half Length

1.0

Fig. lO--Viscosity simulation.

HESI300380
SPE 63238 P. HARRIS, H. WALTERS 9

1000

9OO

8OO

7OO

6OO

5OO

4OO

3OO

2OO

100

0

Optimizer match

,,.".,.-’^/- .............. %.. ..... . ........... =i\

0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9

Dimensionless Fracture Half Length

1.0

Fig. 11--Viscosity optimization.

Nomenclature

= Viscosity

= Reference viscosity module

[U] = Shear rate module

[T] = Temperature thinning module

[D] = Gel domain module

[~] = Kinetic reaction module

= Shear degradation module

= Viscoelastic response module

Acknowledgments

The authors thank the management of Halliburton Energy Services, Inc., for support of this project and the opportunity to

present this paper. We acknowledge the individual contributions

of David Barrick, Start Heath, Ron Morgan, Ron Powell, and

Billy Slabaugh.

References

1. Lehman, L.V; Yaritz, J.G., and Natvig, R.: "Hydraulic

Fracturing of the Frontier Zone in West-Central Wyoming:

A Case History," paper SPE 39958 presented at the 1998

SPE Rocky Mountain Regional/Low Permeability Reservoirs Symposium and Exhibition, Denver, April 5-8.

Powell, R.J. et al. : "Applications of a New, Efficient Hydraulic Fracturing Fluid System," paper SPE 38956 presented at the 1997 American and Caribbean Petroleum

Engineering Conference and Exhibition, Rio De Janeiro,

Brazil, August 30-September 3.

Dawson, J. C.; Le, H.V., and Cramer, D. :" Successful Application of a Novel Fracturing Fluid in the WasatchFormation

in Eastern Utah," paper SPE 49042 presented at the 1998

Annual Technical Conference and Exhibition, New Orleans, September 27-30.

Terracina, J.M. et al. : "Low Gel Loading Increases Well

Production in Eastern U. S.," paper SPE 51070 presented at

the 1998 EasternRegional Conference, Pittsburgh, November 9-11.

Model 50 viscometer, Fann Instruments Company.

Power, D. et al.." "Atomic Force Microscopy Studies on

Hydroxypropyl Guar Gels Formed under Shear," Macromolecules, Vol. 31, No. 25 (1998), 8744-8748.

Fracpro® PT. Vers. 10.0.51~ Computer software. Pinnacle

Technologies, GRI, 2000. Windows 95, 98 or NT.

HESI300381