# 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 information 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



### HESI300340formation 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.



### HESI300341Clay 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.



### HESI300342Cation 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



### HESI300343Permeability 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



### HESI300344Pressure, 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



### HES1300345reduction 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



### HESI300346contain 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



### HESI300347References

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



### HES1300348O 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 ofsmectite 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



### HESI300349abbreviation 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



### HESI300350SPE 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



### HESI3003776 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 genericfile 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).

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Time Fig. 7--Validation of temperature simulator with bottomhole gauge data. 25

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### HESI300378SPE 63238 P. HARRIS, H. WALTERS 7

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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 realtime 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 theon-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 controlto 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 factorsinfluence 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.



### HESI3003798 REAL-TIME CONTROL OF LOW-POLYMER FRACTURING FLUIDS SPE 63238

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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

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Fig. lO--Viscosity simulation.



### HESI300380SPE 63238 P. HARRIS, H. WALTERS 9

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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
AcknowledgmentsThe 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 1998SPE 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 1998Annual 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 atthe 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