in-situ gelation of silicates in drilling, well completion and oil production

Colloids and Surfaces, 63 (1992) 189-199 189 Elsevier Science Publishers B.V., Amsterdam

In-situ gelation of silicates in drilling, well completion and oil production

J o h n K. B o r c h a r d t

Shell Development Company, Westhollow Research Center, P.O. Box 1380, Houston, TX 77251-1380, USA

(Received 15 August 1991; accepted 1 September 1991)

Abstract

Silicate polymerization and gelation have been performed within subterranean formations to plug large cavities and reduce fluid flow capacity. Often during drilling a rock zone is encountered which produces a large amount of water or brine. This fluid dilutes the drilling fluid, greatly reducing its effectiveness. Conversely, large volumes of expensive drilling fluid can flow into a high permeability "thief zone". A solution to these problems is to inject a carefully designed silicate solution which gels in a controlled fashion. This forms an impermeable plug, greatly reducing fluid flow into or from the problem zone. Similar processes are used to reduce the undesirable flow of water into producing oil wells. Silicate systems with longer gelation times are also used to plug high-permeability zones in injection wells so water or other injection fluids flow into other zones still containing appreciable oil saturations.

Keywords: Grouting; in-situ gelation; in-situ polymerization; matrix plugging; oil recovery; sodium silicate.

Introduction

The in-situ gelation of silicates has been employed to reduce or redirect aqueous fluid flow in oil- and gas-bearing formations. Successful well treatments using in-situ polymerization of sodium silicate date back to at least 1955 [1,2]. By 1975, more than 500 production wells had been treated to reduce the produced water: oil ratio [3]. (An introduction to oil well treatment methods and terminology is given in Ref. [3].) The in-situ polymerization of silicates continues to be a popular method of solving problems during drilling and completion of wells, operating injection wells in water-flooding and enhanced oil recovery projects, and in improving production well economics by increasing oil production or reducing the produced water: oil ratio.

Correspondence to: J,K. Borchardt, Shell Development Com- pany, Westhollow Research Center, P.O. Box 1380, Houston, TX 77251-1380, USA.

Silicate gels may be elastic or rigid depending on a number of process parameters such as silicate concentration, concentration of gelation agent, pH, temperature, water hardness, and the presence of oil phases. The silicate gelation process is appli- cable over a range of formation temperatures from 40°F (4°C) to 350°F (177°C) [4]. One reason for the use of silicate solutions is the ability to formu- late treatment solutions to obtain gelation times from a few seconds to over 400 h I-5].

During drilling, the drill bit can penetrate fractures or high permeability zones. Expensive drilling fluid can rapidly flow into these "lost circulation" zones. Another problem sometimes encountered during drilling is penetration of a zone which produces large volumes of aqueous fluids which cause undesired dilution of the drilling fluid. Either situation can be alleviated by applying a silicate gelation process to seal the formation face with a low-permeability barrier.

After drilling, a casing is lowered into the well

0166-6622/92/$05.00 © 1992 - - Elsevier Science Publishers B.V. All rights reserved.

190 J.K. Brochardt/Colloids Surfaces 63 (1992) 189-199

bore. Cement is pumped down the casing and displaced into the annular space between the casing and the rock formation. The cement hardens thereby supporting the casing and bonding it to the formation. Perforations are shot through the cement barrier opposite the petroliferous zone to allow fluid flow into the well bore or injection of fluids into the oil- or gas-bearing formation.

Ideally, the cement forms an impermeable barrier. This prevents fluid flow between fresh water aquifers, brine-containing formations, and oil- and gas-bearing zones. However, in some cases the cement may not form a continuous impermeable barrier. Thus, undesirable fluid inter- change between formations is possible. Loss of oil and gas to another formation can reduce well productivity. Brine or hydrocarbon flow into an aquifer can lead to undesirable contamination of fresh water. One of the means of preventing or reducing such flow is to inject a silicate solution into the open flow channels in the cement sheath. Subsequent rapid gelation plugs these flow channels.

Rapid silicate gelation has been used to reduce water influx to production well bores. This allows a fracture or high permeability streak to be plugged or greatly reduced in permeability. These rock zones often contain a low oil saturation and sup- port a high rate of water flow. By sealing such fractures or high permeability streaks adjacent to a production well, the rate of water production is reduced. This can increase the rate of oil production by reducing the height of fluid in the well bore (and thus the hydrostatic pressure which reduces the rate of fluid influx to the well bore). The operator is paying less for fuel that is used to pump water. The volume of produced water that has to be disposed of is also reduced. Sodium silicate gels have been used to seal channels, vugs, and thief zones in production wells for many years [-1-193.

Slower polymerization is desirable in order for in-depth penetration of a silicate solution into an oil-bearing formation. Use of sodium silicate gels in injection wells has been sufficient to establish

that the in-situ gelation of sodium silicate is a useful method for increasing the volume of rock contacted by the injected fluid [5,6,15,16]. In an injection well, in-depth penetration of silicate solution followed by gelation allows the permeability of watered-out fractures and thief zones to be greatly reduced. More of the fluid then enters adjacent rock containing higher oil saturations. This increases the rate of oil recovery, improving the economics of secondary oil recovery (water- flooding) and enhanced oil recovery. (This is known as improving the injection profile.)

Each of these applications is discussed in more detail below.

Chemistry

The chemistry of silicate gelation has been discussed in detail by Iler [20]. A more recent review surveys recent approaches to studying silicate polymerization and gel structure and properties, includ- ing nuclear magnetic resonance methods [21]. An S iOz :M20 mole ratio of about 3.3 is generally used for the production of gels and precipitated silicas. Less acid is required for alkali neutralization per mole of silica. In situations where acid con- sumption is a critical cost factor, ratios of about 3.8 have been used.

As the solution SiO2:M20 mole ratio is increased from 1 : 1 or 1:2, an increasing fraction of the silica forms three-dimensional oligomeric species. At a mole ratio of 3.3, typical of that used in commercial gelation processes, 39% of the silica is polymeric. Number average molecular weights of 280 [22] to 300 [23] have been proposed for this polymeric species.

Overall, gelation can be represented by the following three-step process:

(1) Monomer polymerization: condensation of monomeric species to form three-dimensional oligomers and eventually polymers. While interior silicon atoms are only linked to other silicon atoms through oxygen bridges, exterior silicon atoms are also bonded to hydroxyl groups.

(2) Polymer growth: ionization of some of the

J.K. Brochardt/Colloids Surfaces 63 (1992) 189-199 191

hydroxyl groups results in the polymer bearing a negative charge.

Ka S i - O H ~ S i -O- + H + (1)

The pK a of the Si-OH group decreases from 9.8 in monomeric silicic acid to about 6.8 in polymers and gelled particles 1-14]. Intramolecular condensation of these Si-OH (silanol) groups results in formation of new siloxane bonds:

S i - O - + S i - O H --, S i - O - S i + O H - (2)

(3) Gel formation: this results when Eqn 2 is intermolecular. This is the rate-limiting step of silicate polymerization. Intermolecular reaction results in condensation of polymer chains. Chain branching and eventual crosslinking result.

Gelation occurs under weakly basic, neutral, and weakly acidic conditions. The rate of reaction 2 and fraction of polymeric species formed is a function of solution pH and temperature. Gelation accelerators (see Tables 1 and 2) may be used to increase the rate of reaction 2. Group I metal salts act as polymerization accelerators by increasing the ionic strength. Organic species such as glycols

TABLE 1

Inorganic sodium silicate gelation agents a'b

Compound type Cation Anion

Inorganic acids H

Ammonium salts NH~ Group I metal Na, K

salts

Polyvalent metal Ca, Mg, AI, salts Fe, B, Ti,

Cr, Mo, Zn, Pb, Mn, Ba, Zr, Cu, Si

CI, SO4, NO3, PO4, BO 3, SiO4, C O 3

C1, SO4, C O 3

CI, SO4, NO3, HSO4, HCO3, ZnO2, F, SiF6, TiF6, Ti40,2 CI, SO4, NO3, HSO4, HCO3, HCO2, F, PO4, S207, P207, O, OH, TiOa, TiO4, CH3CO2, ZnO 2, CrO4, VO,, V207

aCombinations of the indicated cations and anions, if soluble, form gelation agents that have been used in sodium silicate gelation processes both in subterranean formations and on the surface. bTaken from Ref. [14].

TABLE 2

Organic sodium silicate gelation agents a

Compound type Examples

Acid

Acid salt

Acid derivatives Esters Amides Lactones

Aldehyde

Polyhydric alcohols

Polymers

Surfactants Nonionic

Anionic

Formic, acetic, citric, propionic, maleic, succinic, oxalic

Soluble Ca, Mg, AI, Ba, Zn, and Pb salts of the above acids

Ethyl acetate, ethyl chloroformate Formamide, dimethylformamide Butyrolactone

Formaldehyde, glyoxal, benzaldehyde

Ethylene glycol, propylene glycol, glycerol, starches, sugars

Polystyrene, polyvinyl alcohol, polyesters

Alkylphenol ethoxylates, alcohol ethoxylates Alkylbenzene sulfonate

aTaken from Ref. [14].

can be used to alter the dielectric constant of the solvent and accelerate gelation.

Both organic and inorganic acids are used to optimize the pH for more rapid gelation. Organic acid derivatives, e.g. esters, amides, and lactones, must first be hydrolyzed to an acid. Aldehydes are converted to acids using an oxidant such as hydrogen peroxide or sodium persulfate. The time required for acid formation delays the gelation. This allows the silicate solution to be pumped down a well bore and placed in the desired location within the formation while it is still fluid.

The gelation accelerator may promote silicate precipitation by reaction with the S i -O- groups. This is the mode of action of metal ions such as calcium. Polyvalent metals may be incorporated into the siloxane framework (AI 3+). Alternatively, strongly acid metal salts such as ferric sulfate release acidity upon dissolution. This affects the rate of the above condensation reaction.

Acid gelation systems are tolerant of the presence


of divalent metal cations often found in oilfield formation waters while basic gelation systems are not.

Basic gelation is used to attain longer gelation times and deeper penetration of the well treatment fluids into the rock formation [12,13]. These gels are weaker than those formed by acidic gelation. However, the differential pressures to which they are subjected deep in the reservoir are less than those encountered by the acidic gels used in near- well-bore treatments. Thus gel extrusion from treated rock zones is not a major problem despite the lower gel strength.

through the perforations. The water influx was shut off after this treatment.

An old well was scheduled to be plugged with cement and abandoned. This well was offset to a salt water disposal well in Lea County. The casing and tubing in both wells were severely corroded. Lost circulation was occurring at a depth of 1700 ft. This is above the salt water disposal zone.

Two sequences of sodium silicate solution and rapidly setting cement slurry were pumped into the lost circulation zone. This reduced the rate of fluid loss enough for the well bore to be plugged with regular cement.

Applications

Dri l l i ng - treatment design

Hours or days of expensive drilling rig time can be lost due to lost circulation or rapid fluid influx problems while drilling a well. Severe lost- circulation problems may require thousands of gallons of treatment fluid pumped in over days to seal the zone so that drilling can be resumed. Rapid silicate gelation processes have been used in these situations. Sodium silicate fluid stages are often pumped in alternation with cement slurry. The cement accelerates sodium silicate gelation. The final cement stage forms a plug in contact with the well bore having greater strength and less tendency to syneresis than sodium silicate gels (see below).

Drilling - case studies

In a field treatment of a well in Lea County, New Mexico, the problem was a 900 barrel per hour influx of water into a well bore. The surface pipe (8.63 in) had been set to a depth of 365 ft and a 7.88 in diameter hole drilled to 1840ft. At this depth, rapid fluid influx was encountered. Drilling was continued to 2650 ft, a 7.0 in casing was set and this perforated at 1840 ft. Three silicate solution stages and four cement stages were injected

Sealing channels behind well casing - treatment

design

Owing to the presence of drilling mud and for other reasons, open water channels may be left after cementing the casing to the formation. Fluid can flow through these channels between rock formations (see above). Rapid sodium silicate gelation can be used to seal these channels. A three-step treatment is often used [4]. The zone or channel to be treated is mechanically isolated. The cement sheath is perforated if necessary. Then a metal salt solution that promotes rapid silicate gelation is injected. An inert spacer, usually fresh water, is then injected.

This spacer is followed by injection of the silicate solution. Upon mixing with the metal salt solution, rapid silicate gelation occurs. A small volume of water is then injected. Its purpose is to serve as an inert spacer between the silicate solution and subsequently injected Portland cement slurry. Pre- mature contact of the silicate solution with either the high pH cement slurry or the metal salt solution could cause rapid gelation in an undesired location.

As the cement slurry enters the flow channel, a rapid injection pressure build-up (500 lbfin -2, 3500 kPa) should occur. If it does not, the operator should inject alternate stages of silicate solution and cement slurry until a 5 min pressure build-up is maintained.


Sealing channels behind well casing - case studies TABLE 4

Field results [-4] indicate that silicate gelat ion

can be used successfully to plug flow channels in

the cement sheath between the casing and the Well no. Well problem Results

formation. Some of these well t reatments are sum-

Use of silicate gelation to seal casing leaks - results of Scurry County, Texas, well treatments a

marized in Table 3. 1

Casing leaks can arise in older wells due to 2

corrosion and other problems. Silicate gelat ion

t reatments have been used to seal casing leaks.

When this type of t rea tment was applied to a West 3

Texas well experiencing a rapid casing leak, a 1200

barrel silicate solut ion t rea tment s topped the leak 4

into the well bore. The silicate-plugged interval

held an applied pressure of 500 lbf i n - 2 (3500 kPa). 5

Another well in the same field was experiencing

rapid cement slurry dilution. The opera tor could 6

not p u m p and set enough slurry rapidly enough 7

to br ing set cement to the desired height. A 500

barrel silicate t rea tment allowed the cement to be 8

set to the surface as desired.

Other field studies [1] describing the results of

t reatments designed to stop casing leaks are sum-

marized in Table 4.

Hole in 5.5 in casing at 2400 ft A 207 ft split in 7 in casing extending from 2914-3121 ft A 21 ft split in 7 in casing extending from 2658-2679 ft Casing leak in 7 in casing Casing leak in 7 in casing between 6346 and 6567 ft Casing leak in 7 in casing Casing leak in 5.5 in casing Casing leak in 5.5 in casing between 5445 and 5569 ft

Leak was sealed

The split casing was sealed

The split casing was sealed

Leak was sealed

Leak was sealed after three conventional squeeze cementing treatments failed Leak was sealed

Leak was sealed

Leak was sealed

~Data taken from Ref. 14]. A single three-stage silicate gelation treatment was used in all these wells

TABLE 3

Use of silicate gelation to prevent fluid movement behind well casing - results of Lea County, New Mexico, well treatments a

Well no. Well problem Treatment Results

1 Water flow between 8.63 in and 1 three-stage 5.5 in casing

2 Water flow between 8.63 in and 1 three-stage 5.5 in casing

3 Water flow between 8.63 in and 1 three-stage, overnight well shut-in 5.5 in casing

4 Water flow behind 9.63 in casing 1 three-stage 5 Water flow behind 5.5 in casing 1 three-stage 6 Water flow behind 5.5 in casing 1 three-stage

7 Water flow between 8.63 in and 2 three-stage treatments 5.5 in casing

8 Water flow between 8.63 in and 2 three-stage treatments with 3 cement 5.5 in casing stages

Success after failure of two squeeze cementing attempts Success, water flow was sealed off

Successful, water flow controlled

Successful, water flow controlled Successful, water flow controlled Successful, pressure testing indicated no leaks Successful, water flow was controlled

Successful, water flow was controlled

aData taken from Ref. [4].


P r o d u c t i o n we l l s - t r e a t m e n t des ign

Production wells may be treated with silicate solutions to form gels which reduce the rate of water influx to the well bore. In these situations, the water originates in a zone adjacent to that producing oil. This phenomenon is known as water coning. Injection of silicate solution followed by gelation can be designed to provide barriers up to 50 ft in radius from the well bore [4].

Large treatment radii can result from the injection of large volumes of low viscosity (1-2 cPs) silicate solution. Calculations summarized in Table 5 describe the treatment volume required to treat a formation interval as a function of the designed treatment radius. Techniques for place- ment of the silicate solution in only the water- producing zone have been described [3,5,16,19].

A three-stage treatment method has also been used to reduce water production from adjacent zones and through fractures penetrating the oil- bearing formation. A metal salt solution is first injected followed by a silicate solution. A patent report indicates that aluminum sulfate has been used as the metal salt solution injected prior to sodium silicate [18]. The metal ions promote rapid

TABLE 5

The effect of silicate solution treatment radius on treatment volume and injection pressure a

Treatment volume Treatment radius Pressure drop (barrels) (ft) (%)

0.18 1.27 17.6 1.00 2.99 28.9 3.00 5.18 36.1

10.00 9.45 44.1 100.00 29.89 59.2

1000.00 94.53 74.4 2000.00 133.69 79.0

10 000.00 298.94 89.6 48 743.75 660.00 100.0

aData taken from Ref. [16]. The following assumptions are made in calculating these numbers: (1) fluid displacement is radial; (2) formation porosity is 20%; (3) formation thickness to be treated is 1 ft; (4) well bore diameter is 8 in; (5) well spacing is 40 acres.

gelation upon mixing of these two solutions in- situ. A small volume of Portland cement slurry, usually preceded by an inert water spacer, is then injected. Intermixing promotes rapid silicate gelation.

P r o d u c t i o n we l l s - case s t ud i e s

Results for production wells (Table 6) indicate the water production from both sandstone and limestone formations may be reduced using a two- stage treatment. Stage 1 is the gellable silicate solution. It is followed by injection of an inert fresh water spacer (0.5 barrels for each 1000 ft of well depth) and then by a low water-loss Portland cement slurry. A wellhead pressure increase is indicative of contact of the cement slurry with the silicate solution. When this is observed, fluid is pumped down the well annulus to circulate excess cement slurry out of the well bore.

Six West Texas wells were perforated above the water-oil contact. However, subsequent hydraulic fracturing penetrated the underlying water zone. This resulted in excessive water production. Results of silicate gelation treatments are reported in Table 7. The oil zone was isolated during treatment of the water zone. Major reductions in produced water volume were observed combined with mod- erate to substantial increases in oil production.

In 1975 good production well success rates of about 80% were reported [4].

I n j e c t i o n we l l s - t r e a t m e n t des ign

For a secondary (water flood) or enhanced oil recovery process to be an economic success, two critical criteria must be met: sufficient oil must be produced and this production must occur at an economic rate. The amount of oil produced is determined by two parameters: the oil displacement efficiency of the injected fluid in the contacted rock, and the volumetric sweep efficiency. The displacement efficiency is the percentage of oil in place mobilized when a portion of rock is invaded by the injected fluid. Displacement efficiency is deter-

J.K. Brochardt/Colloids Surfaces 63 (1992) 189-199

TABLE 6

Use of silicate gelation to reduce water influx to production wells a

195

Treatment volume Fluid production (barrels per day) b

Oil Water Produced water: oil ratio b Silicate sol. Cement

Format ion (barrels) (sacks) Before After Before After Before After

Dolomite 300 100 63 120 9 0 0.14 0 Ellenberger limestone 400 100 60 160 60 12 1.0 0.08 Ellenberber limestone 100 300 10 160 40 30 4.0 0.19 Ellenberger limestone i00 300 0 42 70 0 - - 0 Ellenberger limestone 300 50 0 50 I00 20 - - 0.4 Strawn limestone 100 50 3 22 120 110 40 5.0

Sandstone 50 50 6 12 90 < 40 15 < 3.3 Sandstone 25 600 0 100 330 170 - - 1.7

aLimestone and dolomite formations were located in West Texas. Sandstone formations were located in Oklahoma. Data taken from Ref. [5]. bBefore, before sodium silicate injection; after, after sodium silicate injection.

TABLE 7

Results of metal ion-promoted silicate gelation treatment of West Texas wells

Well no.

Oil production (barrels per day) Water production (barrels per day) Produced water:oi l ratio

Before After t reatment Before After treatment Before After treatment

1 5 11 300 11 60 1.0 2 0 66 1750 I0 - - 0.15 3 2 50 700 20 350 0.40 4 10 45 600 40 60 0.89 5 5 40 700 30 140 0.75 6 0 60 400 40 - - 0.67

a 100 barrels of a metal salt solution were injected followed by a fresh water spacer. Then 1000-4000 gallons of silicate t reatment solution were injected followed by another fresh water spacer. Then 100-150 sacks of API class C cement were used to prepare a rapidly setting cement slurry. This was pumped down the well bore and displaced into the rock with brine. Data taken from Ref. [5].

mined by the physical and chemical properties of the injected fluid and its interactions with crude oil, other reservoir fluids, and the reservoir rock. Volumetric sweep efficiency is the percentage of reservoir rock volume invaded by the injected fluid. Volumetric sweep efficiency has two components: areal sweep efficiency and vertical sweep efficiency. The areal sweep efficiency is the percentage of reservoir cross-sectional area contacted by the reservoir fluid. The product of vertical and areal sweep efficiency is the volumetric sweep efficiency.

Treatment fluid injection is often performed over the entire flood water injection interval. Treatment fluid injection rate and pressure are the same as those of the injection water [3]. The high permeability (thief) zones receive the deepest and most thorough plugging by the gel formed in-situ. These treatments are designed to either improve injection profiles or shut off channels from injectors to producers.

To achieve a large treatment radius, large volumes of silicate solution must be injected (Table 5).


As the treatment radius increases, the injection pressure required to maintain a given injection rate increases.

In 1966 injection well treatment success rates of 80-85% were reported [6].

I n j e c t i o n w e l l s - c a s e s t u d i e s

Many results of waterflood injection well treatments have been reported [1,2,5,16,17~. Space per- mits the discussion of only a few of tliese.

Injection well treatment example 1 is an old open-hole completion. Water was being injected at a rate of 1300 barrels per day (BPD) into zones extending in depth from 4218-4546ft (1286- 1386 m). A 100 barrel silicate solution was injected into the 4274-4316 ft (1303-1316 m) portion of the interval. The treatment was pumped in three stages. The first is a concentrated metal salt solution injected to assure rapid subsequent gelation when this preflush mixes with the second stage. This second stage is the silica solution with a viscosity of about 200 cP. This solution may optionally contain up to 1.2 kg 1-1 of solid additives when injected into very high permeability formations. The final injection stage is a small volume of rapidly setting Portland cement slurry.

After the treatment, only 11% of the injection water was entering this treated upper zone while 89% of the water entered the 4350-4360 ft (1327-

1330 m) zone. The effectiveness of the treatment in diverting subsequently injected water into rock containing higher oil saturations can be seen from the production from four offset production wells (Table 8). While producers #3 and #4 were little affected by the treatments, the response from producer # 1 was excellent. The oil production increase was sustained for at least eight months after the injection well treatment. The response of producer #2 was more complicated. While there appeared to be some increase in oil production, the primary response was an increase in water production, suggesting that a fracture may have been generated between the injection well and producer #2.

A West Texas well was treated with metal salt solution, 36 barrels of silicate solution, an inert spacer fluid, and a slurry prepared from 200 sacks of Portland cement. Prior to treatment, 60% of the 900 barrel daily water injection volume was entering the zone above the oil-bearing formation. Injec- tion pressure was 800 lbf in-2. After treatment, all of the 300 barrels per day injection water entered the oil-bearing zone at an injection pressure of 1100 lbf in- 2.

The 13 130 acre Willard Unit in the Wasson Field of West Texas was under waterflood when it was discovered that excessive volumes of injection water were entering a brine zone immediately below the oil-bearing formation 1-17]. This brine zone was isolated from the oil-bearing zone so

TABLE 8

Production results from offset production wells after treatment of injection well with sodium silicate a,b

Well status

Well HI Well #2 Well #3 Well #4 Total

Oil Water WOR Oil Water WOR Oil Water WOR Oil Water WOR Oil Water WOR

Before treatment 1 31 31 20 52 2.6 8 4 0.5 7 15 2.1 36 102 2.8

Months after treatment 2 19 82 4.3 24 30 1.2 8 2 0.25 6 15 2.5 57 129 2.3 6 17 56 3.3 9 200 22.2 5 1 0.2 5 16 3.2 36 273 7.6 8 32 116 3.6 27 250 7.1 6 2 0.3 4 16 4.0 69 383 5.6

aData taken from Ref. [5]. See text for description of well treatment. Oil and Water indicate production in barrels per day; WOR is produced water: oil ratio. bDistances from injector are: well HI, 900 ft (274 m); well #2, 1000 ft (305 m); well #3, 800 ft (245 m); well #4, 1000 ft (305 m).


fluid could be injected only into the aqueous fluid zone of an injection well. 117 barrels of sodium silicate containing silica flour was pumped into the 35 ft zone. The in-situ silica gelation reduced the permeability of the brine zone.

A hydraulic fracturing treatment was then used to increase the permeability of the oil-bearing zone. The combined effect of the two well treatments was to decrease injection water entry into the brine zone from 88% to an undetectable level. Injection pressures and rates suggested that the silica gel plug was still partially effective more than a year later. Ten wells were treated using this method, described in detail in Ref. [17].

This method was not highly effective for plugging fractures because the sodium silicate gel had insufficient strength at high shear rates [17]. In these situations, silicate injection was followed by injection of a small volume of cement slurry which, after hardening, successfully plugged fractures.

Discussion

Silicate gelation treatment permanence

Review of Refs [1-3,5,6 and 19] indicates that properly designed in-situ gelation well treatments are long-lasting. The gels are stable to bio- degradation. Gel syneresis is usually not a major concern. The gel plugs, located in the tortuous flow channels of the rock, do not permit much migration of low viscosity aqueous fluid when syneresis occurs. Consequently, enough gel usually remains in place to maintain the desired low permeability. If sufficient syneresis occurs, some gel extrusion may result. More rapid syneresis at elevated temperatures (> 177 ° C, 350 ° F) [4] limits the application of in-situ silicate gelation technology in high temperature environments such as steam injection wells. In higher permeability rock, such as thief zones encountered during drilling, cement may be pumped in after the sodium silicate to accelerate gelation and minimize the effects of syneresis and extrusion by placing a cement plug adjacent to the well bore.

It is extremely rare that the dissolution of the gel is required [16]. Should this be necessary, hydrofluoric acid or mixtures of hydrofluoric and hydrochloric acids can be used to dissolve the gel [14]. Chemistry relating to this process has been discussed [24]. Strongly basic solutions will also reverse the gelation process [14]. Generally 5-20% sodium hydroxide solutions are used.

Competitive methods of matrix plugging

The above results and literature references indicate the wide utility of in-situ polymerization of silicate solutions to reduce rock permeability and solve a variety of oilfield problems. Competitive materials to silicate solutions do exist. Cementing has sometimes been used to plug thief zones encountered while drilling. Squeeze cementing has been used to seal flow channels behind casing. The low viscosity of silicate solutions is often an advantage in this application.

The in-situ cross-linking of organic polymers have been used in production well treatments to reduce water influx into well bores. This technology has been reviewed recently [25,26]. Both sodium silicate and some polymer systems offer good control of gelation time. The lower viscosity of the sodium silicate systems is an advantage in mixing and injecting the treatment fluid. Careful mixing of organic polymers is required to assure complete dissolution and the absence of microscopic solid particles which can prematurely plug flow channels and result in insufficient treatment depth.

The same type of in-situ organic polymer cross- linking has been used to treat injection wells to improve injection profile. Treatment radius is usually more limited than that provided by in-situ silicate gelation due to shorter organic polymer gelation times. Lignosulfonate gelation, usually promoted by trivalent chromium, is an exception to this generalization [27]. Long gelation times are attainable. The in-situ gelation of blends of silicate and lignosulfonate have been evaluated in the field [28]. One advantage of the lignosulfonate technology is that it can be used in high tem-


perature situations [29,30] such as steam injection wells in which silicate gel syneresis is too rapid to permit silicates to be used.

The in-situ polymerization of a mixture of a reactive monomer such as acrylamide and a bifunc- tional cross-linking monomer such as N,N'- dimethylenebis(acrylamide) offers another alterna- tive to the use of sodium silicate gelation [31]. These treatments generally achieve limited rock penetration and are considered most suitable for production well treatments to limit water influx to the well bore.

The use of various organic resins to seal thief zones near injection wells has been described [25]. While these methods could be considered competitive to in-situ sodium silicate gelation, field use appears to be limited.

Conclusions

Field results indicate that in-situ silicate gelation can be used to solve a number of problems when drilling, completing, and operating injection and production wells in oil and gas fields. These problems include undesired fluid communication between rock zones caused by channels behind well casing, well casing leaks, unwanted water influx to production wells, and treatment of injection wells to improve volumetric sweep efficiency and the rate of oil production. The ability to control gelation times over a wide range of temperatures makes in-situ silicate gelation processes suitable for application over a wide range of temperatures.

References

1 W.F. Hower and J. Ramos, J. Pet. Technol., 9 (1957) 17. 2 W.F. Hower and J. Ramos, Selective Plugging of Injection

Wells by In Situ Reactions, API Paper No. 754-G, 1955. 3 R.F. Rensvold, H.J. Ayres and W.C. Carlisle, Completion

of Wells to Improve Water-Oil Ratios, Paper No. SPE 5379 presented at the 1975 California Regional Meeting of the Society of Petroleum Engineers of AIME, Ventura, CA, 1975.

4 C.W. Smith, B. Mody and T.D. Pugh, A Special Sealant Process for Subsurface Water, presented at the Southwest

Petroleum Short Course, Texas Tech University, Lubbock, TX, April 20-21, 1978.

5 R.C. Cole, B. Mody and J. Pace, Water Control for Enhanced Oil Recovery, Paper No. OE81 SPE 10396.1 presented at the Offshore Europe 81 Conference of the Society of Petroleum Engineers of AIME, Aberdeen, Scotland, September 15-18, 1981.

6 R.R. Koch and J.E. Diller, An Economical Large Volume Treatment for Altering Water Injectivity Profiles, Paper No. API 851-40-A presented at the Mid-Continent District, Division of Production, American Petroleum Institute, Dallas, TX, March 30-April 1, 1966.

7 H.C. McLaughlin, U.S. Patent 3,202,214, 1965. 8 J. Ramos, R.R. Koch and H.C. McLaughlin, U.S. Patent

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in-situ gelation of silicates in drilling, well completion and oil production

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