Method for cleaning wellbore surfaces using coiled tubing with a surfactant composition

A method for cleaning a wellbore plugged with deposits of heavy hydrocarbons and finely-divided inorganic solids by circulating a surfactant composition containing an alkyl polyglycoside, an ethoxylated alcohol, a caustic and an alkyl alcohol through the wellbore with a coiled tubing.

BACKGROUND OF THE INVENTION 
1. Field of the Invention 
This invention relates to the removal of plugging deposits comprising heavy 
hydrocarbonaceous materials and finely divided inorganic solids from a 
plugged wellbore using a coiled tubing and an alkyl polyglycoside 
surfactant composition. 
2. Background of the Invention 
Mixtures of oil, gas and water are frequently produced from oil fields. 
Processes for treating such mixtures to produce separate streams of oil, 
gas and water are well known. Typically the oil is separated and recovered 
as a product; the gas may be separated and recovered as a product; or, 
alternatively, the gas may be injected into a gas cap above an oil-bearing 
zone, into an oil-bearing zone or the like as recovered or as a miscible 
injectant which comprises the produced gas adjusted by the addition of 
nitrogen, carbon dioxide, hydrocarbons containing from one to about five 
carbon atoms and the like to adjust the specific gravity of the miscible 
injectant. The water may be recovered for reinjection or disposal by other 
means as known to those skilled in the art. 
The separation is frequently accomplished in large settling tanks where the 
oil, gas and water are allowed to gravimetrically separate. 
In many instances, the mixture of oil, gas and water is passed to central 
processing facilities for separation with the oil being recovered as a 
product and with the gas being either wholly or partially recovered as a 
product also. In some instances, the gas is distributed to injection wells 
and injected; and, in some fields, the water is similarly recovered, 
passed to injection wells and injected into the formation for the disposal 
of the water, for secondary oil recovery and the like. 
It has been found, when such operations are conducted, especially when 
corrosion inhibitors are used in the lines leading from the wells to the 
central processing facility and the like, that, over a period of time, 
deposits of heavy hydrocarbonaceous materials and finely divided inorganic 
solids deposit on the inner surfaces of the lines. These deposits 
typically comprise finely-divided inorganic particles such as produced 
solids which may include hydraulic fracturing proppant, formation sand, 
formation fines and precipitates of materials such as iron sulfide. These 
particles become coated with corrosion inhibitor or other 
hydrocarbonaceous materials and subsequently become coated with additional 
quantities of heavy hydrocarbonaceous material in the flowlines, settling 
tank and the like. These deposits are referred to herein as "schmoo". The 
schmoo is a slimy, oily substance which adheres to almost any surface with 
which it comes in contact, and is difficultly removed from any surface and 
particularly from the inner surfaces of flowlines, water injection lines 
into the formation, wellbore surfaces and the like. The material is 
removable by pigging from flowlines which are of a sufficient size and 
configuration that pigs can be run through the lines. Such lines are 
routinely cleaned by pigging. Other lines, such as injection lines into 
wells, small diameter flowlines, the settling tank surfaces and formation 
surfaces are not accessible by pigging operations and, accordingly, the 
schmoo accumulates on the inner surfaces of these pipe lines, on the 
surfaces of the well and the like. The schmoo can also accumulate to a 
thickness such that it flakes off the inner surfaces of the pipe and 
deposits in the lower portion of a well, the lower portion of a line or 
the like, and plugs the line or the formation in fluid communication with 
the pipe. This can result in the necessity for cleaning operations such as 
the use of coiled tubing with the injection of organic solvents such as 
mixtures of diesel oil and xylene, to clean such deposits from wellbores. 
Such deposits in wellbores are particularly common in wells which are used 
for alternating water and gas injection. In such wells, the schmoo dries 
on the inner surfaces of the tubing during gas injection and subsequently 
cracks and falls into the wellbore, thereby eventually plugging the 
wellbore, sometimes to a considerable depth. 
In view of the difficulties created by the deposit of such materials, a 
continuing search has been directed to the development of an economical 
method for the removal of such deposits, especially deposits which have 
dried and fallen into the wellbore or otherwise been deposited into the 
wellbore to the extent that the wellbore is plugged with such deposits. 
SUMMARY OF THE INVENTION 
According to the present invention, it has been found that such plugged 
wells can be unplugged by positioning a coiled tubing to extend from a 
surface into the wellbore; injecting a surfactant composition consisting 
essentially of an aqueous solution containing from about 0.1 to about 10.0 
weight percent of an alkyl polyglycoside surfactant selected from alkyl 
polyglycosides containing alkyl groups containing from about 8 to about 19 
carbon atoms and mixtures thereof; from about 0.1 to about 10.0 weight 
percent of an ethoxylated alcohol selected from the group consisting of 
ethoxylated alkyl alcohols containing from about 6 to about 16 carbon 
atoms in the alkyl alcohol and from about 2 to about 6 ethylene oxide 
groups and mixtures thereof, and ethoxylated alkyl phenols containing from 
about 8 to about 14 carbon atoms in the alkyl group and from about 2 to 
about 8 ethylene oxide groups and mixtures thereof, and mixtures of the 
ethoxylated alkyl alcohols and the ethoxylated alkyl phenols; from about 
0.5 to about 10.0 weight percent of a caustic selected from the group 
consisting of sodium hydroxide, potassium hydroxide, ammonium hydroxide 
and mixtures thereof; and, from about 0.1 to about 6.0 weight percent of 
at least one alkyl alcohol containing from about 4 to about 6 carbon 
atoms, through the coiled tubing into contact with the deposits and 
circulating at least a portion of the surfactant solution through the 
wellbore.

DESCRIPTION OF PREFERRED EMBODIMENTS 
In the discussion of the figures, various pumps, valves and the like 
necessary to achieve the flows described have not been shown in the 
interest of conciseness. All concentrations are by weight percent of 
active ingredient in the aqueous solution unless otherwise stated. 
The surfactant composition of the present invention consists essentially of 
an aqueous solution containing from about 0.1 to about 10.0 weight 
percent, and preferably from about 0.2 to about 4.0 weight percent, of an 
alkyl polyglycoside surfactant selected from alkyl polyglycosides 
containing alkyl groups containing from about 8 to about 19 carbon atoms 
and mixtures thereof; from about 0.1 to about 10.0 weight percent of an 
ethoxylated alcohol selected from the group consisting of ethoxylated 
alkyl alcohols containing from about 6 to about 16 carbon atoms in the 
alkyl alcohol and from about 2 to about 6 ethylene oxide groups and 
mixtures thereof, and ethoxylated alkyl phenols containing from about 8 to 
about 14 carbon atoms in the alkyl group and from about 2 to about 8 
ethylene oxide groups and mixtures thereof, and mixtures of the 
ethoxylated alkyl phenols and the ethoxylated alkyl alcohols; from about 
0.5 to about 10.0 weight percent of a caustic selected from the group 
consisting of sodium hydroxide, potassium hydroxide, ammonium hydroxide 
and mixtures thereof; and, from about 0.1 to about 6.0 weight percent of 
at least one alkyl alcohol containing from about 4 to about 6 carbon 
atoms. Preferably, the alkyl polyglycoside, ethoxylated alcohol, and alkyl 
alcohol comprise from about 0.5 to about 6.0 weight percent of the aqueous 
solution. Desirably, the alkyl polyglycoside surfactant has a DP number 
from about 1.30 to about 1.80. The DP number is a measure of the degree of 
polymerization of the alkyl polyglycoside as defined in Alkyl 
Polyglycosides: Technology, Properties and Applications, edited by 
Karlheinz Hill, Wolfgang Von Rybinski and Gerhard Stoll, VCH 
Verlagegesellschaft Mbh, Weinhein (Federal Republic of Germany) and VCH 
Publishers Inc., New York, N.Y. 1997, pp 11-12. 
The alkyl polyglycoside surfactant may comprise a first surfactant 
consisting essentially of an alkyl polyglycoside selected from the group 
consisting of alkyl polyglycosides containing alkyl groups containing an 
odd number of carbon atoms from about 9 to about 13 carbon atoms and 
mixtures thereof, and having an oligomer distribution from 1 to 12, and a 
second surfactant consisting essentially of alkyl polyglycosides selected 
from the group consisting of alkyl polyglycosides containing alkyl groups, 
a major portion of which are even numbered alkyl groups which contain from 
about 12 to about 18 carbon atoms and having an oligomer distribution from 
1 to 12. Desirably, the alkyl polyglycoside surfactant contains from about 
20 to about 90 mole percent of the first surfactant. 
The second surfactant may also contain alkyl polyglycosides containing 
alkyl groups containing odd numbers of carbon atoms from about 9 to about 
19 carbon atoms. Either odd-numbered or even-numbered alkyl groups may be 
used in either the first or the second surfactant as desired to optimize 
the surfactant properties. 
The even numbered alkyl groups are representative of naturally occurring 
alkyl groups and tend to have a higher pour point and are less convenient 
to use as surfactants in wellbore operations and the like. Such 
surfactants are much more viscous and tend to gel at lower temperatures 
and are otherwise more difficult to handle than the corresponding alkyl 
polyglycosides containing alkyl groups containing an odd number of carbon 
atoms. The alkyl groups containing odd numbers of carbon atoms are 
representative of refinery product streams and are not naturally 
occurring. 
Preferably, the ethoxylated alcohol is present in an amount equal to from 
about 0.2 to about 4.0 weight percent. The ethoxylated alkyl alcohol may 
be selected from ethoxylated linear alkyl alcohols, branched alkyl 
alcohols, Guerbet alcohols, mixtures thereof, and the like. The 
ethoxylated alkyl phenol alcohols may contain linear, branched, Guerbet or 
a mixture of linear, branched and Guerbet alkyl groups. It is preferred 
that the ethoxylated alcohol be selected from ethoxylated alkyl alcohols 
containing from about 8 to about 16 carbon atoms in the alkyl alcohol and 
from about 2 to about 6 ethylene oxide groups. 
The caustic material is desirably present in an amount equal to from about 
1.0 to about 5.0 weight percent of the aqueous solution. The caustic is a 
necessary component of the surfactant composition since it is required in 
combination with the alkyl polyglycosides and the ethoxylated alcohol to 
effectively dissolve and remove the deposits. 
It is also preferred that the alkyl alcohol be present in an amount equal 
to from about 0.2 to about 3.0 weight percent. The alkyl alcohol may be a 
linear or branched alkyl alcohol. The alcohol facilitates mixing and 
aqueous surfactant composition stability. In the absence of the alcohol, 
an alkyl polyglycoside surfactant layer and a caustic layer may form in 
the surfactant composition. While all of the ingredients are present in 
each layer, they are present in different proportions. With the alkyl 
alcohol, a homogenous mixture is readily achieved and maintained. 
The surfactant composition comprises primarily water. Accordingly, it is 
less economical to transport the surfactant composition in this form. It 
is preferred that the surfactant composition be produced at the location 
where it is to be used by dilution of an aqueous surfactant concentrate. A 
concentrate of the aqueous surfactant composition can be produced for 
dilution with an aqueous solution to produce the surfactant composition. 
The concentrate composition comprises an aqueous solution containing from 
about 4.0 to about 20.0 weight percent of an alkyl polyglycoside 
surfactant selected from alkyl polyglycosides containing alkyl groups 
containing from about 8 to about 19 carbon atoms and mixtures thereof; 
from about 1.0 to about 15.0 weight percent of an ethoxylated alcohol 
selected from the group consisting of ethoxylated alkyl alcohols 
containing from about 6 to about 16 carbon atoms in the alkyl alcohol and 
from about 2 to about 6 ethylene oxide groups and mixtures thereof and 
ethoxylated alkyl phenols containing from about 8 to about 14 carbon atoms 
in the alkyl group and from about 2 to about 8 ethylene oxide groups and 
mixtures thereof and mixtures of the ethoxylated alkyl alcohols and the 
ethoxylated alkyl phenols; from about 4.0 to about 30.0 weight percent of 
a caustic selected from the group consisting of sodium hydroxide, 
potassium hydroxide, ammonium hydroxide and mixtures thereof; and from 
about 0.5 to about 10.0 weight percent of at least one alkyl alcohol 
containing from about 4 to about 6 carbon atoms. Concentrated compositions 
containing more of the materials tend to gel and are more difficult to 
handle and to dilute to produce the surfactant composition. Preferably, 
the concentrate composition is from about 4.0 to about 12.0 weight percent 
alkyl polyglycoside surfactant in the aqueous solution; from about 1.0 to 
about 8.0 weight percent ethoxylated alcohol in the aqueous solution; from 
about 6.0 to about 22.0 weight percent caustic in the aqueous solution; 
and from about 1.0 to about 10.0 weight percent alcohol in the aqueous 
solution. The alkyl polyglycosides and other materials are as described in 
conjunction with the surfactant composition above. 
While the surfactant compositions may be used at substantially any 
temperature between their freezing points and their boiling points, it is 
preferred that they be used at temperatures above about 120.degree. F. At 
lower temperatures, longer contact times may be required to remove the 
schmoo. 
The concentrate may be used at full strength or at any desired dilution. 
It is preferred that the concentrate contain a suitable hydrotrope to 
improve the phase stability of the concentrate and the surfactant 
composition. The hydrotrope may be a hydrotrope such as monosodium salt of 
N-lauryl-.beta.-iminodipropionic acid, an alkyl polyglycoside containing 
linear or branched alkyl groups containing from about 4 to about 8 carbon 
atoms and the like. 
The surfactant composition functions as an alkaline cleaner which 
solubilizes and disperses the schmoo by suspending it in the surfactant 
composition so that the surfactant composition and suspended particulates 
can be injected directly into subterranean formations without damage to 
the formation or circulated out of the wellbore. 
Since the surfactant composition is a foaming surfactant, it is desirable 
in many applications to add a suitable quantity of an antifoaming compound 
such as, for example, a silicon-based antifoam compound. Preferably, the 
antifoaming additive is added at a concentration of about 10 to about 100 
ppm to the aqueous solution containing the caustic before addition of the 
other materials. 
Alkyl polyglycoside surfactants consist of a polar glucose head and an 
organic carbon chain off of the hemiacetal linkage. A representation of 
the molecule is shown in FIG. 1. There are two ether oxygens and three 
hydroxyl groups per glucose unit, plus a terminal hydroxyl group. The 
lipophilic portion of the molecule resides in the alkyl chain R. R can be 
a linear or branched alkyl group containing from about 8 to about 18 
carbon atoms or a Guerbet alkyl containing from about 9 to about 19 carbon 
atoms. The polymerization reaction can provide oligomer distributions from 
1 to 12 (i.e. x=0 to x=11). 
In the use of the surfactant composition, it is desirable that the ratio of 
components be adjusted by testing with the deposits to be removed to form 
a Type III microemulsion in the wellbore. Such microemulsions are referred 
to as Windsor Type III or middle phase microemulsions and are described in 
some detail in "Micellization, Solubilization and Microemulsions", Vol. 2, 
K. L. Mittal, Plenum Press, New York, 1977. In FIG. 2, Type I, Type II and 
Type III microemulsions are shown. FIG. 2(a) shows oil (o) and water (w) 
containing surfactants in a container 10 to a level 11 and having an 
interface 12. In FIG. 2(b), a Type I microemulsion 13, which is an 
oil-in-water microemulsion, is shown below an excess oil layer (o). Such 
microemulsions are water soluble and contain quantities of solubilized 
oil, as shown by the level of the new interface 12' which is above the 
original interface 12. In FIG. 2(c), a Type II microemulsion 14, which is 
a water-in-oil microemulsion, is shown above an excess water layer (w). 
Such microemulsions are oil soluble and contain quantities of solubilized 
water as shown by the level of new interface 12' which is below the 
original interface 12. FIG. 2(d) shows a Type III microemulsion 15, which 
is located between the excess oil (o) and excess water (w) phases and 
extends above and below original interface 12. Such Type III 
microemulsions are preferred for pipe and wellbore cleaning operations 
since their interfacial tensions and solubilization properties toward both 
oil and water can greatly facilitate the removal of both from wellbores, 
pipes or other surfaces. Since it is desirable that the deposits be 
dissolved and removed in the aqueous surfactant, it is desirable that the 
aqueous surfactant be formulated to produce a Type III microemulsion in 
the wellbore or pipe. Such microemulsions are much more effective in 
dissolving hydrocarbonaceous materials in the presence of aqueous 
solutions than either Type I or Type II microemulsions. It is not 
necessary that the composition be adjusted to form the desired Type III 
microemulsion, but it is considered that the surfactant composition is 
more effective when adjusted to form a Type III microemulsion in the 
treated area. 
A typical oil field operation which produces such deposits is shown in FIG. 
3. In FIG. 3, an oil-bearing formation 10 is shown positioned above a 
water-bearing formation 12 and beneath a gas cap 14. Gas cap 14, in turn, 
is positioned beneath an overburden 16 and beneath a surface 18. Oil, gas 
and water are produced from oil-bearing formation 10 through a line 30. In 
the operation of the oil field as shown, sea water may be injected into 
water-bearing formation 12 as shown by an arrow 20, a miscible gas may be 
injected into gas cap 14 as shown by arrow 24, and produced water may be 
injected into water-bearing formation 12 as shown by an arrow 22 with 
produced gas being optionally introduced into gas cap 14 via a line 26. 
The produced oil, gas and water stream from oil-bearing formation 10 is 
passed via a line 30 to an oil, water and gas separator 32. Separator 32 
is typically a relatively large vessel to allow a quiescent zone for the 
gravimetric separation of oil, gas and water. The gas may be recovered, as 
shown, through a line 38 and passed to a natural gas liquids separation 
zone 40. In natural gas liquids separation zone 40, natural gas liquids 
such as butanes, pentanes and the like may be recovered and passed via a 
line 42 to combination with the crude oil which is separated and recovered 
from separator 32 via a line 36. The crude oil and natural gas liquids in 
line 36 are passed to sale or use as a crude oil product. The lighter 
gases from natural gas liquids separation unit 40 may be passed to use as 
a natural gas product via a line 44 or, as shown, may be combined, via a 
line 45, with a portion of the natural gas recovered from separator 32 via 
a line 38' and passed via line 26 back to injection into the gas cap 14. 
The produced water is recovered through a line 34 from separator 32 and 
may be passed with or without further treatment back to water formation 12 
via line 22. 
The operations above have been discussed very generally since such 
operations are considered to be well known to those skilled in the art. 
Deposits of heavy hydrocarbonaceous materials in combination with finely 
divided inorganic particulates may occur in lines such as line 30 through 
which the oil, gas and water mixture is passed to separator 32, in line 34 
which is a produced water injection line, or in any other lines wherein 
water is present, such as the tubing in water injection and water and gas 
injection wells and in the formations in fluid communication with such 
wells. The deposits are generally believed to comprise a finely divided 
inorganic particle which may comprise hydraulic fracturing proppant 
(approximately 1000 microns), formation sand (approximately 100 microns), 
formation fines (approximately 10 microns) and precipitates such as iron 
sulfide (approximately 1 micron). These finely divided inorganic solids 
form a site which may become coated with a corrosion inhibitor or with 
heavy hydrocarbonaceous materials. These materials are found in crude oil 
and in many instances are believed to selectively adhere to the inorganic 
particulate particles. The net result is that these coated particles, 
referred to herein as "schmoo", adhere to pipe surfaces, separator 
surfaces, formation surfaces, equipment surfaces and nearly any other 
surface with which they come in contact. They can accumulate over 
relatively short periods of time to plug formations, lines and the like. 
As discussed previously, they also contribute to accelerated corrosion of 
flowlines, injection lines and the like. The larger particles are 
separated in the settling tank. The smaller particles such as coated iron 
sulfide, finely dispersed oil and the like are primary constituents of the 
schmoo in pipes and other surfaces downstream from the separation tank. As 
a result, these materials, when dispersed in the surfactant composition, 
can be passed into the formation. 
A schematic of a typical particle of schmoo is shown in FIG. 4. The 
particle comprises an inorganic solid particle nucleus 46 surrounded by a 
corrosion inhibitor film 48 and by a layer of oil 50. It is believed that, 
in the oil/water separation step, the oil, which may be heavier 
hydrocarbonaceous materials, may be selectively retained on the particles 
with the lighter hydrocarbonaceous materials floating more readily to the 
surface for recovery as oil. In any event, a sticky, oily mass of this 
material is typically produced in oil field operations, is readily 
transported into operating lines, formations and the like, and creates 
significant operational problems. 
In FIG. 5, a section of a pipe 52 which is encased in insulation 56 and a 
sheathing 58 is shown. Pipe 52 has a center axis 60 and has become coated 
on its inner surfaces by a layer of schmoo 54. The schmoo has resulted in 
the establishment of colonies of bacteria which can generate sulfides and 
other corrosive materials which are effectively sheltered beneath the 
layer of schmoo from treatment by conventional biocide materials. Pits 62, 
as shown, are formed by the bacteria and can lead to early pipe failure. 
Such pipe failure is typically localized so that the life of the pipe is 
greatly shortened. 
In FIG. 6, an injection well 68 for water injection or alternate water and 
gas injection is shown. The injection well comprises a wellbore 70 and 
includes a casing 78 which is cemented in place in wellbore 70 with cement 
80. The well includes a well head 88, which is adapted for the injection 
of water or alternate slugs of water and gas into well 68. A production 
tubing 84 extends downwardly from well head 88 inside casing 78 to a depth 
near a formation 76 into which water and/or gas is to be injected. Casing 
78 has been perforated by perforations 82 in formation 76 to permit the 
injection of water and/or gas into formation 76. It will be understood 
that well 68 may be completed with or without casing through the formation 
of interest, as known to those skilled in the art. In other words, the 
well in the formation of interest may be open hole and the injection may 
be made directly into formation 76. A packer 86 is positioned between 
tubing 84 and casing 78 to prevent the flow of liquids or gas upwardly 
between tubing 84 and casing 78. To inject water into the well a valve 92 
in a water injection line 90 is opened and a valve 96 in a gas injection 
line 94 is closed. Water is then flowed downwardly through tubing 84 and 
into formation 76. When produced water, for instance from an oil/gas/water 
separator, is injected it has been found that schmoo deposits on the inner 
surfaces of the tubing, the casing below packer 86, the perforations, and 
portions of the formation. 
These deposits can become a problem in wells which are used only for water 
injection. The deposits can accumulate to a level sufficient to restrict 
flow and, as discussed previously, can accumulate in the lower portions of 
the well to eventually plug the well and can result in the formation of 
spots of active bacteria which may result in the formation of pits in 
tubing 84 which may eventually extend through tubing 84. Accordingly, it 
is necessary to clean such deposits from the inside of casing 78 below 
tubing 84 and the inside of any open-hole portion of well 68 extending 
into or through formation 76. Similarly, such deposits can form in the 
near wellbore portions of formation 76 and restrict flow into the 
formation. Such deposits can be removed by a method consisting essentially 
of circulating the aqueous surfactant composition described above through 
the well. 
In some wells, especially injection wells used for alternate water and gas 
injection, the schmoo may be deposited in the well and flake off or 
otherwise be deposited in the bottom of the well to a substantial depth. 
When such deposits reach a depth such that contact with the surfactant 
composition at the top of the deposit is not effective to remove the 
deposits, or when the deposits comprise a sufficient quantity of 
finely-divided inorganic solids to constitute a plugging problem after 
removal of the heavy hydrocarbonaceous materials, then it is necessary to 
use other treatments to remove the schmoo deposits. When the deposits are 
of a sufficient depth which varies based upon a variety of factors, such 
as whether the deposits are consolidated or semi-consolidated, the soaking 
method discussed above is less effective since only a small area at the 
top of the plugging deposits can be contacted by the surfactant 
composition. 
In such instances coiled tubing treatments, which circulated solvents such 
as xylene and diesel oil in the well, have been used to remove the 
plugging deposits. It has now been discovered that the surfactant 
composition may be used in such coiled tubing treatments. 
As shown in FIG. 6, plugging deposits have accumulated in well 68 to a 
depth 98 which renders their removal by the soaking method difficult. As 
shown, a coiled tubing 102 extends through tubing 84 into well 68 to a 
depth near the top of the plugging deposits. The surfactant solution is 
injected through coiled tubing 102, preferably at a velocity sufficient to 
maximize the mechanical cleaning action of the coiled tubing and agitate 
the top layer of the plugging deposits. The coiled tubing may be, and 
desirably is, equipped with a washing tool, a jet or other suitable tool 
as known to the art. The injected surfactant composition containing 
dissolved or entrained heavy hydrocarbonaceous materials and 
finely-divided inorganic solids is circulated upwardly through the annulus 
between the outside of the coiled tubing and the inside of the production 
tubing 84 for recovery at the surface via line 90 or line 94. A variety of 
circulation arrangements may be used and the coiled tubing can be raised 
and lowered for multiple passes through the well. As known to those 
skilled in the art, such circulation can be used to remove particulates 
from the well. The recovered surfactant composition may be filtered or 
otherwise cleaned or adjusted prior to re-injection or all fresh 
surfactant composition may be used. The use of coiled tubing for such 
operations using other materials is well-known to those skilled in the art 
and need not be described in further detail. 
As the plugging deposits are progressively removed, the coiled tubing may 
be lowered to keep the surfactant composition injection point near the top 
of the plugging deposits until substantially all of the plugging deposits 
have been removed. The well may then be treated to remove schmoo deposits 
from the near wellbore formation by injecting and maintaining surfactant 
composition in a near wellbore area 100 for a period of time from about 1 
hour to about 4 hours. The surfactant composition is then flushed into the 
formation by injection of a quantity of an aqueous solution. 
EXAMPLE 
An evaluation of various dispersant formulations was done using a cleaning 
test. Metal coupons (10 cm.times.15 cm strips of carbon steel sheet stock) 
were first weighed. Schmoo was then applied to the coupons, and then the 
schmoo-coated coupons were baked at 110.degree. F. in an oven. This 
process was repeated until the schmoo layer was about 6 mm (0.25") thick. 
The coupons were then reweighed--the difference being the weight of schmoo 
applied. Each coupon was then submerged in 30 cc of test dispersant held 
in a 42-cc vial; the coupons were then allowed to soak undisturbed for the 
prescribed length of time (typically 3 hours). During this soak time, the 
temperatures of the vials were maintained at 150.degree. F. in an air 
bath. After the prescribed time, the vials were placed in a rotator (held 
in a 60.degree. angle from the horizontal plane) and then rotated at 24 
rpm for 15 minutes. Rotation of the vials provided a controlled and 
reproducible amount of agitation to remove any lightly adhering schmoo 
residue. The coupons were then removed, dried, and reweighed. The 
difference between the pre- and post-clean weights was the amount of 
schmoo removed by the dispersant. The amount of schmoo removed divided by 
the amount of schmoo applied was the "schmoo removal efficiency" for that 
combination of formulation, soak time, and temperature. Such cleaning 
tests were performed for various dispersant formulations, with each test 
series being repeated three times to test reproducibility. When testing 
different formulations, typically the total weight % of the alkyl 
polyglycoside (APG)+ethoxylated alcohol (EA) was held constant, and the 
relative amounts of the two surfactants were varied (0&lt;APG/(APG+EA)&lt;1). 
The results were plotted as the schmoo removal efficiency versus mole % of 
APG for the dispersant and are shown in FIG. 7. Good schmoo removal was 
achieved in all tests shown. The dispersant contained 1.5 weight percent 
of APG and EA, 1.5 weight percent of N-Butanol, and 2.75 weight percent of 
sodium hydroxide. 
Having thus described the present invention by reference to certain of its 
preferred embodiments, it is pointed out that many variations and 
modifications are possible within the scope of the present invention. Many 
such variations and modifications may be considered obvious and desirable 
by those skilled in the art based upon the foregoing description of 
preferred embodiments.