Note: Descriptions are shown in the official language in which they were submitted.
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25053-351
This invention relates to a method for treating earthen formations
which contain clay, shale or other fines to improve the flow of fluid through
the formation. More particularly the invention relates to such a method
wherein the decrease in the permeability of the formation upon contact with
water is minimized and the permeability can even be increased.
Many earthen formations contain clays, shales, and/or fines, such
as silt sized or smaller particles. The formation can be exposed at the
surface of the earth, e.g., roadbeds, hillsides and the like, or it can be
a subterranean formation, including both those just below or near the
surface in which formations, footings or walls of structures rest, and
those a substantial distance below the surface from which oil, gas or
other fluids can be produced.
When contacted by water, water-sensitive clays and shales,
for example montmorillonite, can swell and decrease the permeability of
the formation. Other non-clay fines often are free to move and tend to be
carried along with a fluid flowing through the formation until they become
lodged in pore throats, i.e., the smaller interstices between the grains of
the formation. This at least partially plugs the openings and reduces the
permeability of the formation. Thus finely divided particulate matter can
obstruct flow through a formation by swelling, migration or both.
Wren footings or foundations of buildings rest in formations
containing such fines, damage or at least great inconvenience often stems
from the inability of the earth to carry away water due to decreased
permeability of the formation when wet. Likewise, drainage of formations
surrounding septic tanks and underlying roadbeds is desirable.
One common instance in which fluids are produced from or injected
into formations is in connection with the production of oil. Often it is
desired to treat oil-bearing formations to increase the amount of oil
recoverable therefrom. One popular method is to inject steam into the
formation. The steam can be either dry or wet, i.e., it can contain a liquid
USSR 528,877 - 1 -
water phase. In some instances steam is injected via a well, the well is
then shut in temporarily and allowed to soak, and subsequently production
is commenced from this same well. In other instances, steam is injected
via one well and acts as a drive fluid to push oil through the formation to
one or more offset wells through which the oil is produced. In either
instance, when the steam reaches the subterranean formation, it at least
partially condenses, thus exposing the formation rocks to fresh water. Even
though the steam may act to mobilize the oil in the formation, if the
formation contains fines and water-sensitive clays, the permeability of the
Formation can be so reduced as a result of the contact of the fines by the
earache water, the increase in oil production can be lower than expected,
and, in some instances, production can even be lower than before the
treatment.
In another instance a fines-containing subterranean formation
penetrated by a well may require stimulation because of water damage which
occurred during drilling or fracturing operations.
Various treatments have been proposed to stabilize clays in a
Formation Such treatments include injecting into the formation solutions
containing such materials as potassium hydroxide, sodium silicate,
ZOO hydroxy-aluminum, organic acid chrome complexes, organic polymers and
salts owe a hydrous oxide-:Eorming metal such as zirconium oxychloride.
While each of these treatments has met with some success in particular
applicatiolls, the need exists for a further improved method for -treating
a tines containing formation to minimize the adverse effect of the fines on
Formation permeability, particularly when such a formation is contacted by
a fluid containing water.
Therefore, this invention is directed to providing a method err
reducirlg the permeability damage in and/or increasing the permeability of
formations containing finely divided particulate matter due to passage of
a fluid there through, and for inhibiting permeability impairment due to
I
migration, transformation and/or swelling of very fine particles within a
porous formation.
The present invention attempts to stabilize a formation containing
water-sensitive clays, shale and other fines by injecting steam into the
formation and/or to stimulate a formation which has been damaged by water.
Briefly the present invention provides a method for treating
or conditioning earthen formations, particularly those which contain
finely divided particulate matter, such as water-sensitive clays and shale
and/or other fines, which materials are free to move through the formation,
lo transform and/or swell if contacted by an aqueous liquid, whereby the
migration, transformation, and/or swelling of the fines is reduced so as
to maintain a relatively high permeability through the formation and to
increase the permeability of formations previously damaged. The method
involves injecting into the formation steam to which has been added at some
point prior to the time the steam contacts the formation an effective fines-
stabilizing amount, typically more than 0.1 to 25 percent by weight based
on the weight of the boiler feed water used to generate the steam, of a
compound containing ammonia Cal nitrogen selected from the group consisting
of ammonium hydroxide, and a water-soiuble ammonia or ammonium ion
precursor selected from the group consisting of asides of carbamic acid
and thiocarbamic acid, derivatives of such asides, tertiary carboxylic
acid asides and their substituted and alkylated derivatives characterized
by the formula:
X Al
R - C - N
R2
wherein I R is hydrogen, or an organic radical, particularly an alkyd
group containing 1 to about 8 carbon atoms, or an -hydroxy substituted
alkyd group containing 1 to about carbon atoms, (2) Al and R2 are
I 3
independently selected from hydrogen and organic radicals, with alkyd groups
containing 1 to about carbon atoms being the preferred organic radicals,
and (3) X is oxygen or sulfur. The preferred additives are ammonium
carbonate and urea, an aside of carbamic acid. urea is most preferred.
If the earthen formation is a subterranean formation, the treatment can be
part of a method for enhanced oil recovery or a method -for stimulating
production from a formation penetrated by one or more wells.
Most formations, regardless of their composition, contain at
least some fines, detrital material or authigenic material which are not
lo held in place by the natural cementations material that binds the larger
formation particles, but instead are loose in the formation or become
dislodged from the formation when food is passed through the formation,
as a result of rainfall, flow of ground water or during production o-f
formation fluids via a well penetrating the formation or injection of
fluids into the formation from the surface or via a well. The loose fines
tend to become dispersed in the fluids passing through the formation and
migrate along with the fluid. They are carried along and are either carried
all the way through the formation and can be produced i-f the fluid is
flowing to a well, or they can become lodged in the formation in
constrictions or pore throats and thus reduce formation permeability. In
addition, if the fines are clays or shale which swell in the presence of
water and the fluid passing through the formation is or contains water,
permeability reduction can occur due to swelled clay or shale particles
occupying a greater proportion of the formation pore volume.
Formation fines can be incorporated into the formation as it is
deposited over geologic time, or in the case of subterranean formations, can
be introduced into the formation during drilling and completion operations.
Fines are present to some extent in most sandstone, shales, limestones,
clolomites and the like. Problems associated with the presence of fines are
often most pronounced in sandstone-containing formations. "Formation fines"
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are defined as particles small enough to pass through the smallest mesh
screen commonly available (400 United States Lucia, or 37 micron openings).
Ire composition of the fines can be widely varied as there are many different
materials present in subterranean formations. Broadly, fines may be
classified as being quartz, other minerals such as feldspar, Muscovite
calcite, dolomite and Burt; water-swellable clays such as montmorillomite,
beidellite, nontronite, sapient, hectorite and sequent, with
montmorillonite being the clay material most commonly encountered; non-
water-swellable clays such as coolant and isle; shales; and amorphous
materials.
In the method of this invention, the above-described fines are
stabilized, rendered less likely to reduce permeability when a water-
containing fluid passes through the formation, and, in some instances,
the permeability of the formation is increased compared to what it was prior
to treatment. In the case of a subterranean formation penetrated by a well,
the treatment can improve the production or injection capability of the
well, i.e., stimulate the well.
kite the reasons for these effects on the formation permeability
are not completely understood, and the invention is not to be held to any
particular theory of operation, it is believed that the success of this
method may be due to one or more of the following: (1) the ammonia or
ammoniwn ions add to the total dissolved solids content both of the water
component of the steam, if wet s-team is employed, and of the water
condensing from the steam itself. These solids appear to decrease the
swelling tendency of the clays when exposed to water, even water contacted
subsequent to the carrying out of this method. I Some non-clay fines
treated with steam alone appear to react hydrothermally to produce water-
syllable clays which then reduce permeability. The presence of the ammonia
or ammoniwn ions in the steam decreases the occurrence of this reaction to
form clays. The Amelia or ammoni~ml iOII may react Whitehall water-swe71able clays to
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transform them into materials which have less telldency to swell in water.
The methods of this invention can be employed to treat or
condition fines-containing earthen formations which are episode at the
surface, located just below the surface, or which are located a substantial
distance below the surface and are penetrated by a well. In one manner
of treating subterranean formations penetrated by a well, the treatment can
involve an enhanced oil recovery method wherein steam is injected into the
forination to mobilize oil, and the method of this invention prevents
formation damage by the steam. In another instance the treatment can involve
stimulation of a well penetrating a formation whose permeability has been
impaired previously. Such impairment can occur in various ways depending
on the previous history of the well, for example, wells drilled with water-
base drilling fluid and/or whose surrounding formations have been exposed
to water. As used herein the term 'stimulation" can include both
improving the fluid flow rate through a formation and removing formation
damage therefrom.
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The ammonium ion precursors suitable for use in this invention
are water-soluble materials which hydrolyze in the presence of steam to
form ammonia and/or ammonium ions.
One group of ammonium ion precursors are the asides of carbamic
acid and thiocarbamic acid including urea, Burt, triuret, -Thor and
ammon:ium carbamate. Urea is the most preferred additive for use in the
present invention.
Another group of ammonium ion precursors are derivatives of
carbamic acid and thiocarbamic acids including monomethylolurea and
dimethylolurea.
Still another group of ammonium ion precursors are tertiary
carboxylic acid asides and their substituted and alkylated aside
counterparts characterized by the formula:
R
R-C-N
wherein (1) R is hydrogen or an organic radical, particularly an alkyd
group containing 1 to about 8 carbon atoms, or an ~-hydroxy substituted
alkyd group containing 1 to about 8 carbon atoms, (2) Al and R2 are
independently selected from hydrogen and organic radicals, with alkyd
groups containing 1 to about 8 carbon atoms being the preferred organic
radical, and (3) X is oxygen or sulfur. Preferred tertiary carboxylic acid
asides and their substituted and alkylated aside counterparts include
Eormamicle, acetamide, N,N-dimethyl:Eormamide, N,N-diethylformamide, NUN-
dimethylacetamide, N,N-dietllylacetamide, N,N-dipropylacetamide, NUN-
dimethylpropionamide and N,N-diethylpropionamide. Other species which may
be used include N-methyl,N-ethylacetamide, N-methyl, N-octylpropionamide, N-
methyl, N-hexyl-n-butyramide, N-methyl,N-propylcaproamide, M,N-cliethyl-
caprylamide and the like. N,N-dimethylformamide is an especially preferred
tertiary carboxylic acid aside.
The ammonia or ammonium ion-containing additive should be
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~32~3
employed in an amolmt which is effective Fiji stabilizing fines. This
amount will vary depending especially on the nature and amount of fines
present in the particular formation being treated and the particular
ammonium ion-containing additive used. Typically, there is used more
than 0.1 to 25 percent by weight ammoniwn ion-containing additive,
preferably Us to 5 percent by weight, based on the weight of the boiler
feed water used to generate the steam.
Additives which are liquid at ambient temperatures can be
added directly either to the boiler feed water or to the steam itself. If
I added to the steam, the addition can be made either at the surface as the
s-team is being injected into the formation or down a well penetrating the
formation to be treated, or the additive can be injected Donnelly via a
separate conduit and mixed with the steam Donnelly prior to its entering
the Formation Additives which are solids at ambient temperature can be
added directly to the feed water or a concentrated solution thereof can be
prepared and then employed as described above for a liquid additive. An
example of a suitable concentrated solution is a solution containing 35 to
50 percent by weight urea and 65 to 50 percent by weight water.
If one of the chief objectives in the application of this
treatment to an enhanced oil recovery method is to use steam to mobilize
oil which otherwise would be difficult to recover, the amount of steam
to be used is well known in the art and is the same as for steam treatments
in general. If mobilization of oil is of secondary importance, as in
treating a surface formation or a water injection well completed in a fines-
contain:irlg formation to stabilize the fines, it is recommended that there
be used the steam generated from about 250 to 3,000 barrels of feed water per
vertical foot of formation to be treated. Preferably the steam should be
injected at a rate of about 200 to 1500 barrels of feed water per day per
well.
I the invention is further illustrated by the following examples
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25053-351
which are illustrative of various aspects of the invention and are no-t
intended as limiting the scope of the invention as defined by the
appended claims.
Example AL (Comparative Example)
A California well T-33 having a depth of 1,124 feet which is
newly completed produces for two months at a rate of 24 barrels per day
(B/D) oil and 1 B/D water. It is desired to carry out an enhanced oil
recovery -treatment of this well with steam. However, it is believed the
formation may contain fines which might damage the permeability of the
formation if treated with steam. That is, experience with nearby wells
indicates the formation may be water sensitize.
. .
A one-inch- diameter core having-a length- of 2.7 inches is I==
removed from the well and tested in the laboratory to determine its
sensitivity to water and its response to a treatment with steam containing
ammonium ions. First a 3 percent by weight aqueous solution of sodium
chloride is injected into the core at ambient temperature and 15 pi
pressure for 3.5 hours at rates starting at 9.1 milliliters per minute
(mls./min) and dropping to 4 mls./min. as the permeability stabilizes.
This established a base permeability of 92.8 millidarcys (muds.). Next,
distilled water is flowed through the core at ambient temperature and 15
pi for 3.25 hours at rates starting at 6 mls./min. and dropping to
0.15 ml./min. where the permeability stabilizes at 3.5 percent of the base
permeability to the sodium chloride solution. Next, there is added to
boiler feedlYater 64 grams/liter gel of ammonium carbonate. Steam is
generated and injected into the core at 500F. and 700 pi back pressure
for 6 hours at a flow rate of 0.5 ml./min. Next, an aqueous solution
containing 6~1 gel of amrnonium carbonate is injected into the core at
ambient temperature and 15 pi for 6 hours at a flow rate of 13.2
mls./min. The permeability increased to 330 percent owe -the base permeability
to the sodium chloride solution.
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25053-351
This example shows that the injection of fresh water
sharply reduces the permeability of the core. Ever, the
permeability can be restored, and even substantially increased
by treatment with steam containing ammonium carbonate.
eye
Well T-33 it riven a steam stimulation treatment as
follows. A 42 percent by weight aqueous solution of urea is
prepared and held in a blending tank. Eighty percent quality
s-team it generated by a battery of steam generators and flowed
down a carbon steel flow line towards the well. At the surface
of the well a 7-foot long section of stainless steel conduit is
positioned in the carbon steel flow line. The aqueous solution
of urea is injected into the steam flowing to the well at the
upstream end of the stainless steel conduit segment to minimize
corrosion. Steam generated from 600 barrels of feed water per
day is injected for 12.5 days. The first day 674 gallons per
day of the 42 percent by weight aqueous solution of urea is
added to the steam. The second day 337 gallons per day of -the
same urea solution is added to the steam. For the remaining
10.5 days of the treatment, 168.5 gallons per day of the same
urea solution is added to the steam. At the end of the treat-
mint it is calculated that 2.3 billion Buts of heat is added
to the formation. The well is shut in for 7 days and allowed
to soak. The well is then returned to production. The product
-lion rate is as follows:
sty week -160 B/D oil and 75 B/D water.
end week -108 B/D oil and 61 B/D water.
3rd week -98 B/D oil and 11 B/D water.
Thea week -90 B/D oil and 11 B/D water.
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25053-351
lust the treatment increases tile rate of oil production
substantially with no observable evidence of permeability reduction due to
swelling or movement of formation fines.
kite various specific embodiments and modifications of this
invention have been described in the foregoing specification, further
modifications are included within the scope of this invention as defined
by the following claims.
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