U.S. patent number 3,664,426 [Application Number 05/034,216] was granted by the patent office on 1972-05-23 for hydraulic fracturing method.
This patent grant is currently assigned to Esso Production Research Company. Invention is credited to Martin E. Chenevert.
United States Patent |
3,664,426 |
Chenevert |
May 23, 1972 |
HYDRAULIC FRACTURING METHOD
Abstract
A method of fracturing water-sensitive formations is disclosed.
The new method involves determining the aqueous vapor pressure of
the formation and injecting a fluid having a continuous oil phase
and a dispersed water phase containing a sufficient quantity of a
water-soluble aqueous vapor pressure depressant therein to reduce
the aqueous vapor pressure of the fluid to a level that is about
equal to that of the formation into the formation at a pressure and
rate sufficient to open a fracture in the formation.
Inventors: |
Chenevert; Martin E. (Houston,
TX) |
Assignee: |
Esso Production Research
Company (N/A)
|
Family
ID: |
21875011 |
Appl.
No.: |
05/034,216 |
Filed: |
May 4, 1970 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
Issue Date |
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726693 |
May 6, 1968 |
|
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675490 |
Oct 16, 1967 |
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699255 |
Jan 19, 1968 |
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Current U.S.
Class: |
166/308.1 |
Current CPC
Class: |
E21B
43/26 (20130101) |
Current International
Class: |
E21B
43/26 (20060101); E21B 43/25 (20060101); E21b
043/26 () |
Field of
Search: |
;166/283,308
;252/8.55A |
References Cited
[Referenced By]
U.S. Patent Documents
Primary Examiner: Purser; Ernest R.
Parent Case Text
CROSS REFERENCES TO RELATED APPLICATIONS
This application is a continuation-in-part of application Ser. No.
726,693, filed May 6, 1968, now abandoned, which in turn was a
continuation-in-part of application Ser. No. 675,490, filed Oct.
16, 1967, and application Ser. No. 699,255, filed Jan. 19, 1968,
both now abandoned. It is also based in part on pending application
Ser. No. 19,574, a continuation-in-part of said application Ser.
No. 726,693, filed Mar. 16, 1970.
Claims
What is claimed is:
1. A method for hydraulic fracturing a water-sensitive subterranean
formation surrounding a wellbore which comprises determining the
aqueous vapor pressure of said water-sensitive formation and
injecting a fluid having a continuous oil phase and a dispersed
water phase that contains a sufficient quantity of a water-soluble
aqueous vapor pressure depressant to reduce the aqueous vapor
pressure of the fluid to a level that is about equal to that of the
formation into said formation at a pressure and rate sufficient to
open a fracture.
2. A method as defined by claim 1 in which said fluid is lubricated
down said wellbore by means of an annular ring of water having an
aqueous vapor pressure about equal to the aqueous vapor pressure of
the formation.
3. A method as defined by claim 1 in which said vapor pressure
depressant is a base.
4. A method as defined by claim 1 in which said vapor pressure
depressant is a salt.
5. A method as defined by claim 4 in which said salt is sodium
chloride.
6. A method as defined by claim 4 in which said salt is calcium
chloride.
7. A method for hydraulic fracturing a water-sensitive subterranean
formation surrounding a wellbore which comprises determining the
aqueous vapor pressure of a sample of water taken from said
water-sensitive formation and injecting a fluid having a continuous
oil phase and a dispersed water phase that contains a sufficient
quantity of a water-soluble aqueous vapor pressure depressant to
reduce the aqueous vapor pressure of the fluid to a level that is
about equal to that of said water sample into said formation at a
rate and pressure sufficient to open a fracture.
8. A method as defined by claim 7 in which said oil base fluid is
lubricated down said wellbore by means of an annular ring of water
having an aqueous vapor pressure about equal to that of a sample of
water taken from said formation.
9. A method as defined by claim 7 in which said vapor pressure
depressant is a base.
10. A method as defined by claim 7 in which said vapor pressure
depressant is a salt.
11. A method as defined by claim 10 in which said salt is sodium
chloride.
12. A method as defined by claim 10 in which said salt is calcium
chloride.
Description
BACKGROUND OF THE INVENTION
1. Field of the Invention
This invention is directed primarily to fracturing water-sensitive
earth formations.
2. Description of the Prior Art
The technique of hydraulic fracturing earth formations from which
crude oil and natural gas are produced for the purpose of
increasing productivity or injectivity has been in use by the
petroleum industry for a number of years. Basically, the process
involves injecting fluid having a propping agent suspended therein
into the permeable formation at a pressure and rate sufficient to
fracture the formation. Injection is continued until a sufficient
volume of propping agent has been deposited in the fracture to hold
the fracture open. The result is a permeable rock matrix having a
high permeability fracture extending therein. The combination of
the high permeability fracture with the permeable matrix enhances
the overall effective permeability of the formation, frequently
resulting in a substantial increase in productivity or
injectivity.
A number of problems are encountered in fracturing water-sensitive
formations which problems are of long standing in the petroleum
industry. The nature and extent of the difficulties encountered
depend on the characteristics of the particular water-sensitive
formation to be stimulated and are particularly acute in formations
containing argillaceous materials. Where a significant amount of
argillaceous material is contained in the formation, contacting the
matrix material with water may result in swelling of the
argillaceous material which in turn causes a reduction in matrix
permeability. This reduction in matrix permeability caused by the
fracturing fluid may significantly impair an otherwise substantial
increase in effective permeability. When fracturing water-sensitive
formations it is therefore desirable that the fracturing fluids
which contact the clay-containing matrix not cause swelling of
clays with attendant reductions in matrix permeabilities.
It is known for instance that employing fresh water to fracture
formations containing montmorillonite or other hydratable clays
results in clay swelling. Accordingly, it has been suggested that
water-sensitive formations be fractured with fluids having oil as
the external phase. Such fluids may include, for example, lease
crudes, refined oils and dispersions of water in oil such as
water-in-oil emulsions. A large number of additives have been
employed in conjunction with oil-base fracturing fluids which
contain dispersed water, including the addition of various
electrolytes to the aqueous phase for a variety of reasons. The
problems caused by swelling of argillaceous materials, despite the
use of oil external emulsion fluids have, however, heretofore
inexplicably persisted. There therefore exists a need for a method
of designing a fracturing fluid that will not result in reduction
of matrix permeability in water-sensitive formations.
SUMMARY OF THE INVENTION
The present invention provides means for alleviating problems
normally encountered when water-sensitive argillaceous earth
formations are contacted with aqueous fluids. The invention greatly
improves the performance of oil base fracturing fluids and while
described herein primarily in relation to the drilling of
water-sensitive formations its applicability to fracturing
operations will be apparent to those skilled in the art.
In accordance with the invention, it has now been found that
shales, shaley sands, and similar argillaceous formations, in spite
of their extremely low permeability, possess a strong attraction
for water and are capable of withdrawing water from water-in-oil
emulsions and other fluids with which they come in contact. This
sensitivity to water is evidenced by dimensional changes in
response to the absorption or desorption of water. These changes,
although sometimes very slight, contribute materially to formation
failure. It has been found that the rate at which such a formation
withdraws water from a particular aqueous fluid is a quantitive
measure of the degree of water sensitivity of the formation in the
presence of that fluid. This rate and hence the water sensitivity
of the formation can be assessed by at least partially immersing a
substantially unaltered sample of the formation in the fluid and
measuring the changes in dimensions, weight, or other properties of
the sample, directly or indirectly, over a selected period. A
preferred method of measuring the water sensitivity of the
formation is to measure the deformation rate, whether visible or
subvisible, of a formation sample in the presence of the fluid.
Although the mechanisms responsible for the transfer of water
between the emulsion fluid and the argillaceous shale with which
the emulsion fluid comes in contact are evidently complex and are
not fully understood, experience has shown that water transfer from
the emulsion fluid to the shale will normally occur if the vapor
pressure of the aqueous phase of the fluid is greater than the
vapor pressure of the formation. Measurement of vapor pressures
thus provides a convenient technique for the evaluation of emulsion
fluids. Aqueous vapor pressure is directly proportional to the
activity of water and hence water transfer will normally occur from
emulsion to shale when the activity of the water contained within
the aqueous phase of the emulsion exceeds that of water contained
within the shale. It is important to note that the aqueous vapor
pressure of the formation normally differs from the vapor pressure
of the water or brine contained within the formation. It appears
that certain electrical or absorptive forces associated with the
matrix or composition of the formation itself greatly decrease the
vapor pressure which the water contained therein would otherwise by
expected to have. Measurement of the aqueous vapor pressure of the
formation, which characterizes the activity of the formation water,
is therefore an important aspect of the invention.
Two general methods for designing oil-base drilling fluids in
accordance with the invention are disclosed. Both involve the
addition of vapor pressure depressants to the aqueous phase of the
emulsion fluid in amounts sufficient to eliminate or to retard
transfer of water from the drilling fluid to the argillaceous
formation. The first method is a direct simulation of the
interaction of the fluid and the water-sensitive formation. A water
vapor pressure depressant is preferably first dissolved in the
aqueous phase of the emulsion drilling fluid. The rate of water
transfer between this fluid and the formation is then
quantitatively determined by immersing a sample of the formation in
substantially its natural state in the fluid and determining the
rate of deformation. The concentration of the water vapor
depressant can then be increased and additional samples tested
until a concentration that reduces the rate of deformation to
substantially zero is found. A deformation rate that for all
practical purposes approaches zero indicates that the fluid can be
used with little likelihood of damaging the formation.
A second method for designing drilling fluids requires that the
aqueous vapor pressure of the argillaceous shale formation first be
determined. This can be done by exposing formation samples to
atmospheres above different saturated salt solutions having known
water vapor pressures until equilibrium is reached. By observing
the weight change of the sample resulting from water migration, the
vapor pressure of an atmosphere that would result in no weight
change is determined. This value represents the formation vapor
pressure. After thus determining the vapor pressure of the shale
formation, an emulsion fluid having an aqueous vapor pressure
substantially equal to that of the formation can be prepared. Such
a fluid can be used to drill the water-sensitive formation with
little likelihood of the hole sloughing.
It is still a further aspect of the invention to provide an
improved method of fracturing water-sensitive earth formations. The
improved fracturing method of the present invention involves
determining the aqueous vapor pressure of the water-sensitive
formation and injecting a fluid into the formation having a
continuous oil phase and a dispersed water phase which contains a
sufficient quantity of water-soluble aqueous vapor pressure
depressant therein to reduce the aqueous vapor pressure of the
fracturing fluid to a level that is about equal to that of the
formation into said formation at a pressure and rate sufficient to
open a fracture. By maintaining this relationship between the
aqueous vapor pressure of the formation and the fracturing fluid,
water transfer therebetween is prevented, eliminating swelling of
the argillaceous material in the matrix and consequent permeability
reduction. The fracturing method of the present invention will thus
be seen to have significant advantages over techniques available
heretofore.
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 schematically depicts an elevation view of a displacement
transducer instrumented with strain gauges suitable for performing
the simulation test method of the invention.
FIG. 2 is a schematic plan view of the apparatus of FIG. 1.
FIG. 3 is a schematic diagram of an electrical circuit that can be
used with the apparatus of FIG. 1.
FIG. 4 graphically illustrates unit elongation versus log time data
recorded while testing a hard shale in accordance with the
simulation test method of the invention.
FIG. 5 graphically illustrates the rate of deformation exhibited by
a number of samples of an argillaceous shale formation contacted by
water-in-oil emulsion drilling fluids having different aqueous
activities.
FIG. 6 shows the water vapor pressure (P), relative to the vapor
pressure of pure water (P.sub.o), exhibited by a West Texas hard
shale at 25.degree. C for various water contents within the
shale.
FIG. 7 is a correlation showing the average variation in the water
content of a shale in terms of depth of burial within the
earth.
FIG. 8 is a correlation showing the average vapor pressure (P) of
two hard shales and one soft shale relative to the vapor pressure
of pure water (P.sub.o) at 25.degree. C for different shale water
contents.
DESCRIPTION OF THE PREFERRED EMBODIMENTS
I. design of Drilling Fluids
A. the Simulation Test Method
1. Nature of the Simulation Test Method
The simulation test is based on the discovery that the rate at
which shales and other argillaceous formations absorb water from a
particular aqueous fluid is a quantitative measure of the degree of
water sensitivity of the formation in the presence of the fluid.
The test is performed by at least partially immersing a sample of
the formation which is in substantially its natural state of
hydration in the drilling fluid of interest and determining the
rate of water absorption.
One method for determining the water absorbed is by change of
weight of the sample. The sample is weighed initially and its
change in weight observed over a period of time. Any change in
weight which occurs is attributable to the migration of water.
Weight measurements can be obtained while the sample is immersed by
suspending it in the drilling fluid and periodically recording the
suspended weight. In lieu of this, the sample may be withdrawn from
the fluid after a fixed period of time, cleaned, and then weighed.
Another method recognizes that the resistivity of the sample will
decrease as it absorbs water and utilizes changes in resistivity to
measure the amount of water absorbed. Still other methods are based
on the measurement of changes in sonic velocity, compressive
strength, and other physical properties which vary with water
content to indicate the rate of absorption.
The preferred method of measuring absorption is to log the rate of
change in dimensions of a shale sample while it is immersed in the
drilling fluid. This gives a direct measurement of the deformation
of the shale due to the drilling fluid and thus provides a
quantitative measurement of the rate of water absorption. A wide
variety of devices for recording changes in dimensions may be used,
including micrometers, optical equipment, dial displacement
indicators, and the like. The preferred apparatus, however, is a
displacement transducer instrumented with strain gauges.
2. The Displacement Transducer Apparatus
FIGS. 1 and 2 illustrates a resistance strain gauge displacement
transducer suitable for measuring the change in dimensions of a
sample of shale or similar material. This apparatus includes a
rectangular base 10 from which a substantially cylindrical column
12 extends vertically. A series of beveled teeth on the upper
portion of column 12 form rack 14.
Cantilever deflection beam 22 engages rack 14. The outermost end of
the deflection beam extends downwardly in an L-shape terminating in
a frusto-conical end terminus 24. Contactor shoe 21 is mounted on
end terminus 24. The innermost end of the deflection beam 22
contains a generally oval aperture 23, one end of which forms a
yoke that fits over upright column 12 and forms a slidable support
with the column. Shaft 18 passes through deflection beam 22 at the
other end of aperture 23. Knobs 16 are mounted on the ends of shaft
18. Pinion 20 is supported on the shaft 18 in a position
corresponding to the middle of the aperture to cooperate with rack
14. Upper strain gauges 25 and 26 are mounted on the upper side of
deflection beam 22. Lower strain gauges 27 and 28 are positioned on
the other side of the beam.
A cylindrical pedestal 30 extends from a rectangular base 10
underneath contactor shoe 21. The upper surface 31 of the
cylindrical pedestal is smooth and forms a bearing surface
underneath shale sample 34. Cylindrical cup 29 slides upon
cylindrical pedestal 30. Sealing member 32 is mounted between the
cup and the pedestal to prevent the leakage of fluids.
FIG. 3 illustrates an electrical circuit suitable for use with the
strain gauge displacement transducer apparatus. A four-resistor
electrical bridge in which strain gauges 25, 26, 27, and 28 form
the resistors is shown. At least four resistors are generally used
to obtain increased amplitude and inherent temperature
compensation. Variable resistor 32 is placed in the circuit to
balance the bridge prior to strain measurements. Voltage source 35
creates a difference in potential across resistor 32 and across the
bridge between contacts 36 and 37, causing direct current to flow
through resistor 32 and the legs of the bridge formed by resistors
25 and 27, and 26 and 28, respectively. Voltage is measured between
terminals 40 and 42 by voltmeter 44. In lieu of this, a suitable
strain indicator, such as Model P-350 sold by The Budd Company,
Phoenixville, Pennsylvania, could be used. Switch 46 is used to
turn the strain gauge transducer on and off. Although the
relatively simple strain gauge circuit illustrated is suitable,
other circuits such as those illustrated in M. Hetenyi's book,
Handbook of Experimental Stress Analysis, John Wiley & Sons,
Inc., New York, New York (1950) could readily be adopted.
Prior to using the strain gauge transducer, it must be calibrated
to determine the relationship between observed voltages and
displacement. This can be done by first zeroing the voltmeter, as
is discussed below, and then placing successively larger or smaller
articles of known length between contactor shoe 21 and cylindrical
pedestal 30 and observing the voltages. From these data a constant
that relates voltage and displacement can be obtained.
To use this equipment to analyze the compatibility of a drilling
fluid and a particular shale, a sample of the shale should be
placed on surface 31 of cylindrical pedestal 30. Deflection beam 22
is then lowered by turning knob 16. This rotates shaft 18 on which
pinion 20 is mounted. Pinion 20 cooperates with rack 14 to convert
the rotational movement of the knob 16 into a downward
translational movement of beam 22. The beam should be lowered until
contactor shoe 21 engages the shale sample 34 and holds it firmly
in place on surface 21 of the pedestal 30.
With the shale sample thus mounted, the strain gauge's electrical
circuit should be balanced. Voltage source 35 is energized by
closing switch 46, causing current to flow through variable
resistor 32 and both sides of the resistance bridge. The bridge is
balanced by adjusting variable resistor 32 until voltmeter 44 is
zeroed. Once the bridge has been balanced, the voltage readings
will indicate deformation. Cylindrical cup 29 is then raised to its
uppermost position so that the upper edges of the cup are above the
top of sample 34. Sufficient drilling fluid to cover the sample is
then poured into the cup held between contactor shoe 21 and surface
31 of cylindrical pedestal 30.
Once the drilling fluid contacts the sample mounted within the
strain gauges, the sample will begin to absorb water and expand if
it is incompatible with the fluid. Expansion of the sample will
force contactor shoe 21 upward, deflecting beam 22. Deflection of
the beam results in deformation of the strain gauges and produces
an imbalance in voltage readings across the bridge. If the fluid
absorbs water from the sample, the sample will generally exhibit
shrinkage. Such shrinkage also normally produces an imbalance in
voltage readings across the bridge. However, these voltages will
have an opposite sign from those caused by swelling.
Several voltage readings should be taken at various times after the
sample has been immersed in the drilling fluid. The voltage
readings are proportional to the displacement of the sample between
contactor shoe 21 and pedestal 30. The relationship between
displacement and time can be determined from the calibration
constant and used to determine the rate at which this sample will
absorb water from the particular drilling fluid. When comparing
data, it is useful to normalize the displacement data by dividing
each reading by the sample length. The normalized data is then
referred to as "strain." The rate so determined is indicative of
the degree of compatibility between the water-sensitive formation
and the drilling fluid.
3. Selection and Preparation of Formation Samples
The determination of the water sensitivity of a subsurface
formamation in the presence of a particular drilling fluid in
accordance with the invention is normally carried out with a sample
of the formation having substantially its in situ composition.
Exposure to high temperatures and other treatment that may alter
the composition should be avoided. It is preferred that this sample
be in substantially its natural state of hydration so that its
surface absorption behavior will approximate in situ absorption
behavior. Laboratory tests performed at reservoir conditions of
temperature and pressure, when compared with absorption tests
conducted under atmospheric conditions, indicate that atmospheric
tests are sufficiently accurate for most practical purposes.
The formation samples utilized may be preserved core samples from
the subject well or from a nearby well that penetrates the same
formation. Such preserved samples are particularly representative
when the coring fluid used inhibits absorption of water by the
water-sensitive formation. Fragments of the formation entrained by
the drilling fluid and carried to the surface can also be used.
Since a water-sensitive formation will begin hydration as soon as
it is contacted with a water-containing drilling fluid, it is
preferable that such fragments be recovered as early as possible
after initial contact of the rock by the fluid. Hence, the depth of
the formation of interest should be estimated and samples from the
earliest returns from drilling the formation should be secured for
the test. The use of an oil-base drilling fluid treated in
accordance with the invention generally simplifies the recovery of
samples in substantially their natural state of hydration.
Where severe hydration of the formation has occurred, the samples
obtained should be restored to their natural state of hydration.
Hydration is not always encountered when the drilling fluid is a
treated oil-base fluid and is generally more severe where a
water-base fluid is used to drill a highly water-sensitive shale.
Restoration to a substantially natural state can be accomplished by
baking the samples at a temperature slightly above 100.degree. C
until sample density corresponds with typical shale density for
this formation and depth of burial. Sample density can be rapidly
determined by means of a graduated density liquid column, the
mercury pump pressure chamber method, or other suitable techniques.
Correlations of shale density versus depth of burial are available
in the literature for various formations and are typified by those
published by K. F. Dallmus in his study "Mechanics of Basin
Evolution and Its Relation to the Habitat of Oil in the Basin,"
Habitat of Oil - A Symposium, Tulsa Amer. Assoc. Petrol. Geol.,
1958, p. 883-931. It is important that temperature not greatly
exceed 100.degree. C since excessive temperatures may result in
substantial changes in characteristics of the sample.
4. Drilling Fluid Design
Use of the method and apparatus of the invention to formulate an
oil-base drilling fluid that will prevent or minimize absorption
and thus promote borehole stability is based in part on the
observation that an oil base or water-in-oil emulsion mud having an
aqueous vapor pressure substantially equal to or less than that of
the troublesome water-sensitive formation will prevent absorption
of water by the formation. Samples of the water-sensitive formation
in substantially their natural state should be used, as indicated
above. Several of these samples are preferably immersed in a
corresponding number of different oil-base drilling fluids having
different aqueous vapor pressures and strain-time data are obtained
for each fluid formation combination. This procedure can be greatly
expedited by using a number of strain guage displacement
transducers.
A series of water-in-oil emulsions or other oil-base muds having
different aqueous vapor pressures can be prepared by adding various
concentrations of inorganic salts such as NaCl or CaCl.sub.2 to the
mud. A number of other vapor pressure depressants are discussed
herein in connection with the method of determining the vapor
pressure of an earth formation. Suitable vapor pressure depressants
are not limited to these or similar inorganic salts, however. Any
solute introduced into the aqueous phase will reduce the aqueous
vapor pressure.
FIG. 4 illustrates strain-time data obtained in accordance with the
invention for the hard, argillaceous Wolfcamp shale. Fluid A is
water, and the high rate of absorption for this fluid is typical of
a very compatible fluid. Fluids B, D, C, and E are water-in-oil
invert emulsions containing in the aqueous phase, as vapor pressure
depressants, 130,000 ppm NaCl, 200,000 ppm NaCl, 270,000 ppm NaCl,
and 450,000 ppm CaCl.sub.2, respectively. Curves B, C, and D
illustrate the reduction in absorption that occurs as the
concentration of the aqueous vapor pressure depressant is increased
and the aqueous vapor pressure of the fluid approaches that of the
formation. Curve E illustrates behavior characteristic of a
water-in-oil emulsion mud with an aqueous vapor pressure that has
been reduced below that of the water-sensitive formation. Instead
of swelling, the shale sample shrinks, indicating that water is
being desorbed from the shale sample. The use of a drilling fluid
with a composition similar to that of mud E would therefore prevent
absorption of water by the shale. Generally, however, there is
little incentive in attempting to dehydrate a water-sensitive
formation and therefore such a fluid would normally be considered
to contain an excessive amount of vapor pressure depressant. In
most cases it would be more economical to reduce the concentration
of CaCl.sub.2 in Fluid E so that its strain-log-time curve would
more closely approach the zero strain line than to use a mud such
as Fluid E.
FIG. 5 illustrates graphically the rates of deformation of a series
of shale samples exposed to invert muds having varying aqueous
activities (relative vapor pressures). The shale formation on which
the tests were run had an aqueous activity of 0.7. Each test
involved immersing a shale sample in an invert mud having a known
aqueous activity for a period of 10 hours, measuring the strain,
and then computing the average rate of strain of the sample over
this time period. It will be noted that shale samples exposed to
muds having aqueous activities higher than 0.7 swelled and that the
observed rate of swelling increased as the difference in aqueous
activity between the mud and the sample increased. Samples
contacted with muds having aqueous activities lower than 0.7
shrank. Again, however, the rate of deformation increased in
relation to the activity difference. These data demonstrate that
when a difference in activity exists, water will flow either from
the emulsion mud to the shale or from the shale to the mud. The
former causes swelling of the water-sensitive subterranean
formation, leading to its sloughing into the wellbore; the latter
increases the water content and thus viscosity of the drilling
fluid, necessitating frequent additions of oil, salt and other
materials required to maintain the drilling fluid. However, when
the activity of the mud is substantially equal to that of the shale
formation being drilled, a unique relationship exists. So long as
this balanced condition is maintained, there is substantially no
migration of water in either direction. Thus, it is especially
desirable to maintain the aqueous activity of the mud about equal
to that of the shale and thereby both eliminate sloughing of the
borehole and obviate the addition of salt, oil or other materials
to the mud normally required when it is contaminated by water.
Although the simulation test has been discussed in relation to
water-in-oil emulsion drilling fluids the utility of the simulation
test is not limited to this type of drilling fluid. The simulation
test method and apparatus can be used to determine the
compatibility of any drilling fluid with a water-sensitive
formation and can be employed to select the most compatible
drilling fluid from any group of drilling fluids. The method and
apparatus can also be used to determine whether or not a particular
formation is water-sensitive and to select fluids for use in
secondary recovery, well stimulation, or other well operations, as
is more fully discussed subsequently herein.
B. the Formation Vapor Pressure Test Method
1. The Method of Determining the Vapor Pressure of an Earth
Formation
The aqueous vapor pressure of a shale or other water-containing
earth formation can be determined by subjecting a sample of the
formation to air of a constant known humidity for a period of time
sufficient for moisture within the shale to reach equilibrium with
the moisture in the air. It will normally be difficult to preselect
a humidity condition such that the natural water content of the
shale will be in equilibrium with this condition of humidity. So,
generally speaking, several different humidity conditions must be
used to obtain a range of water contents within the sample which
will span the in situ water content of the formation within the
earth.
A very convenient procedure for exposing samples of a given
formation to air of different humidities is to suspend or place the
sample in a sealed container in an atmosphere of air above a
saturated aqueous solution of a solute which contains an excess of
undissolved solute. Thus, it is known that the relative humidity of
the enclosed space above such a solution where the sample has been
placed will remain substantially constant at a given temperature --
conveniently room temperature (25.degree. C). An article containing
an explanation of this principle and also listing a number of
saturated solutions and solutes is contained in Ecology: Vol. 41;
No. 1; pp. 232-237 (January, 1960). Typically, a series of several
different saturated solutions can be prepared, and one or more
samples of a given shale or other formation can be exposed to an
enclosed atmosphere above each of these samples for a sufficient
period of time for equilibrium to occur. Complete equilibrium will
normally take about one or two weeks, but substantial equilibrium
can normally be attained in about one or two days.
As noted above, a number of different saturated aqueous solutions
should be selected such that a given formation sample is
equilibrated at a range of relative humidities. The use of 8 to 10
different relative humidities ranging from about 10 percent
relative humidity to 95 percent or more relative humidity has been
found to be very desirable and effective. In this connection, it
has been found to be quite effective to use the following saturated
solutions to obtain a suitable range of atmospheres. The solutions
and the relative humidities which exist above these solutions are
listed below:
Relative humidity Saturated solution of (%) at 25.degree. C
__________________________________________________________________________
ZnCl.sub.2 .sup.. 1-1/2 H.sub.2 O 10.0 CaCl.sub.2 .sup.. 6H.sub.2 O
29.5 Ca(NO.sub.3).sub.2 .sup.. 4H.sub.2 O 50.5 NH.sub.4 Cl +
KNO.sub.3 71.2 (NH.sub.4).sub.2 SO.sub.4 80.0 Na Tartrate 92.0
KH.sub.2 PO.sub.4 96.0 K.sub.2 Cr.sub.2 O.sub.7 98.0
__________________________________________________________________________
many of these salts, incidentally, may themselves be used within
the aqueous phase of invert emulsions for the purpose of
establishing the vapor pressure of that phase. If vapor pressure
less than that obtainable for a saturated calcium chloride solution
are desired, solutions of ZnCl.sub.2 . 1 1/2 H.sub.2 O; LiCl .sup..
H.sub.2 O; ZnBr.sub.2 ; LiBr .sup.. 2H.sub.2 O; potassium hydroxide
or other stronger vapor pressure depressant may be employed. The
depressant, of course, must be compatible with the invert emulsion
of interest; and such compatibility should be tested prior to
actual use.
After a formation sample has reached equilibrium with a particular
atmosphere of known relative humidity, the sample should be
withdrawn from the atmosphere and its water content promptly
determined. A simple procedure for determining its water content is
to weigh the equilibrated sample, and then repeat the weighing
after the sample has been dried at about 105.degree. C for a period
of 12 to 24 hours. The loss in weight of the sample is a direct
measure of the equilibrated water content of the sample. The vapor
pressure of the sample for this water content is the vapor pressure
of water at room temperature (or the temperature of the equilibrium
condition) multiplied by the percent relative humidity of the air
in equilibrium with the sample.
After the vapor pressures and water contents of a given sample or
set of samples have been determined, these values can be recorded
on a suitable chart or other record medium and intermediate values
can be determined from the resulting correlation. Thus, FIG. 6 of
the drawing shows two correlations (A for absorption conditions,
and D for desorption conditions) obtained by subjecting samples of
a West Texas hard shale to eight different conditions of relative
humidity ranging from 10 percent relative humidity to 98 percent
relative humidity at a temperature of 25.degree. C. These curves
also apply for temperatures at least as high as 100.degree. C. As
can be seen, slightly different correlations were obtained for
tests in which water was desorbed from the shale samples as
compared with tests in which water was absorbed by the shale
samples. The shale sample in this instance had an in situ water
content of 2.22 weight percent as determined by analyzing a small
central portion of a core cut directly from the formation under
conditions such that the water content of most of the core was
undisturbed. From FIG. 6, it is apparent that this formation has a
water vapor pressure (or "formation vapor pressure") relative to
the vapor pressure of pure water of between about 0.71 and
0.81.
Another convenient method for determining the aqueous vapor
pressure of a water-sensitive formation is to place a sample that
is representative of the subsurface formation in a sealed container
until it reaches equilibrium with the enclosed atmosphere. A direct
measurement of the relative humidity of the formation sample can
then be made. This method is also useful for determining the
aqueous vapor pressure of a water-containing oil-base drilling
fluid. Apparatus for measuring relative humidity is widely
available. Typical of such apparatus is the Catalog No. 2200
ELECTRO-HYGROMETER that is sold by Lab-Line Instrument, Inc.,
Melrose Park, Illinois.
2. Selection and Preparation of Samples
As indicated earlier, the use of this invention in designing well
fluids should be preceded by a determination of the vapor pressure
characteristics of the portions of the zones or formations which
the emulsion fluid will contact. In the case of a drilling
operation, as pointed out earlier in the discussion of the
simulation test, a sample of the formation of interest should be
obtained so that its vapor pressure can be determined. If a sample
of the formation is not obtainable directly from the well being
drilled, then an effort should be made to obtain a sample from a
nearby well. It is also possible, however, to collect and use
cuttings from the well which is being drilled.
Again, the preferred type of formation sample to obtain and study
is a sample from the central portion of a core which has been cut
from the formation under conditions suitable to preserve the
natural conditions of the core as much as possible. If such a
sample is available, a reasonably accurate determination can be
made of the amount of in situ water contained in the core. If such
a core cannot be obtained, the formation's water content can be
estimated from FIG. 7. FIG. 7 is a correlation showing how the
water content of many shaley formations within the earth vary, on
the average, with increasing depth of burial. Thus, if a given
formation lies about 10,000 feet beneath the surface, it may be
expected to have, on the average, a water content of about 2 weight
percent. It is then possible to use this water content, in
combination with the method described earlier for determining the
vapor pressure of a formation within the earth, to arrive at an
approximate value of the vapor pressure possessed by the formation
in its natural condition within the earth.
3. Drilling Fluid Design
Once the formation vapor pressure is known, it is then possible to
select and formulate a water-in-oil drilling fluid having an
aqueous phase vapor pressure which bears a particular relation to
the aqueous vapor pressure of the formation. Generally speaking, it
is desirable that the aqueous phase of the drilling fluid have an
aqueous vapor pressure no greater than that of the water-sensitive
formation. This frequently requires the aqueous vapor pressure of
the drilling fluid to be less than that of a saturated sodium
chloride solution and often it is desirable to saturate the aqueous
phase of the drilling fluid with calcium chloride. As pointed out
above with respect to drilling fluid design by the simulation
method, it is especially desirable to maintain the aqueous activity
of the mud at a level about equal to that of the water-sensitive
formation. Balancing the activities in this fashion eliminates any
substantial migration of water between the emulsion fluid and the
formation, thereby eliminating any sloughing of the borehole as
well as contamination of the mud by water contained within the
shale.
However, economics or other considerations may occasionally make it
undesirable to attempt to completely reduce the aqueous vapor
pressure of the drilling fluid to that of the formation. As long as
the water transfer between the fluid and formation is insufficient
to cause excessive formation failure during the time period the
water-sensitive formation is exposed to the wellbore, the aqueous
vapor pressure of the drilling fluid can be considered to be
substantially equal to that of the water-sensitive formation.
However, it is preferable to reduce drilling fluid vapor pressure
to a level that is equal to or below that of the formation.
It should be noted that mixtures of salts can be used in the water
phase of an invert, but such mixtures are subject to the common-ion
effect. Their aqueous solutions may thus have higher aqueous vapor
pressures than would otherwise be suggested by the total salt
concentration. It should also be noted that the emulsifier and
other water-soluble constituents of the drilling fluid may tend to
slightly alter the vapor pressure of the aqueous solution
containing the vapor pressure depressants when the emulsion fluid
is prepared. Thus the aqueous vapor pressure of the emulsion fluid,
which is the aqueous vapor pressure of the water phase of the
emulsion fluid, may differ slightly from that of the aqueous salt
solution used to prepare the emulsion. Generally speaking, however,
an invert emulsion drilling fluid wherein the aqueous phase is
saturated with sodium chloride may be used where the vapor pressure
of the formation has a value (P) about three-fourths of the vapor
pressure of water (P.sub.o) at the same temperature (i.e., a
relative vapor pressure of 0.75). Referring to FIG. 8, such a mud
would be successful in drilling the deep, hard, West Texas shale
(A) shown there which possesses a natural water content of about
2.2 weight percent. In that regard, it should be noted that hard
argillaceous shales seldom exhibit relative aqueous vapor pressures
in excess of 0.75. The deep, hard, Louisiana shale (B), for
example, would normally be drilled with an invert emulsion fluid
wherein the aqueous phase consists of saturated calcium chloride
solution (i.e., a relative vapor pressure of 0.30 ). This shale has
a connate or natural water content of about 1.8 or 1.9 weight
percent. The soft, gumbo shale (C) has a connate or natural water
content of about 11 weight percent and is best satisfied by a fluid
with an aqueous phase vapor pressure less than a saturated aqueous
NaCl solution.
C. emulsion Drilling Fluids Designed by the Methods of the
Invention.
Referring specifically to water-in-oil invert emulsion drilling
fluids, a variety of such fluids are commercially available for use
in drilling wells. Fluids of this type may be modified by the
addition of vapor pressure depressants and can be used for drilling
through water-sensitive formations difficult to drill with the
commercial fluids. Typical invert emulsion drilling fluids contain
droplets of water finely dispersed or emulsified in an oil base.
Diesel fuels, kerosenes, and high-gravity crude oils are frequently
used as the oil base; and about 10 to 70 percent of fresh or common
salt water is emulsified therein with the help of suitable
emulsifying and stabilizing agents. Anionic, nonionic, and mixed
anionic-nonionic emulsifiers are all used for this purpose. The
emulsifiers and stabilizing agents employed in the fluids should be
compatible with sodium chloride, calcium chloride, or whatever
water vapor pressure depressant is to be incorporated in the
aqueous phase of the modified compositions. One specific invert
emulsion drilling fluid composition which has been tested and
appears satisfactory for many applications comprises 70 volume
percent No. 2 diesel fuel; 25 volume percent water saturated with
calcium chloride; and 5 volume percent sorbitan mono-oleate as the
emulsifier. No difficulty, however, has been encountered in
obtaining other satisfactory compositions simply by adding sodium
chloride or calcium chloride to certain existing commercially
available invert emulsion drilling fluids. Where formations are
particularly water-sensitive it may be desirable to prepare a
drilling fluid having a vapor pressure which is less than that of a
mud containing a saturated calcium chloride solution. Solutions
containing ZnBr.sub.2, ZnCl.sub.2, LiBr, LiCl, or similar
water-soluble salts can be employed for this purpose. In addition,
it has been found that a supersaturated CaCl.sub.2 mud can be
formed by adding additional CaCl.sub.2 to a mud having a saturated
CaCl.sub.2 solution as the aqueous phase. Such supersaturated
CaCl.sub.2 muds have vapor pressures lower than those of saturated
CaCl.sub.2 muds. Other water vapor depressants contemplated to be
useful in the various embodiments of this invention include still
other water-soluble salts; phosphoric acid, acetic acid, and other
water-soluble acids; glycerol; sodium hydroxide; potassium
hydroxide; etc.
D. monitoring the Drilling Fluid at the Wellsite
Once a compatible drilling fluid has been selected and introduced
into the drilling system, it is advisable to monitor the fluid
periodically to insure retention of compatibility Contaminants,
absorption, and other phenomena may cause gradual changes in the
composition of the mud. Monitoring can be rapidly accomplished by
periodically immersing samples of successive formations penetrated
by the well in portions of the mud in contact with these formations
and logging the direction and extent of water migration between
each such sample and the mud in which it is immersed with the
displacement transducer apparatus.
In some cases it may be desirable to monitor the mud with
calibrated shale samples having known vapor pressures. These
calibrated samples may be preserved samples of the formation being
drilled that have been taken from another well. Synthetic shale
specimens, clay specimens, and the like, prepared so that they have
particular aqueous vapor pressures can also be used. Calibrated
shale samples representative of the water-sensitive formation are
equivalent to substantially unaltered formation samples and the
necessity for obtaining such samples from the well being drilled
can thus be eliminated. By comparing an oil-base fluid of unknown
aqueous vapor pressure with shale samples having known aqueous
vapor pressures, it is apparent that the vapor pressure of the
fluid can be determined. In this connection, it may be desirable to
continuously monitor the aqueous vapor pressure of the oil-base mud
with the displacement transducer and compare it with the formation
vapor pressure. Another convenient method to monitor the aqueous
vapor pressure of the mud is to place a sample in a closed
container and directly measure the relative humidity of the
atmosphere in contact with the samples as is discussed above.
The condition and composition of the oil-base fluid can be
determined by periodically emulsion-breaking a mud sample and
determining its water content. In addition, the water can be
analyzed for its content of vapor pressure depressant. Thus, if the
vapor pressure of the aqueous phase is being controlled by the
presence of calcium chloride, the aqueous phase can be analyzed for
this salt.
The condition of the drilling fluid can also be qualitatively
evaluated by observing the cuttings produced in the drilling
operation if the water-sensitive formation is such that it will
undergo visible deformation as it absorbs water. If the cuttings
are firm and uniform, it can therefore be inferred that the fluid
and the formation are in satisfactory condition. On the other hand,
if the cuttings become softer or more diffuse, the concentration of
the vapor pressure depressant in the aqueous phase of the fluid
should be increased.
If an invert emulsion drilling fluid prepared in accordance with
the invention loses water from its aqueous phase during drilling,
it is probable that the water is being absorbed by the surrounding
formation; and if this is the case, drilling conditions will tend
to become more adverse. It is therefore desirable, under such
circumstances, to add vapor pressure depressant to the aqueous
phase of the fluid until its aqueous vapor pressure is no greater
than the aqueous vapor pressure of the formation being drilled.
This can generally be done by vigorously mixing the fluid at the
surface of the earth with fresh depressant.
As noted previously, drilling fluids prepared in accordance with
the present invention are especially applicable for use in the
drilling of hard shales. Until the advent of this invention, there
has been no satisfactory procedure for dealing with such shales. As
noted previously, such hard shales generally have aqueous
activities less than 0.75 which corresponds to a saturated solution
of NaCl. The results obtained in accordance with the invention have
shown that invert emulsion muds wherein the aqueous phase is water
saturated with calcium chloride are remarkably effective for a wide
variety of such shales. If, during the course of drilling such a
shale, additional calcium chloride must be added to the mud system,
this may be done by mixing powdered calcium chloride into the
fluid. Powdered calcium chloride has been found to readily enter
the aqueous phase of an invert emulsion drilling fluid.
Abnormal pressure zones represent serious drilling hazards in many
areas where wells are drilled. One characteristic of such zones is
a transition zone that lies just above the abnormal pressure zone
and that exhibits a marked increase in water content. Since a
corresponding increase may also be observed in the water activity
of shales in the transition zone, continuously logging the activity
of formations penetrated provides a method of detecting abnormal
pressure zones. Water activity of a shale is reflected by the ratio
of its aqueous vapor pressure to the vapor pressure of pure water
at the same temperature, i.e., relative humidity. It may therefore
be desirable to log the aqueous vapor pressure of the drill
cuttings of the formations as they are penetrated. Measurements can
be performed by exposing the cuttings to atmospheres of varying
known humidities as discussed above, by placing the cuttings in a
closed container and directly measuring the relative humidity of
the atmosphere in contact with them as also discussed above, or by
using the displacement transducer apparatus in conjunction with a
series of oil-base fluids having known aqueous vapor pressures. If
the aqueous vapor pressure of the shale is equal to that of the
oil-base fluid, when the shale sample is placed in contact with the
fluid it will exhibit no deformation.
Ii. use of the Methods of the Invention for Other Fluids
A. treating Fluids
The principles of this invention are also applicable to otherwise
conventional well fluid compositions such as packer fluids, coring
fluids, completion fluids, and well treating fluids. With respect
to treating fluids, for example, the methods and apparatus of the
invention are useful in designing fluids for repairing and
restoring water-damaged formations. In the past, it has been
conventional practice in the field to attempt to restore
water-damaged formations by treating them with concentrated salt
water (30,000-50,000 ppm) or with solvents such as alcohols which
have at least some degree of miscibility with both water and
hydrocarbons. In accordance with the present invention, a suitable
treating fluid is a water-in-oil emulsion wherein the aqueous phase
has a sufficiently low vapor pressure so as to attract water from
the damaged formation, thereby dehydrating and restoring the
formation. Suitable oils for use in the emulsion include diesel
fuels, kerosenes, light fuel oils, light crude oils, light
petroleum fractions, LPG's, and the like. Oil-base and water-in-oil
invert emulsion drilling fluids containing vapor pressure
depressants are also generally suitable for use as packer fluids,
coring fluids, completion fluids, etc.
B. displacement Fluids
The principles of the invention are also applicable to fluid
compositions and methods used in displacing oil from reservoirs. In
recent years, for example, it has been observed that water-in-oil
emulsions and microemulsions are useful in displacing oil from
reservoirs. Such fluids generally are prepared from the same types
of oils used to prepare invert emulsion treating fluids. Soluble
oils have been employed to form microemulsion displacement fluids.
Such formulations are typified by the displacement fluids disclosed
in U.S. Pat. No. 3,254,714. The emulsion or microemulsion is
injected into a reservoir at one point and driven from that point
through the reservoir toward a second point where displaced oil is
recovered from the reservoir. Since such emulsions and
microemulsions have a substantial degree of miscibility with
reservoir oils, and since their viscosities can be controlled to a
considerable degree, they appear attractive for use as
oil-displacing media. If such fluids, however, are employed in
formations which are shaley or have shale streaks, there is a
tendency for the shales to interfere with the effectiveness and
stability of the emulsions. This tendency can be reduced through
application of the present invention by controlling the vapor
pressure of the aqueous phase of the emulsions or microemulsions so
that it is substantially equal to or less than the aqueous vapor
pressure of the shaley constituents of the formation. The manner of
control is the same as that described for drilling fluids earlier
in this disclosure. Since the vapor pressure of droplets of a
liquid become significantly higher than the vapor pressure of the
bulk liquid itself if the droplets are small enough, droplet
diameter can be a design consideration in formulating microemulsion
displacement fluids. Data on the effect of droplet diameter is
presented by Paul Becher on page 8 of Emulsions: Theory and
Practice, Reinhold Publishing Corporation, New York (1957).
C. fracturing Fluids
Many of the hydraulic fracturing fluids used to stimulate oil wells
contain water. When such fracturing fluids are used in the presence
of argillaceous, water-sensitive formations, the formations tend to
swell and are thereby damaged. This damage can be prevented by
using oil-base or water-in-oil invert emulsion fracturing fluids
prepared in accordance with this invention. For fracturing fluids
the amount of vapor pressure depressant added to the aqueous phase
of the emulsion fluid should be sufficient to reduce the aqueous
vapor pressure of the emulsion fluid to a level substantially equal
to that of the water-sensitive formation. A particularly successful
fracturing method which is described in U.S. Pat. No. 3,378,074
utilizes a viscous dispersion of water-in-oil as a fracturing
fluid. The viscous fluid is lubricated down the borehole by means
of an annular ring of water. Since the fracturing fluid and the
annular ring are subjected to extreme turbulence as the combined
stream is forced through perforations and into the formation to be
fractured, it appears that at least temporarily both combine to
form a water-in-oil emulsion. As a result, it is desirable to add a
vapor pressure depressant to both the internal phase of the
fracturing fluid and the water used to form the annular ring.
D. vapor Pressures of Permeable Formations
Where emulsion fluids designed in accordance with the present
invention are to be introduced into permeable, water-sensitive
formations, e.g., oil-producing formations, another technique for
determining the aqueous vapor pressure of the formation should be
considered. This method stems from the fact that such formations
normally contain connate water in a fraction of the pore space
occupied by reservoir fluids. This connate water is generally
highly saline, frequently containing salts in concentrations to or
exceeding several hundred thousand parts per million. Both the
connate water and the salt ions contained therein freely contact
the argillaceous water-sensitive material contained in the
formation. The connate water will therefore normally be in
equilibrium with the argillaceous material so that the aqueous
activity of the formation water will be equal to that of the
water-sensitive formation. It will thus frequently be convenient to
obtain a sample of this formation water and determine its aqueous
activity in lieu of obtaining and analyzing formation samples.
Produced brine serves as a particularly convenient source of such
fluid samples. The aqueous activity of the formation water can
readily be determined by placing a water sample in a closed
container and directly measuring the relative humidity of the
atmosphere in contact with the water.
Iii. general
It will be understood, and particularly so with respect to the
claims which follow, that while numerous references are made herein
to the aqueous activity, relative humidity or relative vapor
pressure of materials, e.g., earth formations, samples of such
formations and water-containing fluids, in each case the
quantitative value referred to is the ratio of the aqueous vapor
pressure of the material to the vapor pressure of water at the same
temperature. This ratio is proportional to the aqueous vapor
pressure of the material, can be measured rapidly and accurately
and has proved to be convenient quantitative value for
characterizing the aqueous vapor pressures of materials employed or
acted upon in association with the methods of the invention. Along
these same lines, it will also be understood that the aqueous vapor
pressure relationships between well fluids and earth formations
referred to herein refer to the aqueous vapor pressures of
materials as they exist at downhole temperatures. Also, when the
aqueous vapor pressure of an earth formation is mentioned it is
assumed that the earth formation is at its natural state of
hydration. A particular advantage in characterizing the aqueous
vapor pressure of a material by its relative aqueous vapor pressure
is the relative insensitivity of the ratio to temperature when
compared to the absolute aqueous vapor pressure. This is
particularly advantageous where measurements are carried out on
well fluids and formation samples in the laboratory or in the field
at ambient conditions for the purpose of designing emulsion fluids
for downhole conditions. That measurements of relative aqueous
vapor pressure conducted at atmospheric conditions of temperature
and pressure are very good approximations of downhole conditions
has been demonstrated repeatedly by the excellent results achieved
when using fluids designed by these techniques in actual well
drilling operations.
* * * * *