Note: Descriptions are shown in the official language in which they were submitted.
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TITLE OF THE INVENTION:
Method of Improving Oil and Gas Well
Productivity
FIELD OF THE INVENTION
This invention relates to methods of oil and
gas well treatment.
P~ OuND OF THE INVENTION
Oil and gas well treatments are notorious
for unexpected results. What may increase production
in one well may shut off another well. Yet a
successful well treatment can significantly increase
production of a well and extend its production life,
with rapid economic payback of the cost of the well
treatment. Significant research is therefore devoted
to improving well treatments.
One such common well treatment is the
fracturing of a well formation using various load
fluids and proppants to increase formation
permeability, commonly known as a frac. Pressure on
load fluid in the well causes cracks to form in the
formation and proppants (sand, for example) injected
into the well with the load fluids become wedged in
the cracks, thus keeping the cracks open and
increasing permeability. Various load fluids are used
for fracturing, including oils, water, methanol and
other alcohols, carbon dioxide, explosives, and acids.
In Canadian patent no. 1,268,325 of Mzik
there is described a method of treating a well
formation penetrated by a wellbore which comprises
injecting down the wellbore and into the formation a
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fluid mixture comprising a mixture of carbon dioxide
and a hydrocarbon fluid containing aromatics at a
pressure sufficient to cause fracturing of the
formation.
5It has been found that fracturing a well
with a mixture of carbon dioxide and hydrocarbon fluid
containing aromatics yields variable recovery of load
fluid in the general case, and thus an uncertain
economic return from the use of the method. Low
10recovery of load fluid may cause a reduction in
permeability of the formation, with consequent decline
in production from the well. Hence, the economic
efficiency of application of the method of Mzik to an
oil or gas well is somewhat uncertain, and may in fact
15be deleterious to the well productivity. Yet the use
of carbon dioxide and a hydrocarbon fluid containing
aromatics may provide significant economic benefits as
shown by the example in the patent of Mzik.
20SU~lARY OF THE INVENTION
The inventor has investigated the treatment
of oil and gas reservoirs with load fluids including
hydrocarbons and carbon dioxide. During a frac with
such a load fluid, the carbon dioxide drives the load
25fluid into the formation containing oil and gas under
frac pressure. Upon release of the frac pressure, the
reservoir pressure drives the load fluid back out of
the well.
In most wells the reservoir drive pressure
30is caused by methane in the reservoir. The inventor
has found that methane is not miscible in a
hydrocarbon based load fluid that contains carbon
dioxide that is totally miscible in the load fluid.
Hence, the methane tends to finger into such a load
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fluid, and thus fails to drive a portion, perhaps a
substantial portion, of the load fluid out of the
reservoir. This loss of load fluid may decrease
permeability of the well, hence decrease production
from the well.
The inventor has found that when carbon
dioxide forms a bank in front of the load fluid, the
methane mixes with the carbon dioxide, and does not
finger into the load fluid. Thus, upon release of the
fracturing pressure, the methane drives a mixture of
CO2 and methane which in turn drives the load fluid
back out of the well.
The inventor has previously proposed a
method of improving oil or gas well productivity from
a well penetrating a formation in an oil or gas
reservoir, in which the steps include:
forming a hydrocarbon based load fluid with an
amount of carbon dioxide determined according to a
predetermined miscibility relationship between the
carbon dioxide and the hydrocarbon fluid that
establishes the amount of carbon dioxide required to
form a bank of carbon dioxide ahead of the load fluid
in the formation;
applying the load fluid to the well at a
pressure such that carbon dioxide in load fluid within
the well bore remains in solution and carbon dioxide
in load fluid within the formation leaks off the load
fluid into the formation and forms a bank of carbon
dioxide ahead of the load fluid; and
releasing the surface pressure from the load
fluid and flowing the load fluid back out of the well.
Preferably, the load fluid contains a significant
proportion of aromatics.
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In the present invention, a miscible bank is
created ahead of the load fluid by:
injecting a stream of liquified drive fluid
into the well;
while injecting the stream of liquified
drive fluid into the well, injecting a load fluid in
which the liquified drive fluid is miscible into the
well mixed with the liquified drive fluid;
the ratio of liquified drive fluid to load
fluid being initially at a level sufficient to form a
miscible bank of drive fluid in the gaseous state
ahead of the load fluid in the well; and
subsequently reducing the ratio of liquified
drive fluid to load fluid injected into the well.
In one aspect of the invention, a pad of
pure liquified drive fluid is initially injected into
the well, and in another the initially injected fluid
contains a greater proportion by volume of liquified
drive fluid than hydrocarbon based load fluid. The
drive fluid is preferably liquified carbon dioxide and
the load fluid is preferably selected from the group
comprising aromatics, alkanes and naphthenes.
BRIEF DESCRIPTION OF THE DRAWINGS
There will now be described preferred
embodiments of the invention, with reference to the
drawings, by way of illustration, in which:
Fig. 1 is a graph showing a phase envelope
for a mixture of hydrocarbon frac fluid and carbon
dioxide;
Fig. 2 is a graph showing the miscibility
relationship of carbon dioxide at various pressures
and temperatures for two fluids containing different
amounts of aromatics;
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Fig. 3 is a section through a hypothetical
reservoir and fracture zone showing fluid distribution
zones during a well treatment according to the
invention; and
Fig. 4 is a graph showing miscibility
relationships of liquified carbon dioxide with alpha-
olefin (tetradecene), methylcyclohexane, FRACSOL~ and
XYSOL~, a xylene rich mixture of liquid alkanes and
aromatics.
DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS
The method of the invention is carried out
as follows. For a given well treatment, where the
well penetrates a formation in an oil or gas
reservoir, the pressure and temperature of the well is
found from information from the well operator. As used
in this patent document, a load fluid is a formation
compatible fluid having a viscosity such that it can
transport proppants during a frac treatment of a well.
A drive fluid is a fluid that has the property that
when pressure is reduced on the fluid in the well, the
drive fluid expands and with the assistance of
formation pressure can drive a load fluid from a well.
The drive fluid must be miscible in the load fluid and
formation gas, such as methane.
In treating a well according to the within
invention, firstly, using equipment that is known in
the art, a stream of liquified drive fluid is injected
into the well, and while this occurs, a load fluid is
injected into the well mixed with the liquified drive
fluid. The drive and load fluids can be pumped from
separate tanks using separate pumpers and mixed at a
pipe junction before proceeding down a single pipe
through a tree saver into the well.
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The ratio of liquified drive fluid to load
fluid should initially be at a level sufficient to
form a miscible bank of drive fluid in the gaseous
state ahead of the load fluid in the well. This amount
may be determined from the graphs in Figs. 1, 2 and 4
for various load fluids and carbon dioxide. Next, the
ratio of liquified drive fluid to load fluid injected
into the well is reduced. With the greater volume of
load fluid in this stage of the treatment, more sand
can be displaced into fractures created by frac
pressure on the mixture of load fluid and drive fluid.
In a first stage of treatment of the well,
the volume of liquified drive fluid injected into the
well may be initially greater than the volume of load
fluid injected into the well, for example the initial
drive fluid may be essentially pure, thus forming a
pad of drive fluid ahead of the load fluid.
In a second stage of treatment of the well,
after the greater volume of liquified drive fluid is
injected into the well, a mixture of liquified drive
fluid and load fluid is injected into the well with
the volume of liquified drive fluid being less than
the volume of load fluid in the mixture.
The drive fluid is preferably liquified
carbon dioxide and the load fluid is preferably
composed of aromatics, alkanes and naphthenes. It is
believed that linear alpha-olefin monomers may also be
used. Fracturing pressures are preferably applied
after the pad of drive fluid is injected into the
well, namely during the second stage of the treatment
only.
The load fluid is preferably a light
petroleum distillate, the preferred cut is about 100C
and greater. A good example is frac fluid known as
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FRACSOL~ fluid, derived from the Sundre C5+ condensate
available from Trysol Canada Limited of Calgary,
Alberta, Canada distilled to 110C. It includes the
following constituents (with volume fraction in
parentheses as determined by gas chromatography):
heptanes (0.0072), octanes (0.1191), nonanes (0.1028),
decanes (0.1143), undecanes (0.0927), dodecanes
(0.0687), tridecanes (0.0598), tetradecanes (0.0449),
pentadecanes (0.0366) and smaller quantities of C16+
alkanes, as well as smaller quantities of toluene
(0.0131), benzene and xylene (ethylbenzene, p + m-
xylene 0.0371, o-xylene 0.0156, 1,2,4 trimethylbenzene
0.0158). However, actual aromatic content is believed
to be about 35% (the gas chromatography does not
distinguish between some aromatics and alkanes). The
following products of Dome Petroleum Limited of
Calgary, Alberta, may also be used: FRAC OIL 120, FRAC
OIL 200, FRAC OIL 300, FRAC and OIL 500, as well as
SUPER FRAC~ made by Home Oil Company Limited of
Calgary, Alberta. A product with increased xylene, for
example XYSOL fluid available from Trysol Canada Ltd.,
may also be useful with actual aromatic content at
about 70% or greater.
In Fig. 2 is shown the miscibility
relationship for FRACSOL fluid and XYSOL fluid. The
miscibility relationship establishes the amount of
carbon dioxide required to form a bank of carbon
dioxide ahead of the load fluid in the formation. At
the frac pressure, the carbon dioxide should be
totally miscible in the hydrocarbon fluid (area A in
Figs. 1 and 2). At a pressure between the frac
pressure and the formation pressure, the carbon
dioxide should come out of solution to form the bank
ahead of the load fluid. It is preferred that the bank
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occupy between 10% and 100% of the pore volume of the
reservoir, with the higher rates (near 100%)
preferred. Thus, if the amount of carbon dioxide that
would be miscible in the load fluid is about 300m3/m3
at the formation pressure and temperature, then an
amount of carbon dioxide about 500m3/m3 should be
added to the hydrocarbon fluid. In the formation, the
load fluid in cracks in the formation and in the well
bore will have pressure equal to the static pressure
plus added pressure due to frac pressure. With
increasing distance within the formation from the
cracks communicating with the well bore, the pressure
gradually decreases to the formation pressure. It is
believed essential that the amount of carbon dioxide
in the load fluid should be sufficient that some
portion of the carbon dioxide comes out of solution
within the area where the pressure gradually reduces
to formation pressure. This may occur in the well bore
as well.
Fig. 4 shows bubble sensitivity curves for
several load fluids including XYSOL~, FRACSOL ~,
methylcyclohexane (a representative naphthene) and
tetradecene. For constant ration drive fluid to load
fluid, each line divides, for a given temperature,
pressures at which the mixture of drive fluid and load
fluid are in single phase (above the line) and two
phase (below the line). In reducing pressure during a
frac, the fluid in the formation and in the well bore
near the formation crosses the line and moves from
single phase to two phase. The line for
methylcyclohexane shows that a load fluid with a large
proportion of naphthenes, such as more than 50% by
volume, will be particularly useful for shallow wells.
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Fig. 3 shows a section from a reservoir
identifying a fracture zone 10, and reservoir 16, with
intermediate zones 12 and 14. From the far field
reservoir with no carbon dioxide and high
concentration of methane (being entirely reservoir
gas) at zone 16, the reservoir composition graduates
from pure methane at boundary 15 to part methane part
carbon dioxide in zone 14, and then to pure carbon
dioxide approximately at 13. This is a first miscible
bank. A second miscible bank starts with the pure
carbon dioxide and gradually becomes denser through
zone 12 as the concentration of the hydrocarbon liquid
base fluid increases until it reaches 7S - 80% base
liquid and 20 - 25% carbon dioxide that remains in the
fracture and the well bore beginning at the fracture
boundary 11.
During pressurizing of the load fluid and
drive fluid, carbon dioxide in load fluid within most
of the well bore remains in solution and carbon
dioxide in load fluid within and near the formation
leaks off the load fluid into the formation and forms
a bank of carbon dioxide ahead of the load fluid in
the formation and in the well bore. If the amount of
carbon dioxide is selected as described above, then
this will occur when fracturing pressure is applied to
the well.
Next, surface pressure is released from the
load fluid and the load fluid flows back out of the
well. For flow back, the amount of carbon dioxide is
reduced to an amount of carbon dioxide that is
effectively totally in solution at the formation
pressure. For the example described above this would
be about 300m3/m3. The pressure during flow back
should not be released too quickly, otherwise the
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methane may drive into and finger into the load fluid,
which may lead to an undesirable amount of load fluid
rem~; n; ng in the pores of the formation.
For wells with very high pressure, for
example 16MPa, a large amount of carbon dioxide is
required for load fluids with a moderate amount (35%
of aromatics). Thus, it is desirable to select a load
fluid having a lower proportion of aromatics, as for
example 10% - 20%, for higher pressure wells. The load
fluid aromatic content is thus selected according to
the pressure of the well formation. For wells with low
pressure, a load fluid with larger amounts of
aromatics is desired, such as XYSOL fluid, since more
carbon dioxide can be added in solution to load fluids
with larger amounts of aromatics.
For some wells, it may be desirable to use
the same or a similar fluid at lower than fracturing
pressures, but the same technique is still used to
ensure complete flowback of the load fluid.
Example 1
The Dunvegan formation in the Waskahigan
area of northwestern Alberta, is typically low in
liquid saturation. In the past, many types of frac
fluids have been used on this formation. The well
Amoco Waskahigan 15-12 for example had been fractured
with an emulsified mixture of aqueous and hydrocarbon
bases. This mixture was not miscible with the
reservoir gases. Production tests indicated the well
was capable of about 10(103)m3/day.
The formation static pressure is
approximately 8,500 kPa and temperature is 50 degrees
C. The well was cased with 177.8 mm casing down to a
formation depth of ca. 1450 m. Formation permeability
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was 1.6 md average, porosity was about 11% and water
saturation was 30%.
Evaluation of the miscibility data showed
that at this temperature and pressure 350 m3/m3 (35%
by volume) of CO2 is miscible in FRACSOL fluid (see
Fig. 2). The fracture treatment was executed with a
pad volume of 20 m3 of Fracsol hydrocarbon aromatic
fracturing fluid and CO2 mixture. The CO2 was mixed
at 550 m3/m3 (50% by volume). Fracturing pressures
at surface were 20,000 kPa and 24,600 kPa in the
formation. All the CO2 remains in solution in the
surface lines, bottom of the hole and in the fracture
as the pressure remains above 11,000 kPa where the gas
starts to evolve (see Fig. 2). However, as the fluid
leaks off, the pressure gradually drops below 11,000
kPa and CO2 comes out of solution until at the
reservoir pressure of 8,500 kPa only 350 m3/m3 of CO2
remains in solution. This evolved CO2 forms a
miscible bank between the reservoir gas methane and
the fracturing fluid CO2 mixture.
The remainder of the fracture treatment
consisted of FRACSOL hydrocarbon aromatic fracturing
fluid and CO2 mixture. The CO2 was mixed at the lower
concentration of 350 m3/m3 (35% by volume) necessary
for flow back.
After the treatment, 70~ of the treating
fluid was recovered. This is considered a high
percentage recovery. Productivity increased to 38
(103)m3/day
The load fluid should be formation
compatible, as would be understood by a person skilled
in the art. For example, it should not precipitate
waxes or asphaltenes to any great extent, which can be
determined experimentally before application of the
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12
fluid. The carbon dioxide forms a drive fluid, which
in the generalized invention is miscible in the load
fluid and in which the reservoir gas is miscible at
well treatment pressures and temperatures (for example
during fracturing, but also during lower pressure
treatments as for example squeezing).
Hypothetical Example
In a proposed frac process, to be applied to
a Rock Creek (Pembina, Alberta) reservoir, the bottom
hole pressure is 17900 KPa and the bottom hole
temperature is 70C, up to 820 m3/m3 of CO2 is miscible
in FRACSOL~. To establish the miscible bank, it is
recommended in this instance that the hole fill is
straight CO2, with the remainder of the frac being at
concentrations of 250 m3/m3 (31.5% by volume) of
liquid CO2 (with 68.5% FRACSOL~ fluid). For the frac
job, up to 61 m3 of FRACSOL~ may be required. Two frac
pumpers, a frac blender, one CO2 pumper and one CO2
trailer with 17,000 m3 CO2 are used, and 30 tonnes of
20/40 mesh sand. Firstly, the hole is filled with CO2
without applying frac pressures. Then 22 m3 CO2 mixed
with FRACSOL~ (31.5% CO2 and 68.5% FRACSOL~ by volume)
is injected at maximum rates down the well tubing.
Next 30 tonnes of the sand is mixed with the drive
fluid/load fluid mixture and frac pressures applied.
Finally, the well is flushed with 6.9 m3 of the same
mixture without sand.
A person skilled in the art could make
immaterial modifications to the invention described
and claimed in this patent without departing from the
essence of the invention.
