Note: Descriptions are shown in the official language in which they were submitted.
CA 02405154 2002-10-07
WO 01/88333 PCT/GBO1/02076
- 1 -
METHOD OF OIL/GAS WELL STIMULATION
The present invention relates to the stimulation of oil and gas wells,
particularly acidising and fracturing
processes, and in particular to such processes in which the well fluid is
based on hydrocarbyl,
especially alkyl or alkenyl, esters of certain aromatic carboxylic acids, to
invert fluids particularly
acidising and fracturing fluids, including such esters.
In hydrocarbon recovery, particularly oil and gas well stimulation e.g.
acidising and fracturing,
operations, it is common practice to fill the well bore with liquid. In many
cases this liquid is an
aqueous liquid having dissolved salts and/or suspended weighting solids to
give a liquid density such
that the hydrostatic pressure at the base of the bore equals, or exceeds the
pressure in the oil or gas
bearing formation at that point. However, with some oil and gas formations,
the presence of aqueous
liquid is desirably avoided e.g. because rock formations in the well bore,
commonly but not necessarily
in the production zone of the well, adversely react with water e.g. by
absorbing water and swelling or
by dissolving in the aqueous well fluid. In such situations it is common to
use non-aqueous liquids as
the well fluids for such operations.
This invention is directed to the use of certain aromatic carboxylic acid
esters, particularly hydrocarbyl,
desirably alkyl or alkenyl, esters, having valuable properties, in oil or gas
well stimulation processes or
as components in stimulation fluids. In particular these esters have a range
of viscosities, especially
extending to low viscosities, and toxicological and environmental profiles
that can make them
potentially very attractive as components of oil phase fluids for use in the
stimulation of oil and/or gas
wells.
Accordingly, the present invention provides a method of stimulating an oil or
gas well which includes
introducing into the well a fluid which has a continuous phase including at
least one compound of the
general formula (I):
(R2)p- Ph - (CH2)m - COO - (AO)n - R1 (I)
where
R1 is a C1 to C20 hydrocarbyl group, particularly a Cg to C1 g alkyl or
alkenyl group;
AO is an alkyleneoxy group, particularly an ethyleneoxy or a propyleneoxy
group, and may vary
along the (poly)alkyleneoxy chain;
n 0 or from 1 to 100, desirably 0;
m is 0, 1 or 2, desirably 0; and
Ph is a phenyl group, which may be substituted with groups (R2)p; where
each R2 is independently a C1 to Cq, alkyl or alkoxy group; and p is 0, 1 or
2, desirably 0;
and thereafter carrying out well stimulation operations.
SUBSTITUTE SHEET (RULE 26)
CA 02405154 2002-10-07
WO 01/88333 PCT/GBO1/02076
-2-
The well stimulation operations are desirably acidisation and/or fracturing of
rock forming the
production zone of the well. Accordingly the invention includes:
a method of acidisation of a hydrocarbon, particularly an oil or gas, well
which includes
introducing a acidisation fluid, which is an emulsion of an aqueous solution
of at least one
acidising material in a continuous phase of an ester containing liquid
including at least one
compound of the formula (I) as defined above, to a production zone of the well
and into contact
with a production formation whereby to acidise the formation;
a method of fracturing of a hydrocarbon, particularly an oil or gas, well in
which a fracturing fluid,
which is an emulsion of an aqueous acid phase in a continuous phase of an
ester containing
liquid including at least one compound of the formula (I) as defined above,
the fluid additionally
including a dispersion of solid proppant particles, is introduced into a
production zone of the well
and applying pressure to the fluid so as to subject the production zone to
hydraulic fracturing;
an acidisation fluid which is an emulsion of an aqueous solution of at least
one acidising material
in a continuous non-aqueous phase including at least on compound of the
formula (!) as defined
above; and
a fracturing fluid which is an emulsion of an aqueous medium in a continuous
non-aqueous
phase including at least on compound of the formula (I) as defined above, the
fluid additionally
including a dispersion of solid proppant particles.
In the compound of the formula (I) used in the invention R1 is desirably an
alicylcic group, and
particularly can be an alkyl or alkenyl group. Alkyl groups have the advantage
that they are more
stable, particularly to oxidation, than alkenyl groups, but alkenyl esters
generally remain fluid at lower
temperatures than alkyl esters, especially for longer chain materials.
Desirably, an alkenyl group
includes only a single double bond as multiple unsaturation generally gives
poor stability. R1 can be a
relatively short chain e.g. a C3 to Cg, alkyl group, and is desirably branched
e.g. it is an iso-propyl
(prop-2-yl), sec-butyl (but-2-yl), iso-butyl (2-methyl-prop1-yl) and/or teri
butyl group, to reduce the ease
with which the ester can be hydrolysed. Such esters with secondary alcohols
are particularly useful
and R1 is thus especially a C3 to C5 secondary alkyl group and very desirably
an iso-propyl group. A
benefit of such short chain esters is that they have low viscosity. Longer
chain esters generally have
somewhat higher viscosites, but may also be used, particularly in mixed
systems (see further below)
and, thus, R1 can be a Cg to C20, particularly a Cg to C1 g alkyl or alkenyl
group which may be straight
chain or branched e.g. as in 2-ethylhexyl or iso-nonyl or branched chain C1 g
alkyl as in so-called iso-
stearyl (actually a mixture of mainly branched C14 to C22 alkyl with an
average chain length close to
C1 g). A particular unsaturated longer chain group is oleyl. Where longer
chain length groups are
SUBSTITUTE SHEET (RULE 26)
CA 02405154 2002-10-07
WO 01/88333 PCT/GBO1/02076
-3-
used, particularly longer than C12, it is desirable that they include
branching and/or unsaturation as
these promote liquid esters where straight chain saturated ester compounds may
be solid and thus
more difficult to use.
Although the carboxylic acid used in the ester can be a dihydrocinnamic acid
or a phenylacetic acid, it
is very desirably a benzoic acid i.e. desirably m is 0. Similarly, although
the phenyl ring of the acid may
be substituted, it is desirable that it is unsubstituted i.e. desirably p is
0. The esters used in the
invention may include a (poly)alkyleneoxy chain, (AO)n in formula (I), between
the carboxyl group and
the group R1. When present the (poly)alkyleneoxy chain is desirably a
(poly)ethyleneoxy, a
(poly)propyleneoxy chain or a chain including both ethyleneoxy and
propyleneoxy residues. Generally,
it is desirable not to include such a chain in the ester i.e. desirably n is
0.
Among the esters useful in this invention is iso-propyi benzoate which has a
combination of properties
that contribute to its usefulness: it has a wide liquid range (BP ca
219°C and pour point < -60°C); it is
classified as non-flammable (flash point ca 99°C) and under normal use
conditions it has a low vapour
pressure; it has a density similar to that of water (1.008 kg.l-1 at
25°C); and a low viscosity (2.32 cSt at
25°C; measured by the U tube method, equivalent to 2.34 mPa.s).
To provide a balance of properties e.g. to have a fluid with a particular
viscosity, mixed esters, having a
variety of groups R1, or blends of compounds of the formula (I), may be
advantageous. Such mixed
esters of blends can have the additional benefit that they are more liquid
than pure, especially linear
saturated compounds of similar overall R1 carbon number. Particular mixed
esters of low to moderate
viscosity are those including esters having a relatively large group R1 e.g.
e.g. iso-stearyl or oleyl, with
esters having a relatively small group R1 e.g. isopropyl.
The fluid used in this invention can be wholly of one or more compounds of the
formula (I), or it may
contain other components used in admixture. Although aromatic hydrocarbons can
be included it is
unlikely that they will be used as a major component of any such mixed carrier
fluid, because of their
adverse environmental impact. Mixtures with non-aromatic hydrocarbon liquids
e.g. paraffinic fluids
may be used, but paraffins are relatively non-biodegradable so will generally
not be preferred.
Mixtures of compounds of the formula (I) with fluid esters such as fatty acid
esters e.g. triglycerides or
C1 to C20 monocarboxylic fatty acid C1 to C20 alkyl or alkenyl esters, can be
used with advantage. In
particular, as the monocarboxylic fatty acid esters often have moderate
viscosities e.g. isopropyl oleate
has a viscosity of ca 5.3 cSt at 40°C, the use of combinations of such
esters with esters of the
formula (I), particularly where R1 is a C1 to C6, more particularly a C3 to C5
branched chain alkyl
group and especially where the ester is or includes isopropyl benzoate, can
give mixtures with low
viscosity.
SUBSTITUTE SHEET (RULE 26)
CA 02405154 2002-10-07
WO 01/88333 PCT/GBO1/02076
-4-
When mixtures are used, compounds of the formula (I) will typically be present
in at least 10%, usually
at least 25%, more usually at least 40%, desirably at least 50%, by weight of
the total fluid used. When
present, other solvent components will desirably be used at level typically of
from 1 to 90, usually 1 to
75%, more desirably 2 to 60, and particularly 5 to 50% by weight of the total
carrier fluid used.
Relatively low proportions of esters of the formula (I) can be usefully used
to reduce the viscosity of
conventional non-aqueous, especially organic ester, fluids.
The compounds of the formula (I) are particularly useful as, or as components
of, fluids for use in oil or
gas well stimulation. Oil and gas wells may initially flow sluggishly, or
after producing at a satisfactory
rate over a period of time, then flow sluggishly. Such wells are often
subjected to stimulation treatment
to increase the flow of oil and/or gas particularly by acidisation and/or
fracturing, particularly hydraulic
fracturing.
Acidisation typically involves injecting into the production zone of an oil or
gas well an acidic fluid
including acidic materials such as hydrochloric acid, typically aqueous HCI at
a concentration usually
from 2 to 30% by weight (based on the total weight of the acidising fluid),
"mud acid", a mixture of
hydrochloric and hydrofluoric acids, typically in aqueous solution at a
concentration usually from
2 to 30% by weight and a weight ratio of HCI to HF typically about 5:1, or,
particularly if slower reaction
is desired, "organic acids", a mixture of acetic and formic acids, typically
in aqueous solution at a
concentration usually from 1 to 40% by weight and a weight ratio of acetic to
formic typically about 1:2.
By applying suitable pressure, usually mainly provided by hydrostatic
pressure, the acidisation fluid is
forced into the production rock around the well and dissolves acid soluble
materials from the
production rock. Subsequently the acidisation fluid is removed from the
production rock by reducing
the pressure and is pumped out of the well. Where water sensitive formations
are treated, it is
desirable to provide the acidisation materials as an emulsion in a non-aqueous
base fluid. Accordingly
this invention includes an oil or gas well acidisation fluid which is an
emulsion of an aqueous solution of
at least one acidising material in a continuous non-aqueous phase including at
least on compound of
the formula (I) as defined above and further includes a method of stimulating
an oil or gas well by
introducing an acidisation fluid into a production zone of the well in which
the well fluid used is an
emulsion of an aqueous solution of at least one acidising material in a
continuous non-aqueous phase
including at least on compound of the formula (I) as defined above.
Well fluids used for acidising treatments typically include other materials
for example:
acid corrosion inhibitors - as the acids used in acidisation are highly
corrosive towards metals,
particularly having a strong tendency to pitting metal surfaces, corrosion
inhibitors such as
propargyl alcohol, amines, thio-compounds, are often included, typically at
levels of from 1 to 4%
by weight of the acidising fluid, to reduce the rate of corrosion of metal,
particularly steel,
equipment such as pipes, tubes and surface equipment.
SUBSTITUTE SHEET (RULE 26)
CA 02405154 2002-10-07
WO 01/88333 PCT/GBO1/02076
-5-
surfactants - are often included in acidising fluids to reduce the interfacial
tension and thereby aid acid
penetration, particularly of smaller capillaries, within the reservoir rock.
Typically such
surfactants are non-ionic surfactants such as alcohol alkoxylates and anionic
surfactants such
as sulphonates or sulphonic acids such as dodecyl benzene sulphonic acid, and
are used
typically at levels of from 0.1 to 1 % by weight of the acidising fluid.
acid retarders - when acidisation materials are injected into the rock
formation there is a tendency for
it to react mainly in the immediate vicinity in the well bore, and organic
acids, particularly acetic
and/or formic acids, can be mixed with the main acidising materials such as
HCI, to slow
reaction such that the formation away from the well bore is also effectively
treated. They are
used typically at levels of from 0.1 to 1 % by weight of the acidising fluid.
demulsifiers - in acidisation treatments of oil and gas wells, the unspent
acidic materials and the
reaction products of acidisation are circulated out of the well. These
materials, together with
other system components such as corrosion inhibitors, tend to give rise to
water in oil emulsions
and to prevent stable emulsions forming, demulsifiers are usually included in
the acidisation
fluid. Suitable demulsifiers are generally blends of cationic surfactants such
as quaternary
ammonium surfactants with non-ionic surfactants such as alcohol alkoxylates
typically at levels
of from 0.1 to 1 % by weight of the acidising fluid and weight ratios of
cationic to non-ionic
surfactant of from 5:1 to 1:1. A further benefit of including demulsifiers is
that they act as anti-
sludge agents.
diverting agents - heterogeneous or layered formations have different
permeability zones and during
acidisation, the acidic materials penetrate further in more permeable strata.
To acidise a
formation uniformly, diverting agents such as wax balls, benzoic acid crystals
and rock salt,
typically having an average particle size of from 1.5 to 6.5 mm, are
introduced to reduce the rate
of flow of acidising material into the more permeable strata and effectively
to divert acid to less
permeable strata. When oil flow (re)starts the diverting agents are dissolved
in the oil and thus
removed. Amounts used are typically in the range 6 to 12% w/v of the acidising
fluid.
clay stabilisers - some oil and gas reservoirs, particularly sandstone
reservoirs, contain varying
amounts of clays, which are usually water sensitive and disperse when
contacted by aqueous
solutions. The dispersed fines can choke the throats of the sand grains and
reduce permeability
of the formation. Clay stabilising agents such as polyquaternary amines and
quaternary
surfactants can be introduced to inhibit mobilisation of clay. The amount of
clay stabiliser used
is typically from 0.1 to 5% by weight of the acidising fluid.
The pressure gradient in a flowing (oil) well is generally broadly
proportional to the logarithm of the
distance from the well bore, so that during production the major pressure drop
is round the well bore
and in tight or low permeable formations the flow of oil or gas can be or
become very sluggish.
SUBSTITUTE SHEET (RULE 26)
CA 02405154 2002-10-07
WO 01/88333 PCT/GBO1/02076
-6-
Increasing the permeability of the production formation around the well bore
can increase the rate of
production very substantially. Such increases in permeability of the rock
formation can be achieved by
fracturing the formation. In hydraulic fracturing a viscous fluid, usually
based on water and typically
including fluid loss chemicals (similar to those described above in relation
to acidising) and propping
agents, typically finely divided inert solid particles, are pumped into the
well to generate in the
formation a pressure above the fracturing pressure of the formation. The
fracturing fluid can be either
water or oil based (e.g. kerosene, a gas oil, diesel oil, or the like). The
following chemicals are used for
hydraulic fracturing:
viscosifiers - are used to increase viscosity of the fracturing fluid.
Examples useful in oil based
fracturing fluids include non-ionic resins such as hydrocarbon resins. Other
viscosity modifiers
include phosphate esters which can be used as gelling agents in oil based
fluids and
polysaccharide derivatives with low residue which can be used as gelling
agents for low
temperature jobs. Viscosifiers such as guar gum and xanthan can be used to
give particular
rheological properties if desired. The amount of viscosifier used is typically
from 0.1 to 1 % by
weight of the fracturing fluid.
propping agents (proppants) - during hydraulic fracturing, fractures are
created, and these tend to
close due to overburden pressure when the fracturing pressure is dissipated.
To prevent this
' proppants are added to the fracturing fluid. Typical proppants are inert
finely divided solid
materials such as silicon dioxide, silica sand, hardened glass, aluminium
oxide and/or zirconium
oxide, usually having an average particle size of from 0.5 to 2 mm. The amount
of proppant
used is typically in the range 12 to 120% w/v of the fracturing fluid.
friction reducers - certain high molecular weight linear polymers are used as
friction reducers to
reduce the pressure drop in the tubing while pumping fracturing fluid at very
high rate (e.g.
polyisobutylene, polyisobutyl methacrylate). The amount of friction reducer
used is typically
from 0.1 to 1 % by weight of the fracturing fluid.
surfactants - non-ionic surfactants such as alcohol alkoxylates and anionic
surtactants such as
sulphonates or sulphonic acids such as dodecyl benzene sulphonic acid, are
used to lower
surface tension and improve well clean-up. The amount of surfactant used is
typically
from 0.1 to 1 % by weight of the fracturing fluid.
One approach to overcome the use of costly oil in a water external emulsion
for hydraulic fracturing,
acidising and other well treatment applications has been to use an oil
external phase or water in oil
emulsion (also known as "invert" emulsions). Such invert emulsions generally
include from about 10 to
30% by volume of oil (as compared with the 50 to 80% oil typical in oil in
water emulsions. However,
conventionally a major disadvantage of invert emulsions which severely limits
their use in well
stimulation is that they have very high viscosities (as compared with oil in
water emulsions) resulting in
SUBSTITUTE SHEET (RULE 26)
CA 02405154 2002-10-07
WO 01/88333 PCT/GBO1/02076
-7-
high frictional resistance to flow down the well tubulars. As is described
above, esters of the formula (I)
e.g. isopropyl benzoate, can have very low viscosities and thus potentially
overcome this difficulty of
invert emulsions.
Other additives can be included in the fluids of the invention in accordance
with common practice.
Examples of such additives include fluid loss agents particularly such as
synthetic polymers such as
polyacrylamides, polyacrylates, polyamides and similar polymers (some of which
can also function as
viscosity improving agents); corrosion inhibitors; scale inhibitors oxygen
scavengers; and other similar
additive materials.
To readily maintain a balancing pressure in the production formation during
stimulation operations, it
will usually be desirable to have an overlying layer of a weighted well fluid
to maintain adequate
pressure at the production zone of the well e.g. to reduce the extent to which
the oil and/or gas enters
the well bore during completion or workover operations. These fluids can be
oil based and such fluids
and their use in drilling, completion and workover operations are described in
co-pending UK patent
application No 0011584.0, filed on 15th May 2000 (applicant's reference UQI
50890). The use of such
fluids in layers above the stimulation fluids, particularly acidisation or
fracturing fluids of and used in
this invention is within this invention which thus includes stimulation
methods in which the overlying
fluid is a fluid which is an emulsion of an aqueous phase including dissolved
salts in a continuous
phase of an ester containing liquid including at least one compound of the
formula (I) as defined above,
the fluid further including a dispersion of weighting solids.
SUBSTITUTE SHEET (RULE 26)
CA 02405154 2002-10-07
WO 01/88333 PCT/GBO1/02076
_g-
The following Examples illustrate the invention. All parts and percentages are
by weight unless
otherwise specified.
Materials
Oil 1 iso-propyl benzoate
Oil 2 ethyl benzoate
Oil 3 2-ethylhexyl benzoate
Oil 4 nonyl benzoate
Oil 5 iso-stearyl* benzoate (* see description above)
Emul1 Hypermer B261: water in oil emulsifier co(polyester polyether)
surfactant ex Uniqema
water demineralised water
brine synthetic sea water (to British Standards 3900 and 2001 )
Example 1
An invert emulsion fracturing fluid was made by emulsifying brine in Oil1 and
then dispersing a
proppant in the emulsion. An invert emulsion fluid was made up by mixing 27
parts by weight Oil1 and
3 parts by weight Emul1 in a Hamilton beach blender under high shear. 70 parts
by weight of brine
was then added dropwise to the oil/emulsifier blend under high shear mixing
(using a Silverson mixer)
to form a water in oil emulsion. The emulsion temperature was maintained below
55°C using a (cold)
water bath around the mixing vessel. Mixing was continued for 15 minutes after
complete addition of
the aqueous phase. 100 parts by weight silica sand, having a minimum particle
size of 100 ~m and an
average particle size of about 300 Vim, was mixed into the emulsion to act as
a proppant. The
dispersion remained stable after storage at 50°C for 24 hours. A
comparative dispersion was made up
by the method described above but using diesel oil as the oil phase and some
sand dropped out of
suspension after storage at 50°C for 24 hours.
Example 2
An invert emulsion acidising fluid was made up by the emulsification method
described in Example 1,
but using 70 parts by weight 15% wlv aqueous hydrochloric acid as the aqueous
phase (and omitting
the proppant).
Example 3
Further invert emulsion fracturing fluids were made up as described in Example
1, but using Oil 2, Oil
3, Oil 4, Oil 5 and Oil 6 rather than the Oil 1 used in Example 1 using a
similar proppant as described in
Example 1. The stability of the propppant dispersion in these emulsion
fracturing fluids (the emulsions
themselves remaining stable) was assessed under storage at ambient temperature
and 50°C for 1 day,
and the results are reported in the table below.
SUBSTITUTE SHEET (RULE 26)
CA 02405154 2002-10-07
WO 01/88333 PCT/GBO1/02076
_g_
Ex Oil Suspension
No stability
ambient 50C
3.1 Oil2 good good
3.2 Oil3 good moderate
3.3 Oil good moderate
4
3.4- Oil5 ~ good moderate
good = proppant remains suspended; moderate = some signs of proppant drop out
observed
Example 4
Further invert emulsion acidising fluids were made up as described in Example
2, but using Oil 2, Oil 3,
Oil 4 and Oil 5 rather than the Oil 1 used in Example 2. The stability of the
acidising fluids was
assessed after 1 hour at ambient and 50°C also after overnight storage
at 50°C. The results are set
out in the Table below.
Ex Oil Stability
No
1 hour amb 1 hour 50C 18 hours
50C
4.1 Oil2 Stable Stable Stable
4.2 Oil Stable Stable 30% break
3
4.3 Oil Stable <1 % break <1 % break
4
4.4 Oil Stable Stable 3% break
~ 5
~
SUBSTITUTE SHEET (RULE 26)
