U.S. patent application number 14/377438 was filed with the patent office on 2016-01-14 for novel nanoparticle-containing drilling fluids to mitigate fluid loss.
The applicant listed for this patent is Geir HARELAND, Maen Moh'd HUSEIN, Mohammad Ferdous ZAKARIA. Invention is credited to Geir HARELAND, Maen Moh'd HUSEIN, Mohammad Ferdous ZAKARIA.
Application Number | 20160009979 14/377438 |
Document ID | / |
Family ID | 48946853 |
Filed Date | 2016-01-14 |
United States Patent
Application |
20160009979 |
Kind Code |
A1 |
HUSEIN; Maen Moh'd ; et
al. |
January 14, 2016 |
NOVEL NANOPARTICLE-CONTAINING DRILLING FLUIDS TO MITIGATE FLUID
LOSS
Abstract
The present invention is directed to a well fluid, and in
particular a drilling fluid having low amounts of nanoparticles
which act as fluid loss material for reducing fluid loss in an
underground formation. The fluid is a nanoparticle-containing well
fluid comprising a base fluid and about 5 wt % or less
nanoparticles, for preventing or reducing fluid loss to an
underground formation, wherein the well fluid is a drilling fluid,
kill fluid, completion fluid, or pre-stimulation fluid. The
invention also includes in situ and ex situ methods of forming the
nanoparticles.
Inventors: |
HUSEIN; Maen Moh'd;
(Calgary, CA) ; ZAKARIA; Mohammad Ferdous;
(Calgary, CA) ; HARELAND; Geir; (Calgary,
CA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
HUSEIN; Maen Moh'd
ZAKARIA; Mohammad Ferdous
HARELAND; Geir |
Calgary
Calgary
Calgary |
|
CA
CA
CA |
|
|
Family ID: |
48946853 |
Appl. No.: |
14/377438 |
Filed: |
February 9, 2012 |
PCT Filed: |
February 9, 2012 |
PCT NO: |
PCT/CA2012/050075 |
371 Date: |
August 7, 2014 |
Current U.S.
Class: |
507/140 |
Current CPC
Class: |
C09K 8/04 20130101; E21B
21/00 20130101; C09K 2208/34 20130101; C09K 8/502 20130101; E21B
43/16 20130101; E21B 21/062 20130101; C09K 8/5045 20130101; C09K
8/36 20130101; C09K 2208/10 20130101; C09K 8/32 20130101; C09K
8/032 20130101 |
International
Class: |
C09K 8/36 20060101
C09K008/36 |
Claims
1. A nanoparticle-containing well fluid comprising a base fluid and
about 5 wt % or less nanoparticles, for preventing or reducing
fluid loss to an underground formation, wherein the well fluid is a
drilling fluid, kill fluid, completion fluid, or pre-stimulation
fluid.
2. The well fluid of claim 1 wherein the well fluid is a drilling
fluid.
3. The well fluid of claim 2 wherein the drilling fluid is an
invert emulsion drilling fluid.
4. The fluid of claim 1 wherein the nanoparticles are present in an
amount of less than about 4 wt %, less than about 3 wt %, or less
than about 1%.
5. (canceled)
6. (canceled)
7. The fluid of claim 1 wherein the nanoparticles are present in an
amount of between about 0.1 to about 1 wt %; between about 0.5 to
about 1.0 wt %; between about 0.6 to 1 wt %; or between about 0.74
to about 1 wt %.
8. (canceled)
9. (canceled)
10. (canceled)
11. The fluid of claim 1 wherein the nanoparticles have a particle
size of between about 1 to about 120 nm or between about 1 to about
30 nm.
12. (canceled)
13. (canceled)
14. The fluid of claim 11 wherein substantially all of the
nanoparticles have a particle size in the range of 1-30 nm.
15. The fluid of claim 1 wherein the nanoparticles are one or more
of metal hydroxide, metal oxide, metal carbonate, metal sulfide,
and metal sulfate.
16. The fluid of claim 15 wherein the nanoparticles are selected
from the group consisting of iron hydroxide, iron oxide, calcium
carbonate, iron sulfide, barium sulfate, or a mixture thereof.
17. The fluid of claim 15 wherein the nanoparticles are iron oxide
formed from iron hydroxide in high pressure high temperature
conditions in the underground formation.
18. The fluid of claim 1 wherein the nanoparticles are formed in
situ in the fluid or formed ex situ and added to the fluid.
19. (canceled)
20. (canceled)
21. (canceled)
22. (canceled)
23. (canceled)
24. The fluid of claim 1 wherein the reduction of fluid loss is at
least about 70% compared to a well fluid that does not contain loss
circulation materials or nanoparticles.
25. (canceled)
26. (canceled)
27. A method of making the nanoparticle-containing well fluid
defined in claim 1 by forming the nanoparticles ex situ, comprising
the steps of providing aqueous-based precursor solutions for
forming the nanoparticles, mixing the precursor solutions under
high shear, and adding the mixed precursor solution to the well
fluid, to form the nanoparticle-containing fluid, wherein the
nanoparticles act as fluid loss material for reducing fluid loss in
an underground formation.
28. A method for making a nanoparticle-containing well fluid
defined in claim 1 by forming the nanoparticles in situ, comprising
the steps of providing aqueous-based precursor solutions for
forming the nanoparticles, adding the precursor solutions to the
well fluid, and subjecting the fluid to mixing and shear to form
the nanoparticle-containing fluid, wherein the nanoparticles act as
a fluid loss material for reducing fluid loss in an underground
formation.
29. The method of claim 28 wherein the fluid is an invert emulsion
drilling fluid and the nanoparticles form in the dispersed water
pools of the invert emulsion drilling fluid.
30. The method of claim 28 wherein the nanoparticle is iron (III)
hydroxide.
31. The method of claim 29 wherein the aqueous-based precursor
solutions comprise an aqueous based solution containing
FeCl.sub.3(aq) and an aqueous based solution containing
NaOH.sub.(aq); the aqueous-based solutions comprise an aqueous
based solution containing Ca(NO).sub.3 and an aqueous based
solution containing Na.sub.2CO.sub.3; the aqueous-based solutions
comprise an aqueous based solution containing BaCl.sub.2 and an
aqueous based solution containing Na.sub.2SO.sub.4; or the
aqueous-based solutions comprise an aqueous based solution
containing Na.sub.2S and an aqueous based solution containing
FeCl.sub.2.
32. (canceled)
33. (canceled)
34. (canceled)
35. The method of claim 27 wherein the fluid is an invert emulsion
drilling fluid and the nanoparticles form in the dispersed water
pools of the invert emulsion drilling fluid.
36. The method of claim 27 wherein the nanoparticle is iron (III)
hydroxide.
37. The method of claim 27 wherein the aqueous-based precursor
solutions comprise an aqueous based solution containing
FeCl.sub.3(aq) and an aqueous based solution containing
NaOH.sub.(aq); the aqueous-based solutions comprise an aqueous
based solution containing Ca(NO).sub.3 and an aqueous based
solution containing Na.sub.2CO.sub.3; the aqueous-based solutions
comprise an aqueous based solution containing BaCl.sub.2 and an
aqueous based solution containing Na.sub.2SO.sub.4; or the
aqueous-based solutions comprise an aqueous based solution
containing Na.sub.2S and an aqueous based solution containing
FeCl.sub.2.
Description
FIELD OF THE INVENTION
[0001] The present invention relates to drilling fluids and in
particular drilling fluids with nanoparticles for mitigating fluid
loss to underground formations.
BACKGROUND OF THE INVENTION
[0002] Hydrocarbons, such as oil and gas, are recovered from
underground formations through drilled wells. The success of any
well drilling operation depends on many factors and one of the most
important is the drilling fluid. Drilling fluids, also called
drilling muds, are circulated from the surface through the drill
string and introduced to the bottom of the borehole as fluid spray
out of drill bit nozzles and subsequently circulated back to the
surface via the annulus between the drill string and the well hole.
Drilling fluids are formulated to cool down and lubricate the drill
bit, remove cuttings from the hole, prevent formation damage,
suspend cuttings and weighting materials when circulation is
stopped, and cake off the permeable formation by retarding the
passage of fluid into the formation.
[0003] Drilling operations face great technical challenges with
drilling fluid loss being the most notable. Fluid loss is also an
issue for other well fluids such as kill fluids, completion fluids
and stimulation fluids. Drilling fluid loss is the partial or
complete loss of fluid to the formation during drilling. Loss of
fluid, in turn, impacts the cost of drilling. Therefore, drilling
and other well fluids are typically formulated with loss
circulation materials or additives (LCM). The primary function of
LCM is to plug the zone of loss in the formation, away from the
borehole face so that subsequent operation will not suffer
additional fluid losses. LCM form a barrier, such as filter cake,
which limits the amount of drilling fluid penetrating the formation
and prevents loss. New lost circulation materials have been
developed in the past 10 years. However, these lost circulation
materials are not sufficiently effective to serve their primary
goal of eliminating fluid loss.
[0004] It is often impossible to reduce fluid loss with these micro
and macro type fluid loss additives due to their physio-chemical
and mechanical characteristics. LCM with diameters in the range of
0.1-100 .mu.m may play an important role when the cause of fluid
loss occurs in 0.1 .mu.m-1 mm porous formations. In practice,
however, the size of pore openings in formations such as shales
that may cause fluid loss is in the range of 10 nm-0.1 .mu.m and
these larger micro and macro type fluid loss additives are not
effective in reducing fluid loss.
[0005] Nanoparticles have been used in well fluids for a number of
purposes.
[0006] U.S. Pat. No. 3,622,513 (1971) is directed to oil-based
drilling fluids with improved plastering properties and reduced
fluid loss properties at extreme conditions of borehole temperature
and pressure. The drilling fluids contain asphaltous material and a
weighting agent, usually barium sulfate having a particle size of
100 to 200 .mu.m, which primarily result in the formation of the
filter cake to prevent fluid loss to the formation. The drilling
fluids also contain a small amount of a secondary weighting
material inert to the fluid and having a particle size of less than
3 .mu.m. Preferred inert materials for the secondary weight phase
include metal oxides such as iron oxides and titanium oxides. The
fluids showed some reduction in fluid loss. However, the
compositions required extra additives, such as the asphalt
material, which bind to the nanoparticles and acted as a filler or
plaster between the particles at high temperature to reduce the
fluid loss. The fluid may also contain other lost circulation
additives.
[0007] U.S. Pat. No. 3,658,701 (1972) is directed to an oil based
drilling fluid, including an invert emulsion drilling fluid,
employing particular oxides, such as manganese oxide, to reduce
fluid loss. The oxide is used with asphalt constituents. The
asphaltic materials bind the metal oxide at high temperature and
acted as a filler between the particles to reduce the fluid loss.
With the addition of MnO.sub.2, and the asphaltic material, the
fluid loss reduction was approximately 66% as compared to the
control sample at 300.degree. F. with substantially no breakdown of
the emulsion. The patent does not disclose the size of the
particles. Further, it appears that the asphaltic material is
necessary to obtain the fluid loss benefit.
[0008] U.S. Pat. No. 6,579,832 (2003) is directed to a method of
rapidly adjusting the fluid density of drilling fluids using
superparamagnetic nanoparticles. The particles were effective to
change the density state of the fluid required to control
subsurface pressures, and to preserve and protect the drilled hole
until a casing is run and cemented. The nanoparticles were sized
between 0.5 and 200 nm and formed into clusters having an average
size of between 0.1 and 500 .mu.m. The clusters were formed by
incorporating the nanoparticles into a matrix of glass or ceramic.
Group VIII metals Cd, Au and their alloys were found to provide an
excellent result in adjusting fluid density in a reversible manner.
90% of the supermagnetic nanoparticles from the treated drilling
fluid from the downhole location were recovered by a magnetic field
at the surface resulting in the adjustment of drilling fluid
density within a short period of time and circulation of the
magnetic nanoparticles to the surface level for reuse in the
drilling fluid. This patent does not however disclose the use of
the nanoparticles for reducing fluid loss. The nanoparticles
controlled only density of the fluid. The nanoparticles were formed
into clusters on a matrix and required an external magnetic field
for recovery.
[0009] U.S. Patent Application 2009/314549 (2009) considered
compounds for reducing the permeability of shale formations using
specific nanoparticles in the drilling fluids. By identifying the
pore throat radii of shale samples, fine particles were selected
that would fit into the pore throats during the drilling process
and create a non-permeable shale surface. The drilling mud was a
water-based mud with nanoparticles having a size range of 1-500 nm
selected from silica, iron, aluminum, titanium or other metal
oxides and hydroxides and also composed of a surface active agent.
The aqueous well-drilling fluid contained between about 5 to 50
weight percent, based on the weight of the aqueous phase and
resulted in a reduction in permeability of the shale, which
resulted in drastic reduction of absorbed water and potential for
collapse. The minimum concentration required to reduce the fluid
penetration was 10 wt % nanoparticles and in some cases, required
high concentrations of nanoparticles of 41 wt %.
[0010] The application of this fluid pertained to nanopore throat
reduction rather than reducing overall fluid loss which can occur
in macro, micro, and nano type pores. Reducing permeability and
plugging the pore throat requires that the fluid particles interact
with the pores internally. This blocks the pore channel and can
cause formation damage which will reduce or interrupt oil and gas
production. Further, permeability reduction took a longer time with
a higher amount of silica nanoparticles. It would be more
preferable to plug the pore externally and avoid reducing
permeability and formation damage.
[0011] Aqueous-based drilling fluids generally require a higher
concentration of nanoparticles than other types of drilling fluids.
They also require additional additives such as surfactants to
stabilize the nanoparticles in the fluid system whereas other based
fluids, such as invert emulsion drilling fluids, do not need to
include other additives to completely disperse the nanoparticles.
Nanoparticles that have a hydroxyl group tend to agglomerate faster
in aqueous based fluids. This agglomeration causes poor dispersions
and the addition of surfactants reduces this problem. Poor
dispersion in turn causes fluid loss even after the addition of the
nanoparticles. As well, flocculated or poorly dispersed suspensions
form more voluminous sediments. The resulting filter cake is not as
dense and impenetrable as compared to that formed from a stable
suspension. Therefore, the use of nanoparticles in aqueous based
fluids teaches little about its use in non-aqueous-based fluids
such as invert emulsions. This publication also did not consider
high temperature and high pressure conditions.
[0012] A related publication is "Use of Nanoparticles for
Maintaining Shale Stability" Sensoy (2009). It also discloses the
use of nanoparticles in an aqueous drilling fluid for nanopore
throat reduction. It found that the 5 wt % of nanoparticles in the
fluid was less effective and the minimum level of nanoparticles was
at least 10 wt %. It also tested higher levels of 29 wt % and 41 wt
%. The paper concludes that higher amounts of nanoparticles were
preferable to achieve the nanopore throat reduction. This paper
does not discuss reducing drilling fluid loss to the formation.
[0013] U.S. Pat. No. 7,559,369 (2009) is directed to a composition
for a well treatment fluid and specifically to a well cement
composition and a method of cementing a subterranean formation. The
cement composition comprises cement, water and at least one
encapsulated nanoparticle selected from the group consisting of
particulate nano-silica, nano-alumina, nano-zinc oxide, nano-boron,
nano-iron oxide and combinations thereof. The nanoparticles have a
particle size in the range of from about 1 nm to about 100 nm and
are present in an amount in the range of from about 1% to about 25
wt %. They reduce the cement setting time and increased the
mechanical strength of the resulting cement. This patent teaches
nothing about the use of nanoparticles as loss circulation
materials in drilling fluids and their effect on fluid loss to the
formation.
[0014] U.S. Patent Application 2011/59871 (2010) relates to a
drilling fluid including graphene and chemically converted
nanoplatelet graphenes with functional groups. The graphene
comprised about 0.001% to about 10 vol % of the drilling fluid. The
functionalized chemically-converted graphene sheets were about 1.8
to about 2.2 nm in thickness. Whatman 50 allowed some graphene
oxide to pass through the filter. Nanoparticles pass through the
filter paper along with the filtrate which may block the
interporosity of rock and create formation damage. This may result
in permeability impairment and thus lead to a reduction in oil and
gas production.
[0015] U.S. Patent Application 2009/82230 (2009) relates to an
aqueous-based well treatment fluid, including drilling fluids,
containing a viscosifying additive. The additive has calcium
carbonate nanoparticles with a median particle size of less than or
equal to 1 .mu.m. The amount of calcium carbonate nanoparticles
used in the drilling fluid was approximately 20 wt %. The
nanoparticles used in the well treatment fluid were capable of
being suspended in the fluid without the aid of a polymeric
viscosifying agent. The addition of the nanoparticles altered the
viscosity of the fluid. Nanoparticles suspended in a well treatment
fluid even at high temperature as 350.degree. F. typically exhibit
sag (inadequate suspension properties) no greater than about 8%.
The viscosity changes of a fluid with the addition of nanoparticles
are well known. However, even with the high amount of nanoparticles
added to the fluid formulation, no fluid loss value is
reported.
[0016] U.S. Patent 2011/162845 discloses a method of servicing a
wellbore. It introduces a lost circulation composition into a lost
circulation zone to reduce the loss of fluid into the formation.
The lost circulation composition comprised Portland cement in an
amount of about 10 wt % to about 20 wt % (of the lost circulation
composition), nanoparticles and in particular nano-silica in an
amount of about 0.5 wt % to about 4 wt % and having a particle size
of about 1 to about 100 nm, amorphous silica in an amount of about
5 wt % to about 10 wt %, synthetic clay in an amount of about 0.5
wt % to about 2 wt %, sub-micron sized calcium carbonate in an
amount of about 15 wt % to about 50 wt % and water in an amount of
about 60 wt % to about 75 wt %. The lost circulation compositions
rapidly developed static gel strength and remained pumpable for at
least about 1 day. The sample was observed to gel while static but
returned to liquid upon application of shear.
[0017] Loss circulation additives are formed with a mix of
nanocomponents and cement to reduce the setting time for mud cake
formation and development of gel strength. However, high amounts of
the nanoparticles are required with the cement to develop the mud
cake formation and gel strength.
[0018] There is therefore a need for an additive for drilling
fluids to effectively reduce fluid loss to the formation, form thin
filter cakes, prevent formation damage, and without affecting the
characteristics of the drilling fluid.
SUMMARY OF THE INVENTION
[0019] The present invention overcomes at least one disadvantage of
the prior art fluids.
[0020] In particular, the present invention is directed to well
treatment fluids, and in particular drilling fluids, kill fluids,
pre-stimulation fluids and completion fluids having nanoparticles.
These nanoparticles act as loss circulation material for reducing
or preventing fluid loss to the formation. In a preferred aspect,
the invention is directed to invert emulsion drilling fluids having
nanoparticles as loss circulation material for reducing fluid loss
to the formation. The nanoparticles are preferably hydroxide,
oxide, sulphate, sulphide, and carbonate nanoparticles. The
nanoparticles are present in the fluid in low amounts. As a result,
the nanoparticles do not significantly alter the other
characteristics of the fluid.
[0021] In a further aspect of the invention, the present invention
is directed to novel ex situ and in situ methods for preparing the
nanoparticle-containing drilling fluids.
[0022] In one embodiment, the invention provides a
nanoparticle-containing well fluid comprising a base fluid and
about 5 wt % or less nanoparticles. The nanoparticles act as fluid
loss agents for reducing or preventing fluid loss to an underground
formation. Preferably, the well fluid is drilling fluid, kill
fluid, completion fluid, or pre-stimulation fluid.
[0023] In a further embodiment, the invention provides a use for
the nanoparticle-containing fluid for reducing or preventing
fluid-loss to an underground formation. Preferably the fluid is a
drilling fluid and fluid loss is prevented or reduced during
drilling of a well in the formation.
[0024] In a further embodiment, the invention provides a method of
making the nanoparticle-containing well fluid by forming the
nanoparticles ex situ, comprising the steps of providing
aqueous-based precursor solutions for forming the nanoparticles,
mixing the precursor solutions under high shear, and adding the
mixed precursor solution to the well fluid, to form the
nanoparticle-containing fluid, wherein the nanoparticles act as
fluid loss material for reducing fluid loss in an underground
formation.
[0025] In a further embodiment, the invention provides a method for
making a nanoparticle-containing well fluid by forming the
nanoparticles in situ, comprising the steps of providing
aqueous-based precursor solutions for forming the nanoparticles,
adding the precursor solutions to the well fluid, and subjecting
the fluid to mixing and shear to form the nanoparticle-containing
fluid, wherein the nanoparticles act as a fluid loss material for
reducing fluid loss in an underground formation.
[0026] The features and advantages of the present invention will be
apparent to those skilled in the art and are described below in
more detail with reference to specific embodiments.
BRIEF DESCRIPTION OF THE FIGURES
[0027] Embodiments of the invention will be described with
reference to the figures, which illustrate aspects of the invention
but should not be considering limiting, in which:
[0028] FIG. 1 is a schematic representation of the ex situ scheme
of preparing nanoparticles and the nanoparticles-based drilling
fluid;
[0029] FIG. 2 is a schematic representation of the in situ scheme
of preparing nanoparticles and the nanoparticles-based drilling
fluid;
[0030] FIG. 3 is an X-ray diffractogram pattern of ex situ prepared
nanoparticles;
[0031] FIGS. 4a)-c) are TEM Photographs and the corresponding
particle size distribution for the ex situ Fe(OH).sub.3
nanoparticles;
[0032] FIGS. 5a)-d) show SEM images of mud cake a) without
nanoparticles (SE); b) without nanoparticles (BSE); c) in situ
nanoparticles (SE); and d) in situ nanoparticles (BSE);
[0033] FIGS. 6a)-b) shows elements containing mud cake without
nanoparticles and b) mud cake with nanoparticles from EDAX
data;
[0034] FIGS. 7a)-c) show a nanoparticle-based drilling fluid
stability evaluation;
[0035] FIGS. 8a)-b) show the rheology behavior of drilling fluid 90
oil:10 water (v/v), with a) LCM and nanoparticles made by both ex
situ and in situ methods and b) with nanoparticles only, made by
both ex situ and in situ methods;
[0036] FIGS. 9a)-b) show gel strength behavior of drilling fluid 90
oil:10 water (v/v) with a) LCM and nanoparticles made by ex situ
and in situ methods and b) with nanoparticles only made by ex situ
and in situ methods;
[0037] FIG. 10 shows the shelf life of drilling fluid samples using
rheology behaviour;
[0038] FIG. 11 shows the aging effect of drilling fluid samples
using gel strength behaviour;
[0039] FIG. 12 shows mud cake before and after addition of
nanoparticles;
[0040] FIG. 13 shows API fluid loss of different drilling fluid
samples without using LCM;
[0041] FIG. 14 shows the fluid loss reduction of high temperature
high pressure drilling fluid filtrates;
[0042] FIG. 15 shows high temperature high pressure drilling fluid
filter cake;
[0043] FIG. 16 shows the effect of shearing on fluid loss
control;
[0044] FIG. 17 shows the quality of unblended and blended drilling
muds;
[0045] FIG. 18 shows the effect of organophilic clays on fluid loss
control;
[0046] FIG. 19 shows nanoparticle-containing drilling fluid
stability evaluations for 4 additional nanoparticle-containing
drilling fluids; and
[0047] FIG. 20 shows nanoparticle-containing drilling fluid filter
cake for 4 additional nanoparticle-containing drilling fluids.
DESCRIPTION OF EMBODIMENTS OF THE INVENTION
[0048] The present invention is an economic and effective method of
controlling lost circulation. Use of the nanoparticles in the well
fluids will prevent or reduce fluid loss to the formation as
compared to a fluid without loss circulation materials.
[0049] The nanoparticle containing fluids have one or more of the
following advantages. The nanoparticle-containing fluids reduce
fluid loss into the formation as compared to fluids without the
nanoparticles. The nanoparticles form a thin and firm filter cake
in the formation. They cause minimal formation damage. They are
stable at extremely high temperatures. The nanoparticles are
present in the fluids at low concentrations and may be used without
other loss circulation materials. The nanoparticles can be formed
ex situ or in situ in the fluid. This results in time and cost
savings. Since less fluid is lost to the formation, the cost of the
fluid is lower. The nanoparticles result in lower torque and drag,
thereby increasing the extended reach of the well. Since a lower
concentration of nanoparticles is used, there is less formation
damage, no significant changes to the characteristics of the fluid,
and an increased productivity index. The nanoparticles may also be
effective at reducing fluid loss in both low temperature low
pressure environments and high temperature high pressure
environments.
[0050] The base fluid of the present invention can be a well
completion fluid and preferably is a drilling fluid, kill fluid,
pre-stimulation fluid, or completion fluid. More preferably, it is
a drilling fluid and in particular, an invert emulsion drilling
fluids. These fluids, and in particular drilling fluids, are well
known in the art.
[0051] The drilling fluids are preferably invert emulsion fluids.
Hydrocarbon based drilling emulsions contain a large amount, i.e.
95%, of hydrocarbon based material (oil) as the continuous phase of
the emulsion. The remainder of the emulsion is a minor amount of an
aqueous phase as the discontinuous phase of the emulsion. Invert
emulsions are a type of water-in-oil emulsions which use
hydrocarbon-based materials but which contain smaller amounts of
the hydrocarbon-based material in the continuous phase and larger
amounts of the aqueous discontinuous phase as compared to other
hydrocarbon-based fluids.
[0052] The drilling fluids may contain a number of common additives
such as weighting agents, emulsifiers, foaming agents, etc. The
nanoparticles are selected so that they do not affect the other
characteristics of the drilling fluids.
[0053] Nanoparticles (NPs) act as a loss circulation material (LCM)
by virtue of their size domain, hydrodynamic properties and
interaction potential with the formation. The nanoparticles will be
selected in accordance with the specific well fluid, the formation,
bottomhole pressures and temperatures, and other well and operating
parameters.
[0054] The nanoparticles are preferably selected from metal
hydroxides, e.g. iron hydroxide, metal oxides, e.g. iron oxide,
metal carbonates, e.g. calcium carbonate, metal sulfides, e.g. iron
sulfide, and metal sulfate, e.g. barium sulfate. More preferably,
they are metal hydroxides such as iron hydroxide. In some cases,
the specific nanoparticles may form under formation conditions. For
example, iron hydroxide may convert to iron oxide under high
temperature high pressure conditions. If the selected nanoparticles
are sulfide or sulfate nanoparticles, they may act as weighting
material in addition to loss circulation material.
[0055] It was previously thought that high amounts of
nanoparticles, in combination with other LCM and/or asphaltic
materials, were required to reduce fluid loss. It has now been
surprisingly found that very low levels of nanoparticles in
drilling fluid will substantially reduce fluid loss to the
formation, even without other LCM being present. The use of the
nanoparticles in the fluids results in a fine, thin, impermeable
layer of particles forming good quality filter cake at the borehole
wall. This filter cake reduces the fluid lost to the formation. The
filter cake is formed even with low concentrations of the
nanoparticles.
[0056] The nanoparticles are present in the base fluid in amounts
below about 5 wt %, more preferably below about 4 wt %, more
preferably below about 3 wt %, even more preferably below about 1
wt %. Further preferred amounts of the nanoparticles in the fluid
is between about 0.5 wt % and about 1%, preferably between about
0.6 wt % and about 1 wt %, and most preferably in an amount between
about 0.74 wt % and about 1 wt %. Because the amount of
nanoparticles is low, other additives are generally not required to
stabilize the particles although in some water-based drilling
fluids, surfactant or polymeric additives may be required. Further,
the nanoparticles do not agglomerate in the fluid even after
several weeks.
[0057] Preferably the nanoparticles have a particle size in the
range of 1-300 nm, more preferably 1-120 nm and even more
preferably the majority or most of the nanoparticles have a
particle size in the range of 1-30 nm. More preferably
substantially all of the nanoparticles have a particle size is the
range of 1-30 nm.
[0058] The particle sizes of the nanoparticles are not limited to
these specific ranges. The particle size will vary in accordance
with the invert emulsion drilling fluid. The water droplets in the
invert emulsion of the drilling fluid provide control over the
particle sizes and therefore the nanoparticle sizes can be varied
according to the diameter of the water pools in the invert
emulsion. Any surfactants in the fluid will also influence the
nanoparticle size since the surfactants tightly hold the water
pools in the oil phase.
[0059] One benefit of using low concentrations of the nanoparticles
is that the nanoparticles do not significantly affect other
characteristics of the fluid. In particular, after the addition of
the nanoparticles, there should be no significant change in the
specific gravity, apparent viscosity, pH, or mud weight of the
fluid. There will also be no significant change in the rheology of
the fluid.
[0060] The use of the nanoparticle-containing drilling fluid of the
present invention resulted in a significant reduction in fluid loss
to the formation. In low pressure low temperature (LPLT)
formations, fluid loss could be reduced by as much as 70% when
using drilling fluid with LCM with ex situ formed nanoparticles and
as much as 80% when using drilling fluid with LCM and in situ
formed nanoparticles as compared to the drilling fluids without LCM
or nanoparticles. Prior references used as much as 30 wt %
nanoparticles and found the fluid loss reduction to be less than
40%. See Amanullah et al. (2011) and Srivatsa (2010). It is worth
noting that prior use of nanoparticles of iron oxide/hydroxide
resulted in less than 7% fluid loss reduction. In high pressure
high temperature formations, fluid loss using the present invention
was reduced by more than 50% with LCM and ex situ nanoparticles and
as much as 60% with LCM and in situ nanoparticles, as compared to
the drilling fluid without LCM or nanoparticles.
[0061] The nanoparticles in the drilling fluid do not cause
significant formation damage. They plug the pores in the formation
externally to reduce fluid loss rather than internally, thereby
avoiding formation damage. The nanoparticles control the spurt and
fluid loss into the formation and therefore control formation
damage. They form a thin, non-erodible and impermeable mud-cake.
Small particles of high concentrations may bridge across the pore
throat. Smaller particles aggregate around larger ones and fill in
the smaller spaces and effectively plug the pore spaces.
[0062] The use of nanoparticles also can reduce the total solid
concentration. The use of the nanoparticles to produce better fluid
loss control means that high amounts of clays are not needed in the
fluid. It also avoids formation damage which decreases the rate of
penetration.
[0063] The prevent invention also includes the use of these
nanoparticle-containing fluids as a pre-stimulation treatment
fluid. The nanoparticles will generate an almost perfect sealant
from the wellbore to the formation. By removing the filter cake in
selected sections of the wellbore, stimulation can be performed
selectively either by hydraulic fracturing or for acid
treatments.
[0064] The nanoparticles-containing drilling fluid can be used in a
variety of formations. However, it is preferably used in formations
with smaller pore sizes, and most preferably in shale formations
having pore openings smaller than 100 .mu.m. It is also preferable
in naturally fractured formations because it has a bridge-building
capability with other fluids.
[0065] In a further aspect of the invention, the present invention
is directed to a method of making the nanoparticle-containing
fluid. The fluid can be made using either an in situ or ex situ
process. The in situ process is preferred.
[0066] The nanoparticles can be formed and suspended in situ in the
drilling fluid. This eliminates the need to pre-form the
nanoparticles. In this method, precursors of the nanoparticles are
prepared, preferably as aqueous solutions. Selecting appropriate
precursors is within the common knowledge in this field, according
to the desired nanoparticle. The precursor solutions are added to
the prepared drilling fluid and mixed. Shear is applied to the
drilling fluid to ensure mixing of the nanoparticles precursors and
complete formation of the nanoparticles in the drilling fluid.
[0067] It is thought that this in situ method uses the dispersed
water pools of the invert emulsion drilling fluid as nano-reactors
to form the nanoparticles. The results that follow later in this
description show that the in situ-formed nanoparticles may provide
improved fluid loss reduction over fluids having nanoparticles
formed ex situ.
[0068] In the ex situ process, the nanoparticles are pre-formed
from their precursors. Precursors, preferably in aqueous precursor
solutions, are mixed and high shear applied. The formed
nanoparticles are then added to the prepared drilling fluid. The
fluid and nanoparticles are mixed.
[0069] In both processes, whether in situ or ex situ, mixing and
the application of shear is preferably applied prior to storage of
the drilling fluid to avoid the formation of fish eyes.
[0070] In one example of the ex situ method, an invert emulsion
drilling fluid having iron (III) hydroxide as the loss circulation
material is formed, where the fluid has lower fluid loss in a
drilling operation. The fluid is formed by the steps of
solubilizing a desired amount of an anhydrous iron (III) chloride
powder, adding a stoichiometric amount of sodium hydroxide pellets,
mixing the solution preferably at 25.degree. C., recovering the
iron (III) hydroxide nanoparticles and forming a bulk aqueous
solution of nanoparticles, mixing the nanoparticles solution in the
invert emulsion drilling fluid in a slurry to form the
nanoparticle-containing drilling fluid. The resultant ex situ
prepared iron (III) hydroxide nanoparticles were characterized
using X-ray powder diffraction (XRD) and transmission electron
microscopy (TEM).
[0071] In an example of the in situ method, the iron (III)
hydroxide nanoparticles were prepared within the invert emulsion
fluid, starting from FeCl.sub.3 and NaOH precursors. The in situ
particles were characterized following their collection on the
filter cake using scanning electron microscopy (SEM). Preliminary
API test results indicated that optimum control of fluid loss has
been achieved using the nanoparticle-containing drilling fluid.
Moreover, at the level of nanoparticles added, of about 1 wt %, no
impact on drilling fluid specific gravity, appartent viscosity and
pH was observed.
1. Drilling Fluid Samples
[0072] The invert emulsion was supplied by a Calgary based drilling
fluid company. One mix of the drilling fluids was test; namely, 90
oil:10 water (v/v). The compositions of the invert emulsion
drilling fluid are shown in Table 1. The LCM, mainly Gilsonite,
content of the drilling fluid was fixed at 1.6 wt %. In one
example, no LCM was used. The nanoparticles concentration was
maintained at 0.74 wt % for the in situ and ex situ prepared
particles.
TABLE-US-00001 TABLE 1 Compositions of drilling fluid samples
Oil:water (v/v) = 90:10 Base Oil = Low-aromatic hydrotreated oil
Brine = 30% Calcium Chloride Organophillic Clays = 15 kg/m.sup.3
Hot Lime = 35 kg/m.sup.3 Primary Emulsifier =10 L/m.sup.3 Secondary
Emulsifier = 5 L/m.sup.3
2. Preparation of Fe(OH).sub.3 Nanoparticles and the
Nanoparticle-Containing Drilling Fluid
[0073] Iron (III) hydroxide nanoparticles were prepared by aqueous
reaction between FeCl.sub.3 and NaOH at specified temperature and
rate of mixing as per the following reaction. The product
Fe(OH).sub.3 nanoparticles were collected and their identity was
confirmed using XRD and their particle size distribution was
determined using TEM.
[0074] Ex situ preparation: Iron hydroxide nanoparticles were
prepared by first solubilizing the specific amount of anhydrous
iron (III) chloride powder (laboratory grade, Fisher Scientific
Company, catalog #189-500, Toronto, Canada) in 2 mL deionized water
to give final concentration of 2.5 M followed by addition of a
stoichiometric amount of NaOH.sub.(a) pellets (Fisher Scientific
Company, Toronto, Canada) under 200 rpm of mixing and 25.degree. C.
The color of the aqueous solution turned reddish brown signaling
the formation of precipitate of Fe(OH).sub.3(a) as per reaction
(R1).
FeCl.sub.3(aq)+3NaOH.sub.(aq).fwdarw.Fe(OH).sub.3(a)+3NaCl.sub.(aq)
(R1)
[0075] The particles were recovered, part was dried for
characterization and the rest was mixed with the invert emulsion
drilling fluid in a slurry form as shown in FIG. 1. The fluids were
mixed, and shear applied, to achieve a homogenous mixture using a
Hamilton beach mixer.
[0076] In situ preparation: This nanoparticle synthesis followed
the two microemulsion method for nanoparticle synthesis. 1 mL of 5
M FeCl.sub.3(aq) was added to 250 mL of the drilling fluid and in a
separate vial 1 mL of 16 M NaOH.sub.(aq) was added to 250 mL of the
drilling fluid. The two vials were mixed overnight at 200 rpm and
25.degree. C. as shown in FIG. 2.
[0077] Two control samples were prepared, one containing the
FeCl.sub.3(aq) in the drilling fluid and another containing the
NaOH.sub.(aq) in the drilling fluid. The samples were left to mix
overnight at 200 rpm and 25.degree. C. It is worth noting that no
phase separation was observed in the nanoparticle-containing fluids
as well as in the control samples, even for a period of 6
weeks.
3. Characterization Methods and Techniques
[0078] Particle Characterization:
[0079] Ex situ prepared Fe(OH).sub.3 nanoparticles were
characterized using XRD. The in situ prepared nanoparticles were
characterized using SEM following their collection on the filter
cake. For the ex situ prepared particles, the aqueous colloidal
suspension was first centrifuged at 5000 rpm to recover the
nanoparticles followed by washing several times with deionized
water. The particles were left to dry at room temperature for 24 h.
The dried particles were ground using a pastel and mantel before
been introduced to Ultima III Multipurpose Diffraction System with
Cu K.alpha. radiation operating at 40 KV and 44 mA (Rigaku Corp.,
TX). JADE software was used to identify the structure. The particle
size distribution was determined by collecting transmission
electron microscopy photographs on a Phillips Tecni TEM (voltage of
200 KV) equipped with a slow-scan camera. The ground particles were
dispersed in methanol and one drop of the methanol dispersion was
deposited on a copper grid covered with carbon and left to dry
overnight before the TEM images could be collected.
[0080] Droplets Size Measurement of the Water-in-Oil Emulsion:
[0081] Samples with primary emulsifier were prepared using the same
composition of 10 vol % water to 90 vol % oil as the drilling fluid
sample except that solids were excluded. The water droplet diameter
was measured using Morphologi G3 microscope (Malvern Instruments
Inc, USA).
[0082] Drilling Fluid Characterization:
[0083] The filtration properties of the different drilling fluids
were measured according to API 30-min test. Data was collected
using a standard FANN filter press (Fann Model 300 LPLT (100 psi
and 25.degree. C.), Fann Instrument Company, USA) and filter paper
(Fann Instrument Company, USA). A volume of 500 mL of the drilling
fluid was poured into the filter press cup and 100.+-.5 psi of
pressure was applied through CO.sub.2 supply cylinder at room
temperature of 25.degree. C. The volume of permeate was reported
after 2.5 min and 30 min from the graduated cylinder reading. Three
replicates were prepared for every sample and the 95% confidence
interval is reported in the tables. The smoothness of the final
filter cake was reported through visual observation; while the
thickness was measured using a digital caliper (0-6 TTC Electronic
digital calipers model # T3506, Canada). The iron and calcium
content in the filtrate was determined by inductively coupled
plasma (ICP) (IRIS Intrepid IIXDL, ThermoInstruments Canada Inc.,
Mississauga, ON, Canada). Iron content of the filtrate is
correlated to nanoparticles escaping the filtration process.
[0084] The effect of nanoparticles on the characteristics of the
drilling fluid was determined as follows: Fann Model 140 mud
balance (Fann Instrument Company, USA) was used to measure the mud
density in the presence and absence of nanoparticles. Care was
taken in order to eliminate any error due to air entrapment. pH
measurements were performed using pH paper (0-14) (VWR
international, Catalog #60775-702 Edmonton, Canada). A rotational
Fann 35 viscometer (Fann Instrument Company, USA) was used to
measure the shear characteristics of the drilling fluid at six
different speeds. A volume of approximately 500 mL of the fluid was
poured into the viscometer cup, and the mud was sheared at a
constant rate in between an inner bob and outer rating sleeve. The
system was left to rotate at a certain rpm until reaching the
steady state reading for 5 min. The readings were taken at 600,
300, 200, 100, 6 and 3 rpm and noted down. The experiments were
conducted at room temperature of 25.degree. C. The dimensions of
bob and rotor were chosen such that the dial reading on the
viscometer is equivalent to apparent viscosity in centipoise at
rotor speed of 300 rpm. The apparent viscosities for all rotor
speeds are calculated using equation (E1) below.
Apparent / Effective viscosity , .mu. a = 300 ( .theta. N ) ( E1 )
##EQU00001##
where N is the rotor speed (rpm) and .theta. is the viscometer dial
reading (.degree.). The shear rate can be calculated as per
equation (E2).
Shear rate,sec.sup.-1=1.7023N (E2)
[0085] The plastic viscosity and yield point are found using the
following equations:
Plastic viscosity, .mu..sub.p=.theta..sub.600-.theta..sub.300
(E3)
Yield point, Y.sub.p=.theta..sub.300-.mu..sub.p (E4)
where .mu..sub.p is the plastic viscosity (cP), Y.sub.p is the
yield point (lb.sub.f/100 ft.sup.2), and .theta..sub.600 and
.theta..sub.300 are the torque readings at 600 rpm and 300 rpm
respectively.
[0086] Gel strength of the drilling fluid was measured at a lower
shear rate after the drilling mud is static for a certain period of
time. The 3 rpm reading was used for calculating the gel strength
after stirring the drilling fluid at 600 rpm from the Fann
viscometer. The first reading is noted after the mud is in a static
condition for 10 sec (10 sec gel strength). The second gel strength
is noted after 10 minutes (10 min gel strength). Gel strength is
usually expressed in the pressure unit lb.sub.f/100 ft.sup.2. The
difference between the initial gel strength and the 10 min value
was used to define how thick the mud would be during round trips.
See ASME Drilling Fluids Processing Handbook (2005).
4. Nanoparticles (NPs) Characterization
[0087] The ex situ prepared Fe(OH).sub.3(s) were identified using
X-ray diffraction (XRD) analysis. The particle size distribution of
the nanoparticles was determined from the TEM photographs. The
details of the particle morphology are described herein.
4.1 X-Ray Diffraction Analysis
[0088] The X-ray diffraction pattern of the ex situ prepared
nanoparticles is shown in FIG. 3. The XRD pattern shows that there
is no evidence of strong distinct peaks which would be expected
from a crystalline material. The peak maximum around
2.theta.=35.degree. can be attributed to the presence of aggregates
dispersed in an amorphous phase. Nevertheless, Streat et al. (2008)
also prepared ferric hydroxide using ferric chloride and
stoichiometric quantity of sodium hydroxide with deionized water
and observed the same XRD pattern. Reaction pH might affect the
final nature of the iron oxide material. See Cai et al. (2001). Cai
et al. (2001) reported that the reaction pH affects the
crystallinity of iron oxide material. At low pH, pH.gtoreq.1.5, the
peaks were found narrow and distinct, while at pH=4 there were two
broad and less intense peaks apparent in the diffraction pattern,
similar to those shown in FIG. 3, indicating poor crystallinity. At
higher pH, pH.gtoreq.6, the XRD pattern showed crystalline
structure. It is to be noted that amorphous iron (III) hydroxide
can transform into .alpha.-Fe.sub.2O.sub.3 and .beta.-FeOOH as well
as .alpha.-FeOOH as a result of further transformation. See Nassar
and Husein (2007). Energy dispersive X-ray (EDX) associated with
the SEM helped identify the in situ formed particles as shown in
FIGS. 5 a)-d) and FIGS. 6a)-b).
4.2 Electron Microscopy Results
4.2.1. Droplet Size
[0089] The emulsion samples containing the primary emulsifier, oil
and water were characterized using Morphologi G3 microscope. A
typical water droplet diameter in the invert emulsion containing
many water droplets was 20 .mu.m. Nonetheless, a few smaller water
droplets (>5 .mu.m) were observed in the emulsion. Similar
observations have been reported by Fjelde et al. (2007) for 25/75
and 5/95 water-in-oil emulsions at different temperature, while
using primary emulsifiers. The stirring speed may also affect the
droplet size distribution. See Fjelde (2007). Kokal (2006) has
shown that the water droplets in emulsion can vary in size from
less than 1 .mu.m to more than 1000 .mu.m. Typically, in oil based
drilling fluids, macroemulsions with droplet sizes in the range of
0.1-100 .mu.m are used. See Bumajdad et al. (2011) and Kokal
(2006).
4.2.2. Particle Size Distribution
[0090] FIGS. 4a-c show the TEM photographs and the corresponding
particle size distribution histograms for the ex situ prepared
Fe(OH).sub.3 particles. The histograms show a spread in the size
distribution with most of the population falling in the range
between 1-30 nm. TEM image shows some aggregates, which are
believed to form during nanoparticle preparation due to the high
mixing. It should be noted that the resultant nanoparticles did not
exhibit magnetic properties at room temperature, which precludes
magnetic attraction. Nevertheless, the wide size distribution of
particles prompted further consideration of the filtration
characteristics of LCM-free nanoparticle-containing drilling fluid.
The results are detailed below.
4.2.3 SEM Analysis
[0091] SEM images of the mud cake without nanoparticles and with
nanoparticles are shown in FIGS. 5 a)-d). The observed morphologies
of the two samples have some distinct features. No cracks were
visible, except clay surface was covered with Fe(OH).sub.3
particles by the SEM observation. The mud cake with nanoparticles
showed a smooth and clean surface. Mud cake without nanoparticles
showed a rough surface and seemed to be deformed and fractured
which led to a porous surface causing more fluid loss. It can be
observed that the formation of voids and gap of pores were filled
with nanoparticles eventually reducing the fluid loss. Thus, it can
be inferred that the adsorption reaction of Fe(OH).sub.3
nanoparticles on organophillic clays may be attributed to the
surface chemical reactivity. Results are in agreement with Lai
(2000) who reported that cu ions were adsorbed on iron oxide coated
sand. Addition of Fe(OH).sub.3 nanoparticles causes a change of
elemental constitution through adsorption reaction. The elemental
distribution mapping of EDAX for the sample of mud cake without
nanoparticles and mud cake with nanoparticles are illustrated in
FIGS. 6a)-b). Results indicated that iron ions could penetrate into
the micropores and mesopores of the cakes containing clays. It can
be also attributed to a diffusion of the adsorbed metals from the
surface into the micropores which are the least accessible sites of
adsorption.
4.3. Effect of Nanoparticles on Drilling Fluid Characterization
[0092] Stability of nanoparticle-containing drilling fluid: The
assessment of the stability of the nanoparticle-containing drilling
fluids was determined by visual observation. Stability relates here
to the `shelf life` of nanoparticle-containing drilling fluid.
FIGS. 5a)-c) are photographs of samples representing the initial
fluid without nanoparticles and the nanoparticle-containing
drilling fluids. The figures show no agglomeration, even when the
samples were left for several weeks. The stability is attributed to
the fact that the amount of nanoparticles added in formulating the
nanoparticle-containing drilling fluid was low, for example, in
FIGS. 7a)-c), only 0.74 wt %. Moreover, steric hindrance arising
from the surface active agents surrounding the particles helps
stabilize the particles against the van der Waals attractive
forces. Consequently, no other additives were required to stabilize
the particles.
[0093] Several other concentrations, below 0.5 wt %, of iron
hydroxide nanoparticles were tested. Further, higher concentrations
of greater than 5 wt % were found to lead to particle
agglomeration. Another qualitative assessment of the stability of
nanoparticle-containing drilling fluid was done by checking its
rheology after 1 month which is detailed in the next section.
[0094] Rheology Behavior of Nanoparticle-Containing Drilling
Fluid:
[0095] Drilling fluids with good pumpability exhibit lower
viscosity at high shear rate and higher viscosity at lower shear
rate. This property of drilling mud is used widely where high
viscosities are required during tripping operation and low
viscosities required during drilling operation to clean the
cuttings from the bottom of the hole. See Srivatsa (2010) and
Amanullah et al (2011). The plot of apparent viscosity and shear
rate as shown in FIGS. 8a)-b) resembles the non-linearity of the
curves at low shear rates and approach linearity at high shear
rates. The addition of nanoparticles created a slight change in the
rheology and supports the theory that nanoparticle behavior is
governed by nanoparticle grain boundary and surface area/unit mass.
See Amanullah et al. (2011).
[0096] The addition of small concentrations of nanoparticles is not
sufficient to cause significant rheology changes in the system
compared to the drilling fluid without LCM and nanoparticles, and
the drilling fluid with LCM only. However, the particle size,
nature of particle surface, surfactants, pH value and particle
interaction forces may play significant roles to alter the
viscosity. Most of the nanoparticles are assumed to be in the water
pools surrounded by surfactants. Some of the particles,
nevertheless, may attach themselves to the clay suspension as a
result of electrostatic and van der Waals forces. The results are
also highly dependent on the hydroxyl group (--OH) on the surface
of the nanoparticles, which causes nanoparticles to be agglomerated
in an organic solution. This leads to a higher mass of selective
physiosorption of organic clay suspension on the surface of the
free nanoparticles which is thought to reduce the fluid viscosity
slightly. See Srivastsa (2010).
[0097] A comparison of the gel strength of the
nanoparticle-containing drilling fluid and the drilling fluid
without LCM and nanoparticles, is shown in FIGS. 9a)-b). During
these experiments, special attention to the rheology of the
nanoparticle-containing drilling fluid was considered. Measurement
was done immediately after the preparation and also after 1 month.
FIGS. 10 and 11 show the time dependent rheological and gel
strength behavior of the drilling fluid respectively compare with
the nanoparticle-containing drilling fluid. Analyses of the
rheological profiles of the drilling fluids shown in the figures
indicate no significant changes of the viscous profile of the
nanoparticle-containing fluid, even after static aging for 1 month.
The 10 second and 10 minute gel strengths shown in the figures also
demonstrate the short and long term stability of the
nanoparticle-containing fluid to fulfill its functional task during
drilling operation.
[0098] Drilling Fluid Density and pH:
[0099] Mud density is one of the important drilling fluid
properties because it balances and controls formation pressure.
Moreover, it also helps wellbore stability. The mud density 0.93
g/cm.sup.3 was found almost constant in all the samples of 90:10
(v/v) oil/water types shown in Table 2. The addition of
nanoparticles did not increase the mud weight. This provides the
advantage of reducing the total solids concentration in the
drilling fluid as and when necessary, which is detailed in the next
section.
TABLE-US-00002 TABLE 2 Density measurements of drilling fluid
samples Density (g/cm.sup.3) DF + DF + Sample DF + LCM + LCM + Type
DF LCM Ex-situ NPs In-situ NPs Oil/Water 0.93 .+-. 0.02 0.93 .+-.
0.02 0.93 .+-. 0.02 0.93 .+-. 0.02 90:10 (v/v)
Table 3 indicates that a pH level 12.5 was also found in all
samples, even nanoparticles addition did not change the pH of the
drilling fluid samples.
TABLE-US-00003 TABLE 3 pH measurments of drilling fluid samples pH
DF + DF + Sample DF + LCM + LCM + Type DF LCM Ex-situ NPs In-situ
NPs Oil/Water 12.5 12.5 12.5 12.5 90:16 (v/v)
[0100] LPLT Filtration Property of Nanoparticle-Containing Drilling
Fluid:
[0101] Filtration property is dependent upon the amount and
physical state of colloidal materials in the mud. When mud
containing sufficient colloidal material is used, drilling
difficulties are minimized. The spurt loss of the drilling fluid is
considered as one of the sources of solid particles and
particulates invasion to the formation that can cause serious
formation damage. This is due to the formation of an internal mud
cake in the vicinity of the wellbore. Consequently, internal pore
throat blockage may create a flow barrier to reduce oil and gas
flow. Moreover, higher particle flocculation in drilling fluid
causes higher mud cake thickness.
[0102] This highlights the importance of using low concentrations
of dispersed nanoparticles in fluid design with virtually no spurt
loss, low filtrate volume and good quality filter cake. The ultra
dispersed nanoparticles in the present drilling fluid system forms
a well dispersed plastering effect on the filter paper and improves
the fluid performance. The filtration properties of the drilling
fluid are determined by means of the standard filter press. The
effectiveness of the nanoparticles in fluid loss prevention can be
clearly seen from Table 4A. The API fluid loss of the samples
indicated a decreasing trend in fluid loss over a period of 30
minutes with around 9% for the drilling fluid with 1.6% w/w LCM,
70% when using fluid with LCM and ex situ prepared nanoparticles
together, and more than 80% when using fluid with LCM and in situ
prepared nanoparticles together. The reported literature values for
the loss reduction was less than 40% even after addition of 30 wt %
of nanoparticles. See Amanullah et al. (2011) and Srivatsa
(2010).
TABLE-US-00004 TABLE 4A API Fluid Loss of Different Drilling Fluid
(DF) Samples LPLT Fluid Loss (mL) DF + 1.6% DF + 14% DF + w/w LCM +
w/w LCM + Sample Time 1.6% w/w 0.74% w/w 0.74% w/w Types (min) DF
LCM NPs ex-situ NPs in-situ 90:10 (v/v) 7.5 2.0 .+-. 0.2 1.4 .+-.
0.2 0.20 .+-. 0.2 -- Oil:Water 30 3.96 .+-. 0.2 3.6 .+-. 0.1 1.10
.+-. 0.1 0.50 .+-. 0.2
[0103] Fluid loss results for fluids with other nanoparticles are
shown in Tables 4B and 4C below. Table 4B sets out fluid loss
results after 30 minutes for both ex situ and in situ prepared
nanoparticles of CaCo.sub.3, Fe(OH).sub.3, BaSO.sub.4, and FeS, in
invert emulsion drilling fluids and compares the results to that
achieved with the drilling fluid alone. Table 4B sets out the fluid
loss results after 30 minutes for water-based drilling fluids with
CaCO.sub.3 and Fe(OH).sub.3 nanoparticles formed ex situ and in
situ.
TABLE-US-00005 TABLE 4B LPLT Fluid Loss with Different
Nanoparticles for Invert Emulsion DF (95% CI) Fluid DF + 4 wt % DF
+ 4 wt % Types DF CaCO.sub.3 (ex-situ) CaCO.sub.3 (in-situ) mL/30
8.7 .+-. 2 2.8 .+-. 0.6 (68%*) 3.9 .+-. 0.3 (55%*) min Fluid DF +
0.74 wt % DF + 0.74 wt % Types DF Fe(OH).sub.3 (ex-situ)
Fe(OH).sub.3 (in-situ) mL/30 3.96 .+-. 0.2 1.25 .+-. 0.2 (68%*)
0.90 .+-. 0.2 (77%*) min Fluid DF + 3 wt % DF + 3 wt % Types DF
BaSO.sub.4 (ex-situ) BaSO.sub.4 (in-situ) mL/30 10.95 .+-. 0.3 3.5
.+-. 0.3 (68%*) 1.6 .+-. 0.3 (85.3%*) min Fluid DF + 3 wt % DF + 3
wt % Types DF FeS (ex-situ) FeS (in-situ) mL/30 10.95 .+-. 0.3 1.15
.+-. 0.3 (89.5%*) 0.93 .+-. 0.1 (91.5%*) min *% fluid loss
reduction
TABLE-US-00006 TABLE 4C LPLT Fluid Loss with Different NPs for
Water Based Mud (95% CI) Water based DF + Water based DF + Fluid
Water 0.60% w/w 0.60% w/w Types based DF Fe(OH)3 (ex-situ) Fe(OH)3
(in-situ) mL/30 8.8 .+-. 0.6 8.0 .+-. 0.2 (9%*) 6.3 .+-. 0.2
(28.4%*) min Water based DF + Water based DF + Fluid Water 3% w/w
CaCO3 3% w/w CaCO3 Types based DF (ex-situ) (in-situ) mL/30 9.5
.+-. 0.2 6.5 .+-. 0.2 (31.6%*) 6.8 .+-. 0.2 (28.4%*) min *% fluid
loss reduction FIGS. 4a-c - LPLT tested at 100 psi; 25.degree.
C.
[0104] The optimum stability concentration of the nanoparticles was
also considered. Various nanoparticles were tested in 500 mL
samples of invert emulsion drilling fluids. See FIG. 18. The
optimum stability concentrations varied with different
nanoparticles. Generally, the ranges are 0.5% w/w to 5% w/w for
Fe(OH).sub.3, 0.5% w/w to 10% w/w for each of BaSO.sub.4, and FeS,
and 0.5% w/w to 20% w/w for CaCo.sub.3. Although generally no
additives are needed for stabilization, water-based drilling fluids
may require surfactant or polymeric additives to stabilize the
nanoparticles.
[0105] In order to prevent drilling and completion problems, mud
cake quality and build up characteristics are very important
nanoparticles mediated drilling fluid form thin and impermeable
filter cake. FIGS. 12 (a-d) show the mud cake formation before and
after addition of nanoparticles. The nanoparticles (FIGS. 12 c-d)
deposit a fine thin layer of particles and looks reddish brown
which shows that iron (III) hydroxide are deposited on the cake
surface. The filtration properties of a drilling fluid with
nanoparticles only consider the wall/cake building ability of the
nanoparticles with solid components of drilling fluid are shown in
FIG. 13. FIG. 19 shows the filter cakes formed from the
nanoparticles-containing fluids tested in Table 4B and 4C.
[0106] An interesting discovery was that a wide range of
nanoparticles particle size gave lower permeability than that
achieved using LCM. A reasonably low fluid loss value and thin mud
cake with a thickness of less than 1 mm achieved with the
nanoparticle-containing drilling fluid was a significant
improvement compared to the drilling fluid with conventional LCM.
Properly dispersed nanoparticles having good filtration
characteristics give the drilling fluid its distinctive
character.
[0107] Loss of fluid from the invert emulsion drilling fluid
usually results in the loss of oil and chemicals into the
formation. The presence of iron and calcium content in the filtrate
were determined by inductively coupled plasma (ICP). Results are
shown in Table 5. In the total filtrate volume, the
nanoparticle-containing fluid reduced the Ca content 500 times than
the filtrate without nanoparticle-containing fluid. Iron content
was found nil in both cases. The results are attributed to the fact
that bentonite clays are highly negatively charged and therefore
favorably attract iron in the nanoparticles. Therefore, larger
surface area of nanoparticles provided bridges between the
bentonite particles. During filtration, the bentonite clays and
iron aggregates became physically significant preventing the
di-valent positively charged Ca content in the filtrate. Moreover,
NaCl salts used as a bridging solid are produced during the
nano-based fluid formulation which can act as the inhibitor to
prevent clay swelling and clay dispersion which in turn lead to the
elimination of clay related formation damage mechanism. See
Amanullah et al. (2011).
TABLE-US-00007 TABLE 5 ICP Test Results of the Collected Filtrate
to Determine the Ca and Fe Content Filtrate Samples Ca Content (mg)
Fe Content (mg) Without NPs (in total 478 Nil volumes) With NPs (in
total volumes) 0.87 Nil
[0108] The effectiveness of the nanoparticle-containing drilling
fluid at high temperature high pressure (500 psi and 177.degree.
C.) can be seen in Table 6. The fluid loss of the samples indicated
a decreasing trend in fluid loss over the 30 minute period with
less than 10% for the drilling fluid with 1.6 wt % LCM, about 50%
for the drilling fluid with LCM and 0.74 wt % ex situ-prepared
nanoparticles, and 60% for the drilling fluid with LCM and 0.74 wt
% in situ-prepared nanoparticles.
TABLE-US-00008 TABLE 6 High Pressure High Temperature (HTHP)
Filtration Property of Nanoparticle-Containing Drilling Fluid HTHP
Fluid Loss (mL) DF + 1.6 DF + 1.6 DF + wt % LCM + wt % LCM + Sample
Time 1.6 wt % 0.74 wt % 0.74 wt % Types (min) DF LCM NPs ex situ
NPs in situ 90:10 (v/v) 7.5 9 .+-. 0.1 6.2 .+-. 0.2 2 .+-. 0.2 --
oil:water 30 19 .+-. 0.1 14.4 .+-. 0.1 9 .+-. 0.1 7.5 .+-. 0.2
[0109] Effect of High Shear on Fluid Loss Control:
[0110] Proper shearing influenced the fluid loss numbers. Care must
be taken to allow sufficient turbulent shearing action time during
the fluid preparation. Shearing device may significantly increase
the dispersed phase fraction and dampens coalescence by breaking
agglomerated particles. See Amanullah et al. (2011). A Hamilton
Beach three blade high speed mixer was used in addition of vigorous
agitation of fluid during preparation steps. This inexpensive
equipment is used mostly in food processing. High-shear mixers
provide rapid micro-mixing and emulsification. Unblended fluid has
higher fluid loss than blended fluid as shown in FIG. 16. Even
nanoparticle-containing unblended fluids were affected due to
proper shearing. Therefore, a shearing process needs to be designed
to achieve optimum results. These indicate that high shear mixing
device is important for innovative nanoparticle-containing drilling
formulations. Low degree of mixing can lead to the formation of
`fish eyes` causing filtration issues and effects on filter cake.
The fish eyes on the unblended mud cake were clearly apparent in
FIG. 17. It was also noticed that fish eyes were completely
minimized after high shear. Therefore the preferred processing
order of building the mud and shearing immediately before storage
may reduce the frequency of fish eyes as compared to drilling fluid
that is stored before shearing.
[0111] Effect of Organophilic Clays on Fluid Loss Control:
[0112] Increasing concentration of organophillic clay particles
increased the fluid loss control. FIG. 18 shows the effect of
varying organophillic clays with iron hydroxide nanoparticles.
Increasing 20 wt % clays will increase 20% fluid loss control.
Solids content of the drilling fluid is one of the factors that
causes formation damage and decreases the rate of penetration
(ROP). See Newman et al. (2009). Solids are added to fulfill the
functional tasks of the mud, such as increase viscosity and fluid
loss control. The higher the amount of total solid in the drilling
fluid; the lower the rate of penetration which in turn increases
rig days and reduces productivity index. The addition of increasing
clays with nanoparticles reduced the fluid loss which can be
attributed to the fact that the larger surface area of
nanoparticles provides bridges between clays particles and
disperses them more effectively. Due to low concentration (<1 wt
%) of nanoparticles in the fluid formulation with desirable fluid
loss property, total solid concentration can be decreased to
enhance the rate of penetration. This demonstrates the potential of
the novel nanoparticle-containing fluid formulation using a low
amount of nanoparticles to produce better fluid loss control than
using significantly high amount of clays.
[0113] Effect of Oil:Water Ratio on Fluid Loss Control:
[0114] Filtration behavior of emulsified oil is strongly influenced
by oil/water ratio, additive chemistry and concentration.
Therefore, it would be expected that oil/water ratio will affect
fluid loss. It is of interest to compare effects of water content
in drilling fluid on fluid loss control. A series of experiments
were undertaken to investigate the effect of oil/water ratios
namely 90:10 (v/v) and 80:20 (v/v) mixes. The results are shown in
Table 8 and clearly illustrate the decrease in filtrate loss with
increasing water content in the emulsion system. Increase in water
content from 10 to 20 percent by volume caused the fluid loss to
decrease 26% and 25% for drilling fluid control samples and
drilling fluid containing gilsonite. Addition of nanoparticles
again decreases the fluid loss to 44% and 10% for ex situ and in
situ methods respectively. The reduction of fluid loss was dramatic
in case of ex situ which suggests that extra water pools are
required to disperse them effectively. In situ prepared
nanoparticles are more readily dispersed in the 10% water content.
When the water content increases, water droplets in the invert
emulsion system are within the vicinity of each other and associate
to create larger water droplets in the system. Since the filter
cake is partly formed by the water droplets, an increase in water
droplet size will increase the size of the nanoparticles and form a
larger molecular size. The frequency of large sized nanoparticles
can be higher with the available binding sites with other
nanoparticles present in waterpools and clays and establishes the
fact that increasing water in the emulsion system forms low
permeability filter cake. Thus, using high water content clearly
improves the fluid loss control. Increase in water pools increases
the available binding sites for the nanoparticles which form more
homogeneous systems. High water content reduces the interaction
between the surfactant head groups and colloidal nanoparticles
which attributed to the increase in nanoparticles size and thereby
enhances particle aggregation during filtration. See Husein and
Nassar 2008. An investigation done with different oil/water ratios
by Aston et al (2002) found the similar trends. 80:20 oil/water
ratio (OWR) compared to the invert emulsion at 90:10 OWR added
value by reducing the base oil content thus adding substantial
savings.
TABLE-US-00009 TABLE 7 Effect of Oil/Water Ratio on Fluid Loss
Control LPLT Fluid Loss (mL) DF + 1.6 DF + 1.6 DF + wt % LCM + wt %
LCM + Sample Time 1.6 wt % 0.74 wt % 0.74 wt % Types (min) DF LCM
NPs ex situ NPs in situ 90:10 7.5 2.0 .+-. 0.2 1.4 .+-. 0.2 0.2
.+-. 0.2 -- (v/v) oil:water 30 3.96 .+-. 0.2 3.6 .+-. 0.1 1.10 .+-.
0.1 0.50 .+-. 0.2 80:20 7.5 1.0 .+-. 0.2 1.0 .+-. 0.2 -- --
oil:water 30 2.9 .+-. 0.1 2.7 .+-. 0.2 0.62 .+-. 0.1 0.45 .+-.
0.1
TABLE-US-00010 TABLE 8 Performance of ex situ vs in situ prepared
nanparticles using three different samples of drilling fluid from
three different suppliers API LPLT fluid Density loss/30 min
Samples (gm/mL) pH (mL) Supplier A DF 0.93 .+-. 0.02 12.5 3.9 .+-.
0.2 DF + LCM 0.93 .+-. 0.02 12.5 3.6 .+-. 0.1 DF + LCM + Ex situ
NPs 0.93 .+-. 0.02 12.5 1.1 .+-. 0.1 Supplier B DF 0.93 .+-. 0.02
12.5 16.5 .+-. 0.3 DF + LCM 0.93 .+-. 0.01 12.5 12.7 .+-. 0.4 DF +
LCM + Ex situ NPs 0.93 .+-. 0.02 12.5 7.5 .+-. 0.2 Supplier C DF
0.90 .+-. 0.02 12.5 1.2 .+-. 0.2 DF + LCM 0.90 .+-. 0.02 12.5 1.0
.+-. 0.1 DF + LCM + Ex situ NPs 0.90 .+-. 0.01 12.5 0.5 .+-.
0.1
[0115] The results in Table 8 show the application of nanoparticles
in drilling fluids for preventing fluid loss. Since it is not
possible to maintain all of the mud properties at optimum, it is
the industry practice to reach a compromise by keeping one critical
property at optimum and the rest at reasonable levels. In most
cases, the filtration property of the mud is maintained at optimum.
The incorporation of custom prepared nanoparticles in invert
emulsion fluid systems substantially reduced the fluid loss due to
the nanoparticles themselves and nano-induced aggregates. However,
the use of nanoparticles in the drilling fluid at a right
concentration and adoption of a specific preparation method left
the fluid with desirable properties of mud density, pH and rheology
behavior. The addition of nanoparticles does not change these
properties in the base fluid. Formation damage due to filtrate and
solids invasion is a major contributor to cost, lost time and lost
production. Nanoparticles work in emulsion based fluids, even at
extreme high temperatures, providing a thin filter cake that gives
maximum formation protection at minimum concentration and cost.
Tailor made nanoparticles with specific characteristics will reduce
the circulation loss and other technical challenges faced with
commercial drilling fluid during oil and gas drilling
operation.
[0116] The present invention is described with reference to
specific examples and embodiments. Those skilled in this field will
understand that numerous variations and modifications are possible,
without departing from the scope of this invention. Although the
invention is described in terms of drilling fluids and in
particular invert emulsion drilling fluids, it will be apparent to
a person skilled in this field that the invention may apply to
other well fluids that suffer from fluid loss to the formation,
including completion fluids, kill fluids, and pre-stimulation
fluids.
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