Note: Descriptions are shown in the official language in which they were submitted.
CA 02797526 2012-11-30
DOVVNHOLE APPARATUS FOR TREATING WELLBORE COMPONENTS, AND
METHOD FOR TREATING A WELLBORE
BACKGROUND OF THE INVENTION
This section is intended to introduce various aspects of the art, which may be
associated with
exemplary embodiments of the present disclosure. This discussion is believed
to assist in
providing a framework to facilitate a better understanding of particular
aspects of the present
disclosure. Accordingly, it should be understood that this section should be
read in this light,
and not necessarily as admissions of prior art.
Field of the Invention
The present disclosure relates to the field of hydrocarbon recovery
operations. More
specifically, the present invention relates to a downhole tool used for
treating a wellbore. The
application also relates to methods for delivering a chemical treatment to a
wellbore below the
surface.
Technology in the Field of the Invention
In the drilling of oil and gas wells, a wellbore is formed using a drill bit
that is urged
downwardly at a lower end of a drill string. After drilling to a predetermined
depth, the drill
string and bit are removed and the wellbore is lined with a string of casing.
An annular area is
thus formed between the string of casing and the surrounding formations.
A cementing operation is typically conducted in order to fill or "squeeze" the
annular area with
columns of cement. The combination of cement and casing strengthens the
wellbore and
facilitates the zonal isolation of the formations behind the casing.
It is common to place several strings of casing having progressively smaller
outer diameters into
the wellbore. A first string of casing may be referred to as a conductor pipe
or surface casing.
This casing string serves to isolate and protect the shallower, fresh water-
bearing aquifers from
contamination by any other wellbore fluids. Surface casing strings are almost
always cemented
entirely back to the surface.
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The process of drilling and then cementing progressively smaller strings of
casing is repeated
several times until the well has reached total depth. In some instances, the
final string of casing
is a liner, that is, a string of casing that is not tied back to the surface.
The final string of casing,
referred to as a production casing, is also typically cemented into place.
Additional tubular bodies may be included in a well completion. These include
one or more
strings of production tubing placed within the production casing or liner.
Each tubing string
extends from the surface to a designated depth proximate a production
interval, or "pay zone."
Each tubing string may have a packer attached at a lower end. The packer
serves to seal off the
annular space between the production tubing string(s) and the surrounding
casing. In this way
production fluids are directed up the tubing string.
In some instances, the pay zones are incapable of flowing fluids to the
surface efficiently. When
this occurs, the operator may include artificial lift equipment as part of the
wellbore completion.
Artificial lift equipment may include a dovmhole pump connected to a surface
pumping unit via
a string of sucker rods run within the tubing. Alternatively, an electrically-
driven submersible
pump may be placed at the bottom end of the production tubing. Gas lift
valves, plunger lift
systems, or various other types of artificial lift equipment and techniques
may alternatively be
employed to assist fluid flow to the surface.
As part of the completion process, a wellhead is installed at the surface. The
wellhead includes
piping and valves used for directing the flow of production fluids at the
surface. The wellhead
also contains wellbore pressures.
Fluid gathering and processing equipment is also provided at the surface. Such
equipment may
include pipes, valves, separators, dehydrators, gas sweetening units, and oil
and water stock
tanks. Upon installation of the wellhead and other surface equipment,
production may begin.
During the production of hydrocarbons from the pay zones, some wells
experience a build-up of
scale. This may be due to the presence of dissolved minerals in oil and water
produced by oil
and gas wells. Changes in temperature and/or pressure which occur as
production fluids are
pumped from the production zone to the surface can cause the inorganic
minerals to come out of
solution ("precipitate") and become deposited on the interior and exterior
surfaces of production
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hardware. Such hardware may include the production tubing, downhole pumps,
surface valves,
and other equipment.
Scale is typically in the form of a mineral salt that deposits on the surface
of metal or other
material. Typical scales are calcium carbonate, calcium sulfate, barium
sulfate, strontium
sulfate, iron sulfide, iron oxides, iron carbonate, the various silicates and
phosphates and oxides,
or any of a number of compounds insoluble or slightly soluble in water. The
presence of mineral
salts can also create corrosion on metal surfaces.
In severe conditions, scale creates a significant restriction, or even a plug,
in the production
tubing and pump orifices. Scale build-up in an artificial lift pump can lead
to failure of the pump
due to blocked flow passages and broken shafts. In addition, scale can clog
perforations,
requiring that a well be treated or even re-perforated.
All waters used in well operations can be potential sources of scale. These
include water used in
waterflood operations and filtrate from completion, workover or treating
fluids. For these and
the other reasons mentioned, scale removal is a common well-intervention
operation.
A wide range of treatment options are available to effect scale removal. These
include
mechanical removal, chemical treatment, and corrosion inhibitor treatment.
Mechanical removal may be done by means of a pig that is pumped downhole.
Alternatively,
mechanical removal may involve abrasive jetting that hydraulically cuts scale
but leaves the
tubing intact. Of course, such mechanical processes do not protect a
submersible pump from
scale during production operations, nor do they prevent any future build-up of
corrosion.
Scale-inhibition treatments involve squeezing a chemical inhibitor into a
water-producing zone
for subsequent commingling with produced fluids. The scale inhibitor prevents
further scale
precipitation along producers. However, such a technique is imprecise as it is
unknown how
much of the inhibitor will make its way back to the wellbore, or when.
Chemical removal is performed by using different solvents according to the
type of scale that is
presented. Sulfate scales such as gypsum [CaS042H20] or anhydrite [CaSO4] can
be dissolved
using ethylene-diamine tetra-acetic acid (EDTA). Carbonate scales such as
calcium carbonate or
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calcite [CaCO3] can be dissolved with hydrochloric acid [HC1] at temperatures
less than 250 F
[121 C]. Silica scales such as crystallized deposits of chalcedony or
amorphous opal normally
associated with steam flood projects can be dissolved using hydrofluoric acid
[HF]. Chloride
scales such as sodium chloride [NaCl] may be dissolved using fresh water or
weak acidic
solutions, including HC1 or acetic acid. Iron scales such as iron sulfide
[FeS] or iron oxide
[Fe203] can usually be dissolved using HCI with sequestering or reducing
agents to avoid
precipitation of by-products, for example iron hydroxides and elemental
sulfur.
In the oil fields of West Texas and other areas where water flooding takes
place, calcium sulfate
and calcium carbonate scales can appear. Calcium scales such as calcium
sulfate, calcium
carbonate and calcium oxalate are insoluble in water. However, all three are
soluble in a Sodium
Bisulfate acid solution. Calcium scale can be removed with an acid wash using
a 5 to 15%
solution of Sodium Bisulfate (SBS). SBS can also be used during a shutdown to
remove scale by
re-circulating it throughout areas of the process where needed. The
concentration of SBS
solutions and the re-circulation time depend on the amount of scale that needs
to be removed.
Sulfamic acid (H3NS03) may also be used in calcium scale (or lime) removal
situations.
Sulfamic acids include amidosulfonic acid, amidosulfuric acid, aminosulfonic
acid, and
sulfamidic acid. Sulfuric acids (H2SO4) may also be considered. Sulfamic acids
can slowly
hydrolyze to ammonium bisulfate in the presence of water.
The delivery of chemical to a wellbore is normally done by placing the
chemical in liquid form
into the wellbore. However, it is believed that such chemical delivery is
frequently ineffective as
it is difficult to assure that the treatment is reaching the lowest portions
of the wellbore where it
is needed most.
Recently, Baker Hughes, Inc. has developed a SorbTM or ScaleSorbTM process for
injecting solid
pellets and liquid comprising scale inhibitor or other chemical material into
a subsurface
formation. The inhibitors are typically injected as part of the initial
formation fracturing process.
The chemicals treat formation fluids before they arrive at the wellbore. Baker
Hughes advertises
that its SorbTM chemicals inhibit scale, paraffin, asphaltenes, and salt; they
counteract bacteria and
corrosion. However, this process is a one-time injection that depends on the
chemical treatment
contacting all fluids produced to the wellbore.
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, .
Therefore, a need exists for a downhole assembly that will slowly deliver
chemical treatment at
the level of production perforations, or at or below the level of a pump.
Further, a need exists for
an assembly and method for using a continuous solid chemical that directly
treats a wellbore as
the solid material dissolves in the presence of wellbore fluids.
BRIEF SUMMARY OF THE INVENTION
A downhole assembly for delivering chemical treatment to a wellbore is
provided herein. The
chemical treatment is delivered along the wellbore at the level of a
hydrocarbon-bearing
formation. The chemical treatment serves to inhibit the build-up of scale or
other material along
wellbore components during the production of reservoir fluids.
The assembly includes a first tubular body and a second tubular body. In one
embodiment, the
second tubular body resides substantially within the first tubular body in
concentric fashion. In
this way, an annular region is formed between the second tubular body and the
surrounding first
tubular body.
The second tubular body is porous. The second tubular body may be, for
example, a perforated
tubing. Alternatively, the second tubular body may define a screen. Either
way, fluid
communication is provided between the first tubular body and a bore within the
second tubular
body.
The assembly also includes a chemical treating material. The chemical treating
material is in
solid phase, but is dissolvable upon contact with reservoir fluids. The
chemical treating material
is designed to (i) inhibit a build-up of precipitate on components in the
wellbore, (ii) remove
scale and corrosion on components in the wellbore, or (iii) combinations
thereof. Alternatively,
the chemical treating material is designed to prevent a build-up of paraffin
or bacteria along the
wellbore.
The chemical treating material preferably resides within the bore of the
second tubular body. In
this instance, the chemical treating material may be in the form of a solid
cylindrical "stick."
The stick would represent one or more cylinders stacked within the downhole
assembly. As
reservoir fluids are produced from a subsurface formation, the fluids contact
the "stick," causing
the chemical treating material to slowly dissolve.
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In one aspect, the downhole assembly further includes a blank pipe section
that is placed at an
end of the second tubular body. One or more cylinders are stacked within the
blank pipe. This
adds volume to the solid chemical treating material within the downhole
assembly.
In another embodiment of the downhole assembly, the first tubular body is a
blank pipe. In this
instance, the chemical treating material is preferably placed in an annular
region formed between
the second tubular body and the surrounding first tubular body. The chemical
treating material
may then be in the form of one or more donut-shaped discs. A porous tubular
body may
optionally be placed on either or both ends of the second tubular body. This
allows reservoir
fluids to enter the bore of the second tubular body and make fluidic contact
with the solid
chemical treating material from the inside out.
In one aspect, the assembly resides below a reciprocating pump within a
wellbore.
A method of treating a wellbore using a solid chemical is also provided
herein. The chemical
treatment is delivered along the wellbore at the level of a hydrocarbon-
bearing formation,
preferably below a downhole pump. The chemical treatment serves to inhibit the
build-up of
scale or other selected contaminant along wellbore components during the
production of
reservoir fluids.
The method includes running a downhole assembly into a wellbore. The downhole
assembly is
designed in accordance with the downhole assembly described above in its
various
embodiments.
The method also includes threadedly connecting the downhole assembly to a
wellbore
component. The wellbore component may be, for example, the lower end of a
seating nipple.
Alternatively, the wellbore component may be a joint of production tubing. The
method then
includes running the downhole assembly into the wellbore.
The method may then include producing hydrocarbon fluids from the wellbore.
BRIEF DESCRIPTION OF THE DRAWINGS
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So that the manner in which the present invention can be better understood,
certain illustrations,
charts and/or flow charts are appended hereto. It is to be noted, however,
that the drawings
illustrate only selected embodiments of the inventions and are therefore not
to be considered
limiting of scope, for the inventions may admit to other equally effective
embodiments and
applications.
Figure 1 is a side, cross-sectional view of a well site constructed for
hydrocarbon production.
The well site includes a wellbore that has a downhole chemical delivery
assembly for treating
wellbore components therein.
Figure 2A is a side view of a downhole chemical delivery assembly for treating
wellbore
components of the present invention, in one embodiment. Portions of the
chemical delivery
assembly are cut away and exploded apart to better show individual components.
Pellets are
shown for the chemical treating material.
Figure 2B is a perspective view of a continuous solid material as may be used
as the chemical
treating material of the downhole chemical delivery assembly of Figure 2A.
Here, the chemical
treating material is in the form of donut-shaped discs.
Figure 2C is a side view of the downhole chemical delivery assembly of Figure
2A, in a
modified embodiment. Portions of the chemical delivery assembly are torn away
to better show
individual components.
Figure 2D is a perspective view of a continuous solid material as may be used
as the chemical
treating material of the downhole chemical delivery assembly of Figure 2C.
Here, the chemical
treating material is in the form of a "stick" having a circular profile.
Figure 2E provides a perspective view of a series of cylindrical chemical
delivery sticks having
different scale-inhibiting properties. The shorter sticks are designed to be
stacked within the
porous tubing of Figure 2C.
Figure 3A is a side, cross-sectional view of a downhole chemical delivery
assembly for treating
wellbore components of the present invention, in an alternate embodiment.
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Figure 3B is a side, cross-sectional view of a portion of the downhole
chemical delivery
assembly of Figure 3A. The portion is from circle 3B of Figure 3A.
Figure 3C is a side, cross-sectional view of another portion of the downhole
chemical delivery
assembly of Figure 3A. The portion is from circle 3C of Figure 3A.
Figure 4A provides a side view of a chemical delivery assembly, in an
alternate embodiment.
Here, elongated solid chemical "sticks" are placed within both blank pipe
sections and perforated
tubing sections along the assembly.
Figure 4B provides a cross-sectional view of the perforated tubing of the
chemical delivery
assembly of Figure 4A. A wire screen is shown supported around the perforated
tubing.
Figure 4C provides another cross-sectional view of the perforated tubing of
the chemical
delivery assembly of Figure 4A. Here, the view is cut across line C-C of
Figure 4A.
Figure 5 provides a Cartesian coordinate. Time (in months) is shown on the "x"-
axis, while
dissolution (in parts per million) is plotted along the "y"-axis.
DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS
Definitions
For purposes of the present application, it will be understood that the term
"hydrocarbon" refers
to an organic compound that includes primarily, if not exclusively, the
elements hydrogen and
carbon. Hydrocarbons may also include other elements, such as, but not limited
to, halogens,
metallic elements, nitrogen, oxygen, and/or sulfur. Hydrocarbons generally
fall into two classes:
aliphatic, or straight chain hydrocarbons, and cyclic, or closed ring
hydrocarbons, including
cyclic terpenes. Examples of hydrocarbon-containing materials include any form
of natural gas,
oil, coal, and bitumen that can be used as a fuel or upgraded into a fuel.
As used herein, the term "hydrocarbon fluids" refers to a hydrocarbon or
mixtures of
hydrocarbons that are gases or liquids. For example, hydrocarbon fluids may
include a
hydrocarbon or mixtures of hydrocarbons that are gases or liquids at formation
conditions, at
processing conditions or at ambient conditions (15 C and 1 atm pressure).
Hydrocarbon fluids
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may include, for example, oil, natural gas, coalbed methane, shale oil,
pyrolysis oil, pyrolysis
gas, a pyrolysis product of coal, and other hydrocarbons that are in a gaseous
or liquid state.
As used herein, the terms "produced fluids" and "production fluids" refer to
liquids and/or gases
removed from a subsurface formation, including, for example, an organic-rich
rock formation, a
conventional sandstone or carbonate formation, or a so-called unconventional
shale or other low
permeability formation. Produced fluids may include both hydrocarbon fluids
and non-
hydrocarbon fluids. Production fluids may include, but are not limited to,
oil, natural gas,
pyrolyzed shale oil, synthesis gas, a pyrolysis product of coal, carbon
dioxide, hydrogen sulfide
and water (including steam).
As used herein, the term "fluid" refers to gases, liquids, and combinations of
gases and liquids,
as well as to combinations of gases and solids, combinations of liquids and
solids, and
combinations of gases, liquids, and solids.
As used herein, the term "gas" refers to a fluid that is in its vapor phase at
about 1 atm and 15 C.
As used herein, the term "oil" refers to a hydrocarbon fluid containing
primarily a mixture of
condensable hydrocarbons.
As used herein, the term "subsurface" refers to geologic strata occurring
below the earth's
surface.
As used herein, the term "formation" refers to any definable subsurface region
regardless of size.
The formation may contain one or more hydrocarbon-containing layers, one or
more non-
hydrocarbon containing layers, an overburden, and/or an underburden of any
geologic formation.
A formation can refer to a single set of related geologic strata of a specific
rock type, or to a set
of geologic strata of different rock types that contribute to or are
encountered in, for example,
without limitation, (i) the creation, generation and/or entrapment of
hydrocarbons or minerals,
and (ii) the execution of processes used to extract hydrocarbons or minerals
from the subsurface.
The terms "zone" or "pay zone" or "zone of interest" refer to a portion of a
formation containing
hydrocarbons. Alternatively, the formation may be primarily a water-bearing
interval.
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For purposes of the present patent, the term "production casing" includes a
liner string or any
other tubular body fixed in a wellbore along a zone of interest.
The term "hydrocarbon-bearing formation" refers to a zone of interest or pay
zone containing
hydrocarbon fluids.
As used herein, the term "precipitate" means any substance precipitated from a
wellbore fluid.
Precipitates may include, for example, paraffin, waxes, scale, and iron
sulfide.
As used herein, the term "wellbore" refers to a hole in the subsurface made by
drilling or
insertion of a conduit into the subsurface. A wellbore may have a
substantially circular cross
section, or other cross-sectional shapes. The term "well," when referring to
an opening in the
formation, may be used interchangeably with the term "wellbore."
Description of Selected Specific Embodiments
Figure 1 provides a side, cross-sectional view of a well site 100 constructed
for hydrocarbon
production. The well site 100 generally includes a wellbore 150 and a wellhead
20. The
wellbore 150 includes a bore 115 for receiving completion equipment and
fluids. The bore 115
extends from a surface 101 of the earth, and down into the earth's subsurface
110.
The wellbore 150 is first formed with a string of surface casing 120. The
surface casing 120 has
an upper end 122 in sealed connection with the well head 20. The surface
casing 120 also has a
lower end 124. The surface casing 120 is secured in the wellbore 150 with a
surrounding cement
sheath 125. The cement sheath 125 resides in an annular region formed between
the surface
casing 120 and the surrounding earth subsurface 110.
The wellbore 150 also includes a lower string of casing 130. The lower string
of casing 130 is
also secured in the wellbore 150 with a surrounding cement sheath 135. The
lower string of
casing 130 extends down to a bottom 104 of the wellbore 150. The lower string
of casing 130
traverses a hydrocarbon-bearing formation 50. Therefore, the lower string of
casing 130 is
referred to as production casing.
CA 02797526 2012-11-30
It is understood that the wellbore 150 may and likely will include at least
one additional string of
casing (not shown) residing between the surface (or conductor) casing 120 and
the lower (or
production) casing 130. These intermediate strings of casing may be hung from
the surface.
Alternatively, they may be hung from a next higher string of casing using a
liner hanger. It is
understood that the present inventions are not limited to the type of casing
arrangement used.
The wellbore 150 also includes a string of production tubing 140. The
production tubing 140
extends from a tubing hanger 30 at the well head 20, down proximate to the
hydrocarbon-bearing
formation 50. The production tubing 140 includes a bore 145 that transports
production fluids
from the hydrocarbon-bearing formation 50 up to the well head 20.
The wellbore 150 further has a production packer 146. The production packer
146 sits just
above or proximate to the top of the formation 50 and seals an annular area
between the
production tubing 140 and the surrounding casing 130. The production packer
146 keeps
reservoir fluids from migrating behind the tubing 140 during production.
Encased within the production tubing 140 is a pump 170. The pump 170 may be
any type of
pump used for lifting production fluids up to the surface 101. The pump 170
may be, for
example, an electrical submersible pump, a jet pump, a gas lift, or a
hydraulic pump. In the
specific arrangement of Figure 1, the pump 170 is a positive displacement pump
that is
reciprocated using a string of sucker rods 160.
The sucker rods 160 represent slender joints of pipe that are typically 25 or
30 feet (7.62 or 9.14
meters) in length. The joints are connected end-to-end through threaded
couplings 165. The
sucker rods 160 extend from the surface 101 to the formation 50 and support
the pump 170.
In order to provide fluid communication between the hydrocarbon-bearing
formation 50 and the
production tubing 140, the production casing 130 has been perforated. A series
of perforations
are shown at 55. It is understood that the wellbore 150 may be completed using
a pre-perforated
pipe, a sand screen, a gravel pack, or some combination thereof in lieu of
perforated casing.
As noted, the well site 100 also includes a well head 20. In the illustrative
well site 100, the well
head 20 represents a pumping unit known as a "pump jack." The pump jack
produces an up-and-
down motion for reciprocating the sucker rods 160 and connected pump 170. The
pump jack
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includes known components such as a walking beam 21, a horse head 22, and
supporting
Samson posts 23. The pump jack further includes a Pitman arm 24, a v-belt 25
and a prime
mover (an electric motor or an internal combustion engine) 26 for turning the
v-belt 24. The
pump jack also includes a rotating counter-weight 27 that assists in providing
mechanical
advantage for reciprocating the horse head 22 and a connected bridle 28.
The well head 20 also includes a polished rod 31. The polished rod 31 connects
the bridle 28
with the sucker rods 160. The polished rod 31 is received within a stuffing
box 32. The pump
jack, the polished rod 31, and the stuffing box 32 are all well-known
components for producing
hydrocarbons to the surface 101.
The well head 20 will also include various valves and flow lines for
controlling the flow of
production fluids at the surface. These may include separate oil 36 and gas 37
production lines.
It is understood that the well site 100 arrangement of Figure 1 is merely
illustrative. In some
instances, the hydrocarbon-bearing formation 50 will possess sufficient
reservoir pressure to
allow production fluids to be produced to the surface 101 without need of a
fluid pump 170,
sucker rods 160, and the pumping unit. In that instance, a well head having a
crown valve and/or
master valves will be sufficient. Alternatively, a hydraulic pumping system
may be employed
that uses a hydraulic pump to cyclically pump fluid into a cylinder (not
shown) above the
wellbore 150. The fluid acts against a piston within the cylinder, causing the
piston and the
connected polished rod 31 and rod string 160 to reciprocate.
In any of these instances, it is oftentimes desirable to treat the wellbore
components (such as the
production tubing 140 and the pump 170) for scale or corrosion. Treating may
mean preventing
a build-up of scale or corrosion; alternatively, treating may mean reducing or
removing scale that
is present. Therefore, the wellbore 150 of Figure 1 contains a novel downhole
chemical delivery
assembly 180.
The chemical delivery assembly 180 preferably resides below the pump 170. In
the arrangement
of Figure 1, the chemical delivery assembly 180 resides below and is connected
to a seating
nipple (not shown) below the pump 170. The chemical delivery assembly 180 is
designed to
provide a solid chemical that slowly dissolves upon contact with hydrocarbon
fluids such as
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brine. Beneficially, the chemical delivery assembly 180 is preferably disposed
at or near the
bottom 104 of the bore 115 so that treatment may be provided to downhole
components and the
entire production tubing 140.
Figure 2A is a side view of a downhole chemical delivery assembly 200A for
treating wellbore
components of the present invention, in one embodiment. Portions of the
chemical delivery
assembly 200A are cut away and exploded apart to better show individual
components.
The chemical delivery assembly 200A first includes a screen 210. The screen
210 has an upper
end 202 and a lower end 204. In the arrangement of Figure 2A, the upper 202
and lower 204
ends define threaded half-collars that have been welded or otherwise connected
to the screen
210. Each half-collar presents female threads 206 for connecting with other
components.
The chemical delivery assembly 200A also includes a string of tubing 220. The
tubing 220
contains perforations 225 to provide fluid communication between wellbore
fluids and a bore
235 of the tool 200A. An annular region 215 is formed between the perforated
tubing 220 and
the surrounding screen 210.
Residing within the annular region 215 is a chemical treating material. The
chemical treating
material is shown in Figure 2A in the form of pellets 230. However, the
chemical treating
material may alternatively be in a continuous solid form. For example, the
chemical treating
material may be shaped as donuts or discs. One or more discs may be stacked
over the
perforated tubing 220 and in the annular region 215.
Figure 2B is a perspective view of a continuous solid material as may be used
as the chemical
treating material of the downhole chemical delivery assembly of Figure 2A.
Here, the chemical
treating material is in the form of a series of donut-shaped discs 230B. Each
disc 230B has a
bore 235 dimensioned to receive the perforated tubing 220. The discs 230B are
stacked within
the annular region 215 according to a desired length. The discs 230B serve as
an alternative to
the pellets 230 of Figure 2A.
The chemical delivery assembly 200A also includes a bull plug 250. The bull
plug 250 contains
threads 254 for connecting with threads 206 within the half-collar at the
lower end 204 of the
assembly 200A. The bull plug 250 seals the lower end 204 of the assembly 200A.
Specifically,
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the bull plug 250 holds the pellets 230 (or other solid chemical treating
material) within the
annular region 215.
It is noted that the bull plug 250 defines a nose 252. The nose 252 is
preferably dimensioned to
fit flush with an outer diameter of the half-collar of the lower end 204 when
the bull plug 250 is
tightened down onto the lower end 204. In this way, the chemical delivery
assembly 200A will
not get hung up on wellbore components during run-in or pull-out.
The chemical delivery assembly 200A also has an optional no-flow nipple 240.
The no-flow
nipple 240 defines a body 241 that has a threaded upper end 242 for connecting
to a landing
nipple or production tubing 160 in a wellbore. The no-flow nipple 240 also has
a lower end 244
for threadedly connecting with threads 206 in the half-collar at the upper end
202 of the screen
210.
As the name suggests, the no-flow nipple 240 restricts the flow of fluids,
serving to seal the top
end of the assembly 200A. A pair of blank plates 246 is provided to form the
seal. The blank
plates 246 are shown in phantom in Figure 2A. A through-opening 245 is drilled
through the
no-flow nipple 240 between the plates 246. This optional feature is simply to
indicate that the
nipple 240 is not a typical tubing nipple.
In one aspect, a novel collar (not shown) is placed at either end of the
chemical delivery
assembly 200A. This is in lieu of the no-flow nipple 240 at the upper end
and/or the bull plug
250 at the lower end. The collar is a socket welded collar with female
threads, not unlike the
half-collar shown at the upper 202 and lower 204 ends of the screen 210. A
solid disc plug is
then threaded into the collar using a special tool. This makes it impractical
for a workover crew
at the well site to improvidently open the chemical delivery assembly 200A at
an end and dump
chemical material 230.
With all components connected, the chemical delivery assembly 200A may be
anywhere from 8
feet to 40 feet (2.44 to 12.19 meters) in length. It is understood that a
longer assembly 200A,
particularly a longer screen 210, will have a greater annular volume for
containing the chemical
treating material 230. Optionally, the screen 210 may be jointed, allowing for
the connection of
multiple screen sections along the wellbore.
14
CA 02797526 2012-11-30
In one aspect, two chemical delivery assemblies 200A may be spaced along a
wellbore to treat a
particularly long section of a pay zone. For example, in the case of a
deviated or horizontally
completed well, different screen joints may be placed between perforated
sections of casing or
between sand screen joints to enable greater treatment of the wellbore
components along the pay-
zone. However, it is preferred that the chemical delivery assembly 200A be
placed at the bottom
of the tubing string and below pump intake and never support any weight.
It is understood that other components may be used for connecting the chemical
delivery
assembly 200A with the production string. In this respect, the screen 210 may
not be strong
enough to support the threaded half collar 206 and connected components.
Therefore, some
other connection, such as a welded or threaded connection with the perforated
tubing 220 may be
needed.
Figure 2C is a side view of the downhole chemical delivery assembly of Figure
2A, in a
modified embodiment. The chemical delivery assembly is indicated at 200C.
Portions of the
chemical delivery assembly 200C are torn away to better show individual
components.
However, the components are not exploded apart as they are in Figure 2A.
The tool 200C of Figure 2C is generally designed in accordance with the tool
200A of Figure
2A. Like parts are indicated using like reference numbers. For example, the
tool 200C includes
a screen 210, a section of perforated tubing 220 within the screen 210, a half-
collar at an upper
end 202 of the screen 210, a no-flow nipple 240 above the upper end 202 of the
screen 210,
another half-collar at a lower end 204 of the screen 210, and a bull plug 250
at the bottom of the
chemical delivery assembly 200C.
However, in Figure 2C, the tool 200C does not employ a significant annulus
between the
perforated tubing 220 and the surrounding screen 210. This means that the
pellets (or other solid
chemical) 230 do not reside in an annular region as they do in Figure 2A.
Instead, the pellets
230 reside within the perforated tubing 220 itself.
The perforated tubing 220 may be a standard size tubing, such as 2-3/8 inches
or 2-7/8 inches
inner diameter. The screen 210 has an inner diameter that closely fits over
the outer diameter of
CA 02797526 2012-11-30
=
the tubing 220. Preferably, longitudinal ribs (shown in Figure 4B) provide
spacing and support
between the tubing 220 and the surrounding screen 210.
In Figure 2C, a portion of the perforated tubing 220 is torn away. A plurality
of packed pellets
230 are seen. As fluids are produced from the wellbore, the wellbore fluids
flow through the
filtering screen 210, through the perforations 225 in the tubing 220, and into
the bore 235 of the
tubing 220. There, the wellbore fluids contact the pellets 230.
As the pellets 230 are contacted by water or other hydrocarbon fluids, the
chemical treating
material making up the pellets 230 is dissolved. The dissolved chemical
treating material slowly
migrates out of the chemical delivery assembly 200A or 200B, and intermingles
with the
wellbore fluids. The chemical treating material is then able to treat
production components such
as a downhole pump, production tubing, and surface valves and pipes. In this
way, the chemical
delivery assembly 200A or 200C acts as something of a "tea bag."
It is noted that the chemical treating material of Figure 2C may be a
continuous solid material
rather than pelletized solid material. Figure 2D is a perspective view of a
continuous solid
material as may be used as the chemical treating material of the downhole
chemical delivery
assembly of Figure 2C. Here, the chemical treating material is in the form of
a "stick" 230D.
The stick has a circular profile that generally conforms to the inner diameter
of the perforated
tubing 220. The stick 230D may represent a single elongated cylinder that
extends along the
length of the perforated tubing 220, or it may be a series of cylindrical
bodies that are stacked
according to a desired length.
The composition of the chemical treating material making up the discs 230B or
the sticks 230D
may be adjusted to provide treatment for different types of scale, corrosion,
paraffin, or iron
sulfide. In the case of scale, a corrosion inhibitor is employed in the solid
chemical treating
material. Corrosion inhibitors may be selected from the group consisting of
carboxylic acids and
derivatives such as aliphatic fatty acid derivatives, imidazolines and
derivatives; including
amides, quaternary ammonium salts, amines, pyridine compounds, rosin
derivatives, trithione
compounds, heterocyclic sulfur compounds, quinoline compounds, or salts,
quats, or polymers of
any of these, and mixtures thereof. In addition, suitable inhibitors may
include primary,
secondary, and tertiary monoamines; diamines; amides; polyethoxylated amines,
diamines or
16
CA 02797526 2012-11-30
'
,
,
amides; salts of such materials; and amphoteric compounds. Other examples
include
imidazolines having both straight and branched alkyl chains, phosphate esters,
and sulfur
containing compounds.
The chemical delivery assemblies 200A or 200C may be "tuned" to fit the needs
of the operator.
In this respect, the use of a longer tubing 220 and surrounding screen 210
allows for a larger
amount of pellets 230 (or more discs 230B or longer sticks 230D). This, in
turn, may increase
the life of the assembly 200A or 200C, thereby delaying the need for the well
to be taken off-line
and the assembly 200A or 200C to be pulled and reloaded. Of course, the amount
of space
available below the pump 170 may determine the length of continuous solid
material that may
be deployed.
Figure 2E demonstrates one method for tuning the chemical delivery assembly
200C. Figure
2E provides a perspective view of a series of cylindrical chemical delivery
sticks having
different scale-inhibiting properties. The "sticks" are designated as 231, 232
and 233.
In one aspect, sticks 231 may be formulated to treat primarily carbonate
scales such as calcium
carbonate or calcite [CaCO3]. Sticks 232 may be formulated to treat primarily
sulfate scales such
as gypsum [CaS042H20] or anhydrite [CaSO4] or calcium sulfate. Stick 233 may
be formulated
to primarily treat chloride scales such as sodium chloride [NaCl] or,
alternatively, iron scales
such as iron sulfide [FeS] or iron oxide [Fe2O3]. Any of these sticks may
include the following
known scale-inhibiting agents: phosphates, phosphate esters, phosphoric acid,
phosphonates,
phosphonic acid, polyacrylamides, salts of acrylamido-methyl propane
sulfonate/acrylic acid
copolymers (AMPS/AA), phosphinated maleic copolymers (PHOS/MA), salts of a
polymaleic
acid/acrylic acid/acrylamido-methyl propane sulfonate terpolymer (PMA/AMPS),
sulfamic
acids, or mixtures thereof.
By stacking all three sticks 231, 232, 233, different types of inhibitors may
be employed
simultaneously in the same wellbore.
In one aspect, more sticks of one type are deployed than of another type. In
this way, the solid
chemical treating material is customized for a particular well.
17
CA 02797526 2012-11-30
=
It is also noted that the discs 230B and sticks 23011 (including sections 231,
232, 233) may be
used to treat well conditions other than scale build-up. For example, the
solid chemical material,
or "stick," may be placed within a chemical delivery assembly to prevent wax
build-up. This
requires the placement of a paraffin inhibitor within the chemical "stick."
Paraffin inhibitors are used in petroleum production operations to reduce wax
deposition along
wellbore equipment and flow lines. The active chemistries of paraffin
inhibitor products are
specialty polymers that alter the wax crystallization process. This, in turn,
changes the
characteristics of wax deposits. The paraffin inhibitor may be, for example, a
blend of
surfactants with aromatic solvents. The surfactants may be either nonionic or
anionic
surfactants.
The discs 230B and sticks 23011 (including sections 231, 232, 233) may also be
used to prevent
the growth of bacteria. This requires that the chemical "stick" have a solid
and dissolvable
biocide. The biocide, or bactericide, may be selected from the group
consisting of, for example,
formaldehyde, paraformaldehyde, glutaraldehyde, ammonia, quaternary ammonium
compounds,
sodium hypochlorite, phenols, and mixtures thereof.
In another embodiment, the continuous solid chemical material 230B or 2300
(including
sections 231, 232, 233) may also have a solid and dissolvable asphaltene
inhibitor. Suitable
asphaltene treatment chemicals include those such as alkylphenol ethoxylates
and aliphatic
polyethers.
Any of the above conditions may be treated by placing a suitably designed
continuous solid
material in the form of discs 230B or sticks 231, 232, 233 in the chemical
delivery assemblies
200A, 200C.
Other arrangements for a chemical delivery assembly may be provided. Figure 3A
is a side,
cross-sectional view of a downhole chemical delivery assembly 300 for treating
wellbore
components of the present invention, in an alternate embodiment. In this
arrangement, a screen
310 is again provided. However, in this design the screen 310 resides
substantially
concentrically within a surrounding tubular body 320.
18
CA 02797526 2012-11-30
The tubular body 320 is preferably a joint of blank pipe. However, the tubular
body 320 may
also be another screen or a body having small perforations. In either event,
an annular region
315 is formed between the screen 310 and the surrounding tubular body 320.
Residing within the annular region 315 is a chemical treating material 330.
The chemical
treating material 330 may again be in the form of pellets. Alternatively, the
chemical treating
material 330 may be shaped as discs as shown at 230B in Figure 2B. One or more
"discs" may
be stacked over the screen 310 and in the annular region 315. The discs 230B
may be fabricated
from pyrophosphate (or phosphoric acid in solid phase) or other material known
to remove scale.
For calcium carbonate deposits, glycolic and citric acids and ammonium salts
and blends
incorporating EDTA may be used as chelation agents. Other chemicals such as
sodium
bisulfates and sulfamic acids may be used to treat a variety of well
conditions as noted above.
The chemical delivery assembly 300 also has upper 340U and lower 340L tubing
sections. The
tubing sections 340U, 340L represent pipe bodies 341 that are perforated to
provide fluid
communication with the screen 310. Perforations are shown at 345. Fluids are
then able to flow
through the perforations 345, into a bore 335 of the screen, and outwardly
through the screen
310. The fluids then contact the chemical treating material 330. In this way,
the chemical
treating material 330 may again be dissolved.
The upper tubing section 340U has an upper end 342U and a lower end 344U. The
upper end
342U is threaded for connecting to a wellbore component such as a seating
nipple or a string of
production tubing. The lower end 344 is threaded for connecting to the upper
end 302 of the
tubular body 320. In another aspect, the entire assembly 300 is run in on a
wireline and landed
on a seating nipple. In this instance, the upper end 342U is configured to
releasably connect to a
wireline.
The lower tubing section 340L also has an upper end 342L and a lower end 344L.
The upper
end 342L is threaded for operatively connecting to the bottom 304 of the
tubular body 320. The
lower end 344L is threaded for operatively connecting to a bull plug 350.
The bull plug 350 contains threads 354 for operatively connecting with the
lower end 344L of
the lower tubing section 340L. In the arrangement of Figure 3A, a threaded
collar 360L
19
CA 02797526 2012-11-30
provides female threads for receiving the threads at the lower end 344L of the
lower tubing
section 340L, and threads 354 of the bull plug 350 at the other end. Thus, the
threaded collar
360L is a female-to-female connector. The bull plug 350 then seals the lower
end 344L of the
lower tubing section 340L.
The chemical delivery assembly 300 has a second threaded collar, shown at
360U. The threaded
collar 360U provides female threads for receiving the threads at the lower end
344U of the upper
tubing section 340U at one end, and the threads at the upper end 302 of the
tubular body 320 at
the opposite end.
The annular region 315 is sealed at the upper 302 and the lower 304 ends of
the tubular body
320. Figures 3B and 3C provide enlarged views of the upper 302 and lower 304
ends,
respectively.
Figure 3B is a side, cross-sectional view of a portion of the downhole
chemical delivery
assembly 300 of Figure 3A. The portion is from circle 3B of Figure 3A at the
upper end 302.
Figure 3C is a side, cross-sectional view of another portion of the downhole
chemical delivery
assembly 300 of Figure 3A. The portion is from circle 3C of Figure 3A at the
lower end 304.
Figures 3A, 3B and 3C all show a bore 335 that extends through the length of
the chemical
delivery assembly 300.
The upper tubing section 340U and the lower tubing section 340L each serve as
a no-flow
nipple. In this respect, the tubing sections 340U, 340L each include a blank
plate 346. The
plates 346 prevent the flow of fluids out of the upper 342U and lower 344L
ends of the chemical
delivery assembly 300. This, in turn, forces fluid communication with the
annular region 315 to
take place through the perforations 345 in the respective tubing sections
340U, 340L.
In the operational orientation shown in Figure 3A, fluids are able to flow
from the wellbore,
through the perforations 345, and into the bore 335 of the screen 310.
Reciprocally, fluids may
flow out of the bore 335, through the perforations 345, and out of the tool
300. It is desirable to
be able to seal the flow of fluid from the screen during transport. To do
this, the orientations of
the upper 340U and lower 340L tubing sections may be reversed so that the
plates 346 are
CA 02797526 2012-11-30
adjacent the upper 302 and lower 304 ends of the tubular body 320,
respectively. In this way,
the screen 310 is fluidically sealed for transport to or from a well site.
The chemical delivery assembly 300 may be modified by enlarging the diameter
of the filter
screen 310, and then placing the chemical treating material 330 within the
bore 335 of the screen
310. A small annular region 315 would be preserved within the tubular body 320
to allow fluid
flow. Such an arrangement is shown in Figure 4A.
Figure 4A provides a side view of a chemical delivery assembly 400, in an
alternate
embodiment. The assembly 400 first includes one or more joints of tubing 410.
Preferably,
tubing 410 is a single joint that is about 23.5 feet (7.16 meters) in length.
Such tubing may have
an inner diameter of, for example, 2-3/8", 2-1/2", or 2/7/8". The tubing 410
will have at least
one, and preferably two perforated sections 440. These are simply sections 440
where holes 445
have been drilled.
In the arrangement of Figure 4A, an upper portion of blank tubing 410 is about
3 to 4 feet (0.91
to 1.22 meters) in length. This length is sufficient to allow a pipe pick-up
machine to handle the
assembly 400 at a well site. The upper portion of blank tubing 410 has a pin
end comprised of
threads 414. A traditional upset (not shown) is preferably provided adjacent
the threads 414 to
allow tongs to better support the assembly 400 over a wellbore.
A short section of perforated tubing 440 is provided just below the upper
section of blank tubing
410. In one aspect, this upper perforated tubing 440 is about 1 foot (0.3
meters) in length. It
may be referred to as a "vent." Because the two sections of tubing 410, 440
are actually the
same piece of pipe, no threaded connection is required. However, in one aspect
the two sections
of tubing 410, 440 may be separate sections of tubing having a threaded
connection.
Below the upper perforated tubing 440, or vent, is another section of blank
tubing 410. This
section is preferably about 10 to 20 feet (3.05 to 6.1 meters) in length. Then
extending below
this long section of blank tubing 410 is a lower perforated section 440. This
lower perforated
section 440 is preferably about 2 feet (0.6 meters) in length. Again, the
blank tubing sections
410 and the perforated tubing sections 440 are preferably all the same joint
of tubing, with two
sections being slotted to allow fluid communication by wellbore fluids
internal to the tubing 440.
21
CA 02797526 2012-11-30
=
=
In another aspect, the assembly 400 includes a combination of blank tubing
joints 410 and
perforated tubing joints 440 that are threadedly connected. In this instance,
the assembly 400
may be between about 30 and 100 feet (9.14 and 30.48 meters) in length. In
either aspect, the
tubing 410 / 440 holds elongated solid chemical "sticks" 415. The chemical
sticks 415 are solid
cylindrical bodies such as chemical sticks 2300 of Figure 20.
In Figure 4A, portions of the blank tubing joints 410 have been cut away. This
reveals portions
of solid chemical treating material 415 therein. The chemical treating
material 415 may define,
for example, a 1 foot, a 10 foot, or a 20 foot (0.31, 3.05 or 6.1 meter)
cylindrical body. In one
aspect, the combined tubing 410 / 440 sections are about 24 feet (7.32 meters)
in length, and are
pre-loaded with three, 8-foot (2.44 meters) solid chemical sticks 415.
A perforated tubing section 440 is more clearly seen in the cross-sectional
views of Figures 4B
and 4C. Figure 48 provides a cross-sectional view of a perforated tubing
section 440 taken
along a longitudinal axis of the chemical delivery assembly 400. Figure 4C
provides another
cross-sectional view of the perforated tubing 440. Here, the view is cut
across line C-C of
Figure 4A. (Note that the chemical stick 415 has been removed for illustrative
purposes.)
Referring to Figures 4B and 4C together, it can be seen that the perforated
tubing 440 represents
a tubular body having a bore 405 therein. Perforations 445 (or drilled slots)
are provided along
the tubing 440. The perforations 445 provide fluid communication between the
bore 405 of the
tubing 440 and the surrounding subsurface formation (shown at 50 in Figure 1).
The perforated tubing 440 is surrounded by a wire screen 430. The wire screen
430 is preferably
a so-called "v" screen, wherein wire having a "v" profile is wound around the
tubing 440. The
wire screen 430 is supported by a series of longitudinal ribs 424 that are
welded in place. The
result is a series of micro-slots 432 that are sized to permit an ingress of
fluids but to keep out
sands and fines of a selected diameter.
A small annulus 435 is formed between the perforated tubing 440 and the
surrounding screen
430. The annulus 435 permits fluid flow along the longitudinal axis of the
screen 430.
However, opposing ends of the screen 430 are sealed using end collars 412. The
end collars 412
define welded rings.
22
CA 02797526 2012-11-30
It is noted that the size of the slots 432 and the size of the annulus 435 may
be adjusted to control
the amount of fluid that flows into the bore 405 of the perforated tubing 440.
This, in turn,
controls the rate of dissolution of the solid chemical stick 415. Preferably,
the slots 432 are
about 0.006 to 0.075 inches in width. A smaller width will decrease the rate
of dissolution of the
solid chemical treating material 415.
The lower perforated tubing section 440 and surrounding screen 430 may be
between about 2
feet and 10 feet (0.61 and 3.05 meters) in length for significant producing
wells. Joints of
perforated tubing 440 and screen 430 may be connected end-to-end to increase
the length of the
perforated tubing section 440 with screen 430. This would be for the purpose
of housing greater
lengths of the solid chemical stick 415 within bore 405.
On the other hand, for so-called stripper wells that produce only small
volumes of reservoir
fluids each day, the combined perforated tubing 440 and surrounding screen 430
may be between
about 1 foot and 3 feet (0.3 and 0.91 meters). In one embodiment, the entire
assembly 400 is
only eight feet in length and may be shipped to a customer via courier with
the chemical stick
415 pre-loaded. Such a scaled-down assembly may also be beneficial for de-
watering gas wells.
In this respect, caustic components in the water and even in the gas can scale
up perforations.
Referring back to Figure 4A, an upper blank tubing section 410 is optionally
connected to a no-
flow nipple 420. The no-flow nipple 420 has a threaded upper end 422 for
connecting to a
landing nipple or production tubing 160 in a wellbore. The no-flow nipple 420
also has a lower
end 424 for threadedly connecting with an upper half-collar 460U. The upper
half-collar 460U
serves as a male-to-male connector for connecting the no-flow nipple 420 to
the upper blank pipe
joint 410 via threads 414. Preferably, the upper half-collar 460U is a
standard full EUE 8 round
collar.
The no-flow nipple 420 also has a through-opening 425 drilled through it. The
through-opening
425 resides between two blank plates 426. The blank plates 426 are shown in
phantom in
Figure 4A. The plates 426 prevent the flow of fluids out of the upper end of
the assembly 400.
A lower end of the chemical delivery assembly 400 is sealed using a plug 450.
In the view of
Figure 4A, the plug 450 is a bull plug. The bull plug 450 includes male
threads 452. The bull
23
CA 02797526 2012-11-30
plug 450 is connected to a bottom screen 430 through a lower half collar 460L.
In the view of
Figure 4A, the half collar 460L is a male-to-male connector that connects the
threads 452 of the
bull plug 450 to threads 454 of a screen connector 455. However, in another
embodiment the
lower half-collar 460L is welded on. To accomplish this, the lower (pin) end
of the tubing is cut
off.
In one aspect, the bull plug 450 is specially designed to present a uniform
profile. Most bull
plugs have a lip that extends out over the threads. However, the bull plug 450
of Figure 4A
meets flush with the outer diameter of the half collar 460L. In another
aspect, the lower plug
450 is a blank disc that is screwed into the lower half collar 460L,
preferably using a keyed tool.
Alternatively, a socket-weld collar and a blank disc (not shown) are used to
seal the lower end of
the chemical delivery assembly 400.
As can be seen improved chemical delivery assemblies for inhibiting the build-
up of paraffin,
scale and corrosion are provided. The use of the assemblies 200A, 200C, 300
and 400 may
reduce the frequency of pulling tubing due to corroded pipe, corroded rods, or
corroded pumps.
In addition, the use of the assemblies 200A, 200C, 300 and 400 may reduce the
frequency of
stuck plungers in plunger lift systems.
In any of the above compositions, portions of chemical treating material 415
may be designed to
have different dissolution rates. This means that different sticks having
different dissolution
rates may be placed along the chemical delivery assembly 400. This serves to
both "smooth out"
the dissolution rate and extend the life of the treating material in the
wellbore.
Referring back to Figure 2E, sticks 231, for example, may be designed to
dissolve quickly, such
as over a first 120 day period in a wellbore. Sticks 232 may have a membrane
coating on them
that delays exposure to reservoir fluids, causing the sticks 232 to dissolve
primarily over a
second 120 day period. The membrane may be a thin polymer coat that dissolves
slowly in the
presence of the slightly acidic reservoir fluids. Sticks 233 may be comprised
of a separate
material that dissolves more slowly, such as over a 240 day period. In this
way, the wellbore is
being continuously treated for a particular type of scale over an 8-month
period.
24
CA 02797526 2012-11-30
Figure 5 provides a Cartesian coordinate 500. Time (in months) is shown on the
"x"-axis, while
dissolution (in parts per million) is plotted along the "y"-axis. Line 531
presents an illustrative
dissolution rate for chemical stick 231; line 532 presents an illustrative
dissolution rate for
chemical stick 232; and line 533 presents an illustrative dissolution rate for
chemical stick 233 of
Figure 2E. Dissolution rates may be, for example, between about 25 ppm and 150
ppm.
In Figure 5, a fourth line is shown at 534. The fourth line 534 is dashed, and
represents a sum of
the values (dissolution rates) for lines 531, 532 and 533. Line 534
demonstrates a smoothing
effect from having three different chemical sticks 231, 232, 233 having
different dissolution
rates.
In Figure 5, lines 531 and 532 suggest an effective life of about 5 months for
the first 231 and
second 232 chemical sticks, while line 533 suggest an effective life of about
6 months for a third
233 chemical stick 233. It is understood that these life spans are merely
illustrative, and that
ideally a life span of 8 to 12 months would be provided.
As an alternative, lines 531, 532 and 533 may all represent chemical sticks
that have the same
rate of dissolution. However, the chemical stick of line 531 may reside along
a perforated tubing
having surrounding screen slots dimensioned to permit a first fluid flow rate
that increases the
dissolution rate. On the other hand, the chemical stick of line 533 may reside
along a perforated
tubing having surrounding screen slots dimensioned to permit a second fluid
flow rate that
decreases the dissolution rate. Then, the chemical stick of line 532 may
reside along the blank
pipe joints 510, wherein reservoir fluids do not significantly reach the
chemical sticks until the
chemical stick of line 531, the chemical stick of line 532, or both have been
substantially
dissolved. Alternatively or in addition, a dissolvable membrane may be placed
at an end of a
blank pipe joint 510 that protects the chemical stick from exposure to
reservoir fluids for a
designated period of time. Such a membrane is shown in phantom at 418 in
Figure 4A.
As an alternative to adjusting screen slot sizes 435 or adjusting the
dissolution rate of a solid
chemical treating material 415 or using a membrane 418, a chemical delivery
assembly may
have an inflow control device. In one aspect, the inflow control device is
electrically powered,
and borrows power from a power cord associated with an electrical submersible
pump, or ESP.
CA 02797526 2012-11-30
While it will be apparent that the inventions herein described are well
calculated to achieve the
benefits and advantages set forth above, it will be appreciated that the
inventions are susceptible
to modification, variation and change without departing from the spirit
thereof. Certain
embodiments of the inventions are presented in the claims, which follow.
26
