Note: Descriptions are shown in the official language in which they were submitted.
CA 02249432 2004-11-08
!NEZ1~OD AND APPARATUS USING COILED-IN-COILED TUBING
10
Field of Invention
This invention pertains to safeguarded methods and
apparatus for providing fluid communication with coiled
tubing, useful in communicating fluids within wells, and
particularly applicable to drill stem testing and/or
operations in sour wells. The invention further pertains
to multicentric coiled-in-coiled tubing, ~ useful for
safeguarded downhole or conduit operations, snd its method.
of assembly, including preferred and alternate methods.
The invention also pertains to the use of coifed-in-coiled
tubing with a bottomhole assembly package, for operations
that may be particularly pertinent to horizontal and/or
deviated wells. including operations such as treating or
forming or testing or measuring and the like, aad~ in
particular, to combinations of the ~ above operations
performable in the same run.
BACKGROUND OF INVfiNTION
This application is related to and comprises a
continuation in part of prior pending application having
PCT Publication No. W097/05361. The corresponding U.S.
Patent No. is 5,638,90'4.
The oil sad gas industry uses various methods to
test the productivity of wells prior to completi.lag and
tying a well into a pipeline or battery. After drilling
operations have been completed and a wall has bsen drilled
to total depth ("TD"), or prior to reaching TD in the case
of multi-zoned discoveries, it is common to perform a
drill stem test ("DST"). This test estimates future
production of oil or gas and can justify a further
expenditure of capital to complete the well.
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 2 -
The decision to "case" a well to a particular depth,
known as a "casing point election", can result in an
expenditure in excess of $300,000. Without a DST, a
wellsite geologist must make a casing point election based
on only core samples, cuttings, well logs, or other
indicators of pay thicknesses. In many cases reservoir
factors that were not knowable at the time of first
penetration of the producing zone, and thus not reflected
in the samples, cuttings, etc., can control the ultimate
production of a well. A wellsite geologist's problem is
exacerbated if the well is exploratory, or a wildcat well,
without the benefit of comparative adjacent well
information. Further, the geologist must make a casing
point election quickly as rig time is charged by the hour.
I5 A DST comprises, thus, a valuable and commonly used
method for determining the productivity of a well so that
optimal information is available to the geologist to make
a casing point election. Traditionally the DST process
involves flowing a well through a length of drill pipe
reinserted through the static drilling fluid. The bottom
of the pipe will attach to a tool or device with openings
through which well fluids can enter. This perforated
section is placed across an anticipated producing
formation and sealed off from the rest of the wellbore
with packers, frequently a pair of packers placed both
above and below the formation. The packer placement or
packing off technique permits an operator to test only an
isolated section or cumulative sections. .The testing can
involve actual production into surface containers or
containment of the production fluid in the closed chamber
comprised by the pipe, pressure testing, physically
retrieving samples of well fluids from the formation level
and/or other valuable measurements.
The native pressure in producing reservoirs is
controlled during drilling through the use of a carefully
weighted fluid, referred to above and commonly called
"drilling mud". The "mud" is continuously circulated
during the drilling to remove cuttings and to control the
well should a pressurized zone be encountered. The mud is
usually circulated down the inside of the drill pipe and
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 3 -
up the annulus outside of the pipe and is typically made
up using water or oil based liquid. The mud density is
controlled through the use of various materials for the
purpose of maintaining a desired hydrostatic pressure,
usually in excess of the anticipated native reservoir
pressure. Polymers and such are typically added to the
mud to intentionally create a "filter cake" sheath-like
barrier along the wellbore surface in order to staunch
loss of over-pressured drilling fluid out into the
formation.
As can be easily appreciated, when an upper packer
of a DST tool seals an annular area between a test string
and a borehole wall, the hydrostatic pressure from the
column of drilling fluid is relieved on the wellbore below
the packer. The well below the packer, thus, can flow if
an open fluid communication channel exists to the surface.
At least the well will flow to the extent that native
pressure present at the open formation of the isolated
section exceeds the hydrostatic head pressure of the
tested fluids in the drill pipe. Such produced fluids
that flow to or toward the surface are either trapped in
the pipe string or collected in a container of known
dimensions and/or flared off. By calculating the volume
of actual fluid produced, after considering such factors
as the time of the test and the size of the choke used, a
reasonable estimate of the ultimate potential production
capacity of a well can be made . Upon occasion formation
pores are too clogged, as by the drilling fluid filter
cake, to be overcome by formation pressure and flow. It
may be desired in such cases to deliver a gas or an acid
to the formation to stimulate flow.
Many wells throughout the world contain hydrogen
sulfide gas (H2S), also known as "sour gas". Hydrogen
sulfide gas can be harmful to humans or livestock at very
low concentrations in the atmosphere. In Alberta, Canada,
sour wells commonly produce hydrocarbon fluids with
concentrations of 2-4o H2S and often as high as 30-35%
H2S. These are among the most sour wells in the world.
It is also known that sour gas can cause embrittlement of
steel, such as the steel used in drill pipe. This is
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 4 -
especially true when drill pipe contains hardened steel,
which is commonly used to increase the life of the drill
string. Due to a tendency for drill pipe to become
embrittled when exposed to H2S and the possibly disastrous
effect of sour gas in the atmosphere with its potential
for environmental damage or injury to people or animals,
it is extremely uncommon to perform drill stem tests on
sour wells. Even a pin hole leak in a drill pipe used for
such purposes could have deleterious results.
Unfortunately, many highly productive wells are very
sour and found in exploratory areas. In some cases, oil
companies have been prepared to go to the expense of
temporarily completing a sour well by renting production
tubing and hanging it in a well without cementing casing
in place, just to effect a production test. This method,
due to the increase in rig time, can cost in excess of
$200,000, which could be greater than the cost of a
completion in shallow wells.
Coiled tubing is now known to be useful for a myriad
of oilfield exploration, testing and/or production related
operations. The use of coiled tubing began more than two
decades ago. In the years that have followed coiled
tubing has evolved to meet exacting standards of
performance and to become a reliable component in the oil
and gas service industry. Coiled tubing is typically
manufactured from strips of low alloy mild steel with a
precision cut, and rolled and seam welded in a range of OD
(outside diameter) sizes, envisioned to run up to 6
inches. Currently, OD sizes are available up to
approximately 4 inches. Improvements in manufacturing
technology have resulted in increased material strength
and consistent material quality. Development of a "strip
bias weld" has improved the reliability of factory made
joints in the coiled tubing string. Heat treatment and
material changes have increased resistance of the tubing
to H2S induced embrittlement and stress corrosion cracking
that can incur in operations in sour environments. An
increase in wall thickness and the development of higher
strength alloys are also allowing the industry to increase
the depth and pressure limits within which the tubing may
CA 02249432 1998-09-18
WO 97/35093 PCTNS97/03563
be run. The introduction of new materials and structure,
such as titanium and composite material tubing design, is
also expected to further expand coiled tubing's scope of
work.
Coiled tubing could be particularly valuable in sour
or very sour wells due to coiled tubing's typically softer
steel composition that is not so susceptible to hydrogen
sulfide embrittlement. However, another factor inhibits
producing sour gas or performing a DST in a sour well with
coiled tubing. The repeated coiling and uncoiling of
coiled tubing causes tubing walls, presently made of the
steel, to plastically deform. Sooner or later the plastic
deformation of the tubing wells is likely to cause a
fracture. A resulting small pin hole leak or crack could
produce emissions.
Oil and gas operations have known the use of
concentric pipe strings. Concentric pipe strings provide
two non wellbore channels for fluid communication
downhole, typically with one channel, such as the inner
channel, used to pump fluid (liquid or gas or multiphase
fluid) downhole while a second channel, such as the
annular channel formed between the concentric strings,
used to return fluid to the surface. (A further annulus
created between the outer string and the casing or liner
or wellbore could, of course, be used for further fluid
communication). Which channel is used for which function
can be a matter of design choice. Both concentric pipe
channels could be used to pump up or down.
Concentric tubing utilizing coiled tubing, at least
in part, has been proposed for use in some recent
applications. Coiled tubing enjoys certain inherent
advantages over jointed pipe, such as greater speed in
running in and out of a well, greater flexibility for
running in "live" wells and greater safety due to
requiring less personnel to be present in high risk areas
and the absence of joints and their inherent risk of
leaks.
Patterson in U.S. Patent No. 4,744,420 teaches
concentric tubing where the inner tubing member may be
coiled tubing. It is inserted into an outer tubing member
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 6 -
after that member has been lowered into the wellbore. In
Patterson the outer tubing member does not comprise coiled
tubing. As figure 8 of Patterson illustrates, the inner
tubing is secured within the outer tubing by spaced apart
spoke-like braces or centralizers which hold the tubing
members generally centered and coaxial. Sudol in U.S.
Patent No. 5,033,545 and Canadian Patent No. 1325969
discloses coaxially arranged endless inner and outer
tubing strings. Sudol's coaxial composite can be stored
on a truckable spool and run in or pulled out of a well by
a tubing injector. Sudol's disclosure does not explicitly
disclose how the coaxial tubing strings are maintained
coaxial, but Sudol does show an understanding of the use
of centralizers. U.S. Patent No. 5,086,8422 to Cholet
discloses an external pipe column 16 which is inserted
into a main pipe column comprising a vertical section and
a curved section. An internal pipe column is then lowered
into the inside of the external pipe column. Cholet
teaches that the pipe columns may be formed to be the
rigid tubes screwed together or of continuous elements
unwound from the surface. Cholet does not teach a single
tubing composite that itself is wound on a spool, the
composite itself comprising an inner tubing length and an
outer tubing length. All of Cholet's drawings teach
coaxial concentricity. U.S. Patent No. 5,411,105 to Gray
teaches drilling with coiled tubing wherein an inner
tubing is attached to the reel shaft and extended through
the coiled tubing to the drilling tool. Gas is supplied
down the inner tube to permit underbalanced drilling.
Gray, like Sudol, discloses coaxial tubing. Further,
Gray does not teach a size for the inner tube or whether
the inner tube comprises coiled tubing. A natural
assumption would be, in Gray's operation, that the inner
tube could comprise a small diameter flexible tube
insertable by fluid into coiled tubing while on the spool,
like wireline is presently inserted into coiled tubing
while on the spool. The Griffiths patent, U.S. No.
5,503,014, issued April 2, 1996, filed July 29, 1994,
practices a version of drill stem testing using dual
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/035b3
_ 7 _
coaxial coil. No test tool or bottomhole assembly is
taught.
The present invention solves the problem of
providing a safeguarded method for communicating
potentially hazardous fluids and materials through coiled
tubing. This safeguarded method is particularly
applicable for producing and testing fluids from wells
including very sour gas wells. The safeguarded method
proposes the use of coiled-in-coiled tubing, comprising an
inside coiled tubing length located within an outside
coiled tubing length. Potentially hazardous fluid or
material is communicated through the inside tubing length.
The outside tubing length provides a backup protective
layer. The outside tubing defines an annular region
between the lengths that can be pressurized and/or
monitored for a quick indication of any leak in either of
the tubing lengths. Upon detection of a leak, fluid
communication can be stopped, a well could be killed or
shut in, or other measures could be taken before a fluid
impermissibly contaminates its surroundings.
As an additional feature, the annular region between
the tubing lengths can be used for circulating fluid down
and flushing up the inside tubing, for providing
stimulating fluid to a formation, for providing lift fluid
to the inside tubing or for providing fluid to inflate
packers located on an attached downhole device, etc.
The present invention also relates to the assembly
of multicentric coiled-in-coiled tubing, the proposed
structure offering a configuration and a method of
improved or novel design. This improved or novel design
provides advantages of efficient, effective assembly,
longevity of use or enhanced longevity with use, and
possibly enhanced structural strength. A preferred method
and alternate methods of assembly of multicentric and
concentric coil-in-coil are disclosed.
It has been discovered that coiled-in-coiled tubing
can offer the same benefits of flexibility and
thrustability that are found in single coiled tubing when
compared to jointed pipe, characteristics particularly
useful for work in horizontal and/or deviated wells.
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
_ g _
However, coiled-in-coiled tubing provides the operator
with two conduits as opposed to one for the communication
of fluids, as from the surface to the bottomhole, or from
the bottomhole to the surface, from the surface to tool
combinations in a bottomhole assembly, and/or to provide
an insulating chamber. These conduits are in addition, of
course, to the tubing-wellbore annulus that can or could
be used as a conduit.
Some operations, as discussed above and below, can
benefit from the availability of a safeguarded or
insulated production conduit. Some tools, as mentioned in
the above discussion of Sudol and the sand vacuuming tool,
prescribe two fluid conduits for their operation, and
others might benefit from such.
Given the construction of prototype coiled-in-coiled
tubing, it has been subsequently discovered that well
operations such as treating, forming, testing and/or
measuring operations and the like, and especially
including combinations of the above, could be performed
cost effectively on coil-in-coil. For instance, the
efficiency of testing combined with well enhancing
operations could be increased if performed in the same run
downhole with other operations. The flexibility provided
by the availability of plural conduits for pumping down,
pumping up, and circulating fluids, and performing the
same simultaneously or sequentially, makes possible many
novel combinations of operations not before possible in a
run downhole. Plural circulating conduits permit
combinations of operations to be performed downhole in
new, improved and novel manners. The added efficiency can
justify the added cost of utilizing coil-in-coil, as well
as add a safety factor.
SUMMARY OF THE INVENTION
This invention relates to the use of coiled-in
coiled tubing (several hundred feet of a smaller diameter
inner coiled tube located within a larger diameter outer
coiled tube) to provide a safeguarded method for fluid
communication. The invention is particularly useful for
well production and testing. The apparatus and method are
of particular practical importance today for drill stem
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 9 -
testing and other testing or production in potentially
sour or very sour wells. The invention also relates to an
improved "multicentric" coiled-in-coiled tubing design,
and its method of assembly.
The use of two coiled tubing strings, one arranged
inside the other, doubles the mechanical barriers to the
outside environment. Fluid in the annulus between the
strings can be monitored for leaks. To aid monitoring,
the annular region between the coils can be filled with an
inert gas, such as nitrogen, or a fluid such as water, mud
or a combination thereof, and pressurized.
In one embodiment a fluid, such as water or an inert
gas, can be placed in the annulus between the tubings and
pressurized. This annular fluid can be pressurized to a
greater pressure than either the pressure of the hazardous
fluid being communicated via the innermost string or the
pressure of the fluid surrounding the outer string, such
as static drilling fluid. Because of this pressure
differential, if a pin hole leak or a crack were to
develop in either coiled tubing string the fluid in the
annulus between the inner and outer string would flow
outward through the hole. Instead of sour gas, for
instance, potentially leaking out and contaminating the
environment, the inner string fluid would be invaded by
the annular fluid and continue to be contained in a closed
system. An annular pressure gauge at the surface could be
used to register a pressure drop in annular fluid,
indicating the presence of a leak.
Communicated fluids through the inner string could
be left in the closed chamber comprised of the inner
string, for one embodiment, or could be separately
channeled from the coiled-in-coiled tubing at the spool or
working reel. Separately channeled fluids. could be
measured, or fed into a flare at the surface or produced
into a closed container, for other embodiments.
The coiled-in-coiled tubing should be coupled or
attached to a device at its distal end to control fluids
flowing through the inner tube. Fluid communications
through the annular channel should also be controlled. At
a minimum this control might comprise simply sealing off
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 10 -
the annular region. For drill stem testing, packers and
packing off techniques could be used in a similar fashion
as with standard drill stem tests. An additional benefit
is provided by the invention in that a downhole packer
could be inflated with fluid supplied down the coiled-in-
coiled tubing.
The inner coiled tube is envisioned to vary in size
between 1/2" (inches) and 5'f" (inches) in outside diameter
("OD"). The outer coiled tube can vary between 1" and 6"
in outside diameter. A preferred size is 1 1/4 to 1 1/2"
O.D. for the inner tube and 2" to 2 3/8" O.D. for the
outer tube.
It is known that steel of a hardness of less than 22
on the Rockwell C hardness scale is suitable for sour gas
uses. Coiled tubing can be commonly produced with a
hardness of less than 22, being without the need for the
strength required for standard drill pipe. Thus, coiled
tubing is particularly fit for sour gas uses, including
drill stem testing, as disclosed. Other materials such as
titanium, corrosion resistant alloy (CRA) or fiber and
resin composite could be used for coiled tubing.
Alternately, other metals or elements could be added to
coiled tubing during its fabrication to increase its life
and/or usefulness.
The invention further includes apparatus and method
for use in downhole well operations such as treating,
forming, testing or measuring and the like, and especially
in combinations of the above. Treating operations refer
generally to operations such as acidizing or fracturing or
heating or other well stimulating activities, including
injecting chemical and biological additives.
Specifically, treating might refer to operations such as a
polymer squeeze to close off suspected water producing
zones, clay swelling control mechanisms, sand control
mechanisms, filter cake removal systems, iron or sludge
control and fines migration control. Treating might also
refer to the addition of one or more of the following,
either separately or in combination: emulsifiers,
gellants, polymers, surfactants, buffers, neutralizers,
corrosion control agents, inhibitors, diverting agents,
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 11 -
breakers, cements, fluid loss control additives,
detergents, cleaning agents, solvents, sequesterants,
suspending agents, gels or proppants, foam or defoamers,
gases, friction reducers, retarders, lost circulation
material, flushes and preflushes, wax or paraffin
removers, asphaltine control agents, viscosifiers,
dispersants, bonding agents, cement additives and scale
inhibitors. Generally, treating fluids could refer to any
combination of acid and/or fracturing fluids as well as to
additives thereto. Treating fluids would be mixed and
applied simultaneously or sequentially according to the
need of the particular formation. Treating operations
could include jet cleaning and sand vacuuming operations.
Forming operations include operations such as
drilling, modifying, perfing (perforating), establishing
build sections and forming dog legs, as well as other
activities that affect the structure and conformance of
the wellbore.
Testing operations include producing operations,
including both production testing and long term
production. A general purpose tool might be referred to
as a production/test tool.
There could be an overlap between testing tools and
measuring tools. Measuring tools include the spectrum of
logging tools as well as pressure measuring devices, flow
meters, densitometers, locating tools, sampling tools and
tools to perform chemical analyses or geological and
geophysical analyses downhole.
Apparatus for use in well operations in accordance
with the present invention comprises coiled-in-coiled
tubing having an inner coiled tubing length contained
within an outer coiled tubing length. The two tubing
lengths define a first inner coil fluid conduit and a
second inter-coil "annular" fluid conduit. The apparatus
includes a bottomhole assembly package adapted to attach
to a portion of the coiled-in-coiled tubing, typically
attaching to the distal end of the coiled-in-coiled
tubing, and in fluid communication with both fluid
conduits defined by the coiled-in-coiled tubing.
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 12 -
The apparatus may include at least one packer
adapted to be associated with the bottomhole assembly or
the tubing. Typically the packer would be associated with
the bottomhole assembly and might comprise a straddle
packer. The packer optionally could be structured to
permit the tubing to reciprocate or to slide while the
packer packs off between a portion of the borehole wall
and the tubing.
An emergency packer deflation mechanism might be
included in the event of loss of communication. The
mechanism could operate by pressure application to a sheer
pin or a number of pins or by a variety of other methods,
which would allow fluid to escape from the packers to the
wellbore or to the coil tubing.
In most applications a surface control mechanism
would control fluid communication within both the inner
conduit and the coiled-in-coiled annular conduit.
Preferably the coiled-in-coiled tubing at the surface
would be connected to a spool or reel at its proximate
end. The flow from both conduits could be separated with
an adapting mechanism at the spool or reel to channel or
control each flow separately, as desired.
A bottomhole assembly package could range from the
elaborate to the simple. A drillstem test tool as
disclosed in figures 5 and 5A comprise one bottomhole
assembly package. The tool is designed such that it could
function as a production/test tool and a treatment
injection tool. Valves in the tool control fluid
communication between the inner and the annular conduits
and the wellbore as well as between the conduits
themselves. Alternately, a bottomhole assembly might
comprise one or more of a production/test tool, a pump
tool, a treatment injection tool, a vacuum tool, a jetting
tool, a perfing tool, a drilling tool, an orienting tool,
a hydraulic motor and/or an electric motor. A treatment
injecting tool could inject treatment fluid. The
bottomhole assembly might include a variable spacing unit.
Such units could provide spacing from one to fifty meters.
Presently available tools, such as enumerated in the
above list, would likely need to be adapted to work
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 13 -
effectively with coiled-in-coiled tubing in a bottomhole
assembly package. Some tools, such as a Sudol sand
vacuuming tool, or a drillstem test tool as in figure 5,
is adapted to work with coiled-in-coiled tubing. Adapting
other tools to function in a bottomhole assembly package
connected to coiled-in-coiled tubing may require only an
appropriate sub to connect the tool fluid communication
ports with the fluid communication capabilities of the
coiled-in-coiled tubing, or with the tool sections above.
If multiple tools are packaged in a bottomhole assembly,
some provision will likely be made to port the tool's own
fluid communication ports with the fluid communication
ports of the above tool as well as to port fluid
communication through or around the tool in order to serve
tools connected below. Such engineering and design
parameters can be worked out as preferred bottomhole
assembly packages develop. The greater the commercial
market for a particular tool package assembly, the greater
the likelihood that fluid communication channels will be
incorporated into the tool body self as opposed to being
arranged in an ad hoc or temporary fashion.
It is envisioned that pumps associated with a
bottomhole assembly may include jet pumps, chamber
liftpumps, and/or electric pumps. Such pumps could
function as alternate systems to recover well effluent to
the surface for measurement or analysis. Electrical
submersible pumps are known. A wireline will likely
extend through one of the two coiled-in-coiled tubing
conduits to establish electrical communication between the
surface and the bottomhole assembly package. The
electrical communication could serve the functions of both
power and communication, as is illustrated and taught in
U.S. patent No. 4,898,236 to Sask, entitled "Drill Stem
Testing System." The important role of real time data is
discussed in the Sask patent. The wireline could include
a conductor within a braided line. Fibre optic wireline
cables are also a possibility. If the wireline is to be
included in the coiled-in-coiled annular conduit, as
opposed to the inner conduit, the coiled-in-coiled tubing
would likely be concentric as opposed to multicentric.
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 14 -
Any single or mufti-line conductor within a braided line
or smaller coil tubing could function as a communication
cable.
A variety of measuring tools may fortuitously be
included in a bottomhole assembly package. Provision
would be advantageously provided for multiple pressure,
temperature, logging or other measurements.
The apparatus for use in well operations may omit a
t packer associated with the tubing and/or bottomhole
assembly, as the bottomhole assembly package may include
multiple tools and function that have no need for packing
off. When a packer is included with the bottomhole
assembly, one conduit of the coiled-in-coiled tubing could
advantageously be used to hydraulically set the packer.
Inflatable/deflatable strata packers may be appropriate
for many operations.
The availability of the above apparatus, namely
coiled-in-coiled tubing and an appropriate bottomhole
assembly package, makes possible the performance of a
variety of novel, efficient and cost effective downhole
well operations, performable in one run. For such
operations, the coiled-in-coiled tubing should be
connected to the bottomhole assembly package such that
both the inner and the annular fluid conduits are in fluid
communication with the assembly.
The bottomhole assembly is to be located down a
wellbore. Most easily the assembly is injected down the
wellbore attached to the distal end of the coiled-in-
coiled tubing being injected from a spool. One
advantageous method of use of the above apparatus includes
packing off between a portion of the wellbore and a
portion of the tubing and/or assembly and pumping fluid
down at least one of the two coiled-in-coiled tubing
conduits for operations. Fluid, for instance, could be
pumped down to set the packer. Fluid pumped down the
conduit could also be advantageously used to power tools
and to circulate into the wellbore. Wellbore fluid could
be produced up a conduit, simultaneously or in sequence
with pumping down to facilitate flushing operations.
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/035b3
- 15 -
For example, if a combination production/test and
treatment injection tool, such as that of figures 5 and
5A, were to comprise the bottomhole assembly, together
with a packer, the methodology could include first setting
the packer amid the drilling fluid in a wellbore by using
water in a first conduit, preferably the annular conduit.
The first conduit could then be shut off and wellbore
fluid below the packer produced up the second conduit,
preferably the inner conduit. The drilling fluid or mud
remains in the wellbore tubing annulus above the packer.
In the present example subsequent operation will not
contaminate or otherwise destroy the value of this
drilling fluid by circulating extraneous materials through
it.
If testing of the produced fluid indicates that a
well treatment might improve production, valves can be
opened that permit circulation between the first conduit
and the second conduit. Water in the first conduit and
production fluid in the second conduit (and in the
wellbore beneath the packer to a certain extent) can be
circulated out and a treating fluid, such as acid, pumped
down. When the fluids are suitably flushed, the second
conduit can be closed and the treating fluid, such as
acid, injected into the wellbore below the packer through
the first conduit. The treating fluid may be followed by
water. Both conduits may then be closed while the
chemical acts. Production can be reestablished back up
the second conduit, producing first any residual fluids in
the conduit, spent acid and then formation fluid.
It can be assumed that the acid injected down the
first conduit was followed by water such that when the
acidizing is complete, water remains trapped in the first
conduit. The formation fluid can be advantageously tested
anew. If the test results on the produced formation fluid
are now satisfactory, the packer can be deflated,
particularly aided by using a conduit to depressurize the
packer chamber, and the process repeated at another
location. If the test results are unsatisfactory, the
flush and treatment cycle can be repeated, using the same
or different treatment fluids. Straddle packers can be
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 16 -
used in lieu of a single packer to suitably isolate a
production zone.
If testing indicates that a zone produces water, a
polymer squeeze chemical could be applied through one
conduit, such as the first conduit, to wall off the zone
from production. The success or effectiveness of the
polymer squeeze could be immediately subsequently tested
by production with the tool. In the above sequence of
operations, the drilling fluid in the well above the
packer has not been contaminated by the necessity to flush
any fluids through the wellbore-tubing annulus above the
packer.
A packer might be set downhole such that it permits
coiled-in-coiled tubing to slidingly reciprocate while the
packer packs off between the wellbore and the tubing wall.
Some treating operations such as sand vacuuming and/or jet
cleaning require the movement of a tool during operation.
Drilling also depends upon movement of the coiled tubing
within the wellbore. A packer permitting the tubing to
reciprocate through it, set at a build section, might
permit, for instance, a horizontal well to be overbalanced
in its vertical section, having drilling fluid above the
packer, and underbalanced in its horizontal section below
the packer. Gas could be pumped down one of the two
conduits with liquid down the other, both to the bit, to
drill under variably balanced conditions while providing
adequate cooling and lifting power to the bit and at the
same time a conduit carrying only liquid for acoustic
communication and hydraulic fluid.
In one methodology, with or without a packer, fluid
could be pumped down both conduits to a bottomhole
assembly where each fluid comprises either a hydraulic
operating fluid or a well treatment fluid. This
methodology would permit the mixing of chemicals downhole.
For instance, a first and second chemical might pump more
favorably unmixed, such as fracturing fluid and gel
setting chemicals and/or gel breaking chemicals, or such
as two different acids. It is sometimes advantageous to
have two different treatment fluids that are not mixed
until ready for use. Heat could be generated downhole
CA 02249432 1998-09-18
WO 97/35093 PCTNS97/03563
- 17 -
more safely by the mixture there of two chemicals.
Combustion downhole might be controlled by a controlled
supply of oxygen. Two different tools could be
hydraulically operated, each having their own independent
hydraulic pressure and flow rate controlled at surface, as
a hydraulically operated bit and a hydraulically operated
orienting tool, or a hydraulically operated bit and a
hydraulic jetting tool. One conduit could contain
hydraulic fluid for operating a rotary cleaning jet while
the other conduit contained a fluid, such as an acid
fluid, for selectively dispensing out the rotating jets.
Hydraulic fluid down one conduit could operate a pump
while a treating or jetting fluid could be administered
through the other conduit. In one embodiment a rotating
jet cleaning tool could be operated together with a sand
vacuuming tool. Many such tools could be computer
controlled through real time feed back data.
In another methodology the outer conduit could be
used to provide thermal insulation for fluid in the inner
conduit. For example, viscous oil could be produced
through the inner conduit while thermal insulation could
be provided by a fluid, such as a gas, air, a gel or other
insulation material in the outer conduit. For the
purposes of the present disclosure a vacuum should be
considered as a "gas" fluid, as it represents a limiting
condition for the presence of a gas. Such insulating
fluid could keep the oil temperature up and thus the oil
viscosity down so that the oil could be more readily
brought to surface.
One utilization of the present invention includes a
methodology in which the bottomhole assembly comprises at
least a pair of valued producing/treating tools separated
by a bottomhole assembly spacer. Wellbore fluid could be
produced from two different locations, each up a different
conduit. The embodiment could be operated with or without
packers. Advantageously the two producing tools could be
separated by a packer in order to test alternative
producing zones.
A surface computer system could be advantageously
employed to recover and analyze data in real-time in order
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 18 -
to calculate reservoir parameters. The same surface
computer system could be used to control all downhole tool
valves for the movement of all fluids and gases. The
apparatus and method advantageously includes capability
for remote data transmission from the well site to another
location.
The present invention also includes optimal methods
for assembling coiled-in-coiled tubing. These methodolo-
gies include extending a first length of coiled tubing
essentially horizontally. A second inner coiled tubing
length could then be pumped through the first coiled
tubing length and/or pulled through the first coiled
tubing length, by means of a cable, and/or injected
through the first coiled tubing length by means of a
coiled tubing injector. Any combination of pumping,
pulling and injecting, together with lubricating between
the coils, could be used simultaneously or sequentially to
accomplish the assembling of coiled-in-coiled tubing.
BRIEF DESCRIPTION OF THE DRAWINGS
A better understanding of the present invention can
be obtained when the following detailed description of the
preferred embodiment is considered in conjunction with the
following drawings, in which:
Figure 1 illustrates typical equipment used to
inject coiled tubing into a well.
Figures 2A, 2B and 2C illustrate a working reel for
coiled tubing with plumbing and fittings capable of
supporting an inner coil with an outer coil.
Figure 3 illustrates in cross-section an embodiment
for separating or splitting inner and outer fluid
communication channels into side-by-side fluid
communication channels.
Figure 4 illustrates in cross-section an inner and
an outer coiled tubing section having a wireline within.
Figures 5 and 5A illustrate an embodiment of a
downhole device or tool, adapted for attachment to coiled-
in-coiled tubing, and useful for controlling fluid flow
between a wellbore and an inner coiled tubing string as
well as between the wellbore and an annular region between
inner and outer coiled tubing strings, and also useful for
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 19 -
controlling fluid flow between the inner coiled tubing
string and the annular region.
Figure 6 illustrates helixing of an inner coil
within an outer coil in "multicentric" coiled-in-coiled
tubing.
Figure 7 illustrates an injection technique for
injecting an inner coil within an outer coil to produce
"multicentric" coiled-in-coiled tubing.
Figure 8 illustrates a method of assembling
"multicentric" coiled-in-coiled tubing.
Fig. 9 illustrates coiled-in-coiled tubing having
wireline within the inner tubing and the inner tubing
helixed within the outer tubing.
Fig. 10 illustrates coiled-in-coiled tubing having
an inner tubing centralized within an outer tubing and
having a wireline extending in the annulus between the
inner and outer tubing.
Fig. 11 illustrates schematically a bottomhole
assembly package.
Fig. 12 illustrates a bottomhole assembly including
an assembly unit where a packer might be carried.
Fig. 13 illustrates coiled-in-coiled tubing attached
to a bottomhole assembly located downhole in a wellbore
having a packer sealing a wellbore annulus at the build
section and providing for reciprocation of the tubing
within the packer.
Fig. 14 illustrates a horizontal method of assembly
for coiled-in-coiled tubing.
Fig. 15 illustrates the use of computer control with
coiled-in-coiled tubing and a bottomhole assembly.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
Figure 1 illustrates a typical rigup for running
coiled tubing. This rigup is known generally in the art.
In this rigup truck 12 carries behind its cab a power pack
including a hook-up to the truck motor or power take off,
a hydraulic pump and an air compressor. The coiled tubing
injecting operation can be run from control cab 16 located
at the rear of truck 12. Control cab 16 comprises the
operational center. Work reel 14 comprises the spool that
carries the coiled tubing at the job site. Spool or reel
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 20 -
14 must be limited in its outside or drum or spool
diameter so that, with a full load of coiled tubing wound
thereon, the spool can be trucked over the highways and to
a job site. A typical reel might offer a drum diameter of
ten feet. Reel 14, as more fully explained in figures 2
and 3, contains fixtures and plumbing and conduits to
permit and/or control communication between the inside of
the coiled tubing string and other instruments or tools or
containers located on the surface.
Figure 1 illustrates coiled tubing 20 injected over
gooseneck guide 22 by means of injector 24 into surface
casing 32. Injector 24 typically involves two hydraulic
motors and two counter-rotating chains by means of which
the injector grips the tubing and reels or unreels the
tubing to and from the spool. Stripper 26 packs off
between coiled tubing 20 and the wellbore. The well is
illustrated as having a typical well Christmas tree 30 and
blowout preventor 28. Crain truck 34 provides lifting
means for working at the well site.
Figures 2A, 2B and 2C illustrate side views and a
top cutaway view, respectively, of a working reel 14
fitted out for operating with coiled-in-coiled tubing.
Figure 2A offers a first side view of working reel
14. This side view illustrates in particular the plumbing
provided for the reel to manage fluid communication, as
well as electrical communication, through the inner coiled
tubing. The inner tubing is the tubing designated for
carrying the fluid whose communication should be
safeguarded, fluid that might be hazardous. The coiled-
in-coiled tubing connects with working reel 14 through
rotating connector 44 and fitting 45. Aspects of
connector 44 and fitting 45 are more particularly
illustrated in figure 3. This plumbing connection
provides a lateral conduit 62 to channel fluid from the
annular region between the two tubing lengths. Fluid
communication through lateral conduit 62 proceeds through
a central portion of reel 14 and a swivel joint on the far
side of working reel 14. These connections are more
particularly illustrated in figures 2B and 2C, discussed
below. Fluid from inside the inner coiled tubing, as well
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 21 -
as wireline 66, communicate through high pressure split
channel valve fixture 45 and into high pressure piping 46.
High pressure channel splitter 45 as well as high pressure
piping 46 are suitable for H2S service and rotate with
S reel 14. Lateral conduit 62 also rotates with reel 14.
Wireline telemetry cable 66, which connects to service
downhole tools and provide real time monitoring,
controlling and data collecting, passes out of high
pressure piping 46 at connector 47. Telemetry line 66,
which may be a multiple line, connects with a swivel joint
wireline connector 42 in a manner known in the industry.
Swivel pipe joint 50 provides a fluid connection
between the high pressure non-rotating plumbing and
fittings connected to the axis of working reel 14 and the
rotating high pressure plumbing attached to the rotating
portions of the drum, which are attached in turn to the
coiled tubing on the reel. High pressure conduit 52
connects to swivel joint 50 and comprises a non-rotating
plumbing connection for fluid communication with the inner
coiled tubing. Valuing can be provided in the rotating
and/or non-rotating conduits as desired or appropriate.
Conduit 52 can lead to testing and collecting equipment
upon the surface related to fluid transmitted through the
inner coiled tubing.
Figure 2B offers a side view of the other side of
working reel 14 from that shown in figure 2A. Figure 2B
illustrates plumbing applicable to the annular region
between the two coils of the coiled-in-coiled tubing.
Conduit 58 comprises a rotating pipe connecting with the
other side of reel 14 and conduit 61 providing fluid
communication through a central section 60 of the reel.
Conduit or piping 58 rotates with the reel. Swivel joint
54 connects non-rotating pipe section 56 with rotating
pipe 58 and provides for fluid communication with the
annular region for fixed piping or conduit 56 at the
surface. Piping 56 may be provided with suitable valuing
for controlling communication from the annular region
between the two coiled tubing strings with appropriate
surface equipment. Such surface equipment could comprise
a source of fluid or pressurized fluid 76, indicated
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 22 -
schematically. Such fluid could comprise gas, such as
nitrogen, or water or drilling mud or some combination
thereof. Monitoring means 78, also illustrated
schematically, may be provided to monitor fluid within the
annular region between the inner and outer coiled tubing.
Monitoring equipment 78 might monitor the composition
and/or the pressure of such fluid in the annular region,
for example.
Figure 2C illustrates a top cutaway view of working
reel 14. Figure 2C illustrates spool diameter 74 of
working reel 14. Spool surface 75 comprises the surface
upon which the coiled-in-coiled tubing is wound. Surface
75 is the surface from which the tubing is reeled and to
which it is respooled. Figure 2C illustrates wireline
connector 42 connecting to wireline 66 and from which
electrical line 67 is illustrated as emerging. Wireline
66 and electrical line 67 can be complex multi-stranded
lines. Dashed line 72 illustrates the axial center of
working reel 14, the axis around which working reel 14
rotates. The right side of figure 2C illustrates rotating
plumbing or conduit 58 and non-rotating plumbing or
conduit 56, both illustrated in figure 2B. They provide
for fluid communication at the surface with the annular
region between the coiled tubing strings. Conduit 61
communicates through channel 60 in working reel 14 to
connect conduit 58 with lateral 62 on the far side of
working reel 14. Conduit 61 and channel 60 rotate with
the rotation of the drum of working reel 14. The left
side of figure 2C illustrates rotating pipe 46 and non-
rotating pipe or conduit 52. As discussed in connection
with figure 2A, these sections of pipe or conduit provide
for fluid communication between the inner coiled tubing
string and surface equipment, if desired.
Split channel plumbing 45 providing lateral 62 is
illustrated in cross-section more particularly in Figure
3. Wireline 66 is shown entering plumbing fixture 45 from
the left side and emerging on the right side in fluid
communication channel 83. Channel 83 is in communication
with the inside of the inner tubing string. Bushing 49
anchors inner tubing 102 within plumbing fixture 45.
CA 02249432 1998-09-18
WO 97135093 PCT/US97/03563
- 23 -
Packing and sealing means 51 prevents communication
between the annular area 80, defined between outer tubing
100 and inner tubing 102, and fluid communication channel
83. Fitting 44 anchors outer coiled tubing 100 to fixture
45.
Figure 4 illustrates in cutaway section components
of coiled-in-coiled tubing. Figure 4 illustrates cable or
wireline 66 contained within inner tubing 102 contained in
turn within outer tubing 100. Cable 66 could comprise
fiber optic cable for some applications. Channel 82
identifies the channel of fluid communication within inner
tubing 102. Annular area 80 identifies an annular region
between tubings, providing for fluid communication between
inner tubing 102 and outer tubing 100 if desired. A
typical width for inner tubing 102 is .095 inches. A
typical width for outer tubing 100 is .125 inches.
Figure 5 illustrates an embodiment, schematically,
of a downhole tool usable with coiled-in-coiled tubing,
and in particular useful for drill stem testing. Tool or
device 112 is attached by means of slip connector 116 to
the outside of outer tubing 100. Tool 112 is shown
situated in region 106 defined by borehole 120 in
formation 104. Packers 108 and 110 are shown packing off
between tool 112 and borehole 120 in formation 104. If
formation 104 is capable of producing fluids, they will be
produced through wellbore 120 in the zone defined between
upper packer 110 and lower packer 108. Tool bull nose 118
lies below lower packer 108.
Indicated region 122 in tool 112 refers to a general
packer and tool spacer area typically incorporated within
a device 112. Spacers are added to adjust the length of
the tool. Provision may be made in this space, as is
known in the art, to collect downhole samples for
retrieval to the surface. Indicated region 124 in tool
112 refers to a general electronic section typically
incorporated within a device 112. Anchor 114 anchors
inner coiled tubing 102 within outer coiled tubing 100 at
device 112 while continuing to provide means for fluid
communication between annular region 80 between the two
tubing lengths and portions of tool 112.
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 24 -
Valuing provided by the tool is indicated
stylistically in Figure 5. Valve 130 performs the
function of a circulation valve, permitting circulation
between annular region 80 between the coils and fluid
communication channel 82 within inner coiled tubing 102.
Valve 130 could be used to circulate fluid down annular
region 80 and up inner tubing channel 82, or vice versa.
Wireline 66 would commonly terminate at a wireline
termination fitting, illustrated as fitting 69 in tool
112. Valve 132 indicates valuing to permit fluid
communication between inner channel 82 and the borehole
above upper packer 110. Valve 134 permits well fluids
from formation 104 within borehole annular region 106 to
enter into downhole tool 112 between upper packer 110 and
lower packer 108 and from thence into inner tubing conduit
82. Valve 136 indicates an equalizing valve typically
provided with a tool 112. Valve 131 provides for the
inflation of packers 110 and 108 by fluid from annular
regions 80. Valve 133 is available for injecting fluids
from annular region 80 into the formation, for purposes
such as to stimulate formation 104. Connector 105 between
the tubing and downhole tool could contain an emergency
release mechanism 103 associated therewith, as is known in
the art. Valve 138 provides for deflating packers 108 and
110.
Figure 6 illustrates a helixed inner coil 102 within
an outer coil 100 forming "multicentric" coiled-in-coiled
tubing 21, shown strung in well 120 through formation 104.
It is believed that when hung in a vertical well a coiled
tubing, such as outer coil 100, would not hang completely
straight. However, the weight of the coil would insure
that outer coil 100 hung almost straight. Cap 150 is
shown attached to the distal end of outer coil 100,
downhole in well 120. Inner coil 102 is illustrated as
helixed within outer coil 100. This helixing provides a
lack of concentricity, or coaxiality, and is intentional.
The intentional helixing provides a multicentricity for
the tubes, as opposed to concentricity or coaxiality. The
helixing can be affected between an inner coil 102 and an
outer coil 100 and is believed will not always take the
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 25 -
same direction. That is, the helixing might alternate
between clockwise and counterclockwise directions. Inner
coil 102 is illustrated in figure 6 as having its weight
landed upon bottom cap 150 attached to outer coil 100. In
this fashion, the weight of inner coil 102 is being borne
by outer coil 100, illustrated as hung by a coiled tubing
injector mechanism 24. Alternately, the weight of inner
coil 102 could be landed on the bottom of well 120, or cap
150 could sit on the bottom of well 120, thereby relieving
outer coil 100 of bearing the weight of inner coil 102.
Figure 7 illustrates inner coiled tubing 102 spooled
from spool 152 over gooseneck 154 and through inner coiled
tubing injector 156 into outer coiled tubing 100. Outer
coiled tubing 100 is illustrated as hung by coiled tubing
injector 24 into well 120 in formation 104.
Figures 8A through 8F illustrate a method for
assembling multicentric coiled-in-coiled tubing 21 on reel
14, as illustrated in figure 8G. Figure 8A illustrates
spool 152 holding inner coiled tubing 102 sitting beside
well 120. With spool 152 is inner coiled tubing injector
156 and inner coiled tubing gooseneck support 154. Also
at well site 120 is outer coiled tubing spool 158, outer
coiled tubing injector 162 and outer coiled tubing
gooseneck 160. Figure 8B illustrates outer coil 100 being
injected by coiled tubing injector 162 into well 120 from
spool 158 and passing of a gooseneck 160. Figure 8C
illustrates outer coiled tubing 100 hung by outer coiled
tubing injector 162 over well 120. Gooseneck 160 and
spool 158 have been removed. Outer coiled tubing 100 is
shown having cap 150 affixed to its distal or downhole
end. Figure 8D illustrates inner coiled tubing 102,
injected and helixed into outer coil 100 hung in well 120.
Inner coil 102 is injected from spool 152 over gooseneck
154 and by injector 156. The bottom of inner coil 102 is
shown resting upon cap 150 at the downhole end of outer
coil 100, hung in well 120 by outer coil injector 162.
Figure 8E illustrates inner coil 102 being allowed to
relax and to sink, to helix and to spiral further, inside
outer coiled tubing 100 hung by injector 162 in well 120.
Figure eF illustrates respooling coiled-in-coiled tubing
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 26 -
21 onto working reel 14 using outer coiled tubing injector
162 and outer coiled tubing gooseneck 160. Outer tubing
100 has been connected to reel 14. If separate means for
hanging outer tubing 100 are provided, the operation can
be carried out with one coiled tubing injector and one
gooseneck.
In operation, the safeguarded method of the present
invention for the communication of fluid from within a
well is practiced with coiled tubing carried on a spool.
The method is practiced by attaching a distal end of
coiled-in-coiled tubing from a spool to a device for
controlling fluid communication. The device, a
specialized tool for the purpose, will be inserted into a
well. (The safeguarded method for fluid communication
would also, of course, be effective on the surface.
Safeguarded communication from within a well offers the
difficult problem to solve.)
Coiled-in-coiled tubing comprises a first coiled
tubing length situated within a second coiled tubing
length. A first channel for fluid communication is
defined by the inside tubing length. The device or tool
attached at the distal end of the coiled-in-coiled tubing
controls fluid communication through this first inner
communication channel. The device may also control some
fluid communication possibilities through an annular
region as well. An annular region is defined between the
first inner coiled tubing length and the second outer
coiled tubing length. Fluid communication is also to be
controlled, at least to a limited extent, within this
annular region. At the least, such control should extend
to sealing off the annular region to provide the margin of
safety in the case of leaks in the inner tubing.
Preferably, such control would include a capacity to
monitor the fluid status, such as fluid composition and/or
fluid pressure, within such region, for leaks. Preferably
such control would include a capacity to pressurize a
selected fluid within the annular region, to more speedily
detect leaks. In preferred embodiments, the annular
region may also function as a second fluid communication
channel.
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 27 -
The coiled-in-coiled tubing is injected from a spool
into the well. Primary fluid is communicated through the
inside tubing length from the well to the spool. Of
course, fluid could also be communicated in a safeguarded
manner from the spool to the well, if such need arose.
The primary fluid may remain contained within the inside
tubing length, as in a closed chamber, to minimize risk.
Alternately the fluid may be communicated from the inside
tubing length through a swivel joint located upon the
spool to other equipment and/or surface containers. The
coiled-in-coiled tubing is eventually respooled.
The device for controlling fluid communication
through the inside tubing length usually comprises a
specialized tool developed for multiple purposes, fitted
to operate in conjunction with coiled-in-coiled tubing.
The tool may communicate electronically through a
wireline, probably multistrand, run through the inside
tubing. The tool may also collect one or more samples of
fluid and physically carry the samples upon respooling, to
the surface. The tool may further contain means for
measuring pressure.
The annular region between the inside and the
outside coiled tubing provides the safeguard, the
secondary protective barrier in case of leaks in the
inside tubing, for the present method for fluid
communication. For that reason, as mentioned above, fluid
in the annular region should at least be controlled in the
sense that control comprises sealing off the annular
region. As discussed above, preferably, the control
includes monitoring fluid status within the annular
region, such as fluid composition and/or fluid pressure,
and may include supplying pressurized fluid to the annular
region, such as pressurized water, inert gas or nitrogen,
drilling mud, or any combination thereof. The pressure of
such monitoring fluid can be monitored to indicate leaks
in either of the coiled tubing walls. Overpressuring the
annular region would ensure that a leak in either the
inner tubing wall or the outer tubing wall would result in
annular fluid evacuating the annular region and invading
the inner tubing string or the outside of the coiled-in-
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 28 -
coiled tubing. Such overpressurization in particular
guards against potentially hazardous fluid from inside the
inner tubing ever entering the annular region.
Upon the indication of a leak in either coiled
tubing wall, the primary fluid communication in the inner
tubing could be terminated. The well may also be shut in
by closing the valve and/or the well may be killed by
deflating the packers. A blowout preventor (BOP) could be
activated, if necessary.
The present safeguarded method for fluid
communication is applicable to work within a wellbore as
well as in a cased well or well tubing. Such wellbore,
cased well or well tubing may itself be filled with fluid,
such as static drilling fluid.
The device or tool for controlling fluid
communication from the well frequently includes a packer
or packers for isolating a zone of interest. The annular
region between the tubing walls can be used as a fluid
communication channel for supplying fluid to inflate the
packers. The annular region could also be used as a fluid
communication channel for supplying a stimulating fluid,
such as acid, or a lifting fluid such as nitrogen,
downhole to the well.
The coiled-in-coiled tubing is attached at the
surface to a working reel or spool. The spool for coiled
in-coiled tubing will contain means for splitting the
fluid communication channel originally from within the
inner coiled tubing from the potential communication
channel defined by the annular region between the coiled
tubing lengths. Generally speaking, the inside length
also should be no longer than 1% of the outside length.
One aspect of the present invention provides
improved apparatus for practicing above the method, the
improved apparatus comprising "multicentric" coiled-in
coiled tubing. Such multicentric coiled-in-coiled tubing
includes several hundred feet of continuous thrustable
tubing, coiled on a truckable spool. The tubing includes
a first length of coiled tubing of at least 1/2 inch
outside diameter helixed within a second length of coiled
tubing. Generally speaking, taking into account the
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 29 -
variations possible between OD's of inside and outside
tubing and wall thickness, when measured coextensively the
first inside length would be at least .Olo longer than the
second outside length. Generally speaking, the inside
S length also should be no longer than 1% of the outside
length. (It is of course clear, that either the inside
length or the outside length could be extended beyond the
other at either the spool end or at the downhole end.
"Measuring coextensively" is used to indicate that such
extension of one length beyond the other at either end is
not intended to be taken into account when comparing
lengths.)
When coiled-in-coiled tubing is spooled, it is
believed that the inner length, to the extent it overcomes
friction, would tend to spool at the maximum possible
spool diameter. That is, the inner length would tend to
spool against the outer inside surface of the outer
length. Such tendency, if achieved, would result in a
significantly longer length for the inside tubing versus
the outside tubing. The difference in length is
significant because the present inventors anticipate that
if the coiled-in-coiled tubing were allowed to assume this
maximum spool diameter position on the spool and the ends
were fixed to each other, then when straightened, the
inner tubing would tend to fail or buckle within the outer
tubing.
"Concentric" or "coaxial" tubing comprises, of
course, strands of the same length. Centralizers could be
used to maintain an inner tubing concentric or coaxial
within an outer tubing on a spool. Alternately, an inner
tubing could be inserted coaxially in a straightened
position within an outer tubing, and the two ends of the
two tubings could then be affixed together to prevent
retreat of the inner tubing within the outer tubing upon
spooling. For instance, an inner coiled tube could be
injected within an outer coiled tube hung in a vertical
well, possibly using means to minimize friction there
between, such that, measured coextensively, the lengths of
both coils would tend to hang straight and be very close
to the same length. The inner coil would not be helixed
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 30 -
within the outer coil. To help straighten out any
undesired helixing, the inner coil could latch on to a cap
attached to the bottom of the hung outer coil. The weight
of the outer coil could then be picked up and carried by
the inner coil if the inner coil were lifted subsequent to
latching onto the end cap. So lifting the inner coil,
bearing not only its own weight but part or all of the
weight of the outer coil would help straighten the inner
coil out within the outer coil and align the two coils.
This solution, "coaxial" or "concentric" coils is believed
not to be optimal. Coaxiality might result in an
unacceptable level of compression and/or tension being
placed upon on portions of one and/or the other length
while resting on the spool.
I5 It is proposed by the present inventors that the
"multicentric" coiled-in-coiled tubing disclosed herein
best solves the above problems without involving the
complexity of centralizers. Helixing the inner coil
within the outer coil provides an advantageous amount of
frictional contact between the two coils, frictional
contact that is dispersed relatively uniformly.
Furthermore, the inner coil has a certain amount of
flexibility in which to adjust its configuration
longitudinally upon spooling in and out. The helixed
inner coil should not buckle or fail upon respooling and
spooling. The frictional contact is sufficient between
the helixed inner coil and outer coil that unacceptably
high areas of compression or tension between the two coils
are not created while on the spool. The helixed inner
coil, under certain circumstances, may even enhance the
structural strength of the coiled-in-coiled tubing as a
whole.
Fig. 9 illustrates an embodiment for coiled-in
coiled tubing wherein an inner coil is helixed within an
outer coil and a wireline cable or fibre optic cable or
braided cable, or the like, is included within the conduit
provided by the inner coil. Fig. 10, in contrast,
illustrates a concentric coil-in-coil arrangement. In
Fig. 10, centralizer CN maintains inner coil tubing ICT,
defining a first conduit IC, centralized within outer
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 31 -
coiled tubing OCT. A second annular fluid conduit AC is
defined in the annulus between inner coil ICT and outer
coil OCT. Fig. 10 illustrates wireline W located in the
annular conduit AC.
Fig. 11 illustrates schematically a bottomhole
assembly package BHA comprised of multiple units. Coiled-
in-coiled tubing CNCT having wireline W located inside the
inner coil is shown affixed to unit U1. Unit U1 may be a
sub, preferably a multi-purpose coiled-in-coiled tubing
head for connecting to a bottomhole assembly package such
that both conduits IC and AC are in fluid communication
with package BHA.
In bottomhole assembly BHA, each unit, U2 - U8,
could indicate a different tool or measuring instrument or
packer or spacer. Bottomhole assembly BHA. is shown with
the tools and/or instruments mated together and in
preparation for mating its upper end with the coiled-in-
coiled tubing head. Units U1 through Ue would be provided
for mating such that fluid communication is continued
through most, if not all, units with both the first
conduit IC and the second conduit AC, as well as with wire
line W.
Fig. 12 illustrates that a packer might well be
carried in an early unit, such as Unit U2. Fig. 13
illustrates packer PK set in a build section of a bore
hole. One of the conduits defined by the coiled-in-coiled
tubing could be used to supply fluid to set the packer, as
well as to assist in deflation or unsetting. Packer PK is
illustrated as having an inner sleeve through which the
tubing CNCT sealingly reciprocates. Analogous packers
have been taught and could be adapted to work with coiled
tubing.
Fig. 14 illustrates alternate methods for the
construction of coiled-in-coiled tubing. For illustrative
purposes, Fig. 14 illustrates outer coiled tubing OCT
extended essentially horizontally. Inner coil tubing ICT
is illustrates as being simultaneously pulled through
outer coil OCT by cable CB. Inner coil ICT is also being
thrust into outer coil OCT by a coil tubing injector,
illustrated schematically as CTI. In addition, inner coil
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 32 -
ICT is illustrated as connected at its distal end with a
plug PL. Pump P is illustrated as pumping fluid in the
annulus between outer coil OCT and inner coil ICT thereby
pressuring plug PL to pump inner coil ICT through outer
coil OCT.
Fig. 15 illustrates the use of computer control for
monitoring and operating complex operations such as
alternating testing, treating and testing. Computer CPU
is illustrated in electrical connection through line L
with the wire line WL that extends through the coiled-in-
coiled tubing CNCT and into and through connectors located
in the working reel or spool R/S. Computer CPU can
collect real time data through wireline communication as
well as control downhole tools such as the setting and
deflating of packers, the opening and closing of valves,
the operating of drills and orienting tools and jetting
tools and pumping tools and motors.
EXAMPLE: TEST, TREAT, TEST SYSTEM
The flow testing of oil and gas reservoirs is a
critical operation used by operators in both openhole and
cased hole applications. The information gained from
openhole Drill Stem Tests (DST), permeability, flow rates,
skin damage and water production is used to confirm well
deliverability and justifies casing the well. Alternately
many wells are production tested after being cased to
gather additional well information establishing reservoir
limits and the presence of wellbore skin damage. In wells
with large pay zones (horizontal), production tests are
often used to selectively determine the source of well
production, hydrocarbon or water, to allow remedial
workovers.
Although well testing is common in nearly all
reservoirs, the testing of sour gas wells and horizontal
wells is still a significant challenge for operators and
service companies alike. The testing of sour wells has
been very limited due to the concerns of H2S embrittlement
of drillpipe and overall wellsite safety as sour gas is
produced to surface. In most cases, without DST data,
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 33 -
operators must rely on limited geological and openhole log
evaluation to establish well deliverability allowing
justification to case the well. In horizontal wells the
challenge is to selectively test the horizontal section in
the well and use this information to implement remedial
stimulation to improve production.
The new technology of the current example uses an
inflatable straddle packer tool deployed into vertical or
horizontal wells using a "Coil-in-Coil" coiled tubing
string configuration. An electrical conductor is located
inside the inner string which allows for "real time"
formation, evaluation and tool operation. The inner coil
string is used for all well flow and stimulation
operations, with the coil-in-coil annulus utilized for
circulation operations and packer element inflation. More
importantly, the outside string also provides for pressure
monitoring, flow containment and well control in the
unlikely event of a failure of the inner string.
This is in contrast to the testing of wells that has
been part of the oil and gas business since the first oil
wells were drilled many years ago. Historically, after
drilling a well to the target formation, many operators
will undertake a flow test of the formation of interest
using DST tools run back into the well on the drillpipe.
This drillpipe, often empty, is positioned over the zone
of interest and then the packer elements are expanded
through pipe rotation or setdown weight . A valve in the
DST tool is opened allowing formation fluids to enter the
evacuated drillpipe, and if adequate bottom hole pressure
(BHP) and flow capacity is present, this results in well
production to surface. If, however, the BHP is not
sufficient, the well will continue to flow into the
drillpipe until its hydrostatic pressure equals the
reservoir pressure. The tools are then closed and
recovered from the well and the produced fluid is measured
and analyzed. In the early years of DST use, only well
flow data was available. This information, combined with
openhole logs, was valuable in the confirmation that well
potential was sufficient to warrant casing the well and
pursuing a completion. Later advancements in the
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 34 -
understanding of well flow and reservoir deliverability
resulted in the use of downhole pressure recorders and
pressure transient analysis to obtain information on
formation permeability, wellbore skin damage and DST tool
performance. Some of today's DST tools use data
transmission technology to enable the recovery of the
pressure drawdown and build-up data during the test,
allowing optimization of well flow and buildup durations.
The value of the DST data can not be understated as a
means of gathering critical well information prior to
committing to the cost of casing and completing wells
whose deliverability might be marginal.
Unfortunately the development of sour gas and oil
formations and the recent growth of horizontal drilling
have presented significant challenges for the use of
conventional DST tools. Sour wells are presently drill
stem tested in very limited applications due to safety
concerns and the overall cost. During the testing of a
sour well, the drillpipe is exposed to HZS in the produced
oil or gas. Since most drillpipe is made of high tensile
strength steel with a Rockwell Hardness in excess of 22Rc,
the drillpipe is susceptible to HAS embrittlement. As a
result, most operators will not use the drillpipe for sour
flow tests but will stand back or lay down the drillpipe
and pick-up a new string of sour service tubing to conduct
the DST operation. After the testing operations are
completed, the tubing is laid back down and the drillpipe
used to either abandon the well or condition the hole for
casing operations.
DST data is important in all well evaluations but
especially so in the case of carbonate reservoirs since
openhole log information may not adequately address the
question of well deliverability with the same degree of
confidence available on similar logs for sandstone
reservoirs. Consequently, the operator is very interested
in any additional information on well deliverability,
reservoir pressure and wellbore skin damage that will give
the operator confidence in the decision to case or abandon
the well. The decision to run casing and then
subsequently complete the well will cost the operator in
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 35 -
the order of CS 400k-60ok based on a typical 11, 500 foot
(3,500m) sour gas well. However, the decision to abandon
the well and bypass a significant find has a more serious
impact on future profitability.
Another limitation of current DST tool technology is
the ability to quickly evaluate multiple zones in a well
and to recover test fluids from each test. In a
conventional subhydrostatic DST with drillpipe, formation
fluid is recovered into the drillpipe. To analyze this
fluid for water, drilling filtrate and hydrocarbon
requires the retrieval of the DST tools to surface. In
addition, although real-time data transmission is
available via Wet-Connect and Electro-Magnetic systems,
both have their challenges at present. With the Wet-
Connect system, every time one needs to reset the tools
across a new pay zone the wire/wet connect needs to be
pulled. Once the tools are across the new pay zone,
wireline needs to be run in the hole (RIH) to the wet
connector and re-establish electrical connection. With
the EM system, depth and geology are its main limitations.
Horizontal Wells
Horizontal wells present a similar challenge for
existing well testing tools although the requirement is
not to obtain data to support a "run casing - don't run
casing" decision but to obtain well flow and pressure
transient data to allow for maximizing well production and
recoverable reserves. Horizontal drilling has developed
as a cost effective technology to enhance well production
in existing pressure depleted fields or tight low
deliverability reservoirs. Unfortunately, although most
horizontal wells result in increased well production, both
hydrocarbon and water, the operator has limited resources
to confirm from where along the extensive openhole section
the respective well flows originate.
Many of the most successful horizontal wells are in
heterogeneous reservoirs where formation geology varies
significantly resulting in bypassed production when using
vertical well development. In most horizontal wells, the
openhole section is extensive in length with numerous
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 36 -
changes in well porosity and permeability along the
openhole length. Consequently well deliverability varies
considerably both in hydrocarbon and water production. In
vertical wells, current openhole and cased hole logging
tools can be used to confirm well deliverabiltiy based on
previous well experience. Unfortunately the use of these
same tools in horizontal wells is not as effective.
Similarly the use of production logging tools, although
successful in vertical wells, is very limited in
horizontal wells due to openhole conditions, openhole
length, stratified flow, subhydrostatic reservoirs and
cost.
The most viable technology presently for use in
testing horizontal wells in Canada has been the use of
inflatable straddle packers run into the well on jointed
tubing and set across a selected area of the openhole.
Pressure recorders are located in the BHA and the well is
swabbed in to obtain inflow data specific to the test zone
after which the well is shut-in at surface for the
pressure build-up. The straddle packer assembly is then
pulled out of hole (POOH) and the recorded pressure and
recovered fluids analyzed to predict wellbore skin and
assess production data. If skin is evident, a decision is
made to undertake a selective stimulation which would
require running back into the well and resetting the
packers across the production zone of interest. After
stimulation/evaluation process must be repeated multiple
times to cover a 3,000 foot (900m) openhole section.
Obviously this procedure is both time consuming, expensive
and will produce data of limited quality.
In both sour well development and horizontal well
development, there is a need for a downhole tool design
and deployment system that will allow for the straddle
packer testing of multiple zones, the recovery of
reservoir fluid sample without the need to POOH and real-
time pressure transient data. The design should also
allow for the stimulation or flow modification of the
specific evaluation zone based on the real-time evaluation
of the flow composition, rate and pressure transient data
without having to remove the toolstring.
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 37 -
While the previous discussion reviewed the
limitations of current technologies to satisfy the
evaluation / stimulation / evaluation requirements of
DST's for vertical sweet and sour oil and gas wells and
similar service operations for horizontal wells, the
following discussion reviews the operational features of
the optimum test system and the benefits of these features
for actual operations.
For Sour Production Flow Capabilities, the system
must be capable of continuous exposure to significant acid
gas conditions without concern for axial load conditions.
The minimum number of connections and a means of
monitoring the condition of the string would be a plus.
For Real-Time Data Recovery And Tool Control, the
recovery of data by a real-time system is critical to
optimizing both flow and pressure build-up durations as
well as optimizing stimulation or flow profile
modification treatments. The pressure buildup data must
be of sufficient length and sensitivity for pressure
transient analysis o~ wellbore permeability and skin. The
optimum system would consist of wireline telemetry (higher
data transfer than other present systems? that allowed for
continuous surface readouts and downhole tool operation
without pipe movement.
For Sample Recovery To Surface, in both vertical
and horizontal wells, there is a need to recover
bottomhole samples to surface during the test if the
well's HHP is inadequate to support continuous flow. In
some cases, it would be advantageous if the fluid could be
recovered during the test while the well was shut-in at
the formation face for build-up.
For Stimulation/Flow Profile Modification
Capabilities, in both the horizontal and vertical case,
there is benefit to undertake a formation treatment while
the tools are still set across the pretested interval.
This helps minimize packer resets and enables evaluation
during and after the stimulation is complete. Real time
read-outs during the treatment would allow one to optimize
the treatment. How better to maximize production than to
measure a wellbore skin, stimulate to remove the wellbore
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 38 -
skin, unload the treatment fluids and then re-evaluate to
confirm results all with-in the same test interval and
immediate time frame.
For Gas Flow Capabilities, minimum gas flow
capability is preferably, although not necessarily, in the
order of 2-3 MMCF/day to ensure adequate reservoir
drawdown to confirm reasonable gas flow rates at a
corresponding formation flowing pressure. In addition the
drawdown is required to allow for sufficient pressure
build-up data for the pressure transient analysis.
Minimum liquid flow capability is preferably,
although not necessarily, in the order 200 - 300 bbls/day
to again ensure adequate reservoir drawdown for
deliverability forecasts and pressure build-up analysis.
When drawing down openhole sections with large upset
tools, the ability to get stuck is greatly increased.
Work history with inflatable packers in openhole DST
situations shows that overpulls up to 20,000 pounds (8,900
daN) are sometimes required. The ability to underbalance
the inner string slightly so as to "suck" the inflatable
packer onto its mandrel would be beneficial since all
inflatable packers retain some set after their first
inflation. Also the ability to circulate from below to
disturb or dissolve debris that might have accumulated on
top of the packers while they were set would be
advantageous.
Of the 6,000 DST's carried out in Canada during
1995, over 98% were shallower than 11,500 feet (3,500m).
Straddling the right zone is crucial. Real time
gamma and CCL incorporated into the tool suite would
alleviate most concerns.
Since no openhole section is ever true, an
inflatable element is preferred to allow setting in minor
washouts. Since one of the tool's requirements is to test
multiple zones quickly, a straddle configuration is
required.
The surface equipment is very similar to a
conventional coiled tubing wireline logging operation.
Basically a standard coiled tubing unit plus one
monitoring truck gathers the downhole DST data and operate
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 39 -
the downhole electrically actuated valves. The part of
the CT surface layout that has been modified is the work
reels which have two rotating joints, one for the inner
coil and the other for the coil-in-coil annulus, plus one
standard wireline collector. This will allow continuous
logging (CCL/gamma), the ability to operate downhole
valves plus gather pressure and temperature data while
RIH/POOH and continuous circulation through either
annulus. It will also allow the system to be of a closed
loop design so that sour/hydrocarbon based fluids do not
need to be purged whenever the tools need to be RIH/POOH.
The Coiled Tubing String Configuration consists of a
2.375" (60.3mm) exterior coil with an 1.25" (31.8mm) coil
placed inside. Inside the 1.25" coil resides a 3
conductor wireline cable. All sour/corrosive fluids will
travel only through the 1.25" while fluid for inflating
the packers or gas lifting the well in will be pumped down
the coil-in-coil annulus. Pulls and pushes by the
injector head will only be subjected to the exterior coil.
With this larger size coil, good horizontal reach is
achievable, even with a heavy BHA.
The Coiled Tubing - DST Connector, due to the weight
(2,000 lbs.), OD (5 ins.) and length (+/-30 - 90ft.) of
the BHA, will be deployed in a similar manner to a
standard DST. After having been hung below the rotary
table in a set of slips, the CT injector will be swung
over the BHA and connected. This connector has built into
it a safety release, should the BHA become stuck while
downhole, plus a 3 conductor feed through. Due to the
difficulty of rotating either end of the assembly during
make-up, it latches in a similar manner to a snap tight.
The heart of the BHA consists of two microprocessors
connected through the wireline to a computer at surface.
This allows continuous two way communication with the
electronic section incorporated in the BHA. The system is
capable of full data acquisition as well as complete
control of all downhole functions.
Dual inflatable packers provide the ability to
isolate discreet segments of the wellbore during flow
tests or stimulation / flow profile modification
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 40 -
treatments. Inflation of the packers is accomplished by
applying pressure through the coil-in-coil annulus. Since
this annulus can be circulated to clean fluids (with
returns taken up the 1.25"), it eliminates the potential
plugging of inflate ports with well debris. It also
eliminates the potential of having the inner packer cavity
filled with sour, corrosive, hydrocarbon or aromatic
fluids. The pressure within the packers, as well as the
external wellbore pressure is continuously monitored
throughout the operation.
Unlike conventional inflatable packer systems where
pressure after a test can only be equalized, these packers
can be RIH and POOH in an underbalanced state (less
pressure inside than out). This keeps the packers fully
collapsed and reduces the potential for encountering
wellbore bridges while running into the well or having the
packers stuck after deflation due to accumulated debris on
top of them. It also reduces the chance of swabbing or
surging the well while POOH/RIH.
The minimum bottom hole pressures at which various
continuous production rates can be obtained in a 11,500
foot (3,500m) vertical well through the inner 1.25" string
are shown below. In the case of oil, production is aided
by nitrogen gas lift with the nitrogen being supplied down
the annulus between the inner and outer CT strings.
as ow a a o om o a ow a ea 'FTow
Pressure Pressure
BHFP WHFP
~MMSC=) (psi) (psi)
4
i ow a a
Wpa) lpsi) (psi)
CA 02249432 1998-09-18
WO 97/35093 PCTNS97/03563
- 41 -
Four (See Fig. 5A) of the downhole fluid control
valves are computer controlled, electronically actuated
valves, which have been field proven in existing Drill
Stem Testing (DST) systems. One is hydraulic. These
valves control the flow of fluids between the various
components of the system. They are detailed below:
The first valve controls the flow of fluids from the
annulus between the straddle packers and the inner coiled
tubing string. This "Flow Valve" (VI) normally controls
the flow of formation fluids from the well into the inner
coil string and is a two position (open/closed) valve. It
can also be used to inject fluids from the inner string
into the wellbore between the two packers for stimulation,
flow profile modification or circulation purposes.
The "Inflation Valve" (V2) is a three position valve
which in the "Inflation/Deflation" position allows fluid
from the coil-in-coil annulus to be pumped into the
packers for inflation purposes or to discharged this
pressure at the conclusion of a test. The "Closed"
position locks in whatever pressure (negative/positive)
that is inside the packers allowing pressure control of
the coil-in-coil annulus. In its third position,
"Circulation", fluid can be circulated between the inner
coil and coil-in-coil annulus in either direction.
The "Equalization Valve" (V3) is a two position
(open/closed) valve which allows fluid communication
between the three segregated wellbore areas that are
created when the two inflate packers are inflated. The
one above and below the straddle packers and the one
between the two packers. This helps equalize the pressure
above and between the packers before deflating them. It
also nullifies the chance of fracturing the zone of
interest while the packers are still inflating (trapping
fluid between the two packers before full expansion has
occurred).
The "Injection Valve" (V4) is a two position
(open/closed) valve which provides the ability to pump
fluids down the coil-in-coil annulus and inject them into
the wellbore annular region.
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 42 -
The "Relief Valve" (V5) is a hydraulic, shear pinned
valve that protects the packers from over inflation but
has a secondary purpose. Namely, should the electronic
signal to surface ever fail, the over pressurization of
this valve will open it up allowing the packers to
deflate.
The following pressures are monitored continuously
during all operations at a 5 second sample rate:
Surface:
1. Inner coil (closed chamber or open flow pressure
measurements).
2. Outer coil pressure.
Downhole:
1. Outside pressure between the packers (formation
pressure), two gauges.
2. Wellbore hydrostatic pressure.
3. Inflation pressure within the packers.
4. Inner coil above the flow valve (recovery pressure).
5. Coil-in-coil annulus pressure.
Downhole temperatures are also recorded
continuously. A Gamma Ray and CCL correlation log is
incorporated into the tool suite to provide well depth
control for critical testing and stimulation operations
while RIH/POOH and setting the packers.
One of the primary reasons for the development of
this system was safety, particularly in the application of
testing sour oil and gas wells. There are a number of
safety features which are inherent within the design of
this system and address safety. These include:
~ Pressure and fluid containment barriers are provided by
the coil-in-coil system. Continuous monitoring of the
outer coil's pressure allows any leak in the inner coil
to be detected immediately and testing halted.
~ Materials of Construction for Equipment: All of the
materials used in the fluid handling components of this
system are to NACE MR-175 specifications. The coiled
tubing is manufactured from an A-606 Type 4, Modified
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 43 -
metallurgy which has been used in numerous applications
in sour environments over the years. The wireline
sheath is made from Incology 825, and the downhole
tools from either 4140 carbon steel heat treated to 18-
22 Rc or from 17-4PH stainless steel heat treated to
H1150 - 1150 specifications.
~ The small volume of the inner coiled tubing string
minimizes the amount of sour fluids and hydrocarbons
contained in the test string and reduces the risk in
well control situations.
~ Retrieving the test tools with the packers in an
underbalanced pressure condition reduces the risk for
swabbing the wellbore fluids while pulling out of the
well.
~ If the BHA is stuck and conventional methods can not
free it, the BHA can be released by pressurizing up the
inner string. If electrical power has also been lost
and the valves are in the open position, tension can be
applied to the BHA to close a downhole check valve,
allowing pressurization.
~ If electrical power is lost and the packers are still
inflated, pressure can be applied down the coil-in-coil
annulus to open a deflate port. If the downhole valve
is open, an orifice downhole still allows one to
generate enough differential pressure to be generated
when pumping to open the port.
The procedures to be followed will vary depending on
the well configuration and the objectives of the
evaluation and/or stimulation program for the well. The
following procedures include the most common anticipated
situations:
Tripping BHA Into the Well for Well Evaluation
1. Inner string is air or nitrogen filled, depending on
well depth.
2. Outer string is partially or fully liquid filled,
depending upon BHP.
3. Pressures in each of the two strings may be adjusted
while running in the hole.
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 44 -
4. All downhole valves are normally closed while
running in the hole.
5. The bypass system in the tools will allow wellbore
fluids to circulate through the tool to avoid
being forced into the formation by the piston
effect, if the clearance between the wellbore and
the tool is restricted.
6. The outer string will be slightly underbalanced when
compared to the wellbore pressure while RIH to keep
the packers fully collapsed and reduce the potential
for premature setting when filter cake or tight hole
conditions are encountered.
Packer Inflation
1. The packers are inflated by opening the inflation
valve and applying pressure to the outer string
until the packer inflation pressure is 300 - 500 psi
(2,000 - 3,500kPa) above BHP.
2. The inflation valve is then closed, trapping
pressure within the packers. Additional pressure
can be added at any time by pressurizing the outer
string and opening the inflation valve.
Evaluation
The most significant aspect of this coiled tubing
delivered system is the flexibility that it provides to
the formation evaluation process. It is expected that all
operations to be conducted with this technology will
commence with an evaluation phase, which will normally
consist of at least one flow period and one build up
period.
~ The flow valve, which connects the wellbore to the
inner string, is opened electronically to allow
produced fluids to flow into the inner string. The
volume of the inner string is approximately 11.5 bbls
(I.8m') .
~ The initial (Preflow) period is usually conducted under
closed chamber conditions, providing real time two
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 45 -
phase flow rate measurements. Subsequent flow periods
may also be conducted under closed chamber conditions
when inflow rates are low, or where safety and
confidentiality are of major concern.
~ Pressure and flow rate data can be monitored
continuously in the control cab at the wellsite, or
remotely at the well operators office.
Interpretation
The value of this technology to well operators is
encompassed not only in the quality of the data that is
collected, but more importantly, in the ability to
interpret and utilize that data instantaneously to
maximize operational efficiency.
The essential ingredients for an optimized well test
interpretation with the above described system are:
~ Two phase-flow rate information on a real time basis.
~ Sample description and analysis prior to the end of the
test.
~ Reservoir parameters from the well operator. Porosity,
net pay, fluid saturations, etc.
~ Personnel on location trained in well test
interpretation.
~ Real time pressure build up data sufficient for radial
(direction perpendicular to wellbore)(or other flow
regime)analysis.
~ Flexibility to gas lift to maintain reservoir inflow
required.
~ Well test interpretation software package which
provides semi-log and log-log analysis, as well as
modeling capabilities and predictions for damage
removed productivity.
~ A communications system between the field and the well
operators head office to provide for fast decision
making capabilities.
Stimulation/Profile Modification
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 46 -
Treatment fluids will normally be pumped down the
inner string with returns taken either up the outer
coil/casing annulus or the coil-in-coil annulus. The
exhaust / intake ports of these conduits are preferably
spaced four and a half feet apart with the inner coil's
port just below the upper packer. This provides the
ability to spot the treatment fluid directly across the
majority of the interval before commencing squeeze
operations.
Produced Fluid Circulation
During the final shut in, or after the packers have
been deflated, the produced fluids within the inner string
can be circulated to surface in order to obtain samples,
and to dispose of hydrocarbons and sour fluids.
Traditional drill stem testing systems require the use of
the wellbore fluid for circulating produced fluids from
the test string, which raises well control concerns and
restricts circulation operations until after the
conclusion of the test. In addition, these systems
require that the entire test string be retrieved to
surface to reset the circulating valve after it has been
opened, since the valve cannot be closed.
The coil-in-coil string plus electronic valve
control system provides several benefits with respect to
circulation. The circulating valve can be opened and
closed an unlimited number of times, allowing circulation
of produced fluids after each test during multiple test
sequences without tripping out the hole. Fluids from the
coil-in-coil annulus are used to circulate produced fluids
from the inner string, which allows well control
capabilities to be maintained with the wellbore fluid.
The outer coiled fluid will be a clean fluid and will
provide a better interface to the produced fluids, whereas
circulation of wellbore fluids can result in ambiguity
since they are sometimes similar to the produced fluids.
Circulation can be accomplished during the final shut in
period of the test rather than utilizing operational time
CA 02249432 1998-09-18
WO 97/35093 PCT/US97/03563
- 47 -
after the conclusion of the test. It also allows samples
to be collected and analyzed several hours sooner.
Packer Deflation
The packers are deflated by opening the inflation
valve and allowing pressure to bleed back into the outer
string. By using a fluid in the outer string with Lower
density than the wellbore fluids, the packers can be
returned to a slightly underbalanced state after
deflation. This reduces the potential for having the
tools stuck in the well.
CONCLUSIONS
A new wireline controlled, concentric coiled tubing
DST system has been developed for testing, stimulation and
profile modification of sour and/or horizontal wells.
The new system has numerous user benefits as
outlined above. Namely; safety, sour service rated
equipment, circulation control, inflatable elements,
multiple sets, test-treat-test and gas lifting
capabilities, real-time surface read-out, on-site
interpretation and on-line data transmission to head
offices.
The real-time capabilities of the system will result
in the optimization of rig time. The systems flexibility
and inherent safety will also allow for faster turn
arounds of these critical operations.
The foregoing disclosure and description of the
invention are illustrative and explanatory thereof.
Various changes in the size, shape and materials as well
as the details of the illustrated construction may be made
without departing from the spirit of the invention.
