Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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UNDERBALANCED DRILLING TOOL AND METHOD
FIELD OF INVENTION
This invention relates to drilling devices and processes used in the drilling
of underground
wellbores. More specifically, the invention is concerned with the control of
fluid pressure within
a wellbore during the process of drilling a wellbore.
BACKGROUND OF THE INVENTION
During the process of "rotary" drilling a wellbore into an underground rock
formation, drilling
fluid is circulated through the drill string and the drill bit to lubricate,
cool and clean the rotating
drill bit. The drilling fluid also erodes the rock surface and flushes drilled
cuttings to surface.
Commonly, when drilling through formations containing moveable oil, gas or
water, the drilling
fluid is a water or oil-based liquid containing specific soluble and insoluble
compounds and
materials. Such drilling fluids are normally of high enough density that the
pressure of the fluid
column from the depth of the formation to surface is higher than the pressure
of the fluid in the
underground formation and this condition is called pressure "overbalance". The
advantage of
"overbalance" is to prevent excessive flow of formation fluids into the
wellbore, wherein the
excessive flow could lead to a blowout situation wherein unmanageable and
dangerous amounts
of formation fluid are released at surface while drilling.
The disadvantages of overbalance condition are, first, that drilling fluids
are pressured into the
formation which impairs the flow capability of the completed wellbore; and,
second, that the
drilling rate is reduced, which increases well cost.
In many situations, wells are drilled with pressure "underbalance" to
counteract the
disadvantages of overbalance drilling. Underbalanced drilling is typically
accomplished by
using a fluid with lower density than water or oil-based liquid to reduce the
pressure of the fluid
column. Compressed air is used as a drilling fluid in some dry or dry gas
wellbores but has the
disadvantage of fire/explosion risk and corrosion of the drill string. The use
of compressed
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hydrocarbon gas rather than air will remove the corrosion and downhole
fire/explosion risks but
surface fire/explosion risks remain. Compressed inert gas, such as nitrogen,
offsets the
fire/explosion risks and reduces corrosion but is more costly because the gas
must be either
purchased or generated on site. Also the use of inert gas can result in
release of unburned
hydrocarbon and toxic formation gases into the surface environment. Reduction
of fluid column
pressure is also achieved by compressing gases into liquid-based drilling
fluids to create misted,
foamed or gasified fluids. These drilling fluids are used commonly where
liquids are produced
by the formation.
The use of compressed gases have multiple disadvantages. Data from
conventional pressure
pulse downhole data telemetry devices, referred to as monitoring while
drilling(MWD) or
logging while drilling (LWD) tools, is lost due to the inability to transmit
and receive adequate
pressure pulses through highly compressible fluids. Vibrations created by
multiphase fluid
through downhole devices cause damage to the downhole data sensors and
transmitters. While
connecting or disconnecting drill string components, the compressed fluids in
the drill string
must be allowed to vent. Backflow prevention devices installed in the drill
string, will usually
eliminate the use of electronic data transmission cables. Rapid decompression
of gases through
the drill bit and downhole fluid-powered drilling-motors results in damage to
those components
and also leads to local cooling at the formation face which may result in
precipitation of paraffin
or other plugging solids. The combination of erosive fluid velocities,
irregular pressure cycles
and very low backpressure on the wellbore walls often results in instability
of the wellbore walls
or collapse thereof. The use of compressed gas in combination with liquids
creates a technical
challenge in accurately estimating fluid column pressure, and as a result, the
condition of
pressure underbalance is sometimes not achieved.
Prior art for underbalanced drilling also includes the use of parasite pipe
and concentric casing
flow paths to enable continuous injection of compressed gas in the upper
portion of the return
circulation flow path at a sufficient depth that the reduced fluid column
pressure creates a
condition of pressure underbalance. The additional disadvantage of using
compressed gas in this
system is the expense of installing the extra flow paths.
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The decompression of large volumes of gas within the circulated fluids
returning to surface
creates a hostile environment which must be controlled and monitored within
large multiphase
pressure vessels. Highly gasified compression and control lines contain high
energy and are very
dangerous when ruptured accidentally or by erosion/corrosion. Self energizing
elastomer seals
are installed at the wellhead to divert return wellbore flow for low pressure
underbalanced
drilling operations. Energized blow out preventers or extra bag type blow out
preventers are
installed at the wellhead to divert flow for higher pressure and toxic gas
operations.
Prior art for underbalanced drilling also includes the use of hollow
microspheres which are lower
in density than water. The method has been field tested and disadvantages
include the cost of the
material, loss of the material through solids disposal equipment normally used
in rotary drilling,
and a tendency to float. The method is applied more to zero underbalance
drilling, often referred
to as "on balance drilling".
Although underbalanced drilling is common, any decrease in the pressure
overbalance created by
a full column of drilling fluid will create an increase in drilling
penetration rates. Therefore, any
of the methods used for reduction of fluid column pressure may be used to
increase drill rate
alone without necessarily creating a condition of pressure underbalance.
Jet pumps have been patented to set up pressure differentials along the
wellbore. In particular,
jet pumps have been patented for annular restriction devices to create reduced
pressure at the bit.
One such jet pump configuration is disclosed in U.S. Patent no. 4,534,426 of
Hooper. This
patent discloses a "Big Hole" shaft drilling method for creating boreholes of
very large diameter.
Big Hole drilling is used in construction applications for drilling of shafts
of diameter from 36
inches to 180 inches. Big Holes are drilled using cutting structures on frames
which differ
dramatically from conventional drill bits which are useful for drilling holes
of up to 26 inches in
diameter. The patent describes the use of dual walled drill pipe and the
drilling fluid does not
flow to the surface through the casing annulus. This is fundamentally
different than
conventional drilling which uses simple single walled pipe.
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Another prior art jet pump device is disclosed in U.S. Patent no. 4,630,691.
While a jet pump is
used to create a pressure differential, the assembly as described in the
patent does not provide
adequate control and maintenance of the fluid pressure differential in the
wellbore, thereby,
reducing the effectiveness of the assembly in any underbalanced drilling
operation.
SUMMARY OF THE INVENTION
When drilling an underground wellbore, reducing the pressure of the circulated
drilling fluid is
of advantage and the technique of underbalanced drilling is frequently
applied. Many of the
recognized disadvantages with respect to the use of compressed gas in
underbalanced drilling
can be alleviated or eliminated by use of the pressure differential drilling
tool of the present
invention in place of the gas system. The tool of the present invention
reduces the circulating
pressure at the bottom of the wellbore by using the energy of the drill fluid.
The pressure differential drilling tool is mounted in the drill string and
includes a jet pump and a
wellbore packoff seal. The wellbore pack off seal, commonly referred to as a
"packer",
maintains a seal in the annulus between the drill string and the wellbore, or
wellbore casing pipe
if the well is cased, (herein referred to as the wellbore) during the drilling
process. The packer
prevents drilling fluid from passing therepast in at least a selected
direction through the annulus,
while being moveable along the wellbore. The jet pump draws the drilling fluid
from the annulus
below the packer, forces it through a flow path through the tool of the
present invention and
injects the drilling fluid back into the annulus above the packer. This
creates an underbalanced
condition in the annulus below the packer (toward the bit), referred to herein
as the lower
annulus, wherein the fluid pressure in the annulus between the drill bit and
the packer is reduced
relative to that fluid pressure in the drill string and in the annulus above
the packer on the uphole
side of the packer, referred to herein as the upper annulus.
Thus, in accordance with a broad aspect of the present invention, there is
provided a pressure
differential drilling tool for reducing pressure in the annulus between a
drill string and a wellbore
in a drilling zone, the pressure differential drilling tool comprising: (a) a
jet pump including a
power nozzle having a nozzle inlet, a pump inlet, a pump outlet and a drilling
fluid conduit,
including a throat and a diffuser, extending between the pump inlet and the
pump outlet and in
communication with the power nozzle inlet, the jet pump being connectable into
the drill string
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such that the power nozzle inlet is open to a power fluid flow path providing
a source of power
fluid to the power nozzle to drive the jet pump and the pump inlet is open to
a return flow path
from below the jet pump, the jet pump being driveable to reduce pressure of
fluid in the return
flow path (b) a bypass port for fluid flow downwardly and around the jet pump
and (c) a
wellbore pack off seal positioned about the jet pump and operable to create a
seal in the annulus
preventing fluid communication between a high pressure region in the annulus
and a low
pressure region in the annulus and being moveable with the jet pump, while in
operation, through
the wellbore.
In accordance with another aspect of the present invention, there is provided
pressure differential
drilling assembly for reducing fluid pressure in an annulus between a drill
string and a wellbore
in a drilling zone, the drill string including an inner bore for conducting
drilling fluid
therethrough, the pressure differential drilling assembly comprising: a drill
bit for removing
formation cuttings from the bore bottom and connected at a distal end of the
drill string; a
wellbore pack off seal for creating a seal against drilling fluid flow
therepast through the annulus
about the drill string and defining a lower annulus therebelow and an upper
annulus thereabove;
a jet pump connected into the drill string and including a power nozzle, a
throat, a diffuser, a
pump inlet opening between the power nozzle and the throat and a pump outlet
past the diffuser,
the power nozzle having an nozzle inlet open to a power fluid flow path for
providing a source of
power fluid to the power nozzle to drive the jet pump and the pump inlet being
open to a return
flow path in pressure communication with the lower annulus, the jet pump being
operable to
reduce the fluid pressure in the return flow path; and a bypass port for fluid
flow toward the drill
bit and around the jet pump.
Extra drilling fluid is added at surface and the extra fluid is diverted
through the power nozzle of
the jet pump which is mounted in the drill string in the vicinity of the
packer. The venturi action
created by sufficiently high flow rates through an appropriately sized jet
pump will create suction
at the pump inlet. The pump inlet is located below the packer such that the
jet pump draws fluid
from the drilling fluid down stream of the drill bit. This reduces the
pressure of the fluid column
downstream of the bit and thereby creates a region of low pressure in the
annulus between the
packer and the bit. The suction fluid, along with the entrained drill cuttings
and any formation
fluid influx in response to the pressure underbalance condition, is discharged
from the pump via
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the outlet port located above the packer at sufficient pressure to flow into
the surface fluid
control system.
The tool of the present invention can accommodate various circulation paths.
In particular,
drilling fluid can be pumped from surface through the drill string bore or
through the annulus.
Return fluid from the bit can also flow either through the drill string bore
or through the annulus.
The packer and the jet pump energy prevent the pressure of the fluid column
above the packer
from exerting full pressure on the fluid below the packer. By locating the jet
pump device at
sufficient depth in the drill string, it is possible to achieve the required
degree of pressure
underbalance or reduced pressure overbalance at the drillface and open
wellbore adjacent the
drill face.
One embodiment of the present invention, includes flow pressure and/or rate
control devices to
ensure that proper flow diversion occurs through the jet pump. The tool of the
present invention
can include at least one check valve to ensure that underbalanced conditions
are maintained
when drilling fluid circulation is stopped. The packer must maintain its seal
while the drill bit is
advancing and during all other operations where it is desirable to maintain
reduced pressure in
the annulus below the packer.
To facilitate repair and other handling, the jet pump portion of the tool can
be made to be
retreivable from its operational position along the drill string. In
particular, the drill string can
carry the packer while a body carrying the jet pump is latchable in the drill
string and can be
retrieved therethrough.
In accordance with another broad aspect of the present invention, there is
provided a process for
drilling a wellbore through an underground formation using a drill string
including an inner bore
for conducting drilling fluid therethrough and creating a reduced fluid
pressure in an annulus
between the drill string and the wellbore in the drilling zone, the process
comprising: providing
a pressure differential drilling assembly including a drill bit for removing
formation cuttings
from the bore bottom and connected at a distal end of the drill string; a
wellbore pack off seal for
creating a seal against drilling fluid flow therepast through the annulus
about the drill string and
defining a lower annulus therebelow and an upper annulus thereabove; a jet
pump connected into
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the drill string and including a power nozzle, a throat, a diffuser, a pump
inlet opening between
the power nozzle and the throat and a pump outlet past the diffuser, the power
nozzle having an
nozzle inlet conveying a source of power fluid to the power nozzle to drive
the jet pump and the
pump inlet being open to a return flow path in pressure communication with the
lower annulus,
the jet pump being operable to reduce the fluid pressure in the return flow
path; and a bypass port
for fluid flow toward the drill bit and around the jet pump; providing a flow
of drilling fluid to
pass through the power nozzle inlet, the drill bit and the return flow path;
operating the drill bit
to extend the wellbore.
The preferred process for drilling an underground wellbore from the surface
places the invention
at sufficient depth to create the desired condition at the drill face and
exposed rock formation.
Power fluid actuates the jet pump to reduce bottomhole pressure while the bit
is drilling or fluid
is circulating at sufficient rate. The power fluid driven jet pump draws in
the bottom hole fluid,
along with drill cuttings and entrained formation fluids, at reduced pressure
and discharges the
mixture above the packer at sufficient pressure to reach the earth surface.
Check valves maintain
reduced pressure when drilling fluid is not circulating such as while making
pipe connections or
while tripping the pipe. The packer is operable to maintain the seal while
operations occur that
reduce fluid circulation pressure.
Reduced lower annulus fluid pressure must be ensured to achieve the objectives
of reducing cost,
reducing well flow impairment and evaluating formation fluid characteristics
and flow
capability.
BRIEF DESCRIPTION OF THE DRAWINGS
A further, detailed, description of the invention, briefly described above,
will follow by reference
to the following drawings of specific embodiments of the invention. These
drawings depict only
typical embodiments of the invention and are therefore not to be considered
limiting of its scope.
In the drawings:
Figure 1 is a is a schematic view illustrating an assembly according to the
present invention.
Figure 2 is a longitudinal cross section through a pressure differential
drilling tool according to
the present invention.
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Figure 3 is a sectional view along line 3 - 3 of the complete tool of Figure
2.
Figure 4 is a sectional view along line 4 - 4 of the complete tool of Figure
2.
Figure 5 is a longitudinal cross section through another pressure differential
drilling tool
according to the present invention.
Figure 6A is a longitudinal cross section through another pressure
differential drilling tool
according to the present invention.
Figure 6B is a sectional view along line B-B of Figure 6A.
Figure 6C is a sectional view through a oil filled chamber useful in the tool
of Figure 6A.
Figure 7 is a longitudinal cross section through another pressure differential
drilling tool
according to the present invention.
Figure 8 is a longitudinal cross section through another pressure differential
drilling tool
according to the present invention.
Figure 9 is a longitudinal cross section through another pressure differential
drilling tool
according to the present invention.
Figure 10 is a longitudinal cross section through another pressure
differential drilling tool
according to the present invention.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
Referring to Figure 1, a pressure differential drilling assembly and tool
according to the present
invention are shown.
A pressure differential drilling tool 10 according to the present invention
includes a jet pump 12
and sliding packer 14. For use, the drilling tool is mounted in a drill string
16 passing into a
wellbore 18 through a formation 19. Packer 14 is selected to create a seal
between drill string 16
and the wellbore 18 such that a pressure differential can be set up in the
annulus about the
packer. To facilitate sealing of the packer, a stabilizer or centralizer 20 is
mounted on the drill
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string. The drill string can be formed of, for example, drill pipe, tubing,
coiled tubing or drill
casing. The wellbore extends from surface 21 to bore bottom 22 and includes
wellbore casing 23
at its upper end. The wellbore can be of any type that is bored using a drill
string and wherein
drilling fluid is returned to surface by circulation through the annulus 25
between the drill string
and the wellbore wall such as conventional or slim hole sized wellbores.
Wellbore 18 will
generally be a vertical, deviated, directional or horizontal, conventional or
slim hole sized
wellbore of less than 36 inch diameter. A drill bit 26 such as, for example, a
rotary drill bit or
hammer bit, is attached onto drill string 16. The drill bit cuts into the
formation at bore bottom
22 and advances the wellbore into the formation. Drill bit 26, in the
illustrated embodiment, is
driven to rotate and thereby cut into the formation by operation of a downhole
motor 27 driven
by drilling fluid. Alternately, the drill bit and drill string can be driven
to rotate from surface.
The drill string can also include measurement while drilling or other devices
for monitoring the
drilling operation.
In a drilling operation, drilling fluid, for which flow is shown in Figure 1
by arrows, is pumped
from a system of surface tanks or pits and pipes, generally shown as 28, by a
pump 30, and
injected into the inner bore 32 of drill string 16. The drilling fluid is
injected at a sufficient rate
and pressure to achieve proper performance in the wellbore and subsequently to
achieve return
fluid circulation to surface.
When the drilling fluid passing through the drill string bore 32 reaches tool
10, the fluid can pass
through two separate paths. In particular, bypass ports 33 are provided about
tool 10 so that a
portion of the fluid, referred to herein as bit fluid, can flow therepast,
while some fluid, referred
to as power fluid, passes through a power nozzle 34 of jet pump 12, as will be
described in more
detail hereinafter. The bypass ports can be drilled ports as shown or other
fluid conduit
arrangements.
The bit fluid continues through drill string 16 until it passes through motor
27 and out through
nozzles in drill bit 26 into the space between the drill string and the
wellbore, referred to herein
as annulus 36. The drilling fluid then passes up the annulus towards surface
21. This fluid
usually contains formation cuttings, created by action of the drill bit, and
can contain formation
fluids such as water or gas.
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Using the tool of the present invention, the fluid, after passing through the
drill bit, can pass up
the annulus until it reaches packer 14. The slidable packer seals against
fluid passage therepast
through the annulus, therefore, the fluid is diverted through jet pump 12. Jet
pump 12 has a
pump inlet 40 and a pump outlet 42. A fluid conduit 45 extends between power
nozzle 34, pump
inlet 40 and pump outlet 42. Drilling fluid can flow past the packer through
inlet 40 and outlet
42 as assisted by fluid flowing through power nozzle 34.
In an underbalanced drilling operation, the pressure of the drilling fluid in
the lower annulus near
the bore bottom must be less than the fluid pressure of the surrounding
formation 19. According
to the present invention, the power fluid portion of the drilling fluid
activates the jet pump action
to suck drilling fluid from the annulus below the packer reducing fluid
pressure acting against
the wellbore and the drill face below the packer.
To provide for control of the amount of fluid passing through power nozzle 34,
preferably a fluid
flow rate regulator 46 is provided in the drill string between the jet pump
and the drill bit. In
particular, fluid from surface is divided into two flow paths at the jet pump.
The portion of the
volume that will flow through each flow path is determined by how much flow
resistance occurs
in each path. The restriction through the power nozzle is very small so a
relatively small amount
of fluid will go through the power nozzle. For ajet pump to work it must have
a large amount of
fluid passing through it. Therefore, for improved functioning and control of
the jet pump, extra
flow restriction is applied to the bit fluid to decrease the volume of fluid
to the bit and increase
the proportion of fluid passing through the power nozzle. Flow rate regulator
46 when installed
below the tool will not allow flow rates through the bit to exceed a
predetermined value. Thus, it
will be appreciated that the use of a flow rate regulator as shown will permit
control of the
function of the jet pump since an increase in the flow rate of drilling fluid
from surface will
directly affect the amount of fluid passing through the jet pump.
One embodiment of tool 10 of the present invention is shown in greater detail
in Figures 2 to 4.
The tool is inserted into a drill string 16 by upper and lower threaded
connections 47, 48. The
tool includes a jet pump 12 and a packer 14. Bypass ports 33 provide for fluid
flow past the jet
pump through bore 32 of the drill string. In the illustrated tool (Figures 3
and 4), five bypass
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ports are formed through the body defining the jet pump. However, it is to be
understood that
any number and configuration of ports is within the invention provided that
fluid flow past the jet
pump is provided without opening into any of the internal fluid passages of
the jet pump.
Packer 14 is sealably disposed about the exterior surface 10a of the tool
between pump inlet 40
and pump outlet 42. While the tool has an outer diameter selected to pass
through the wellbore,
packer is selected such that when it is in sealing position in the wellbore,
it extends between the
jet pump and the wellbore wall (not shown in Figures 2 to 4) and creates a
seal therebetween.
The seal prevents fluid flow past the packer. While some microscopic fluid
flow past the packer
may periodically occur, any detectable leakage must be avoided. Those skilled
in the art will
know methods for testing the seal integrity of a packer such as, for example,
by monitoring drill
string weight during a drilling operation using the tool.
The packer is mounted on the tool and is slidable along the wellbore while
maintaining the seal.
This is necessary to permit advancement of the drill string and jet pump as
the drill bit extends
the wellbore. A packer that can withstand the movement along the wellbore and
preferably
repeated trips down and uphole is preferred. As an example, a packer having a
reinforced and/or
beveled outer edge can be used. Drilling of the underground formation is
achieved by applying
compressional force to the formation, via the drill bit, most often in
combination with rotating
the drill bit. The packer seal must withstand all movements of the drill
string, if pressure
underbalance is to be maintained. In order to advance the drill bit it is
necessary to advance the
drill string so the packer in this embodiment must be able to move
longitudinal through the
wellbore without losing its seal. In order to rotate the bit, it is necessary
to either rotate the drill
string or use a downhole motor and it is sometimes necessary to combine the
two rotational
methods. Thus, in many applications the packer must allow for rotational
movement of the drill
string. Such rotational movement may be accommodated at the packer-wellbore
interface and/or
preferably at the packer-drill string interface. Cup type packers, of the type
commonly available
through petroleum industry suppliers such as Guiberson AVA (part no. 17786 for
7 inch casing),
will accommodate, longitudinal and rotate such motion under low loadings in
terms of pressure,
rotation and sliding. Modification of that packer or use of an alternative
packer may be
necessary as more severe loadings are demanded for specific well drilling
situations. In some
applications, it may be necessary or desirable to use a plurality of packers
in series.
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A cup-type packer is shown in Figure 2. Such a packer has a base 49 and a
circumferential wall
50 extending therefrom. During use, pressures above the packer are intended to
be greater than
pressures below the packer. Therefore, the packer is mounted such that wall 50
extends
upwardly from the base to its outer edge 50a. The packer is formed of
deformable, elastomeric
material such as, for example, rubber or polyurethane cast about an internal
support 51 of rigid
material such as steel or aluminum. Outer edge 50a is beveled to facilitate
movement along the
wellbore wall and in particular through casing connections when being pulled
towards surface.
A seal 52 such as an 0-ring is carried on the base to effect a seal between
the jet pump and the
packer. The packer is mounted on drill string by use of set screws 53. The set
screws pass
through the packer and engage the drill string surface preventing the packer
from moving relative
to the jet pump. Where it is desirable to permit rotation of the packer about
the jet pump body,
the mounting can be achieved in other ways. In one embodiment, the base of the
packer is
mounted between a pair of shoulders on the surface of the jet pump. The
shoulders can be
integral with the jet pump body or can be formed by rings mounted about the
jet pump.
While the illustrated packer has been described, any packer that is capable of
sealing between the
jet pump and the wellbore while being slidable along the wellbore can be used.
Jet pump 12 includes a power nozzle 34, a pump inlet 40 and a pump outlet 42.
A fluid conduit
45 extends between power nozzle 34 and pump outlet 42. Pump inlet 40 opens
into fluid conduit
45 and, thereby, open communication is provided between inlet 40 and outlet
42. Conduit 45 is
shaped to define the standard parts of a jet pump including a throat 54 and a
diffuser 56. While a
central-type power nozzle, as illustrated, is preferred, alternately a
peripheral or annular-type
power nozzle can be used. While only one each of the inlet and outlet are
shown, more than one
of each can be provided.
Inlet 40, outlet 42 and throat 54 are sized to permit passage therethrough of
drill cuttings.
Preferably, inlet 40 has a diameter that is reduced from that of the throat
such that the inlet acts
as a screen against oversized debris entering the jet pump where it may become
jammed in the
throat. Any materials that bridge the inlet can be cleared easily when the
tool is brought to
surface and/or may fall away from the inlet when the fluid circulation is
stopped.
Jet pump 12 can be formed as a single unit or, to facilitate manufacture and
repair it is formed of
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a plurality of parts connected together by, for example, welding and/or
threaded connections. In
particular, it is preferred that the power nozzle be removable since it is
prone to fluid erosion and
may need to be changed to select for size depending on the well conditions and
depth. As such,
in one embodiment power nozzle 34 is connected into the tool by threads 354. A
top plug 57
provides access to conduit 45 and can be replaced since this portion of the
conduit will also be
prone to erosion. '
The tool is formed of materials, and can have coatings, selected to reduce the
effects of erosion.
In addition, rough and/or sharp edges should be avoided as much as possible to
reduce fluid
turbulence and frictional pressure losses. In addition or alternately,
additives can be added to the
drilling fluid that reduce turbulent friction pressure losses. Common
additives for this purpose
are, for example, hydrolyzed polyacrylamides, xanthan gums and
hydroxyethylcellulose
polymers.
In operation, drilling fluid from surface passes through bore 32 of drill
string and passes through
bypass ports 33. Once out of ports 33, a portion of the drilling fluid,
referred to herein as the bit
fluid, continues down the drill string towards the bit. A second portion of
the drilling fluid,
referred to herein as the power fluid, passes through power nozzle 34. Power
fluid exits the
power nozzle of the jet pump, enters throat 54, passes through the tapered
diffuser section 56 of
the jet pump and exits the jet pump via pump outlet 42. Because of the seal in
the annulus
created by packer 14, the power fluid next flows toward the surface via the
annulus between the
drill string and the cased wellbore.
When power fluid flows through an appropriately sized jet pump, an area of
reduced pressure is
created in the region between the nozzle and the throat by means of a Venturi
effect. External
fluid is drawn into the area of Venturi reduced pressure via inlet 40. The
external fluid then
passes through the jet pump where it is mixed with the power fluid and
discharged from the jet
pump at high pressure through pump outlet 42.
The external fluid is the bit fluid that has passed the bit and includes drill
cuttings and formation
fluids generated by the drill bit. The external fluid is in the annulus below
the packer. The
pressure in the annulus is a combination of the pressure at the top of the
annulus plus the
pressure exerted by the column of fluid in the annulus. The suction inlet 40
is located at the top
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of this annulus so when pressure is reduced at the suction inlet, the pressure
at all points in this
annulus will be reduced accordingly. When power fluid is supplied to the jet
pump at sufficient
rate and pressure, the resulting pressure in the drillstring-wellbore annulus
can be made lower
than the pressure of fluids in the formation and such fluids will then flow
into the annulus. This
is the condition for what is referred to as "underbalanced drilling" when
drilling is
simultaneously occurring.
During periods of reduced or interrupted fluid circulation, it may be
necessary to maintain
underbalanced conditions wherein the region in the annulus below the packer is
at a lower fluid
pressure than those above the packer and within the drill string. Thus,
referring to Figure 5, in
one embodiment, the tool of the present invention includes at least one valve
for preventing fluid
flow in a reverse direction through the jet pump. In particular, a ball 70 is
disposed in diffuser
portion 56 and is selected to seat in throat 54 to seal against reverse flow
through the throat of
the jet pump. When tool 10 is in use and fluid is flowing upwardly through the
throat portion,
ball 70 is carried in the flow and creates no seal. In particular, outlet 42
is formed to retain ball
70 within diffuser portion 56 without blocking fluid flow through the outlet.
In particular, outlet
port 42 is formed as a slot or an oval and the ball is wider than the
narrowest portion of the
opening. Other means for maintaining the ball in the diffuser can be used as
desired.
To prevent reverse flow through the nozzle, a spring-actuated reverse flow
ball-type check valve
72 is provided at the power nozzle inlet. Valve 72 includes a spring 74 that
adds a back pressure
function to the valve. Normally, the spring forces ball 76 into sealing
relation against seat 78.
The force of spring is selected such that fluid pressures below a selected
level will be unable to
unseat ball 76. Thus, when drilling fluid is below the selected pressure, the
drill string will
operate in a standard mode without action of the jet pump and the jet pump
will only begin to
operate when the fluid pressure reaches a predetermined level sufficient to
overcome the
compression in spring 74. This is particularly, useful during drilling start-
up where it is
preferred to drive operation of the drill bit before the jet pump. In
addition, when drilling is
stopped, valve 72 prevents passage of the drill pipe fluid into the upper and
lower annulus.
An elastomeric cup seal 80 is mounted about nozzle 34 and is sized to prevent
reverse flow from
the throat through inlet 40. In particular, cup seal 80 is deformable such
that during normal
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operation flow through inlet 40 can pass into throat 54. However, when the jet
pump is not
operating any fluids flowing back through inlet 40 act on cup seal 80 to seal
off flow through the
inlet.
Valves can be provided at additional or alternate positions within the jet
pump to prevent reverse
flow and loss of differential pressure or to control fluid supply sequence.
For example, instead
of a ball valve in the diffuser, a valve can be positioned to seal off the
pump inlet or the pump
outlet. However, generally there is more room in the diffuser for such a
valve. A valve in the
suction inlet can be used to prevent overpressuring the annulus while the jet
pump is being
brought up to the appropriate rate. Valves can also be added in bit fluid
paths. In some
embodiments, valves are positioned for safety and well control to reduce
passage of high
pressure fluid up hole, for example, in a well blow out situation.
Various forms of valves are useful. Ball valves have been proven particularly
useful in oilfield,
vertical orientation applications. Spring actuated valves may be needed in non-
vertical
orientations. Plunger, flapper and sliding sleeve valves are also useful in
certain applications.
The selection of a suitable valve for various purposes is within the art.
As noted previously, a fluid flow rate regulator can be provided in the drill
pipe below the tool to
regulate fluid flow to the drill bit. In one embodiment, a fluid flow rate
regulator can be
provided to regulate fluid flow through the power nozzle where it is necessary
to be able to vary
flow through the bit without affecting the lift created by the power nozzle.
Referring to Figure 6, another tool according to the present invention is
shown in drilling
configuration wherein the jet pump would be operating to create lift in the
lower annulus. The
tool 100 has a body 111 defining a jet pump 112 and, mounted about the body, a
compound
packer 114 including five sealing elements 115. Jet pump 112 includes a power
nozzle 134, three
pump inlets 140, three pump outlets 142, a throat 154 and a diffuser 156.
Five bypass ports 133 extend through body 111. Bypass ports 133 at their lower
end are open to
a chamber 158. Chamber 158 is in communication with power nozzle inlet 134a
and the lower
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drill string bore 132 through a port 159. Thus, any fluid passing out of
bypass ports 133 into
chamber 158 divides such that a portion passes through power nozzle 134 and a
portion passes
toward the drill bit.
A ball 170 is positioned in the diffuser and creates a reverse flow check
valve. The ball is shown
in an open position, which is the position during normal fluid circulation.
A sliding sleeve valve 172 is provided to seal passage of fluid through the
bypass valves when
the circulation of drilling fluid is stopped. In particular, nozzle 134 and
throat 154 are carried on
sleeve 172 and sleeve 172 is slidable in a bore 174 in body 111. Sleeve 172 is
slidable between
an open position wherein fluid can pass out of chamber 158 and a closed
position wherein access
from chamber 158 to power nozzle 134 and port 159 is sealed off. Upwards
sliding movement
of sleeve 172 is limited by shoulder 175 in bore 174 and downwards movement is
limited by seat
176. 0-rings 178 are positioned between sleeve 172 and bore 174 to prevent
fluid flow
therethrough while permitting sliding therebetween.
The sleeve has formed thereon a shoulder 180 sized and positioned to be acted
on by circulation
fluid pressure (hydrostatic pressure and pump pressure) to drive sleeve into
the open position.
When the pump is stopped, the ball 170 seats in the diffuser due to gravity.
Since the sleeve 172
is connected to and moves with diffuser 156, setting of ball 170 in diffuser
causes sleeve 172 to
seats due to a combination of higher upper annular hydrostatic pressure and
gravity acting on the
ball and sleeve assembly. Inertia, such as when the drill string is moved
upward in the process of
making or breaking a connection or tripping out the drill string, will also
cause the sleeve 172 to
seat.
As noted hereinbefore, packer 114 includes five sealing elements 115. Each
element is formed of
a durable elastomeric material such as rubber or polyurethane. The outer
diameter of each
element in uncompressed form is selected to be greater than the inner diameter
of wellbore or
casing 123, (shown in phantom,) in which it is to be used. As such, the packer
acts as an
interference fit packer.
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Packer elements 115 are held in side by side relation between rings 190. An
oil-filled bearing
192 provides for rotation of the packer about body 111. Bearing 192 includes a
plurality of ball
bearings 193 in grooves 194 in the tool body. An oil filled bearing chamber is
sealed by sealing
elements 197 in rings 190. The bearing restricts the packer against
longitudinal movement along
the body. In one embodiment, a bypass port 198 is sealed off by pistons 199 at
either end
thereof and is filled with oil in communication with the oil filled chamber of
bearing 192. Fluid
pressure acting against the pistons acts to adjust for pressure differences
between the oil in the
bearing and the external fluid pressure to prevent drilling fluid entry to the
bearing area such that
oil lubrication is maintained to minimize bearing friction and wear.
Referring to Figure 7, another tool according to the present invention is
shown in drilling
configuration wherein the jet pump is operating to create lift in the lower
annulus. The tool 200
includes a body 211 defining a jet pump 212 and, mounted about the body, two
cup packers 214.
Too1200 includes two reverse flow check valves. In particular, a ball 270 is
disposed in the inlet
to jet pump nozzle 234. A rod 272 extends across the nozzle inlet to prevent
the ball from
sealing off the nozzle. When flow reverses, ball 270 seats against valve seat
276 to prevent
reverse flow through the nozzle.
The tool's other reverse flow check valve is positioned in pump inlet 240. The
check valve
includes a ba11290 and seat 292. Ba11290 is positioned an opening with a slot
293 formed at the
inner end. Slot 293 is narrower than the diameter of the ball such that ball
290 cannot pass
therethrough to seal against the throat 254.
In a drilling operation where there is a low volume of drilling fluid
circulating, it may be
advantageous to reverse circulation of drilling fluid over those systems
discussed hereinbefore
such that it flows downhole through the annulus to return up through the bore
of the drill string.
The tool of the present invention can be used to create underbalanced
conditions in such a
drilling operation. In particular, referring to Figure 8, a pressure
differential drilling tool 300 is
shown that is useful for operating with a circulation of drilling fluid
passing down hole through
the annulus between the drill string and the borehole and returning,
containing drill cuttings,
through the drill string bore.
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Tool 300 is connectable at its ends into a drill string and includes a jet
pump 312 and a pair of
sliding packers 314. Jet pump 312 includes a throat 354 and a diffuser 356.
Fluid acted on by jet
pump enters through a pump inlet 340 and exits through a pump outlet 342 above
the diffuser.
In a drilling operation, drilling fluid, for which flow is shown by the
arrows, is pumped down the
annulus and enters the tool through an inlet port 318. Continued flow through
the annulus is
prevented by packers 314. After entering through port 318, drilling fluid can
pass through
channel 320 and out into the annulus below the packers through a lower annulus
outlet port
having a fluid flow restrictor 323 mounted therein. Fluid flow restrictor 323
limits the volume of
fluid that can flow therepast. Thus, a pressure differential can be
established about flow
restrictor 323 wherein the pressure in the annulus is lower than the pressure
in channel 320.
Fluid passing through channel 320 and flow restrictor 323, referred to herein
as bit fluid, flows
down the annulus, passes through the drill bit and returns up through the
drill string bore.
A portion of the drilling fluid entering through inlet port 318 passes through
power nozzle 334 of
the jet pump. This portion of the drilling fluid is referred to herein as
power fluid. This power
fluid draws fluid through port 340, from bore 336 of the tool and through the
bore of the drill
string and through the nozzles of the drill bit to create lift and reduce the
pressure of the fluid in
the drill string bore and in the annulus between the drill string and the
formation below flow
restrictor 323 of the tool.
Another tool 400 according to the present invention is shown in Figure 9. Tool
400 is useful in
drilling operations where, after the drilling operation is complete, it is
desirable to leave the drill
string downhole and to pump produced fluids therethrough. Tool 400 can act to
both create
underbalance condition in the drilling fluid during a drilling operation and
to create lift for
produced fluids.
Tool 400 is connectable at its ends into a drill string and includes a jet
pump 412 and a pair of
sliding packers 414. Jet pump 412 includes a nozzle 434, a throat 454 and a
diffuser 456. Fluid
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acted on by jet pump enters through a pump inlet conduit 440 and exits through
a pump outlet
442 above the diffuser.
In a drilling operation, drilling fluid, for which flow is shown by arrows, is
pumped down the
annulus and enters the tool through an inlet port 418. Continued flow through
the annulus is
prevented by packers 414. After entering through port 418, drilling fluid can
pass through bore
420 and into the inner bore of the drill string. This drilling fluid, termed
herein as bit fluid, flows
down through the drill bit and returns up through the annulus between the
borehole wall and the
drill string until it reaches packers 414. At this point, the drilling fluid
can pass into the tool via
pump inlet conduit 440. Pump inlet conduit extends from port below the packer
to open between
nozzle 434 and throat 454.
A portion of the drilling fluid, referred to herein as power fluid, passing
through inlet port 418
passes through power nozzle 434 of the jet pump. This power fluid acts on
fluid returning
through the annulus and draws fluid through a pump inlet conduit 440. In this
way, lift is created
in the drilling fluid and the pressure of the fluid in the annulus below the
packer is reduced, or
underbalanced, relative to the drilling fluid pressure in the annulus above
the packer and in the
drill string bore.
When it is desired to cease drilling and begin producing the formation fluids,
the drill bit is
actuated, as is known, to close off all ports therethrough such that no fluid
will pass through bore
420. Thus, all fluid pumped downhole through the annulus will pass through
port 418 and power
nozzle 434. In the same way as the drilling operation, fluid passing through
power nozzle 434
will create a vacuum in pump inlet conduit 440 and will tend to lift any
fluids, including any
formation fluids located in the annulus below the packer.
In one embodiment, the jet pump is included in a body that is releasably
mounted within the drill
string and is retrievable therethrough without removing the drill string. In
particular, referring to
Figure 10, a pressure differential drilling tool 500 includes a retrievable
body 505 sized to fit into
and be positionable in a section of drill pipe 516 that is connected into the
drill string.
Retrievable body 505 includes a jet pump 512 including a power nozzle 534, a
throat 554 and a
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diffuser 556, a bypass port 533, a pump inlet 540 and a pump outlet 542.
Deformable seals 543
are positioned about body 505 to create seals between the body and the drill
pipe section about
inlet 540 and outlet 542. The retrievable body has mounted thereon at least
one retractable latch
531 (two are shown) for engagement with an annular profile 532 in the drill
pipe. Latch 531,
when engaged in profile 532, holds body in position in the section of drill
pipe. Drill pipe
section 516 has disposed thereabout a packer 514. A lower port 546 is
positioned below the
packer and an upper port 548 is positioned above the packer. Ports 546, 548
each extend through
the wall of the drill pipe section and open into lower and upper annular
recesses 550, 551,
respectively, formed on the inner surface of the drill pipe. When latches 531
are latched into
profile 532, inlet 540 and outlet 542 align with and open into recesses 550,
551, respectively.
Latches 531 are common wireline latches. In particular, the latches pivot
about pin connections
559 and are biased outwardly by springs 560 such that, during installation,
when the latches ride
into the profile, the latches will spring out into engagement with the
profile. In the engaged
position, rear extensions 561 protrude through slots 562 into upper bore 563
of body 505. To
retrieve body 505 from drill pipe section 516, a fishing tool (not shown) is
tripped downhole to
engage fishing neck 565. The fishing tool also includes a spear portion that
is sized to fit down
into bore 563 and push against rear extensions 561. This action causes latches
531 to rotate
about pin connections 559 and against the force in springs 560 to retract
latches out of
engagement with profile 532.
The jet pump body can be retrievable by means of a wireline, coiled tubing or
other pulling
means. In other tool embodiments, not shown, retrieval can be by circulating
fluid to dislodge
the body from its mounting position in the drill string. While a retrievable
embodiment is not
preferred, it is sometimes useful to quickly retrieve the jet pump for
unplugging ports, for repair
or for changing nozzle or throat sizes. If a retrievable jet pump is desired
and it is also desirable
to maintain fluid pressure differential about the packer, it may be necessary
to provide a valve in
the drill pipe to block open ports in the drill pipe remaining after removal
of a retrievable jet
pump.
In order to achieve underbalance, a pressure reduction must be achieved at the
bottom of the
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wellbore. The pressure reduction that is required for any particular
application can be
determined by consideration of, for example, minimum drilling requirements,
jet pump
performance calculations, pipe circulating pressure friction loss
calculations, field fluid
properties and variations at the drill location.
For example, in one preferred embodiment where the power fluid is pumped down
the drill pipe
with the objective of underbalance, as a first step in using the tool of the
present invention input
parameters are considered. As will be appreciated, input parameters in
conventional drilling are,
for example, hole size; maximum drill depth; largest useable drill pipe
diameter; drilling fluid
type and properties; minimum fluid circulation rate through the drill bit;
drill string components;
drilling rig pump limitations of pressure, horsepower and flow rate; and
existing pressure of
fluids in the formation to be drilled.
Next, the desired bottom hole pressure is selected to create the desired
underbalance or reduced
pressure condition. Calculate the height of the column of drilling fluid above
the bit, that would
create the desired bottom hole pressure. Convert this height into well depth
and use this depth as
the minimum depth, at the end of drilling operations, at which the jet pump
drilling tool of the
present invention would be installed. This depth also represents the
recommended minimum
depth to which casing should be run in a wellbore planned for continuous
underbalanced drilling,
since preferably, the packer of the tool acts against casing.
To select an appropriate size of jet pump for achieving the underbalance,
start by making
estimations for jet pump section pressure, jet pump power nozzle diameter and
jet pump throat
diameter. Then calculate the power fluid flow rate required for the jet pump
to lift fluid at a rate
equal to the minimum fluid circulation rate through the drill bit. If the
pressure exceeds the
pressure rating acceptable for the rig operation, then recalculate with larger
nozzle sizes.
Calculate the friction pressures with those rates and iterate to determine
workable limits for
pressure in the system. Many different calculation procedures can be used to
arrive at an
optimum solution. Computer aided selection is the most practical as this
facilitates trying a
number of different values for each parameter.
CA 02315969 2007-11-05
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The pump performance characteristics can be taken from the Petroleum
Engineering Handbook
(Petrie, H(ed.), February 1992, Society of Petroleum Engineers: Richardson,
TX, USA) which
has typical performance normalized from tests using oil or water as the power
fluid. To
obtain more accurate performance characteristics it may be necessary to put an
actual power
fluid through an actual pump mounted at a surface and analyze function by use
of pressure
gauges and flow meters. Actual testing to optimize the pump parameters is
preferred where:
non-Newtonian drilling fluids are used; friction reducing chemicals are used;
or experimental
pump configurations are employed.
Once the operating parameters are established it will be necessary to
calculate the pressure losses
for the bit fluid through the balance of the flow path. If the calculated
pressure losses from the
power nozzle to the pump inlet are less via the flow path through the bit than
via the flow path
through the jet pump nozzle, then extra flow restriction must be installed
such that the pressure
loss is equal.
Once the tool according to the present invention is deployed in the wellbore,
the circulating
friction losses at various rates should be compared to the theoretical. If
there are differences, the
equations should be calibrated accordingly and the system performance
recalculated. Downhole
pressure information can also be used for recalibration. The differential
pressure acting on the
cross sectional area of the packer annulus will create a downward force that
is accurately
reflected by the change in tension held at surface as observed by a weight
indicating device. The
difference between the initial static weight and the weight during fluid
circulation will therefore
reflect the pressure reduction achieved by the jet pump. Programmable logic
controllers can be
used to ensure the surface pump rates, surface pump pressures, and back
pressure on the
circulating system are within the proper balance.
It will be apparent that many other changes may be made to the illustrative
embodiments, while
falling within the scope of the invention and it is intended that all such
changes be covered by the
claims appended hereto.
