Note: Descriptions are shown in the official language in which they were submitted.
CA 02559248 2008-06-06
DOWNHOLE PROBE ASSEMBLY
BACKGROUND
During the drilling and completion of oil and gas wells, it may be necessary
to engage
in ancillary operations, such as monitoring the operability of equipment used
during the drilling
process or evaluating the production capabilities of formations intersected by
the wellbore. For
example, after a well or well interval has been drilled, zones of interest are
often tested to
determine various formation properties such as permeability, fluid type, fluid
quality,
formation temperature, formation pressure, bubblepoint and formation pressure
gradient.
These tests are performed in order to determine whether commercial
exploitation of the
intersected formations is viable and how to optimize production.
Wireline formation testers (WFT) and drill stem testing (DST) have been
commonly
used to perform these tests. The basic DST test tool consists of a packer or
packers, valves or
ports that may be opened and closed from the surface, and two or more pressure-
recording
devices. The tool is lowered on a work string to the zone to be tested. The
packer or packers
are set, and drilling fluid is evacuated to isolate the zone from the drilling
fluid column. The
valves or ports are then opened to allow flow from the formation to the tool
for testing while
the recorders chart static pressures. A sampling chamber traps clean formation
fluids at the end
of the test. WFTs generally employ the same testing techniques but use a
wireline to lower the
test tool into the well bore after the drill string has been retrieved from
the well bore, although
WFT technology is sometimes deployed on a pipe string. The wireline tool
typically uses
packers also, although the packers are placed closer together, compared to
drill pipe conveyed
testers, for more efficient formation testing. In some cases, packers are not
used. In those
instances, the testing tool is brought into contact with the intersected
formation and testing is
done without zonal isolation across the axial span of the circumference of the
borehole wall.
WFTs may also include a probe assembly for engaging the borehole wall and
acquiring
formation fluid samples. The probe assembly may include an isolation pad to
engage the
borehole wall. The isolation pad seals against the formation and around a
hollow probe, which
places an internal cavity in fluid communication with the formation. "This
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creates a fluid pathway that allows fonnation fluid to flow between the
formation and the
fonnation tester while isolated from the borehole fluid.
Tii order to acquire a useful sainple, the probe must stay isolated from the
relative higll
pressure of the borehole fluid. Therefore, the integrity of the seal that is
formed by the
isolation pad is critical to the performance of the tool. If the borehole
fluid is allowed to leak
into the collected formation fluids, a non-representative sa.inple will be
obtained and the test
will have to be repeated.
With the use of WFTs and DSTs, the drill string with the drill bit must be
retracted
from the borehole. Then, a separate work string containing the testing
equipment, or, with
WFTs, the wireline tool string, inust be lowered into the well to conduct
secondary
operations. Interrupting the drilling process to perform formation testing can
add significant
ainotuits of time to a drilling program.
DSTs and WFTs may also cause tool sticking or formation damage. There may also
be difficulties of running WFTs in highly deviated and extended reach wells.
WFTs also do
not have flowbores for the flow of drilling mud, nor are they designed to
withstand drilling
loads such as torque and weiglit on bit.
Further, the fonnation pressure measurement accuracy of drill stem tests and,
especially, of wireline formation tests may be affected by filtrate invasion
and mudcalce
buildup because significant amounts of time may have passed before a DST or
WFT engages
the fonnation. Mud filtrate invasion occurs when the drilling mud fluids
displace formation
fluids. Because the inud filtrate ingress into the fonnation begins at the
borehole surface, it is
rnost prevalent there and generally decreases further into the formation. When
filtrate
lnvaslon occurs, it may become iinpossible to obtain a representative sainple
of forination
fluids or, at a ininimtun, the duration of the sainpling period must be
increased to first remove
the drilling fluid and tlien obtain a representative sample of fonnation
fluids. The mudcake is
made up of the solid particles that are deposited on the side of the well as
the filtrate invades
the near well bore during drilling. The prevalence of the mudcake at the
borehole surface
creates a"skin." Thus there may be a "skin effect" because formation testers
can only
withdraw fluids froin relatively short distances into the formation, thereby
distorting the
representative sample of formation fluids due to the filtrate. The mudcake
also acts as a
region of reduced perineability adjacent to the borelzole. Thus, once the
mudcake forms, the
accuracy of reseivoir pressure measurements decreases, affecting the
calculations for
perineability and producibility of the formation.
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Another testing apparatus is the measurement while drilling (MWD) or logging
while
drilling (LWD) tester. Typical LWD/MWD formation testing equipment is suitable
for
integration with a drill string during drilling operations. Various devices or
systems are
provided for isolating a formation from the remainder of the wellbore, drawing
fluid from the
formation, and measuring physical properties of the fluid and the formation.
With
LWD/MWD testers, the testing equipment is subject to harsh conditions in the
wellbore
during the drilling process that can damage and degrade the formation testing
equipment
before and during the testing process. These harsh conditions include
vibration and torque
from the drill bit, exposure to drilling mud, drilled cuttings, and formation
fluids, hydraulic
forces of the circulating drilling mud, and scraping of the formation testing
equipment against
the sides of the wellbore. Sensitive electronics and sensors inust be robust
enough to
withstand the pressures and temperatures, and especially the extreme vibration
and shoclc
conditions of the drilling enviromnent, yet maintain accuracy, repeatability,
and reliability.
BRIEF DESCRIPTION OF THE DRAWINGS
For a more detailed description of preferred embodiments of the present
invention,
reference will now be made to the accoinpanying drawings, wherein:
Figure 1 is a scheinatic elevation view, partly in cross-section, of an
embodiment of a
fonnation tester apparatus disposed in a subterranean well;
Figures 2A-2C are elevation views, in cross-section, of portions of the
bottomhole
asseinbly and formation tester assembly shown in Figure 1;
Figures 3A-3B are enlarged elevation views, in cross-section, of the formation
tester
tool portion of the fornnation tester assembly shown in Figures 2B-2C;
Figure 4 is an elevation view of the formation probe assembly and equalizer
valve
collar shown in Figure 3B;
Figure 5 is an enlarged cross-section view along line 5-5 of Figure 4;
Figure 6A is an enlarged view, in cross-section, of the fonnation probe
assembly in a
retracted position and equalizer valve shown in Figure 5;
Figure 6B is an enlarged view, in cross-section, of the formation probe
assembly along
line 6-6 of Figure 4, the probe assembly being in an extended position;
Figures 7A-7F are cross-sectional views of another embodiment of the formation
probe assembly talcen along the same line as seen in Figure 6B, the probe
assembly being
shown in a different position in each of Figures 7A-7F;
Figure 8A is a scheinatic elevation view, in cross-section, of the probe
retract switch
portion of the formation probe assembly;
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Figure 8B is an enlarged view of the contact portion of the retract switch
shown in
Figtiue SA;
Figure 9 is a schematic view of a hydraulic circuit employed in actuating the
formation tester apparatus;
Figure 10A is a top elevation view of a hydraulic reservoir accumulator
assembly
employed in the formation tester assembly;
Figure l OB is an end view of the reservoir accumulator assembly of Figure
10A;
Figure 10C is a cross-section view taken along line C-C of Figure l OB;
Figure 10D is a cross-section view taken along line D-D of Figure lOB;
Figure 10E is a cross-section view taken along line E-E of Figure 10D;
Figure I OF is a cross-section view talcen along line F-F of Figure 10C;
Figure lOG is an enlarged view of the detail of Figure 10D;
Figures lOH-10I are perspective views of the reservoir accumulator assembly
and
probe collar;
Figures 11-13 are elevation views, in cross-section, of the draw down piston
and
shutoff valve assemblies disposed in the probe collar of the formation tester
assembly; and
Figure 14 is a flow diagram of a formation test sequence.
DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS
Certain ternns are used throughout the following description and claims to
refer to
particular system components. This document does not intend to distinguish
between
components that differ in name but not function.
Tia the following discussion and in the claims, the tenns "including" and
"comprising"
are used in an open-ended fashion, and thus should be interpreted to mean
"including, but not
limited to...". Also, the terms "couple," "couples", and "coupled" used to
describe any
electrical coiuzections are each intended to mean and refer to either an
indirect or a direct
electrical connection. Tlius, for example, if a first device "couples" or is
"coupled" to a second
device, that intercoiuzection may be through an electrical conductor directly
interconnecting the
two devices, or through asi indirect electrical connection via other devices,
conductors and
connections. Further, reference to "up" or "down" are made for purposes of
ease of description
with "up" meanuig towards the surface of the borehole and "down" meaning
towards the
bottom or distal end of the borehole. In addition, in the discussion and
claims that follow, it
may be sometimes stated that certain components or eleinents are in fluid
comm.unication. By
this it is meant that the components are constructed and 'uzterrelated such
that a fluid could be
coininiuzicated between them, as via a passageway, tube, or conduit. Also, the
designation
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"MWD" or "LWD" are used to mean all generic measurement while drilling or
logging while
drilling apparatus and systems.
To understand the mechanics of fonnation testing, it is important to first
understand
how hydrocarbons are stored in subterranean formations. Hydrocarbons are not
typically
located in large underground pools, but are instead found within very small
holes, or pore
spaces, within cei-tain types of rock. Therefore, it is critical to ktiow
certain properties of both
the formation and the fluid contained tlierein. At various times during the
following
discussion, certain formation and formation fluid properties will be referred
to in a general
sense. Such formation properties include, but are not limited to: pressure,
permeability,
viscosity, inobility, spherical mobility, porosity, saturation, coupled
compressibility porosity,
skin dainage, and anisotropy. Such formation fluid properties include, but are
not limited to:
viscosity, compressibility, flowline fluid compressibility, density,
resistivity, composition and
bubble point.
Permeability is the ability of a rock formation to allow hydrocarbons to move
between
its pores, and consequently into a wellbore. Fluid viscosity is a measure of
the ability of the
hydrocarbons to flow, and the permeability divided by the viscosity is termed
"mobility."
Porosity is the ratio of void space to the bulk voluine of rock formation
containing that void
space. Saturation is the fraction or percentage of the pore volume occupied by
a specific fluid
(e.g., oil, gas, water, etc.). Slcin damage is an indication of how the mud
filtrate or mud cake
has changed the penneability near the wellbore. Anisotropy is the ratio of the
vertical and
horizontal permeabilities of the formation.
Resistivity of a fluid is the property of the fluid which resists the flow of
electrical
current. Bubble point occurs when a fluid's pressure is brought down at such a
rapid rate, a.nd
to a low enough pressure, that the fluid, or portions thereof, changes phase
to a gas. The
dissolved gases in the fluid are brought out of the fluid so gas is present in
the fluid in an
undissolved state. Typically, this lcind of phase change in the fonnation
hydrocarbons being
tested and measured is undesirable, unless the bubblepoint test is being
administered to
detei7nine what the bubblepoint pressure is.
In the drawings and description that follows, like parts are marked throughout
the
specification and drawings with the same reference numerals, respectively. The
drawing figures
are not necessarily to scale. Certain features of the invention may be shown
exaggerated in
scale or in somewhat schematic fonn and some details of conventional elements
may not be
shown in the interest of clarity and conciseness. The present invention is
susceptible to
embodiments of different forms. Specific embodiments are described in detail
and are shown in
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CA 02559248 2008-06-06
the drawings, with the understanding that the present disclosure is to be
considered an
exemplification of the principles of the invention, and is not intended to
limit the invention to
that illustrated and described herein. It is to be fully recognized that the
different teachings of
the embodiments discussed below may be employed separately or in any suitable
combination
to produce desired results. The various characteristics mentioned above, as
well as other
features and characteristics described in more detail below, will be readily
apparent to those
skilled in the art upon reading the following detailed description of the
embodiments, and by
referring to the accompanying drawings.
Referring to Figure 1, a formation tester tool 10 is shown as a part of bottom
hole
assembly 6 which includes an MWD sub 13 and a drill bit 7 at its lower most
end. Bottom
hole assembly 6 is lowered from a drilling platform 2, such as a ship or other
conventional
platform, via drill string 5. Drill string 5 is disposed through riser 3 and
well head 4.
Conventional drilling equipment (not shown) is supported within the derrick I
and rotates drill
string 5 and drill bit 7, causing bit 7 to form a borehole 8 through the
formation material 9.
The borehole 8 penetrates subterranean zones or reservoirs, such as reservoir
11, that are
believed to contain hydrocarbons in a commercially viable quantity. It should
be understood
that formation tester 10 may be employed in other bottom hole assemblies and
with other
drilling apparatus in land-based drilling, as well as offshore drilling as
shown in Figure 1. In
all instances, in addition to formation tester 10, the bottom hole assembly 6
contains various
conventional apparatus and systems, such as a down hole drill motor, rotary
steerable tool, mud
pulse telemetry system, measurement-while-drilling sensors and systems, and
others well
known in the art.
It should also be understood that, even though formation tester 10 is shown as
part of
drill string 5, the embodiments of the invention described below may be
conveyed down
borehole 8 via wireline technology, as is partially described above, or via a
rotary steerable
drill string that is well known to one skilled in the art. Further context and
examples for
methods of use of the embodiments described herein may be obtained from U.S.
Patent
Publication No. 2005/0268709 published on December 8, 2005 and entitled
"Methods for
Using a Formation Tester"; and U.S. Patent Publication No. 2005/0235745
published on
October 27, 2005 and entitled "Methods for Measuring a Formation Supercharge
Pressure."
Referring now to Figures 2A-C, portions of the formation tester tool 10 are
shown.
Figure 2A illustrates the electronics module 20, which may include battery
packs, various
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circuit boards, capacitors banks and other electrical components. Figure 2B
shows fillport
asseinbly 22 having fillports 24, 26 for adding or removing hydraulic or other
fluids to the
tool 10. Below fillport assembly 22 is hydraulic insert assembly 30. Below
assembly 30 is
the hydraulic connectors ring assembly 32, which acts as a hydraulic line
manifold. Figure
2C illustrates the portion of tool 10 including equalizer valve 60, formation
probe assembly
50 (or probe assembly 200), draw down shutoff valve asseinbly 74, draw down
piston
asseinblies 70, 72 and stabilizer 36. Also included is pressure instrument
assembly 38,
including the pressure transducers used by formation probe assemblies 50, 200.
Referring to Figures 3A-B now, the enlarged portions of tool 10 shown in
Figures 2B-
C ue shown. Hydraulic insert assembly 30, probe retract acctunulator 424,
equalizer valve
60, forznation probe assembly 50, draw down shutoff valve 74 and draw down
piston
assemblies 70, 72 can be seen in greater detail. Equalizer valve 60 may be any
of a variety of
equalizer valves known to one skilled in the art.
Referring now to Figure 4, formation probe assembly 50 is disposed within
probe drill
collar 12, and covered by probe cover plate 51. Also disposed within probe
collar 12 is an
equalizer valve 60 having a valve cover plate 61. Adjacent formation probe
assembly 50 and
equalizer valve 60 is a flat 136 in the surface 17 of probe collar 12. Probe
drill collar 12
includes a draw down cover 76 for protecting other devices associated with the
formation
probe assembly 50 mounted in the collar 12, such as draw down pistons (not
shown).
As best shown in Figure 5, it can be seen how formation probe assembly 50 and
equalizer valve 60 are positioned in probe collar 12. Formation probe
asseinbly 50 and
equalizer valve 60 are mounted in probe collar 12 just above the flowbore 14.
F16wbore 14
inay be deviated from the center longitudinal axis 12a of probe collar 12, or
from other
portions 14b, 14c of flowbore 14, to accommodate at least formation probe
assembly 50. For
exainple, in Figure 5, flowbore portion 14a is offset radially from the
longitudinal axis 12a,
and also from the flowbore portion 14b via transition flowbore portion 14c.
Also shown are
draw down piston asseinblies 70, 72 and draw down shutoff valve 74.
The details of a first embodiunent of formation probe asseinbly 50 are best
shown in
Figure 6A-6B. In Figure 6A, fonnation probe assembly 50 is retained in probe
collar 12 by
tlireaded engagement witli collar 12 and also by cover plate 51. Fonnation
probe assembly 50
generally includes stem 92, a generally cylindrical threaded adapter sleeve
94, piston 96
adapted to reciprocate witliin adapter sleeve 94, and a snorlcel assembly 98
adapted for
reciprocal inovement witliin piston 96. Probe collar 12 includes an aperture
90 for receiving
fonnation probe asseinbly 50. Cover plate 51 fits over the top of formation
probe assembly
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50 and retains and protects formation probe assembly 50 when the formation
probe assembly
50 is within probe collar 12. Formation probe assembly 50 may extend and
retract through
aperture 52 in cover plate 51.
Stem 92 includes a circular base portion 105 with an outer flange 106 having
stem
holding screw 97 (shown in figure 6B) for retaining stem 92 in aperture 90.
Extending from
base 105 is a tubular extension 107 having central passageway 108. The end of
extension 107
includes internal threads at 109. Central passageway 108 is in fluid
connection with fluid
passageway 91 (not shown, but seen schematically in Figure 9) that connects to
fluid
passageway 93 (not shown, but seen schematically in Figure 9) leading to other
portions of tool
10, including equalizer valve 60.
Adapter sleeve 94 includes inner end 111 that engages flange 106 of stem 92.
Adapter
sleeve 94 is secured within aperture 90 by threaded engagement with collar 12
at segment 110.
The outer end 112 of adapter sleeve 94 may extend to be substantially flushed
with recess 55
formed in collar 12 for receiving cover plate 51. Outer end 112 also includes
flange 158 for
engaging recess 162 of cover plate 51. Adapter sleeve 94 includes cylindrical
inner surface
113 having reduced diameter portions 114, 115. A seal 116 is disposed in
surface 114.
Piston 96 is slidingly retained within adapter sleeve 94 and generally
includes
cylindrical outer surface 141 having an increased diameter base portion 118. A
seal 143 is
disposed in increased diameter portion 118. Just below base portion 118,
piston 96 may rest on
flange 106 of stem base portion 105 while formation probe assembly 50 is in
the fully retracted
position as shown in Figure 6A. Piston 96 may also include cylindrical inner
surface 145
having reduced diameter portion 147. Piston 96 may further include central
bore 121 having a
bore surface 120 and extending through upper extending portion 119.
Referring to Figure 6B, at the top of extending portion 119 of piston 96 is a
seal pad
180. Seal pad 180 may be donut-shaped with a curved outer sealing surface 183
and central
aperture 186. However, seal pad 180 may include numerous other geometries as
is known in
the art, or, for example, as is seen in U.S. Patent Publication No.
2005/0072565 published on
April 7, 2005 and entitled "MWD Formation Tester." Base surface 185 of seal
pad 180 may be
coupled to a skirt 182. Seal pad 180 may be bonded to skirt 182, or otherwise
coupled to skirt
182, such as by molding seal pad 180 onto skirt 182 such that the seal pad
material fills
grooves or holes in skirt 182, as can be seen in U.S. Patent Publication No.
2005/0072565.
Skirt 182 is detachably coupled to extending portion 119 by way of threaded
engagement with
surface 120 of central bore 121 (see Figure 6A), or other means of engagement,
such as a
pressure fit with central bore
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surface 120. Because the seal pad/skii-t combination may be detachable from
extending
portion 119, it is easily replaced in the field. Alternatively, seal pad 180
may be coupled
directly to extending portion 119 without using a slcirt.
Seal pad 180 is preferably inade of an elastomeric material. Seal pad 180
seals and
prevents drilling fluid or other contaminants from entering the formation
probe assembly 50
during fonnation testing. More specifically, seal pad 180 may seal against the
filter cake that
may foim on a borehole wall. Typically, the pressure of the formation fluid is
less than the
pressure of the drilling fluids that are injected into the borehole. A layer
of residue from the
drilling fluid forms a filter cake on the borehole wall and separates the two
pressure areas.
Seal pad 180, when extended, may conform its shape to the borehole wall and/or
mud calce
and forms a seal through which fonnation fluids can be collected alid/or
formation properties
measured.
Iii an altenzative embodiment of the seal pad 180, the seal pad 180 may have
an
internal cavity such that it can retain a voluine of fluid. A fluid may be
pumped into the seal
pad cavity at variable rates such that the pressure in the seal pad cavity may
be increased and
decreased. Fluids used to fill the seal pad may include hydraulic fluid,
saline solution or
silicone gel. By way of example, the seal pad may be emptied or unpressured as
the probe
extends to engage the borehole wall. Depending on the contour of the borehole
wall, the seal
pad may be pressured by filling the seal pad witlz fluid, thereby conforming
the seal pad
surface to the contour of the borehole wall and providing a better seal.
In yet another embodiment of the seal pad, the seal pad may be filled, either
before or
after engagement witll the borehole wall, with an electro-rheological fluid.
An electro-
rlieological fluid may be an insulating oil containing a dispersion of fine
solid particles, for
example, 5 m to 50 m in diaineter. Such an electro-rheological fluid is well
luiown in the
art. When subjected to an electric field, tlieses fluids develop an increased
shear stress and an
increased static yield stress that make them more resistant to flow. This
change of fluid
properties is evident, for example, as an increase in viscosity, most notably
the plastic
viscosity, when the electric field is applied. The fluid in the seal pad may
effectively become
seini-solid. The seini-solid effect is reversed when the fluid is no longer
subjected to the
electric field. Iii the absence of the electric field, the electro-rheological
fluid that may fill the
seal pad becomes less viscous, causing the seal pad to conform to the contour
of a borehole
wall. Once the seal pad has conformed to the borehole wall, an electric field
may be applied
to the electro-rheological fluid inside the seal pad, causing an increase in
fluid viscosity, a
stiffening of the seal pad, and a better seal.
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Still referring to Figure 6B, snorlcel assembly 98 includes a base portion
125, a snorlcel
extension 126, and a central passageway 127 extending through base 125 and
extension 126.
Base portion 125 may include a cylindrical outer surface 122 and inner surface
124.
Extension 126 inay include a cylindrical outer surface 128 and inner surface
138. Disposed
inside the top of extension 126 is a screen 100. Screen 100 is a generally
tubular member
having a central bore 132 extending between a fluid inlet end 131 and fluid
outlet end 135.
Screen 100 further includes a flange 130 adjacent to fluid inlet end 131 and
an internally
slotted seginent 133 having slots 134. Between slotted segment 133 and outlet
end 135,
screei1.100 includes threaded seginent 137 for threadedly engaging snorkel
extension 126.
Tlireaded to the bottom of base portion 125 of snorkel 98 is scraper tube
keeper 152
having a circular base portion 154 with flange 153, a tubular extension 156
having a central
passageway 155 and a central aperture 157 for receiving stem extension 107.
Just below
scraper tube keeper 152 is retainer ring 159, which provides seated engagement
witli snorkel
98 such that the movement of snorkel 98 is limited in the retract direction.
Scraper tube
keeper 152 supports scraper tube 150 when scraper tube 150 is in the retracted
position shown
in Figure 6B. Scraper tube 150 having central passageway 151 extends up from
scraper tube
keeper 152 and through passageway 127 of snorkel 98. Coupled at the top of
scraper tube
150 is scraper or wiper 160. Scraper 160 is threadedly engaged with scraper
tube 150 at
tlu-eaded segment 161. Scraper 160 is a generally cylindrical member including
scraper plug
portion 163, central bore 164 and apertures 166 that are in fluid
coinmunication with central
bore 164. Scraper 160 is disposed within central bore 132 of screen 100 and
may be actuated
back and forth (or reciprocal) between screen inlet end 131 and outlet end
135. When scraper
tube 150 and scraper 160 are in their retracted positions, as shown in Figure
6B, apertures 166
are in fluid cormnunication with fluid outlet end 135 of screen 100, thereby
allowing fluid to
pass from screen 100, through scraper bore 164, and into central passageway
155 of scraper
tube 150. Scraper or wiper 160 is thus configured to be a moveable or floating
scraper.
In an alternative embodiment of the scraper 160 within the screen 100, the
actuation
of scraper 160 may be a rotational movement around the longitudinal axis of
scraper 160.
This rotational movement may be in place of the reciprocal movement, or in
addition to the
reciprocal movement.
As shown in Figure 6B, a connector 176 is disposed in aperture 178 of probe
collar
12, just beneatli ituier end 111 of sleeve 94. Contact lead 175 electrically
connects connector
176, via a wire, to a contact assembly (not shown) preferably disposed in
flange 106 of stem
base portion 105 so that the contact asseinbly can be in direct contact with
base portion 118 of
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piston 96. Figures 8A-8B show the details of comiector 176 and contact
assembly 310, with
the surrounding structures shown in a more general fashion such that the
different parts of
foimation probe assembly 50a generally correspond witli similar parts of
formation probe
asseinbly 50 of Figures 6A-6B.
RefeiTing first to Figure 8A, connector 176a is disposed in aperture 178a in
probe
collar 12a. Contact lead 175a is coupled to wire 300, which extends through
recess 301 in
collar 12a to openin.g 305 in base portion 105a of stein 92a. From opening
305, wire 300
extends througll base portion 105a to a cavity 307, where contact assembly 310
is disposed.
Referring now to Figure 8B, wire 300 leads into contact assembly 310. Contact
assembly 310 generally includes housing 316 having aperture 317, a conductive
contact body
312 having a flange 314 and a central bore 319, a stripped end 318 of wire 300
extending into
and soldered to bore 319, a non-conductive spring support 322, and wave
springs 324. The
flange 314 of body 312 is disposed between the upper portion of housing 316
and the lower
portion of spring support 322. Disposed between spring support 322 and flange
314 are wave
springs 324, which are supported by lower plate 326 and upper plate 328.
Springs 324
provide an upward force on flange 314 such that top surface 313 of body 312
extends out of
aperttue 317 such that top surface 313 protrudes out of cavity 307. As
formation probe
asseinbly 50a is retractiuig, piston 96a comes into contact with and presses
downward on
surface 313 of body 312, causing springs 324 to compress and bottom surface
315 to move
downward into space 324. When piston 96a contacts surface 313 of body 312, an
electric
circuit is completed to ground (not shown) through piston 96a, providing a
signal to the tool
electronics (not shown) that fornzation probe assembly 50a has been fully
retracted. After
piston 96a makes contact with surface 313 of body 312, piston 96a continues to
travel until
making contact with base portion 105a of stem 92a. Heat shrink 320 is shrunk
in place over
wire 300 for mechanical protection.
Referring now to Figures 6A and 6B, formation probe asseinbly 50 is assembled
such
that piston base 118 is permitted to reciprocate along surface 113 of adapter
sleeve 94, and
piston outer surface 141 is permitted to reciprocate along surface 114.
Similarly, snorkel base
125 is disposed within piston 96 and is adapted for reciprocal inovement along
surface 147
while flange 153 of scraper tube keeper 152 reciprocates along surface 145.
Snorkel
extension 126 is adapted for reciprocal moveinent along piston surface 120.
Central
passageway 127 of snorkel 98 is axially aligned with tubular extension 107 of
stem 92,
scraper tube keeper 152, scraper tube 150, scraper 160 and with screen 100.
Formation probe
asseinbly 50 is reciprocal between a fully retracted position, as shown in
Figure 6A, and a
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fully extended position, as shown in Figure 6B. Also, scraper tube 150 is
reciprocal between
a fi.illy retracted position, as shown in Figures 6A-6B, and a fully extended
position, as is
illustrated by a similar scraper tube 278 in Figures 7A-7E. When scraper tube
150 is fully
retracted, fluid may be communicated between central passageway 108 of
extension 107,
passageway 155 of scraper tube keeper 152, passageway 151 of scraper tube 150,
scraper bore
164, scraper apertures 166, screen 100, and the surrounding environment 15.
Witli reference to Figures 6A and 6B, the operation of formation probe
assembly 50
will now be described. Formation probe assembly 50 is normally in the
retracted position.
Formation probe assembly 50 reinains retracted when not in use, such as when
the drill string
is rotating wliile drilling if formation probe assembly 50 is used for an MWD
application, or
when the wireline testing tool is being lowered into borehole 8 if formation
probe assembly
50 is used for a wireline testing application. Figure 6A shows fonnation probe
assembly 50
in the fully retracted position, except that scraper tube 150 is shown in the
retracted position,
and scraper tube 150 is typically extended when formation probe assembly 50 is
in this
position, as shown in Figures 7A-7E. Figures 7A-7F will be referred to in
describing the
operation of formation probe assembly 50 because the structures of formation
probe assembly
50 previously described are similar to corresponding parts of probe asseinbly
200 seen in
Figi.tres 7A-7F.
Fonnation probe assembly 50 typically begins in the retracted position, as
shown in
Figure 6A. Upon an appropriate coininand to formation probe assembly 50, a
force is applied
to base portion 118 of piston 96, preferably by using hydraulic fluid. Piston
96 extends
relative to the other portions of fonnation probe assembly 50 until retainer
ring 159 engages
flange 153 of scraper tube keeper 152. This position of piston 96 relative to
snorlcel assembly
98 can be seen in Figure 7B. As hydraulic fluid continues to be pumped into
hydraulic fluid
reservoir 54, piston 96 and snorkel assembly 98 continue to move upward
together. Base
portion 118 slides along adapter sleeve surface 113 until base portion 118
coiues into contact
with shoulder 170. After such contact, formation probe assembly 50 will
continue to
pressurize reservoir 54 until reservoir 54 reaches a certain pressure Pi.
Alternatively, if seal
pad 180 comes into contact with a borehole wall before base portion 118 comes
iuzto contact
witli shoulder 170, formation probe assembly 50 will continue to apply
pressure to seal pad
180 by pressurizing reservoir 54 up to the pressure P1. The pressure P1
applied to formation
probe assembly 50, for exa.inple, may be 1,200 p.s.i.
The contuiued force from the lzydraulic fluid in reservoir 54 causes snorkel
assembly
98 to extend such that the outer end of snorkel extension 126, inlet end 131
of screen 100 and
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the top of scraper 160 extend beyond seal pad surface 183 through seal pad
aperture 186.
This snorkel extending force must overcome the retract force being applied on
the retract side
of snorlcel base portion 125 facing piston shoulder 172. Previously, the
retract force,
provided by retract accumulator 424 and the retract valves, was greater tha.ii
the extend force,
thereby maintaining snorkel 98 in the retract position. However, the extend
force continues
to increase until it overcomes the retract force at, for example, 900 p.s.i.
Snorkel assembly 98
stops extending outward when snorkel base portion 125 comes into contact with
shoulder 172
of piston 96. Scraper tube 150 and scraper 160 are still in the extended
position, as is best
shown with the snorkel assembly and piston configuration of Figure 7E.
Altei7iatively, if snorkel asseinbly 98 comes into contact with a borehole
wall before
snorkel base portion 125 comes into contact with shoulder 172 of piston 96,
continued force
from the hydraulic fluid pressure in reservoir 54 is applied up to the
previously mentioned
inaximuin pressure. The maximum pressure applied to snorkel assembly 98, for
example,
may be 1,200 p.s.i. Preferably, the snorkel and seal pad will contact the
borehole wall before
either piston 96 or snorkel 98 shoulders at full extension. Then, the force
applied on the seal
pad is reacted by stabilizer 36, or other similar device disposed on or near
probe collar 12.
If, for exainple, seal pad 180 had made contact with the borehole wall 16
before being
fi.illy extended and pressurized, then seal pad 180 should seal against the
mudcake on
boreliole wall 16 through a combination of pressure and seal pad extrusion.
The seal
separates snorkel assembly 98 from the mudcake, drilling fluids and other
contaminants
outside of seal pad 180. As the snorkel assembly extends, snorkel extension
126, screen inlet
end 131 and the top of scraper 160 pierce the mudcalce that has been sealed
off, an.d
preferably go through the entire mudcake layer and into formation 9.
Witli screen 100 and scraper 160 extended, the piston 96 and snorkel 98
assembly
configtiration looks similar to the piston and snorkel configuration shown in
Figure 7E.
While extending snorkel extension 126 into the mudcalce and formation,
contaminants and
debris tend to gather on screen 100 which can affect the sampling of formation
fluids. To
clear the debris, which may be mudcalce or other contaminants from previous
sampling
procedures, scraper 160 may be retracted after snorkel assembly 98 has been
extended. A
downward retract force is applied to scraper tube 150, preferably by applying
a hydraulic fluid
force downward on flange 177 of scraper tube 150. The cavity formed by scraper
tube 150
and snorkel surface 124 fills with llydraulic fluid as scraper tube 150 moves
downward, until
scraper ttibe 150 bottoms out on scraper tube keeper 152. As scraper 160 is
drawn witliin
snorkel extension 126 during this process, scraper 160 passes through screen
100 while also
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frictionally engaging screen 100, thereby agitating and removing debris that
has gathered on
screen 100. Alternatively, as previously described, debris agitation may be
achieved with
rotational inovement of scraper 160 about its longitudinal axis within screen
100. When
scraper tube 150 is fully retracted, apertures 166 radially align with outlet
end 135 of screen
100 such that fluid coirnnunication is possible between bore 132 of screen 100
and
passageway 151 of scraper tube 150. This scraper 160 action that removes
debris is
preferably perfonned as part of the formation probe asseinbly 50 retract
sequence, as
described below.
To retract fonnation probe assembly 50, forces, or pressure differentials, may
be
applied to snorkel 98 and piston 96 in opposite directions relative to the
extending forces.
Siinultaneously, the extending forces may be reduced or ceased to aid in probe
retraction. A
hydraulic force is applied to snorkel base portion 125 at shoulder 172 to push
snork-el
asseinbly 98 down until flange 153 of scraper tube keeper 152 sits on retainer
ring 159,
thereby fully retracting snorkel assembly 98. Concuirently, a hydraulic force
is applied
downward on piston base portion 118 at shoulder 170 until base portion 118
bottoms out on
stein base portion 105, thereby fully retracting fornnation probe assembly 50.
When piston 96
contacts stem base portion 105, probe retract switch 176 is triggered as
described above,
signaling a successful retraction of fonnation probe assembly 50. Scraper 160
may be
exteilded to its original position at any time during retraction. When the
extend pressure on
tlie probe asseinbly, which provides the retract pressure for the scraper
assembly because the
probe assembly extend portions are hydraulically coupled to the scraper
assembly retract
portions, falls below the extend pressure on the scraper assembly, scraper 160
is extended.
Another einbodiment of the present invention is shown in Figures 7A-7F. Probe
collar 202 having flowbore 14a houses telescoping formation probe assembly
200. Probe
asseinbly 200, as coinpared to formation probe assembly 50, extends to reach a
borehole wall
that is fi.irther displaced from collar 202. Such borehole walls that may be
displaced further
fiom collar 12 may be found in washed out portions of a well, irregular holes
in the well,
wells drilled with hole openers or near bit reamers or large wells drilled
with bi-center bits.
Telescoping probe assembly 200 is useful in reaching a borehole wall in these
types of wells.
Telescoping probe assembly 200 generally includes stem plate 210, stem 212, a
generally cylindrical threaded adapter sleeve 220, an outer piston 230 adapted
to reciprocate
within adapter sleeve 220, a piston 240 adapted to reciprocate within outer
piston 230, and a
snorkel assembly 260 adapted for reciprocal movement within piston 240. Probe
collar 202
inch.ides an aperture 204 for receiving telescoping formation probe assembly
200. Cover
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plate 206 fits over the top of probe assembly 200 and retains and protects
assembly 200
within probe collar 202. Fonnation probe assembly 200 is configured to extend
through
aperhue 208 in cover plate 206.
Referring first to Figure 7A, adapter sleeve 220 includes inner end 221 near
the
bottom 207 of aperture 204. Adapter sleeve 220 is secured within aperture 204
by threaded
engageinent with collar 202 at segment 209. The outer end 223 of adapter
sleeve 220 extends
to be substantially flushed with opening 205 of aperture 204 formed in collar
202. Outer end
223 includes flanges 225 for engaging cover plate 206. Adapter sleeve 220
includes
cylindrical inner surface 227 having reduced diameter portion 226. A seal 229
is disposed in
surface 226.
Referring next to Figure 7B, stem plate 210 includes a circular base portion
213 with
an outer flange 214. Extending from base 213 is a short extension 216.
Extending through
extension 216 and base 213 is a central passageway 218 for receiving the lower
end 215 of
stem 212 having central passageway 203. Lower end 215 threadedly engages stem
plate
passageway 218. Central passageway 218 is in fluid connection with fluid
passageway 91
(not shown, but seen schematically in Figure 9) that connects to fluid
passageway 93 (not
shown, but seen scliematically in Figure 9) leading to other portions of tool
10, including
equalizer valve 60. Stem 212 extends up through the center of probe assembly
200.
Disposed about stem 212 is outer stem 219. Threadedly engaged at the top of
outer stem 219
is outer stem capture screw 222 having central bore 224.
Referring again to Figure 7B, outer piston 230 is slidingly retained within
adapter
sleeve 220 and generally includes cylindrical outer surface 232 having an
increased diameter
base portion 234. A sea1235 is disposed in increased diaineter portion 234.
Outer piston 230
also includes cylindrical inner surface 236 having reduced diaineter portions
237, 238 at
upper extending portion 233. A seal 239 is disposed in surface 237.
Referring now to Figure 7C, piston 240 is slidingly retained within outer
piston 230
and generally includes cylindrical outer surface 242 having an increased
diameter base
portion 244. A seal 245 is disposed in increased diameter portion 244. Just
below base
portion 244, piston 240 rests on capture sleeve 254 which is engaged with base
portion 234 of
outer piston 230. Retainer ring 256 is engaged at the bottom of capture sleeve
254 and holds
the capture sleeve in position. Piston 240 also includes cylindrical inner
surface 246 having
reduced diaineter portion 248. Piston 240 fiirtller includes central bore 249
having bore
surface 241 and extending tlirough upper extending portion 250.
CA 02559248 2008-06-06
At the top of extending portion 250 of piston 240 is a seal pad 280. As shown
in
Figures 7A-7F, seal pad 280 may be donut-shaped with a curved outer surface
283 and central
aperture 286. However, seal pad 280 may include numerous other geometries as
is known in
the art, or, for example, as is seen in U.S. Patent Publication No.
2005/0072565 published on
April 7, 2005 and entitled "MWD Formation Tester." Base surface 285 of seal
pad 280 may be
coupled to a skirt 282. Seal pad 280 may be bonded to skirt 282, or otherwise
coupled to skirt
282, such as by molding seal pad 180 onto skirt 282 such that the seal pad
material fills
grooves or holes in skirt 282, as can be seen in U.S. Patent Publication No.
2005/0072565.
Skirt 282 is detachably coupled to extending portion 250 by way of threaded
engagement with
surface 241 of central bore 249, or other means of engagement, such as a
pressure fit with
central bore surface 241. Because the seal pad/skirt combination is detachable
from extending
portion 250, it is easily replaced in the field. Alternatively, seal pad 280
may be coupled
directly to extending portion 250 without using a skirt. Other characteristics
of seal pad 280,
such as seal pad material and the way seal pad 280 functions, are similar to
the previously
described seal pad 180.
Referring now to Figure 7D, snorkel 260 includes a base portion 262, a snorkel
extension 266, and a central passageway 264 extending through base 262 and
extension 266.
Base portion 262 includes a cylindrical outer surface 268 and inner surface
269. Extension 266
includes a cylindrical outer surface 263 and inner surface 265. Disposed
inside the top of
extension 266 is a screen 290, best shown in Figure 7F. Screen 290 is a
generally tubular
member having a central bore 292 extending between a fluid inlet end 294 and
fluid outlet end
296. Screen 290 further includes a flange 298 adjacent to fluid inlet end 294
and an internally
slotted segment 293 having slots 295. Between slotted segment 293 and outlet
end 296, screen
290 includes threaded segment 297 for threadedly engaging snorkel extension
266.
Threaded to the bottom of base portion 262 of snorkel 260 is scraper tube
keeper 270
having a circular base portion 272 and retaining edge 273, a tubular extension
274 having a
central passageway 275 and a central aperture 271 for receiving outer stem
219. Outer stem
219 includes central passageway 243. A retainer ring 277 is radially aligned
and engageable
with retaining edge 273, which limits the movement of snorkel 260 in the
retract direction.
After snorkel 260 has been extended, retainer ring 277 is disposed below
scraper tube keeper
270 in piston surface 246, as can be seen in Figure 7E. Scraper tube keeper
270 supports
scraper tube 278 when scraper tube 278 is in the retracted position shown in
Figure 7F, and
isolates the hydraulic fluid reservoir formed by tubular extension 274 and
snorkel surface 269.
Scraper tube 278 having central passageway 279 is slidingly retained above
scraper tube
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WO 2005/114134 PCT/US2005/018123
keeper 270 in passageway 264 of snorkel 260. Coupled at the top of scraper
tube 278 is
scraper 288. Scraper 288 is threadedly engaged with scraper tube 278 at
threaded segment
281. Scraper 288 is a generally cylindrical member including scraper plug
portion 284,
central bore 287 and apertures 289 that are in fluid communication with
central bore 287.
Scraper 288 is disposed within central bore 292 of screen 290 and is
reciprocal between
screen inlet end 294 and outlet end 296; alternatively, as previously
described, scraper 288
may be rotatable within screen 290. When scraper tube 278 and scraper 288 are
in their
retracted positions, as shown in Figure 7F, apertures 289 are in fluid
communication with
fluid outlet end 296 of screen 290, thereby allowing fluid to pass fiom screen
290, through
scraper bore 287, and into central passageway 279 of scraper tube 278.
Referring baclc to Figure 7B, a probe retract switch connector 276 is disposed
in
aperture 278 of probe collar 202, just beneath inner end 221 of sleeve 220.
The details of
switch comlector 276 are similar to the previously described switch 176,
above, with
reference to figures 8A-8B. Although not shown, switch and connector 276 are
electrically
coupled to a contact asseinbly disposed in stem base portion 213. The contact
assembly
contacts piston 240 when piston 240 is bottomed out on stem base portion 213
indicating to
the tool electronics that probe assembly 200 is fully retracted.
Fonnation probe assembly 200 is assembled such that outer piston base 234 is
permitted to reciprocate along surface 227 of adapter sleeve 220, and outer
piston surface 232
is pennitted to reciprocate along surface 226. Similarly, piston base portion
244 is permitted
to reciprocate along outer piston iiuler surface 236, and piston surface 242
is permitted to
reciprocate along outer piston surface 237. Snorkel base portion 262 is
disposed within
piston 240 and is adapted for reciprocal movement along surface 248 while
retaining edge
273 of scraper tube keeper 270 reciprocates between retainer ring 277 and
decreased diameter
portion 248. Snorkel extension 266 is adapted for reciprocal movement along
piston surface
241. Central passageway 264 of snorkel 260 is axially aligned with stem 212,
outer stem 219,
scraper tube keeper 270, scraper tube 278, scraper 288 and with screen 290.
Formation probe
assembly 200 is reciprocal between a fiilly retracted position, as shown in
Figure 7A, and a
ftilly extended position, as shown in Figure 7F. Also, scraper tube 278 is
reciprocal between
a fiilly extended position, as shown in Figures 7A-7E, and a fiilly retracted
position, as is
illustrated in Figure 7F. When scraper tube 278 is fiilly retracted, fluid may
be communicated
between central passageway 203 of stem 212, passageway 243 of outer stem 219,
passageway
275 of scraper tube keeper 270, passageway 279 of scraper tube 278, bore 287
of scraper 288,
scraper apertures 289, screen 290, and the surrounding enviromnent 15.
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WO 2005/114134 PCT/US2005/018123
With reference to Figures 7A-7F, the operation of formation probe assembly 200
will
now be described. Fonnation probe assembly 200 typically begins in the
retracted position,
as shown in Figure 7A. Assembly 200 remains retracted when not in use, such as
when the
drill string is rotating while drilling if asseinbly 200 is used for an MWD
application, or wllen
the wireline testing tool is being lowered into - borehole 8 if asseinbly 200
is used for a
wireline testing application. Figure 7A shows assembly 200 in the fully
retracted position,
with scraper tube 278 in the extended position.
Upon an appropriate comma.nd to probe assembly 200, a force is applied to base
portion 234 of outer piston 230, preferably by using hydraulic fluid. Outer
piston 230 raises
relative to adapter sleeve 220, with outer piston base portion sliding along
sleeve surface 227.
Retainer ring 256 and capture sleeve 254 force piston 240 upward along with
outer piston 230
by pressing on piston base portion 244. As seen in Figure 7B, snorkel 260
remains seated on
stem plate 210 while outer piston 230 and piston 240 begin to rise, until
retainer ring 277
contacts retaining edge 273 of scraper tube keeper 270. At this point, the
upward hydraulic
force continues to be applied to the reciprocal parts of assembly 200, and
fluid reservoir 334
enlarges and fills until outer piston base portion 234 seats on adapter sleeve
shoulder 332, as
sliown in Figure 7C. Then hydraulic fluid is directed into reservoir 336,
causing piston 240
a. d snorkel 260 to extend out, with piston base portion 244 sliding along
outer piston surface
236. Finally, piston base portion 244 seats on outer piston shoulder 342, as
shown in Figure
7D. Once again, typically, snorlcel 260 and seal pad 280 (Figure 7C) contact
the borehole
wall prior to reaching full extension, as previously described. The tool
stabilizer, or otlier
such device, will react the probe extension force.
Before reaching the position shown in Figure 7D, seal pad 280 is preferably
engaged
with the boreliole wall (not shown). To form a seal with seal pad 280, probe
assembly 200
will continue to pressurize the reservoirs 334, 336 until the reservoirs reach
a maximum
pressLUe. Altematively, if seal pad 180 comes into contact with the borehole
wall before
probe asseinbly 200 is fiilly extended, probe assembly 200 will continue to
apply pressure to
seal pad 280 up to the previously mentioned maximuin pressi.ire. The maximiun
pressure
applied by probe assembly 200, for example, may be 1,200 p.s.i.
As liydraulic fluid continues to be pumped through reservoirs 334, 336,
snorkel 260
slides along surfaces 248, 241 as hydraulic fluid is directed into reservoir
338 and this snorkel
extend force increases. This snorkel exteiiding force must overcome the
retract force being
applied on the retract side of snorkel base portion 262 facing piston shoulder
352. Previously,
the retract force, provided by retract accumulator 424 and the retract valves,
was greater than
18
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WO 2005/114134 PCT/US2005/018123
the extend force, thereby maintaining snorkel 260 in the retract position.
However, the
extend force continues to increase until it overcomes the retract force at,
for example, 900
p.s.i. Snorkel base portion 262 finally seats on piston shoulder 352, as shown
in Figure 7E.
Snorlcel 260 has extended such that the outer end of snorkel extension 266,
inlet end 294 of
screen 290 and the top of scraper 288 extend beyond seal pad surface 283
through seal pad
aperture 286. Scraper tube 278 and scraper 288 are still in the extended
position, as seen in
Figure 7E. If seal pad 280 is engaged with the borehole wall, snorkel
extension 266, screen
inlet end 294 and the top of scraper 288 pierce the mudcake that has been
sealed off, and
preferably go through the entire inudcake layer and into formation 9.
As previously described, extending snorkel extension 266 into the mudcake and
fonnation causes contaninants and debris to gather on screen 290, which can
affect the
sainpling of formation fluids. Floating scraper 288 is used to clear the
debris in a similar
fashion to that described with respect to formation probe asseinbly 50. A
downward force is
applied to scraper tube 278, preferably by applying a hydraulic fluid force
downward on
flange 372 of scraper tube 278. The cavity formed by scraper tube 278 and
inner snorkel
surface 269 fills with hydraulic fluid as scraper tube 278 moves downward,
until tube flange
372 seats on scraper tube keeper 270. As scraper 288 is drawn within snorkel
extension 266
during this process, scraper 288 passes through screen 290, agitating and
removing debris that
has gathered on screen 290 through frictional engagement between scraper 288
and screen
290, as previously described. Also previously described was an alternative
embodiment
including a rotating screen 290, equally applicable here. When scraper tube
278 is fully
retracted, apertures 289 radially align witlz screen outlet end 296 suclz that
fluid
communication is possible between screen bore 292 and passageway 279 of
scraper tube 278.
This scraper 288 action that removes debris is preferably performed as part of
the formation
probe assembly 200 retract sequence, as described below.
To retract probe assembly 200, forces, or pressure differentials, may be
applied to
probe assembly 200 in opposite directions relative to the extending forces.
Simultaneously,
the extending forces may be reduced or ceased to aid in probe retraction.
First, and
preferably, a pressure differential is applied across flailge 372 of scraper
tube 278 by
increasing the hydraulic flr.iid pressure on the bottom of flange 372. This
extends scraper tube
278 until scraper 288 is fully extended once again, wiping screen 290 cleal as
scraper 288
passes tluough it. Next, a lrydraulic force is applied to snorkel base portion
262 at shoulder
352 to push snorlcel assembly 260 down imtil retaining edge 273 of scraper
tube keeper 270
sits on retainer ring 277, thereby fully retracting snorkel assembly 260.
Next, a hydraulic
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WO 2005/114134 PCT/US2005/018123
force is applied downward on piston base portion 244 at shoulder 342 until
base portion 244
seats on capture sleeve 254 and retainer ring 256 adjacent outer piston base
portion 234.
From this position, a hydraulic fluid is inserted at adapter sleeve slloulder
332 onto outer
piston base portion 234 to force outer piston 230 downward. Outer piston 230
then seats on
bottom 207 of aperture 204, and the piston 240/snorke1260 assembly seats on
stem plate 210,
thereby fully retracting probe asseinbly 200. When piston 240 contacts stem
plate 210, probe
retract switch 276 is triggered as described above, signaling a successful
retraction of
assembly 200.
It is noted that fonnation probe assembly 50 may only extend the outer end of
piston
extending portion 119 past the outer end of sleeve 94 a distance that is less
than the length of
piston 96. The length of piston 96 is defined as the distance between the
uppennost end of
extending portion 119 and the lowennost end of base portion 118. In
coinparison, probe
asseinbly 200 may extend the outer end of piston upper portion 250 past the
outer end of
sleeve 220 a distance that exceeds the length of piston 240. Therefore, the
telescoping feature
of probe assembly 200, i.e., the concentric pistons 230, 240, allows seal pad
280 to engage a
borehole wall that is significantly fiuther from collar 202 than the length of
piston 240.
Refen-ing now to Figure 14, an example of how the probe asseinblies may be
used to
test a fonnation will be described. The test sequence 700 may begin (box 702)
upon a
coinmand to the tool 10 from the surface of the borehole, for example, or from
embedded tool
software. In a first embodiment, piston 96 and seal pad 180 maybe extended
(box 704). In a
fiirther enibodiment, piston 230 may be extended (box 703) to provide the
telescopic effect
previously described. The borehole wall is contacted by seal pad 180 (box
706). Next, a
volume surrounding snorkel 98 is sealed (box 708). In a further embodiment,
seal pad 180
may be filled with a fluid (box 707), as previously described. Continuing with
the sequence
700, snorkel 98 may be extended (box 710), and the borehole wall contacted by
snorlcel 98
(box 712). Scraper 160 n-iay now be retracted (box 714), causing agitation and
removal of
contanlinants from snorlcel 98. A formation property may then be measured (box
716). In a
fiirther embodimeilt, contaminants may be filtered (box 715), such as by a
screen 100. After
ineasLuing a formation property, snorkel 98 is retracted (box 718), piston 96
and seal pad 180
are retracted (box 720), and scraper 160 is extended (box 722). The extension
of scraper 160
may also seive to remove containinants from snorkel 98. Sequence 700 ends (box
724) with
a fonnation property having been measured for uses fitrther described herein.
Iii an alteniative einbodiment of tool 10, fonnation probe assemblies 50, 200
may be
located elsewhere in the tool. Referring now to Figure 3B, formation probe
assembly 50 may
CA 02559248 2008-06-06
instead be disposed in blade 37 of stabilizer 36. Equalizer valve 60, shutoff
valve 74 and draw
down pistons 70, 72 may remain in the same position as shown in Figure 3B,
although it is
preferred that they be in closer proximity to formation probe assembly 50, and
therefore may
be moved closer to stabilizer 36. Locating formation probe assemblies 50, 200
in stabilizer
blade 37 allows the assemblies to be placed closer to the borehole wall while
still mounted in a
robust portion of the tool. Further, the other blades of stabilizer 36 may be
used to back up
formation probe assemblies 50, 200 as they extend out and pressure up against
the borehole
wall.
Even if formation probe assemblies 50, 200 are not disposed in stabilizer 36,
the blades
of stabilizer 36 are preferably used to back up the extending formation probe
assemblies 50,
200. To provide a sufficient sealing force for the probe seal pad, a reactive
force must be
applied to the tool to counter the force of the extending probe.
Alternatively, if a stabilizer is
not used, centralizing pistons such as those illustrated and described in U.S.
Patent Publication
No. 2004/0011525 published on January 22, 2004 and entitled "Method and
Apparatus for
MWD Formation Testing", may be used.
With respect to any of the probe assembly embodiments described above, a probe
assembly position indicator may be included in the probe assembly to measure
the distance that
the probe assembly has extended from its fully retracted position. Numerous
sensors may be
used to detect the position of the probe assembly as it extends. In one
embodiment, the probe
assembly position indicator may be a measure of the volume of hydraulic fluid
used to extend
the probe assembly. If the probe assembly is configured to use hydraulic fluid
and pressure
differentials to extend, as is described in the embodiments above, the volume
of fluid pumped
into the probe assembly may be measured. With known diameters for the adapter
sleeves and
pistons, the distance that the pistons have extended may be calculated using
the volume of fluid
that has been pumped into the probe assembly. To make this measurement more
accurate,
certain characteristics of the probe assembly may be accounted for, such as
seal pad
compression as it compresses against the borehole wall.
In another embodiment of the probe assembly position indicator, an optical or
acoustic
sensor may be disposed in the probe assembly, such as in an aperture formed in
the piston
surface 141 of formation probe assembly 50, or piston surface 242 of probe
assembly 200. The
optical or acoustic sensor may measure the distance the piston moves from a
known reference
point, such as the piston position when the probe assembly is fully retracted.
Such devices are
well known to one skilled in the art.
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WO 2005/114134 PCT/US2005/018123
[0001] fi-i yet another embodiment, a potentiometer, resistance-measuring
device or other
such device well lu-iown to one skilled in the art may be used to detect
movement of the
reciprocating portions of the probe assemblies through electrical means. The
potentiometer
or resistance-measuring device may measure voltage or resistance, and such
infonnation can
be used to calculate distance.
The distance measurement gathered from the probe position indicator may be
used for
nuinerous purposes. For example, the borehole caliper may be calculated using
this
meastuement, thereby obtaining an accurate measurement of the borehole
diameter.
Alternatively, multiple probes may be spaced radially around the drill string
or wireline
instri.unent, and measurements may be taken with the multiple probes to obtain
borehole
diameter and shape. Having an accurate borehole caliper measurement allows the
driller to
lazow where borehole breakout or collapse may be occurring. The caliper
measurement may
also be used to help correct formation evaluation sensors. For example,
resistivity
measurements are affected by borehole size. Neutron corrections applied to a
neutron tool are
also affected, as well as density corrections applied to a density tool.
Ot1Zer sensor tools may
also be affected. An accurate borehole caliper measurement assists in
correcting these tools,
as well as any other drilling, production and completion process that requires
borehole size
characteristics, such as cementing.
hi another embodiment, the probe position indicator may be used to correct for
probe
flow line volume changes. Flow lines, such as flow lines 91, 93 in Figures 6A,
6B and 9, are
susceptible to volume changes as the probe seal pad compresses and
decompresses.
Particularly, when the seal pad is engaged with the boreliole wall and a
formation test is in
progress, the pressure from drawing down the formation fluids causes the seal
pad to
coinpress and the flow line vohune to increase. The flow line voluine is used
in several
fomiation calculations, such as mobility; permeability may then be calculated
using formation
fluid viscosity and density. To correct for this volume change and obtain an
accurate flow
line voluine measurement, probe positioning may be used. Further, although the
full flow
line volume is lcnown, if the probe does not fully extend before engaging the
borehole wall,
only a portion of the flow line voh.une is used and that quantity may not be
known.
Therefore, the probe position may be used to correct for the portion of the
flow line volume
that is not being used.
The embodinlents of the position indicator described above may also be applied
to the
draw down piston assemblies, described in more detail below, for knowing where
in the
cylinder the draw down piston is located, and how the piston is inoving.
Volume and
22
CA 02559248 2006-09-08
WO 2005/114134 PCT/US2005/018123
diaineter calculations may be used to obtain distance moved, or sensors may be
used as
described above. T11us, the exact distance the piston has moved may be
obtained, rather than
relying on the voluine of fluid used to actuate the piston as an indication of
distance moved.
Furtller, the steadiness of the draw down may be obtained from the position
indicator. The
rate may be calculated from the distance measured, and the steadiness of the
rate maybe used
to correct other measurements.
For example, to gain a better understanding of the formation's perrneability
or the
bubble point of the formation fluids, a reference pressure may be chosen to
draw down to, and
then the distance the draw down piston moved before that reference pressure
was reached
may be measured by the draw down piston position indicator. If the bubble
point is reached,
the distance the piston moved may be recorded and sent to the surface, or to
the software in
the tool, so that the piston may be commanded to move less and thereby avoid
the bubble
point.
Sensors intended for other purposes may also be disposed in the probe
assemblies.
For exainple, a temperature sensor, laiown to one skilled in the art, may be
disposed on the
probe asseinbly for taking annulus or formation temperature. In one
embodiment, the
teinperatiue sensor may be placed in the snorkel extensions 126, 266. In the
probe assembly
retracted position, the sensor would be adjacent the annulus environment, and
the aimulus
temperature could be taken. In the probe assembly extended position, the
sensor would be
adjacent the fonnation, allowing for a formation teinperature measurement.
Such temperature
measurements could be used for a variety of reasons, such as production or
completion
coniputations, or evaluation calculations such as permeability and
resistivity. These sensors
may also be placed adjacent the probe asseinblies, such as in the stabilizer
blades or
centralizing pistons.
Referring back to Figures 3B and 5, it can be seen that probe collar 12 also
houses
draw down piston assemblies 70, 72 and draw down shutoff valve assembly 74.
Referring
now to Figure 11, draw down piston assembly 70 generally includes aiinular
seal 502, piston
506, phuiger 510 and endcap 508. Piston 506 is slidingly received in cylinder
504 and
plunger 510, wllich is integral with and extends froin piston 506, is
slidingly received in
cylinder 514. hi Figure 11, piston 506 is in its drawn down position, but is
typically biased to
its uppermost or shouldered position at shoulder 516. A bias spring (not
shown) biases piston
506 to the shouldered position, and is disposed in lower cylinder portion 504b
between piston
506 and endcap 508. Separate hydraulic lines (not shown) intercomiect with
cylinder 504
above and below piston 506 in portions 504a, 504b to move piston 506 either up
or dovcni
23
CA 02559248 2006-09-08
WO 2005/114134 PCT/US2005/018123
within cylinder 504 as described more fully below. Plunger 510 is slidingly
disposed in
cyliizder 514 coaxial with cylinder 504. Cylinder 512 is the upper portion of
cylinder 514 that
is in fluid cominunication with the longitudinal passageway 93 (seen
schematically in Figure
9) that interconnects with draw down shutoff valve assembly 74, draw down
piston 72,
foi7nation probe asseinbly 50, 200 atid equalizer valve 60. Cylinder 512 is
flooded with
drilling fluid via its interconnection with passageway 93. Cylinder 514 is
filled with
1lydraulic fluid be.neath seal 513 via its interconnection with hydraulic
circuit 400.
Endcap 508 houses a contact switch (not shown) having a contact that faces
toward
piston 506. A wire 515 is coupled to the contact switch. A plunger 511 is
disposed in piston
506. When drawdown of piston assembly 70 is complete, as shown in Figure 11,
piston 506
actuates the contact switch by causing plunger 511 to engage the contact of
the contact
switch, which causes wire 515 to couple to system ground via the contact
switcli to plunger
511 to piston 506 to endcap 508 which is in communication with system ground
(not shown).
Referring to Figure 12, a second draw down piston assembly 72 is shown. Draw
down piston 72 is similar to piston 70, with the most notable difference being
that the draw
down volume is greater and the assembly does not include a bias spring. Draw
down piston
assembly 72 generally includes annular seal 532, piston 536, plunger 540 and
endcap 538.
Piston 536 is slidingly received in cylinder 534 and plunger 540, which is
integral with and
extends from piston 536, is slidingly received in cylinder 544. Plunger 540
and cylinder 544
have greater diameters than the corresponding portions of piston 70. In Figure
12, piston 536
is in its drawn down position, but is typically maintained at its uppermost or
shouldered
position at shoulder 546 by hydraulic force. Separate lrydraulic lines (not
shown)
intercorulect with cylinder 534 above and below piston 536 in portions 534a,
534b to move
piston 536 either up or down within cylinder 534 as described more fully
below. Plunger 540
is slidingly disposed in cylinder 544 coaxial with cylinder 534. Cylinder 542
is the upper
portion of cylinder 544 that is in fluid communication with the longitudinal
passageway 93
(seen schematically in Figure 9) that interconnects witli draw down shutoff
valve assembly
74, draw down piston 70, formation probe assembly 50, 200 and equalizer valve
60. Cylinder
542 is flooded with drilling fluid via its interconnection with passageway 93.
Cylinder 544 is
filled with hydraulic fluid beneath sea1543 via its interconnection witll
hydraulic circuit 400.
Endcap 538 houses a contact switch 548 having a contact 550 that faces toward
piston
536. A wire 545 is coupled to contact switch 548. A plunger 541 is disposed in
piston 536.
Wlien drawdown of piston asseinbly 72 is complete, as shown in Figure 12,
piston 536
actuates contact switch 548 by causing plunger 541 to engage contact 550,
which causes wire
24
CA 02559248 2006-09-08
WO 2005/114134 PCT/US2005/018123
545 to couple to system ground via contact switch 548 to plunger 541 to piston
536 to endcap
538 which is in communication with system ground (not shown).
It will be understood that the draw down pistons may vary in size such that
their
voluines vary. The pistons may also be configured to draw down at varying
pressures. The
enibodiment just described includes two draw down piston assemblies, but the
formation
tester tool may include more or less than two.
The hydraulic circuit 400 used to operate formation probe assemblies 50, 200,
equalizer valve 60 and draw down pistons 70, 72 is shown in Figure 9. A
microprocessor-
based controller 402 is electrically coupled to all of the controlled
eleinents in the hydraulic
circuit 400 illustrated in Figure 9, although the electrical connections to
such elements are
conventional and are not illustrated other than schematically. Controller 402
is located in
electronics module 20, shown in Figure 2A, although it could be housed
elsewhere in tool 10
or bottoin hole assembly 6. Controller 402 detects the control signals
transmitted fiom a
inaster controller 401 housed in the MWD sub 13 of the bottom hole assembly 6
which, in
turn, receives instructions transmitted from the surface via mud pulse
telemetry, or any of
various otller conventional means for transmitting signals to downliole tools.
When controller 402 receives a command to initiate fonnation testing, the
drill string
has stopped rotating if tool 10 is disposed on a drill sting. As shown in
Figure 9, motor 404 is
coupled to pump 406 which draws hydraulic fluid out of hydraulic reservoir 408
through a
serviceable filter 410. As will be understood, the pump 406 directs hydraulic
fluid into
hydraulic circuit 400 that includes fonnation probe assembly 50, 200 (either
can be used
interchangeably), equalizer valve 60, draw down pistons 70, 72 and solenoid
valves 412, 414,
416, 418, 420, 422. It will be understood that although the description below
will reference
only fonnation probe assembly 50, the hydraulic circuit described may be used
to operate
foianation probe asseinbly 50 or probe assembly 200.
The operation of formation tester 10 is best understood with reference to
Figure 9 in
conjunction witli Figures 6A-6B, 7A-F, 11 and 12. In response to an electrical
control signal,
controller 402 energizes retract solenoid valve 412 and valve 414, and starts
motor 404.
Ptunp 406 then begins to pressurize hydraulic circuit 400 and, more
particularly, charges
probe retract accumulator 424. The act of charging accumulator 424 also
ensures that the
forination probe assembly 50 is retracted, the equalizer valve 60 is open and
that draw down
pistons 70, 72 are in their initial shouldered position as described with
reference to Figures 11
and 12. When the pressure in system 400 reaches a predetermined value, such as
1800 p.s.i.
as sensed by pressure transducer 426a, controller 402 (which continuously
monitors pressure
CA 02559248 2006-09-08
WO 2005/114134 PCT/US2005/018123
in the system) energizes extend solenoid valve 416 which causes fonnation
probe assembly
50 to begin to extend toward the borehole wall 16. Concurrently, check valve
428 and relief
valve 429 seal the probe retract accumulator 424 at a pressure charge of
between
approximately 500 to 1250 p.s.i. Solenoid valve 412 is still energized.
Fonnation probe assembly 50 extends, as previously described, from the
position
shown in Figure 6A to a position before full extension as shown in Figure 6B
(except witli
snorkel still retracted), where seal pad 180 engages the mud cake 49 on
borehole wall 16. At
this point, retract solenoid valve 412 is de-energized, thereby allowing
snorkel 98 to be
extended and scraper 160 to be retracted. With hydraulic pressure continuing
to be supplied
to the extend side of piston 96 and snorkel 98 for formation probe assembly
50, the snorkel
may then penetrate the inud cake and the scraper retracted, as shown in Figure
6B (and
Figures 7E-7F for assembly 200). The outward extensions of pistons 96 and
snorkel 98
continue iu7til seal pad 180 engages the borehole wall 16, as previously
described with regard
to fonnation probe assembly 50. This combined motion continues until the
pressure pushing
against the extend side of piston 96 and snorkel 98 reaches a pre-determined
magnitude, for
exainple 1,200 p.s.i., controlled by relief valve 417, causing seal pad 1S0 to
be squeezed. At
this point, a second stage of expaiision talces place with snorlcel 98 then
moving within the
cylinders 120 in piston 96 to penetrate the mud cake 49 on the borehole wall
16 and to
receive formation fluids or take other measurements.
De-energizing solenoid valve 412 also closes equalizer valve 60, thereby
isolating
fluid passageway 93 from the annulus. In this manner, valve 412 ensures that
valve 60 closes
only after the seal pad 140 has entered contact with mud cake 49 which lines
borehole wall
16. Passageway 93, now closed to the annulus 15, is in fluid coinmunication
with cylinders
512, 542 at the upper ends of cylinders 514, 544 in draw down piston
assemblies 70, 72, best
shown in Figures 11 and 12.
With extend solenoid valve 416 still energized, and the hydraulic circuit 400
at
approximately 1,200 p.s.i., probe extend accumulator 430 has been charged and
controller
402 energizes solenoid valve 414. Energizing valve 414 closes off the extend
section of the
hydraulic circuit, tllereby maintaining the extend section at approximately
1,200 p.s.i. and
allowing drawdown to begin. With valve 414 energized, pressure can be added to
the draw
down circuit, wl-lich generally inchides draw down accumulator 432, solenoid
valves 418,
420, 422 and draw down piston asseniblies 70, 72.
Controller 402 now energizes solenoid valve 420 which permits pressurized
fluid to
enter poi-tion 504a of cylinder 504 causing draw down piston 70 to retract.
When that occurs,
26
CA 02559248 2006-09-08
WO 2005/114134 PCT/US2005/018123
pILu-iger 510 moves within cylinder 514 such that the volume of fluid
passageway 93 increases
by the volume of the area of the plunger 510 times the length of its stroke
along cylinder 514.
The volume of cylinder 512 is increased by this movement, thereby increasing
the volume of
fluid in passageway 93. Preferably, these elements are sized such that the
volume of fluid
passageway 93 is increased by preferably 30 cc maximum as a result of piston
70 being
retracted.
If draw down piston 70 is to be stopped due to, for exainple, the need for
only a partial
draw down or an unsuccessful partial draw down, controller 402 may energize
solenoid valve
418 to pressurize the draw down shutoff valve assetnbly 74. Pressurizing valve
assembly 74
causes draw down piston 70 to cease drawing down fonnation fluids. Now, valve
assembly
74 and draw down piston 70 have been pressured up to approximately 1,800
p.s.i. This
enstires that shutoff valve assembly 74 holds draw down piston 70 in its drawn
down, or
partially drawn down, position such that the drawn formation fluids are
retained and not
inadvertently expelled.
When it is desired to continue drawing down with draw down piston 70, solenoid
valve 418 can be de-energized, thereby tuming shutoff valve 74 off. Draw down
with draw
down piston 70 then commences tuitil the volume of cylinder 514 filled. The
draw down of
draw down piston 70 may continue to be interrupted using valves 418 and 74.
Such
interruptions may be necessary to change draw down parameters, such as draw
down rate and
volume.
Controller 402 may be used to command draw down piston 70 to draw down fluids
at
differing rates and voluines. For example, draw down piston 70 may be
commanded to draw
down fluids at lcc per second for 10 cc and then wait 5 minutes. If the
results of this test are
unsatisfactory, a downlink signal may be sent using mud pulse telemetry, or
another form of
dowirl7ole communication, progra.inining controller 402 to cormnand piston 70
to now draw
down fluids at 2cc per second for 20 cc and then wait 10 minutes, for example.
The first test
may be interrupted, parameters changed and the test may be restarted with the
new parameters
that have been sent from the surface to the tool. These parameter changes may
be made while
fonnation probe assembly 50 is extended.
Wliile draw down piston 70 is stopped, controller 402 may energize solenoid
valve
422 which permits presstuized fluid to enter portion 534a of cylinder 534
causing draw down
piston 72 to retract. When that occurs, plunger 540 moves witliin cylinder 534
such that the
volume of fluid passageway 93 increases by the voluine of the area of the
plunger 540 times
the length of its stroke along cylinder 544. The volume of cylinder 542 is
increased by this
27
CA 02559248 2006-09-08
WO 2005/114134 PCT/US2005/018123
moveinent, thereby increasing the volume of fluid in passageway 93.
Preferably, these
eleinents are sized such that the volume of fluid passageway 93 is increased
by 50 cc as a
result of piston 72 being retracted. Preferably, draw down piston 72 does not
have the stop
and start feature of piston 70, and is able to draw down more fluids at a
faster rate. Thus,
draw down piston 72 may be configured to draw down fluids at rates of 3.8 or
7.7 cc per
second, for example. However, it should be understood that either piston 70,
72 may be
different sizes, and piston 72 may also be configured to have the stop and
start feature via the
shutoff valve asseinbly. Thus, hydraulic circuit 400 may be configured to
operate multiple
pistons 70 and/or multiple pistons 72. Also, pistons 70, 72 may be operated in
any order.
The ability to control draw down pistons 70, 72 as described above also allows
the
operator to purge fluids in the draw down piston assemblies and probe flow
lines. For
example, if a pre-test voluune of fluid has been drawn into the probe, it may
be purged by
actuating the draw down pistons in the opposite directions. This may be useful
for cleaning
out any accuinulated debris in the flow lines and probe assembly.
Maintaining clean flow lines is iinportant to protecting instruinents in the
testing tool,
and to inaintaining the integrity of the formation tests by purging old fluids
left in the flow
lines. Thus, in another embod'vnent for keeping the flow lines clean, a
mechanical filter may
be placed in the flow lines, such as anywhere along flow lines 91, 93 in
Figures 6A, 6B and 9.
Alteniatively, the flow lines may be purged by opening equalizer valve 60,
puinping out
fluids present in the flow lines, then closing equalizer valve 60 in
preparation of another draw
down sequence.
As draw down piston 70 is actuated, 30 cc of formation fluid will thus be
drawn
tluough central passageway 127 of snorkel 98 and through screen 100. The
movement of
draw down piston 70 within its cylinder 5041owers the pressure in closed
passageway 93 to a
pressure below the fonnation pressure, such that formation fluid is drawn
through screen 100
and into apertures 166, tlzrougli snorlce198, then through stem passageway 108
to passageway
91 that is in fluid communication with passageway 93 and part of the same
closed fluid
system. In total, fluid chambers 93 (which include the volume of various
interconnected fluid
passageways, including passageways in formation probe assembly 50, passageways
91, 93,
the passageways interconnecting 93 with draw down pistons 70, 72 and draw down
shutoff
valve 74) preferably has a voluine of approxiinately 63 cc. If draw down
piston 72 is also
activated, this voh.une should increase approximately 30 cc, up to
approximately 90 cc total.
Drilling mud in annulus 15 is not drawn into snorkel 98 because seal pad 180
seals against
the mud cake. Snorkel 98 serves as a conduit through which the formation fluid
may pass
28
CA 02559248 2006-09-08
WO 2005/114134 PCT/US2005/018123
-ui.d the pressure of the formation fluid may be measured in passageway 93
while seal pad 180
serves as a seal to prevent annular fluids from entering the snorkel 98 and
invalidating the
forination pressure measurement.
Referring inoinentarily to Figure 6B, formation fluid is drawn first into the
central
bore 132 of screen 100. It then passes through slots 134 in screen slotted
segment 133 such
that particles in the fluid are filtered from the flow and are not drawn into
passageway 93.
The fornnation fluid then passes between the outer surface of screen 100 and
the inner surface
of snorkel extension 126 wliere it next passes through outlet end 135,
apertures 166 in scraper
160, scraper tube 150 and into the central passageway 108 of stem 92.
Screen 100 (and screen 290 of assembly 200) may be optimized for particular
applications. For example, if prior knowledge of the formation is obtained,
then the screen
can be tailored to the type of rock or sediment that is present in the
formation. One type of
adjustable screen is a gravel-packed screen, which may be used instead of or
in conjunction
with the slotted screen 100. Generally, a gravel-packed screen is two
longitudinal, cylindrical
screens of different diaineters. The screens are disposed concentrically and
the annulus is
filled with gravel pack sieve, or a known sand size.
Despite the type of formation encountered, the gravel pack may be tailored to
have a
10-to-1 ratio of formation sand size to gravel paclc size, which is the
preferable formation
particle size to gravel particle size ratio. With this ratio, it is expected
that the gravel pack
screen will have the ability to screen fonnation particles up to 1/10t" the
size of the nominal
fonnation particle diameter size encountered. With this embodiinent, the
gravel pack sand
size can be tailored to the specific intended application.
In yet another embodiment, the screens 100, 290 as they are illustrated in
Figures 6B,
7F may be optimized by adjusting the size and number of slits required for a
particular
application. The slits, or slots, are illustrated schematically as internally
slotted segment 133
having slots 134 in Figi.tre 6B, and intenially slotted segment 293 having
slots 295. The size
and number of slits can be tailored to the particular fonnation expected to be
intersected, and
the nominal sand particle size of the produced sand. For example, more slits
with smaller
openings may be used for smaller nominal formation particle size.
hi a fiirther einbodiment, the above mentioned adjustment of slot size may be
accomplished real-time. hi the previous embodiment, the slot size is set upon
deployment of
tool 10 into the borellole. The slot size remains unchanged wliile tool 10 is
deployed. The
slot size may be adjusted at the surface of the borehole by replacing screens
100, 290, or by
inanually adjusting the slot sizes, but may not be adjusted real-time, or
while tool 10 is
29
CA 02559248 2006-09-08
WO 2005/114134 PCT/US2005/018123
deployed downhole. In the current embodiment, detection of the type of
formation actually
intersected may be achieved via the various apparatus and methods disclosed
herein. If the
detected formation value, such as particle size, differs fiom a predetermined
value, the slot
size may be adjusted without tripping tool 10 out of the borehole. A command
may be given
from the surface of the borehole, or from tool 10, and slot size may be
adjusted by moving
two concentrically disposed slotted cylindrical members relative to each
other, for example,
or by adjusting sliutter mechanisms adjacent the slots.
Referring again to Figure 9, with seal pad 180 sealed against the borehole
wall, checlc
valve 434 inaintains the desired pressure acting against piston 96 and snorkel
98 to maintain
the proper seal of seal pad 180. Additionally, because probe seal accumulator
430 is fully
charged, should tool 10 move during drawdown, additional hydraulic fluid
volume may be
supplied to piston 96 and snorke198 to ensure that seal pad 180 remains
tightly sealed against
the borehole wall. In addition, should the borehole wall 16 move in the
vicinity of seal pad
180, the probe seal acctunulator 430 will supply additional hydraulic fluid
volume to piston
96 and snorkel 98 to ensure that seal pad 180 remains tightly sealed against
the borehole wall
16. Without accumulator 430 in circuit 400, inoveinent of the tool 10 or
borehole wall 16, and
tlnis of fonnation probe assembly 50, could result in a loss of seal at seal
pad 180 and a
failure of the formation test.
With the drawdown pistons 70, 72 in their fully, or partially, retracted
positions and
anywhere from one to 90 cc of formation fluid drawn into closed system 93, the
pressure will
stabilize enabling pressure transducers 426b,c to sense and measure formation
fluid pressure.
The measured pressure is transmitted to the controller 402 in the electronic
section where the
infonnation is stored in meinory and, alternatively or additionally, is
communicated to the
master controller 401 in the MWD tool 13 below formation tester 10 where it
caii be
transinitted to the surface via mud pulse telemetry or by any otlier
conventional telemetry
mean.s.
When drawdown is coinpleted, pistons 70, 72 actuate their contact switches
previously described. When the contact switch 550, for example, is actuated
controller 402
responds by shutting down motor 404 and pump 406 for energy conservation.
Checlc valve
436 traps the llydraulic pressure and maintains pistons 70, 72 in their
retracted positions. In
the event of any lealcage of hydraulic fluid that might allow pistons 70, 72
to begin to move
toward their original shouldered positions, drawdown accumulator 432 will
provide the
necessary fluid voluine to compensate for any such leakage a.nd thereby
maintain sufficient
force to retain pistons 70, 72 in their retracted positions.
CA 02559248 2006-09-08
WO 2005/114134 PCT/US2005/018123
During this interval, controller 402 continuously monitors the pressure in
fluid
passageway 93 via pressure transducers 426 b, c. When the measured pressure
stabilizes, or
after a predetermuzed time interval, controller 402 de-energizes extend
solenoid valve 416.
When this occurs, pressure is removed fiom the close side of equalizer valve
60 and from the
~
extend side of probe piston 96. Equalizer valve 60 will retunl to its normally
open state and
probe retract accumulator 424 will cause piston 96 and snorkel 98 to retract,
such that seal
pad 180 becomes disengaged with the borehole wall. Thereafter, controller 402
again powers
motor 404 to drive pump 406 and again energizes solenoid valve 412. This step
ensures that
piston 96 and snorke198 have fully retracted and that the equalizer valve 60
is opened. Given
this arrangement, the fonnation tool has a redundant probe retract mechanism.
Active retract
force is provided by the pump 406. A passive retract force is supplied by
probe retract
accuinulator 424 that is capable of retracting the probe even in the event
that power is lost. It
is preferred that accumulator 424 be charged at the surface before being
einployed downhole
to provide pressure to retain the piston and snorlcel in housing 12.
It will be understood that the equalizer valve 60 may be opened in a similar
manner at
other times during probe engagement with the borehole wall. If the probe seal
pad is in
danger of becomiuig stuck on the borehole wall, the suction inay be broken by
opening
equalizer valve 60 as described above.
After a predetermined pressure, for example 1800 p.s.i., is sensed by pressure
transducer 426a and communicated to controller 402 (indicating that the
equalizer valve is
open and that the piston and snorkel are fully retracted), controller 402 de-
energizes solenoid
valves 418, 420, 422 to remove pressure from sides 504a, 534a of drawdown
pistons 70, 72,
respectively. With solenoid valve 412 remaining energized, positive pressure
is applied to
sides 504b, 534b .of drawdown pistons 70, 72 to ensure that pistons 70, 72 are
returned to
their oa.-iginal positions. Controller 402 monitors the pressure via pressure
transducer 426a
and when a predetermined pressure is reached, controller 402 determines that
pistons 70, 72
v-e fiilly returned anid it shuts off motor 404 and pump 406 and de-energizes
solenoid valve
412. With all solenoid valves returned to their original positions and with
motor 404 off, tool
10 is baclc in its original condition.
The hydraulic circuit 400, as described and illustrated in Figure 9, may also
act as a
regenerative circuit wl-iile extending the probe assembly. With both retract
valve 412 and
extend valve 416 energized or actuated, as described above, and the difference
in areas
between the smaller area on the retract side of the probe piston, such as
piston 96 or piston
240, and the larger area on the extend side of the piston, there is a net
effect of extending the
31
CA 02559248 2006-09-08
WO 2005/114134 PCT/US2005/018123
probe assembly. As the piston continues to extend with retract valve still
open, there is a
back flow of hydraulic fluid through retract valve 412 due to the laclc of a
check valve behind
retract valve 412. This relatively uniinpeded back flow patli leads into the
pressurized
hydraulic fluid flowing into extend valve 416, adding to the pressure on the
extend side of the
circuit and increasing the rate at which the probe may extend.
During extension of the probe assembly, using hydraulic circuit 400, it can be
seen
that the total volume of hydraulic fluid required to be displaced by pump 406,
and hence the
number of revolutions of motor 404, is reduced coinpared to a non-regenerative
circuit. The
regenerative nature of circuit 400 also allows the moveable wiper or scraper,
such as scraper
160, to remain extended during extension of the probe assembly, especially as
the snorkel
assembly is penetrating the mudcake and formation and there is an extra force
pushing back
on the moveable scraper. As can be seen in Figures 6A, 6B and 7A-7F, the area
of the extend
side of the scraper assembly, for example, the bottom of flange 372 of scraper
tube 278 in
Figure 7F, is greater than the area of the retract side, or the upper side of
flange 372. Thus,
with both valves 412 and 416 actuated, the same hydraulic pressure acts on
different areas,
causing the wiper eleinent to extend and the pressurized fluid to regenerate
on the extend side
of the scraper tube 278, as previously described.
Further, as mentioned before, the regeneration of pressure in circuit 400
allows faster
exteilsion of the probe assembly. lii addition, the regenerated pressure
assists with control of
equalizer valve actuation.
A 1lydraulic reservoir accumulator assembly 600 is disposed in probe collar 12
as
shown in Figure 101. Reservoir accumulator assembly 600 maintains a pressure
above the
auululus or surrolul.ding environment pressure in the complete tool 10
hydraulic system. This
condition in the hydraulic system compensates for pressure and temperature
changes in the
tool. Also, the pressure provided from assembly 600 causes pump 406 (Figure 9)
to begin
operating from the aiuiulus pressure, thereby reducing the work load that
would be required
from starting puinp 406 at atinospheric pressure. Thus, accumulator assembly
600 may be
used to conununicate am-iulus pressure into the tool's hydraulic system. As
will be seen
below, assembly 600 is self contained and easily field replaceable.
Asseinbly 600 generally includes a body 602 having a top surface 632, bottom
surface
634 (Figure 10C) and endcap 604 at end 606, several locking wings 608 and
drilling fluid
apertures 618, 620 at end 622. Top stuface 632 includes additional fluid
apertures 628, 630
covered by a screen 639 as illustrated in Figure 10F. Screen 639 is held in
place by retaining
ring 637, and prevents large particles in the drilling fluid from entering the
cylinders and
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CA 02559248 2006-09-08
WO 2005/114134 PCT/US2005/018123
ulterfering with the reciprocation of the pistons. Endcap 604 includes a
pressure plug 638 for
coiuiecting asseinbly 600 to probe collar 12, wliich helps to lock assembly
600 into place as
ilh.istrated in Figure 10H. Endcap 604 also includes hydraulic fluid check
valves 640, 642 for
fluid connnunication with the tool hydraulic circuit, and for checking fluid
into assembly 600
and the tool hydraulic system when assembly 600 is removed from collar 12.
Referring briefly to Figure 10F, it can be seen that the inside of assembly
600 is split
into two cylinders 626, 646. Figure 10C illustrates cylinder 626 retaining a
piston 636 which
separates cylinder 626 into hydraulic fluid portion 626a and drilling fluid
portion 626b.
Piston 636 is reciprocal between the position shown in Figure lOC and the
position of piston
656 shown in Figure lOD. Spring 624 is retained in cylinder portion 626b
between piston
636 and end 622. Spring 624 extends past piston end 636b around piston 636 and
seats on
increased piston diameter portion 633. Increased diameter portion 633 is
similar to increased
diaineter portion 653 of piston 656, illustrated in Figure lOG. At end 622,
aperture 620
allows drilling fluids to enter cylinder portion 626b and exert the
surrounding annulus
pressure on side 636b of piston 636. Because spring 624 also exerts a force on
side 636b, the
pressure of hydraulic fluid in cylinder portion 626a is greater than the
annulus pressure. The
pressure of the hydraulic fluid in cylinder portion 626a is the annulus
pressure plus the
pressure added by spring 624. Spring 624 may exert, for example, a pressure of
approxiinately 60-80 p.s.i.
Cylinder 646 of Figure lOD operates in a similar fashion to cylinder 626.
Drilling
fluid enters cylinder portion 646b tlirougli aperture 622, thereby exerting
the armulus pressure
on side 656b of piston 656. Spring 644 then increases the pressure on piston
656, causing the
hydraulic fluid in cylinder 646a, and therefore the hydraulic fluid in the
tool hydraulic system,
to be greater than the annulus pressure. Spring 644 is shown in the fully
compressed position
in Figure 10D.
Refen-ing now to Figure IOG, enlarged piston end 656a includes seal 659 for
sealing
the drilliuig mud from the system hydraulic fluid, and scraper 661 for
cleaning the cylinder
bore 646 as piston 656 reciprocates. Spring 644 seats on increased diameter
portion 653.
Piston end 636a is similar to piston end 656a illustrated in Figure lOG.
Preferably, pistons 636, 656 reciprocate independently of each other while
maintaining the pressure in the hydraulic systein of the tool. Also, both
pistons communicate
with the entire tool lrydraulic system.
Refeiring now to FigLue IOH, accumulator assembly 600 is illustrated placed
into
position in collar 12, but not locked down. To engage assembly 600 with cavity
601 in collar
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CA 02559248 2006-09-08
WO 2005/114134 PCT/US2005/018123
12, assembly 600 is disposed above cavity 601 and locking wings 608 (Figure
10A) are
aligned with recesses 664. Recesses 664 are L-shaped (not shown) with the
bottom portions
of the L extending toward endcap 604 and end 603 of cavity 601. Assembly 600
is lowered
into cavity 601 with locking wings 608 sliding down through recesses 664 until
assembly 600
seats at the bottom of cavity 601 and top surface 632 is substantially flush
witli the surface of
collar 12. Asseinbly 600 is t11en moved toward cavity end 603 such that
locking wings 608
inove into the extending bottom portions of recesses 664 and pressure plug 638
(Figure 10A)
pressure fits into an aperture (not shown) disposed at end 603 of cavity 601.
This forward
inoveinent also causes a gap 678 to be formed between cavity end 605 and
assembly end 622.
To loclc assembly 600 into place, a wedge 670 is placed into gap 678. The
angled end
622 (illustrated in Figure 10C) matingly receives the angled side 676 of wedge
670. The
wedging action of these mating surfaces ensures that assembly 600 is moved f-
ully forward in
cavity 601. Bolts 674 and nuts 672 lock down wedge 670. Further, L-shaped
locking pieces
668 are placed into recesses 664 and bolts 666 are used to lock down wings
608. The final
locked position of assembly 600 is illustrated in Figure 101. Fluid ports 628,
630
cominunicate with drilling fluid in annulus 15. Fluid entering cylinder
portions 626b and
646b througll apertures 618, 620 is screened by slots in wedge 670 (slots not
shown).
Removing accumulator assembly 600 requires a process done in reverse of the
process
just described. While removing assembly 600, check valves 640, 642 close and
maintain oil
in the tool hydraulic system. Asseinbly 600 may then be cleaned and/or
replaced. Check
valves 640, 642 open again once assembly 600 is locked into position.
Hydraulic fluid may
then be added to make up for any fluid loss, and preferable fluid is added to
the extent that
pistons 636, 656 are pushed back to the position illustrated in Figure lOD.
The uplink and downlinlc coinmands used by tool 10 are not limited to mud
pulse
teleinetiy. By way of example and not by way of limitation, other telemetry
systems may
include inanual metliods, including pump cycles, flow/pressure bands, pipe
rotation, or
combinations thereof. Other possibilities include electromagnetic (EM),
acoustic, and
wireline telemetry methods. An advantage to using alternative telemetry
methods lies in the
fact that mud pulse telemetry (both uplink and downlink) requires pump-on
operation but
other teleinetry systems do not.
The down hole receiver for downlink commands or data from the surface may
reside
within the fonnation test tool or within an MWD tool 13 witll which it
communicates.
Likewise, the down hole transmitter for uplink commands or data from down hole
may reside
within the fonnation test tool 10 or within an MWD tool 13 witli wliich it
communicates. In
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CA 02559248 2006-09-08
WO 2005/114134 PCT/US2005/018123
the prefezTed embodiment specifically described, the receivers and
transmitters are each
positioiied in MWD tool 13 and the receiver signals are processed, analyzed
and sent to a
inaster controller 401 in the MWD tool 13 before being relayed to local
controller 402 in
forination testing tool 10.
The above discussion is meant to be illustrative of the principles and various
embodiinents of the present invention. While the preferred embodiment of the
invention and
its inethod of use have been shown and described, modifications thereof can be
made by one
skilled in the art without departing from the spirit and teachings of the
invention. The
einbodiments described herein are exemplary only, and are not limiting. Many
variations and
inodifications of the invention and apparatus and methods disclosed herein are
possible and
are witliin the scope of the invention. Accordingly, the scope of protection
is not limited by
the description set out above, but is only limited by the claims which follow,
that scope
including all equivalents of the subject matter of the claims.
