U.S. patent application number 11/135050 was filed with the patent office on 2005-11-24 for methods and apparatus for measuring formation properties.
This patent application is currently assigned to Halliburton Energy Services, Inc.. Invention is credited to Beique, Jean Michel, Dudley, James H., Fogal, James M., Hardin, John R. JR., Hendricks, William Edward, Marsh, Laban M., Proett, Mark A., Welshans, David.
Application Number | 20050257611 11/135050 |
Document ID | / |
Family ID | 37712124 |
Filed Date | 2005-11-24 |
United States Patent
Application |
20050257611 |
Kind Code |
A1 |
Fogal, James M. ; et
al. |
November 24, 2005 |
Methods and apparatus for measuring formation properties
Abstract
This application relates to various methods and apparatus for
rapidly obtaining accurate formation property data from a drilled
earthen borehole. Quickly obtaining accurate formation property
data, including formation fluid pressure, is vital to beneficially
describing the various formations being intersected. For example,
methods are disclosed for collecting numerous property values with
a minimum of downhole tools, correcting and calibrating downhole
measurements and sensors, and developing complete formation
predictors and models by acquiring a diverse set of direct
formation measurements, such as formation fluid pressure and
temperature. Also disclosed are various methods of using of
accurately and quickly obtained formation property data.
Inventors: |
Fogal, James M.; (Houston,
TX) ; Proett, Mark A.; (Missouri City, TX) ;
Dudley, James H.; (Spring, TX) ; Marsh, Laban M.;
(Houston, TX) ; Welshans, David; (Damon, TX)
; Beique, Jean Michel; (Katy, TX) ; Hardin, John
R. JR.; (Spring, TX) ; Hendricks, William Edward;
(Kingwood, TX) |
Correspondence
Address: |
CONLEY ROSE, P.C.
P. O. BOX 3267
HOUSTON
TX
77253-3267
US
|
Assignee: |
Halliburton Energy Services,
Inc.
Houston
TX
|
Family ID: |
37712124 |
Appl. No.: |
11/135050 |
Filed: |
May 23, 2005 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60573289 |
May 21, 2004 |
|
|
|
Current U.S.
Class: |
73/152.22 |
Current CPC
Class: |
E21B 49/10 20130101 |
Class at
Publication: |
073/152.22 |
International
Class: |
E21B 047/06 |
Claims
What is claimed is:
1. A method of measuring a formation property, the method
comprising: disposing a drill collar in a borehole at a first
depth, the drill collar comprising a formation tester tool, a
formation probe assembly, and at least a first sensor and a second
sensor; engaging the formation tester tool with an earth formation
using the formation probe assembly; selectively sampling at least
one of the first and second sensors; making at least a first and a
second measurement; and comparing the first measurement to the
second measurement.
2. The method of claim 1 further comprising: communicating a
formation fluid to the first and second sensors; communicating an
annulus fluid to the first and second sensors; and wherein making
at least a first and second measurement comprises simultaneously
measuring a plurality of pressure values of any one of the
formation fluid and the annulus fluid, wherein at least one of the
pressure values is measured by the first sensor and at least one of
the pressure values is measured by the second sensor.
3. The method of claim 2 further comprising supplementing a
formation fluid pressure from the first sensor with a formation
fluid pressure from the second sensor.
4. The method of claim 2 further comprising supplementing an
annulus fluid pressure from the first sensor with an annulus fluid
pressure from the second sensor.
5. The method of claim 1 wherein making at least a first and a
second measurement comprises measuring a first formation pressure
using the first sensor and measuring a second formation pressure
using the second sensor, the method further comprising: correcting
the first and second formation pressures; and obtaining a first
corrected formation pressure, wherein the first corrected formation
pressure is substantially the same as an actual formation
pressure.
6. The method of claim 5 wherein correcting the first and second
formation pressures further comprises: obtaining a first offset
error by subtracting the second formation pressure from the first
formation pressure; and adding the first offset error to at least
one of the first and second formation pressures.
7. The method of claim 1 wherein making at least a first and a
second measurement comprises measuring a plurality of pressures
with each of the first and second sensors, the method further
comprising: identifying at least one pressure value from the first
sensor plurality of pressures; and calibrating the second sensor to
the at least one first sensor pressure value.
8. The method of claim 7 further comprising: identifying at least
two first sensor pressure values P.sub.Q1 and P.sub.Q2; identifying
at least two second sensor pressure values P.sub.SG1 and P.sub.SG2;
and correcting the second sensor pressure values using any one of:
P.sub.SG corrected=P.sub.off+(P.sub.slope*P.sub.SG); and P.sub.SG
corrected=P.sub.Q1-(P.sub.Q1-P.sub.Q2)/(P.sub.SG1-P.sub.SG2)*(P.sub.SG1-P-
.sub.SG2).
9. The method of claim 7 wherein the calibrating the second sensor
to the at least one first sensor pressure value occurs during the
measuring a plurality of pressures with each of the first and
second pressure sensors.
10. The method of claim 7 further comprising: disposing the drill
collar at a plurality of depths in the borehole; identifying at
least one pressure value from the first sensor at each of the
depths; and continually calibrating the second sensor to the at
least one first sensor pressure value for each of the depths.
11. The method of claim 7 further comprising: disposing the drill
collar at a plurality of depths in the borehole; identifying at
least one pressure value from the first sensor at each of the
depths; identifying at least one pressure value from the second
sensor at each of the depths; measuring at least one temperature
value at each of the depths from a temperature sensor disposed
adjacent the first and second sensors; developing a plot of the
pressure values versus the temperature value; and continually
calibrating the second sensor to the plot for each of the
depths.
12. The method of claim 1 wherein: the formation tester tool
further includes embedded software; and the comparing the first
measurement to the second measurement occurs downhole using the
formation tester tool embedded software.
13. The method of claim 1 wherein the second sensor is an LWD tool,
the method further comprising: imaging a portion of the borehole
using the LWD tool; wherein making a first measurement comprises
identifying a first formation property of the imaged borehole
portion; wherein making a second measurement comprises
pre-determining a formation property; and adjusting the drill
collar if the first formation property differs from the
predetermined formation property.
14. The method of claim 13 further comprising: orienting the
formation tester tool toward a selected location; disengaging the
formation probe assembly from the formation; imaging the selected
location; and verifying formation probe assembly engagement
adjacent the selected location.
15. The method of claim 1 further comprising: communicating a
formation fluid through the formation probe assembly to at least
the first sensor; wherein making a first measurement comprises
measuring a first formation fluid pressure; pumping a drilling
fluid down the borehole; wherein making a second measurement
comprises measuring a second formation fluid pressure while the
pumping occurs; and determining a difference between the first and
second pressures.
16. The method of claim 15 further comprising: disposing the drill
collar near the distal end of a drill string, the distal end of the
drill string having a drill bit for drilling the borehole to the
first depth; and calculating a property using the pressure
difference.
17. The method of claim 1 further comprising: communicating a
formation fluid through the formation probe assembly to the first
sensor; sending a pressure pulse into the borehole; wherein making
a first measurement comprises measuring the pressure pulse at a
location in an annulus of the borehole; wherein making a second
measurement comprises measuring the pressure pulse at the first
sensor; comparing the annulus pressure pulse measurement and the
first sensor pressure pulse measurement; and calculating a
formation property.
18. The method of claim 17 wherein the pressure pulse is sent from
a second formation probe assembly disposed on the drill collar.
19. The method of claim 1 wherein making at least a first and a
second measurement comprises measuring a pressure using the first
sensor and obtaining a second measurement using the second sensor,
the method further comprising: correcting the pressure using the
second measurement.
20. The method of claim 19 further comprising: drawing a formation
fluid into the formation probe assembly, wherein the pressure
comprises a formation pressure and the second measurement comprises
a formation temperature; and compensating the formation pressure
for thermal effects using the formation temperature.
21. The method of claim 1 wherein making at least a first and a
second measurement comprises measuring a pressure using the first
sensor and obtaining a second measurement using the second sensor,
the method further comprising: correcting the second measurement
using the pressure.
22. The method of claim 1 further comprising: drawing a formation
fluid into the formation probe assembly, wherein the first
measurement comprises a formation pressure and the second
measurement comprises a formation fluid resistivity; and
calculating a formation fluid saturation.
23. The method of claim 1 further comprising: disposing the drill
collar near the distal end of a drill string, the distal end of the
drill string having a drill bit for drilling the borehole to the
first depth; wherein the first measurement is made at the first
depth; retracting the formation probe assembly; pulling the drill
string up the borehole to a second depth above the first depth;
engaging the formation probe assembly with the formation at the
second depth; and wherein the second measurement is made at the
second depth.
24. The method of claim 23 further comprising at least one of
correcting a formation model, supplementing a pore pressure
prediction model, and calibrating a pore pressure prediction
model.
25. A method of measuring a formation property, the method
comprising: disposing a drill collar in a borehole at a first
depth, the drill collar comprising a formation tester tool, a
formation probe assembly and a first sensor; engaging the formation
tester tool with an earth formation using the formation probe
assembly; making at least a first measurement; and adjusting the
first measurement.
26. The method of claim 25 wherein: making a first measurement
comprises measuring a first pressure with the first sensor; and the
adjusting the first measurement comprises improving an accuracy of
the first pressure relative to an actual formation pressure.
27. The method of claim 26 wherein the improving an accuracy of the
first pressure further comprises: inputting a plurality of pressure
values into the first sensor, the pressure values representing a
full first pressure input range; obtaining a plurality of output
pressure values; determining a transducer effect on the output
values; establishing at least two calibration tables based on the
transducer effect; and interpreting the first pressure using at
least one of the calibration tables.
28. The method of claim 26 wherein the improving an accuracy of the
first pressure further comprises: providing a second sensor having
a pressure range, wherein the second sensor pressure range differs
from a first sensor pressure range; measuring a second pressure
using the second sensor; and wherein the second pressure is outside
the first sensor pressure range.
29. The method of claim 25 further comprising: disposing the
formation probe assembly at a first location and the first sensor
at a second location; communicating a fluid to the first sensor
through a flow line between the formation probe assembly and the
first sensor; wherein making a first measurement comprises
measuring a first pressure with the first sensor; and wherein
adjusting the first measurement comprises correcting the first
pressure to an actual pressure at the first location.
30. The method of claim 29 wherein the correcting the first
pressure further comprises: determining a pressure difference
between the first and second locations; and subtracting the
pressure difference from the first pressure.
31. The method of claim 25 wherein the engaging the formation
tester tool occurs at a first location immediately after the drill
bit intersected the first location and before a mudcake is formed
on the borehole wall.
32. The method of claim 31 further comprising determining a
formation quality and taking a corrective action comprising at
least one of casing the borehole, changing a drilling mud property,
and continuing drilling.
33. A method of measuring a formation property, the method
comprising: disposing a drill collar in a borehole, the drill
collar comprising a formation tester tool, a formation probe
assembly and a sensor; engaging the formation tester tool with a
formation using the formation probe assembly; injecting a fluid
from the formation probe assembly into the formation; and measuring
a pressure.
34. The method of claim 33 further comprising calculating a
formation property, the formation property at least one of mud cake
permeability and formation mobility.
35. The method of claim 33 further comprising: fracturing the
formation; and wherein the measured pressure comprises a fracture
pressure.
36. A method of measuring a formation property, the method
comprising: disposing a drill collar in a borehole at a first
depth, the drill collar comprising a formation tester tool and a
formation probe assembly having an extendable probe; extending the
probe; engaging the probe with an earth formation; maintaining a
substantially non-flow condition within the formation probe
assembly; and measuring a formation property.
37. The method of claim 36 wherein measuring a formation property
further comprises: recording a pressure response to the probe
engagement; and determining a formation property.
38. The method of claim 36 wherein measuring a formation property
further comprises: indicating a first position of the probe;
indicating a second position of the probe; measuring a distance
between the first and second probe positions; and determining a
formation property.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] The present application claims the benefit of U.S.
Provisional Application Ser. No. 60/573,289, filed May 21, 2004,
entitled Methods and Apparatus for Measuring Formation Properties,
which is hereby incorporated herein by reference.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[0002] Not applicable.
BACKGROUND
[0003] 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.
[0004] 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.
[0005] 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 creates a fluid pathway that allows formation
fluid to flow between the formation and the formation tester while
isolated from the borehole fluid.
[0006] In order to acquire a useful sample, the probe must stay
isolated from the relative high 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 sample will be obtained and the test
will have to be repeated.
[0007] Examples of isolation pads and probes used in WFTs can be
found in Halliburton's DT, SFTT, SFT4, and RDT tools. Isolation
pads that are used with WFTs are typically rubber pads affixed to
the end of the extending sample probe. The rubber is normally
affixed to a metallic plate that provides support to the rubber as
well as a connection to the probe. These rubber pads are often
molded to fit within the specific diameter hole in which they will
be operating.
[0008] 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, must be lowered into the well to conduct
secondary operations. Interrupting the drilling process to perform
formation testing can add significant amounts of time to a drilling
program.
[0009] 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 weight on bit.
[0010] Further, the formation pressure measurement accuracy of
drill stem tests and, especially, of wireline formation tests may
be affected by filtrate invasion and mudcake buildup because
significant amounts of time may have passed before a DST or WFT
engages the formation. Mud filtrate invasion occurs when the
drilling mud fluids displace formation fluids. Because the mud
filtrate ingress into the formation begins at the borehole surface,
it is most prevalent there and generally decreases further into the
formation. When filtrate invasion occurs, it may become impossible
to obtain a representative sample of formation fluids or, at a
minimum, the duration of the sampling period must be increased to
first remove the drilling fluid and then obtain a representative
sample of formation fluids. The mudcake is made up of the solid
particles that are plastered to the side of the well by the
circulating drilling mud 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 extend
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 permeability adjacent
to the borehole. Thus, once the mudcake forms, the accuracy of
reservoir pressure measurements decreases, affecting the
calculations for permeability and producibility of the
formation.
[0011] Another testing apparatus is the formation tester while
drilling (FTWD) tool. Typical FTWD formation testing equipment is
suitable for integration with a drill string during drilling
operations. Various devices or systems are used for isolating a
formation from the remainder of the borehole, drawing fluid from
the formation, and measuring physical properties of the fluid and
the formation. For example, the FTWD may use a probe similar to a
WFT that extends to the formation and a small sample chamber to
draw in formation fluids through the probe to test the formation
pressure. To perform a test, the drill string is stopped from
rotating and the test procedure, similar to a WFT described above,
is performed.
BRIEF DESCRIPTION OF THE DRAWINGS
[0012] For a more detailed description of the embodiments of the
present invention, reference will now be made to the accompanying
drawings, wherein:
[0013] FIG. 1 is a schematic elevation view, partly in
cross-section, of an embodiment of a formation tester apparatus
disposed in a subterranean well;
[0014] FIGS. 2A-2E are schematic elevation views, partly in
cross-section, of portions of the bottomhole assembly and formation
tester assembly shown in FIG. 1;
[0015] FIG. 3 is an enlarged elevation view, partly in
cross-section, of the formation tester tool portion of the
formation tester assembly shown in FIG. 2D;
[0016] FIG. 3A is an enlarged cross-section view of the draw down
piston and chamber shown in FIG. 3;
[0017] FIG. 3B is an enlarged cross-section view along line 3B-3B
of FIG. 3;
[0018] FIG. 4 is an elevation view of the formation tester tool
shown in FIG. 3;
[0019] FIG. 5 is a cross-sectional view of the formation probe
assembly taken along line 5-5 shown in FIG. 4;
[0020] FIGS. 6A-6C are cross-sectional views of a portion of the
formation probe assembly taken along the same line as seen in FIG.
5, the probe assembly being shown in a different position in each
of FIGS. 6A-6C;
[0021] FIG. 7 is an elevation view of the probe pad mounted on the
skirt employed in the formation probe assembly shown in FIGS. 4 and
5;
[0022] FIG. 8 is a top view of the probe pad shown in FIG. 7;
[0023] FIG. 9 is a schematic view of a hydraulic circuit employed
in actuating the formation tester apparatus;
[0024] FIG. 10 is a graph of the formation fluid pressure as
compared to time measured during operation of the tester
apparatus;
[0025] FIG. 11 is another graph of the formation fluid pressure as
compared to time measured during operation of the tester apparatus
and showing pressures measured by different pressure transducers
employed in the formation tester;
[0026] FIG. 12 is another graph of the formation fluid pressure as
compared to time measured during operation of the tester apparatus
that can be used to calibrate the pressure transducers; and
[0027] FIG. 13 is a graph of the annulus and formation fluid
pressures in response to pressure pulses.
DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS
[0028] Certain terms 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.
[0029] In the following discussion and in the claims, the terms
"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 connections are each intended to mean and
refer to either an indirect or a direct electrical connection.
Thus, for example, if a first device "couples" or is "coupled" to a
second device, that interconnection may be through an electrical
conductor directly interconnecting the two devices, or through an
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" meaning 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 elements are in fluid communication. By this it is
meant that the components are constructed and interrelated such
that a fluid could be communicated between them, as via a
passageway, tube, or conduit. Also, the designation "MWD" or "LWD"
are used to mean all generic measurement while drilling or logging
while drilling apparatus and systems.
[0030] To understand the mechanics of formation 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 certain types of rock. Therefore, it
is critical to know certain properties of both the formation and
the fluid contained therein. 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,
mobility, spherical mobility, porosity, saturation, coupled
compressibility porosity, skin damage, and anisotropy. Such
formation fluid properties include, but are not limited to:
viscosity, compressibility, flowline fluid compressibility,
density, resistivity, composition and bubble point.
[0031] 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 volume 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.). Skin
damage is an indication of how the mud filtrate or mudcake has
changed the permeability near the wellbore. Anisotropy is the ratio
of the vertical and horizontal permeabilities of the formation.
[0032] 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, and 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 kind of phase change in the formation hydrocarbons
being tested and measured is undesirable, unless the bubblepoint
test is being administered to determine what the bubblepoint
pressure is.
[0033] 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 form 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 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.
[0034] Referring to FIG. 1, an MWD formation tester tool 10 is
illustrated as a part of bottom hole assembly 6 (BHA) which
includes an MWD sub 13 and a drill bit 7 at its lower most end. BHA
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 derrick 1 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 illustrated in
FIG. 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, mud pulse telemetry
system, measurement-while-drilling sensors and systems, and others
well known in the art.
[0035] It should also be understood that, even though the MWD
formation tester 10 is illustrated as part of a drill string 5, the
embodiments of the invention described below may be conveyed down
the borehole 8 via wireline technology, as is partially described
above. It should also be understood that the exact physical
configuration of the formation tester and the probe assembly is not
a requirement of the present invention. The embodiment described
below serves to provide an example only. Additional examples of a
probe assembly and methods of use are described in U.S. patent
application Ser. No. 10/440,593, filed May 19, 2003 and entitled
"Method and Apparatus for MWD Formation Testing"; Ser. No.
10/440,835, filed May 19, 2003 and entitled "MWD Formation Tester";
and Ser. No. 10/440,637, filed May 19, 2003 and entitled "Equalizer
Valve"; each hereby incorporated herein by reference for all
purposes. Further examples of formation testing tools, probe
assemblies and methods of use, whether conveyed via a drill string
or wireline, or any other method, include U.S. patent application
Ser. No. ______ entitled "Downhole Probe Assembly," having U.S.
Express Mail Label Number EV 303483549 US and Attorney Docket
Number 1391-52601; U.S. patent application Ser. No. ______ entitled
"Formation Tester Tool Assembly and Methods of Use," having U.S.
Express Mail Label Number EV 303483552 US and Attorney Docket
Number 1391-53801; U.S. patent application Ser. No. ______ entitled
"Methods and Apparatus for Using Formation Property Data," having
U.S. Express Mail Label Number EV 303483570 US and Attorney Docket
Number 1391-54001; U.S. patent application Ser. No. ______ entitled
"Methods and Apparatus for Controlling a Formation Tester Tool
Assembly," having U.S. Express Mail Label Number EV 303483362 US
and Attorney Docket Number 1391-54101; and U.S. patent application
Ser. No. ______ entitled "Methods for Measuring a Formation
Supercharge Pressure," having U.S. patent application Ser. No.
11/069,649; each hereby incorporated herein by reference for all
purposes.
[0036] The formation tester tool 10 is best understood with
reference to FIGS. 2A-2E. Formation tester 10 generally comprises a
heavy walled housing 12 made of multiple sections of drill collar
12a, 12b, 12c, and 12d which threadedly engage one another so as to
form the complete housing 12. Bottom hole assembly 6 includes flow
bore 14 formed through its entire length to allow passage of
drilling fluids from the surface through the drill string 5 and
through the bit 7. The drilling fluid passes through nozzles in the
drill bit face and flows upwards through borehole 8 along the
annulus 150 formed between housing 12 and borehole wall 151.
[0037] Referring to FIGS. 2A and 2B, upper section 12a of housing
12 includes upper end 16 and lower end 17. Upper end 16 includes a
threaded box for connecting formation tester 10 to drill string 5.
Lower end 17 includes a threaded box for receiving a
correspondingly threaded pin end of housing section 12b. Disposed
between ends 16 and 17 in housing section 12a are three aligned and
connected sleeves or tubular inserts 24a,b,c which creates an
annulus 25 between sleeves 24a,b,c and the inner surface of housing
section 12a. Annulus 25 is sealed from flowbore 14 and provided for
housing a plurality of electrical components, including battery
packs 20, 22. Battery packs 20, 22 are mechanically interconnected
at connector 26. Electrical connectors 28 are provided to
interconnect battery packs 20, 22 to a common power bus (not
shown). Beneath battery packs 20, 22 and also disposed about sleeve
insert 24c in annulus 25 is electronics module 30. Electronics
module 30 includes the various circuit boards, capacitors banks and
other electrical components, including the capacitors shown at 32.
A connector 33 is provided adjacent upper end 16 in housing section
12a to electrically couple the electrical components in formation
tester tool 10 with other components of bottom hole assembly 6 that
are above housing 12.
[0038] Beneath electronics module 30 in housing section 12a is an
adapter insert 34. Adapter 34 connects to sleeve insert 24c at
connection 35 and retains a plurality of spacer rings 36 in a
central bore 37 that forms a portion of flowbore 14. Lower end 17
of housing section 12a connects to housing section 12b at threaded
connection 40. Spacers 38 are disposed between the lower end of
adapter 34 and the pin end of housing section 12b. Because threaded
connections such as connection 40, at various times, need to be cut
and repaired, the length of sections 12a, 12b may vary in length.
Employing spacers 36, 38 allow for adjustments to be made in the
length of threaded connection 40.
[0039] Housing section 12b includes an inner sleeve 44 disposed
therethrough. Sleeve 44 extends into housing section 12a above, and
into housing section 12c below. The upper end of sleeve 44 abuts
spacers 36 disposed in adapter 34 in housing section 12a. An
annular area 42 is formed between sleeve 44 and the wall of housing
12b and forms a wire way for electrical conductors that extend
above and below housing section 12b, including conductors
controlling the operation of formation tester 10 as described
below.
[0040] Referring now to FIGS. 2B and 2C, housing section 12c
includes upper box end 47 and lower box end 48 which threadingly
engage housing section 12b and housing section 12c, respectively.
For the reasons previously explained, adjusting spacers 46 are
provided in housing section 12c adjacent to end 47. As previously
described, insert sleeve 44 extends into housing section 12c where
it stabs into inner mandrel 52. The lower end of inner mandrel 52
stabs into the upper end of formation tester mandrel 54, which is
comprised of three axially aligned and connected sections 54a, b,
and c. Extending through mandrel 54 is a deviated flowbore portion
14a. Deviating flowbore 14 into flowbore path 14a provides
sufficient space within housing section 12c for the formation tool
components described in more detail below. As best shown in FIG.
2E, deviated flowbore 14a eventually centralizes near the lower end
48 of housing section 12c, shown generally at location 56.
Referring momentarily to FIG. 5, the cross-sectional profile of
deviated flowbore 14a may be a non-circular in segment 14b, so as
to provide as much room as possible for the formation probe
assembly 50.
[0041] As best shown in FIGS. 2D and 2E, disposed about formation
tester mandrel 54 and within housing section 12c are electric motor
64, hydraulic pump 66, hydraulic manifold 62, equalizer valve 60,
formation probe assembly 50, pressure transducers 160, and draw
down piston 170. Hydraulic accumulators provided as part of the
hydraulic system for operating formation probe assembly 50 are also
disposed about mandrel 54 in various locations, one such
accumulator 68 being shown in FIG. 2D.
[0042] Electric motor 64 may be a permanent magnet motor powered by
battery packs 20, 22 and capacitor banks 32. Motor 64 is
interconnected to and drives hydraulic pump 66. Pump 66 provides
fluid pressure for actuating formation probe assembly 50. Hydraulic
manifold 62 includes various solenoid valves, check valves,
filters, pressure relief valves, thermal relief valves, pressure
transducer 160b and hydraulic circuitry employed in actuating and
controlling formation probe assembly 50 as explained in more detail
below.
[0043] Referring again to FIG. 2C, mandrel 52 includes a central
segment 71. Disposed about segment 71 of mandrel 52 are pressure
balance piston 70 and spring 76. Mandrel 52 includes a spring stop
extension 77 at the upper end of segment 71. Stop ring 88 is
threaded to mandrel 52 and includes a piston stop shoulder 80 for
engaging corresponding annular shoulder 73 formed on pressure
balance piston 70. Pressure balance piston 70 further includes a
sliding annular seal or barrier 69. Barrier 69 consists of a
plurality of inner and outer o-ring and lip seals axially disposed
along the length of piston 70.
[0044] Beneath piston 70 and extending below inner mandrel 52 is a
lower oil chamber or reservoir 78, described more fully below. An
upper chamber 72 is formed in the annulus between central portion
71 of mandrel 52 and the wall of housing section 12c, and between
spring stop portion 77 and pressure balance piston 70. Spring 76 is
retained within chamber 72. Chamber 72 is open through port 74 to
annulus 150. As such, drilling fluids will fill chamber 72 in
operation. An annular seal 67 is disposed about spring stop portion
77 to prevent drilling fluid from migrating above chamber 72.
[0045] Barrier 69 maintains a seal between the drilling fluid in
chamber 72 and the hydraulic oil that fills and is contained in oil
reservoir 78 beneath piston 70. Lower chamber 78 extends from
barrier 69 to seal 65 located at a point generally noted as 83 and
just above transducers 160 in FIG. 2E. The oil in reservoir 78
completely fills all space between housing section 12c and
formation tester mandrel 54. The hydraulic oil in chamber 78 may be
maintained at slightly greater pressure than the hydrostatic
pressure of the drilling fluid in annulus 150. The annulus pressure
is applied to piston 70 via drilling fluid entering chamber 72
through port 74. Because lower oil chamber 78 is a closed system,
the annulus pressure that is applied via piston 70 is applied to
the entire chamber 78. Additionally, spring 76 provides a slightly
greater pressure to the closed oil system 78 such that the pressure
in oil chamber 78 is substantially equal to the annulus fluid
pressure plus the pressure added by the spring force. This slightly
greater oil pressure is desirable so as to maintain positive
pressure on all the seals in oil chamber 78. Having these two
pressures generally balanced (even though the oil pressure is
slightly higher) is easier to maintain than if there was a large
pressure differential between the hydraulic oil and the drilling
fluid. Between barrier 69 in piston 70 and point 83, the hydraulic
oil fills all the space between the outside diameter of mandrels
52, 54 and the inside diameter of housing section 12c, this region
being marked as distance 82 between points 81 and 83. The oil in
reservoir 78 is employed in the hydraulic circuit 200 (FIG. 9) used
to operate and control formation probe assembly 50 as described in
more detailed below.
[0046] Equalizer valve 60, best shown in FIG. 3, is disposed in
formation tester mandrel 54b between hydraulic manifold 62 and
formation probe assembly 50. Equalizer valve 60 is in fluid
communication with hydraulic passageway 85 and with longitudinal
fluid passageway 93 formed in mandrel 54b. Prior to actuating
formation probe assembly 50 so as to test the formation, drilling
fluid fills passageways 85 and 93 as valve 60 is normally open and
communicates with annulus 150 through port 84 in the wall of
housing section 12c. When the formation fluids are being sampled by
formation probe assembly 50, valve 60 closes the passageway 85 to
prevent drilling fluids from annulus 150 entering passageway 85 or
passageway 93.
[0047] As shown in FIGS. 3 and 4, housing section 12c includes a
recessed portion 135 adjacent to formation probe assembly 50 and
equalizer valve 60. The recessed portion 135 includes a planar
surface or "flat" 136. The ports through which fluids may pass into
equalizing valve 60 and probe assembly 50 extend through flat 136.
In this manner, as drill string 5 and formation tester 10 are
rotated in the borehole, formation probe assembly 50 and equalizer
valve 60 are better protected from impact, abrasion and other
forces. Flat 136 is recessed at least 1/4 inch and may be at least
12 inch from the outer diameter of housing section 12c. Similar
flats 137, 138 are also formed about housing section 12c at
generally the same axial position as flat 136 to increase flow area
for drilling fluid in the annulus 150 of borehole 8.
[0048] Disposed about housing section 12c adjacent to formation
probe assembly 50 is stabilizer 154. Stabilizer 154 may have an
outer diameter close to that of nominal borehole size. As explained
below, formation probe assembly 50 includes a seal pad 140 that is
extendable to a position outside of housing 12c to engage the
borehole wall 151. As explained, probe assembly 50 and seal pad 140
of formation probe assembly 50 are recessed from the outer diameter
of housing section 12c, but they are otherwise exposed to the
environment of annulus 150 where they could be impacted by the
borehole wall 151 during drilling or during insertion or retrieval
of bottom hole assembly 6. Accordingly, being positioned adjacent
to formation probe assembly 50, stabilizer 154 provides additional
protection to the seal pad 140 during insertion, retrieval and
operation of bottom hole assembly 6. It also provides protection to
pad 140 during operation of formation tester 10. In operation, a
piston extends seal pad 140 to a position where it engages the
borehole wall 151. The force of the pad 140 against the borehole
wall 151 would tend to move the formation tester 10 in the
borehole, and such movement could cause pad 140 to become damaged.
However, as formation tester 10 moves sideways within the borehole
as the piston is extended into engagement with the borehole wall
151, stabilizer 154 engages the borehole wall and provides a
reactive force to counter the force applied to the piston by the
formation. In this manner, further movement of the formation test
tool 10 is resisted.
[0049] Referring to FIG. 2E, mandrel 54c contains chamber 63 for
housing pressure transducers 160 a, c, and d as well as electronics
for driving and reading these pressure transducers. In addition,
the electronics in chamber 63 contain memory, a microprocessor, and
power conversion circuitry for properly utilizing power from a
power bus (not shown).
[0050] Referring still to FIG. 2E, housing section 12d includes
pins ends 86, 87. Lower end 48 of housing section 12c threadedly
engages upper end 86 of housing section 12d. Beneath housing
section 12d, and between formation tester tool 10 and drill bit 7
are other sections of the bottom hole assembly 6 that constitute
conventional MWD tools, generally shown in FIG. 1 as MWD sub 13. In
a general sense, housing section 12d is an adapter used to
transition from the lower end of formation tester tool 10 to the
remainder of the bottom hole assembly 6. The lower end 87 of
housing section 12d threadedly engages other sub assemblies
included in bottom hole assembly 6 beneath formation tester tool
10. As shown, flowbore 14 extends through housing section 12d to
such lower subassemblies and ultimately to drill bit 7.
[0051] Referring again to FIG. 3 and to FIG. 3A, drawdown piston
170 is retained in drawdown manifold 89 that is mounted on
formation tester mandrel 54b within housing 12c. Piston 170
includes annular seal 171 and is slidingly received in cylinder
172. Spring 173 biases piston 170 to its uppermost or shouldered
position as shown in FIG. 3A. Separate hydraulic lines (not shown)
interconnect with cylinder 172 above and below piston 170 in
portions 172a, 172b to move piston 170 either up or down within
cylinder 172 as described more fully below. A plunger 174 is
integral with and extends from piston 170. Plunger 174 is slidingly
disposed in cylinder 177 coaxial with 172. Cylinder 175 is the
upper portion of cylinder 177 that is in fluid communication with
the longitudinal passageway 93 as shown in FIG. 3A. Cylinder 175 is
flooded with drilling fluid via its interconnection with passageway
93. Cylinder 177 is filled with hydraulic fluid beneath seal 166
via its interconnection with hydraulic circuit 200. Plunger 174
also contains scraper 167 that protects seal 166 from debris in the
drilling fluid. Scraper 167 may be an o-ring energized lip
seal.
[0052] As best shown in FIG. 5, formation probe assembly 50
generally includes stem 92, a generally cylindrical adapter sleeve
94, piston 96 adapted to reciprocate within adapter sleeve 94, and
a snorkel assembly 98 adapted for reciprocal movement within piston
96. Housing section 12c and formation tester mandrel 54b include
aligned apertures 90a, 90b, respectively, that together form
aperture 90 for receiving formation probe assembly 50.
[0053] Stem 92 includes a circular base portion 105 with an outer
flange 106. 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 that, in turn, is in fluid
communication with longitudinal fluid chamber or passageway 93,
best shown in FIG. 3.
[0054] Adapter sleeve 94 includes inner end 111 that engages flange
106 of stem number 92. Adapter sleeve 94 is secured within aperture
90 by threaded engagement with mandrel 54b at segment 110. The
outer end 112 of adapter sleeve 94 extends to be substantially
flushed with flat 136 formed in housing member 12c.
Circumferentially spaced about the outermost surface of adapter
sleeve 94 is a plurality of tool engaging recesses 158. These
recesses are employed to thread adapter 94 into and out of
engagement with mandrel 54b. 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 base section 118
and an extending portion 119 that includes inner cylindrical
surface 120. Piston 96 further includes central bore 121.
[0055] Snorkel 98 includes a base portion 125, a snorkel extension
126, and a central passageway 127 extending through base 125 and
extension 126.
[0056] Formation tester apparatus 50 is assembled such that piston
base 118 is permitted to reciprocate along surface 113 of adapter
sleeve 94. Similarly, snorkel base 125 is disposed within piston 96
and snorkel extension 126 is adapted for reciprocal movement along
piston surface 120. Central passageway 127 of snorkel 98 is axially
aligned with tubular extension 107 of stem 92 and with screen
100.
[0057] Referring to FIGS. 5 and 6C, screen 100 is a generally
tubular member having a central bore 132 extending between a fluid
inlet end 131 and outlet end 122. Outlet end 122 includes a central
aperture 123 that is disposed about stem extension 107. Screen 100
further includes a flange 130 adjacent to fluid inlet end 131 and
an internally slotted segment 133 having slots 134. Apertures 129
are formed in screen 100 adjacent end 122. Between slotted segment
133 and apertures 129, screen 100 includes threaded segment 124 for
threadedly engaging snorkel extension 126.
[0058] Scraper 102 includes a central bore 103, threaded extension
104 and apertures 101 that are in fluid communication with central
bore 103. Section 104 threadedly engages internally threaded
section 109 of stem extension 107, and is disposed within central
bore 132 of screen 100.
[0059] Referring now to FIGS. 5, 7 and 8, seal pad 140 may be
generally donut-shaped having base surface 141, an opposite sealing
surface 142 for sealing against the borehole wall, a
circumferential edge surface 143 and a central aperture 144. In the
embodiment shown, base surface 141 is generally flat and is bonded
to a metal skirt 145 having circumferential edge 153 with recesses
152 and corners 2008. Seal pad 140 seals and prevents drilling
fluid from entering the probe assembly 50 during formation testing
so as to enable pressure transducers 160 to measure the pressure of
the formation fluid. The rate at which the pressure measured by the
formation test tool increases is an indication of the permeability
of the formation 9. More specifically, seal pad 40 seals against
the mudcake 49 that forms on the borehole wall 151. Typically, the
pressure of the formation fluid is less than the pressure of the
drilling fluids that are circulated in the borehole. A layer of
residue from the drilling fluid forms a mudcake 49 on the borehole
wall and separates the two pressure areas. Pad 140, when extended,
conforms its shape to the borehole wall and, together with the
mudcake 49, forms a seal through which formation fluids may be
collected.
[0060] As best shown in FIGS. 3, 5, and 6, pad 140 is sized so that
it may be retracted completely within aperture 90. In this
position, pad 140 is protected both by flat 136 that surrounds
aperture 90 and by recess 135 that positions face 136 in a setback
position with respect to the outside surface of housing 12. Pad 140
is preferably made of an elastomeric material, but is not limited
to such a material.
[0061] To help with a good pad seal, tool 10 may include, among
other things, centralizers for centralizing the formation probe
assembly 50 and thereby normalizing pad 140 relative to the
borehole wall. For example, the formation tester may include
centralizing pistons coupled to a hydraulic fluid circuit
configured to extend the pistons in such a way as to protect the
probe assembly and pad, and also to provide a good pad seal.
[0062] The hydraulic circuit 200 used to operate probe assembly 50,
equalizer valve 60, and draw down piston 170 is illustrated in FIG.
9. A microprocessor-based controller 190 is electrically coupled to
all of the controlled elements in the hydraulic circuit 200
illustrated in FIG. 10, although the electrical connections to such
elements are conventional and are not illustrated other than
schematically. Controller 190 is located in electronics module 30
in housing section 12a, although it could be housed elsewhere in
bottom hole assembly 6. Controller 190 detects the control signals
transmitted from a master controller (not shown) 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 other conventional means for transmitting signals
to downhole tools.
[0063] When controller 190 receives a command to initiate formation
testing, the drill string has stopped rotating. As shown in FIG. 9,
motor 64 is coupled to pump 66 that draws hydraulic fluid out of
hydraulic reservoir 78 through a serviceable filter 79. As will be
understood, the pump 66 directs hydraulic fluid into hydraulic
circuit 200 that includes formation probe assembly 50, equalizer
valve 60, draw down piston 170 and solenoid valves 176, 178,
180.
[0064] The operation of formation tester 10 is best understood in
reference to FIG. 9 in conjunction with FIGS. 3A, 5 and 6A-C. In
response to an electrical control signal, controller 190 energizes
solenoid valve 180 and starts motor 64. Pump 66 then begins to
pressurize hydraulic circuit 200 and, more particularly, charges
probe retract accumulator 182. The act of charging accumulator 182
also ensures that the probe assembly 50 is retracted and that
drawdown piston 170 is in its initial shouldered position as shown
in FIG. 3A. When the pressure in system 200 reaches a predetermined
value, such as 1800 p.s.i. as sensed by pressure transducer 160b,
controller 190 (which continuously monitors pressure in the system)
energizes solenoid valve 176 and de-energizes solenoid valve 180,
which causes probe piston 96 and snorkel 98 to begin to extend
toward the borehole wall 151. Concurrently, check valve 194 and
relief valve 193 seal the probe retract accumulator 182 at a
pressure charge of between approximately 500 to 1250 p.s.i.
[0065] Piston 96 and snorkel 98 extend from the position shown in
FIG. 6A to that shown in FIG. 6B where pad 140 engages the mudcake
49 on borehole wall 151. With hydraulic pressure continued to be
supplied to the extend side of the piston 96 and snorkel 98, the
snorkel then penetrates the mudcake as shown in FIG. 6C. There are
two expanded positions of snorkel 98, generally shown in FIGS. 6B
and 6C. The piston 96 and snorkel 98 move outwardly together until
the pad 140 engages the borehole wall 151. This combined motion
continues until the force of the borehole wall against pad 140
reaches a pre-determined magnitude, for example 5,500 lbs., causing
pad 140 to be squeezed. At this point, a second stage of expansion
takes place with snorkel 98 then moving within the cylinder 120 in
piston 96 to penetrate the mudcake 49 on the borehole wall 151 and
to receive formation fluids.
[0066] As seal pad 140 is pressed against the borehole wall, the
pressure in circuit 200 rises and when it reaches a predetermined
pressure, valve 192 opens so as to close equalizer valve 60,
thereby isolating fluid passageway 93 from the annulus. In this
manner, valve 192 ensures that valve 60 closes only after the seal
pad 140 has entered contact with mudcake 49 that lines borehole
wall 151. Passageway 93, now closed to the annulus 150, is in fluid
communication with cylinder 175 at the upper end of cylinder 177 in
draw down manifold 89, best shown in FIG. 3A.
[0067] With solenoid valve 176 still energized, probe seal
accumulator 184 is charged until the system reaches a predetermined
pressure, for example 1800 p.s.i., as sensed by pressure transducer
160b. When that pressure is reached, controller 190 energizes
solenoid valve 178 to begin drawdown. Energizing solenoid valve 178
permits pressurized fluid to enter portion 172a of cylinder 172
causing draw down piston 170 to retract. When that occurs, plunger
174 moves within cylinder 177 such that the volume of fluid
passageway 93 increases by the volume of the area of the plunger
174 times the length of its stroke along cylinder 177. This
movement increases the volume of cylinder 175, thereby increasing
the volume of fluid passageway 93. For example, the volume of fluid
passageway 93 may be increased by 10 cc as a result of piston 170
being retracted.
[0068] As draw down piston 170 is actuated, formation fluid may
thus be drawn through central passageway 127 of snorkel 98 and
through screen 100. The movement of draw down piston 170 within its
cylinder 172 lowers the pressure in closed passageway 93 to a
pressure below the formation pressure, such that formation fluid is
drawn through screen 100 and snorkel 98 into aperture 101, 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
probe assembly 50, passageways 85, 93 [FIG. 3], the passageways
interconnecting 93 with draw down piston 170 and pressure
transducers 160a,c) may have a volume of approximately 40 cc.
Drilling mud in annulus 150 is not drawn into snorkel 98 because
pad 140 seals against the mudcake. Snorkel 98 serves as a conduit
through which the formation fluid may pass and the pressure of the
formation fluid may be measured in passageway 93 while pad 140
serves as a seal to prevent annular fluids from entering the
snorkel 98 and invalidating the formation pressure measurement.
[0069] Referring momentarily to FIGS. 5 and 6C, 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 formation fluid then passes between the outer
surface of screen 100 and the inner surface of snorkel extension
126 where it next passes through apertures 123 in screen 100 and
into the central passageway 108 of stem 92 by passing through
apertures 101 and central passage bore 103 of scraper 102.
[0070] Referring again to FIG. 9, with seal pad 140 sealed against
the borehole wall, check valve 195 maintains the desired pressure
acting against piston 96 and snorkel 98 to maintain the proper seal
of pad 140. Additionally, because probe seal accumulator 184 is
fully charged, should tool 10 move during drawdown, additional
hydraulic fluid volume may be supplied to piston 96 and snorkel 98
to ensure that pad 140 remains tightly sealed against the borehole
wall. In addition, should the borehole wall 151 move in the
vicinity of pad 140, the probe seal accumulator 184 will supply
additional hydraulic fluid volume to piston 96 and snorkel 98 to
ensure that pad 140 remains tightly sealed against the borehole
wall 151. Without accumulator 184 in circuit 200, movement of the
tool 10 or borehole wall 151, and thus of formation probe assembly
50, could result in a loss of seal at pad 140 and a failure of the
formation test.
[0071] With the drawdown piston 170 in its fully retracted position
and formation fluid drawn into closed system 93, the pressure will
stabilize and enable pressure transducers 160a,c to sense and
measure formation fluid pressure. The measured pressure is
transmitted to the controller 190 in the electronic section where
the information is stored in memory and, alternatively or
additionally, is communicated to the master controller in the MWD
tool 13 below formation tester 10 where it may be transmitted to
the surface via mud pulse telemetry or by any other conventional
telemetry means.
[0072] When drawdown is completed, piston 170 actuates a contact
switch 320 mounted in endcap 400 and piston 170, as shown in FIG.
3A. The drawdown switch assembly consists of contact 300, wire 308
coupled to contact 300, plunger 302, spring 304, ground spring 306,
and retainer ring 310. Piston 170 actuates switch 320 by causing
plunger 302 to engage contact 300 that causes wire 308 to couple to
system ground via contact 300 to plunger 302 to ground spring 306
to piston 170 to endcap 400 that is in communication with system
ground (not shown).
[0073] When the contact switch 320 is actuated controller 190
responds by shutting down motor 64 and pump 66 for energy
conservation. Check valve 196 traps the hydraulic pressure and
maintains piston 170 in its retracted position. In the event of any
leakage of hydraulic fluid that might allow piston 170 to begin to
move toward its original shouldered position, drawdown accumulator
186 will provide the necessary fluid volume to compensate for any
such leakage and thereby maintain sufficient force to retain piston
170 in its retracted position.
[0074] During this interval, controller 190 continuously monitors
the pressure in fluid passageway 93 via pressure transducers 160a,c
until the pressure stabilizes, or after a predetermined time
interval.
[0075] When the measured pressure stabilizes, or after a
predetermined time interval, controller 190 de-energizes solenoid
valve 176. De-energizing solenoid valve 176 removes pressure from
the close side of equalizer valve 60 and from the extend side of
probe piston 96. Spring 58 then returns the equalizer valve 60 to
its normally open state and probe retract accumulator 182 will
cause piston 96 and snorkel 98 to retract, such that seal pad 140
becomes disengaged with the borehole wall. Thereafter, controller
190 again powers motor 64 to drive pump 66 and again energizes
solenoid valve 180. This step ensures that piston 96 and snorkel 98
have fully retracted and that the equalizer valve 60 is opened.
Given this arrangement, the formation tool 10 has a redundant probe
retract mechanism. Active retract force is provided by the pump 66.
A passive retract force is supplied by probe retract accumulator
182 that is capable of retracting the probe even in the event that
power is lost. Accumulator 182 may be charged at the surface before
being employed downhole to provide pressure to retain the piston
and snorkel in housing 12c.
[0076] Referring again briefly to FIGS. 5 and 6, as piston 96 and
snorkel 98 are retracted from their position shown in FIG. 6C to
that of FIG. 6B and then FIG. 6A, screen 100 is drawn back into
snorkel 98. As this occurs, the flange on the outer edge of scraper
102 drags and thereby scrapes the inner surface of screen member
100. In this manner, material screened from the formation fluid
upon its entering of screen 100 and snorkel 98 is removed from
screen 100 and deposited into the annulus 150. Similarly, scraper
102 scrapes the inner surface of screen member 100 when snorkel 98
and screen 100 are extended toward the borehole wall.
[0077] After a predetermined pressure, for example 1800 p.s.i., is
sensed by pressure transducer 160b and communicated to controller
190 (indicating that the equalizer valve is open and that the
piston and snorkel are fully retracted), controller 190
de-energizes solenoid valve 178 to remove pressure from side 172a
of drawdown piston 170. With solenoid valve 180 remaining
energized, positive pressure is applied to side 172b of drawdown
piston 170 to ensure that piston 170 is returned to its original
position (as shown in FIG. 3). Controller 190 monitors the pressure
via pressure transducer 160b and when a predetermined pressure is
reached, controller 190 determines that piston 170 is fully
returned and it shuts off motor 64 and pump 66 and de-energizes
solenoid valve 180. With all solenoid valves 176, 178, 180 returned
to their original position and with motor 64 off, tool 10 is back
in its original condition and drilling may again be commenced.
[0078] Relief valve 197 protects the hydraulic system 200 from
overpressure and pressure transients. Various additional relief
valves may be provided. Thermal relief valve 198 protects trapped
pressure sections from overpressure. Check valve 199 prevents back
flow through the pump 66.
[0079] The formation test tool 10 may operate in two general modes:
pumps-on operation and pumps-off operation. During a pumps-on
operation, mud pumps on the surface pump drilling fluid through the
drill string 6 and back up the annulus 150 while testing. Using
that column of drilling fluid, the tool 10 may transmit data to the
surface using mud pulse telemetry during the formation test. The
tool 10 may also receive mud pulse telemetry downlink commands from
the surface. During a formation test, the drill pipe and formation
test tool are not rotated. However, it may be the case that an
immediate movement or rotation of the drill string will be
necessary. As a failsafe feature, at any time during the formation
test, an abort command may be transmitted from surface to the
formation test tool 10. In response to this abort command, the
formation test tool will immediately discontinue the formation test
and retract the probe piston to its normal, retracted position for
drilling. The drill pipe may then be moved or rotated without
causing damage to the formation test tool.
[0080] During a pumps-off operation, a similar failsafe feature may
also be active. The formation test tool 10 and/or MWD tool 13 may
be adapted to sense when the mud flow pumps are turned on.
Consequently, the act of turning on the pumps and reestablishing
flow through the tool may be sensed by pressure transducer 160d or
by other pressure sensors in bottom hole assembly 6. This signal
will be interpreted by a controller in the MWD tool 13 or other
control and communicated to controller 190 that is programmed to
automatically trigger an abort command in the formation test tool
10. At this point, the formation test tool 10 will immediately
discontinue the formation test and retract the probe piston to its
normal position for drilling. The drill pipe may then be moved or
rotated without causing damage to the formation test tool.
[0081] The uplink and downlink commands are not limited to mud
pulse telemetry. By way of example and not by way of limitation,
other telemetry systems may include manual methods, 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 active pumping, but
other telemetry systems do not. The failsafe abort command may
therefore be sent from the surface to the formation test tool using
an alternative telemetry system regardless of whether the mud flow
pumps are on or off.
[0082] The down hole receiver for downlink commands or data from
the surface may reside within the formation test tool or within an
MWD tool 13 with which it communicates. Likewise, the down hole
transmitter for uplink commands or data from down hole may reside
within the formation test tool 10 or within an MWD tool 13 with
which it communicates. The receivers and transmitters may each be
positioned in MWD tool 13 and the receiver signals may be
processed, analyzed, and sent to a master controller in the MWD
tool 13 before being relayed to local controller 190 in formation
testing tool 10.
[0083] Commands or data sent from surface to the formation test
tool may be used for more than transmitting a failsafe abort
command. The formation test tool may have many preprogrammed
operating modes. A command from the surface may be used to select
the desired operating mode. For example, one of a plurality of
operating modes may be selected by transmitting a header sequence
indicating a change in operating mode followed by a number of
pulses that correspond to that operating mode. Other means of
selecting an operating mode will certainly be known to those
skilled in the art.
[0084] In addition to the operating modes discussed, other
information may be transmitted from the surface to the formation
test tool 10. This information may include critical operational
data such as depth or surface drilling mud density. The formation
test tool may use this information to help refine measurements or
calculations made downhole or to select an operating mode. Commands
from the surface might also be used to program the formation test
tool to perform in a mode that is not preprogrammed.
[0085] Measuring Formation Properties
[0086] Referring again to FIG. 9, the formation test tool 10 may
include four pressure transducers 160: two quartz crystal gauges
160a, 160d, a strain gauge 160c, and a differential strain gage
160b. One of the quartz crystal gauges 160a is in communication
with the annulus mud and also senses formation pressures during the
formation test. The other quartz crystal gauge 160d is in
communication with the flowbore 14 at all times. In addition, both
quartz crystal gauges 160a and 160d may have temperature sensors
associated with the crystals. The temperature sensors may be used
to compensate the pressure measurement for thermal effects. The
temperature sensors may also be used to measure the temperature of
the fluids near the pressure transducers. For example, the
temperature sensor associated with quartz crystal gauge 160a is
used to measure the temperature of the fluid near the gage in
chamber 93. The third transducer is a strain gauge 160c and is in
communication with the annulus mud and also senses formation
pressures during the formation test. The quartz transducers 160a,
160d provide accurate, steady-state pressure information, whereas
the strain gauge 160c provides faster transient response. In
performing the sequencing during the formation test, chamber 93 is
closed off and both the annulus quartz gauge 160a and the strain
gauge 160c measure pressure within the closed chamber 93. The
strain gauge transducer 160c essentially is used to supplement the
quartz gauge 160a measurements. When the formation tester 10 is not
in use, the quartz transducers 160a, 160d may operatively measure
pressure while drilling to serve as a pressure while drilling
tool.
[0087] Referring now to FIG. 10, a pressure versus time graph
illustrates in a general way the pressure sensed by pressure
transducers 160a, 160c during the operation of formation tester 10.
As the formation fluid is drawn within the tester, pressure
readings are taken continuously by transducer 160a, 160c. The
sensed pressure will initially be equal to the annulus pressure
shown at point 201. As pad 140 is extended and equalizer valve 60
is closed, there will be a slight increase in pressure as shown at
202. This occurs when the pad 140 seals against the borehole wall
151 and squeezes the drilling fluid trapped in the now-isolated
passageway 93. As drawn down piston 170 is actuated, the volume of
the closed chamber 93 increases, causing the pressure to decrease
as shown in region 203. This is known as the pretest drawdown. The
combination of the flow rate and snorkel inner diameter determines
an effective range of operation for tester 10. When the drawn down
piston bottoms out within cylinder 172, a differential pressure
with the formation fluid exists causing the fluid in the formation
to move towards the low pressure area and, therefore, causing the
pressure to build over time as shown in region 204. The pressure
begins to stabilize, and at point 205, achieves the pressure of the
formation fluid in the zone being tested. After a fixed time, such
as three minutes after the end of region 203, the equalizer valve
60 is again opened, and the pressure within chamber 93 equalizes
back to the annulus pressure as shown at 206.
[0088] In an alternative embodiment to the typical formation test
sequence, the test sequence is stopped after pad 140 is extended
and equalizer valve 60 is closed, and the slight increase in
pressure is recorded as shown at 202 in FIG. 10. The normal test
sequence is stopped so that a response to the increase in pressure
202 may be observed. Since the test sequence has been stopped
before draw down piston 170 is actuated, no fluid flow has been
induced by the formation probe assembly; the formation probe
assembly is maintaining a substantially non-flow condition. The
non-flow pressure response to increase 202 can be recorded and
interpreted to determine properties of the mudcake, such as
mobility. If the response to increase 202 is a quick equalization
of the pressure back to hydrostatic 201, then the mudcake has high
permeability, and is most likely not very thick or durable. If the
response is a slow decrease in pressure, then the mudcake is likely
thicker and more impermeable.
[0089] To assist in determining mudcake thickness, in addition to
the method described above, the position indicator on the probe
assembly, described in the U.S. patent application Ser. No. ______
entitled "Downhole Probe Assembly," having U.S. Express Mail Label
Number EV 303483549 US and Attorney Docket Number 1391-52601, may
be used to measure how far the probe assembly extends after
engagement with the mud filtrate. This measurement gives an
indication of how thick the mud filtrate is, and may be used to
bolster the data gathered using pressure response, described above.
Again, this measurement may be taken under a non-flow condition of
the formation probe assembly, as previously described.
[0090] When taking pressure measurements, it is also possible to
use the different pressure transducers to verify each gauge's
reading compared to the others. Additionally, with multiple
transducers, hydrostatic pressure in the borehole may be used to
reverify gauges in the same location, by confirming that they are
taking similar hydrostatic measurements. Because quartz gauges are
more accurate, the quartz gauge response may be used to calibrate
the strain gauge if the response is not highly transient.
[0091] FIG. 11 illustrates representative formation test pressure
curves. The solid curve 220 represents pressure readings P.sub.sg
detected and transmitted by the strain gauge 160c. Similarly, the
pressure P.sub.q, indicated by the quartz gauge 160a, is shown as a
dashed line 222. As noted above, strain gauge transducers generally
do not offer the accuracy exhibited by quartz transducers and
quartz transducers do not provide the transient response offered by
strain gauge transducers. Hence, the instantaneous formation test
pressures indicated by the strain gauge 160c and quartz 160a
transducers are likely to be different. For example, at the
beginning of a formation test, the pressure readings P.sub.hyd1
indicated by the quartz transducer P.sub.q and the strain gauge
P.sub.sg transducer are different and the difference between these
values is indicated as E.sub.offs1 in FIG. 11.
[0092] With the assumption that the quartz gauge reading P.sub.q is
the more accurate of the two readings, the actual formation test
pressures may be calculated by adding or subtracting the
appropriate offset error E.sub.off1 to the pressures indicated by
the strain gauge P.sub.sg for the duration of the formation test.
In this manner, the accuracy of the quartz transducer and the
transient response of the strain gauge may both be used to generate
a corrected formation test pressure that, where desired, is used
for real-time calculation of formation characteristics or
calibration of one or more of the gauges.
[0093] As the formation test proceeds, it is possible that the
strain gauge readings may become more accurate or for the quartz
gauge reading to approach actual pressures in the pressure chamber
even though that pressure is changing. In either case, it is
probable that the difference between the pressures indicated by the
strain gauge transducer and the quartz transducer at a given point
in time may change over the duration of the formation test. Hence,
it may be desirable to consider a second offset error that is
determined at the end of the test where steady state conditions
have been resumed. Thus, as pressures P.sub.hyd2 level off at the
end of the formation test, it may be desirable to calculate a
second offset error E.sub.offS2. This second offset error
E.sub.offs2 might then be used to provide an after-the-fact
adjustment to the formation test pressures, or calibration of the
strain gauge.
[0094] The offset values E.sub.offs1 and E.sub.offs2 may be used to
adjust specific data points in the test. For example, all critical
points up to P.sub.fu might be adjusted using errors E.sub.offs1,
whereas all remaining points might be adjusted offset using error
E.sub.offs2. Another solution may be to calculate a weighted
average between the two offset values and apply this single
weighted average offset to all strain gauge pressure readings taken
during the formation test. Other methods of applying the offset
error values to accurately determine actual formation test
pressures may be used accordingly and will be understood by those
skilled in the art.
[0095] As previously generally described, quartz gauges are used
for accuracy because they are steady and stable over time and
retain their calibration over a wide variety of conditions.
However, they are slow to respond to their environment. There are
changes in pressure taking place during the measurement that the
quartz gauge cannot detect. On the other hand, strain gauges are
susceptible to change and to calibration effects. However, they are
quick to respond to changes in their environment. Thus, both gauges
may be used, with the quartz gauge used to get an accurate pressure
reading while the strain gauge is used to look at the differences
in pressure.
[0096] In another embodiment for calibrating the strain gauge using
the quartzdyne gauge, a simple linear fit may be used. Referring to
FIG. 12, pressure curve 500 is illustrated representing a typical
drawdown and buildup curve measured during a pressure formation
test. Portion 502 of curve 500 shows a stable pressure, which is
typically a measure of the annulus pressure because the formation
test has not begun yet. The annulus pressure will usually be higher
than the formation pressure because most wells are drilled in
overbalanced situations, where the drilling fluid in the annulus is
kept at a higher pressure than the formation so as to stabilize the
borehole and prevent borehole deterioration and blowout.
[0097] The pressures measured by the quartz gauge, P.sub.Q1, and
the corrected strain gauge, P.sub.SG1, will be the same in curve
portion 502, where the pressure is stable and near hydrostatic, and
before any dynamic responses are detected by either gauge. Once the
formation pressure test has begun, a slight increase in pressure is
illustrated at 501 before the drawdown is commenced, illustrated by
curve portion 504. After drawdown is completed, the formation
pressure is allowed to build back up until it stabilizes,
illustrated at curve portion 506. Now, a second set of stabilized
pressures may be taken, P.sub.Q2 and P.sub.SG2, and they will most
likely be different because the dynamic response of the strain
gauge is much less accurate than the dynamic response of the quartz
gauge.
[0098] To recalibrate the strain gauge, two unknown values are
identified and a simple linear fit is applied to the known and
unknown values. The unknown values may be identified as P.sub.off,
representing the pressure offset between the two sets of stable
pressure measurements, and P.sub.slope, representing the slope of
the curve between the two sets of stable pressure measurements. The
known values are P.sub.Q1, P.sub.SG1, P.sub.Q2 and P.sub.SG2. The
linear fit equations may be represented as:
P.sub.Q1=P.sub.off+(P.sub.slope*P.sub.SG1), and
P.sub.Q2=P.sub.off+(P.sub.slope*P.sub.SG2); which may be expressed
as:
P.sub.slope=(P.sub.Q1-P.sub.Q2)/(P.sub.SG1-P.sub.SG2), and
P.sub.off=P.sub.Q1-(P.sub.Q1-P.sub.Q2)/(P.sub.SG1-P.sub.SG2)*P.sub.SG1;
which may be expressed as:
P.sub.SG corrected=P.sub.off+(P.sub.slope*P.sub.SG).
[0099] With two equations and two unknowns, the equations may be
solved as above to arrive at P.sub.SGcorrected, a corrected value
obtained from the strain gauge. Alternatively, the strain gauge may
be corrected based on the known values alone, substituting for
P.sub.off and P.sub.slope to acquire the equation:
P.sub.SG
corrected=P.sub.Q1-(P.sub.Q1-P.sub.Q2)/(P.sub.SG1-P.sub.SG2)*(P.s-
ub.SG1-P.sub.SG2).
[0100] Further, these gauge corrections may be done "on the fly,"
or after each test as each sequential test is completed in the
wellbore. The corrections may be done on the fly using real time
streaming of the data to the surface using telemetry means, or,
alternatively, using downhole processors and software placed in the
tool.
[0101] Using the MWD tool's embedded software (and neural network
techniques) and a downhole reference standard, such as the quartz
gauge, every depth point in the borehole may be corrected to the
reference. In a formation tester, there will typically be various
types of pressure gauges for measuring pressure in the flow lines
that carry formation fluids. For example, the formation fluid flow
lines, such as lines 91, 93 may be in fluid communication with
quartz gauges and strain gauges, such as transducers 160a, 160c of
FIG. 9. After a drawdown, where formation fluids are drawn into the
formation tester, drawing in of fluids is stopped and the fluids
are allowed to build back up to the pressure of the surrounding
formation. After several of these drawdowns and buildups, the
strain gauges may exhibit large errors in their readings. Thus, as
mentioned before, these strain gauge pressure transducers need to
be calibrated. In one embodiment, the pressure readings at every
point in the well where pressure was measured may be used as a
reference point for continual calibration of the strain gauges,
thereby eliminating the need to calibrate and recalibrate the
strain gauges.
[0102] Every location in the well has a discrete pressure and
associated temperature as well stabilization occurs. Each time a
pressure test is run, the pressure taken by the quartz gauge may be
used as a continual calibration point for the strain gauges. If the
data is continuously collected, a three-dimensional, contour-type
plot of pressure vs. temperature may be created. The three
dimensions that may be used are measured pressure, reference
pressure, as described above, and temperature. Then, neural network
techniques found in the tool's embedded software may be applied to
the collected data such that the strain gauge transducers do not
require recalibration.
[0103] Pressure transducers typically have a pressure data input
range to which their accuracy is defined, such as zero to 10,000
p.s.i. or zero to 20,000 p.s.i. Accuracy is commonly measured as a
percentage of full scale, thus the accuracy of a 10,000 p.s.i.
gauge will be greater because the percentage number of that gauge
will be less than the same percentage number of 20,000. To improve
accuracy of the formation testing tool, several gauges may be used
to cover the possible ranges of pressures to be tested, instead of
using one gauge that covers the whole range. Therefore, to make the
tool more accurate, multiple pressure gauges are used.
[0104] Alternatively, the range of a gauge may be calibrated for a
smaller range to make the gauge more accurate. The manufacturer of
the pressure gauge may set the electronics to detect a broad range
of pressures. The electronics, which are very similar between
gauges, may be adjusted to scale the transducer over a smaller
range, thereby improving accuracy. Similarly, the same transducer
may be used for different pressure ranges by using two or more
calibration tables. The pressure data output effect of the
transducer for the full pressure input range may be determined for
one pressure transducer, and then two or more calibration tables
may be established to interpret the output information given by the
transducers for different pressure input ranges. Therefore,
accuracy may be improved without the use of multiple
transducers.
[0105] Accurate determination of formation pressure is vital to
proper use of the measured formation pressures. However, changing
densities of fluids in the formation testing tool's flow lines can
be problematic. The measured pressure can be corrected for the
density of the fluid in the vertical column of the flow line. The
pressure transducers may be measuring accurate pressures of the
formation fluids the transducers communicate with, but these
transducers are removed from the location of the probe that gathers
the formation fluids. For example, transducers 160a, 160c, 160d are
located below the probe assembly, as illustrated in FIG. 2D-E.
Thus, the pressure at the probe may be different from the pressure
measured at the transducers due to this location offset.
[0106] Preferably, the vertical offset between the reference point
of the transducer and the fluid inlet point at the probe is a known
distance. Additionally, if the formation testing tool is located in
a deviated or inclined well, the orientation of the tool may be
known from a navigational package. Thus, vertical known distance
between the transducer and the probe inlet may be calculated for
any inclination of the tool in the well. Lastly, if the fluid
present in the flow line connecting the transducer and the probe
inlet is known, then the pressure gradient of that fluid may be
used to calculate the pressure at the probe inlet with respect to
the pressure at the transducer.
[0107] For example, water has a pressure gradient of 0.433 p.s.i.
per foot. If it was known that water was present in the flow line
and that there was a foot difference between the pressure
transducer and the probe inlet, a 0.433 p.s.i. correction may be
made in the reading of the pressure transducer.
[0108] Thus, it is preferred that the pressure transducers be
disposed as close to the probe assembly as possible.
[0109] In another embodiment of formation testing, while the
formation probe assembly is engaged with the borehole, instead of
pulling fluids into the probe assembly, or after pulling fluids
into the probe assembly, fluids can be pushed out of the assembly
into the formation. Thus, fluid communication may be established
with the formation in the direction that is opposite to that of
draw down, with such communication tending to pressure up the
formation. This may be accomplished by adjustments to the sequence
of events described previously. Now, the response to this pressure
up can be recorded, and the pressure over time can observed for a
portion of the formation. How the formation responds can be
interpreted to obtain many of the formation properties previously
described. Specifically, the pressure transient response to the
change in formation pressure may be used to determine permeability
of the mud cake, estimating the damage to the near wellbore
formation and calculating mobility of the formation. For further
detail on the process just described, reference may be made to the
Society of Petroleum Engineers paper number 36524 entitled
"Supercharge Pressure Compensation Using a New Wireline Method and
Newly Developed Early Time Spherical Flow Model" and U.S. Pat. No.
5,644,075 entitled "Wireline Formation Tester Supercharge
Correction Method," each hereby incorporated herein by reference
for all purposes.
[0110] Furthermore, the formation may be pressured up as just
described, except to the point where the formation material breaks
or fractures. This is called an injectivity test, and may be done
with fluid from the same area (at the present measurement
location), or fluid, such as water, which may be obtained from
another area of the formation. The fluids obtained from another
area may be stored in either a pressure vessel or in the drawdown
piston assembly, and then injected into another area that contains
a different fluid. Fluids may also be carried from the surface and
selectively injected into the formation.
[0111] If injection rates are high enough to materially break or
induce fracture in the formation, a change in pressure can be
observed and interpreted, as has been previously described, to
obtain formation properties, such as fracture pressure, which may
be used to efficiently design future completion and stimulation
programs. It should be noted that the injectivity may be performed
to test the mud cake's ability to prevent fluid ingress to the
formation. Alternatively, the test may be performed after a draw
down and the mud cake is no longer present.
[0112] Formation testers may also be used to gather additional
information aside from properties of the producible hydrocarbon
fluids. For example, the formation tester tool instruments may be
used to determine the resistivity of the water, which can be used
in the calculation of the formation's water saturation. Knowing the
water saturation helps in predicting the producibility of the
formation. Sensor packages, such as induction packages or button
electrode packages, may be added adjacent the probe assembly that
are tailored to measuring the resistivity of the bound water in the
formation. These sensors, preferably, would be disposed on the
extending portions of the probe assembly, such as the snorkel 98
that may penetrate the mudcake and formation, as illustrated in
FIG. 6C. In addition, sensors may be disposed in the flow lines,
such as flow lines 91, 93, to measure water properties in the
fluids that are drawn into the formation tester assembly.
[0113] The advantage of the probe style formation test tool
described herein is the flexibility to place the probe in a
specific position upon the borehole to best obtain a formation
pressure, or, alternatively, to not place the probe in an
undesirable location. A tool such as an acoustic imaging device can
provide a real time image of the borehole so the operator can
determine where to take a pressure test. Additionally, the image
from a porosity-type tool may provide information on porosity
quality at an orientation within a portion of the well at constant
depth, or at a direction along the wellbore (constant azimuth). It
may also provide a real-time image of fractures intersecting the
wellbore, providing the opportunity to avoid these fractures to
obtain a good test for matrix pressures, or to test at these
fractures to determine fracture properties. The image from these
tools may be sensitive enough to determine that the probe from the
pressure device actually tested at the pre-determined position and
verify that the test was taken at the chosen position. These tools
may also be used to examine the condition of the wellbore. This may
be significant in high angle or horizontal wellbores where debris
such as unremoved cuttings may still be in place and could
interfere with obtaining an accurate formation pressure
measurement.
[0114] It is common for the borehole to exhibit abnormalities due
to erosion from the drill string or circulated drilling fluids.
Abnormalities also exist due to fault lines and different types of
formations abutting each other. Thus, often it is necessary to have
a pre-existing image of the formation so that pressure measurements
may be taken at pinpoint locations rather than at random locations
in the formation. Acoustic, sonic, density, resistivity, gamma ray
and other imaging techniques may be used to image the formation in
real time. Then, the formation testing tool may be azimuthally
oriented to locations of greatest or least porosity, permeability,
density or other formation property, depending on what is to be
gained from the pressure or other formation testing tool
measurement. In cases where imaging tools indicate a sealing or
"tight" zone, pressure measurements may be used to verify whether
there is fluid communication or not. Alternatively, the imaging
tools may be used to find zones that should not be pressure tested,
such as highly dense or impermeable zones.
[0115] Afterwards, the previously mentioned imaging techniques may
be used to verify where the pressure or other measurement was
taken. The seal pad may leave an imprint on the borehole wall, thus
an electrical imaging tool or acoustic scanning tool may be used to
image after the test to verify the pad location on the borehole
wall.
[0116] Pressure and other formation testing tool measurements may
be taken with the mud pumps on or off. Pressure in the annulus is
higher with pumps on than with pumps off, and the pressure drops in
the direction of flow. With higher pressures from circulating,
there is a higher rate of influx of drilling fluids and filtrate
going into the formation, thus forming the mudcake more rapidly.
The equivalent circulating density (ECD) is a measure of the
drilling fluid density taking into account suspended drilling
cuttings, fluid compressibility and the frictional pressure losses
related to fluid flow. ECD will decrease with time if circulation
continues but drilling stops because, as the drilling mud
circulates, more of the drilling cuttings are filtered out while
new cuttings are not being added. If pressure measurements are
being taken by the formation tester, a difference may be noticed in
the formation pressure because of the change in ECD from pumps-on
to pumps-off.
[0117] For example, the formation probe assembly may be extended
and a drawdown test performed wherein the pressure decreases as the
fluids are drawn into the formation tester. Then, after the
drawdown chamber is full, the pressure may build back up to
equilibrate with the pressure in the undisturbed formation. Now, if
the pumps are turned on, the ECD in the annulus increases,
increasing the pressure sensed by the formation tester. If the
pumps are turned off, the pressure will return to the original
pressure before pumps were turned on. This pressure difference is
due to the difference in the ECD and the hydrostatic pressure, and
may be used to indicate how much drilling fluid is penetrating the
formation, or how much communication there is between the drilling
fluids and the formation. This difference may be equated to
mobility or pressure transients, thereby obtaining more accurate
measurements. These effects are associated with supercharge
pressures and effects, which are more thoroughly described in
various of the previously incorporated references.
[0118] With the pumps on, pressure pulses are sent downhole by the
mud pumps, communication pulsers or other devices, and the pulses
may be seen to exhibit sinusoidal behavior. During a pressure test,
with the probe assembly extended, the probe may detect these
pressure pulses through the formation because the inside of the
probe assembly is relatively isolated from the wellbore fluids. The
pressure pulses as detected in the wellbore may be compared with
the pressure pulses as detected by the formation tester.
[0119] Referring now to FIG. 13, a pressure pulse curve 600
represents pressures created by the mud pumps or pulsers and
detected by a pressure sensor in communication with the annulus
such as a PWD sensor in the MWD tool 13, or other LWD tool.
Pressure curve 602 represents pressures detected by the formation
probe assembly, which are the pressure pulses that have traveled
from the annulus, through the formation, and into the isolated
probe assembly. Pressure curves 600 and 602 have peaks 604, 606 and
608, 610, respectively. These peaks may be used to determine peak
shifts or phase delay 612 and amplitude difference 614. With the
phase delay 612 and amplitude difference 614, mudcake properties,
such as permeability, porosity and thickness may be determined.
Further, similar formation properties may be determined.
[0120] In an alternative embodiment to the embodiment just
described, the formation testing tool includes more than one
formation probe assembly. Instead of creating pressure pulses at
the surface of the wellbore, the pulses may be created by one probe
assembly while the other probe assembly takes measurements. While
at least two formation probe assemblies are extended and engaged
with the borehole wall, one probe assembly may pulse fluid into the
assembly and back out into the formation by reciprocating the draw
down pistons. Meanwhile, the other probe assembly takes
measurements as described above.
[0121] Formation tests may be taken with the formation tester tool
very soon after the drill bit has penetrated the formation. For
example, the formation tests may be taken immediately after the
formation has been drilled through, such as within ten minutes of
penetration. Taking tests at this time means there is less mud
invasion and less mudcake to contend with, resulting in better
pressure and/or permeability tests, better formation fluid samples
(less contamination) and less rig time required to obtain these
data. Taking tests immediately after drilling will also allow the
drilling operator look for casing points immediately. These tests
may also indicate whether the zone is depleted, or whether hole
collapse is imminent. Corrective actions may then be taken, such as
casing the hole, changing mud properties, continuing drilling, or
others.
[0122] Additionally, the formation may be tested on the way into a
drilled hole and on the way out to observe changes in the mudcake
and formation over time. The two sets of measurements may be
compared to identify changes that are occurring to the borehole and
surrounding formation. The differences over time may indicate
supercharging effects, more fully developed in the various
references previously mentioned, and may be used to correct a model
of the formation to account for the supercharge pressure.
[0123] Predicting pore pressure is typically accomplished by
measuring the magnitude of formation compaction. Formation
compaction typically occurs in shales, thus shale formations must
be drilled and logged to obtain the necessary data to create pore
prediction models. The formation testing tool described herein may
measure pore pressure directly. This measurement is more accurate
and may be used to calibrate pore pressure predictor models.
[0124] Using Formation Property Data
[0125] After measuring formation pressure, permeability and other
formation properties, this information may be sent to the surface
using mud pulse telemetry, or any of various other conventional
means for transmitting signals from downhole tools. At the surface,
the drilling operator may use this information to optimize bit
cutting properties or drilling parameters.
[0126] Knowing mudcake properties allows adjustments to certain
drilling parameters if the mudcake differs from a known,
predetermined, or desirable value; adjustments to the mud system
itself may also be made, to enhance the mud properties and reduce
mud cake thickness or filtrate invasion rate. For example, if the
mudcake is found to be contaminated or impermeable, the drilling
mud properties can be adjusted to reduce the pressure on the
mudcake or reduce the amount of contaminants ingressing into the
mudcake, or chemicals may be added to the mud system to correct mud
cake thickness.
[0127] Furthermore, pressure measurements taken downhole may
indicate the need to make downhole pressure adjustments if, again,
the downhole measurements differ from a desirable known or
predetermined value. However, instead of adjusting mud properties,
other mechanical means may be use to control the downhole pressure.
For example, with a choke control or a rotating blowout preventer
(BOP), the choke or rotating BOP restriction may be manipulated to
mechanically increase or decrease the resistance to flow at the
surface, thereby adjusting the downhole pressure.
[0128] An exemplary drilling parameter that may be adjusted is the
rate of drill bit penetration. Using the formation tester in the
ways described above, certain rock properties, also described
above, can be measured. These properties may be directed to the
surface in real time so as to optimize the rate of penetration
while drilling. With a certain shape of the probe and knowing the
shape of the frontal contact area of the borehole wall, certain
formation properties may be measured. If a formation probe assembly
such as that illustrated in FIGS. 5 and 6A-C, or in the U.S. patent
application Ser. No. ______ entitled "Downhole Probe Assembly,"
previously mentioned and incorporated by reference, is used to
engage the formation, force vs. displacement of the probe assembly
may then be determined using an extensiometer or potentiometer. The
force vs. displacement information may be used to calculate
compressive strength, compressive modulus and other properties of
the formation materials themselves. These formation material
properties are useful in determining and optimizing the rate of
drill bit penetration.
[0129] Measurements taken by the formation testing tool may be used
for optimizing additional drilling applications. For example,
formation pressure may be used to determine casing requirements.
The formation pressures taken downhole may be used to determine the
optimal size and strength of the casing required. If the formation
is found to have a high formation pressure, then the hole may be
cased with a relatively strong casing material to ensure that the
integrity of the borehole is maintained in the high pressure
formation. If the formation is found to have a low pressure, the
casing size may be reduced and different materials may be used to
save costs. Rock strength measurements taken with the tool may also
assist with casing requirements. Solid rock formations require less
casing material because they are stable, while formations composed
of sediments require thicker casing.
[0130] In inclined or horizontal wells, and particularly when the
drilling fluid has stopped circulating, heavier density particles
in the drilling fluid settle toward the lower side of the borehole.
This condition is undesirable because the effective density of the
fluid is lowered. When the surrounding formation is at a higher
pressure than the drilling fluid, hole blowout becomes more likely.
To detect this condition, the formation testing tool may be
oriented to the low side of the borehole, where measurements may
now be taken. In one embodiment, the probe assembly may be extended
and pressures taken. Preferably, the pressure transducers that are
in communication with the annulus, such as transducer 160c or the
PWD sensor in the MWD tool, can be used to take the pressure of the
annulus fluid without extending the probe. If the fluid on the low
side of the borehole is found to have a higher density or weight
than the equivalent drilling fluid density or weight, then the
drilling fluid properties may be adjusted to correct this
condition. Alternatively, or in addition, the measurements may be
taken at other locations in the borehole, such as at the upper
side.
[0131] Anisotropic formations exhibit properties, any property,
with different values when measured in different directions. For
example, resistivity may be different in the horizontal direction
than in the vertical direction, which may be due to the presence of
multiple formation beds or layering within certain types of
rocks.
[0132] For example, formation anisotropy may be determined by
taking formation measurements, such as pressure and temperature,
re-orienting the tool rotationally and taking additional
measurements at additional angles around the borehole.
Alternatively, if multiple probe assemblies or other measuring
devices are disposed about the tool, these measurements taken about
the tool may be taken simultaneously. In addition to taking direct
formation measurements, the tool may take other measurements, such
as sonic and electromagnetic measurements. After all such
measurements have been taken, the formation anisotropy for each
type of measurement may be calculated. A formation anisotropy value
may be tied to or compared with acoustic, resistivity and other
measurements taken by other tools. This would allow, for example,
resistivity to be correlated with permeability changes using known
formation models (more fully described below).
[0133] Typically, formation pressure measurements are estimated
and/or predicted by interpreting certain formation measurements
other than the direct measurement of formation pressure. For
example, pressure while drilling (PWD) and logging while drilling
(LWD) measurements are gathered and analyzed to predict what the
actual formation pressure is. Analysis of data such as rock
properties and stress orientation, and of models such as
fracture-gradient models and trend-based models, can be used to
predict actual formation pressure. Furthermore, direct formation
measurements may be used too supplement, correct or adjust these
data and models to more accurately predict formation pressures. The
advantage with the formation testing tools described and referenced
herein is that the pressure and other formation data may be sent
uphole real time, thereby allowing the models to be updated real
time.
[0134] Additionally, each measured formation property, including
those previously listed and defined, may themselves be used to map
or image the formation. Ultimately, a formation model is developed
so it is known what the formation looks like on a computer screen
at the surface of the borehole. An example of such a formation
model is the Landmark earth model. Each additional measured
property of the formation may be used to make complementary images,
with each new property and image adding to the accuracy of the
formation model or image. Thus, the properties gathered by the
formation tester tools referenced herein, particularly pressure
data, may be used to create better models or enhance existing ones,
to better understand the formations that are being penetrated. As
described before, these models and data may be updated "on the fly"
to calibrate various models for better formation pressure
predictions.
[0135] Similarly, formation test data, such as pressure,
temperature and other previously described data, gathered using a
formation testing tool 10 may be used to improve or correct other
measurements, and vice-versa. Other measurements that may benefit
from real time pressure data and pressure gradient information
include: pressure while drilling (PWD), sonic or acoustic tool
measurements, nuclear magnetic resonance imaging, resistivity,
density, porosity, etc. These measurements or interpretive tools,
such as pore-pressure prediction tools or models, may be updated
based on physical measurements, and are at least somewhat dependent
on pressure or other formation properties. Drilling mud properties
may also be adjusted in a similar fashion, based on the formation
measurements taken real time. Further, the formation data may be
used to assist other services, including drilling fluid services
and completion services, and operation of other tools.
[0136] While drilling, LWD tools may be measuring the resistivity
of the formation fluids and creating resistivity logs. From the
resistivity log and other data, water saturation of the formation
may be calculated. Changes in water saturation with depth may be
observed and may be consolidated into a gradient. The water
saturation level is related to how far above the 100% free water
level the test depth is. The water saturation levels and gradient
may be used to create a capillary pressure curve. The pressure data
from the formation testing tool may be matched up with the
capillary pressure curve, which may then be projected downhole to
estimate the free water level. The free water level may be used to
determine the amount of hydrocarbons, especially gas, that are
available for production. At the 100% free water level, production
is not viable. Thus, the free water level may be determined without
having to test down to the actual free water level.
[0137] Pressure measurements may also be used to steer the bottom
hole assembly (BHA). If formation pressure measurements indicate
that the current zone is not producible or otherwise unattractive
for drilling, then the BHA, including the drill bit, may be steered
in another direction. An example of a steerable BHA assembly is
Halliburton's GeoPilot system. Such directional drilling is
intended to steer the BHA into the highest pressure portions of the
reservoir, maintain the BHA in the same pressure zone, or avoid a
decreased pressure zone. Again, petrophysical data, such as those
formation properties previously mentioned, may also be used to more
accurately steer the BHA.
[0138] The bubble point, as previously defined, can be a beneficial
real time measurement. Measuring changes in the bubble point of
formation fluids with depth of the formation tester tool in the
wellbore allows a bubble point gradient to be determined. Plotting
the bubble point gradient generally allows transitions back and
forth between gas, water and oil and to be observed, or
identification of a zone that is not connected to another zone
based on downhole pressure measurements. The bubble point gradient
may be used to steer the BHA. Steering downward toward denser
fluids is desirable, as the lighter fluids, i.e., the ones having
higher bubble points due to retaining more dissolved gases, tend to
move upward. Therefore, as fluids with lower bubble points are
encountered, the BHA is steered toward these fluids.
[0139] The bubble point gradient, as well as other gradients, may
be computed on the fly as bubble points and pressure measurements
are taken at different depths during the same trip into the
borehole. The data is sent to the surface real time for the
gradients to be calculated and used.
[0140] As described above, pressure while drilling, taken in the
annulus, and actual formation pressure are two distinct
measurements. With the ability to obtain actual formation pressure,
these two measurements may be combined and interpreted for flags,
or warnings, and the flags may then be sent to the surface. Prior
to the advent of FTWD, these measurements had to combined and
interpreted at the surface because actual formation pressure could
only be obtained after drilling had stopped. Therefore, the warning
could only be determined after the fact. The types of flags that
may be sent to the surface include the annulus pressure being below
the formation pressure and the annulus pressure being above the
fracture gradient.
[0141] The above discussion is meant to be illustrative of the
principles and various embodiments of the present invention. While
the preferred embodiment of the invention and its method 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 embodiments described herein are
exemplary only, and are not limiting. Many variations and
modifications of the invention and apparatus and methods disclosed
herein are possible and are within 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.
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