U.S. patent application number 09/960084 was filed with the patent office on 2002-01-31 for subsurface measurement apparatus, system, and process for improved well drilling, control, and production.
Invention is credited to Ward, Christopher D..
Application Number | 20020011333 09/960084 |
Document ID | / |
Family ID | 21919900 |
Filed Date | 2002-01-31 |
United States Patent
Application |
20020011333 |
Kind Code |
A1 |
Ward, Christopher D. |
January 31, 2002 |
Subsurface measurement apparatus, system, and process for improved
well drilling, control, and production
Abstract
Subsurface wellbore conditions are measured directly in the
wellbore while the fluid circulation system is not pumping. The
measured values are recorded at the subsurface location and
subsequently transmitted to the well surface when circulation is
resumed using fluid pulse telemetry (FPT). Real-time measurements
made when the fluids are circulating are transmitted real time
using FPT. Axially spaced measurements are used to obtain
differential values. The apparatus of the invention comprises an
assembly carried by a drill string that is used to selectively
isolate the area within the well that is to be evaluated. The
apparatus includes an assembly having axially spaced inflatable
well packers that are used to isolate an uncased section of the
wellbore. The apparatus is equipped with self-contained measuring
and recording equipment, a fluid receiving reservoir, circulation
valving, measurement while drilling equipment, and automated
controls. Measurements are made while the circulation is terminated
or while the well packers are being used to isolate an area of the
wellbore from the circulating fluid. The method is used to directly
measure and evaluate conditions caused by pumping and drill string
movement, such as swab and surge pressures. Other conditions such
as the formation strength, formation pressure, the fluid density,
and other subsurface conditions related to the well are also
measured.
Inventors: |
Ward, Christopher D.;
(Houston, TX) |
Correspondence
Address: |
Browning Bushman P.C.
Suite 1800
5718 Westheimer
Houston
TX
77057
US
|
Family ID: |
21919900 |
Appl. No.: |
09/960084 |
Filed: |
September 21, 2001 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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09960084 |
Sep 21, 2001 |
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09618984 |
Jul 19, 2000 |
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6296056 |
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09618984 |
Jul 19, 2000 |
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09495576 |
Feb 1, 2000 |
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Current U.S.
Class: |
166/250.07 ;
166/105; 166/250.15; 166/250.17 |
Current CPC
Class: |
E21B 49/08 20130101;
E21B 47/18 20130101; E21B 49/006 20130101; E21B 49/087 20130101;
E21B 47/06 20130101; E21B 43/26 20130101; E21B 49/008 20130101;
E21B 21/08 20130101; E21B 47/26 20200501; E21B 33/1243
20130101 |
Class at
Publication: |
166/250.07 ;
166/250.15; 166/250.17; 166/105 |
International
Class: |
E21B 047/00 |
Claims
What is claimed is:
1. A method of evaluating a subsurface well condition in a well
having a well fluid pumping circulation system comprising the steps
of: terminating fluid pumping in said circulation system; taking
measurements of one or more well conditions in a subsurface
wellbore section of said well; recording said measurements of said
well conditions at a subsurface location within said well; resuming
fluid pumping in said well fluid pumping circulation system;
transmitting said recorded measurements to the well surface using
fluid pulse telemetry; and evaluating one or more subsurface well
conditions using said recorded measurements received at the well
surface.
2. A method as defined in claim 1 wherein said weilbore section is
isolated by sealing said wellbore with a well packer to isolate the
wellbore above the well packer from the wellbore below the well
packer.
3. A method as defined in claim 1 wherein said welibore section is
isolated between two, axially spaced well packers.
4. A method as defined in claim 1 wherein said measured well
condition includes the pressure of the fluid in said wellbore
section.
5. A method as defined in claim 2 wherein said measured well
condition includes the pressure of the fluid in said welbore
section.
6. A method as defined in claim 3 wherein said measured well
condition includes the pressure of the fluid in said isolated
section.
7. A method as defined in claim 2 wherein said measuring is done by
a drill-string-supported measuring assembly and said well packer
forms a seal between said drill string and said wellbore.
8. A method of evaluating a condition in a fluid-filled wellbore at
a location remote from the well surface in a well having a well
fluid circulating pumping system comprising: terminating fluid
circulation by said pumping system; measuring the pressure of the
fluid in said wellbore at said remote location adjacent a moving
drill string assembly while the fluid circulating is terminated;
recording the measured pressures with a recorder carried by said
drill string assembly; initiating fluid circulation of fluids
through said drill string assembly; transmitting the recorded
pressure values from said recorder to the well surface through said
circulating fluid using fluid pulse telemetry; and adjusting the
rate of movement of said drill pipe assembly based on said
transmitted values to maintain desired pressure conditions in said
wellbore as said drill pipe is being moved.
9. A method as defined in claim 8 wherein said movement is the
rotation of said drill string assembly.
10. A method as defined in claim 8 wherein said movement is the
axial movement of said drill string assembly through said
wellbore.
11. A method as defined in claim 9 wherein said movement is the
axial movement of said drill string assembly through said
wellbore.
12. A method of controlling the surge pressure in a well having a
well fluid pumping circulation system comprising the steps of:
terminating fluid circulation by said pumping system; measuring the
pressure of the fluid in said wellbore at a location remote from
the well surface adjacent a drill string assembly while said fluid
circulation is terminated; recording the measured pressure values
in a recorder carried by said drill string assembly; resuming fluid
circulation by said pumping system; measuring the pressure of said
fluid at said location while said fluid is circulating;
transmitting said recorded pressure values to the well surface
using fluid pulse telemetry; and adjusting the rate of resumption
of fluid circulation using information obtained from said
transmitted pressure values to regulate the resultant pressure in
said wellbore.
13. A method of evaluating a well condition in a well having a well
fluid pumping circulation system comprising the steps of: isolating
a section of the wellbore of said well below a well packer;
circulating the well fluids above said isolated section; and
measuring one or more well conditions in said isolated section
while transmitting measurement values to the well surface through
said circulating well fluid using FPT.
14. A method as defined in claim 13 wherein said packer comprises
an inflatable packer and further including the step of inflating
said packer into engagement with the surrounding wall of said
wellbore to isolate said section.
15. A method as defined in claim 13, further comprising the steps
of drawing down the pressure in said isolated section for measuring
the formation pressure.
16. A method as defined in claim 13, further comprising the steps
of: pressuring up said isolated section and measuring the real-time
leak off of the increased pressure into the formation adjacent said
isolated section.
17. A method as defined in claim 13, further comprising the step of
isolating said section between axially spaced well packers.
18. A method as defined in claim 14, further comprising the step of
removing a protective drilling sleeve from said packer before
inflating said packer.
19. A method of evaluating a well condition in a well having a
fluid circulating pumping system comprising the steps of: measuring
a well condition at axially spaced locations within the wellbore of
said well; transmitting said measurements to the well surface using
fluid pulse telemetry; and using the differences in the
measurements at said spaced locations to evaluate a condition of
said well.
20. A method as defined in claim 19 wherein said well condition is
the pressure of the fluid in said wellbore.
21. A method as defined in claim 20 wherein said measurements are
used to determine the pressure gradient between said spaced
locations for evaluating the fluid density of the fluid in said
wellbore.
22. A method as defined in claim 19 wherein said measurements are
made and recorded while said pumping system is off.
23. A method as defined in claim 19 wherein said well condition is
the pressure of the fluid in said wellbore.
24. An apparatus for evaluating subsurface well conditions
comprising: a drill-string-supported measuring instrument for
measuring and recording data values for one or more well
characteristics at a subsurface location within the wellbore remote
from the well surface; a fluid pulse telemetry instrument for
transmitting said recorded data values to the well surface through
circulating well fluids in said drill string and said wellbore; and
a subsurface isolation control mechanism for controlling the
effects of well fluids on said measuring instrument while said
measuring instrument is measuring said data values.
25. An apparatus as defined in claim 24, further comprising a
system control instrument for initiating the transmission of said
recorded data values from said recording instrument to the well
surface using said fluid pulse telemetry instrument.
26. An apparatus as defined in claim 24 wherein said isolation
control mechanism comprises a well packer for isolating an area of
said well from said circulating well fluids while said measuring
instrument is measuring said data values.
27. An apparatus as defined in claim 24, further comprising a
surface-directed flow control for controlling circulation of well
fluids through said drill string and said wellbore.
28. An apparatus as defined in claim 26, further comprising a
pump-out module for receiving fluid from said isolated area of said
well.
29. An apparatus as defined in claim 24 wherein said measuring
instrument includes axially spaced measurement while drilling
instruments for simultaneously measuring wellbore pressure at
spaced axial locations within said wellbore.
30. An apparatus as defined in claim 26, further comprising a
protective drilling cover carried over said well packer for
protecting said packer while said drill string is moved in said
wellbore.
31. An apparatus as defined in claim 30 wherein said cover
comprises an axially movable metal sleeve.
32. A system for evaluating variable well parameters in the
wellbore of a well comprising: a fluid pumping system for
circulating well fluids in said wellbore; a drill string assembly
disposed within said wellbore for conducting fluids between a
subsurface wellbore location and the well surface; axially spaced
measuring instruments included in said drill string assembly for
simultaneously measuring one or more variable well parameters at
axially spaced locations in said wellbore remote from the surface
of said well; a recorder included in said measuring instrument for
recording measured values of said parameters; a fluid isolating
mechanism included in said drill string assembly for controlling
the effects of said circulating well fluids on the measurements
taken by said measurement system; and a fluid pulse telemetry
instrument included in said drill string assembly for conveying
measured values to the well surface through the circulating well
fluids while said pump system is on.
33. A system as defined in claim 32, further comprising a
controller for initialing the measurement, recording, and
transmission of data to the well surface.
34. A system as defined in claim 32 wherein said fluid isolating
mechanism comprises a well packer.
35. A system as defined in claim 34, further comprising a second
well packer for isolating a section of said wellbore from fluids
above and below said packers.
36. A system as defined in claim 35, further including a reservoir
for receiving fluid from said isolated section.
37. A system as defined in claim 32, further comprising a
circulating mechanism above said isolating mechanism for
circulating fluids in said wellbore above said fluid isolating
mechanism.
38. A system as defined in claim 34, further comprising a packer
protection cover for protecting said packer while said drill string
assembly is being moved in said wellbore, said cover being
selectively removable from said packer to permit said packer to
expand radially into sealing engagement with said wellbore.
39. A method of evaluating a well condition in a well having a
circulating system for circulating fluid through a drill string
assembly disposed within a wellbore comprising the steps of:
measuring the pressure of said circulating fluid at axially spaced
locations within said wellbore; transmitting the measured pressure
values from said spaced locations to the well surface using fluid
pulse telemetry; evaluating the transmitted pressure values to
determine the fluid pressure difference between said two locations;
and shutting in or otherwise initiating a change in said
circulating system when said pressure differential reaches or
exceeds a predetermined value.
40. A method as defined in claim 39 wherein said pressure
differential is evaluated to detect the occurrence of a kick in
said well.
41. A method as defined in claim 39 wherein said pressure
differential is evaluated to determine the rheology of said
circulating fluid.
42. A method of determining the equivalent circulating density of a
wellbore fluid used in a well having a circulating well fluid
system comprising the steps of: measuring the pressure values of
said well fluid at a subsurface location within said wellbore while
said fluid is circulating in the well; stopping circulation of said
well fluid in said well; measuring and recording the pressure
values of said well fluid while said circulation is stopped;
resuming circulation of said well fluid; transmitting said recorded
pressure values to the well surface using fluid pulse telemetry;
and comparing the pressure values of said circulating well fluid
with said transmitted recorded pressure values for determining the
pressure effect of fluid circulation on the fluid in said
wellbore.
43. A method as defined in claim 42 wherein said pressure values of
said circulating well fluid are transmitted to the well surface
using FPT.
44. A method as defined in claim 43 wherein said measured pressure
values of said circulating well fluid are recorded before being
transmitted to the well surface.
Description
BACKGROUND OF THE INVENTION
[0001] 1. Field of the Invention
[0002] The present invention relates to the field of well drilling
and completion. More specifically, the present invention relates to
direct measurement apparatus and methods for evaluating subsurface
conditions in a wellbore.
[0003] 2. Description of the Background Art
[0004] In a typical well drilling operation, conditions in the
wellbore must be closely monitored and controlled to optimize the
well operation and to maintain control of the well. One of the most
important conditions in well drilling procedures is the bottomhole
pressure of the circulating drilling fluid or "mud" used in forming
or conditioning the well. The actual or effective density of the
mud is an important condition that can be affected by a number of
different variables related to the composition of the mud, the
characteristics of the formation being penetrated by the wellbore,
the dynamics of the drilling mechanism, and the procedures being
implemented in the wellbore. In this latter regard, for example,
the circulation of the fluid creates an effective density within
the wellbore, referred to as an equivalent circulating density,
that exceeds the static density of the fluid. The equivalent
circulating density is caused by pressure losses in the annulus
between the drilling assembly and the wellbore and is strongly
dependent on the annular geometry, mud hydraulics, and flow
properties of the well fluid. The maximum equivalent circulating
density is always at the drill bit, and pressures of more than 100
psi above the static mud weight may occur in long, extended reach
and horizontal wells.
[0005] This equivalent circulating density, which must be known in
order to determine well pressures existing at different locations
within the wellbore, may be calculated using hydraulics models from
input well geometry, mud density, mud rheology, and flow
properties, through each component of the circulating system. There
are, however, often large discrepancies between the measured and
calculated pressures due to uncertainties in the calculations
through poor knowledge of pressure losses through certain
components of the circulation system, changes in the mud density
and rheology with temperature and pressure, and/or poor application
of hydraulics models for different mud systems.
[0006] In many high pressure, high temperature (HPHT), deepwater,
and extended reach and horizontal wells, the margin between the
formation pore or collapse pressure and the formation fracture
pressure often diminishes to the point that the equivalent
circulating density can become critical. In extreme cases, the well
may flow or cave in while the pumps used to circulate the mud are
off ("pumps off"), allowing the well fluid to flow into the
formation. Accurate determination of the actual static and dynamic
mud pressures within the wellbore is therefore a critical design
parameter for the successful drilling of these wells.
[0007] Another phenomenon affecting pressures in the wellbore
results from movement of the drill string. As the drill string is
lowered into the well, mud flows up the annulus between the string
and the wellbore and is forced out of the flowline at the well
surface. A surge pressure results from this movement, producing a
higher effective mud weight that has the potential to fracture the
formation. A swabbing pressure occurs when the pipe is pulled from
the well, causing mud to flow down the annulus to fill the void
left by the pipe. The pressure effectively reduces the mud weight
and presents the potential for inducing a discharge of fluid from
the formation into the wellbore. As with the equivalent circulating
density measurements, the swab and surge pressures are strongly
dependent on the running speed, pipe geometry, and mud rheology
involved in the drilling or completion of the well. These pressures
reach a maximum value around the bottom hole assembly (BHA), where
the annular volume between the drilling string assembly and the
surrounding wellbore is the lowest, and thus where flow through the
well is the fastest.
[0008] Theoretical and experimental evidence suggests that during
running pipe in and out of the wellbore, a much larger pressure
differential is exerted on the formation than is experienced from
static and circulating pressures during driling, unless the pipe
running speed is lowered significantly. Formation susceptibility to
wellbore instability, although not problematic while drilling, may
increase due to the swab and surge pressures incurred during
tripping when the entire pipe string is rapidly withdrawn or
reinserted in the well.
[0009] Modeling swab and surge pressure is difficult because of the
manner in which the fluid flows as the pipe is moved within the
well. A moving pipe causes the mud adjacent to the pipe to be
dragged with it to a certain extent, although the bulk of the
annular fluid is moving in the opposite direction. The mechanics
are therefore different from the hydraulics calculations described
for the mud circulation since, in that case, fluid flow is
considered to be only moving in one direction. Swab and surge
hydraulics models therefore require a "clinging constant" to
account for the two relative motions.
[0010] A pressure surge caused by breaking the gels when increasing
the flow rate too quickly after breaking circulation has been
responsible for many packoff and lost circulation incidents. In
this situation, where the well circulation is terminated for a
period of time ("pumps off") and then reinitiated ("pumps on"), if
the circulation rate is reinitiated too quickly, a pressure surge
is created in the mud, causing a damaging imbalance with the
formation. This danger, which is particularly evident in high angle
wells, led to the procedure of slowly bringing the volume of the
mud pumps up anytime after circulation is temporarily suspended. A
pressure surge associated with restarting circulation may also be
caused by a restriction in the annulus due to cuttings sagging and
accumulating while the mud is static.
[0011] In extended reach and horizontal wells, hole cleaning can
become critical. If parts of the wellbore are unstable, as in
common in these types of wells, the accumulation of cuttings, beds,
and an overloaded annulus make it difficult to clean the hole
properly. Remedial measures, such as control drilling, the pumping
of viscous pills, and wiper trips, are commonly employed in an
attempt to avoid packing off and sticking the pipe. These
procedures, however, consume valuable time and may also damage the
formation leading to further wellbore instabilities.
[0012] Yet another situation where knowledge about the subsurface
conditions is important occurs when drilling out of the bottom of a
casing shoe into new formation. It is common to perform a leak-off
test (LOT) to determine the strength of the cement bond around the
casing shoe. However, because of the small margins between the
formation pore or collapse pressure and fracture pressure in many
wells, the LOT has become a critical measure of the formation
strength and is used as a guide to the maximum allowable
circulating pressure that may be used in a subsequent hole section
without breaking down the formation and losing circulation in the
well.
[0013] Conventionally, LOT pressures are recorded at the surface of
the well. The measurements must be corrected for the pressure being
exerted by the mud column. To obtain an accurate reading in these
surface conducted measurement procedures, the mud must be
circulated thoroughly to condition it to produce an exact and even
density for the LOT calculation. This process can be
time-consuming, and the calculated results are subject to the
correctness of the information and assumptions used for the values
of the variable conditions affecting the mud column density.
[0014] Subsurface pressure information is especially important when
the well "takes a kick" during drilling. The term"kick" is commonly
employed to describe the introduction of formation gas, a lower
density formation fluid, or a pressured formation fluid into the
wellbore. If not controlled, the kick can reduce the density of the
drilling fluid sufficiently to allow the formation pressure to flow
uncontrollably through the well and become a "blowout." In
riserless offshore drilling, the kick can allow formation fluids to
flow into the sea.
[0015] After the kick is detected and the well is shut in, the
stabilized casing shut-in pressure and the stabilized drill pipe
shut-in pressure are measured at the well surface and recorded. The
drill pipe shut-in pressure is used as a guide in determining the
formation properties. Since the formation fluid type is generally
unknown, it is not possible to determine the formation pressure
from the casing shut-in pressure. The formation pressure and influx
volume are required to calculate the density of the mud required to
"kill" the well. )ile circulating the kill mud, the annular
pressure is controlled by the choke and pump speed to maintain a
constant bottom hole formation pressure and prevent further entry
of formation fluid. As with the other evaluations dependent upon
fluid or mud pressure, the accuracy of the calculations is
dependent upon the correct evaluation of the factors affecting the
mud density.
[0016] Another situation that requires knowledge of the mud column
density is that of determining the mud weight. The mud weight is
normally determined at the well surface from surface mud checks or
sensors in the flowline or the return pit. It has been proposed
that the mud density actually decreases with temperature increases
due to expansion and that this effect may become important in HPHT
wells with tight margins between the formation pressure and the
wellbore pressures. In high angle wells, a heavy cuttings load may
increase the annular mud weight significantly. Additionally, a
number of measurements can be made during a trip to detect barite
sag, which also affects the mud weight.
[0017] A conventional pressure while drilling (PWD) tool can be
used to measure the differential well fluid pressure in the annulus
between the tool and the wellbore while drilling mud is being
circulated in the well. These measurements are employed primarily
to provide real-time data at the well surface, indicative of the
pressure drop across the BHA for monitoring motor and measurement
while drilling (MWD) performance. The measurement values are also
affected by the effects of the circulating well fluid. Direct
annular pressure measurements were not customarily made.
[0018] Downhole well pressures may also be measured directly using
a drill-string-supported tool isolating a section of the wellbore
from the effects of the well fluid above the point of measurement.
U.S. Pat. No. 5,555,945 (the '945 patent) describes a tool that
employs an inflatable packer with an MWD instrument designed to
sense fluid pressure or temperature, or other variable well
characteristics. The measurement is typically made in the annulus
between the tool and the formation in the area below the set
packer. The packer is set and the subsurface variable is measured
and recorded in an instrument contained within an assembly of the
tool. The recorded data is retrieved to the surface by pulling the
drill string and assembly from the well. Constant remote
communication may be maintained with a surface command station
using mud pulse telemetry or other remote communication
systems.
[0019] U.S. Pat. No. 5,655,607 describes a drill-string-supported,
inflatable packerthat can be anchored in an open wellbore and used
to measure well pressures above or below the packer. An internal
cable control is used to regulate inflation and deflation of the
packer. Subsurface measurement data are presumably sent directly
through the cable to the well surface or recorded and retrieved
when the assembly is retrieved to the well surface.
[0020] In some MWD systems, downhole temperature and pressure, as
well as other parameters, are measured directly, and the measured
data values are communicated to the surface as the measurements are
being made using "fluid pulse telemetry" (FPT), also called "mud
pulse telemetry" (NPT). FPT, such as described in U.S. Pat. No.
4,535,429, requires that the well fluid be circulated to transmit
data to the well surface. While data transmission during
circulation of the well provides information on a timely basis, the
measurements taken are affected by the fluid circulation and must
be corrected for its effects. This requirement imposes the same
uncertainties previously noted regarding calculated values for
subsurface parameters, computer modeling, and surface measurement
techniques used to estimate a subsurface condition.
[0021] It is also possible to directly obtain subsurface measured
data using transmission techniques that do not rely on circulating
well fluid. For example, subsurface measurement and transmitting
devices using low frequency electromagnetic waves transmitted
through the earth to a receiver at the surface are capable of
transmitting data without regard to whether the well fluid is
circulating or static. These devices, however, are not suitable for
use in all applications and also require highly specialized
transmitting and receiving systems that are not as commonly
available as are the FPT systems.
[0022] MWD systems that use RAPT are only able to send information
to the surface while circulating. Thus, real-time pressure and
temperature information can only be sent real time while
circulating the mud system. However, much information useful to
well drilling and formation evaluation processes can be gained from
the data recorded while the pumps are off. While the pumps are off,
pressure and temperature and other data are recorded Aat a specific
sampling rate. On resumption of circulation, this stored
information is transmitted to the surface using FPT. This may be as
detailed as each discrete recorded sample. However, sending all
data may take an unacceptable amount of time. Some smart processing
downhole will reduce the amount of data that has to be sent up.
[0023] U.S. Pat. No. 4,216,536 (the '536 patent) describes a system
that, among other things, uses the storage capacity in a subsurface
assembly to store data measurements of a downhole condition made
while the drilling liquid is not circulating. The stored data is
transmitted to the well surface after flow of the drilling liquid
is resumed using FPT. Subsurface temperature and formation
electrical resistivity are examples of the conditions sensed and
recorded while the circulation of the drilling fluid is
interrupted. The '536 patent also discloses a method for increasing
the effective transmission rate of data through FPT by deriving and
transmitting condensed data values for the measured conditions. The
'536 patent employs multiple transducers on a logging tool for
measuring a number of downhole conditions.
[0024] U.S. Pat. No. 5,353,637 (the '637 patent), describes
multiple, axially spaced inflatable packers included as part of
awireline or coil tubing supported sonde that is used to conduct
measurements in cased or uncased boreholes. The '637 patent system
measures conditions in the wellbore between axially spaced
inflatable packers and sends the measurement values to the surface
over the supporting wireline cable.
[0025] The '945 patent, previously noted, describes methods and
apparatus for early evaluation testing of subsurface formation. A
drill-string-supported assembly that includes one or more well
packers and measuring instruments is used to measure subsurface
pressures. Recorded measurements are accessed by retrieval of the
drill string or connection with a wireline coupling. The system may
also provide constant remote communication with the surface through
mud pulse telemetry.
SUMMARY OF THE INVENTION
[0026] The present invention provides methods and apparatus for
directly measuring a subsurface well condition, transmitting the
measured condition values to the well surface using FPT, and
evaluating the transmitted data to determine the value of a well
condition at a location in the well remote from the well
surface.
[0027] One method of the present invention measures a subsurface
pressure directly while the circulating fluid system is off,
records the measured values, transmits the recorded pressure values
to the well surface when circulation is resumed using FPT, and
evaluates the received data to determine such conditions as casing
cement integrity, kick tolerance of a newly drilled borehole
section, openhole fracture strength, and formation pressure.
[0028] The method of the present invention is employed to determine
surge and swab pressures by measuring and recording "pumps off"
pressure changes caused by pipe movement and fluid flow rate
increases. The measured values are recorded while the pumps are off
and transmitted to the well surface when circulation is resumed
using FPT. The received data are employed to adjust the speed of
pipe movement or the rate of pumping to maintain well fluid
pressures at optimum values as the pipe is being pulled or run
and/or as the pumps are being started back up after a period of
"pumps off."
[0029] The methods of the invention are also employed to determine
subsurface mud weight, cuttings, volumes, and other solids content
of the well fluid, and to determine an equivalent circulating mud
density.
[0030] In one method of the invention, measurements made while the
fluid system of the well is circulating, or not, are taken at
axially spaced locations in the wellbore to detect a pressure
differential. Measurements taken with the pumps off are recorded.
The measurement data are sent to the well surface using FPT.
Circulating pressure measurements are recorded or are transmitted
to the surface as they are taken using FPT. The received data are
used to detect the occurrence of a kick or to monitor mud rheology
or solids content of the circulating mud. Circulating and
non-circulating measurements are used to determine the pressure
effect of circulation on the wellbore.
[0031] The present invention also employs a method of directly
measuring subsurface well conditions in an area of the wellbore
that is temporarily freed from the effects of circulating well
fluids to obtain true subsurface condition values. Where the area
being measured is isolated from the circulating fluid by an
isolation packer during "pumps on," the measured data may be
transmitted real time through the circulating fluid using FPT. In
another method of the invention, measurements are made in an
isolated part of the wellbore, the measurements are recorded,
contact with the circulating well fluid is reestablished, and the
recorded data is transmitted to the well surface using FPT. In
either application, conventional FPT systems may be employed in a
pumps off condition and/or in combination with an isolating well
packer and subsurface recorder and measuring devices to obtain
direct measurement of subsurface well parameters free of the
effects of the well fluid used in the well's circulation
system.
[0032] The apparatus of the invention comprises a
drill-string-carried assembly that is employed to perform MWD
measurements, as well as to selectively isolate the subsurface well
area to be evaluated. The preferred form of the invention includes
two axially spaced inflatable well packers, either one of which, or
both, may be used to isolate a section of the wellbore. The
assembly is equipped with axially spaced measuring instruments,
recording equipment, a fluid receiving reservoir, valves, and
control equipment that may be actuated from the well surface.
[0033] The apparatus may be used to directly measure the swab and
surge pressures caused by drill string movement, the surge pressure
caused by the initiation of fluid circulation, the formation
strength, the formation pressure, the downhole fluid density, the
effectiveness of kill fluids being added to the circulation system
and other subsurface variables related to the condition of the
well. Data measured and/or recorded at the subsurface location are
sent by FPT to the well surface through the circulating well
fluid.
[0034] The apparatus of the present invention is the provided with
axially spaced sensors, such as PWD sensors or temperature sensors,
to provide simultaneous measurement of wellbore conditions at
axially spaced locations either with the packers set or unset. The
differential in the spaced measurements is used to evaluate
subsurface wellbore conditions. The measured values may be
transmitted to the well surface as they are being taken using FPT,
or they may be taken in a static or isolated area of the well fluid
and recorded for subsequent transmission using FPT when
communication with circulating fluid is reestablished.
[0035] From the foregoing, it will be appreciated that a primary
object of the present invention is to measure and record subsurface
well conditions within an area of the wellbore, free from the
effects of fluid circulating in the circulation system of the well,
and transmit the recorded data to the well surface using FPT for
directly evaluating one or more subsurface conditions without
having to correct for the effects of the circulating well
fluids.
[0036] Another object of the present invention is to provide an
apparatus carried by the drill string that may be employed to
isolate a section of the wellbore with one or more inflatable
packers, measure, and record variable well conditions within the
isolated section, and transmit the recorded data to the well
surface using FPT.
[0037] Yet another object of the present invention is to provide a
method of directly measuring subsurface pressure, temperature,
and/or other variables within a wellbore at axially spaced
positions within the wellbore to obtain differential values of such
variables and transmitting the measured values to the well surface
using FPT while the pumps are on or after circulation of the well
fluids is reestablished.
[0038] Yet another object of the present invention is to provide a
method for directly measuring the effects of pressure changes
induced in a wellbore due to the movement of the drilling string
assembly within the wellbore, to record the changes, and to
transmit the recorded data through the well fluids using FPT.
[0039] An important object of the present invention is to provide a
drill-string-carried tool having provision to isolate a section of
a wellbore from the well fluids in the bore, receive formation
fluids in a reservoir chamber included in the well tool and measure
variable parameters of the entry of such formation fluids into the
chamber, record such measurements, and subsequently transmit the
recorded measurements to the well surface using FPT.
[0040] An object of the present invention is to provide a
drill-string-supported assembly that can isolate a section of a
wellbore, receive fluids from the formation in the isolated section
of the wellbore, measure variable characteristics regarding the
fluid being received from the formation, record such measured
characteristics, and subsequently transmit the recorded
characteristics to the well surface using FPT.
[0041] Another object of the present invention is to provide a
subsurface assembly included as part of a drilling string assembly
for isolating a section of a wellbore from the circulating fluids
within the well, such assembly having expandable packer seals that
are normally protected within a wear protecting sleeve that may be
displaced from the packer seal to permit engagement of the seal
with the surrounding formation.
[0042] It is an object of the present invention to provide a
composite subsurface tool, carried by a drill string and included
as part of a drilling assembly comprising dual, axially spaced
inflatable packers that can be expanded radially to seal off the
wellbore area between the packers, protective covering over the
packers that is displaced when the packers are to be expanded, a
circulating sub above the uppermost packer for circulating well
fluids while an area of the wellbore is isolated, a receiving
chamber for accepting fluid flow from the formation in the isolated
wellbore area, an FPT module for conveying data to the well surface
through the circulating well fluids, a measurement system for
measuring wellbore conditions, a recording system for recording
measured values, and a self-contained control system responsive to
well surface commands for initiating setting and release of the
well packers and for controlling the taking, recording, and
transmission of measurement values.
BRIEF DESCRIPTION OF THE DRAWINGS
[0043] FIG. 1 is an elevation, partially in section, illustrating
the drill-string-supported tool of the present invention within a
wellbore before inflation of the inflatable well packers; and
[0044] FIG. 2 is a view of the tool of FIG. 1 illustrating the
packers inflated into engagement with the wall of the surrounding
wellbore.
DESCRIPTION OF THE EMBODIMENTS
[0045] Enhanced Leak-off Test (LOT) and Pressure Integrity Test
(PIT) and Formation Integrity Test (FIT) Using Direct Pressure
Measurement
[0046] In a typical LOT, the start of each well section, after
casing and cementing the wellbore, a short interval (approximately
3 m) of new hole is drilled below the casing shoe. The well is then
shut in and the wellbore pressured up by pumping at a slow rate
until the wellbore strength is exceeded and mud starts to leak off
(LOT) or until a specified pressure is achieved (PIT/FIT). These
pressures are monitored from the well surface. This test is used to
verify the casing cement integrity, the kick tolerance for the next
section, and an estimate of the openhole fracture strength.
[0047] Because of the small margins between pore or collapse
pressure and fracture pressure in many HPHT, deepwater, and
extended reach/horizontal wells, the LOT has become a critical
measure of the formation strength and is used as a guide to the
maximum allowable circulating pressure in the subsequent hole
section to prevent lost circulation.
[0048] LOT pressures are recorded at surface usually by the cement
unit but should be corrected for the pressure exerted by the mud
column. The mud is therefore usually circulated thoroughly an hour
or two to condition it and to measure the exact and even density
for the LOT calculation.
[0049] In the method of the present invention, a downhole pressure
tool measures directly or isolates and then measures and records
the LOT pressure close to the formation, thus removing the
ambiguities of the prior art method, resulting in more accurate
determination of the formation strength. The recorded data are sent
to the well surface through the circulating well fluid using FPT.
The LOT pressure is measured without first circulating an even mud
weight, and the measurement is taken using a PWD instrument that
provides direct subsurface measurements with quicker and more
accurate determinations. Because the PWD is located downhole next
to the formation, the measurements are accurate, and the
uncertainties of measuring at surface that are caused in part by
the compressibility and transmissibility of pressure through a
gelled mud system over thousands of meters are eliminated.
[0050] The method for the LOT, PIT, and FIT procedures are:
[0051] 1. Shut in the well.
[0052] 2. Pressure the wellbore slowly until a specified pressure
is reached or the wellbore strength is exceeded.
[0053] 3. Record the bottomhole pressure of the well fluid during
step 2.
[0054] 4. Resume circulation in the wellbore.
[0055] 5. Transmit the recorded pressure data to the well surface
using FPT.
[0056] 6. Evaluate the received data to determine subsurface
formation conditions.
[0057] Swab and Surge Pressures Caused by Pipe Movement
[0058] The steps of the method to determine surge and swab pressure
caused by pipe movement are as follows:
[0059] 1. Terminate circulation of the mud.
[0060] 2. Measure and record the subsurface pressure changes
occurring in the mud as the pipe is moved (pulled, run, and/or
rotated).
[0061] 3. Resume circulation.
[0062] 4. Transmit the recorded pressure values to the well surface
using FPT.
[0063] 5. Evaluate the transmitted values to establish pipe
movement rates that will not cause undesired pressure changes in
the wellbore.
[0064] Effective Downhole Mud Weight Measurements
[0065] The mud weight at a subsurface location in the wellbore is
directly determined by the following method steps:
[0066] 1. Terminate mud circulation.
[0067] 2. Measure and record the mud pressure at the subsurface
location.
[0068] 3. Resume circulation of the mud.
[0069] 4. Transmit the recorded pressure values to the well surface
using FPT.
[0070] 5. Evaluate the transmitted pressure values to determine the
mud weight at the subsurface location.
[0071] The solids content of the well fluid at the subsurface
location may also be determined from the subsurface mud weight by
comparing the measured weight with that of the mud that has a known
solids content. This data can be used to evaluate hole cleaning as
well as other conditions of the well drilling operation.
[0072] Optimizing Speed of Pump Resumption Using "Pumps On"
Pressure Surge Indicator
[0073] The thixotropic nature of mud systems gives them a tendency
to gel to varying degrees when circulation is stopped. This gelling
process tends to increase with mud viscosity and time. Care must be
taken on resumption of circulation, while breaking the gels, not to
put excessive pressures on the formation, which may threaten the
formation integrity and lead to mud losses. Often the pumps and
pipe rotation are broughtup slowly in order to mitigate this
problem. The rates of pumping and rotation change are based on
estimates and experience rather than an exact knowledge of the
surge pressures being produced.
[0074] Many packoff and lost circulation incidents have been
attributed to a pressure surge caused when increasing the flow rate
too quickly after breaking circulation. This is particularly common
in high angle wells. A pressure surge may also be caused by a
restriction in the annulus due to cuttings sagging and accumulating
while the mud is static. Alternatively, the surge may represent the
additional pressure needed to overcome the gel strength of the
mud.
[0075] In the method of the present invention, "pumps off" PWD
information is used to recognize the magnitude of the "pumps on"
pressure surge. Once pumping is resumed, the measured and recorded
data are sent to the well surface through the circulating well
fluid using FPT. The data received at the surface are used to
optimize the speed of the pumps and pipe rotation immediately after
resuming circulation and pipe movement to prevent overpressuring
the wellbore.
[0076] The method steps are:
[0077] 1. Stop circulation of the mud.
[0078] 2. Measure and record the bottomhole static mud
pressure.
[0079] 3. Resume circulation while continuing to measure the
bottomhole pressure.
[0080] 4. Record or transmit the circulating pressure values.
[0081] 5. Transmit the recorded and any real-time pressure data to
the well surface using FPT.
[0082] 6. Evaluate the received data to establish the preferred
rate at which circulation is to be resumed.
[0083] Kick Detection and Kill Monitoring PWD Using PWD Measurement
Tools
[0084] The existing PWD tool, already in commercial use, is used to
detect "kicks" caused by the influx of formation fluids (water,
oil, or gas) to the wellbore. A dual, annular PWD device having
axially spaced well packers according to the present invention is
used for enhanced kick detection and other potential benefits.
[0085] Use of a downhole PWD information is used to detect kicks
earlier than possible using surface measurement information to
significantly increase drilling safety and avoid kick-related
drilling problems.
[0086] Because the density of gas (0.2 sg) or oil (0.7 sg) or water
(1.0-2.25 sg) is usually less than that of the drilling fluid (1-2
sg), the presence of a kick can be recognized by a reduction in PWD
annular pressure. Because the measurement is downhole, it is
observable earlier than when indicated by surface information. In
the case of shallow salt water flows drilled with seawater, kicks
may be recognized by increase in downhole measured pressure due to
the formation pressure itself and the suspension of solids (loose
sand). If the kick type is known (water, oil, or gas), the volume
of the influx can be estimated from the degree of pressure change.
The pressure is directly measured downhole so that it is an
accurate measurement, and the measurement is transmitted to the
surface so that it is obtained quickly.
[0087] If a kick is identified, the well is usually shut in with
the blowout preventer (BOP) to prevent further influx. The
stabilized casing shut-in pressure (CSIP) and stabilized drill pipe
shut-in pressure (DPSIP) are recorded. The DPSIP is used as a guide
to determining the formation condition properly. Since the
formation fluid type and the influx volume are generally not
accurately known, it is not possible to determine the formation
pressure from the CSIP. The formation pressure is required to
calculate the density of the kill mud required. The well is then
circulated through the BOP at a slow rate to replace the well with
a kill mud of higher density to balance the higher pressures.
During this process, a constant bottom hole pressure is applied to
the system by adjusting the choke pressure. This bottom hole
pressure must be above the formation pressure to prevent farther
influx and below the fracture pressure to prevent losses. In
conventional surface measuring systems, uncertainties due to lack
of knowledge about the influx type and the volume of influx can
lead to error in calculating the bottom hole pressure. PWD
monitoring enables the bottom hole pressure to be measured directly
and to be promptly received so that the choke pressure can be
adjusted accordingly. The results of the adjustment are also
correctly and quickly obtained.
[0088] An enhancement to the conventional PWD kick detector is the
addition of a second PWD measurement downhole. A single PWD tool
measures the average fluid density and pressure loss in the hole
annulus. In a dual PWD system of the present invention, the
pressure gradient between the two PWD tools is a downhole density
measurement that picks up changes in density downhole due to a kick
much more quickly. This dual PWD has other important applications
such as downhole mud weight determination to better monitor
cuttings loading and barite sag. It may also be used to estimate
the downhole mud rheology.
[0089] In the method of the invention, circulating well fluid
pressure values are taken simultaneously at spaced locations within
the wellbore. The measured values are transmitted to the surface
using FPT. The values are compared to evaluate the pressure
differential between the measurement points. The size of the
pressure differential is used to indicate the occurrence of a kick
or the solids content of the mud or other aspects of the mud
rheology. Measurements taken and recorded while the pumps are off
or taken in an isolated section of the wellbore are sent to the
surface using FPT.
[0090] In the method of the invention, a downhole pressure sensor
measures formation fluid pressure in the presence of a float sub.
The recorded data are transmitted to the surface using FPT. The
tool and method provide actual bottom hole pressure measurement
during the well kill operation.
[0091] Apparatus and System for Repeat Subsurface Testing,
Measurement, and Recording While Drilling
[0092] The tool of the present invention is indicated generally at
10 in FIG. 1. The tool is illustrated disposed in a wellbore 11
that penetrates a subsurface formation 12. As illustrated best in
FIG. 2, the tool 10 includes two axially separated inflatable well
packers 13 and 14 that may be actuated to expand radially to a set
position at which they seal the tool to the surrounding wellbore
11. The packers 13 and/or 14 function as a subsurface isolation
control mechanism for isolating an area from the effects of
circulating well fluids. The construction and operation of
inflatable packers are well known. See, for example, U.S. Pat. No.
3,850,240, describing an inflatable drill string well packer used
in an assembly to collect well fluid samples. See also the '637
patent, which describes axially spaced packers supported by a
wireline or coil tubing string.
[0093] A retractable metal sleeve 15 covers the packer 14 while the
packer is in its unexpanded state, illustrated in FIG. 1. A similar
retractable sleeve 16 covers the unexpanded packer 13. When the
packers are actuated to set, the sleeves 15 and 16 retract axially
to the reduced radius areas 15a and 16a formed on the tool 10 to
permit the packers to expand. The sleeves return to the positions
illustrated in FIG. 1 when the packers are unset. The tool 10 is
carried by a drill string 17 that extends to the well surface (not
illustrated). In the form of the invention illustrated in FIGS. 1
and 2, the tool 10 is part of a BHA that includes one or more drill
collars 18 carried over a rotary drill bit 19.
[0094] The tool 10 is provided with a pulsar subassembly (sub) 20
that produces data communicating pressure pulses in well fluid 21
that surrounds the tool 10. A circulation sub 22 is included in the
tool 10 to be used to circulate well fluid through the wellbore
above the isolated wellbore section when the packers 13 and/or 14
are set.
[0095] An isolated area 23 between the set packers 13 and 14
communicates with an MWD sub 24 used as a system control that
provides power, measuring and recording, and flow control for the
tool 10. The instruments of the sub 24 measure the variable
parameters in the adjacent annular bore area 23. Fluid in the area
23 is selectively transmitted through the sub 24 through a port 25
to a pump-out module sub 26 positioned between the packer 14 and
the circulating sub 20. The MWD module 24 provides system power and
the control mechanisms used, for example, for initiating packer
setting and release and for measuring and recording subsurface
variables in response to surface-directed instructions. Examples of
mechanisms and techniques capable of use as the system power and
control mechanism of the MWD module 24 may be found in the
description of the '536 and the '637 patents. Any suitable power
and control techniques and mechanisms may, however, be employed to
regulated the operation of the packer, instrument, and flow control
components of the tool 10. Recorded or real-time data measured by
the sub 24 is transmitted to the pulsar sub 20 for communication to
the well surface when the well fluids are being circulated.
[0096] Two openhole drill string packers are employed, in the
preferred form of the invention, above and below the PWD tool.
However, certain of the methods of the invention may be performed
using a tool having only a single packer.
[0097] The sleeves 15 and 16, which may be constructed of steel or
other suitable material, are provided for packer protection as the
drill string is rotated during drilling. Rubber packers are
susceptible to wear during drilling unless the gauge is protected.
The volume of fluid and fluid pressure within the packers 14 and 15
is selected to ensure sealing of the packers in enlarged boreholes.
In operation, the pressure in the packer must be higher than the
pressure in the test interval to ensure a proper seal.
[0098] In the embodiment of FIGS. 1 and 2, the measured values
taken by the measuring instruments in the area below the packer 14
may be communicated through the set packer 14. This permits
real-time MPT capabilities while measurements are being made in an
area free of the effects of the circulating well fluid.
[0099] Fluid is pumped in and out of the test interval to perform
LOTs and RFTs. The draw-down and test are automated under the
control of the module 24. The top openhole packer 14 may be used as
a pump-out reservoir.
[0100] The circulating sub 22 may be employed for real-time
monitoring with MPT tools. The circulating sub 22 is not needed for
recorded tests or if EM telemetry is used.
[0101] The tool 10 may be employed in the following procedure to
obtain real-time formation pressure:
[0102] 1. Align the MWD sub 24 across a suitable interval, ideally
across zones selected with formation evaluation measurement while
drilling (FEMWD).
[0103] 2. Inflate the openhole packers 13 and 14.
[0104] 3. Circulate through the circulation sub 22 above the top
packer 14.
[0105] 4. Draw down the annular pressure in the area 23 between
packers 13 and 14.
[0106] 5. Monitor the real-time formation pressure with MWD 24 and
transmit measured values to the surface through the pulsar sub 20
using FPT.
[0107] 6. Deflate the packers 13 and 14 and close circulation sub
22.
[0108] 7. Resume drilling or testing.
[0109] The advantages over a pad-type device such as used on a
wireline tool are as follows:
[0110] 1. Larger area of formation is tested.
[0111] 2. A quicker and more reliable test; more likely to get a
seal with the formation.
[0112] 3. The tool is less likely to get differentially stuck; a
quick test; no metal parts against the formation.
[0113] 4. A gross permeability measurement is possible; a larger
area of formation can be tested.
[0114] 5. Accurate placement of the tool is combined with FEMWD;
less likelihood of getting a time-consuming low permeability tight
test, particularly in thin beds.
[0115] 6. Early detection of proper packer seal since no draw-down
is possible if the seal is not properly set.
[0116] 7. Reliable RFTs in low permeability formations.
[0117] Benefit of Isolating the Test Area
[0118] The under balanced situation in the annulus is controllable
by the mud column being in overbalance (if it were under balanced
in a permeable formation, it would flow). The pressure draw-down
using the tool of the present invention is only in a small annular
volume and does not impact the hydrostatic head for the whole
column. If the formation is tight but underbalanced as determined
by the tool 10, control measures (i.e., kill mud, bullheading) may
be employed.
[0119] If the packer fails during the test, then no draw-down
occurs and essentially only mud weight is measured during the test.
Only a small volume of fluid needs to be pumped out to get
sufficient draw-down. If this is not happening, the test can be
stopped.
[0120] Development wells are normally drilled overbalanced.
However, in exploration drilling, large underbalanced or
overbalanced situations may develop without warning. In such cases,
the risk factor obtained by getting early RFTs outweighs concerns
over taking the RFT.
[0121] Rig heave on floaters will employ good compensation to stop
packers from Amoving.
[0122] Mud-cake: a pad-type RFT device has a probe with a filter to
get through the mud cake skin. The large chamber area and the
draw-down of a PWD RFT overcome the mud cake.
[0123] Openhole Leak-off Test (LOT) Using the Isolation Tool
[0124] An LOT below the shoe can now be measured at the surface and
downhole using the PWD of the present invention. This is useful
when the shoe has just been drilled out and there is a small
openhole volume. To be able to record the formation strength in the
open hole as drilling progresses is a significant improvement. The
LOT using the isolation tool of the present invention may be
performed as follows:
[0125] 1. Align the MWD sub 24 over the interval of interest,
picked by FEMWD.
[0126] 2. Inflate the openhole packers 13 and 14.
[0127] 3. Circulate through the circulation sub 22 above the top
packer 14.
[0128] 4. Pressure up an annular volume between the packers 13 and
14.
[0129] 5. Monitor the real-time LOT and report the measured data to
the well surface using FPT.
[0130] 6. Deflate the packers 13 and 14 and close the circulating
sub 22.
[0131] Advantages over Standard LOT
[0132] 1. Saves time circulating an even mud weight before the test
(typically one hour).
[0133] 2. Provides a more accurate test when measured at surface
than when measured downhole (no compressing mud and breaking gel
pressure to overcome).
[0134] 3. Multiple LOTs are possible to assess the strength ofweak
formations. The equivalent circulating density (ECD) can then be
limited to prevent lost circulation.
[0135] 4. Used as a casing setting depth decision tool (in a strong
rock), allowing additional kick tolerance in the following
section.
[0136] 5. Only breaks down the small volume of rock between the
packers.
[0137] Fracturing and Stimulation
[0138] An extension of the LOT described above can effectively
fracture the rock. The uses of this are:
[0139] 1. Test-fracture-test to measure the effectiveness of the
stimulation technique.
[0140] 2. Measure water injection rates.
[0141] 3. Test other stimulation techniques such as acidization and
propped fractures.
[0142] The foregoing description and examples illustrate selected
embodiments of the present invention. In light thereof, variations
and modifications will be suggested to one skilled in the art, all
of which are in the spirit and purview of this invention.
* * * * *