U.S. patent application number 12/271000 was filed with the patent office on 2009-06-25 for method for detecting formation pore pressure by detecting pumps-off gas downhole.
This patent application is currently assigned to BP Corporation North America, Inc.. Invention is credited to Mark W. Alberty.
Application Number | 20090159334 12/271000 |
Document ID | / |
Family ID | 40404894 |
Filed Date | 2009-06-25 |
United States Patent
Application |
20090159334 |
Kind Code |
A1 |
Alberty; Mark W. |
June 25, 2009 |
Method for detecting formation pore pressure by detecting pumps-off
gas downhole
Abstract
Methods and systems are described for drilling a well while
distinguishing circulated gas or air from pumps-off gas in a
drilling fluid at downhole pressure and temperature. A well is
drilled with a drilling fluid, drill string, and drill bit.
Drilling fluid is pumped through the drill string, drill bit, and
into an annulus between the drill string and a wellbore. The drill
string comprises one or more sensors sensing a parameter indicative
of circulated gas or air in the drilling fluid flowing through the
drill string, one or more sensors being behind and near the drill
bit. The sensors measuring gas in the drill string may be at the
same level as gas detectors in the annulus. The measurements are
communicated to a human-readable interface at the surface, allowing
an operator to determine if pressure of the wellbore fluid is
greater than formation fluid pressure.
Inventors: |
Alberty; Mark W.; (Houston,
TX) |
Correspondence
Address: |
CAROL WILSON;BP AMERICA INC.
MAIL CODE 5 EAST, 4101 WINFIELD ROAD
WARRENVILLE
IL
60555
US
|
Assignee: |
BP Corporation North America,
Inc.
Warrenville
IL
|
Family ID: |
40404894 |
Appl. No.: |
12/271000 |
Filed: |
November 14, 2008 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
12004175 |
Dec 19, 2007 |
|
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12271000 |
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Current U.S.
Class: |
175/40 |
Current CPC
Class: |
E21B 44/00 20130101;
E21B 21/00 20130101; E21B 21/08 20130101 |
Class at
Publication: |
175/40 |
International
Class: |
E21B 49/00 20060101
E21B049/00 |
Claims
1. A method of drilling a well while distinguishing circulated gas
or air from pumps-off gas in a drilling fluid at downhole pressure
and temperature, the method comprising: a) drilling a well with a
drilling fluid, a drill string, and a drill bit from an earth
surface through a formation, the drilling fluid being pumped
through the drill string, drill bit, and into an annulus between
the drill string and a wellbore, the drill string comprising one or
more sensors sensing a parameter indicative of circulated gas or
air in the drilling fluid flowing through the drill string, at
least one of the sensors located in the drill string behind and
near the drill bit; b) measuring, while drilling, a parameter of
the drilling fluid indicative of circulated gas or air inside the
drill string behind and near the drill bit using the sensors; c)
supporting at least one annulus gas sensor by the drill pipe behind
and near the drill bit to sense an amount of gas in the drilling
fluid in the annulus behind and near the drill bit during pumping
at a depth of the at least one annulus gas sensor; d) detecting an
amount of gas in the drilling fluid in the annulus behind and near
the drill bit using the at least one annulus gas sensor during
drilling periods before and after a period when pumping has
stopped; and e) communicating the result of steps (b)-(d) to a
human-readable interface at the surface while drilling to allow an
operator to compare the amount of gas in the drilling fluid in the
annulus behind and near the drill bit during the periods before and
after the period when pumping has been stopped, and thus determine
if pressure of the wellbore fluid is greater than formation fluid
pressure behind and near the drill bit.
2. The method of claim 1 wherein the measuring of the parameter of
the drilling fluid indicative of circulated gas or air inside the
drill string comprises measuring the parameter in the drilling
fluid flowing through the drill string at a same level as an
annulus gas sensor monitoring gas present in fluid flowing through
the annulus.
3. The method of claim 1 comprising tracking gas levels
volumetrically as a function of drilling fluid volumes pumped to
recognize when recirculated gasses or air pass sensors monitoring
gas content in the annulus.
4. The method of claim 3 further comprising correcting annulus gas
volume to remove effects of circulated gas or air.
5. The method of claim 1 further comprising sensing parameters
indicative of circulating gas or air using sensors placed along the
drill string to assess the movement of recirculated gasses or air
out of the well, or to detect influxes of gases up the well.
6. The method of claim 1 wherein the measuring comprises measuring
one or more physical properties selected from density, velocity,
temperature, pressure, conductivity, and resistivity of drilling
fluid containing recirculating gasses and/or air at downhole
pressures and temperatures.
7. The method of claim 6 wherein the physical property is measured
in real-time, and the real-time measurements compared with
measurements obtained using control samples to determine the actual
gas content at downhole conditions.
8. The method of claim 1 wherein the measuring employs a technique
selected from pulse-echo, density, ultrasonic, velocity, sonic
impedance, acoustic impedance, and combinations thereof.
9. The method of claim 1 further comprising assessing formation
pressure relative to wellbore pressure and adjusting a parameter of
the drilling fluid.
10. The method of claim 9 wherein the parameter of the drilling
fluid is selected from weight, density, specific gravity, API
gravity, thermal conductivity, pH, viscosity, compressibility,
thermal conductivity, salinity, and water activity.
11. A method for detecting pumps-off gas in drilling fluid in a
wellbore during drilling from an earth surface and penetrating a
plurality of subterranean formations, the method comprising: a)
pumping drilling fluid through a drill pipe extending into a
wellbore to provide pressure on the drilling fluid in the drill
pipe and discharging drilling fluid from a bottom end of the drill
pipe into a drill bit and an annulus between an outside of the
drill pipe and an inside of the wellbore to drill the wellbore to a
greater depth; b) supporting at least one gas sensor by the drill
pipe near the bottom of the drill pipe and positioned and sensing
the amount of gas in the drilling fluid in the annulus at a depth
of the at least one sensor; c) periodically stopping the pumping of
the drilling fluid for one or more time periods; and d) comparing
amounts of gas detected by the at least one sensor in the drilling
fluid in the annulus at the level of the at least one sensor during
pumping time periods to determine a change in an amount of gas in
the annulus resulting from the periodic stopping of pumping.
12. The method of claim 11 wherein the wellbore is drilled to a
greater depth at an under-balanced condition.
13. The method of claim 11 wherein the wellbore is at an
under-balanced condition during one or more of the periods when
pumping has been stopped.
14. The method of claim 11 wherein the wellbore is at an
under-balanced condition at a hydrostatic drilling fluid
pressure.
15. The method of claim 11 wherein a pore pressure of the
subterranean formations penetrated by the drill pipe is between a
drilling fluid pumping pressure and a hydrostatic drilling fluid
pressure.
16. The method of claim 11 wherein the at least one sensor is
mounted in a section of drill pipe.
17. The method of claim 11 wherein the at least one sensor is
mounted on the outside of the drill pipe.
18. The method of claim 11 wherein the sensor is selected from the
group consisting of pulse-echo, density, ultrasonic, velocity,
sonic impedance and acoustic impedance sensors.
19. The method of claim 11 wherein the amount of gas in the
drilling fluid during a period when pumping has been stopped is
compared to a previous amount of gas detected during a previous
period when pumping had been stopped.
20. The method of claim 11 wherein a plurality of sensors are
positioned at a plurality of locations along a length of the drill
pipe.
21. The method of claim 11 wherein at least one of the pluralities
of sensors is positioned at a distance from about 1 to about 1500
feet [460 meters] above the drill bit along a length of drill
pipe.
22. The method of claim 11 wherein the wellbore is at an
under-balanced condition during pumping.
23. The method of claim 1 wherein an upper portion of the wellbore
is cased.
24. A system for distinguishing circulated gas or air from
pumps-off gas in a drilling mud or fluid at downhole pressure and
temperature, comprising: a) one or more sensors for measuring a
parameter indicative of circulated gas or air in mud flowing
through the drill string, at least one of the sensors located in a
drill string behind and near a drill bit, and at least one sensor
for measuring a parameter indicative of gas or air in an annulus
behind and near the drill bit; b) means for communicating the
parameters to a human-readable interface at the surface; and c) a
human-readable interface from which an operator can compare amounts
of gas present in the annulus during pumps-on periods which occur
before and after a pumps-off period to determine if a pressure of
the wellbore fluid is greater than the formation fluid pressure
using the amount of circulated gas or air present inside the drill
string and the annulus behind and near the drill bit.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] The present application is a continuation-in-part of, and
claims benefit under 35 U.S.C. .sctn. 120 from application Ser. No.
12/004,175, filed Dec. 19, 2007, which is incorporated herein by
reference in its entirety.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[0002] Not applicable.
BACKGROUND OF THE INVENTION
[0003] The present disclosure relates in general to methods of
drilling wellbores, for example, but not limited to, wellbores for
producing hydrocarbons from subterranean formations, and more
particularly to methods of distinguishing circulated gases from
connection gas or gas influx in a drilling oil or gas well.
BACKGROUND ART
[0004] Drilling techniques for producing wellbores to great depths
in the earth are well known and are widely used, especially in the
exploration for and production of hydrocarbons. These wells are
typically produced by the use of a drill bit positioned on the
lower end of a drill string which is supported for rotation to
cause the bit to drill into the earth with the drilling being
stopped periodically, with the drill string being lifted and
supported on slips or similar devices so that a new section of pipe
can be attached to the top drill pipe section. These drill pipe
sections are fitted with upset ends so that they can be threaded
with male fittings on one end and female fittings on the other end.
These drill pipe sections are typically about 30 feet long and when
joined together can be used to drill for great distances into the
earth.
[0005] In drilling such boreholes into the earth, it is not
uncommon to case the upper portions of the well after it has been
drilled to a suitable depth. Frequently the diameter of the
wellbore is decreased as it is drilled deeper into the earth. These
techniques are well known to those skilled in the art.
[0006] During drilling a drill string is positioned from a surface
into the wellbore and to the bottom of the wellbore so that the bit
can be rotated. The bit is typically rotated by passing a drilling
fluid downwardly through the drill pipe to drive the drill bit and
extend the bottom of the hole downwardly.
[0007] Drilling fluids (sometimes referred to herein as drilling
muds, or simply muds) are well known and comprise water-based
drilling fluid and oil-based drilling fluid. Further specialized
drilling fluids, such as drill-in fluids may also be used. The
drilling fluids are typically made up to have a specific gravity so
that a column of drilling fluid of a height equal to the wellbore
depth exerts a bottom hole pressure equal to the anticipated
pressure in the formations penetrated by the wellbore over the
entire depth of the well. This drilling fluid pressure tends to
inhibit the production of gases and oil formation fluids into the
wellbore or to the surface when greater than the formation
pressure. It also inhibits events such as kicks and blow-outs where
high pressure permeable formations are encountered. The industry
has developed numerous techniques for detecting such kicks and
blow-outs early to prevent significant damage to the drilling
apparatus and to prevent blowing the entire mud column out of the
wellbore and possibly contaminating the surrounding area with
hydrocarbons.
[0008] One technique for identifying such high-pressure formations
is illustrated in U.S. Pat. Nos. 5,214,251 and 5,354,956. Both
these patents are hereby incorporated herein by reference in their
entirety. These references disclose methods for detecting large gas
bubbles which may be discharged into the wellbore from a
high-pressure formation (kicks) and possibly damage the well and
blow all the drilling fluid from the well onto the earth
surface.
[0009] It is highly desirable that such conditions be identified
prior to drilling into such high-pressure formations so that the
weight of the drilling fluid can be adjusted to prevent the
blow-out.
[0010] Accordingly, considerable effort has been directed to the
development of methods for detecting subtle amounts of gas invading
a wellbore as drilling is conducted. It is recognized that it would
be desirable to know the pressure of small amounts of gas in the
drilling fluid. Many wells are drilled slightly under-balanced. In
other words, the drilling fluid is pumped into the drill pipe at a
pressure such that the drilling fluid passing through the drill and
into the annulus between the outside of the drill pipe and the
inside of the borehole is at a pressure slightly less than that
anticipated from the formations through which the well passes. This
permits the drilling of the well without unduly contaminating the
faces and near-wellbore portions of the formations penetrated by
the well. Use of over-pressure drilling can force drilling fluid
into the formations penetrated by the wellbore. Drilling fluid
components in the well formation faces and near-wellbore portions
of the formation can be detrimental to the production of fluids
from the formation after the well has been completed.
[0011] In other instances, the well may be drilled slightly
over-balanced but the drilling fluid may have a weight insufficient
to maintain over-balance on the well if the pumps are stopped. This
is also an under-balanced condition when the pumps are off. Such
conditions exist periodically during the drilling operation because
it is periodically necessary to stop the pumps, disconnect from the
drill pipe and add a new section of drill pipe to allow the
drilling to proceed to an even greater depth. The pressure
resulting from the weight of the column of the drilling fluid is
referred to as a hydrostatic pressure. This hydrostatic pressure
also can be greater than or less than the pressure in the
formation. Desirably this hydrostatic pressure is to be slightly
greater than the pressure in the formations penetrated by the
wellbore for a safety perspective. One desire of this invention is
to detect the condition of the hydrostatic pressure being slightly
less than the pressure in the formations penetrated by the well
when these conditions are first observed in the pumps off condition
when the hydrostatic pressure in the well is slightly less than in
the pumps on condition.
[0012] Of course if an over-balance, i.e., a hydrostatic pressure
greater than the pressure in the pores of the formations penetrated
by the wellbore is used then little, if any, gas will enter the
wellbore from the formations during drilling. There may be gas
associated with the formation that has been excavated by the bit
that is released as the formation cuttings are returned to the
surface but the amount of gas present will then be independent of
the pumps-on/pumps-off condition. When an over-balanced condition
exits, portions of the drilling fluid will enter the permeable
formations and constitute an obstacle to the production of fluids
from those formations.
[0013] In a preferred embodiment the hydrostatic pressure in the
well during pumping of the drilling fluid is slightly over-balanced
relative to the formation pressure with the hydrostatic pressure
being slightly less when the pumps are off, either due to the loss
of the friction of the fluid movement or as a result of a slight
swabbing effect from lifting the bit off bottom to set the drill
string into the slips. In such instances very small amounts of
formation gas can enter the wellbore from low permeability
formations, such as shale. This gas may exist as a free fluid in
the formation or it may be dissolved in water. The presence of this
small amount of gas entering the wellbore is indicative that a
higher-pressure formation may be exposed in the wellbore. As a
result, it is desirable to check this gas periodically to determine
whether the amount of gas entering the well under comparable
conditions is increasing or stable when pumps are turned on and
off.
[0014] It is important to recognize the difference in the response
of the high pressure low permeability formation compared to the
high pressure high permeability formation. The low permeability
shale formations encapsulate the high permeability reservoirs and
provide the barrier or trap for hydrocarbons which accumulate in
these reservoirs. Most low permeability shale achieve pressure
equilibrium with those reservoirs. When the high pressure high
permeability reservoirs are exposed to the lower pressure mud
columns in pumps-on or pumps-off state, the fluids in the formation
can flow into the well at high rates and volume and produce the
kick that creates the unstable and potentially unsafe condition
drilling operators desire to avoid.
[0015] When the high pressured low permeability shale is exposed to
the lower pressured mud column, the flow into the well is severely
limited by the low permeability and there is little risk of
creating an unstable or potentially dangerous well condition. Since
the shale encapsulates the reservoir and since the shale reaches
pressure equilibrium with the reservoir, drillers can use the
underbalanced condition created by pumps-off when drilling the
overlying low permeability shale and the associated pumps-off gas
to determine if the mud weight is sufficiently high to safely drill
the high permeability reservoir before exposing the reservoir and
risk generating a kick.
[0016] The most commonly used methods of making this determination
is to separate the gas from the drilling fluid at the surface. This
is an effective method for determining how much gas may be in the
drilling fluid but unfortunately in a well of any substantial depth
it may take two to three hours for this drilling fluid to reach the
earth surface. This may be too late to avoid drilling into a
high-pressure permeable formation without making adequate
preparations. Failure to take adequate preparations before drilling
into a permeable high-pressure formation may result in a kick and
potential blowout.
[0017] If the pressure conditions in the well are such to allow
fluids to flow into the wellbore, fluids flowing from the formation
may carry gas either dissolved in the fluid (oil or water) or in a
free state in the rock into the well which can be easily detected
with these surface devices. When the surface measured gas
increases, this can be an indication that the formation pressure is
greater than the hydrostatic pressure created by the drilling
fluid.
[0018] An additional factor to consider is that the hydrostatic
pressure created by the mud increases as a result of the
circulating mud pumps being on due to friction resulting from the
resistance to flow in the system. This difference in pressure
results in a change in the differential pressure between the
formation and the borehole. When the pressure difference is greater
into the borehole, then fluid flows more rapidly from the formation
into the borehole resulting in a greater amount of gas in the mud.
When the formation pressure is greater than the pumps off pressure
(without the pressure necessary to overcome friction) higher gas
amounts are measured in the mud. Pumps are usually turned off when
making connections or to simulate a connection to look for
associated increases in gas that may indicate that the pressure in
the borehole is less than the pressure in the formation.
[0019] The above-described surface detection method is most
effective when the pore pressure of the formation lies between the
pumps-off and pumps-on pressures. This condition creates the
maximum contrast between pumps-off and pumps-on gas content in the
mud. It can then be used to narrow the estimate of formation pore
pressure to a value that lies between these two pressures. However,
as noted previously, the mud at the bottom of the well must be
circulating back to the surface to determine if the amount of gas
in the mud has increased as a result of turning the pumps off. This
can take many hours to do and usually results in a significant
delay in understanding if the phenomena is occurring and assessing
the magnitude of the formation pressure relative to the drilling
fluid pressure. Significant savings could occur in drilling time if
the amount of gas in the drilling fluid could be assessed downhole
before the fluid is circulated out the well.
[0020] Mud being pumped down the well through the drill pipe may
contain recirculated gas or may contain air added to the mud
through circulation across the shale shakers or introduced as an
air bubble at the time drill pipe connections are made at the
surface. Applicant's previously filed application Ser. No.
12/004,175 describes how to analyze gas content in drilling fluids
in the annulus; however, the most suitable gas detection devices
used downhole to monitor gases in the annulus are not capable of
distinguishing freshly introduced formation gas from circulated
gas. These gases need to be distinguished so as not to lead to a
false conclusion that the well is underbalanced due to the
detection of circulated gas downhole.
[0021] It would be advantageous if methods and systems could be
developed to distinguish circulated gas or air from pumps-off gas
at downhole pressure and temperature for the purpose of determining
if the pressure of the wellbore fluid is greater than the formation
fluid pressure. Detection of pumps-off gas downhole would allow the
assessment of formation pressure relative to wellbore pressure in a
much quicker and timelier manner which would result in a more
accurate assessment of formation pore pressure and reduced
associated drilling problems such as fluid influxes, lost
circulation or wellbore instability.
SUMMARY
[0022] In accordance with the present disclosure, it has now been
determined that circulated gas can be identified by placing a
detector sensitive to the gas in the drill string behind the drill
bit, in certain embodiments at the same level as the detectors
monitoring the gas present in the annulus, to monitor the amount of
gas present in the drilling fluid inside the drill pipe. The
detected gas levels can then be tracked volumetrically as a
function of the drilling fluid volumes pumped to recognize when
those gasses pass the detectors monitoring the annulus. In this
manner the observed annulus gas volumes can be corrected to remove
the effects of circulated gas or air. This could be accomplished by
placing detectors sensitive to the gas in the drill string behind
and near the bit to assess the amount of gas present. As used
herein, "behind and near" the bit means the sensors nearest the bit
(when discussing sensors inside the drill pipe only, in the annulus
only, or both) should be within 500 feet [150 meters] of the bit,
or 400 feet [120 meters], or 300 feet [90 meters], or 200 feet [60
meters], or 100 feet [30 meters], in some case within 50 feet [15
meters] of the bit, so as to allow the gas to enter the well and be
measured, with additional detectors optionally placed along the
drill string (when discussing sensors inside the drill pipe only,
in the annulus only, or both) to assess the movement of the gas out
of the well or to detect influxes of gas up the well. For example,
sensors inside the drill pipe, and/or in the annulus could be
positioned every 2000 feet [614 meters], every 1500 feet [460
meters], every 1000 feet [307 meters] or so back to surface, or at
least the previous casing point. This would allow monitoring
expansion of the gas with the decrease in hydrostatic pressure as
the gases move upward in the well and to detect pressure from
additional gases entering the well at a shallower depth. The
physical properties of the gases typically found in the drilling
fluid at downhole pressures and temperatures may be studied, and
the results used to determine the different physical properties of
the drilling fluid that could be used to measure the gas content
(drilling fluid density, drilling fluid velocity, and the like).
Methods and apparatus of the invention are applicable to both
on-shore (land-based) and offshore (subsea-based) drilling.
[0023] A first aspect of the disclosure is a method of drilling a
well while distinguishing circulated gas or air from pumps-off gas
in a drilling fluid at downhole pressure and temperature, the
method comprising: [0024] a) drilling a well with a drilling fluid,
a drill string, and a drill bit from an earth surface through a
formation, the drilling fluid being pumped through the drill
string, drill bit, and into an annulus between the drill string and
a wellbore, the drill string comprising one or more sensors sensing
a parameter indicative of circulated gas or air in the drilling
fluid flowing through the drill string, at least one of the sensors
located in the drill string behind and near the drill bit; [0025]
b) measuring, while drilling, a parameter of the drilling fluid
indicative of circulated gas or air inside the drill string behind
and near the drill bit using the sensors; [0026] c) supporting at
least one annulus gas sensor by the drill pipe behind and near the
drill bit to sense an amount of gas in the drilling fluid in the
annulus behind and near the drill bit during pumping at a depth of
the at least one annulus gas sensor (in certain embodiments, one of
the sensors monitoring gas present in the drill string may be at
the same level as a sensor monitoring gas present in the annulus);
[0027] d) detecting an amount of gas in the drilling fluid in the
annulus behind and near the drill bit using the at least one
annulus gas sensor during drilling periods before and after a
period when pumping has stopped; and [0028] e) communicating the
results of steps (b)-(d) to a human-readable interface at the
surface while drilling to allow an operator to compare the amount
of gas in the drilling fluid in the annulus behind and near the
drill bit during the periods before and after the period when
pumping has been stopped, and thus determine if pressure of the
wellbore fluid is greater than formation fluid pressure behind and
near the drill bit.
[0029] In certain embodiments, the method comprises tracking
detected gas levels volumetrically as a function of the drilling
fluid volumes pumped to recognize when recirculated gases or air
pass detectors monitoring gas content in the annulus. In this
manner the observed annulus gas volumes may be corrected to remove
the effects of circulated gas or air. In certain embodiments
additional sensors sensitive to parameters indicative of
circulating gas or air may also be placed along the drill string to
assess the movement of recirculated gasses or air out of the well,
or to detect influxes of gases up the well. In certain embodiments,
one or more physical properties (density, velocity, temperature,
pressure, conductivity, resistivity, and the like) of drilling
fluids containing recirculating gasses and air typically found in
the mud at downhole pressures and temperatures may be measured in
real-time, and the real-time measurements compared with
measurements obtained using control samples to determine the actual
gas content at downhole conditions.
[0030] The detecting circulated gas or air inside the drill string,
or a physical property indicative of such gasses, whether behind
and near the drill bit, distributed along the drill string both
inside and outside of the drill pipe (in the annulus), may proceed
using any one or more known measuring techniques which are already
described in the literature and understood by those in the art. For
example, common methods used for gas detection downhole include the
methods and apparatus described in U.S. Pat. Nos. 3,872,721;
5,859,430; 6,465,775; and 6,995,369, all of which are incorporated
herein by reference, and discussed more fully herein. Techniques
for measuring other wellbore fluid properties, from which gas
content may be deduced, are described for example in U.S. Pat. Nos.
6,208,586; 5,850,369; 6,640,625, and Published U.S. Pat.
Application Nos. 2008047337; 2007227241; and 2007016464, all of
which are incorporated herein by reference in their entirety.
[0031] Detection of pumps-off gas downhole and communication of
that information (or information indicative of the presence of
pumps-off gasses) to a human-readable interface at the surface
would allow the assessment of formation pressure relative to
wellbore pressure in a much quicker and timelier manner, which
should result in a more accurate assessment of formation pore
pressure and reduced associated drilling problems such as fluid
influxes, lost circulation or wellbore instability. In certain
embodiments, the method further comprises using the information on
whether pressure of the wellbore fluid is greater than the
formation fluid pressure to locate a point of lost circulation or a
well fluid influx in the well. In yet other methods, the
information on location of lost circulation or well fluid influx
may be used to diagnose the root cause of the lost circulation or
fluid influx. In still other methods, once the root cause of the
lost circulation or well fluid influx is diagnosed, the method
comprises selecting an appropriate treatment, and placing a well
treatment where the problem has developed in the well.
[0032] Another aspect of the disclosure comprises a method for
detecting pumps-off gas in drilling fluid in a wellbore during
drilling from an earth surface and penetrating a plurality of
subterranean formations, the method comprising: [0033] a) pumping
drilling fluid through a drill pipe extending into a wellbore to
provide pressure on the drilling fluid in the drill pipe and
discharging drilling fluid from a bottom end of the drill pipe into
a drill bit and an annulus between an outside of the drill pipe and
an inside of the wellbore to drill the wellbore to a greater depth;
[0034] b) supporting at least one gas sensor by the drill pipe near
the bottom of the drill pipe and positioned and adapted to sense
the amount of gas in the drilling fluid in the annulus at a depth
of the at least one sensor; [0035] c) detecting the amount of gas
in the drilling fluid in the annulus at the level of the at least
one sensor during a period when pumping has been stopped; and
[0036] d) comparing the amount of gas in the drilling fluid in the
annulus at the level of the at least one sensor during the period
when pumping has been stopped to an amount of gas in the annulus at
the level of the drill bit detected during pumping.
[0037] In this method, the comparing step (d) may occur
continuously or intermittently during drilling.
[0038] Another aspect of the invention is a system for
distinguishing circulated gas or air from pumps-off gas in a
drilling mud or fluid at downhole pressure and temperature,
comprising: [0039] a) one or more sensors for measuring a parameter
indicative of circulated gas or air in mud flowing through the
drill string, at least one of the sensors located in a drill string
behind and near a drill bit, and at least one sensor for measuring
a parameter indicative of gas or air in an annulus behind and near
the drill bit; [0040] b) means for communicating the parameters to
a human-readable interface at the surface; and [0041] c) a
human-readable interface from which an operator can compare amounts
of gas present in the annulus during pumps-on periods which occur
before and after a pumps-on period to determine if a pressure of
the wellbore fluid is greater than the formation fluid pressure
using the amount of circulated gas or air present inside the drill
string and the annulus behind and near the drill bit.
[0042] The methods and apparatus described herein may provide other
benefits, and the methods for obtaining the gas content in the
drill string and/or annulus are not limited to the methods and
apparatus noted herein; other methods and apparatus may be
employed. Certain embodiments may include temperature and pressure
measuring sensors in the vicinity of the gas detection sensors for
measuring temperature and pressure near the gas sensors and using
the temperatures and pressures to correct acoustic
measurements.
[0043] These and other features of the methods of the disclosure
will become more apparent upon review of the brief description of
the drawings, the detailed description, and the claims that
follow.
BRIEF DESCRIPTION OF THE DRAWINGS
[0044] The manner in which the objectives of this disclosure and
other desirable characteristics can be obtained is explained in the
following description and attached drawings in which:
[0045] FIG. 1 is a schematic diagram of an embodiment in accordance
with the present disclosure;
[0046] FIG. 2 is a schematic diagram of an alternate embodiment in
accordance with the present disclosure; and
[0047] FIG. 3 is a logic diagram in flowchart form illustrating a
method embodiment in accordance with the present disclosure.
[0048] It is to be noted, however, that the appended drawings are
not to scale and illustrate only typical embodiments of this
disclosure, and are therefore not to be considered limiting of its
scope, for the invention may admit to other equally effective
embodiments. Identical reference numerals are used throughout the
several views for like or similar elements.
DETAILED DESCRIPTION
[0049] In the following description, numerous details are set forth
to provide an understanding of the disclosed methods and apparatus.
However, it will be understood by those skilled in the art that the
methods and apparatus may be practiced without these details and
that numerous variations or modifications from the described
embodiments may be possible.
[0050] In the discussion of the drawing figures, the same numbers
will be used throughout to refer to the same or similar
components.
[0051] As illustrated in FIG. 1, a wellbore 10 extends from an
earth surface 12 through an overburden 14 and through formations
16, 18, 20, 22, 24 and 26. Some of these formations may be
oil-bearing or gas-bearing formations while others may be shale
formations which contain pressured fluids. A drill pipe (also
referred to herein as a drill string) 34 is positioned to extend
from the earth surface to a drill bit 36. Drilling fluid is pumped
through the drill string as illustrated by arrows 38 and recovered
as illustrated by arrows 40. No equipment has been illustrated for
performing this operation since such equipment is considered to be
well known to those skilled in the art. The drilling fluid injected
through lines 38 passes through drill bit 36 and is discharged as
illustrated by arrows 40 through an annulus 60 between an inside 44
of wellbore 10 and an outside 62 of drill pipe 34.
[0052] As the drilling fluid moves upwardly it is eventually
recovered as illustrated by an arrow 42. This drilling fluid is
typically passed to a drill cuttings separation section and is
typically degassed and adjusted to the desired composition and
thereafter reinjected.
[0053] As illustrated schematically in FIG. 1, a first enlarged
section 46 is positioned on an upper end of the drill pipe 34. A
section of enlarged section 48 is positioned on an end of a second
drill pipe 50 so that they may be matingly joined. The slips 52
support slightly lifted drill pipe 34 while second pipe section 50
is joined to the drill pipe 34. Such techniques are considered to
be well known to those skilled in the art and do not require
further description. A centralizer 58 is commonly used to maintain
drill pipe 34 in a central portion of the wellbore.
[0054] Sensors 54 for sensing gas or a parameter indicative of gas
in the annulus are illustrated near a bottom 64 of the drill
string. Sensors 54 are referred to herein as "annulus sensors" for
reasons that will become apparent. Annulus sensors 54 are desirably
placed at a distance from about 1 to about 200 feet (about 0.3
meter to about 60 meters) above the bottom 64 of drill pipe 34.
Annulus sensors 54 may be positioned as a portion of a drill pipe
section or they may be attached to the inside or the outside of the
drill pipe. With some types of sensors the annulus sensors 54 could
be positioned inside drill pipe 34. In certain embodiments, the
annulus sensors 54 for sensing gas or parameter indicative of gas
in the annulus may be positioned in the drill pipe; in other
embodiments, the annulus sensors 54 for sensing gas or parameter
indicative of gas in the annulus may be positioned on the outside
of the drill pipe. Annulus sensors 54 are effective to sense the
amount of gas contained in the drilling fluid in the annulus,
particularly to distinguish the amount of gas during times when the
pumps are turned off compared to the amount of gas when pumps are
on. The pressure reduction in the drilling fluid during a pumps-off
condition will be substantially less in some wells (as high as 300
psi, about 2 MPa, in some cases) than when the drilling fluid pumps
are on. This allows the relatively accurate measurement of the
amount of gas entering the wellbore annulus from the formations
during the times when the pumps are turned off. This provides an
accurate basis for estimating the amount of pressure generated by
the formation against the hydrostatic pressure of the drilling
fluid. This information is desirably transmitted up the drill
string as known to those skilled in the art, by connectors passing
along the drill string. While not illustrated in FIG. 1, a
plurality of annulus sensors 54 could be used. The plurality of
annulus sensors 54 could be distributed along drill pipe 62 from
drill bit 36 back to the surface. Annulus sensors 54 provide
information which can be used to determine the amount of gas in the
drilling fluid at the bottom of the well during periods when the
pumps are shut down.
[0055] As noted previously, drilling fluid being pumped down the
well through the drill pipe may contain recirculated gas or may
contain air added to the drilling fluid through circulation across
the shale shakers or introduced as an air bubble at the time drill
pipe connections are made at the surface. The most suitable gas
detection devices used downhole to monitor the annulus, such as
annulus sensors 54 in FIG. 1, are not capable of distinguishing
freshly introduced formation gas from circulated gas. These gases
need to be distinguished so as not to lead to a false conclusion
that the well is underbalanced due to the detection of circulated
gas downhole.
[0056] Referring again to FIG. 1, it has now been determined that
recirculated and/or air gas can be identified and distinguished
from fresh influx gas in the wellbore by placing one or more
sensors 55 sensitive to the recirculating gas and/or air gas in the
drill string behind the drill bit, in certain embodiments at the
same level as annulus sensors 54 (although not necessarily) to
monitor the amount of gas present in the drilling fluid inside the
drill pipe. Sensors 55 will be referred to herein as "drill string
sensors" to distinguish them from annulus sensors 54. The detected
internal drill string gas levels can then be tracked volumetrically
as a function of the drilling fluid volumes pumped to recognize
when recirculating gasses and/or air pass annulus sensors 54. In
this manner the observed annulus gas volumes measured by annulus
sensors 54 may be corrected to remove the effects of circulated gas
and/or air measured by drill string sensors 55.
[0057] As illustrated in FIG. 1, drill string sensors 55 for
sensing gas or a parameter indicative of gas in the drill string
are illustrated near a bottom 64 of the drill string, similar to
the position of annulus sensors 54, although this is mainly for
convenience, and is not strictly necessary. Drill string sensors 55
are desirably placed at a distance from about 1 to about 200 feet
(about 0.3 meter to about 60 meters) above the bottom 64 of drill
pipe 34. Drill string sensors 55 may be positioned as a portion of
a drill pipe section or they may be attached to the inside or the
outside of the drill pipe. With some types of sensors the drill
string sensors 55 could be positioned inside drill pipe 34. In
certain embodiments, drill string sensors 55 for sensing gas or
parameter indicative of gas in the drill string may be positioned
in the drill pipe; in other embodiments, drill string sensors 55
for sensing gas or parameter indicative of gas in the drill string
may be positioned on the outside of the drill pipe. Drill string
sensors 55 are effective to sense the amount of gas contained in
the drilling fluid in the drill string during drilling fluid flow
or during period of no or little drilling fluid flow in the drill
string. This information allows correction of the annulus sensors
54 and provides a more accurate basis for estimating the amount of
pressure generated by the formation against the hydrostatic
pressure of the drilling fluid. This information is desirably
transmitted up the drill string as known to those skilled in the
art, by connectors passing along the drill string. While not
illustrated in FIG. 1, a plurality of drill string sensors 55 could
be used. The plurality of drill string sensors 55 could be
distributed along drill pipe 62 from drill bit 36 back to the
surface.
[0058] The sensors 54 and 55 may be of any suitable type, such as
pulse-echo, density, ultrasonic, velocity, sonic impedance,
acoustic impedance and the like, as known to those skilled in the
art. They may be the same or different from each other. In certain
embodiments, sensors 54 will be all one type, while sensors 55 will
all be of a different type. In certain other embodiments, all
sensors 54 and 55 will be identical in operation. The particular
type sensors required are not considered to constitute part of the
present disclosure but rather the use of the sensors to perform the
methods claimed in the present disclosure is considered to
constitute the present disclosure. Sensors 54 and 55 could be
positioned on, inside or outside of the drill pipe and adapted to
detect comparable values for the drill fluid in the drill pipe and
in the annulus.
[0059] In FIG. 2 a second embodiment of the present invention is
illustrated. In this embodiment the upper portion of wellbore 10
has been cased with a casing 30 supported in place in the wellbore
by cement 32. The drilling fluid is injected as described through
drill pipe 34 as illustrated by arrows 38 with the drilling fluid
being passed downwardly through drill pipe 34, out through drill
bit 36 and upwardly through the annulus as illustrated by arrows 40
to recovery through a recovery line 42. In this embodiment, a
centralizer 58 is also used. In addition to annulus sensors 54 and
drill string sensors 55 positioned near a bottom 64 of drill pipe
34, a plurality of sensors 54 and 55 are arranged along the length
of drill pipe 34. Sensors 54 will affect a measurement of the
amount of gas which may be leaking into the wellbore at levels
above the bottom of the wellbore. This can be of considerable
interest in the event that formations penetrated by the wellbore
tend to become more active in releasing materials into the wellbore
at the hydrostatic pressure of the drilling fluid. It will be noted
that the hydrostatic pressure of the drilling fluid will be
somewhat less at the upper portions of the formation than at the
bottom of the wellbore.
[0060] By the use of the methods of the present disclosure,
circulated gas can be identified and an amount of gas present in
the drilling fluid inside the drill pipe may be quantified. The
detected gas levels can be tracked volumetrically as a function of
the drilling fluid volumes pumped to recognize when those gasses
pass the detectors monitoring the annulus. In this manner the
observed annulus gas volumes can be corrected to remove the effects
of circulated gas or air. Furthermore, gas concentration in the
drilling fluid may be determined during a pumps-off period and then
may be compared to a standard gas amount to determine whether the
weight of the drilling fluid should be increased or whether other
steps should be taken to control the wellbore. Particularly, it may
be desirable to compare this gas measurement to previous gas
measurements in the same well taken at an earlier pumps-off period
or while the pumps were on. Desirably the gas concentration is
measured at each pumps-off period and more frequently if
significant changes are detected. This provides an indication as to
whether the pressure in the formation is increasing relative to the
pressure in the well as indicated by the result of gases entering
the wellbore increasing at pumps-off conditions. Alternatively,
other standards can be adopted to determine whether amounts of
gases entering the wellbore are excessive. By the methods of the
present disclosure, upon the drill bit approaching a high pressure
formation, an increase in gas entry into the bottom of the wellbore
will be detected. This enables the operator to weight the drilling
fluid more heavily to impose a back pressure upon the drilling
fluid contained in the annulus or the like to control the well.
[0061] By the methods of the present disclosure, upon the drill bit
approaching a high pressure formation, an increase in gas entry
into the bottom of the wellbore will be detected. This enables the
operator to weight the drilling fluid more heavily to impose a back
pressure upon the drilling fluid contained in the annulus or the
like to control the well.
[0062] The methods of the present disclosure provide an effective
method for determining a meaningful number related to conditions at
the bottom of the borehole in substantially real time. The amount
of gas contained in the drilling fluid is indicative of the amount
of gas-containing materials entering the wellbore annulus from the
surrounding formations. Furthermore, knowledge of the recirculating
gasses or air allows correction of the measured annulus gas
amounts. This information is very helpful in controlling the well,
adjusting the weight of the drilling fluid and the like.
[0063] By the methods of the present disclosure, quantities of gas
on the order of 0.01 and up to in excess of 5.0 vol. % as measured
at surface conditions or greater can be detected downhole.
Typically these methods will detect relatively small amounts of gas
in the drilling fluid near the downhole annulus sensor to enable
the detection of trends. These quantities of gas do not exert
appreciable pressure and are detectable at the wellhead using
conventional gas detection techniques and while indicative of gas
invasion into the well, are not normally detected downhole by
existing testing systems for detecting large gas bubbles. The
methods of the present disclosure enable early detection of
increasing gas levels before the gas concentrations can reach
problematic levels. These methods may be used by comparing
successive annulus gas readings under similar conditions, as well
as comparing to gas measured in the drill string by the drill
string sensors. An increase in annulus gas from about 1 to about 3
times a background or baseline value is of great concern. The
background or baseline value may be a previous quantitative
measurement of annulus gas, a measurement of drill string gas, or
another indicia of the background conditions. This early detection
enables the driller to take corrective action much earlier than if
the drilling fluid were analyzed for the same or similar
information at the surface.
[0064] FIG. 3 illustrates a method embodiment of the present
disclosure in flowchart form. Embodiment 300 of FIG. 3 illustrates
in box 302 drilling a well with a drilling fluid, a drill string,
and a drill bit from an earth surface through a formation. Box 304
illustrates pumping the drilling fluid through the drill string,
drill bit, and into an annulus between the drill string and a
wellbore. It should be pointed out that the steps illustrated in
FIG. 3 are merely for illustrating the concepts of the disclosure;
it is not intended that the steps must be taken sequentially or in
parallel. Box 306 indicates measuring, while drilling, a parameter
of the drilling fluid indicative of circulated gas or air inside
the drill string behind and near the drill bit using one or more
sensors. Box 305 illustrates supporting at least one annulus gas
sensor by the drill pipe near the bottom of the drill pipe and
positioned to sense the amount of gas in the drilling fluid in the
annulus at a depth of the at least one annulus gas sensor. Box 307
illustrates periodically stopping pumping, and detecting the amount
of gas in the drilling fluid in the annulus at the level of the at
least one sensor during pumping periods before and after stopping
of pumping. In embodiment 300, the next step, illustrated by box
308 is communicating the result to a human-readable interface at
the surface. Box 310 illustrates comparing the amount of gas in the
drilling fluid in the annulus at the level of the at least one
sensor during the pumping periods.
[0065] In accordance with the present disclosure, a primary
interest lies in using one or more of the methods and apparatus
described above to correct observed annulus gas volumes to remove
the effects of circulated gas or air, and using this information to
diagnose, make decisions on, and implement changes to drilling
fluid weight, density, or other parameter. The skilled operator or
designer will determine which methods, apparatus and drilling
fluids are best suited for a particular well and formation to
achieve the highest efficiency without undue experimentation.
[0066] Methods and apparatus in accordance with the present
disclosure may include means for measuring drilling fluid
temperature and annular fluid pressure of fluids flow (or not
flowing) inside the drill string, and/or flowing (or not flowing)
in the annulus. Suitable temperature measurement means include
thermocouples, thermistors, resistant temperature detectors (RTDs),
and the like. Suitable fluid pressure measurement means include
piezoelectric sensors, fiber optic sensors, strain gauges,
microelectromechanical (MEMS) sensors, and the like. The apparatus
and methods of the present disclosure may also include means for
calculating temperature- and pressure-corrected measurement values
using the measured temperatures and fluid pressures. Suitable means
for calculating include digital computers, and the like, either
hard-wired or wirelessly connected to the drill string or tools in
the drill string, and which may include wired or wireless
connections to human-readable devices, such as video CRT screens,
printers, and the like.
[0067] Useful drilling muds for use in the methods of the present
disclosure include water-based, oil-based, and synthetic-based
muds. The choice of formulation used is dictated in part by the
nature of the formation in which drilling is to take place. For
example, in various types of shale formations, the use of
conventional water-based muds can result in a deterioration and
collapse of the formation. The use of an oil-based formulation may
circumvent this problem. A list of useful muds would include, but
not be limited to, conventional muds, gas-cut muds (such as air-cut
muds), balanced-activity oil muds, buffered muds, calcium muds,
deflocculated muds, diesel-oil muds, emulsion muds (including oil
emulsion muds), gyp muds, oil-invert emulsion oil muds, inhibitive
muds, kill-weight muds, lime muds, low-colloid oil muds, low solids
muds, magnetic muds, milk emulsion muds, native solids muds, PHPA
(partially-hydrolyzed polyacrylamide) muds, potassium muds, red
muds, saltwater (including seawater) muds, silicate muds, spud
muds, thermally-activated muds, unweighted muds, weighted muds,
water muds, and combinations of these.
[0068] Useful mud additives include, but are not limited to
asphaltic mud additives, viscosity modifiers, emulsifying agents
(for example, but not limited to, alkaline soaps of fatty acids),
wetting agents (for example, but not limited to dodecylbenzene
sulfonate), water (generally a NaCl or CaCl.sub.2 brine), barite,
barium sulfate, or other weighting agents, and normally amine
treated clays (employed as a viscosification agent). More recently,
neutralized sulfonated ionomers have been found to be particularly
useful as viscosification agents in oil-based drilling muds. See,
for example, U.S. Pat. Nos. 4,442,011 and 4,447,338, both
incorporated herein by reference. These neutralized sulfonated
ionomers are prepared by sulfonating an unsaturated polymer such as
butyl rubber, EPDM terpolymer, partially hydrogenated polyisoprenes
and polybutadienes. The sulfonated polymer is then neutralized with
a base and thereafter steam stripped to remove the free carboxylic
acid formed and to provide a neutralized sulfonated polymer
crumb.
[0069] The mud system used may be an open or closed system. Any
system used should allow for samples of circulating mud to be taken
periodically, whether from a mud flow line, a mud return line, mud
motor intake or discharge, mud house, mud pit, mud hopper, or two
or more of these.
[0070] In actual operation, depending on the mud report from the
mud engineer, the drilling rig operator (or owner of the well) has
the opportunity to adjust the density, specific gravity, weight,
viscosity, water content, oil content, composition, pH, flow rate,
solids content, solids particle size distribution, resistivity,
conductivity, and combinations of these properties of the mud. The
mud report may be in paper format, or more likely today, electronic
in format. The change in one or more of the list parameters and
properties may be tracked, trended, and changed by a human operator
(open-loop system) or by an automated system of sensors,
controllers, analyzers, pumps, mixers, agitators (closed-loop
systems).
[0071] "Drilling" as used herein may include, but is not limited
to, rotational drilling, directional drilling, non-directional
(straight or linear) drilling, deviated drilling, geosteering,
horizontal drilling, and the like. Rotational drilling may involve
rotation of the entire drill string, or local rotation downhole
using a drilling mud motor, where by pumping mud through the mud
motor, the bit turns while the drillstring does not rotate or turns
at a reduced rate, allowing the bit to drill in the direction it
points. A turbodrill may be one tool used in the latter scenario. A
turbodrill is a downhole assembly of bit and motor in which the bit
alone is rotated by means of fluid turbine which is activated by
the drilling mud. The mud turbine is usually placed just above the
bit.
[0072] "Bit" or "drill bit", as used herein, includes, but is not
limited to antiwhirl bits, bicenter bits, diamond bits, drag bits,
fixed-cutter bits, polycrystalline diamond compact bits,
roller-cone bits, and the like. The choice of bit, like the choice
of drilling mud, is dictated in part by the nature of the formation
in which drilling is to take place.
[0073] The rate of penetration (ROP) during drilling methods of
this disclosure depends on permeability of the rock (the capacity
of a porous rock formation to allow fluid to flow within the
interconnecting pore network), the porosity of the rock (the volume
of pore spaces between mineral grains expressed as a percentage of
the total rock volume, and thus a measure of the capacity of the
rock to hold oil, gas, or water), and the amount or percentage of
vugs. Generally the operator or owner of the well wishes the ROP to
be as high as possible toward a known trap (any geological
structure which precludes the migration of oil and gas through
subsurface rocks, causing the hydrocarbons to accumulate into
pools), without excess tripping in and out of the wellbore. In
accordance with the present disclosure the drilling contractor or
operator is able to drill more confidently and safely, knowing the
pore pressure in the formation ahead of the drill bit before the
drill bit actually penetrates the hydrocarbon-bearing region.
[0074] From the foregoing detailed description of specific
embodiments, it should be apparent that patentable methods and
apparatus have been described. Although specific embodiments of the
disclosure have been described herein in some detail, this has been
done solely for the purposes of describing various features and
aspects of the methods and apparatus, and is not intended to be
limiting with respect to the scope of the methods and apparatus. It
is contemplated that various substitutions, alterations, and/or
modifications, including but not limited to those implementation
variations which may have been suggested herein, may be made to the
described embodiments without departing from the scope of the
appended claims.
* * * * *