U.S. patent application number 11/737163 was filed with the patent office on 2007-10-25 for pressure safety system for use with a dynamic annular pressure control system.
Invention is credited to Donald G. Reitsma.
Application Number | 20070246263 11/737163 |
Document ID | / |
Family ID | 38625720 |
Filed Date | 2007-10-25 |
United States Patent
Application |
20070246263 |
Kind Code |
A1 |
Reitsma; Donald G. |
October 25, 2007 |
Pressure Safety System for Use With a Dynamic Annular Pressure
Control System
Abstract
A method for controlling formation pressure during the drilling
of a borehole through a subterranean formation includes selectively
pumping a drilling fluid through a drill string extended into a
borehole, out a drill bit at the bottom end of the drill string,
and into an annular space between drill string and the borehole.
The drilling fluid is discharged to a reservoir to clean the
drilling fluid for reuse. Annular space fluid pressure is
selectively increased to maintain a selected fluid pressure
proximate the bottom of the borehole by applying fluid pressure to
the annular space. The selective increasing includes controlling an
aperture of an orifice operatively coupled between the annular
space and the reservoir. Fluid from the annular space is discharged
other than through the orifice when the annular space fluid
pressure exceeds a selected value, or drops below a selected
value.
Inventors: |
Reitsma; Donald G.; (Katy,
TX) |
Correspondence
Address: |
RICHARD A. FAGIN
P.O. BOX 1247
RICHMOND
TX
77406-1247
US
|
Family ID: |
38625720 |
Appl. No.: |
11/737163 |
Filed: |
April 19, 2007 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60793488 |
Apr 20, 2006 |
|
|
|
Current U.S.
Class: |
175/38 ; 175/48;
175/57 |
Current CPC
Class: |
E21B 21/08 20130101;
E21B 21/06 20130101; E21B 21/10 20130101 |
Class at
Publication: |
175/38 ; 175/57;
175/48 |
International
Class: |
E21B 7/00 20060101
E21B007/00; E21B 44/00 20060101 E21B044/00 |
Claims
1. A method for controlling formation pressure during the drilling
of a borehole through a subterranean formation, comprising:
selectively pumping a drilling fluid through a drill string
extended into a borehole, out a drill bit at the bottom end of the
drill string, and into an annular space between drill string and
the borehole; discharging the drilling fluid to a reservoir to
clean the drilling fluid for reuse; selectively increasing annular
space fluid pressure to maintain a selected fluid pressure
proximate the bottom of the borehole by applying fluid pressure to
the annular space, the selective increasing including controlling
an aperture of an orifice operatively coupled between the annular
space and the reservoir; and discharging fluid from the annular
space other than through the orifice when the annular space fluid
pressure exceeds a selected value or drops below a selected
value.
2. The method of claim 1 wherein the discharging comprises opening
a pressure relief valve when the fluid pressure in the annular
space exceeds a preselected fraction of a formation integrity test
pressure.
3. The method of claim 2 wherein the preselected fraction is
between about 80 to 90 percent of the formation integrity test
pressure.
4. The method of claim 1 further comprising operating a safety
valve if the fluid pressure in the annular space falls below a
selected value.
5. The method of claim 4 wherein the operating the safety valve
comprises stopping fluid flow to the orifice.
6. The method of claim 4 wherein the operating the safety valve
comprises diverting fluid flow from the orifice to a backup
selectively controllable orifice.
7. A method for controlling formation pressure during the drilling
of a borehole through a subterranean formation, comprising:
selectively pumping a drilling fluid through a drill string
extended into a borehole, out a drill bit at the bottom end of the
drill string, and into an annular space between drill string and
the borehole; discharging the drilling fluid to a reservoir to
clean the drilling fluid for reuse; selectively increasing annular
space fluid pressure to maintain a selected fluid pressure
proximate the bottom of the borehole by applying fluid pressure to
the annular space, the selective increasing including controlling
an aperture of an orifice operatively coupled between the annular
space and the reservoir; and operating a safety valve if the fluid
pressure in the annular space falls below a selected value.
8. The method of claim 7 wherein the operating the safety valve
comprises stopping fluid flow to the orifice.
9. The method of claim 7 wherein the operating the safety valve
comprises diverting fluid flow from the orifice to a backup
selectively controllable orifice.
10. The method of claim 7 further comprising causing fluid to flow
other than through the orifice if the fluid pressure in the annular
space increases above a selected value.
11. The method of claim 10 wherein the causing fluid flow comprises
opening a pressure relief valve.
12. The method of claim 11 wherein the pressure relief valve is
caused to operate when the fluid pressure reaches a preselected
fraction of a formation integrity test pressure.
13. The method of claim 12 wherein the preselected fraction is
between about 80 to 90 percent of the formation integrity test
pressure.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] Priority is claimed from U.S. Provisional Application No.
60/793,488 filed on Apr. 20, 2006.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[0002] Not applicable.
BACKGROUND OF THE INVENTION
[0003] 1. Field of the Invention
[0004] The invention relates generally to the field of drilling
boreholes using dynamic annular pressure control devices. More
specifically, the invention relates to method for determining
borehole fluid control events, such as loss of drilling fluid or
formation fluid entry into a borehole when such devices are
used.
[0005] 2. Background Art
[0006] The exploration for and production of hydrocarbons from
subsurface Earth formations ultimately requires a method to reach
and extract the hydrocarbons from the formations. The reaching and
extracting are typically performed by drilling a borehole from the
Earth's surface to the hydrocarbon-bearing Earth formations using a
drilling rig. In its simplest form, a land-based drilling rig is
used to support a drill bit mounted on the end of a drill string.
The drill string is typically formed from lengths of drill pipe or
similar tubular segments connected end to end. The drill string is
supported by the drilling rig structure at the Earth's surface. A
drilling fluid made up of a base fluid, typically water or oil, and
various additives, is pumped down a central opening in the drill
string. The fluid exits the drill string through openings called
"jets" in the body of the rotating drill bit. The drilling fluid
then circulates back up an annular space formed between the
borehole wall and the drill string, carrying the cuttings from the
drill bit so as to clean the borehole. The drilling fluid is also
formulated such that the hydrostatic pressure applied by the
drilling fluid is greater than surrounding formation fluid
pressure, thereby preventing formation fluids from entering into
the borehole.
[0007] The fact that the drilling fluid hydrostatic pressure
typically exceeds the formation fluid pressure also results in the
fluid entering into the formation pores, or "invading" the
formation. To reduce the amount of drilling fluid lost through such
invasion, some of the additives in the drilling fluid adhere to the
borehole wall at permeable formations thus forming a relatively
impermeable "mud cake" on the formation walls. This mud cake
substantially stops continued invasion, which helps to preserve and
protect the formation prior to the setting of protective pipe or
casing in the borehole as part of the drilling process, as will be
discussed further below. The formulation of the drilling fluid to
exert hydrostatic pressure in excess of formation pressure is
commonly referred to as "overbalanced drilling."
[0008] The drilling fluid ultimately returns to the surface, where
it is transferred into a mud treating system, generally including
components such as a shaker table to remove solids from the
drilling fluid, a degasser to remove dissolved gases from the
drilling fluid, a storage tank or "mud pit" and a manual or
automatic means for addition of various chemicals or additives to
the fluid treated by the foregoing components. The clean, treated
drilling fluid flow is typically measured to determine fluid losses
to the formation as a result of the previously described fluid
invasion. The returned solids and fluid (prior to treatment) may be
studied to determine various Earth formation characteristics used
in drilling operations. Once the fluid has been treated in the mud
pit, it is then pumped out of the mud pit and is pumped into the
top of the drill string again.
[0009] The overbalanced drilling technique described above is the
most commonly used formation fluid pressure control method.
Overbalanced drilling relies primarily on the hydrostatic pressure
generated by the column of drilling fluid in the annular space
("annulus") to restrain entry of formation fluids into the
borehole. By exceeding the formation pore pressure, the annulus
fluid pressure can prevent sudden influx of formation fluid into
the borehole, such as gas kicks. When such gas kicks occur, the
density of the drilling fluid may be increased to prevent further
formation fluid influx into the borehole. However, the addition of
density increasing ("weighting") additives to the drilling fluid:
(a) may not be rapid enough to deal with the formation fluid
influx; and (b) may cause the hydrostatic pressure in the annulus
to exceed the formation fracture pressure, resulting in the
creation of fissures or fractures in the formation. Creation of
fractures or fissures in the formation typically results in
drilling fluid loss to the formation, possibly adversely affecting
near-borehole permeability of hydrocarbon-bearing formations. In
the event of gas kicks, the borehole operator may elect to close
annular sealing devices called "blow out preventers" (BOPs) located
below the drilling rig floor to control the movement of the gas up
the annulus. In controlling influx of a gas kick, after the BOPs
are closed, the gas is bled off from the annulus and the drilling
fluid density is increased prior to resuming drilling
operations.
[0010] The use of overbalanced drilling also affects the depths at
which casing must be set during drilling operations. The drilling
process starts with a "conductor pipe" being driven into the
ground. A BOP stack is typically attached to the top of the
conductor pipe, and the drilling rig positioned above the BOP
stack. A drill string with a drill bit may be selectively rotated
by rotating the entire string using the rig kelly or a top drive,
or the drill bit may be rotated independent of the drill string
using a drilling fluid powered motor installed in the drill string
above the drill bit. As noted above, an operator may drill through
the Earth formations ("open hole") until such time as the drilling
fluid pressure at the drilling depth approaches the formation
fracture pressure. At that time, it is common practice to insert
and hang a casing string in the borehole from the surface down to
the lowest drilled depth. A cementing shoe is placed on the drill
string and specialized cement is displaced through the drill string
and out the cementing shoe to travel up the annulus and displace
any fluid then in the annulus. The cement between the formation
wall and the outside of the casing effectively supports and
isolates the formation from the well bore annulus. Further open
hole drilling can be carried out below the casing string, with the
drilling fluid again providing pressure control and formation
protection in the drilled open hole below the bottom of the casing.
The casing protects the shallower formations from fracturing
induced by the hydrostatic pressure of the drilling fluid when the
density of the fluid must be increased in order to control
formation fluid pressures in deeper formations.
[0011] FIG. 1 is an exemplary diagram of the use of drilling fluid
density to control formation pressures during the drilling process
in an intermediate borehole section. The top horizontal bar
represents the hydrostatic pressure exerted by the drilling fluid
and the vertical bar represents the total vertical depth of the
borehole. The formation fluid (pore) pressure graph is represented
by line 10. As noted above, in overbalanced drilling, the drilling
fluid density is selected such that its pressure exceeds the
formation pore pressure by some amount for reasons of pressure
control and borehole stability. Line 12 represents the formation
fracture pressure. Borehole fluid pressures in excess of the
formation fracture pressure can result in the drilling fluid
pressurizing the formation walls to the extent that small cracks or
fractures will open in the borehole wall. Further, the drilling
fluid pressure overcomes the formation pressure and causes
significant fluid invasion. Fluid invasion can result in, among
other problems. reduced permeability, adversely affecting formation
production. The pressure generated by the drilling fluid and its
additives is represented by line 14 and is generally a linear
function of the total vertical depth. The hydrostatic pressure that
would be generated by the fluid absent any additives, that is by
plain water, is represented by line 16.
[0012] In an "open loop" drilling fluid system described above,
where the return fluid from the borehole is exposed only to
atmospheric pressure, the annular pressure in the borehole is
essentially a linear function of the borehole fluid density with
respect to depth in the borehole. In the strictest sense this is
true only when the drilling fluid is static. In reality the
drilling fluid's effective density may be modified during drilling
operations due to friction in the moving drilling fluid, however,
the resulting annular pressure is generally linearly related to
vertical depth.
[0013] In the example of FIG. 1, the hydrostatic pressure 16 of the
drilling fluid and the pore pressure 10 generally track each other
in the intermediate section of the borehole to a depth of
approximately 7000 feet. Thereafter, the pore pressure 10 (pressure
of fluids in the pore spaces of the Earth formations) increases at
a rate above that of an equivalent column of water in the interval
from a depth of 7000 feet to approximately 9300 feet. Such abnormal
formation pressures may occur where the borehole penetrates a
formation interval having significantly different characteristics
than the prior formation. The hydrostatic pressure 14 maintained by
the drilling fluid is safely above the pore pressure prior to about
7000 feet. In the 7000-9300 foot interval, the differential between
the pore pressure 10 and hydrostatic pressure 14 is significantly
reduced, decreasing the margin of safety during drilling
operations. A gas kick in this interval may result if the pore
pressure exceeds the hydrostatic pressure, with an influx of fluid
and gas into the borehole possibly requiring activation of the
BOPs. As noted above, while additional weighting material may be
added to the drilling fluid to increase its hydrostatic pressure,
such will be generally ineffective in dealing with a gas kick due
to the time required to increase the fluid density at the kick
depth in the borehole. Such time results from the fact that the
drilling fluid must be moved through thousands of feet of drill
pipe to even reach the bit depth, let alone begin filling the
annulus to increase the hydrostatic pressure in the annulus.
[0014] An open loop drilling fluid system is subject to a number of
other problems. It will be appreciated that it is necessary to shut
off the mud pumps in order to assemble successive drill pipe
segments ("joints") to the drill string to increase its length
(called "making a connection"), to enable drilling successively
deeper Earth formations. When the pumps are shut off, the annular
pressure will undergo a negative spike that dissipates as the
annular pressure stabilizes. Similarly, when the pumps are turned
back on after making a connection, the annular pressure will
undergo a positive spike. Such spiking occurs each time a pipe
joint is added to or removed from the string. It will be
appreciated that these pressure spikes can cause fatigue on the mud
cake and borehole wall, and could result in formation fluids
entering the borehole or fracturing the formation again leading to
a well control event.
[0015] To overcome the foregoing limitations of drilling using an
open-loop fluid circulating system, there have been developed a
number of drilling systems called "dynamic annular pressure
control" (DAPC) systems. One such system is disclosed, for example,
in U.S. Pat. No. 6,904,981 issued to van Riet and assigned to Shell
Oil Company. The DAPC system disclosed in the '981 patent includes
a fluid backpressure system in which fluid discharge from the
borehole is selectively controlled to maintain a selected pressure
at the bottom of the borehole, and fluid is pumped down the
drilling fluid return system to maintain annulus pressure during
times when the mud pumps are turned off. A pressure monitoring
system is further provided to monitor detected borehole pressures,
model expected borehole pressures for further drilling and to
control the fluid backpressure system.
[0016] It has been a concern in the industry that the use of DAPC
systems such as disclosed in the van Riet '981 patent that plugging
of any part of the backpressure system such that discharge of the
drilling fluid from the annulus back to the mud tank or pits is
restricted may result in damage to the borehole. Another concern
expressed in the industry is that failure of the backpressure
regulating components to hold the backpressure may result in loss
of pressure control over the borehole.
[0017] What is needed is a system to provide backup pressure
control in the borehole in the event of failure of components of a
DAPC system.
SUMMARY OF THE INVENTION
[0018] One aspect of the invention is a method for controlling
formation pressure during the drilling of a borehole through a
subterranean formation. A method according to this aspect includes
selectively pumping a drilling fluid through a drill string
extended into a borehole, out a drill bit at the bottom end of the
drill string, and into an annular space between drill string and
the borehole. The drilling fluid is discharged to a reservoir to
clean the drilling fluid for reuse. Annular space fluid pressure is
selectively increased to maintain a selected fluid pressure
proximate the bottom of the borehole by applying fluid pressure to
the annular space. The selective increasing includes controlling an
aperture of an orifice operatively coupled between the annular
space and the reservoir. Fluid from the annular space is discharged
other than through the orifice when the annular space fluid
pressure exceeds a selected value, or drops below a selected
value.
[0019] Other aspects and advantages of the invention will be
apparent from the following description and the appended
claims.
BRIEF DESCRIPTION OF THE DRAWINGS
[0020] FIG. 1 is a graph depicting annular pressures and formation
pore and fracture pressures.
[0021] FIGS. 2A and 2B are plan views of two different embodiments
of the apparatus that can be used with a method according to the
invention.
[0022] FIG. 3 is a block diagram of the pressure monitoring and
control system used in the embodiment shown in FIG. 2.
[0023] FIG. 4 is a functional diagram of the operation of the
pressure monitoring and control system.
[0024] FIG. 5 is a graph showing the correlation of predicted
annular pressures to measured annular pressures.
[0025] FIG. 6 is a graph showing the correlation of predicted
annular pressures to measured annular pressures depicted in FIG. 5,
upon modification of certain model parameters.
[0026] FIG. 7 is a graph showing how the DAPC system may be used to
control variations in formation pore pressure in an overbalanced
condition;
[0027] FIG. 8 is a graph depicting DAPC operation as applied to at
balanced drilling.
[0028] FIGS. 9A and 9B are graphs depicting how the DAPC system may
be used to counteract annular pressure drops and spikes that
accompany pump off/pump on conditions.
[0029] FIG. 10 shows another embodiment of a DAPC system that uses
only rig mud pumps for providing selected fluid pressure to both
the drill string and the annulus.
[0030] FIG. 11 shows one embodiment of a pressure safety system
that can be used with a DAPC system.
[0031] FIG. 12 shows another embodiment of the safety system of
FIG. 11 that includes a stand-alone controller.
DETAILED DESCRIPTION
[0032] 1. Drilling Circulation System and First Embodiment of a
Backpressure Control System
[0033] FIG. 2A is a plan view depicting a land-based drilling
system having one embodiment of a dynamic annular pressure control
(DAPC) system that can be used with the invention. It will be
appreciated that an offshore drilling system may likewise have a
DAPC system using methods according to the invention. The drilling
system 100 is shown including a drilling rig 102 that is used to
support drilling operations. Many of the components used on the
drilling rig 102, such as the kelly, power tongs, slips, draw works
and other equipment are not shown separately in the Figures for
clarity of the illustration. The rig 102 is used to support a drill
string 112 used for drilling a borehole through Earth formations
such as shown as formation 104. As shown in FIG. 2A the borehole
106 has already been partially drilled, and a protective pipe or
casing 108 set and cemented 109 into place in part of the drilled
portion of the borehole 106. In the present embodiment, a casing
shutoff mechanism, or downhole deployment valve, 110 is installed
in the casing 108 to optionally shut off the annulus and
effectively act as a valve to shut off the open hole section of the
borehole 106 (the portion of the borehole 106 below the bottom of
the casing 108) when a drill bit 120 is located above the valve
m110.
[0034] The drill string 112 supports a bottom hole assembly (BHA)
113 that can include the drill bit 120, a mud motor 118, a
measurement- and logging-while-drilling (MWD/LWD) sensor suite 119
that preferably includes a pressure transducer 116 to determine the
annular pressure in the borehole 106. The drill string 112 includes
a check valve to prevent backflow of fluid from the annulus into
the interior of the drill string 112. The MWD/LWD suite 119
preferably includes a telemetry package 122 that is used to
transmit pressure data, MWD/LWD sensor data, as well as drilling
information to be received at the Earth's surface. While FIG. 2A
illustrates a BHA utilizing a mud pressure modulation telemetry
system, it will be appreciated that other telemetry systems, such
as radio frequency (RF), electromagnetic (EM) or drill string
transmission systems may be used with the present invention.
[0035] As noted in the Background section above, the drilling
process requires the use of a drilling fluid 150, which is
typically stored in a reservoir 136. The reservoir 136 is in fluid
communications with one or more rig mud pumps 138 which pump the
drilling fluid 150 through a conduit 140. The conduit 140 is
connected to the uppermost segment or "joint" of the drill string
112 that passes through a rotating control head or "rotating BOP"
142. A rotating BOP 142, when activated, forces spherically shaped
elastomeric sealing elements to rotate upwardly, closing around the
drill string 112 and isolating the fluid pressure in the annulus,
but still enabling drill string rotation. Commercially available
rotating BOPs, such as those manufactured by National Oilwell
Varco, 10000 Richmond Avenue, Houston, Tex. 77042 are capable of
isolating annular pressures up to 10,000 psi (68947.6 kPa). The
fluid 150 is pumped down through an interior passage in the drill
string 112 and the BHA 113 and exits through nozzles or jets in the
drill bit 120, whereupon the fluid 150 circulates drill cuttings
away from the bit 120 and returns the cuttings upwardly through the
annular space 115 between the drill string 112 and the borehole 106
and through the annular space formed between the casing 108 and the
drill string 112. The fluid 150 ultimately returns to the Earth's
surface and goes through a diverter 117, through conduit 124 and
various surge tanks and telemetry receiver systems (not shown
separately).
[0036] Thereafter the fluid 150 proceeds to what is generally
referred to herein as a backpressure system 131. The fluid 150
enters the backpressure system 131 and flows through a flowmeter
126. The flow meter 126 may be a mass-balance type or other
high-resolution flowmeter. Utilizing measurements from the
flowmeter 126, a system operator will be able to determine how much
fluid 150 has been pumped into the well through the drill string
112, and the amount of fluid 150 returning from the borehole 106.
Based on differences between the amount of fluid 150 pumped and
fluid 150 returned, the system operator is be able to determine
whether fluid 150 is being lost to the formation 104, which may
indicate that formation fracturing or breakdown has occurred, i.e.,
a significant negative fluid differential. Likewise, a significant
positive differential would be indicative of formation fluid
entering into the borehole 106 from the Earth formations 104.
[0037] The returning fluid 150 proceeds to a wear resistant,
controllable orifice choke 130. It will be appreciated that there
exist chokes designed to operate in an environment where the
drilling fluid 150 contains substantial drill cuttings and other
solids. Choke 130 is preferably one such type and is further
capable of operating at variable pressures, variable openings or
apertures, and through multiple duty cycles. The fluid 150 exits
the choke 130 and flows through a valve 121. The fluid 150 can then
be processed by an optional degasser 1 and by a series of filters
and shaker table 129, designed to remove contaminants, including
drill cuttings, from the fluid 150. The fluid 150 is then returned
to the reservoir 136. A flow loop 119A, is provided in advance of a
three-way valve 125 for conducting fluid 150 directly to the inlet
of a backpressure pump 128. Alternatively, the backpressure pump
128 inlet may be provided with fluid from the reservoir 136 through
conduit 119B, which is in fluid communication with the trip tank.
The trip tank is normally used on a drilling rig to monitor
drilling fluid gains and losses during pipe tripping operations
(withdrawing and inserting the full drill string or substantial
subset thereof from the borehole). In the invention, the trip tank
functionality is preferably maintained. The three-way valve 125 may
be used to select loop 119A, conduit 119B or to isolate the
backpressure system. While the backpressure pump 128 is capable of
utilizing returned fluid to create a backpressure by selection of
flow loop 119A, it will be appreciated that the returned fluid
could have contaminants that would not have been removed by
filter/shaker table 129. In such case, the wear on backpressure
pump 128 may be increased. Therefore, the preferred fluid supply
for the backpressure pump 128 is conduit 119A to provide
reconditioned fluid to the inlet of the backpressure pump 128.
[0038] In operation, the three-way valve 125 would select either
conduit 119A or conduit 119B, and the backpressure pump 128 is
engaged to ensure sufficient flow passes through the upstream side
of the choke 130 to be able to maintain backpressure in the annulus
115, even when there is no drilling fluid flow coming from the
annulus 115. In the present embodiment, the backpressure pump 128
is capable of providing up to approximately 2200 psi (15168.5 kPa)
of pressure; though higher pressure capability pumps may be
selected at the discretion of the system designer.
[0039] The ability to provide backpressure is a significant
improvement over normal fluid control systems. The pressure in the
annulus provided by the fluid is a function of its density and the
true vertical depth and is generally a by approximation linear
function. As noted above, additives added to the fluid in reservoir
136 must be pumped downhole to eventually change the pressure
gradient applied by the fluid 150.
[0040] The system can include a flow meter 152 in conduit 100 to
measure the amount of fluid being pumped into the annulus 115. It
will be appreciated that by monitoring flow meters 126, 152 and
thus the volume pumped by the backpressure pump 128, it is possible
to determine the amount of fluid 150 being lost to the formation,
or conversely, the amount of formation fluid entering to the
borehole 106. Further included in the system is a provision for
monitoring borehole pressure conditions and predicting borehole 106
and annulus 115 pressure characteristics.
[0041] FIG. 2B shows an alternative embodiment of the DAPC system.
In this embodiment the backpressure pump is not required to
maintain sufficient flow through the choke when the flow through
the borehole needs to be shut off for any reason. In this
embodiment, an additional three-way valve 6 is placed downstream of
the drilling rig mud pumps 138 in conduit 140. This valve 6 allows
fluid from the rig mud pumps 138 to be completely diverted from
conduit 140 to conduit 7, thus diverting flow from the rig pumps
138 that would otherwise enter the interior passage of the drill
string 112. By maintaining action of rig pumps 138 and diverting
the pumps' 138 output to the annulus 115, sufficient flow through
the choke to control annulus backpressure is ensured.
[0042] 2. DAPC Monitoring System
[0043] FIG. 3 is a block diagram of the pressure monitoring system
146 of the DAPC system. System inputs to the pressure monitoring
system 146 include the downhole pressure 202 that has been measured
by the appropriate sensor in MWD/LWD sensor package 119,
transmitted to the Earth's surface by the MWD telemetry package 122
and received by transducer equipment (not shown) at the Earth's
surface. Other system inputs include pump pressure 200, input flow
204 from flow meter 152, drilling penetration rate and drill string
rotation rate, as well as axial force on the drill bit ("weight on
bit" or WOB) and torque on the drill bit (TOB) that may be
transmitted from suitable sensors (not shown separately) the BHA
113. Return mud flow is measured using flow meter 126. Signals
representative of the various data inputs are transmitted to a
control unit 230, which itself includes a drill rig control unit
232, a drilling operator's station 234, a DAPC processor 236 and a
back pressure programmable logic controller (PLC) 238, all of which
can be connected by a common data network 240. The DAPC processor
236 serves three functions, monitoring the state of the borehole
pressure during drilling operations, predicting borehole response
to continued drilling, and issuing commands to the backpressure PLC
to control the aperture of the choke 130 and to selectively operate
the backpressure pump 128. The specific logic associated with the
DAPC processor 236 will be discussed further below.
[0044] 3. Calculation of Backpressure
[0045] A schematic model of the functionality of the DAPC pressure
monitoring system 146 is shown in FIG. 4. The DAPC processor 236
includes programming to carry out "Control" functions and "Real
Time Model Calibration" functions. The DAPC processor 236 receives
data from the various sources and continuously calculates in real
time the correct backpressure set-point based on the values of the
input parameters. The backpressure set-point is then transferred to
the programmable logic controller 238, which generates control
signals for the backpressure pump 128 and the choke 130. The input
parameters fall into three main groups. The first are relatively
fixed parameters 250, including parameters such as borehole and
casing string geometry, drill bit nozzle diameters, and borehole
trajectory. While it is recognized that the actual borehole
trajectory may vary from the planned trajectory, the variance may
be taken into account with a correction to the planned trajectory.
Also within this group of parameters are temperature profile of the
drilling fluid in the annulus (115 in FIG. 2A) and the drilling
fluid composition. As with the trajectory parameters, these are
generally known and do not substantially change over small portions
of the course of the borehole drilling operations. In particular,
with the DAPC system, one objective is to be able to keep the fluid
150 density and composition relatively constant notwithstanding
changes in formation fluid pressure, by using the backpressure
system to provide the additional pressure to control the annulus
pressure.
[0046] The parameters in the second group of parameters 252 are
variable in nature and are sensed and logged substantially in real
time. The common data network 240 provides these data to the DAPC
processor 236. These data includes flow rate data provided by both
downhole and return flow meters 152 and 126, respectively, the
drill string rate of penetration (ROP) or axial velocity, the drill
string rotational speed, the drill bit depth, and the borehole
depth, the latter two being derived from data from well known
drilling rig sensors. The last parameter is the downhole pressure
254 that is provided by the downhole MWD/LWD sensor suite 119 and
can be transmitted to the Earth's surface using the mud pulse
telemetry package 122. One other input parameters is the set-point
downhole pressure 256, that is, the desired annulus pressure.
[0047] Functionally, the control module 258 attempts to calculate
the pressure in the annulus (115 in FIG. 2A) at each point over its
full borehole length, utilizing various models designed for various
formation and fluid parameters. The pressure in the annulus is a
function not only of the hydrostatic pressure or weight of the
fluid column in the borehole, but includes the pressures caused by
drilling operations, including fluid displacement by the drill
string, frictional losses returning up the annulus, and other
factors. In order to calculate the pressure within the well, the
programming in the control module 258 considers the borehole as a
finite number of segments, each assigned to a segment of borehole
length. In each of the segments the dynamic pressure and the fluid
weight (hydrostatic pressure) is calculated and are used to
determine the pressure differential 262 for the segment. The
segments are then summed and the pressure differential for the
entire borehole profile is determined.
[0048] It is known that the flow rate of the fluid 150 being pumped
into the borehole is proportional to the flow velocity of the fluid
150 and the velocity may thus may be used to determine dynamic
pressure loss as the fluid 150 is being pumped into the borehole
through the drill string. The fluid 150 density is calculated in
each segment, taking into account the fluid compressibility,
estimated drill cuttings loading and the thermal expansion of the
fluid 150 for the specified segment, which is itself related to the
temperature profile for that segment of the borehole. The fluid
viscosity at the estimated temperature for the segment is also
important for determining dynamic pressure losses for the segment.
The composition of the fluid is also considered in determining
compressibility and the thermal expansion coefficient. The drill
string rate of axial movement is related to "surge" and "swab"
pressures encountered during drilling operations as the drill
string is moved into or out of the borehole. The drill string
rotation is also used to determine dynamic pressures, as rotation
creates a frictional force between the fluid in the annulus and the
drill string. The drill bit depth, borehole depth, and borehole and
drill string geometry are all used to help generate the borehole
segments to be modeled. In order to calculate the weight of the
fluid, the present embodiment considers not only the hydrostatic
pressure exerted by fluid 150, but also the fluid compression,
fluid thermal expansion and the drill cuttings loading of the fluid
observed during drilling operations. It will be appreciated that
the cuttings loading can be determined as the fluid is returned to
the surface and reconditioned for further use. All of these factors
can be used in calculation of the "static pressure" of the fluid in
the annulus.
[0049] Dynamic pressure calculation includes many of the same
factors in determining static pressure. However, dynamic pressure
calculation further considers a number of other factors. Among them
is whether the fluid flow is laminar or turbulent. Whether the flow
is laminar or turbulent is related to the estimated roughness,
borehole size and the flow velocity of the fluid. The calculation
also considers the specific geometry for the segment in question.
This would include borehole eccentricity and specific drill string
segment geometry (e.g. threaded connection or "box/pin" upsets)
that affect the flow velocity observed in any segment of the
borehole annulus. The dynamic pressure calculation further includes
cuttings accumulation in the borehole, as well as fluid rheology
and the drill string movement's (axial and rotational) effect on
dynamic pressure of the fluid.
[0050] The pressure differential 262 for the entire annulus is
calculated and compared to the set-point pressure 251 in the
control module 264. The desired backpressure 266 is then determined
and conducted to programmable logic controller 238, which generates
control signals for the backpressure pump 128 and the choke 130.
Generally, backpressure is increased by reducing the choke
aperture. Backpressure is decreased by increasing the choke
aperture. As will be explained in more detail below, the particular
choke aperture extant at any time can be used as an indicator that
a well control event is taking place, namely, that formation fluid
is entering the borehole from one or more of the formations (a
"kick"), or drilling fluid is leaving the borehole and entering one
or more of the formations adjacent to the borehole ("lost
circulation").
[0051] 4. Calibration and Correction of the Backpressure
[0052] The above discussion of how backpressure is generally
calculated uses several downhole parameters, including downhole
pressure and estimates of fluid viscosity and fluid density. These
parameters are determined downhole and are typically transmitted up
the mud column using mud pressure pulses. Because the data
bandwidth for mud pulse telemetry is very low and the bandwidth is
also used by other MWD/LWD functions, as well as drill string
control functions, downhole pressure, fluid density and viscosity
essentially cannot be input to the DAPC model on a real time basis.
Accordingly, it will be appreciated that there is likely to be a
difference between the measured downhole pressure, when transmitted
up to the surface using the mud pulse telemetry, and the predicted
downhole pressure for that depth. When such occurs the DAPC system
computes adjustments to the parameters and implements them in the
model to make a new best estimate of downhole pressure. The
corrections to the model may be made by varying any of the variable
parameters. In the present embodiment, the fluid density and the
fluid viscosity are modified in order to correct the predicted
downhole pressure. Further, in the present embodiment the actual
downhole pressure measurement is used only to calibrate the
calculated downhole pressure, rather than to predict downhole
annular pressure. If downhole telemetry bandwidth is improved in
the future to enable essentially real-time transmission of the
pressure and temperature near the bottom of the borehole, it may
then be practical to include real-time downhole pressure and
temperature information to correct the model.
[0053] Because there is a delay between the measurement of downhole
pressure and other real time inputs, the DAPC control system 236
further operates to index the inputs such that real time inputs
properly correlate with delayed downhole transmitted inputs. The
rig sensor inputs, calculated pressure differential and
backpressure pressures, as well as the downhole measurements, may
be "time-stamped" or "depth-stamped" such that the inputs and
results may be properly correlated with later received downhole
data. Using a regression analysis based on a set of recently
time-stamped actual pressure measurements, the model may be
adjusted to more accurately predict actual pressure and the
required backpressure.
[0054] FIG. 5 depicts the operation of the DAPC control system
demonstrating an uncalibrated DAPC model. It will be noted that the
downhole pressure while drilling (PWD) 400 is shifted in time as a
result of the time delay for the signal to be selected and
transmitted uphole. As a result, there exists a significant offset
between the DAPC predicted pressure 404 and the non-time stamped
pressure while drilling or annular pressure (PWD) measurement 400.
When the PWD is time stamped and shifted back in time 402, the
differential between PWD 402 and the DAPC predicted pressure 404 is
significantly less when compared to the non-time shifted PWD 400.
Nonetheless, the DAPC predicted pressure differs significantly. As
noted above, this differential is addressed by modifying the model
inputs for fluid 150 density and viscosity. Based on the new
estimates, in FIG. 6, the DAPC predicted pressure 404 more closely
tracks the time stamped PWD 402. Thus, the DAPC model uses the PWD
to calibrate the predicted pressure and modify model inputs to more
accurately predict downhole pressure throughout the entire borehole
profile.
[0055] Based on the DAPC predicted pressure, the DAPC control
system 236 will calculate the required backpressure level 266 and
transmit it to the programmable logic controller 240. The
programmable controller 240 then generates the necessary control
signals to choke 130, valves 121 and 123, and backpressure pump
128.
[0056] In a particular embodiment, calculation of the DAPC system
predicted borehole pressure is delayed, after each time the rig mud
pumps are started, at least until the pressure of the drilling mud
at the mud pump outlet is at least equal to the backpressure extant
at the inlet to the choke. The purpose for the present embodiment
is to overcome several adverse artifacts in pressure modeling
caused by charging of the mud circulation system after restarting
the rig mud pumps. It will be appreciated that when the rig mud
pumps are first started, such as after adding a new segment of
drill pipe to the drill string ("making a connection"), a
substantial quantity of drilling mud will be added to the total
drill string and borehole circulation system volume due to
compression of the mud when it is pressurized by the rig mud pumps
to the degree necessary to overcome all the friction in the
circulation system. The present embodiment may have particular
benefit in the case where a flowmeter is not available in the fluid
discharge circuit of the borehole.
[0057] In another particular embodiment, pressure in the annulus
may be measured at a plurality of different depths by using
pressure sensors disposed at spaced apart locations along the drill
string. Such distributed pressure sensors may be similar to those
disposed in data repeater devices in a "wired" drill string such as
one sold under the trademark INTELLIPIPE, which is a trademark of
Grant Prideco, L.P., Houston, Tex. Typically, the INTELLIPIPE
system includes a data repeater, which may have included
temperature and pressure sensors, every 1,000 feet along the drill
string. The system may include a pressure sensor proximate the
bottom of the drill string just as with conventional "pressure
while drilling" measuring instruments. In the present embodiment,
by having pressure measurements made at a plurality of positions
along the borehole, the hydraulics model may be calibrated for a
number of different effects, including variations in borehole
geometry that may result from washout or the like, changes in fluid
temperature, fluid viscosity and/or fluid density as a result of
fluid entry into the borehole or temperature changes resulting from
changes in drilling fluid flow rate within the borehole. Pressure
measurements made at a plurality of different positions along the
borehole may also provide indication of the existence of fluid
entry into the borehole from one or more of the Earth formations
adjacent the borehole. Fluid pressure at one or more of the
measurement positions that is at variance with a predicted pressure
from the hydraulics model may indicate fluid entry into the
borehole, and may be able to determine whether the fluid entering
the borehole is water, oil, gas or mixtures thereof.
[0058] From the foregoing description, it may be readily inferred
that the predicted pressure may be based on drilling fluid flow
rate and drill string fluid pressure, and expected borehole
geometry among other factors.
[0059] 5. Applications of the DAPC System
[0060] The advantage in using the DAPC controlled backpressure
system may be readily observed in the chart of FIG. 7. The
hydrostatic pressure of the fluid is depicted by line 302. As may
be seen, the hydrostatic pressure increases as a linear function of
the depth of the borehole according to the formula:
P=.rho.gTVD+C (1)
[0061] where P is the pressure, .rho. is the fluid specific
gravity, TVD is the total vertical depth of the borehole, g is the
Earth's gravitational constant and C is the backpressure supplied
by the backpressure system. In the instance of water gradient
hydrostatic pressure 302, the density of the fluid is that of
water. Moreover, in an open circulation system, the backpressure C
is always zero. In order to ensure that the annular pressure 303 is
in excess of the formation pore pressure 300, the fluid is weighted
(its density is increased), thereby increasing the pressure applied
with respect to the depth in the borehole. The pore pressure
profile 300 can be seen in FIG. 7 as being linear, until such time
as it exits casing 301, in which instance, it is exposed to the
actual formation pressure, resulting in a sudden increase in
formation pressure. In normal operations, the fluid density must be
selected such that the annular pressure 303 exceeds the formation
pore pressure below the casing 301.
[0062] By contrast, the use of the DAPC controlled backpressure
system permits an operator to make essentially step changes in the
annular pressure. Multiple DAPC pressure lines 304, 306, 308 and
310 are shown in FIG. 7. In response to the increase observed in
the pore pressure at 300b, the back pressure C may be increased to
increase the annular pressure from 304 to 306 to 308 to 310 in
response to increasing pore pressure 300b, in contrast with normal
annular pressure techniques as depicted in line 303. The DAPC
system further offers the advantage of being able to decrease the
back pressure in response to a decrease in pore pressure as shown
in 300c. It will be appreciated that the difference between the
DAPC-maintained annular pressure 310 and the pore pressure 300c,
known as the overbalance pressure, can be significantly less than
the overbalance pressure seen using conventional pressure control
methods 303. Highly overbalanced conditions can adversely affect
the formation permeability be forcing greater amounts of borehole
fluid into the formation.
[0063] FIG. 8 is a graph depicting one application of the DAPC
system in an at-balance drilling (ABD), or near ABD, environment.
The situation in FIG. 8 shows the pore pressure gradient in an
interval 320a as being substantially linear until approximately 2
km TVD, and the fluid in the formations as being kept in check by
conventional annular pressure 321a. At 2 km TVD a sudden increase
in pore pressure occurs, as shown at 320b. Utilizing pressure
control techniques known in the art, the procedure would be to
increase the fluid density to prevent formation fluid influx and
sloughing off of the borehole mud cake. The resulting increase in
density modifies the pressure gradient of the fluid to that shown
at 321b. However, in doing so it dramatically increases the
overbalance pressure, not only in region 320c, but in region 320a
as well.
[0064] Using the DAPC system, the technique to control the borehole
in view of the pressure increase observed at 320b is to apply
backpressure to the fluid in the annulus to shift the entire
annulus pressure profile to the right, such that pressure profile
322 more closely matches the pore pressure 320c, as opposed to that
presented by pressure profile 321b.
[0065] The DAPC system for pressure control may also be used to
control a major well control event, such as a fluid influx. Under
methods known in the art, in the event of a large formation fluid
influx, such as a gas kick, the only practical borehole pressure
control procedure was to close the BOPs to effectively
hydraulically "shut in" (seal) the borehole, relieve excess annulus
pressure through a choke and kill manifold, and weight up the
drilling fluid to provide additional annular pressure. This
technique requires time to bring the well under control. An
alternative method is sometimes called the "driller's method",
which uses continuous drilling fluid circulation without shutting
in the borehole. A supply of heavily weighted fluid, e.g., 18
pounds per gallon (ppg) (3.157 kg/l) is constantly available during
drilling operations below any set casing. When a gas kick or
formation fluid influx is detected, the heavily weighted fluid is
added and circulated downhole, causing the influx fluid to go into
solution in the circulating fluid. The influx fluid starts coming
out of solution upon reaching the casing shoe and is released
through the choke manifold. It will be appreciated that while the
Driller's method provides for continuous circulation of fluid, it
may still require additional circulation time without drilling
ahead, to prevent additional formation fluid influx and to permit
the formation fluid to go into circulation with the now higher
density drilling fluid.
[0066] Utilizing the present DAPC technique, when a formation fluid
influx is detected, the backpressure is increased, as opposed to
adding heavily weighted fluid. Like the driller's method, the mud
circulation is continued. With the increase in annulus pressure,
the formation fluid influx goes into solution in the circulating
fluid and is released via the choke manifold. Because the pressure
has been increased, it is no longer necessary to immediately
circulate a heavily weighted fluid. Moreover, as a result of the
fact that the backpressure is applied directly to the annulus, the
formation fluid is quickly forced to go into solution, as opposed
to waiting until the heavily weighted fluid is circulated into the
annulus.
[0067] An additional application of the DAPC technique relates to
its use in non-continuous circulating systems. As noted above,
continuous circulation systems are used to help stabilize the
formation, avoiding the sudden pressure 502 drops that occurs when
the mud pumps are turned off to make/break new pipe connections.
This pressure drop 502 is subsequently followed by a pressure spike
504 when the pumps are turned back on for drilling operations. This
is depicted in FIG. 9A. These variations in annular pressure 500
can adversely affect the borehole mud cake, and can result in fluid
invasion into the formation. As shown in FIG. 9B, the DAPC system
backpressure 506 may be applied to the annulus upon shutting off
the mud pumps, ameliorating the sudden drop in annulus pressure
from pump off condition to a more mild pressure drop 502. Prior to
turning the pumps on, the backpressure may be reduced such that the
pump on condition spike 504 is likewise reduced. Thus the DAPC
backpressure system is capable of maintaining a relatively stable
downhole pressure during drilling conditions.
[0068] 6. Determining Well Control Events with the DAPC System
[0069] It has been determined that a DAPC system such as the one
explained above with reference to FIGS. 2A through 9B, and one that
will be further explained below with reference to FIG. 10, can be
used to determine the existence of well control events. Well
control events include influx of fluid from the Earth formations
surrounding the borehole, and efflux of fluid in the borehole into
the surrounding formations. An influx event (called a "kick") can
be detected by comparing the calculated down hole pressure to the
actual down hole pressure. Calculating the down hole pressure can
be performed using a hydraulics model that determines down hole
pressure based on an expected fluid density in the borehole,
usually the density of the drilling fluid as pumped through the
drill string. The actual recorded down hole pressure is typically
measured near to the drill bit as with an annular pressure sensor
or some other form of bottom hole pressure measurement that
measures the actual down hole pressure.
[0070] Should an influx occur and there is a density contrast
between the influx fluid and the drilling fluid that is in the
borehole, the model-calculated and the actual borehole down hole
pressures will diverge as a result of the difference in the
calculated pressure of the column of fluid and the actual pressure
as measured, whether the column is static or dynamic. This
divergence can be recorded as an error by the DAPC system and
corrective action can be taken to maintain the down hole pressure
at the desired value (the set point pressure) by either reducing
the aperture of the choke if the density of the influx is less than
the density of the fluid in the well, or increasing the aperture of
the choke somewhat if the density of the influx is greater than the
density of the fluid in the well. Change in the choke aperture
resulting from such bottom hole pressure differences, when there is
no change in the pumped fluid flow rate, is used as an indicator
that an influx has taken place.
[0071] Another characteristic of an influx is that the choke
aperture may increase somewhat due to the increased fluid discharge
rate at the Earth's surface, and then stabilize at a new aperture,
which may be less, greater or the same as the immediately prior
choke aperture, depending on the influx fluid density. If the
influx continues and the density is less than the drilling fluid,
the average density of the fluid in the borehole will continue to
decrease and the choke aperture will continue to close in response
to the DAPC system attempting to maintain the down hole pressure at
the set point value. Conversely, if the influx fluid density is
greater than the borehole fluid density, as fluid influx continues,
the density of the fluid column in the borehole annulus will
increase, continuing to reduce the surface pressure in the annulus,
and thus causing the DAPC system to continue to increase the choke
aperture.
[0072] The DAPC system determines the new choke aperture based on
an adjustment of the predicted down hole pressure with respect to
the actual measured down hole pressure. In the case of a lower
density fluid influx, the predicted down hole pressure will be less
than the previous prediction because the fluid influx has continued
to reduce the average density of the column of fluid in the
annulus. This will continue to indicate an error and the DAPC
system will correct for the error by continuing to close the choke
for so long as the influx continues and the average density in well
bore continues to decrease. For the case of the influx fluid having
a higher density than the drilling fluid, for example, influx from
a salt water zone when drilling with an oil-based drilling fluid,
the DAPC system will open the choke aperture to reduce the surface
annulus pressure in order to compensate for the increasing density
of the fluid in the annulus for so long as the influx continues and
the average density is increasing.
[0073] The only other case is when the density of the influx is
practically equal to the extant borehole fluid density. In this
case the choke may open somewhat due to the increase in discharge
volume and then continue at the new aperture or a new averaged
aperture (due to choke aperture fluctuation using the PID
controller 238, such fluctuation being typically sinusoidal). The
DAPC system will produce an error that the choke aperture has
changed without changes calculated by the hydraulics model since
the model is using a number of standard parameters to calculate
down hole pressure, one of which is the pump rate. So long as the
pump rate does not change, or a change in the pump rate has not
indicated that the choke aperture is to be changed by the DAPC
system, an error will result. Therefore, a sustained increase in
choke aperture for no other apparent reason may be inferred to be a
kick when the density of the incoming formation fluid is
substantially the same as the drilling mud.
[0074] 7. Alternative Embodiment of Backpressure Control System
Using Only Rig Mud Pumps
[0075] It is also possible to provide selected, controlled annulus
fluid pressure without the need for an additional pump to supply
back pressure to the annulus when such back pressure must be
generated by a pump, as explained above with reference to FIG. 2B.
Another embodiment of a backpressure system that uses the rig mud
pumps is shown in schematic form in FIG. 10. The rig mud pump(s),
shown at 138 discharge drilling mud at selected flow rates and
pressures, as is ordinarily performed during drilling operations.
In the present embodiment, a first flowmeter 152 may be disposed in
the drilling mud flow path downstream of the pump(s) 138. The first
flowmeter 152 may be used to measure the flow rate of the drilling
fluid as it is discharged from the pump(s) 138. Alternatively, a
familiar "stroke counter", that estimates mud discharge volume by
monitoring movement of the pump(s) may be used to estimate the
total flow rate from the pump(s) 138. The drilling fluid flow is
then applied to a first controllable orifice choke 130A, the outlet
of which is ultimately coupled to the standpipe 602 (which is
itself coupled to the inlet to the interior passage in the drill
string). During regular drilling operations, the first choke 130A
is ordinarily fully opened.
[0076] Drilling fluid discharge from the pump(s) 138 is also
coupled to a second controllable orifice choke 130B, the outlet of
which is ultimately coupled to the well discharge (the annulus
604). As in previously described embodiments, the interior of the
well is sealed by a rotating control head or spherical BOP, shown
at 142. Not shown in FIG. 10 are the drill string and other
components in the well located below the rotating control head 602,
because they can be essentially identical to those used in other
embodiments, particularly such as shown in FIG. 2. A third
controllable orifice choke 130 can be coupled between the annulus
604 and the mud tank or pit (136 in FIG. 2) and controls the rate
at which the drilling mud leaves the well so as to maintain a
selected back pressure on the annulus, similarly to what is
performed in the previously described embodiments.
[0077] The first 130A and second 130B controllable orifice chokes
may each include downstream thereof a respective flow meter 152A,
152B. In conjunction with either the stroke counter (not shown) or
the first flowmeter 152 on the pump discharge, the flow rate of
drilling fluid from the pump(s) 138 into the standpipe and into the
annulus may be determined. The flowmeters 152, 152A, 152B are shown
as having their respective signal outputs coupled to the PLC 238 in
the DAPC unit 236, which may be essentially the same as the
corresponding devices shown in FIG. 3. Control outputs from the PLC
238 are provided to operate the three controllable orifice chokes
130, 130A, 130B.
[0078] For purposes of making or breaking connections in the drill
string during operation, it is necessary to release all the fluid
pressure at the top of the drill string, while it may be necessary
to continue to maintain fluid pressure to the top of the annulus
604. To perform the necessary pressure functions, the PLC 238 may
operate the first controllable orifice choke 130A to completely
close. Then, a bleed off or "dump" valve 600, which may be under
operative control of the PLC 238, is opened to release all the
drilling fluid pressure. The check valve or one way valve in the
drill string retains pressure below it in the drill string. Thus,
connections may be made or broken to lengthen or shorten the drill
string during drilling operations.
[0079] During such connection operations, selected fluid pressure
on the annulus is maintained by controlling the operation of the
pump(s) 138, and the second 130B and third 130 controllable orifice
chokes. Such control may be performed automatically by the PLC
238.
[0080] During regular drilling operations, the correct fluid
pressure is maintained on the annulus 604, using the same
hydraulics model as in the previous embodiments, by selectively
diverting a portion of the pump(s) 138 flow into the annulus 604 by
controlling the orifices of the first 130A and second 130B chokes,
and by controlling discharge from the well by controlling the
orifice of the third choke 130. Ordinarily during drilling, the
second choke 130B may remain closed, such that back pressure on the
well is maintained entirely by control of the orifice of the third
choke 130, similar to the manner in which back pressure is
maintained according to the previous embodiments. Ordinarily, it is
contemplated that the second choke 130B will be opened during
connection procedures to maintain back pressure, similar to the
times at which the back pressure pump in the previous embodiments
would be operated.
[0081] The present embodiment advantageously eliminates the need
for a separate pump to maintain back pressure. The present
embodiment may have additional advantages over the embodiment shown
in FIG. 2B which uses a three-way valve to diver mud flow from the
rig mud pumps to maintain back pressure, the most important of
which is that connections can be made without the need to stop the
rig mud pumps.
[0082] Depending on the particular equipment configuration, it may
be possible to determine mud flow rate into the annulus 604 using
the stroke counter (not shown) and the third flowmeter 152B, or
using the first and second flowmeters 152, 152A, respectively.
[0083] 8. Controlling Backpressure in Response to a Prediction of
Formation Fluid Pressure
[0084] The foregoing embodiments of a dynamic annular pressure
control system and methods for controlling fluid pressure in a
borehole generally operate on the principle that the bottom hole
pressure required to control the fluid pressure in the subterranean
formations is known. As will be readily appreciated by those
skilled in the art, prior knowledge of the formation fluid pressure
may be obtained from a number of sources. In so-called "normally
pressured" formations, the fluid pressure in the formations is
substantially the same as the fluid pressure of a column of water
having the same height as the true vertical depth in the wellbore
under consideration. Normally pressured formations occur where the
formations have some form of pressure conduit to the Earth's
surface, such that compression of the formations by the weight of
layers of rock thereabove (called "overburden") can be
hydraulically communicated to the Earth's surface. Compression of
the formations results in reduction of the fractional volume of
pore space to less than what was extant at the time the rock was
deposited. Such reduction in fractional volume of pore space
compresses the fluid in the pore spaces. If the fluid is in
hydraulic communication with the Earth's surface, then the
reduction in pore space is not accompanied by any increase in fluid
pressure. However, in many depositional environments, certain
layers of rock deposited above a porous, permeable Earth formation
may be impermeable, thus closing hydraulic communication with the
Earth's surface. In such cases, the weight of the overburden may be
increasingly borne by the fluid itself, as well as the solid rock
material ("matrix"). Where the fluid bears increasing amounts of
the overburden load, the fluid pressure in the subterranean
formations may increase to well beyond that of an equivalent height
water column. Such elevated formation pressures are known as
"overpressures" or "abnormal formation pressures." One object of
controlling fluid pressure in the borehole using the DAPC system
according to the various embodiments described herein is to control
abnormal formation pressures by maintaining a suitable bottom hole
pressure in the borehole.
[0085] Accordingly, in a particular implementation, one or more
techniques may be used to predict the formation fluid pressure at a
depth below that to which the wellbore has already been drilled.
The bottom hole pressure maintained by the DAPC system may be
adjusted in response to the predicted formation fluid pressure. As
used herein, increasing "depth" in the borehole means that the
total length of the borehole extending from the Earth's surface is
increased, even if the vertical depth in the Earth to which the
borehole extends may or may not be increased correspondingly. As
will be appreciated by those skilled in the art, a borehole may
increase in depth as defined above without penetrating deeper in
the vertical direction when such a borehole is drilled along a
substantially horizontal direction. A "depth below that to which
the borehole is drilled", therefore, may include for purposes of
defining the scope of this invention, a position in the Earth in
any position contemplated by the trajectory of the borehole to
which the borehole is expected to penetrate, but has not yet so
penetrated.
[0086] There are a number of formation fluid pressure estimation
techniques known in the art. An important technique is velocity
analysis from reflection seismic surveys. A reflection seismic
survey includes placing a seismic energy source and one or more
seismic receivers proximate the Earth's surface (or water surface
if conducted in a marine environment). The source is actuated and a
record of signals detected by the receiver, indexed with respect to
actuation, time is made. Inferences about the structure and
composition are made from events in the record determined to be a
result of subsurface acoustic impedance boundaries (usually at
formation layer boundaries) in the Earth. Estimates of seismic
energy velocity may be made from the travel times of the seismic
energy to the various reflectors. The estimates of seismic energy
velocity may be used to make an estimate of the formation fluid
pressure in the following manner. An ordinary rate of change in
seismic velocity ("normal trend") with respect to depth is
established from the velocity analysis. Deviations of velocity at
certain depths, usually slower than expected velocities determined
from the ordinary rate of change are correlated to abnormal
formation pressures. The amount of variation from the normal trend
has been shown by substantial experience to be directly correlated
to an amount of overpressure.
[0087] Other methods known in the art for estimating formation
fluid pressure include establishing "normal trends" for electrical
resistivity of the Earth formations, and acoustic velocity of the
formations. Various types of measuring instruments may be included
in the drill string, such as "logging while drilling" devices that
include resistivity and/or acoustic travel time sensors. Such
sensors make measurements corresponding to formation resistivity
and/or acoustic velocity. Such measurements may be communicated to
the Earth's surface as explained earlier herein. The measurements
may be used at the Earth's surface to estimate the formation fluid
pressure at a greater depth ("ahead of the bit") than the borehole
is drilled.
[0088] Yet another method for estimating formation fluid pressure
includes establishing a normal trend of a factor known as
"d-exponent." The d-exponent is also known as normalized rate of
penetration and can be calculated by a formula that includes the
diameter of the drill bit, the axial force (weight) applied to the
drill bit, the rotation rate of the drill bit and the rate of axial
movement of the drill string as the formations are drilled.
Deviations of the d-exponent from the normal trend are also shown
by considerable experience to correspond to the amount of
overpressure.
[0089] As may be inferred from the foregoing description, a normal
trend for any or all of the above parameters would indicate that as
overburden increases, the fractional volume of pore space in the
rock decreases as the rock matrix is compressed into tighter and
tighter contact. Therefore, the expectation in a normal trend is
for acoustic velocity, seismic velocity and formation resistivity
to increase with depth in the Earth, and for the d-exponent to
decrease. When some of the overburden load is carried by the
formation fluid because it is hydraulically isolated from the
Earth's surface, such contact between the matrix components is
effectively reduced from what it would otherwise be. Such reduction
in rock matrix compression results in lower resistivity and
velocity than that predicted by the normal trend, and
correspondingly, higher d-exponent.
[0090] A number of pore pressure prediction and analysis techniques
are available commercially and may have application with the DAPC
system. See, for example a sales brochure entitled, Pore Pressure
Prediction, Western Geco LLC, Houston, Tex. (2005). See also, Real
Time Pore Pressure Detection Ahead of the Bit, C. Esmersoy et al.,
Western Geco LLC, Houston, Tex. (2004).
[0091] 9. Safety Systems for Use with a DAPC System
[0092] FIG. 11 shows one embodiment of a safety system that can be
used with the foregoing DAPC system, or any other form of "closed
loop" managed pressure drilling system. For purposes of the
following description, "closed loop" means drilling such that the
rotating diverter, spherical BOP or similar device is used and
actuated, such that all drilling fluid returning from the borehole
is within a sealed environment until finally discharged into the
mud tank or pit. The mud tank 700 holds a supply of drilling fluid,
which is drawn through pump intake line 702A to the drilling rig
mud pumps 702. The drilling fluid is discharged through discharge
line 702B into the interior of the drill string 710. The drill
string 710 preferably includes a check valve 704 disposed at a
selected position along the string to hold fluid pressure from
returning to the mud pumps 702 when the mud pumps 702 are stopped.
The drilling fluid exits the drill string 710 at the bottom end
thereof through a drill bit 716, and returns to the surface through
the annulus 714. In the present embodiment, a rotating diverter,
spherical BOP or similar device, shown at 712, that rotatably seals
against the drill string 710 hydraulically closes the upper part of
the annular space 714. One fluid outlet from the rotating diverter
712 can be coupled to components of a DAPC system, for example, as
described above with reference to FIGS. 2A and 2B. Such components
may include a fluid pressure sensor 706, and a fluid flowmeter 708
that measure pressure and flow of the drilling fluid. The signals
from the sensor 706, 708 are in communication with a programmable
logic controller (PLC) 724 or similar device that operatively
controls a variable orifice choke 726 to regulate the flow of
drilling fluid out of the borehole and back to the mud tank 700. In
order to provide backpressure when the rig mud pumps 702 are
stopped, the system may include a backpressure pump 718 in fluid
communication on its discharge side with the annulus 714, as shown
in FIG. 11. The backpressure pump 718 may include a check valve 720
in its outlet line to prevent fluid flow back through the
backpressure pump 718 when the backpressure pump 718 is stopped.
Operation of the foregoing devices may be substantially as
explained above with reference to the DAPC system.
[0093] In the present embodiment, the safety system may provide
control over the pressure in the annular space 714 in the event the
DAPC system is unable to maintain such control. A shutoff valve
722, which may be solenoid operated, in the present embodiment is
disposed between a fluid outlet of the rotating diverter 712 and
the variable choke 726. If the pressure in the annulus 714 is below
the pressure required to maintain formation pressure control, and
the PLC 724 is attempting to close the variable choke 726, such may
be an indication of choke failure in the open position (enabling
more fluid flow than required). In such event, the PLC may be
programmed to close the shutoff valve 722. Alternatively, as shown
in the inset in FIG. 11, the shutoff valve 722 may be substituted
by a crossover valve 722A. The outlets of the crossover valve 722A
may be selected to place the fluid outlet of the rotating diverter
712 in fluid communication with either the controllable orifice
choke 726, or, when switched, a backup controllable orifice choke
726A. The crossover valve 722A would be switched in the event the
PLC 724 is attempting to operate the controllable choke 722 but the
pressure in the annular space 714 is not within a selected range.
In such event, the PLC 724 would operate the crossover valve 722A
to connect the fluid outlet of the rotating diverter through the
backup controllable orifice choke 726A.
[0094] In the event the PLC 724 is attempting to open the
controllable orifice choke 726, and pressure in the annular space
714 exceeds a safe value, to prevent failure of the bore hole, a
pressure relief valve 728 may be provided at the same or a
different fluid outlet from the rotating diverter 712. In the
present embodiment, the pressure relief valve 728 may be manually
set, such as by an adjustable, spring-biased diaphragm 730, to open
at a fixed relief pressure. The fixed relief pressure may be a
value that is a selected fraction of the most recent formation
integrity test (FIT) pressure, or "leakoff test" pressure. Such
pressure, as is known in the art, is the fluid pressure to which
the deepest casing shoe in the borehole, above the "open hole" or
uncased portion of the borehole, is tested by pumping drilling
fluid into the borehole. Once the fluid pressure acting on the
pressure relief valve 728 reaches the preselected fraction of the
FIT pressure, the pressure relief valve 728 will open, allowing
drilling fluid in the annular space 714 to leave the borehole and
return to the mud tank 700. The preselected fraction may be any
value deemed to be within industry accepted safety standards, such
as 80 to 90 percent of the FIT pressure.
[0095] FIG. 12 shows an alternative embodiment of a safety system
that includes a separate, stand alone programmable logic controller
(PLC) 724A, referred to as a "sfety system" PLC. The safety system
PLC 724A may be the same or different type of PLC as the PLC (724
in FIG. 11) used to operate the DAPC. The safety system PLC 724A
may be coupled at respective signal inputs to the same or a
different pressure sensor 706A and flow sensor 708A as for the DAPC
PLC (724 in FIG. 11). In the present embodiment, the safety system
PLC 724A may directly operate the shutoff valve 722 in the manner
described above with reference to FIG. 11. In some embodiments, the
safety system PLC 724A may operate the pressure relief valve 728
rather than having the pressure relief valve 728 be a mechanically
operated device.
[0096] In some embodiments, the safety system PLC 724A may be
programmed to include essentially the same functionality as the PLC
programmed to operate the DAPC system as explained above. In such
embodiments, the safety system PLC 724A may be programmed to
operate a crossover valve 722A coupled at one outlet thereof to a
controllable orifice choke 726A, similar to the valve and
controllable orifice choke explained above with reference to FIG.
11. In such embodiments, failure of the DAPC system will not
require stopping of the drilling operation, as the functionality
provided by the safety system PLC 724A, its associated sensors
706A, 708A, and controllable orifice choke 726A can provide
completely redundant annular space pressure control to the DAPC
system.
[0097] While the invention has been described with respect to a
limited number of embodiments, those skilled in the art, having
benefit of this disclosure, will appreciate that other embodiments
can be devised which do not depart from the scope of the invention
as disclosed herein. Accordingly, the scope of the invention should
be limited only by the attached claims.
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