U.S. patent application number 13/415945 was filed with the patent office on 2012-09-13 for method for automatic pressure control during drilling including correction for drill string movement.
Invention is credited to Ossama R. Sehsah.
Application Number | 20120227961 13/415945 |
Document ID | / |
Family ID | 46794469 |
Filed Date | 2012-09-13 |
United States Patent
Application |
20120227961 |
Kind Code |
A1 |
Sehsah; Ossama R. |
September 13, 2012 |
METHOD FOR AUTOMATIC PRESSURE CONTROL DURING DRILLING INCLUDING
CORRECTION FOR DRILL STRING MOVEMENT
Abstract
A method for determining annulus/wellbore fluid pressure, which
is corrected for movement of a pipe string into or out of a
wellbore, includes determining an initial annulus fluid pressure in
the wellbore. Determining the initial annulus fluid pressure may
include measuring a fluid flow rate into the wellbore and/or
measuring a fluid pressure in the annulus proximate the surface. A
rate of movement of a pipe string into or out of the wellbore is
also determined. The initial annulus fluid pressure is adjusted to
a corrected annulus fluid pressure by an amount which is a function
of the rate of motion of the pipe string, a surface area of the
outer wall of the pipe string and a surface area of the inner wall
of the wellbore.
Inventors: |
Sehsah; Ossama R.; (Katy,
TX) |
Family ID: |
46794469 |
Appl. No.: |
13/415945 |
Filed: |
March 9, 2012 |
Related U.S. Patent Documents
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
|
|
61450646 |
Mar 9, 2011 |
|
|
|
Current U.S.
Class: |
166/250.07 |
Current CPC
Class: |
E21B 21/08 20130101 |
Class at
Publication: |
166/250.07 |
International
Class: |
E21B 47/06 20120101
E21B047/06 |
Claims
1. A method for determining wellbore fluid pressure, corrected for
movement of a pipe string within a wellbore, the method comprising
the steps of: determining a rate of movement of a pipe string
within a wellbore; determining an initial wellbore fluid pressure
at a position within an annular space of the wellbore, the annular
space being defined between an outer wall of the pipe string and an
inner wall of the wellbore; and adjusting the initial wellbore
fluid pressure to a corrected wellbore fluid pressure by an amount
that is at least a function of the rate of movement of the pipe
string, a surface area of the outer wall of the pipe string and a
surface area of the inner wall of the wellbore.
2. The method of claim 1 wherein the step of adjusting the initial
wellbore fluid pressure includes the step of: determining a
pressure change in the annular space of the wellbore resulting from
movement of the pipe string.
3. The method of claim 2 wherein the step of determining a pressure
change in the annular space of the wellbore resulting from movement
of the pipe string is calculated using a flow rate of fluid flowing
from the wellbore, the flow rate measured with a flow meter
disposed in a fluid discharge conduit in fluid communication with
the annular space of the wellbore.
4. The method of claim 2 wherein the step of determining a pressure
change in the annular space of the wellbore resulting from movement
of the pipe string is a function of fluid displacement of the pipe
string in the wellbore, the fluid displacement calculated using
volumetric dimensions of the pipe string within the wellbore.
5. The method of claim 2 wherein an empirical correction factor is
used to correct the determined pressure change, the empirical
correction factor being a function of the rate of movement of the
pipe string, the surface area of the outer wall of the pipe string
and the surface area of the inner wall of the wellbore.
6. The method of claim 5 wherein the amount is a function of the
determined pressure change and the empirical correction factor.
7. The method of claim 1 wherein an empirical correction factor is
used to adjust the wellbore fluid pressure to the corrected
wellbore fluid pressure, the empirical correction factor being a
function of the rate of movement of the pipe string, the surface
area of the outer wall of the pipe string and the surface area of
the inner wall of the wellbore.
8. The method of claim 7 wherein the empirical correction factor is
calibrated by measuring pressure proximate a bottom end portion of
the pipe string.
9. The method of claim 1 further comprising the steps of: operating
a back pressure system to maintain the corrected wellbore fluid
pressure in the annular space of the wellbore near a selected value
during any rate of movement of the pipe string within the wellbore,
the backpressure system being arranged and designed to apply a back
pressure on the annular space of the wellbore.
10. The method of claim 1 wherein the amount of adjusting
corresponds to surge pressure indicative of pipe string movement
into the wellbore.
11. The method of claim 1 wherein the amount of adjusting
corresponds to swab pressure indicative of pipe string movement out
of the wellbore.
12. The method of claim 1 wherein all of the steps are conducted in
real time.
13. A method for determining wellbore fluid pressure, corrected for
movement of a pipe string within a wellbore, the method comprising
the steps of: determining a rate of movement of a pipe string
within a wellbore; determining an initial wellbore fluid pressure
at a position within an annular space of the wellbore, the annular
space being defined between an outer wall of the pipe string and an
inner wall of the wellbore; determining a pressure change in the
annular space of the wellbore resulting from movement of the pipe
string; determining an empirical correction factor that is at least
a function of the rate of movement of the pipe string, a surface
area of the outer wall of the pipe string and a surface area of the
inner wall of the wellbore; and adjusting the initial wellbore
fluid pressure to a corrected wellbore fluid pressure by an amount
that is a function of the determined pressure change and the
empirical correction factor.
14. The method of claim 13 wherein the step of determining a
pressure change in the annular space of the wellbore resulting from
movement of the pipe string is calculated using a flow rate of
fluid flowing from the wellbore, the flow rate measured with a flow
meter disposed in a fluid discharge conduit in fluid communication
with the annular space of the wellbore.
15. The method of claim 13 wherein the step of determining a
pressure change in the annular space of the wellbore resulting from
movement of the pipe string is a function of fluid displacement of
the pipe string in the wellbore, the fluid displacement calculated
using volumetric dimensions of the pipe string within the
wellbore.
16. The method of claim 13 wherein the empirical correction factor
is calibrated by measuring pressure proximate a bottom end portion
of the pipe string.
17. The method of claim 13 wherein all of the steps are conducted
in real time.
18. A method for determining a pressure change in wellbore fluid
pressure due to movement of a pipe string within a wellbore, the
method comprising the steps of: determining a rate of movement of a
pipe string within a wellbore; determining a pressure change in an
annular space of the wellbore resulting from movement of the pipe
string; the annular space being defined between an outer wall of
the pipe string and an inner wall of the wellbore; determining an
empirical correction factor that is at least a function of the rate
of movement of the pipe string, a surface area of the outer wall of
the pipe string and a surface area of the inner wall of the
wellbore; and correcting the determined pressure change by an
amount that is a function of the empirical correction factor.
19. The method of claim 18 wherein the empirical correction factor
is calibrated by measuring pressure proximate a bottom end portion
of the pipe string.
20. The method of claim 18 wherein all of the steps are conducted
in real time.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the benefit of U.S. Provisional
Application No. 61/450,646, filed on Mar. 9, 2011, which is
incorporated herein by reference.
BACKGROUND
[0002] The exploration for and production of hydrocarbons from
subsurface rock formations requires devices to reach and extract
the hydrocarbons from the rock formations. Such devices are
typically wellbores drilled from the Earth's surface to the
hydrocarbon-bearing rock formations in the subsurface. The
wellbores are drilled using a drilling rig. In its simplest form, a
drilling rig is a device used to support a drill bit mounted on the
end of a pipe known as a "drill string." A drill string is
typically formed from lengths of drill pipe or similar tubular
segments threadedly connected end to end. The drill string is
longitudinally supported by the drilling rig structure at the
surface, and may be rotated by devices associated with the drilling
rig such as a top drive, or kelly/kelly busing assembly. 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 toward the surface in an annular space formed between the
wellbore wall and the drill string, carrying the cuttings from the
drill bit so as to clean the wellbore. The drilling fluid is also
formulated such that the fluid pressure applied by the drilling
fluid is typically greater than the surrounding formation fluid
pressure, thereby preventing formation fluids from entering the
wellbore and the collapse of the wellbore. However, such
formulation also must provide that the hydrostatic pressure does
not exceed the pressure at which the formations exposed by the
wellbore will fail (fracture).
[0003] It is known in the art that the actual pressure exerted by
the drilling fluid ("hydrodynamic pressure") is related to its
formulation as explained above, its other rheological properties,
such as viscosity, and the rate at which the drilling fluid is
moved through the drill string into the wellbore. It is also known
in the art that, by suitable control over the discharge of drilling
fluid from the wellbore through the annular space, it is possible
to exert pressure in the annular space between the drill string and
the wellbore wall that exceeds the hydrostatic and hydrodynamic
pressures by a selected amount. There have been developed a number
of drilling systems called "dynamic annular pressure control"
(DAPC) systems that perform the foregoing fluid discharge control.
One such system is disclosed, for example, in U.S. Pat. No.
6,904,981 issued to van Riet and assigned to the assignee of the
present disclosure. 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 may be pumped
down the drilling fluid return system to maintain annulus pressure
during times when the mud pumps are turned off (and no mud is
pumped through the drill string). 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. U.S. Pat. No. 7,395,878 issued to
Reitsma et al. and assigned to the assignee of the present
disclosure describes a different form of DAPC system.
[0004] The formulation of the drilling fluid, and when used,
supplemental control over the fluid discharge such as by using a
DAPC system, are intended to provide a selected fluid pressure in
the wellbore during drilling. Such fluid pressure is, as explained
above, selected so that fluid from the pore spaces of certain
subsurface formations does not enter the wellbore, so that the
wellbore remains mechanically stable during continued drilling
operations, and so that exposed rock formations are not
hydraulically fractured or distended during drilling operations.
DAPC systems, in particular, provide increased ability to control
the fluid pressure in the wellbore during drilling operations
without the need to reformulate the drilling fluid extensively. As
explained in the patents referenced above, using DAPC systems may
also enable drilling wellbores through formations having fluid
pressures and fracture pressures such that drilling using only
formulated drilling fluid and uncontrolled fluid discharge from the
wellbore is essentially impossible.
[0005] Movement of the drill string axially along the wellbore
creates changes in the wellbore annulus fluid pressure as a result
of fluid friction effects between the outside surface of the pipe
string and the wall of the wellbore. The amount of change in
annulus fluid pressure is related to the exterior geometry of the
drill string, the geometry of the wellbore wall, the rheological
properties of the drilling fluid and the speed at which the drill
string is moved into the wellbore (sometimes called "surge"
pressure; i.e., an increase in pressure, depending on the drill
string movement rate) or is removed from the wellbore (sometimes
called "swab" pressure, i.e., a reduction in pressure, depending on
the drill string movement rate). Various techniques are known in
the art for direct calculation of surge and swab pressures;
however, the known techniques require implementation of complex
algorithms related to the geometry of the drill string and the
wellbore. Other techniques may determine the wellbore annulus
pressure proximate the bottom of the well.
[0006] There is a need for techniques to estimate, preferably in
real time, the changes in dynamic wellbore fluid pressure affected
by axial drill string movement in order to better select drilling
operating parameters for efficient drilling operations.
SUMMARY
[0007] A method according to the disclosure for determining
wellbore fluid pressure, corrected for drill string movement
effects during wellbore drilling operations, includes the step of
determining an initial annulus fluid pressure in the wellbore.
Determining the initial annulus/wellbore fluid pressure may be
accomplished in any manner known to those of skill in the art and
may include the steps of measuring a fluid flow rate into the
wellbore and/or measuring a fluid pressure in the annulus proximate
the surface. A rate of movement of a pipe string into or out of the
wellbore is also determined. The determined initial annulus fluid
pressure is then adjusted to a corrected annulus fluid pressure by
an amount that is a function of the rate of movement of the pipe
string, a surface area of the outer wall of the pipe string and a
surface area of the inner wall of the wellbore In one or more
embodiments, the annulus fluid pressure is determined and adjusted
in real time.
[0008] Other aspects and advantages of one or more embodiments of
the invention will be apparent from the following description and
the appended claims.
BRIEF DESCRIPTION OF THE DRAWINGS
[0009] FIG. 1 shows an example of a wellbore drilling unit
including a dynamic annular pressure control (DAPC) system.
[0010] FIGS. 2A and 2B show an example of calculating surge
pressure according to an embodiment of the disclosure.
[0011] FIGS. 3A and 3B shown an example of calculating swab
pressure according to an embodiment of the disclosure.
[0012] FIG. 4 shows a comparison of using the method according to
an embodiment of the disclosure for calculating an increase in
wellbore fluid pressure resulting from drill string movement into
the wellbore with prior art methods for calculating such an
increase in wellbore fluid pressure.
[0013] FIG. 5 shows a comparison of using the method according to
an embodiment of the disclosure for calculating a decrease in
wellbore fluid pressure resulting from drill string movement out of
the wellbore with prior art methods for calculating such a decrease
in wellbore fluid pressure.
DETAILED DESCRIPTION
[0014] Methods according to one or more embodiments of the
disclosure in general make use of a dynamic annular pressure
control (DAPC) system during drilling operations involving a
wellbore to adjust the fluid pressure in a wellbore annulus (i.e.,
the annular space between the wall of the wellbore and the exterior
of the drill string) to selected values that are adjusted or
corrected to account for movement of the drill string into or out
of the wellbore.
[0015] An example of a drilling unit drilling a wellbore through
subsurface rock formations, including a dynamic annular pressure
control (DAPC) system is shown schematically in FIG. 1. Operation
and details of the DAPC system may be substantially as described in
U.S. Pat. No. 7,395,878 issued to Reitsma et al. and assigned to
the assignee of the present disclosure or may be as described in
U.S. Pat. No. 6,904,981 issued to van Riet and assigned to the
assignee of the present disclosure, both incorporated herein by
reference.
[0016] The drilling system 100 includes a hoisting device known as
a drilling rig 102 that is used to support drilling operations
through subsurface rock formations, such as shown at 104. Many of
the components used on the drilling rig 102, such as a kelly (or
top drive), power tongs, slips, draw works and other equipment are
not shown for clarity of the illustration. A wellbore 106 is shown
being drilled through the rock formations 104. A drill string 112
is suspended from the drilling rig 102 and extends into the
wellbore 106, thereby forming an annular space (annulus) 115
between the wellbore wall and the drill string 112, and/or between
a casing 101 (when included in the wellbore) and the drill string
112. One of the functions of the drill string 112 is to convey a
drilling fluid 150 (shown in a storage tank or pit 136), the use of
which is for purposes as explained in the Background section
herein, to the bottom of the wellbore 106 and into the wellbore
annulus 115.
[0017] The drill string 112 supports a bottom hole assembly ("BHA")
113 proximate the lower end thereof that includes a drill bit 120,
and may include a mud motor 118, a sensor package 119, a check
valve (not shown) to prevent backflow of drilling fluid from the
annulus 115 into the drill string 112. The sensor package 119 may
be, for example, a measurement while drilling and logging while
drilling (MWD/LWD) sensor system. In particular the BHA 113 may
include a pressure transducer 116 to measure the pressure of the
drilling fluid in the annulus 115 near the bottom of the wellbore
106. The BHA 113 shown in FIG. 1 can also include a telemetry
transmitter 122 that can be used to transmit pressure measurements
made by the transducer 116, MWD/LWD measurements as well as
drilling information to be received at the surface. A data memory
including a pressure data memory may be provided at a convenient
place in the BHA 113 for temporary storage of measured pressure and
other data (e.g., MWD/LWD data) before transmission of the data
using the telemetry transmitter 122. The telemetry transmitter 122
may be, for example, a controllable valve that modulates flow of
the drilling fluid through the drill string 112 to create pressure
variations detectable at the surface. The pressure variations may
be coded to represent signals from the MWD/LWD system and the
pressure transducer 116.
[0018] The drilling fluid 150 may be stored in a reservoir 136,
which is shown in the form of a mud tank or pit. The reservoir 136
is in fluid communications with the intake of one or more mud pumps
138 that in operation pump the drilling fluid 150 through a conduit
140. An optional flow meter 152 can be provided in series with one
or more mud pumps 138, either upstream or downstream thereof. The
conduit 140 is connected to suitable pressure sealed swivels (not
shown) coupled to the uppermost segment ("joint") of the drill
string 112. During operation, the drilling fluid 150 is lifted from
the reservoir 136 by the pumps 138, is pumped through the drill
string 112 and the BHA 113 and exits the through nozzles or courses
(not shown) in the drill bit 120, where it circulates the cuttings
away from the bit 120 and returns them to the surface through the
annulus 115. The drilling fluid 150 returns to the surface and goes
through a drilling fluid discharge conduit 124 and optionally
through various surge tanks and telemetry systems (not shown) to be
returned, ultimately, to the reservoir 136.
[0019] A pressure isolating seal for the annulus 115 is provided in
the form of a rotating control head forming part of a blowout
preventer ("BOP") 142. The drill string 112 passes through the BOP
142 and its associated rotating control head. When actuated, the
rotating control head on the BOP 142 seals around the drill string
112, isolating the fluid pressure therebelow, but still enables
drill string rotation and longitudinal movement. Alternatively, a
rotating BOP (not shown) may be used for essentially the same
purpose. The pressure isolating seal forms a part of a back
pressure system (a greater portion of which is represented by
dotted box 131) used to maintain a selected fluid pressure in the
annulus 115.
[0020] As the drilling fluid returns to the surface it goes through
a side outlet below the pressure isolating seal (rotating control
head) to a back pressure system 131 configured to provide an
adjustable back pressure on the drilling fluid in the annulus 115.
The back pressure system may comprise a variable flow restrictive
device, suitably in the form of a wear resistant choke 130, which
applies a corresponding back pressure on the drilling fluid in the
annulus 115 as flow is restricted through such device. It will be
appreciated that chokes exist that are designed to operate in an
environment where the drilling fluid 150 contains substantial drill
cuttings and other solids. The choke 130 is one such type and is
further capable of operating at variable pressures, flowrates and
through multiple duty cycles.
[0021] The drilling fluid 150 exits the choke 130 and flows through
an optional flow meter 126 to be directed through an optional
degasser 1 and solids separation equipment 129. The degasser 1 and
solids separation equipment 129 are designed to remove excess gas
and other contaminants, including drill cuttings, from the drilling
fluid 150. After passing through the solids separation equipment
129, the drilling fluid 150 is returned to reservoir 136.
[0022] The flow meter 126 may be a mass-balance type or other
high-resolution flow meter. A pressure sensor 147 can be optionally
provided in the drilling fluid discharge conduit 124 upstream of
the variable flow restrictive device (e.g., the choke 130). A flow
meter, similar to flow meter 126, may be placed upstream of the
back pressure system 131 in addition to the back pressure sensor
147. A back pressure control means, e.g. preferably a programmed
computer system but which may also be a trained operator, monitor
data relevant for the annulus pressure, including data from a
pressure monitoring system 146 (i.e., pressure sensor data), and
provide control signals to at least the back pressure system 131
(and/or specifically to the back pressure pump 128) and optionally
also to the injection fluid injection system.
[0023] In general terms, the required back pressure to obtain the
desired annulus pressure proximate the bottom of the wellbore 106
can be determined by obtaining, at selected times, information on
the existing pressure of the drilling fluid in the annulus 115 in
the vicinity of the BHA 113, referred to as the bottom hole
pressure (BHP), comparing the information with a desired BHP and
using the differential between these for determining a set-point
back pressure. The set point back pressure is used for controlling
the back pressure system in order to establish a back pressure
close to the set-point back pressure. Information concerning the
fluid pressure in the annulus 115 proximate the BHA 113 may
alternatively be determined using an hydraulic model and
measurements of drilling fluid pressure as it is pumped into the
drill string and the rate at which the drilling fluid is pumped
into the drill string (e.g., using a flow meter or a "stroke
counter" typically provided with piston type mud pumps). The BHP
information thus obtained may be periodically checked and/or
calibrated using measurements made by the pressure transducer
116.
[0024] The injection fluid pressure in an injection fluid supply
143 passage represents a relatively accurate indicator for the
drilling fluid pressure in the drilling fluid gap at the depth
where the injection fluid is injected into the drilling fluid gap.
Therefore, a pressure signal generated by an injection fluid
pressure sensor anywhere in the injection fluid supply passage,
e.g., at 156, can be suitably used to provide an input signal for
controlling the back pressure system 131 (e.g., choke 130), and for
monitoring the drilling fluid pressure in the wellbore annulus
115.
[0025] The pressure signal can, if so desired, optionally be
compensated for the density of the injection fluid column and/or
for the dynamic pressure loss that may be generated in the
injection fluid between the injection fluid pressure sensor 156 in
the injection fluid supply passage and where the injection into the
drilling fluid return passage takes place 144, for instance, in
order to obtain an exact value of the injection pressure in the
drilling fluid return passage at the depth 144 where the injection
fluid is injected into the drilling fluid gap.
[0026] The pressure of the injection fluid in the injection fluid
supply passage 141 is advantageously utilized for obtaining
information relevant for determining the current bottom hole
pressure. As long as the injection fluid is being injected into the
drilling fluid return stream, the pressure of the injection fluid
at the injection depth can be assumed to be equal to the drilling
fluid pressure at the injection point 144. Thus, the pressure as
determined by the injection fluid pressure sensor 156 can
advantageously be used to generate a pressure signal for use as a
feedback signal for controlling or regulating the back pressure
system 131.
[0027] It should be noted that the change in hydrostatic
contribution to the down hole pressure that would result from a
possible variation in the injection fluid injection rate, is in
close approximation compensated by the above-described controlled
re-adjusting of the back pressure system 131 by the back pressure
control means. Thus, by controlling the back pressure system 131,
the fluid pressure in the bore hole 106 is almost independent of
the rate of injection fluid injection.
[0028] One possible way to use the pressure signal corresponding to
the injection fluid pressure, is to control the back pressure
system 131 so as to maintain the injection fluid pressure on a
certain suitable constant value throughout the drilling or
completion operation. The accuracy is increased when the injection
point 144 is in close proximity to the bottom of the bore hole
106.
[0029] When the injection point 144 is not so close to the bottom
of the wellbore 106, the magnitude of the pressure differential
over the part of the drilling fluid return passage stretching
between the injection point 144 and the bottom of the wellbore 106
is preferably established. For this situation, a hydraulic model
can be utilized as will be described below.
[0030] In one example, the pressure difference of the drilling
fluid in the drilling fluid return passage in a lower part of the
wellbore 106 extending between the injection fluid injection point
144 and the bottom of the well bore 106, can be calculated using a
hydraulic model taking into account inter alia the well geometry.
Because the hydraulic model is generally only used for calculating
the pressure differential over a relatively small section of the
wellbore 106, the precision is expected to be much better than when
the pressure differential over the entire wellbore length must be
calculated.
[0031] In this example, the back pressure system 131 can be
provided with a back pressure pump 128, in fluid communication with
the wellbore annulus 115 and the choke 130, to pressurize the
drilling fluid in the drilling fluid discharge conduit 124 upstream
of the flow restrictive device 130. The intake of the back pressure
pump 128 is connected, via conduit 119A/B, to a drilling fluid
supply which may be the reservoir 136. A stop valve 125 may be
provided in conduit 119A/B to isolate the back pressure pump 128
from the drilling fluid supply 136. Optionally, a valve 123 may be
provided to selectively isolate the back pressure pump 128 from the
drilling fluid discharge conduit 124 and choke 130.
[0032] The back pressure pump 128 can be engaged to ensure that
sufficient flow passes the choke 130 to be able to maintain
backpressure, even when there is insufficient flow coming from the
wellbore annulus 115 to maintain pressure on the choke 130.
However, in some drilling operations it may often suffice to
increase the weight of the fluid contained in the upper part 149 of
the well bore annulus by reducing the injection fluid injection
rate when the circulation rate of drilling fluid 150 via the drill
string 112 is reduced or interrupted.
[0033] The back pressure control means in the present example can
generate the control signals for the back pressure system 131,
suitably adjusting not only the variable choke 130 but also the
back pressure pump 128 and/or valve 123.
[0034] In this example, the drilling fluid reservoir 136 also
comprises a trip tank 2 in addition to the illustrated mud tank or
pit. A trip tank is normally used on a drilling rig to monitor
drilling fluid gains and losses during movement of the drill string
into and out of the wellbore 106 (known as "tripping operations").
The trip tank 2 may not be used extensively when drilling using a
multiphase fluid system involving injection of a gas into the
drilling fluid return stream, because the wellbore 106 may often
remain alive (i.e., continuously flowing) or the drilling fluid
level in the well bore 106 drops when the injection gas pressure is
bled off. However, in the present embodiment, the functionality of
the trip tank 2 is maintained, for instance, for those occasions
when a high-density drilling fluid is pumped down into
high-pressure wells.
[0035] A valve manifold system 5, 125 can be provided downstream of
the back pressure system 131 to enable selection of the reservoir
to which drilling mud returning from the wellbore 106 is directed.
In the present example, the valve manifold system 5, 125 can
include a two way valve 5, allowing drilling fluid 150 returning
from the well bore 106 to be directed to the mud pit 136 or the
trip tank 2.
[0036] The valve manifold system 5, 125 may also include a two way
valve 125 provided for either feeding drilling fluid 150 from
reservoir 136 via conduit 119A or from trip tank/reservoir 2 via
conduit 119B to backpressure pump 128, optionally provided in fluid
communication with the drilling fluid return passage 115 and the
choke 130.
[0037] In operation, valve 125 is operated to select either conduit
119A or conduit 119B and the backpressure pump 128 is engaged to
ensure sufficient flow passes the choke 130 so that backpressure on
the annulus 115 is maintained, even when there is little to no flow
coming from the annulus 115. Unlike the drilling fluid passage
inside the drill string 112, the injection fluid supply 143 passage
can preferably be dedicated to one task, which is supplying the
injection fluid for injection into the drilling fluid gap, e.g., at
injection point 144. In this way, the hydrostatic and hydrodynamic
interaction of the drilling fluid with the injection fluid can be
accurately determined and kept constant during a drilling
operation, so that the weight of the injection fluid and dynamic
pressure loss in the supply passage 141 can be accurately
established.
[0038] The description of the drilling system above with reference
to FIG. 1 is to provide an example of drilling a wellbore using a
DAPC system which can determine and maintain annulus/wellbore fluid
pressure near the bottom of the wellbore 106, i.e., the
above-described BHP, near a selected/desired value. Such DAPC
system may include a hydraulics model that, as explained above,
uses as input the rheological properties of the drilling mud/fluid
150, the rate at which the mud/fluid flows into the wellbore 106,
the wellbore and drill string configuration, pressure on the
discharge conduit 124 and if available, measurements of annulus
fluid pressure proximate the bottom of the wellbore (e.g., from
transducer 116) or proximate the surface to supplement or refine
calculations made by the hydraulics model, e.g., to determine an
initial wellbore fluid pressure.
[0039] In one or more methods according to one or more embodiments
of the invention, the DAPC system may be operated in a specific
manner to adjust the BHP for pressure changes, i.e., increases
and/or decreases, resulting from drill string movement, e.g., by
adding or subtracting the pressure increase or pressure decrease,
respectively. An increase in BHP may be created by fluid friction
in the fluid disposed in the annular space 115 in the wellbore 106
when the drill string 112 is moved into the wellbore 106. The
magnitude of the pressure increase is related to the surface area
of the annular space 115 (per unit length), the length of the drill
string 115 in the wellbore 106, the frictional and viscous
properties of the fluid, and the speed/rate at which the drill
string 112 is moved into the wellbore 106. Conversely, a decrease
in BHP may be created by fluid friction in the fluid disposed in
the annular space 115 in the wellbore 106 when the drill string 112
is moved out of the wellbore 106. The magnitude of the pressure
decrease is related to the foregoing factors as well as the rate at
which the drill string 112 is removed from the wellbore 106. The
rate of movement of a pipe string into or out of the wellbore is
determined in any manner known to those skilled in the art.
[0040] Pressure increases (and/or decreases) resulting from drill
string movement may be initially determined in real time by
measuring the increased fluid flow out of (or into) the wellbore
upon movement of the drill string. Such flow out of or into the
wellbore may be conducted, e.g., via flow meter disposed proximate
the discharge conduit 124. The pressure increases (and/or
decreases) resulting from drill string movement may alternatively
be initially determined in real time by converting the fluid
displacement (or placement), as a result of the drill string
movement into (or out of) the wellbore, into an analogous pressure
increase (or decrease), e.g., as if the fluid were being pumped.
However, such initial determinations of pressure increases (i.e.,
surge pressures) or decreases (i.e., swab pressures) do not account
for all of the factors given above that may affect the actual
pressure increases or decreases due to drill string/pipe string
movement into and out of the wellbore.
[0041] Referring to FIG. 2B, an increase in annulus fluid pressure
(i.e., a surge pressure or tripping in pressure) due to drilling
string 112 movement into the wellbore 106 is generally understood
to be related to (and/or a function of) the drilling fluid
properties, the surface area of the drill string 112 and the
wellbore 106 (per unit length) and the rate at which the drill
string 112 is moved into the wellbore 106. FIG. 2B shows the drill
string 112 being moved into the wellbore 106 through a casing 101,
which may be disposed therein was disclosed with reference to FIG.
1. Fluid flow out of the annular space 115 in the wellbore 106 may
be diverted through an outlet 124 by a rotating control head 142 or
rotating blowout preventer, as previously disclosed.
[0042] Referring now to FIG. 2A, a cross sectional view through a
portion of the drill string 112 disposed in the wellbore 106 (as
designated by the hash marks on FIG. 2B) is illustrated, and
presents the calculations that may be performed according to one or
more embodiments of the invention to determine surge pressure. The
rate at which the drill string 112 is moved into the wellbore 106
is a readily measured quantity. Such rate may be referred to as
"tripping in" speed or may also include the rate of lengthening or
rate of penetration of the formations during drilling (called
"ROP"), and is represented by V.sub.dp and the downward arrow in
FIG. 2A. The respective surface areas of the drill string 112 and
wellbore annular space 115 per unit length are functions of A.sub.2
and A.sub.1. Drilling fluid velocity, as a result of pumping or as
represented by pumping, at a position proximate the wellbore wall
is represented by V.sub.f and the upward arrow in FIG. 2A. Fluid
velocity relative to (i.e., proximate) the moving drill string 112
may be represented by V.sub.r1 (and the accompanying directional
arrow), and as will be recognized by those skilled in the art, is a
relation between V.sub.f and V.sub.dp (rarely, but sometimes, being
the sum of the these two quantities). A fluid pressure F.sub.Surge
as a result of moving the drill string 112 into the wellbore 106 is
a function of V.sub.r1 as well as the surface areas A.sub.2 and
A.sub.1 (per unit length) and may be represented by
F.sub.Surge{V.sub.r1, (A.sub.2, A.sub.1)}. An exemplary equation
for calculating F.sub.surge is presented below:
F.sub.surge=(.mu.V.sub.r1Lc.sub.1)/A.sub.p
wherein, .mu. is the fluid viscosity, V.sub.r1 is the drill string
velocity or fluid velocity relative to the drill string, L is the
length of the pipe, c.sub.1 is a constant and A.sub.p represents
the surface area of the annular space (per unit length). Those
skilled in the art will readily recognize and appreciate that the
constant is dependent on a number of fluid mechanic properties
specific to the wellbore/drilling operation and that the surface
area of the annular space (per unit length) is a readily calculated
quantity as a function of A.sub.2 and A.sub.1.
[0043] A fluid pressure F.sub.DrillOp due to the drilling operation
as a result of movement of the fluid through the drill string 112,
excepting movement of the drill string 112, is a function of
V.sub.f and the surface areas A.sub.2 and A.sub.1 (per unit length)
and may be represented by F.sub.DrillOp {V.sub.f, (A.sub.2,
A.sub.1)}. An exemplary equation for calculating F.sub.DrillOp is
presented below:
F.sub.DrillOp=(.mu.V.sub.fLc.sub.1)/A.sub.c
wherein, .mu. is the fluid viscosity, V.sub.f is the fluid
velocity, L is the length of the pipe, c.sub.1 is a constant and
A.sub.c represents the surface area of the annular space (per unit
length). Those skilled in the art will readily recognize and
appreciate that the constant is dependent on a number of fluid
mechanic properties specific to the wellbore/drilling operation and
that the surface area of the annular space (per unit length) is a
readily calculated quantity as a function of A.sub.2 and
A.sub.1.
[0044] A ratio of the fluid pressure due to movement of the drill
string 112 into the wellbore 106 with respect to the fluid pressure
due to the drilling operation (i.e., fluid movement alone) may be
used to calculate a "friction mechanism factor", f, (i.e., an
empirical correction factor) as represented by the following
equation:
f = Pressure Tripping In / Pressure Drilling Operations = F Surge {
V r 1 , ( A 2 , A 1 ) } / F DrillOp { V f , ( A 2 , A 1 ) } = ( V r
1 * A c ) / ( V f * A p ) ##EQU00001##
As is readily apparent in the above equation, the friction
mechanism factor, f, is not dependent upon the viscosity of the
fluid or a constant, as are the fluid pressures F.sub.Surge and
F.sub.DrillOp.
[0045] While a value of the friction mechanism factor may be
calculated via the above equations, the value off may also be
calibrated and/or determined, for example, by using pressure
measurements made in the annular space 115 proximate the bottom end
portion of the drill string while drilling ("pressure while
drilling" or PWD) or by observation of change in pressure in the
annular space 115 measured proximate the surface at known rates of
movement of the drill string 112 into the wellbore 106. The
friction mechanism factor is preferably calculated in real time and
used to correct the initially determined surge pressure in real
time. Experimentation has shown that an friction mechanism factor
value of about 1.2 to 1.3 adequately corrects such determined surge
pressure for any selected drill string speed into the wellbore 106.
The friction mechanism factor also corrects for other conditions in
the wellbore 106, which may affect an accurate determination of
surge pressure. Such conditions may include solids in the drilling
fluid, temperature changes with depth and changes in the geometry
of the well with depth.
[0046] Conversely, and now referring to FIGS. 3A and 3B, movement
of the drill string 112 out of the wellbore 106 may result in a
decrease in annular fluid pressure (i.e., a swab pressure or
tripping out pressure). In FIG. 3A, a surface area of the interior
of the drill string 112 per unit length may be represented by
A.sub.3, and is usually a consideration because the one-way check
valve disposed at the bottom end portion of the drill string 112
permits fluid inside the drill string 112 to flow down and out of
the drill string 112 when the drill string 112 is moved out of the
wellbore 106. A fluid pressure F.sub.Swab as a result of moving the
drill string 112 out of the wellbore 106 is a function of V.sub.r1
and the surface areas A.sub.3, A.sub.2 and A.sub.1 (per unit
length) and may be represented by F.sub.Swab{V.sub.r1, (A.sub.3,
A.sub.2, A.sub.1)}. A fluid pressure F.sub.DrillOp as a result of
movement of the fluid through the drill string 112, excepting
movement of the drill string 112 is a function of V.sub.f and the
surface areas A.sub.2 and A.sub.1 (per unit length) and may be
represented byF {V.sub.f, (A.sub.2, A.sub.1)}, just as is done for
determining a surge pressure. A ratio of the fluid pressure due to
movement of the drill string 112 out of the wellbore 106 with
respect to the fluid pressure due to drilling fluid movement alone
may also be used to calculate a "friction mechanism factor", f,
(i.e., an empirical correction factor) as represented by the
following equation:
f = Pressure Tripping Out / Pressure Drilling Operations = F Swab {
V r 1 , ( A 3 , A 2 , A 1 ) } / F DrillOp { V f , ( A 2 , A 1 ) } =
( V r 1 * A c ) / ( V f * A p ) ##EQU00002##
wherein, A.sub.p in this instance represents the surface area of
the annular space (per unit length) as a function of A.sub.3,
A.sub.2 and A.sub.1.
[0047] While a value of the friction mechanism factor may be
calculated via the above equations, the value off may also be
calibrated and/or determined, for example, by using pressure
measurements made in the annular space 115 proximate the bottom end
portion of the drill string while drilling (PWD) or by observation
of change in pressure in the annular space 115 measured proximate
the surface at known rates of movement of the drill string 112 out
of the wellbore 106. The friction mechanism factor is preferably
calculated in real time and used to correct the initially
determined swab pressure in real time. Experimentation has shown
that an friction mechanism factor value of about 1.2 to 1.3
adequately corrects such determined swab pressure for any selected
drill string speed out of the wellbore 106. The friction mechanism
factor also corrects for other conditions in the wellbore 106,
which may affect an accurate determination of surge pressure. Such
conditions may include solids in the drilling fluid, temperature
changes with depth and changes in the geometry of the well with
depth.
[0048] FIG. 4 graphically shows comparisons of surge pressures
calculated using the method according to one or more embodiments of
the invention with surge pressures calculated using several
selected techniques known in the art. The calculated/estimated
surge pressures are graphed versus running speed of the drill/pipe
string. The increase in annulus pressure (i.e., surge pressure)
with respect to drill string movement speed using a method known as
the Shell IDM method is shown at curve 20. A technique explained in
the reference by N.J. Lapeyrouse, Formulas and Calculations for
Drilling, Production and Workover (Elsevier 2002), has its
calculated increases in annulus pressure shown by curve 30. Curve
26 shows results obtained using a surge and swab calculation
technique developed by Texas A&M University, College Station,
Texas USA. Curve 28 shows increases in annulus fluid pressure
calculated using the American Petroleum Institute (API) recommended
practice 13D. The results obtained using the method according to
one or more embodiments of the invention is shown at curve 24. The
measured surge pressures using pressure measurement on the drill
string (PWD) are shown at curve 22. As illustrated in FIG. 4, such
measured surge pressures at curve 22 confirm the greater accuracy
at curve 24 of using the method of one or more embodiments of the
invention.
[0049] FIG. 5 graphically shows comparative results of using the
various methods of FIG. 4 for determining swab pressures (resulting
from movement of the drill string out of the wellbore). The
calculated/estimated swab pressures are graphed versus running
speed of the drill/pipe string. The results shown by curves 20A
through 30A correspond to the results shown in FIG. 4 for the
techniques/methods referenced by curves 20 through 30,
respectively.
[0050] In specific examples of the method according to one or more
embodiments of the invention, so called "surge" and "swab"
pressures may be calculated. Surge pressure is generally known as
the change in annulus fluid pressure resulting from movement of the
drill string into the wellbore at relatively high speeds during
"tripping in" operations, i.e., where the drill string is partially
or totally reassembled to move the lower end thereof to the bottom
of the wellbore or other position in the wellbore. Swab pressure,
conversely, is generally known as the change in annulus fluid
pressure when the drill string is partially or totally disassembled
and is correspondingly removed from the wellbore at relatively high
speeds. It is to be clearly understood, however, that the present
method is applicable to drill string movement at any speed into or
out of the wellbore, and is therefore not limited to calculation of
surge and/or swab pressures.
[0051] The foregoing examples of the present method are described
in terms of a drill string being moved into and out of a wellbore.
It is also to be understood that the invention is not limited to
use with a "drill string" as that term is ordinarily understood
(i.e., having drilling instruments proximate the bottom thereof).
For purposes of this disclosure, any type of pipe whose external
dimensions are determinable may be used with one or more methods
disclosed herein. Such pipe may be referred to generally as a "pipe
string."
[0052] One or more methods according to the invention provide an
accurate calculation of change in annulus fluid pressure at any
pipe speed into or out of a wellbore. Furthermore, the calculated
increase or decrease in fluid pressures may be used in connection
with the DAPC system, as explained with reference to FIG. 1, to
maintain a selected fluid pressure in the annular space (i.e.,
maintain the fluid pressure in the annular space near a selected
value), notwithstanding pressure changes caused by pipe movement
effects.
[0053] 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.
* * * * *