U.S. patent number RE43,199 [Application Number 12/256,740] was granted by the patent office on 2012-02-21 for arrangement and method for regulating bottom hole pressures when drilling deepwater offshore wells.
This patent grant is currently assigned to Ocean Rider Systems AS. Invention is credited to Borre Fossli.
United States Patent |
RE43,199 |
Fossli |
February 21, 2012 |
Arrangement and method for regulating bottom hole pressures when
drilling deepwater offshore wells
Abstract
An arrangement and a method to control and regulate the bottom
hole pressure in a well during subsea drilling at deep waters: The
method involves adjustment of a liquid/gas interface level in a
drilling riser up or down. The arrangement comprises a high
pressure drilling riser and a surface BOP at the upper end of the
drilling riser. The surface BOP havs a gas bleeding outlet. The
riser also comprises a BOP, with a by-pass line. The drilling riser
has an outlet at a depth below the water surface, and the outlet is
connected to a pumping system with a flow return conduit running
back to a drilling vessel/platform.
Inventors: |
Fossli; Borre (Oslo,
NO) |
Assignee: |
Ocean Rider Systems AS (Oslo,
NO)
|
Family
ID: |
33456228 |
Appl.
No.: |
12/256,740 |
Filed: |
September 10, 2002 |
PCT
Filed: |
September 10, 2002 |
PCT No.: |
PCT/NO02/00317 |
371(c)(1),(2),(4) Date: |
March 10, 2004 |
PCT
Pub. No.: |
WO03/023181 |
PCT
Pub. Date: |
March 20, 2003 |
Related U.S. Patent Documents
|
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
Issue Date |
|
|
60318391 |
Sep 10, 2001 |
|
|
|
Reissue of: |
10489236 |
Mar 10, 2004 |
7264058 |
Sep 4, 2007 |
|
|
Current U.S.
Class: |
166/367; 175/72;
166/364; 175/38; 175/25; 175/5 |
Current CPC
Class: |
E21B
21/001 (20130101); E21B 21/01 (20130101); E21B
21/08 (20130101); E21B 21/10 (20130101); E21B
21/085 (20200501) |
Current International
Class: |
E21B
17/01 (20060101) |
References Cited
[Referenced By]
U.S. Patent Documents
Foreign Patent Documents
|
|
|
|
|
|
|
0290250 |
|
Nov 1988 |
|
EP |
|
2787827 |
|
Apr 1999 |
|
FR |
|
2787827 |
|
Jun 2000 |
|
FR |
|
9918327 |
|
Apr 1999 |
|
WO |
|
Other References
NO Search Report dated Feb. 15, 2005 of Patent Application No.
PCT/NO02/00317 filed Sep. 10, 2002. cited by other.
|
Primary Examiner: Beach; Thomas A
Attorney, Agent or Firm: Vern Maine & Associates
Parent Case Text
.Iadd.RELATED APPLICATIONS.Iaddend.
.Iadd.This application is a U.S. National Phase Application of PCT
Application No. PCT/NO02/00317, filed Sep. 10, 2002, which claims
the benefit of U.S. Provisional Application No. 60/318,391, filed
Sep. 10, 2001. Each of these applications is herein incorporated in
its entirety by reference..Iaddend.
Claims
The invention claimed is:
1. A drilling system for compensating for changes in equivalent mud
circulation density (ECD) or dynamic pressure in an annulus bore in
a well resulting from drilling activities during subsea drilling at
great water-depths, comprising: a high pressure drilling riser
extending from a seafloor wellhead to near the surface; a near
surface BOP at the upper end of the drilling riser, the near
surface BOP having an upper high pressure line; a subsea outlet in
communication with the interior of the riser at a point above the
seafloor wellhead; a flow return conduit running back to the
surface; a pumping system suspended above the seafloor and
connecting said subsea outlet to said flow return conduit; a valve
adapted to isolate the riser from the pumping system; means for
converting changes in pressure in said riser to an equivalent
change in height of drilling fluid in the riser; means for
adjusting the pump rate of said pumping system according to the
difference of the height of drilling fluid in said riser and said
equivalent change in height of drilling fluid; thereby adjusting
the height of drilling fluid in the drilling riser so as to
neutralize the changes in pressure in said annulus bore created by
said drilling activities by varying the actual amount of drilling
fluid in the riser; .Iadd.and.Iaddend. a subsea shut-off device at
the sea floor, the shut off device having at least one by-pass line
providing communication between the well below the shut-off device
and the interior of the riser, the by-pass line containing at least
one shut-off valve.
2. A system according to claim 1, further comprising a gas bleeding
outlet connected to a choke line in communication with a high
pressure choke and stand pipe manifold on a drilling vessel.
3. A system according to claim 1, wherein the pumping system with
flow return line is adapted to be launched and run with the
riser.
4. A system according to claim 1, further comprising a filling line
coupled to the riser substantially below sea level and above said
subsea outlet, the filling line being adapted for filling the riser
with a gas or liquid.
5. A system according to claim 4, wherein the gas is an inert gas
for displacement of the air above the drilling fluid.
6. A system according to claim 1, further comprising a valve in the
flow return conduit, and a particle collection box in the flow
return line, the valve being adapted for opening and closing the
communication between the particle collection box and the flow
return conduit.
7. A system according to claim 6, wherein the particle collection
box is hanging underneath the pumping system and the particle
collection box has a re-circulation and jetting means for breaking
down particle size to prevent particle build up.
8. A method for compensating for equivalent mud circulation density
(ECD) or dynamic pressure increase or decrease in an annulus bore
in a well during subsea drilling at great water-depths resulting
from drilling activities, comprising the steps: maintaining the
pressure in the top of a drilling riser extending from a seafloor
wellhead to the surface at equal to or lower than atmospheric
pressure, said riser configured with a seabed BOP and bypass;
.Iadd.monitoring bottom hole pressure in the well for a change in
pressure created by drilling activities;.Iaddend. converting
.[.a.]. .Iadd.the .Iaddend.change in pressure in the well created
by drilling activities to an equivalent change in height of
drilling fluid in the riser; adjusting the pump rate of a drilling
fluid return pump suspended above the seafloor and connected at a
point above the seafloor wellhead to the drilling riser so as to
adjust the height of drilling fluid in the drilling riser by the
equivalent change in height of drilling fluid so as to neutralize
the change in pressure created by the drilling activities by
varying the actual amount of drilling fluid in the riser.
9. A method according to claim 8, wherein gas escaping from an
underground formation is separated from liquid during offshore
drilling, comprising the steps: permitting gas and drilling fluid
in a drilling riser extending from a seafloor wellhead to the
surface to form a gas/liquid interface within the drilling riser;
providing a liquid outlet below the gas/liquid interface level and
substantially above the seafloor wellhead, said outlet being
connected to a pumping system suspended above the seafloor and
hence to a return conduit, providing a gas outlet above the
gas/liquid interface level, closing a near surface BOP at the upper
end of the drilling riser.[.,.]. and pumping liquid out of the
drilling riser through the liquid outlet, whereby the drilling
riser is acting as a gas separator.
10. A method according to claim 9, wherein a flow return line
between the liquid outlet and the pumping system is adapted to
prevent free gas from entering the return conduit by having a
.[.U-shaped.]. .Iadd.V-shaped .Iaddend.loop acting as a
gas-lock.
11. A method according to claim 10, where the height of the
gas-lock can be adjusted by varying the subsea level of the pumping
system.
12. A method according to claim 9, wherein the level of the
gas/liquid interface between the drilling fluid and the gas in the
drilling riser is maintained below sea level so that the pressure
in the bottom of the well is lower than the hydrostatic pressure
exerted by seawater from sea level.
13. A method according to claim 12, wherein the drilling riser
comprises sensors for monitoring the height of the gas/liquid
interface level in the riser, the sensors being coupled to a
regulating means controlling the pump rate of the pumping system
and thereby controlling the height of the gas/liquid interface
level.
14. A method according to claim 8, said change in pressure
occurring in said riser by drilling activities comprising a change
in pressure created by the drill string being moved up or down in
the well.
15. A method according to claim 8, said change in pressure in said
drilling riser being created by circulation of drilling fluid
through the bit.
16. A method for controlling equivalent mud circulation density
(ECD) in a well during subsea drilling operations, comprising:
using a high pressure drilling riser extending from a seafloor
wellhead and subsea BOP to the surface, within which there is
drilling fluid present, there being no outside kill or choke lines
extending from the surface to the subsea BOP, said subsea BOP
configured with a bypass; maintaining the pressure in the top of
the drilling riser at equal to or lower than atmospheric pressure;
monitoring the height of drilling fluid in the riser; monitoring
bottom hole pressure in the well for a change in pressure;
calculating an equivalent change in height of drilling fluid to the
change in pressure; using a drilling fluid pump suspended above the
seafloor and connected to the riser substantially above the
seafloor wellhead and below the height of drilling fluid, adjusting
the height of drilling fluid in the riser by the equivalent change
in height of drilling fluid, thereby adjusting the drilling fluid
level in the drilling riser so as to reverse the change in the
bottom hole pressure.
17. A drilling system for controlling equivalent mud circulation
density (ECD) in a well resulting from drilling activities during
subsea drilling operations, comprising: a high pressure drilling
riser extending from a seafloor wellhead to the surface and having
a surface BOP at the upper end of the drilling riser, the surface
BOP having an upper high pressure line, there being no kill or
choke lines extending from the surface to the seafloor wellhead; a
subsea outlet in communication with the interior of the riser at a
point above the seafloor wellhead; a flow return conduit running
back to the surface; a pumping system suspended above the seafloor
and connecting the subsea outlet to the flow return conduit; a
valve adapted to isolate the riser from the pumping system; means
for monitoring the height of drilling fluid in the drilling riser;
means for sensing a change in pressure in the drilling riser; means
for converting the change in pressure in the drilling riser to an
equivalent change in height of drilling fluid in the riser; means
for adjusting the pump rate of the pumping system according to the
difference of the height of drilling fluid in the drilling riser
and the equivalent change in height; thereby adjusting the height
of drilling fluid in the drilling riser so as to neutralize the
change in pressure by varying the actual amount of drilling fluid
in the riser; and a subsea shut-off device at the sea floor; the
shut off device having at least one by-pass line providing
communication between the well below the shut-off device and the
interior of the riser, the by-pass line containing at least one
shut-off valve or pressure regulating valve.
Description
FIELD OF THE INVENTION
The present invention relates to a particular arrangement for use
when drilling oil and gas wells from offshore structures that float
on the surface of the water in depths typically greater than 500 m
above seabed. More particularly, it describes a drilling riser
system so arranged that the pressure in the bottom of an underwater
borehole can be controlled in a completely novel way, and that the
hydrocarbon pressure from the drilled formation can be handled in
an equally new and safe fashion in the riser system itself.
BACKGROUND OF THE INVENTION
This invention defines a particular novel arrangement, which can
reduce drilling costs in deep ocean and greatly improve the safe
handling of the hydrocarbon gas or liquids that may escape the
subsurface formation below seabed and then pumped from the
subsurface formation with the drilling fluid to the drilling
installation that floats on the ocean surface. By performing
drilling operations with this novel arrangement as claimed, there
is provided a complete new way of controlling the pressure in the
bottom of the well and at the same time safely and efficiently
handling hydrocarbons in the drilling riser system. The arrangement
comprises the use of prior known art but arranged so that totally
new drilling methods is achieved. By arranging the various systems
coupled to the drilling riser in this particular way, totally new
and never before used methods can be performed safely in deepwater.
The invention relates to a deep water drilling system, and more
specifically to an arrangement for use in drilling of oil/gas
wells, especially for deep water wells, preferably deeper than 500
m water-depth.
Experience from deepwater drilling operations has shown that the
subsurface formations to be drilled usually have a fracture
strength close to that of the pressure caused by a column of
seawater.
As the hole deepens the difference between the formation pore
pressure and the formation fracture pressure remains low. The low
margin dictates that frequent and multiple casing strings have to
be set in order to isolate the upper rock sections that have lower
strength from the hydraulic pressure exerted by the drilling fluid
that is used to control the larger formation pressures deeper in
the well. In addition to the static hydraulic pressure acting on
the formation from a standing column of fluid in the well bore
there are also the dynamic pressures created when circulating fluid
through the drill bit. These dynamic pressures acting on the bottom
of the hole are created when drill fluid is pumped through the
drill bit and up the annulus between the drill string and
formation. The magnitude of these forces depends on several factors
such as the rheology of the fluid, the velocity of the fluid being
pumped up the annulus, drilling speed and the characteristics of
the well bore/hole. Particularly for smaller diameter hole sizes
these additional dynamic forces become significant. Presently these
forces are controlled by drilling relatively large holes thereby
keeping the annular velocity of the drilling fluid low and by
adjusting the rheology of the drilling fluid. The formula for
calculating these dynamic pressures is stated in the following
detailed description. This new pressure seen by the formation in
the bottom of the hole caused by the drilling process is often
referred to as Equivalent Circulating Density (ECD).
In all present drilling operations to date in offshore deepwater
wells, the bottom of the well will observe the combined hydrostatic
pressure exerted by the column of fluid from the drilling vessel to
the bottom of the well, plus the additional pressures due to
circulation. A drilling riser that connects the seabed wellhead
with the drilling vessel contains this drilling fluid. The
bottom-hole pressure to overcome the formation pressure is
regulated by increasing or decreasing the density of the drilling
fluids in conventional drilling until the casing has to be set in
order to avoid fracturing the formation.
In order to safely conduct a drilling operation there has to be a
minimum of two barriers in the well. The primary barrier will be
the drilling fluid in the borehole with sufficient density to
control the formation pressure, also necessary in the event that
the drilling riser is disconnected from the wellhead. This
difference in pressure caused by the difference in density between
seawater and the drilling fluid can be substantial in deep water.
The second barrier will be the blowout preventer BOP (BOP) in case
the primary barrier is lost.
As the drilling fluid must have a specific gravity such that the
fluid remaining in the well is still heavy enough to control the
formation when the drilling marine riser is disconnected, this
creates a problem when drilling in deep waters. This is due to the
fact that the marine riser will be full of heavy mud when connected
to the sub sea blowout preventer, causing a higher bottom-hole
pressure than required for formation control. This results in the
need to set frequent casings in the upper part of the hole since
the formation cannot support the higher mudweight from the
surface.
In order to be able to drill wells with a higher density drilling
fluid than necessary, multiple casings will be installed in the
borehole for isolation of weak formation zones.
The consequences of multiple casing strings will be that each new
casing reduces the borehole diameter. Hence the top section must be
large in order to drill the well to its planned depth. This also
means that slimhole or slender wells are difficult to construct
with present methods in deeper waters.
Normally it is not possible to control the pressure from the
surface in a conventional drilling operation, due to the fact that
the well returns will flow into an open flow line at atmospheric
pressure. In order to obtain wellhead pressure control, the well
return has to be routed through a closed flow line by way of a
closed blow out preventer to a choke manifold. The advantage of
controlling bottom hole pressure by means of wellhead pressure
control is that a pressure change at the surface results in an
almost instantaneous pressure response at the bottom of the hole
when a single-phase drilling fluid is used. In general, the surface
pressure should be kept as low as possible to obtain safer working
environment for the personnel working on the rig. So, it is
preferable to control the well by changing pressures in the well
bore to the largest extent. Conventionally, this can be performed
by means of hydrostatic pressure control and friction pressure
control in the annulus.
Hydrostatic pressure control is the prime means of bottom hole
pressure control in conventional drilling. The mud weight will be
adjusted so that the well is in an overbalanced condition in the
well when no drilling fluid circulation takes place. If needed, the
mud weight/density can be changed depending on formation pressures.
However, this is a time consuming process and requires adding
chemicals and weighting materials to the drilling mud.
The other method for bottom hole pressure control is friction
pressure control. Higher circulating rates generates higher
friction pressure and consequently higher pressures in the bore
hole. A change in pump rate will result in a rapid change in the
bottom hole pressure (BHP). The disadvantage of using frictional
pressure control is that control is lost when drilling fluid
circulation is stopped. Frictional pressure loss is also limited by
the maximum pump rate, the pressure rating of the pump and by the
maximum flow through the down hole assembly.
The only reference referring to neutralization of ECD effects is
found in SPE paper LIDC/SPE 47821. Reference in this paper is made
to WO 99/18327.
All and each of the above references are hereby incorporated by
reference.
SUMMARY OF THE INVENTION
The above prior art has many disadvantages. The object of the
present invention is to avoid some or all of the disadvantages of
the prior art.
Below some aspects of the present invention will be indicated.
In one aspect the present invention in a particular combination
gives rise to new, practically feasible and safe methods of
drilling deepwater wells from floating structures. In this aspect
benefits over the prior art are achieved with improved safety. More
precisely the invention gives instructions on how to control the
hydraulic pressure exerted on the formation by the drilling fluid
at the bottom of the hole being drilled by varying the liquid level
in the drilling riser.
In another aspect the invention gives a particular benefit in well
controlled situations (kick handling) or for planned drilling of
wells with hydrostatic pressure from drilling fluid less that the
formation pressure. This can involve continuous production of
hydrocarbons from the underground formations that will be
circulated to the surface with the drilling fluid. With this novel
invention, both kick and handling of hydrocarbon gas can be safely
and effectively controlled.
In still another aspect of the invention the riser liquid level
will be lowered to a substantial depth below the sea-level with air
or gas remaining in the riser above said level.
In contrast to prior art dual gradient systems an aspect of the
present invention uses a single liquid gradient system, preferably
drilling fluid (mud and/or completion fluid), with a gas (air)
column on top.
In still another aspect the present invention has the combination
of both a surface and a subsurface pressure containment (BOP). The
present invention differs in this respect from U.S. Pat. No.
4,063,602 in that it includes the following features: a high
pressure riser with a pressure integrity high enough to withstand a
pressure equal to the maximum formation pressure expected to be
encountered in the sub surface terrain, typically 3000 psi (200
bars) or higher; the riser is terminated in both ends by a high
pressure containment system, such as a blow-out preventer; an
outlet from the riser to a subsea pump system, typically
substantially below the sea level and substantially above the
seabed, which contains a back-pressure or non-return check valve;
the sub-sea blowout preventer has an equalizing loop (by-pass) that
will balance pressure below and above a closed subsea BOP, wherein
the equalizing loop connects the subsea well with the riser; the
loop has at least one, and preferably two, surface controllable
valve(s).
There may be at least one choke line in the upper part of the
drilling riser of equal or greater pressure rating than the
drilling riser.
By incorporating the above features a well functioning system will
be achieved that can safely perform drilling operations. The
equalizing line can be used in a well control situation when and if
a large gas influx has to be circulated out of the well.
In the present invention the high pressure riser and a high
pressure drilling pipe may be so arranged between the subsea
blowout preventer and the surface blowout preventer that they can
be used as separate high pressure lines as a substitute for choke
line and kill line.
In still another aspect the present invention incorporates this
equalizing loop in combination with a lower than normal air/liquid
interface level in the riser for well control purposes. This
feature may be combined with a particular low level of drilling
fluid in the riser. The well may not be closed in at the surface
BOP while drilling with a low drilling fluid level in the riser,
since it can take too long before the large amount of air would
compress or the liquid level in the riser might not raise fast
enough to prevent a great amount of influx coming into the well if
a kick should occur. Hence, according to an aspect of the present
invention, the well is closed in at the subsea BOP. However, since
a high pressure riser with no outside kill and choke lines from the
subsea BOP to the surface is used, the bypass loop is included in
order to have the ability to circulate out a large influx past a
closed subsea BOP into the high pressure riser. If the influx is
gas, this gas can be bled off through the choke line in or under
the closed surface BOP while the liquid is being pumped up the low
riser return conduit through the low riser return outlet. This low
riser return conduit and outlet has preferably a "gas-lock" U-tube
form below the subsea return pumps, which will prevent the
substantial part of the gas from being sucked into the pump system.
If only small amount of hydrocarbon gas is present in the drilling
riser, an air/gas compressor is installed in the normal flowline on
surface, which will suck air from inside the drilling riser,
creating a pressure below that of the atmospheric pressure above
the riser. The compressor will discharge the air/gas to the burner
boom or other safe gas vents on the platform. In still another
aspect the liquid level (drilling mud) is kept relatively close to
the outlet and the gas pressure is close to atmospheric pressure,
resulting in a separation of the major part of the gas in the
riser. The riser will in this aspect of the invention become a gas
separation chamber.
In still another aspect of the invention the bypass loop in
combination with the low riser return outlet will also give rise to
many other useful and improved methods of kick, formation testing
and contingency procedures. Hence this combination is a unique
feature of the invention.
In still another aspect of the present invention, the bottom hole
pressure is regulated without the need of a closed pressure
containment element around the drill string anywhere in the system.
Pressure containment will only be required in a well control
situation or if pre-planned under-balanced drilling is being
performed. The present invention specifies how the bottom hole
pressure can be regulated during normal drilling operation and how
the ECD effects can be neutralized.
The present invention presents the unique combination of a
high-pressure riser system and a system with pressure barriers both
on surface and on seabed, which coexists with the combination of a
low level return system. The invention gives the possibility to
compensate for both pressure increases (surge) and decreases (swab)
effects from running pipe into the well or pulling pipe out of the
well, in addition to and at the same time compensate for the
dynamic pressures from the circulation process ECD . The invention
relates in this aspect to how this control will be performed.
In an aspect the present invention overcomes many disadvantages of
other attempts and meets the present needs by providing methods and
arrangements whereby the fluid-level in the high pressure riser can
be dropped below sea level and adjusted so that the hydraulic
pressure in the bottom of the hole can be controlled by measuring
and adjusting the liquid level in the riser in accordance with the
dynamic drilling process requirements. Due to the dynamic nature of
the drilling process the liquid level will not remain steady at a
determined level but will constantly be varied and adjusted by the
pumping control system. The liquid level can be anywhere between
the normal return level on the drilling vessel above the surface
BOP or at the depth of the low riser return section outlet. In this
fashion the bottom-hole pressure is controlled with the help of the
low riser return system. A pressure control system controls the
speed of the subsea mud lift pump and actively manipulates the
level in the riser so that the pressure in the bottom of the well
is controlled as required by the drilling process.
The arrangements and methods of the present invention represents in
still another aspect a new, faster and safer way of regulating and
controlling bottom hole pressures when drilling offshore oil and
gas wells. With the methods described it is possible to regulate
the pressure in the bottom of the well without changing the density
of the drilling fluid. The ability to control pressures in the
bottom of the hole and at the same time and with the same equipment
being able to contain and safely control the hydrocarbon pressure
on surface makes the present invention and riser system completely
new and unique. The combination will make the drilling process more
versatile and give room for new and improved methods for drilling
with bottom hole pressures less than pressure in the formation, as
in under-balanced drilling.
The liquid/air interface level can also be used to compensate for
friction forces in the bottom of the well while cementing casing
and also compensate for surge and swab effects when running casing
and/or drill pipe in or out of the hole while continuously
circulating at the same time. To demonstrate this, the level in the
annulus will be lower when pumping through the drill pipe and up
the annulus than it will be when there is no circulation in the
well. Similarly, the level will be higher than static when pulling
the drill bit and bottom-hole assembly out of the open hole to
compensate for the swabbing effect when pulling out of a tight
hole.
The method of varying the fluid height can also be used to increase
the bottom-hole pressure instead of increasing the mud density.
Normally as drilling takes place deeper in the formations the pore
pressure will also vary. In conventional drilling operation the
drilling mud density has to be adjusted. This is time-consuming and
expensive since additives have to be added to the entire
circulating volume. With the low riser return system (LRRS) the
density can remain the same during the entire drilling process,
thereby reducing time for the drilling operations and reducing
cost.
In contrast to the prior art, the level in the riser can be dropped
at the same time as mud-weight is increased so as to reduce the
pressure in the top of the drilled section while the bottom hole
pressure is increased. In this way it is possible to reduce the
pressure on weak formations higher up in the hole and compensate
for higher pore pressures in the bottom of the hole. Thus it is be
possible to rotate the pressure gradient line from the drilling mud
around a fixed point, for example the seabed or casing shoe.
The advantage is that if an unexpected high pressure is encountered
deep in the well, and the formation high up at the surface casing
shoe cannot support higher riser return level or higher drilling
fluid density at present return level, this can be compensated for
by dropping the level in the riser further while increasing the mud
weight. The combined effect will be a reduced pressure at the upper
casing shoe while at the same time achieving higher pressure at the
bottom of the hole without exceeding the fracture pressure below
casing.
Another example of the ability of this system is to drill severely
depleted formations without needing to turn the drilling fluid into
gas, foam or other lighter than water drilling systems. A pore
pressure of 0.7 SG (specific gravity) can be neutralized by low
liquid level with seawater of 1.03 SG. This ability gives rise to
great advantages when drilling in depleted fields, since reducing
the original formation pressure 1.10 SG to 0.7 SG by production,
can also give rise to reduced formation fracture pressure, that can
not be drilled with seawater from surface. With the present
invention the bottom-hole pressure exerted by the fluid in the well
bore can be regulated to substantially below the hydrostatic
pressure for water. With the prior art of drilling arrangements
this will require special drilling fluid systems with gases, air or
foam. With the present invention this can be achieved with simple
seawater drilling fluid systems.
However and additionally, the system can be used for creating
under-balanced conditions and to safely drill depleted formations
in a safer and more efficient way than by radically adjusting
drilling fluid density, as in conventional practice. In order to
achieve this and in order to drill safely and effectively, the
apparatus must be designed according to the present invention. The
economical savings come from the novel combination according to the
present invention.
The system can be used for conventional drilling with a surface BOP
with returns to the vessel or drilling installation as normal with
many added benefits in deepwater. The sub sea BOP can be greatly
simplified compared to prior art where there is a sub sea BOP only.
In the present invention the subsea BOP can be made smaller than
conventional since fewer casings are needed in the well. Also since
several functions, such as the annular preventer and at least one
pipe ram is moved to the surface BOP on top of the drilling riser
above sea-level, the total system is less expensive and will also
open the way for new improved well control procedures. In addition
there are no longer need for outside kill and choke lines running
from the surface to the subsea BOP as in conventional drilling
systems.
By having a surface blowout preventer on top of the drilling riser,
all hydrocarbons can safely be bled off through the drilling rig's
choke line manifold system.
Another aspect of the present invention is a loop forming a
"water/gas-lock" in the circulating system below the subsea mudlift
pump, which will prevent large amount of hydrocarbon gases from
invading into the pump return system. The height of the pump
section can easily be adjusted since it can be run on a separate
conduit, thereby adjusting the height of the water lock. By
preventing hydrocarbon gas entering the return conduit, the subsea
mud return pump will operate more efficiently, and the rate at
which the return fluid is pumped up the conduit can be controlled
more precisely.
During normal operation the drilling riser will preferably be kept
open to the atmosphere so that any vapour from hydrocarbons from
the well will be vented off in the drilling riser. An air
compressor will suck air/gas from the top of the drilling riser to
the burner boom or other safe air vents on the drilling
installation, and create a pressure below that of atmospheric
pressure in the top of the riser system. Since the pressure in the
drilling riser at the low riser return outlet line will be close to
that of atmospheric pressure and substantially below the pressure
in the pump return line, the majority of the gas will be separated
from the liquid. If large amount of gases is released from the
drilling mud in the riser, the surface BOP will have to be closed
and the gas bled off through the chokeline 58 to the choke manifold
system (not shown) on the drilling rig. A rotating head can be
installed on the surface BOP hence the riser system can be used for
continuous drilling under-balanced and gas can be handled safely by
also having stripper elements arranged in the surface BOP system.
Hence, this system can be used for under-balanced drilling purposes
and can also be used for drilling highly depleted zones without
having the need for aerated or foamed mud. This arrangement will
make the riser function as a gas knockout or first stage separator
in an under-balanced or near balance drilling situation. This can
save space topside, since the majority of gas is already separated
and the return fluid is at atmospheric pressure at surface, meaning
that the return fluid can be routed to the rig's conventional mud
gas separator or "Poor-Boy degasser" from the subsea mud lift pump.
For extreme cases the return fluid from the subsea mud return pumps
might have to be routed through the choke manifold on the drilling
rig or tender assist vessel alongside the drilling rig.
By using this novel drilling method and apparatus, great cost
savings and improved well safety can be achieved compared to
conventional drilling. The present invention will mitigate adverse
effects of the prior art and at the same time open the way for new
and never before possible operations in deeper waters.
If an under-balanced situation arises whereby the formation
pressure is greater than the pressure exerted by the drilling
fluid, and formation fluid is unexpectedly introduced into the
well-bore, then the well can be controlled immediately with the
arrangements and methods of the present invention by simply raising
the fluid level in the high pressure riser. Alternately the well
can be shut in with the subsea BOP. With the help of the by-pass
line in the subsea BOP, the influx can be circulated out of the
well and into the high pressure riser under constant bottom-hole
pressure equal to the formation pressure. The potential gas that
will separate out at the liquid/gas level (close to atmospheric
pressure) in the riser will be vented out and controlled with the
surface BOP.
The riser of the arrangements of the present invention preferably
has no kill or chokes line, which is contrary to what is normal for
most marine risers. Instead the annulus between the drill pipe and
the riser becomes the choke line and the drill pipe becomes the
kill line when needed when the subsea BOP is closed. This will
greatly increase the operator's ability to handle unexpected
pressures or other well control situations.
The arrangements and methods of the present invention, will in a
specific new way make it possible to control and regulate the
hydrostatic pressure exerted by the drilling fluid on the
subsurface formations. It will be possible to dynamically regulate
the bottom-hole pressure by lowering the level down to a depth
below sea level. Bottom-hole pressures can be changed without
changing the specific gravity of the drilling fluid. It will now be
possible to drill an entire well without changing the density of
the drilling fluid even though the formation pore-pressure is
changing. It will also be possible to regulate the bottom-hole
pressure in such a way that it can compensate for the added
pressures due to fluid friction forces acting on the borehole while
pumping and circulating drilling mud/fluids through a drill bit, up
the annulus between the open hole/casing and the drill pipe.
The invention is also particularly suitable for use with coiled
tubing apparatus and drilling operations with coiled tubing. The
present invention will also be specifically usable for creating
"underbalance" conditions where the hydraulic pressure in the well
bore is below that of the formation and below that of the seawater
hydrostatic pressure in the formation.
Hence having a distinct liquid level low in the well/riser and a
low gas pressure in the wellbore/riser that in sum balances out the
formation pressure, will not only make it possible to drill
in-balance from floating rigs, it will to the a person of skill in
the art open up a complete new set of possibilities that can not be
achieved in shallow water or on land.
Since the drilling riser can be disconnected from a closed subsea
BOP, it can be safer to drill under-balanced than from other
installations that does not have this combination. The reason also
is that the gas pressure in the riser is very low and will cause
the drill string to be "pipe heavy" at all times, excluding the
need for snubbing equipment or "pipe light" inverted slips in the
drilling operation. If pressure build up in the gas/air phase
cannot be kept low, a reduction in the riser pressure can be
achieved by closing the subsea BOP and taking the return through
the equalizing loop, thereby reducing the pressure in the riser.
This stems from the fact that the friction pressure from fluid
flowing in the reduced diameter of the equalizing loop will
increase the bottom hole pressure, hence a reduced pressure in the
drilling riser will be achieved.
The present invention specifies a solution that allows
process-controlled drilling in a safe and practical manner.
DESCRIPTION OF THE DRAWINGS
These and other aspects of the present invention will be readily
apparent to those skilled in the art from a review of the following
detailed description of a preferred embodiment in conjunction with
the accompanying drawings and claims. The drawings show in:
FIG. 1 a schematic overview of the arrangement.
FIG. 2 a schematic diagram of and partial detail of the arrangement
of FIG. 1.
FIG. 3 a schematic diagram of and partial detail of the arrangement
of FIG. 2.
FIG. 4: in schematic detail the use of a pull-in device to be used
together with the arrangement of FIG. 1.
FIG. 5 an ECD (or downhole) process control system flow chart.
FIG. 6 a diagram illustrating the benefits from the improved method
of drilling through and producing from depleted formations.
FIG. 7 a diagram illustrating the benefits the effects of the
improved methods of controlling hydraulic pressures in a well being
drilled.
DETAILED DESCRIPTION OF THE INVENTION
In the following detailed description, taken in conjunction with
the foregoing drawings, equivalent parts are given the same
reference numerals.
FIG. 1 illustrates a drilling platform 24. The drilling platform 24
can be a floating mobile drilling unit or an anchored or fixed
installation. Between the sea floor 25 and the drilling platform 24
is a high-pressure riser 6 extending, a subsea blowout preventer 4
is placed at the lower end of the riser 6 at the seabed 25, and a
surface blowout preventer 5 is connected to the upper end of the
high pressure riser 6 above or close to sealevel 59. The surface
BOP has surface kill and choke line 58, 57, which is connected to
the high pressure choke-manifold on the drilling rig (not shown).
The riser 6, does not require outside kill and choke lines
extending from subsea BOP to the surface. The subsea BOP 4 has a
smaller bypass conduit 50 (typically 1-4'' ID), which will
communicate fluid between the well bore below a closed blowout
preventer 4 and the riser 6. The by-pass line (equalizing line) 50
makes it possible to equalize between the well bore and the high
pressure riser 6 when the BOP is closed. The by-pass line 50 has at
least one, preferably two surface-controllable valves 51, 52
The blowout preventer 4 is in turn connected to a wellhead 53 on
top of a casing 27, extending down into a well.
In the high pressure riser system a low riser return system (LRRS)
riser section 2 can be placed at any location along the high
pressure riser 6, forming an integral a part of the riser.
Near the lower end of the high pressure riser 6 a riser shutoff
pressure containment element 49 is included, in order to close off
the riser and circulate the high pressure riser to clean out any
debris, gumbo or gas without changing the bottom-hole pressure in
the well. In addition it is also possible to clean the riser 6
after it is disconnected from the subsea BOP 4 without spillage to
the ocean.
Between the drilling platform/vessel 24 and the high-pressure riser
6 a riser tension system, schematically indicated by reference
number 9, is installed.
The high-pressure riser includes a remotely monitored an upper
pressure sensor 10a and a lower pressure sensor 10b. The sensor
output signals are transmitted to the vessel 24 by, e.g., a cable
20, electronically or by fiber optics, or by radio waves or
acoustic signals. The two sensors 10a and 10b measure the pressure
in the drilling fluid at two different levels. Since the distance
between the sensors 10a and 10b is predetermined, the density of
the drilling fluid can be calculated. A remotely monitored pressure
sensor 10c is also included in the subsea BOP 4, to supervise the
pressure when the subsea BOP 4 is closed.
The high pressure riser 6 is a single bore high-pressure tubular
and in contrary to traditional riser systems there is no
requirement for separate circulation lines (kill or choke lines)
along the riser, to be used for pressure control in the event oil
and gas has unexpectedly entered the borehole 26. High pressure in
the context of this invention is high enough to contain the
pressures from the subsurface formations, typically, 3000 psi (200
bars) or higher.
Included in the high pressure riser system is the low riser return
section (LRRS) 2 that can be installed anywhere along the riser
length, the placement depending on the borehole to be drilled and
the sea-water depth on the location. The riser section 2 contains a
high-pressure valve 38 of equal or greater rating than the riser 6
and which can be controlled through the rotary table on the
drilling rig.
FIG. 1 also shows a drill string 29 with a drill bit 28 installed
in the borehole. Near the bottom of the drill string 29 inside the
string is a pressure regulating valve 56. The valve 56 has the
capability to prevent U-tubing of drilling fluid into the riser 6
when the pumping stops. This valve 56 is of a type that will open
at a pre-set pressure and stay open above this pressure without
causing significant pressure loss inside the drill string once
opened with a certain flow rate through the valve.
An air compressor 70, a pump by which a pressure differential is
created or maintained by transferring a volume of air from one
region to another, is connected to the riser 6 above the surface
BOP 6. The compressor 70 is capable of providing a sub-atmospheric
pressure inside of the riser 6. Exhaust air, that may contain some
amount of hydrocarbon can be led to the burner boom or other safe
vent.
Included in the riser section 6 is an injection line 41, which runs
back to the vessel/platform 24. This line 41 has a remotely
operated valve 40 that can be controlled from the surface. The
inlet to the riser 6 from the line 41 can be anywhere on the riser
6. The line 41 can extend parallel to the lines of the low riser
return pumping system that is to be explained below.
The LRRS riser section 2 includes a drilling fluid return outlet
42a comprising at least one or more high-pressure riser outlet
valve 38 and a hydraulic connector hub 39. The hydraulic connector
hub 39 connects a low riser return pumping system 1 (FIGS. 2 and 3)
with the high-pressure riser 6.
The low riser return pumping system includes a set of drilling
fluid return pumps 7a and 7b. The pumps are connected to the
connector 39 via a gumbo/debris box 8, an LRRS mandrel 36 and a
drilling fluid return suction hose 31 with a controllable non
return valve 37. A discharge drilling fluid conduit 15 connects the
pumps 7a and 7b with the drilling fluid handling systems (not
shown) on the platform 24. As shown in FIG. 4, the top of the
drilling fluid return conduit 15 is terminated in a riser
suspension assembly 44 where a drilling fluid return outlet 42
interfaces the general drilling fluid handling system on the
platform 24.
The pump system 1 is shown in greater detail in FIG. 2.
The high-pressure valves 11a, b on the suction side of the pumps
7a, b, and high-pressure valves 14a, b and non return valves 13a, b
on the discharge side of the pumps 7a, b, controls the drilling
fluid inlet and outlet to the drilling fluid return pumps 7.
The gumbo debris box 8 includes a number of jet nozzles 22 and a
jet and flushback line 21 with valves 12 to break down particle
size in the box 8.
The LRRS mandrel 36 includes a drilling fluid inlet port 16 and a
drilling fluid pump outlet port 35. A stress taper joint 3a is
attached to either end of the LRRS mandrel 36.
As best shown in FIG. 2, the mud return pumps 7a, 7b are powered by
power umbilical 19 or by seawater lines of a hydraulic system.
The fluid path for the drilling fluid return goes from the outlet
42, though the hose 31, into the mandrel 36, out through the
drilling fluid inlet port 16 and into the gumbo box 8. The pumps
are pumping the fluid from the gumbo box 8 out through the mud pump
outlet port 35 and into the drilling fluid conduit 15 and back to
the platform 24.
A dividing block/valve 33 is installed in the LRRS mandrel 36
acting as a shut-off plug between the mud return pump suction and
discharge sides. The dividing valve/block 33 can be opened so as to
dump debris into the gumbo box 8 to empty the return conduit 15
after prolonged pump stoppage. A bypass line 69 with valves 32 can
bypass the non-return valves 13 when valve 61 is shut, making it
possible to gravity feed drilling mud from the return conduit 15
into the riser 6 for riser fill-up purposes. Hence there are three
riser fill-up possibilities, 1) From the top of the riser 2)
through injection line 41 and through bypass line 69. In this
system design the injection line 41 might also be run alongside the
return conduit and connected to the riser at valve 40 with a ROV
and /or to the bypass line 69.
The LRRS 1 is protected within a set of frame members forming a
bumper frame 23.
By controlling the output of the pumps 7a, b, the mud level 30 (the
interface between the drilling fluid and the air in the riser 6) in
the high-pressure riser 6 can be controlled and regulated. As a
consequence the pressure in the bottom hole 26 will vary and can
thus be controlled.
FIG. 3 shows in even greater detail the lower part of the pump
system 1. The level of gumbo or other debris in the gumbo debris
tank 8 is controlled by a set of level sensors 17a, b connected to
a gumbo debris control line 18 running back to the vessel or
platform 24.
Reference is now made to FIG. 4. On the platform or vessel 24 a
handling frame 43 for the discharge drilling fluid conduit 15 is
installed. The LRRS 1 is deployed into the sea by the discharge
drilling fluid conduit 15 or on cable until it reaches the
approximate depth of the LRRS riser section 2. The system can also
be run from an adjacent vessel (not shown) lying alongside the main
drilling platform 24.
A pull-in assembly will now be described referring to FIG. 4.
Attached to the end of the drilling fluid suction hose 31 is a
pull-in wire 47 operated by a heave compensated pull-in winch 48.
The pull-in wire 47 runs through a suction hose pull-in unit and a
sheave 46. The end of the suction hose 31 is pulled towards the
hydraulic connector 39 for engagement with the connector 39 by the
pull-in assembly 46, 47, 48.
The drilling fluid suction hose 31 may be made neutrally buoyant by
buoyancy elements 45.
The control system for determining the ECD and calculation of the
intended lifting or lowering of the liquid/gas interface in the
riser 6 will now be described referring to FIG. 5.
The bottom hole pressure is the sum of five components:
P.sub.bh=P.sub.hyd+P.sub.fric+P.sub.wh+P.sub.sup+P.sub.swp Where:
P.sub.bh=Bottom hole pressure P.sub.hyd=Hydrostatic pressure
P.sub.fric=Frictional pressure P.sub.wh=Well head pressure
P.sub.sup=Surge pressure due to lowering the pipe into the well
P.sub.swp=Swab pressure due to pulling the pipe out of the well
Controlling bottom hole pressure means controlling these five
components.
The Equivalent circulation Density (ECD) is the density calculated
from the bottom hole pressure P.sub.bh) .rho..sub.Egh=P.sub.bh (1)
Where: .rho..sub.E=Equivalent Circulation Density (ECD) (kg/m3)
g=Gravitational constant (m/s.sup.2) h=Total vertical depth (m)
For a Newtonian Fluid, the pressure in the annulus can be
calculated as follows assuming no wellhead pressure and no surge or
swab effect:
.rho..eta..pi. ##EQU00001##
For a Bingham fluid, the following formula is used:
.rho..eta..pi..tau. ##EQU00002## Where: .rho..sub.m=Density of
drilling fluid being used .eta.=Viscosity of drilling fluid
L.sub.1=Drillstring length Q=Flowrate of drilling fluid
D.sub.0=Diameter of wellbore d.sub.ds=Diameter of drillstring
g=Gravitational constant h=Total vertical depth .tau..sub.0=Yield
point of drilling fluid
FIG. 5 is an is an illustration of parameters used to calculate the
ECD/dynamic pressure and the height (h) of the drilling fluid in
the marine drilling riser using the low riser return and lift pump
system (LRRS).
From eq. 4 (Newtonian Fluid ), it is seen that in order to keep the
bottom hole pressure P.sub.bh) constant, an increase in flowrate
(Q) requires the hydrostatic head (h) to be reduced.
.rho..eta..pi. ##EQU00003##
The expression for calculating swab and surge pressure is not shown
in Eq. 4. However, when moving the drillstring into the hole, an
additional pressure increase (P.sub.sup) will take place due to the
swab effect. In order to compensate for this effect, the
hydrostatic head (h) and/or the flowrate (Q) would have to be
reduced.
When moving the drill string out of the hole, a pressure
(P.sub.swp) drop will take place due to the surge effect. In order
to compensate for this effect, the hydrostatic head (h) and/or the
flowrate (Q) would have to be increased.
The swab and surge effects, are as described above, a result of
drill string motion. This motion is not caused due to tripping
only, but also due to vessel motion when the drill string is not
compensated, i.e. make and break of the drill string stands.
FIG. 5 shows a flowchart to illustrate the input parameters to the
converter indicated above, for control of bottom hole pressure
(BBP) using the low return riser and lift pump system (LRRS)
described above.
Into the converter 100 a set of parameters are put. The well and
pipe dimensions 101, which are evidently known from the start, but
may vary depending on the choice of casing diameter and length as
the drilling is proceeding, the mud pump speed 102, which, e.g.,
may be measured by a sensor at each pump, pipe and draw-work
movement (direction and speed) 103, which also may be measured by a
sensor that, e.g., is placed on the draw-work main winch, and the
drilling fluid properties (viscosity, density, yield point, etc.)
104.
The parameters 101, 102, 103, 104 are entered as values into the
converter 100.
Additional parameters, such as bottom hole pressure 105, which may
be the result of readings from Measurements While Drilling (MWD)
systems, actual mud weight (density) 106 in the drilling riser,
preferably resulting from calculations based on measurements by the
sensors 10a and 10b, as explained above, etc., may also be
collected before the needed hydrostatic head (level of interface
between drilling fluid and air) (h) to gain the intended bottom
hole pressure is calculated.
The needed hydrostatic head (h) is input to a comparator/regulator
108
The fluid level (h') in the riser is continuously measured and this
parameter 107 is compared with the calculated hydrostatic head (h)
in the comparator/regulator 108. The difference between these two
parameters is used by the comparator/regulator 108 to calculate the
needed increase or decrease of pump speed and to generate signals
109 for the pumps to achieve an appropriate flow rate that will
result in a hydrostatic head (h).
The above input and calculations may take place continuously or
intermittently to ensure an acceptable hydrostatic head at all
times.
Referring to FIGS. 6 and 7 some effects of the present invention on
the pressure will be explained. In the figures the vertical axis is
the depth from sea level, with increasing depth downward in the
diagrams. The horizontal axis is the pressure. At the left hand
side the pressure is atmospheric pressure and increasing to the
right.
In FIG. 7 the line 303 is the hydrostatic pressure gradient of
seawater. The line 306 is the estimated pore pressure gradient of
the formation. In conventional drilling the mud weight gradient 305
indicates that a casing 310 have to be set in order to stay in
between the expected pore pressure and the formation strength--the
formation strength at this point being indicated by reference
number 309--at the bottom of the last casing 315. If drilling with
an arrangement and method according to the present invention, the
gradient of the mud can be higher, as indicated by the line 310,
which means that one can drill deeper.
If however, the pore pressure, indicated by 312, at some point
should exceed the expected pressure, indicated by 311, a kick could
occur. With the method of present invention the level can be
dropped further, down to 302 and the mud weight further increased.
The net result is a pressure decrease at the casing shoe 309 with
an increase in pressure near the bottom of the hole, as indicated
by 307, making it possible to drill further before having to set a
casing.
In this way it is possible to reduce the pressure on weak
formations higher up in the hole and compensate for higher pore
pressures in the bottom of the hole. Thus it is possible to rotate
the pressure gradient line from the drilling mud around a fixed
point, for example the seabed or a casing shoe.
Another example of the ability of this system is shown in FIG. 6.
In this situation a severely depleted formation 210 is to be
drilled. The formation has been depleted from a pressure at 205 at
which it was possible to drill using a drilling fluid slightly
heavier than seawater (1,03 SG) as drilling fluid, with a pressure
gradient shown at 203. The fracture gradient of the depleted
formation is now reduced to 211, which is lower than the pressure
gradient of seawater from the surface, as indicated by the line
201.
With the present invention drilling can be done without needing
reduce the density of the drilling fluid substantially and having
to turn the drilling fluid into gas, foam or other lighter than
water drilling systems, as shown by the pressure gradient 214.
By introducing an air column in the upper part of the riser the
upper level of the drilling fluid can be dropped down to a level
202. Ea the case shown a drilling fluid with the same pressure
gradient as seawater 201 can be used, but starting at a
substantially lower point, as shown by 202.
A pore pressured of 0,7 SG can be neutralized by low liquid level
with seawater of 1,03 SG as shown by 202. This ability gives rise
to great advantages when drilling in depleted fields, since
reducing the original formation pressure of 1,10 SG at 205 to 0,7
SG at 210 by production, can also give rise to reduced formation
fracture pressure, shown at 211, that can not be drilled with
seawater from surface, as shown by 201. With the present invention
the bottom-hole pressure exerted by the fluid in the well bore can
be regulated to substantially below the hydrostatic pressure for
water. With the prior art of drilling arrangements this will
require special drilling fluid systems with gases, air or foam.
With the present invention this can be achieved with a simple
seawater drilling fluid system.
It should be apparent that many changes may be made in the various
parts of the invention without departing from the spirit and scope
of the invention and the detailed embodiments are not to be
considered limiting but have been shown by illustration only. Other
variations will no doubt occur to those skilled in the art upon the
study of the detailed description and drawings contained herein.
Accordingly, it is to be understood that the present invention is
not limited to the specific embodiments described herein, but
should be deemed to extend to the subject matter defined by the
appended claims, including all fair equivalents thereof.
* * * * *