U.S. patent application number 14/753343 was filed with the patent office on 2015-12-31 for multiphase drilling systems and methods.
The applicant listed for this patent is Lubrizol Oilfield Solutions, Inc.. Invention is credited to Stuart D. BUTLER, Keith K. CORB, Gregg M. JOLLYMORE, Daniel G. POMERLEAU, Robert T. STAYSKO.
Application Number | 20150376964 14/753343 |
Document ID | / |
Family ID | 41669338 |
Filed Date | 2015-12-31 |
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United States Patent
Application |
20150376964 |
Kind Code |
A1 |
POMERLEAU; Daniel G. ; et
al. |
December 31, 2015 |
MULTIPHASE DRILLING SYSTEMS AND METHODS
Abstract
In one embodiment, a method for drilling a wellbore includes
injecting drilling fluid through a drill string disposed in the
wellbore and rotating a drill bit disposed on a bottom of the drill
string. The drilling fluid includes a liquid and a gas. The
drilling fluid is injected at the surface. The drilling fluid exits
the drill bit and carries cuttings from the drill bit. The drilling
fluid and cuttings (returns) flow to the surface via an annulus
formed between the drill string and the wellbore. The liquid is
injected at a rate so that a liquid velocity of the returns in the
annulus is sufficient to transport the cuttings. The method further
includes drilling through at least a portion of a non-productive
formation.
Inventors: |
POMERLEAU; Daniel G.;
(Calgary, CA) ; CORB; Keith K.; (Calgary, CA)
; BUTLER; Stuart D.; (Calgary, CA) ; STAYSKO;
Robert T.; (Calgary, CA) ; JOLLYMORE; Gregg M.;
(Cochrane, CA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Lubrizol Oilfield Solutions, Inc. |
Wickliffe |
OH |
US |
|
|
Family ID: |
41669338 |
Appl. No.: |
14/753343 |
Filed: |
June 29, 2015 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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12541242 |
Aug 14, 2009 |
9097085 |
|
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14753343 |
|
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61159176 |
Mar 11, 2009 |
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61089456 |
Aug 15, 2008 |
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Current U.S.
Class: |
175/69 |
Current CPC
Class: |
E21B 4/02 20130101; E21B
21/08 20130101; E21B 21/14 20130101; C09K 8/38 20130101; E21B 7/00
20130101; E21B 3/04 20130101; E21B 21/16 20130101; E21B 21/067
20130101 |
International
Class: |
E21B 21/16 20060101
E21B021/16; C09K 8/38 20060101 C09K008/38; E21B 4/02 20060101
E21B004/02; E21B 3/04 20060101 E21B003/04; E21B 7/00 20060101
E21B007/00; E21B 21/06 20060101 E21B021/06 |
Claims
1. A method for drilling a wellbore, comprising: injecting drilling
fluid through a drill string disposed in the wellbore; rotating a
drill bit disposed at a bottom of the drill string, wherein: the
drilling fluid comprises a liquid and a gas; the drilling fluid is
injected at the surface; the drilling fluid exits the drill bit and
carries cuttings from the drill bit; the drilling fluid and
cuttings (returns) flow to the surface via an annulus formed
between the drill string and the wellbore; and the liquid is
injected at a rate so that a liquid velocity of the returns in the
annulus is sufficient to transport the cuttings; and drilling
through at least a portion of a non-productive formation with the
drill bit.
2. The method of claim 1, wherein an injection rate of the gas is
controlled so that an equivalent circulating density (ECD) of the
drilling fluid is less than a pore equivalent mud density (EMD) of
the formation and greater than a stability EMD of the
formation.
3. The method of claim 1, wherein an equivalent circulating density
(ECD) of the drilling fluid is substantially equal to a stability
equivalent mud density (EMD) of the formation.
4. The method of claim 1, wherein an injection rate of the gas is
controlled so that an equivalent circulating density (ECD) of the
drilling fluid is substantially less than a pore equivalent mud
density (EMD) of the formation.
5. The method of claim 4, wherein the ECD is less than or equal to
two-thirds of the pore EMD.
6. The method of claim 4, wherein the ECD is less than or equal to
one-half of the pore EMD.
7. The method of claim 1, wherein an injection rate of the gas is
controlled to maximize rate of penetration.
8. The method of claim 1, wherein a liquid volume fraction of the
drilling fluid at standard temperature and pressure is less than or
equal to 0.07 and greater than or equal to 0.01.
9. The method of claim 1, wherein the drilling fluid is
hydrostatically dominated.
10. The method of claim 1, wherein the liquid is a base oil.
11. The method of claim 10, wherein the drilling fluid further
comprises water emulsified in the base oil.
12. The method of claim 11, wherein the drilling fluid further
comprises organophillic clay.
13. The method of claim 11, wherein the drilling fluid further
comprises a metal halide.
14. The method of claim 11, wherein the drilling fluid further
comprises a polymer prill.
15. The method of claim 1, wherein the gas has an oxygen
concentration less than the oxygen concentration sufficient for
combustion.
16. The method of claim 15, wherein the gas is substantially pure
nitrogen.
17. The method of claim 16, further comprising generating the
nitrogen at the surface using air.
18. The method of claim 1, wherein the drill string comprises a mud
motor and wherein the drill bit is rotated by the mud motor.
19. The method of claim 1, wherein a bottom of the wellbore is at a
depth distal from a productive formation.
20. The method of claim 1, wherein a rotating control device (RCD)
engages an outer surface of the drill string at the surface and
wherein the RCD diverts the returns from the annulus to an outlet
line.
21. The method of claim 20, wherein a separator is in fluid
communication with the outlet line and wherein the separator
separates gas from the returns.
22. The method of claim 21, further comprising: flaring the
separated gas; and processing remaining returns using a solids
shaker.
23. The method of claim 22, wherein a variable choke is in fluid
communication with the outlet line.
24. The method of claim 21, further comprising recycling a portion
of the separated gas.
25. A method for drilling a wellbore, comprising: injecting
drilling fluid through a drill string disposed in the wellbore;
rotating a drill bit disposed on a bottom of the drill string,
wherein: the drilling fluid comprises a liquid and a gas; the
drilling fluid is injected at the surface; the drilling fluid exits
the drill bit and carries cuttings from the drill bit; the drilling
fluid and cuttings (returns) flow to the surface via an annulus
formed between the drill string and the wellbore; and a liquid
volume fraction of the drilling fluid at standard temperature and
pressure is greater than or equal to 0.01; and drilling through at
least a portion of a non-productive formation with the drill
bit.
26. The method of claim 25, wherein an injection rate of the gas is
controlled so that a velocity of the drilling fluid is equal to or
greater than a slip velocity of the cuttings.
Description
CLAIM OF PRIORITY UNDER 35 U.S.C. .sctn.119
[0001] This application is a continuation of U.S. patent
application Ser. No. 12/541,242, filed Aug. 14, 2009, which claims
benefit of U.S. Prov. Pat. App. No. 61/159,176, filed Mar. 11,
2009, and U.S. Prov. Pat. App. No. 61/089,456, filed Aug. 15, 2008,
all of which are herein incorporated by reference in their
entireties.
BACKGROUND OF THE INVENTION
[0002] 1. Field of the Invention
[0003] The present invention relates to multiphase drilling systems
and methods.
[0004] 2. Description of the Related Art
[0005] Drilling a wellbore typically requires circulating a
drilling fluid to flush the bore of cuttings produced by action of
a rotating drill bit. The drilling fluid may be pumped down the
well inside the drill string and through the bit and jetted into
the cutting face where it assists in penetrating the fractures
created by the bit, lifting the bit fractured chips by penetrating
the fractures and hydraulically lifting the chips into the
circulating fluid stream. The drilling fluid then carries the chips
up the lower annulus formed between an outer surface of the drill
string and a wall of the wellbore. The drilling fluid and chips or
returns continue up the upper annulus formed between a casing or
lining and the drill string and to the surface where the chips are
separated from the fluid. The cleaned fluid is then reintroduced to
the well completing the circulation cycle. The drilling fluid may
also cool the drill bit and support the wall of the wellbore.
[0006] Deploying a drilling rig to a wellsite is an expensive task.
Oil and gas companies are constantly searching for ways to reduce
time spent by the drilling rig at the wellsite. The rig time
includes time spent drilling/tripping and non-productive time. The
time spent drilling may be reduced by increasing a rate of
penetration (ROP) of the drill bit through the rock formations,
especially non-productive formations between the surface and the
deeper hydrocarbon-bearing formations.
[0007] Primary factors which govern ROP include: bit type, weight
on bit (WOB), rotary speed of the bit, formation characteristics,
and a bottom hole pressure (BHP) exerted by the returns on the
formation being drilled. The BHP includes a static component
generated by the hydrostatic fluid column weight and a dynamic
component generated by hydraulic drag due to naturally occurring
resistance to flow through the annulus. The influence of BHP on the
ROP is often discussed in terms of chip hold down effect. An
increase in BHP tends to compact the rock formation being drilled,
artificially increasing the shear strength of the rock and tending
to hold rock chips created by the bit in place (chip hold down
effect) thereby forcing re-drilling/re-fracturing of previously
drilled rock and reducing the ROP. An increase in BHP also
increases downtime by shortening the life of the bit, thereby
requiring more frequent replacement or tripping of the drill
bit.
[0008] To increase the ROP, drillers in many hard rock drilling
areas have turned to using air for drilling fluid. As compared to
conventional drilling mud, typically oil or water based, the
density is reduced by orders of magnitude, thereby greatly reducing
BHP, improving ROP and extending the life of the drill bit.
However, air drilling is limited to select geological formations,
which are consolidated with minimal water influx and do not produce
hydrogen sulfide. Therefore, there exists a need in the art for a
method of drilling a wellbore that increases ROP, improves the life
of the drill bit, and does not suffer from the limitations of air
drilling.
SUMMARY OF THE INVENTION
[0009] In one embodiment, a method for drilling a wellbore includes
injecting drilling fluid through a drill string disposed in the
wellbore and rotating a drill bit disposed on a bottom of the drill
string. The drilling fluid includes a liquid and a gas. The
drilling fluid is injected at the surface. The drilling fluid exits
the drill bit and carries cuttings from the drill bit. The drilling
fluid and cuttings (returns) flow to the surface via an annulus
formed between the drill string and the wellbore. The liquid is
injected at a rate so that a liquid velocity of the returns in the
annulus is sufficient to transport the cuttings. The method further
includes drilling through at least a portion of a non-productive
formation.
[0010] In another embodiment, a method for drilling a wellbore
includes injecting drilling fluid through a drill string disposed
in the wellbore and rotating a drill bit disposed on a bottom of
the drill string. The drilling fluid includes a liquid and a gas.
The drilling fluid is injected at the surface. The drilling fluid
exits the drill bit and carries cuttings from the drill bit. The
drilling fluid and cuttings (returns) flow to the surface via an
annulus formed between the drill string and the wellbore. A liquid
volume fraction of the drilling fluid at standard temperature and
pressure is greater than or equal to 0.01. The method further
includes drilling through at least a portion of a non-productive
formation.
BRIEF DESCRIPTION OF THE DRAWINGS
[0011] So that the manner in which the above recited features of
the present invention can be understood in detail, a more
particular description of the invention, briefly summarized above,
may be had by reference to embodiments, some of which are
illustrated in the appended drawings. It is to be noted, however,
that the appended drawings illustrate only typical embodiments of
this invention and are therefore not to be considered limiting of
its scope, for the invention may admit to other equally effective
embodiments.
[0012] FIG. 1A is a flow diagram of a drilling system, according to
one embodiment of the present invention. FIG. 1B is a cross-section
of a wellbore being drilled with the drilling system.
[0013] FIG. 2 illustrates a pressure profile comparing an
embodiment of the present invention with prior art drilling
systems. FIG. 2A illustrates controlling injection rates based on
formation changes.
[0014] FIG. 3 is a cross-section of an actual wellbore partially
drilled with a method, according to another embodiment of the
present invention. FIG. 3A is a table illustrating intervals of the
wellbore drilled with conventional methods and embodiments of the
present invention. FIG. 3B is a table illustrating intervals of
other wellbores in the same field drilled with embodiments of the
present invention. FIG. 3C is a table illustrating motors used with
embodiments of the present invention. FIG. 3D illustrates ROPs of
similar intervals in the same field air drilled.
[0015] FIG. 4 is a cross-section of an actual wellbore partially
drilled with a method, according to another embodiment of the
present invention. FIG. 4A is a table of intervals of the wellbore
drilled with conventional methods and embodiments of the present
invention. FIG. 4B is a table of some of the geological formations
traversed by the wellbore. FIG. 4C is a table illustrating
intervals of other wellbores in the same field drilled with
embodiments of the present invention. FIG. 4D is a table
illustrating motors used with embodiments of the present
invention.
[0016] FIG. 5 is a cross-section of an actual wellbore partially
drilled with a method, according to another embodiment of the
present invention. FIG. 5A is a table of intervals of the wellbore
drilled with conventional methods and embodiments of the present
invention. FIG. 5B is a table of geological formations traversed by
the wellbore. FIG. 5C is a table illustrating an interval of
another wellbore in the same field drilled with an embodiment of
the present invention. FIG. 5D is a table illustrating motors used
with embodiments of the present invention.
[0017] FIGS. 6A-6H are tables illustrating simulated annulus
profiles of drilling a wellbore while varying gas injection rate
and liquid/mud injection rate, according to other embodiments of
the present invention.
[0018] FIG. 7 is a flow diagram of a drilling system, according to
another embodiment of the present invention.
DETAILED DESCRIPTION
[0019] FIG. 1A is a flow diagram of a drilling system 1, according
to one embodiment of the present invention. FIG. 1B is a
cross-section of a wellbore 100 being drilled using the drilling
system 1. The drilling system 1 may be deployed on land or
offshore. The drilling system 1 may include a drilling rig (not
shown) used to support drilling operations. The drilling rig may
include a derrick supported from a support structure having a rig
floor or platform on which drilling operators may work. Many of the
components used on the rig, such as a Kelly and rotary table or top
drive, power tongs, slips, draw works and other equipment, are not
shown for ease of depiction. A wellbore 100 has already been
partially drilled, casing 115 set and cemented 120 into place. The
casing string 115 extends from the surface 105 of the wellbore 100
where a wellhead 40 is typically located. Drilling fluid 145f may
be injected through a drill string 135 deployed in the
wellbore.
[0020] The drilling fluid 145f may be a mixture and may include a
first fluid which is a gas 145g (see FIG. 2A) at standard
temperature and pressure (STP, 60.degree. F., 14.7 psia) and a
second fluid which is a liquid 145l (see FIG. 2A) at STP. The
mixture may be heterogeneous (i.e., insoluble) or homogenous (i.e.,
a solution) and may vary in properties (i.e., density and/or
phases) in response to temperature and/or pressure. The liquid 145l
may be water, glycerol, glycol, or base oil, such as kerosene,
diesel, mineral oil, fuel oil, vegetable ester, linear alpha
olefin, internal olefin, linear paraffin, crude oil, or
combinations thereof. The gas 145g may be any gas having an oxygen
concentration less than the oxygen concentration sufficient for
combustion (i.e., eight percent), such as nitrogen, natural gas, or
carbon dioxide. The nitrogen may be generated at the surface using
a nitrogen production unit (NPU) 20 which may generate
substantially pure (i.e., greater than or equal to ninety-five
percent pure) nitrogen. Alternatively, the nitrogen may be
delivered from cryogenic bottles or bulk tanks. The gas 145g may be
a mixture of gases, such as exhaust gas from the rig's prime mover
or fuel-gas driven compressors or a mixture of nitrogen, natural
gas, and/or carbon dioxide.
[0021] The liquid 145l may be mud (have solids suspended and/or
dissolved therein). The mud may be oil-based and may have water
emulsified therein (invert emulsion). The solids may include an
organophilic clay, lignite, and/or asphalt. The base oil may be
viscosified. Alternatively, the mud may be water-based. The solids
may be dissolved in the liquid, forming a solution, such as brine.
The dissolved solids may include metal halides, such as potassium,
cesium, or calcium salts or mixtures thereof; or formates, such as
cesium, sodium, potassium, lithium, or mixtures thereof. The brine
may further include silicates, amines, oils, such as distillated
hydrocarbons, olefins, or paraffins. The brine may further include
hydration and dispersion inhibiting polymers, such as polyanionic
cellulose (PAC), partially hydrolyzed polyacrylamide (PHPA),
partially hydrolyzed polyacylanitrile (PH-PAN) fluids).
[0022] Alternatively, the mud may be glycol based as discussed in
U.S. Pat. No. 6,291,405, which is hereby incorporated by reference
in its entirety. The glycol-based mud may include a water-miscible
glycol, with a molecular weight of less than about two hundred,
such as ethylene glycol, diethylene glycol, triethylene glycol,
propylene glycol, butylene glycol and mixtures thereof, at a
concentration: of at least 70%, 70% to 100%, 80% to 100%, or 85% to
100%, (by volume); water, not in excess of 30% by volume; a salt or
salts selected from the group consisting of sodium chloride,
potassium chloride, magnesium chloride, calcium chloride, sodium
bromide, calcium bromide, potassium acetate, potassium formate and
choline chloride at a concentration greater than 50,000 mg/liter of
water in the mud; an anti-sticking additive at a concentration of
greater than 0.5% by weight of the mud; a filtration control agent
for lowering fluid loss of the drilling fluid; a viscosifier for
suspension of solids and weighting material in the drilling fluid,
such as glycol-soluble gums, polymers or gels, or with rod-like
clays such as attapulgite or sepiolite; and weighting material,
such as barite, iron oxide, dolomite, calcium carbonate or soluble
salts.
[0023] Alternatively, the mud may be an oil in water emulsion as
discussed in U.S. Pat. No. 4,411,801, which is hereby incorporated
by reference in its entirety. The mud may include an emulsifying
amount of an emulsifier, such as one or more surfactants, such as
three surfactants in equal parts, such as polyoxyethylene glycol
five hundred mono-tallate which is, generally, the mono esters of
tall oil fatty acids and mixed polyoxyethelene diols having an
average polymer length of about four hundred fifty to five hundred
fifty oxyethylene (EtO) units, a nonyl pheno ethoxylate containing
about 43% by weight EtO groups, and a nonyl phenol ethoxylate
containing 65% by weight EtO groups; a liquid hydrocarbon coating
agent, being present in an amount of at least about 5% or 5% to 35%
by volume of the mud, such as light crude oil, certain napthas,
kerosene, fuel oil, gas oil, light lubricating oil, coal oil,
diesel, light shale oil, pure or mixed liquid aliphatic
hydrocarbons, or mixtures thereof; an aqueous medium, such as water
or brine, such as sodium chloride solutions, calcium chloride
solutions, potassium chloride solutions, calcium sulfate solutions,
or a mixture of such solutions, present in amounts of about 0.5
lbs/gal (ppg) to saturation (2.5 lbs/gal); a viscosifier, such as
starches or starch derivatives, such as converted starches;
water-dispersible cellulose derivatives; polysaccharide gums,
carboxyalkyl cellulose ethers, hydroxyalkyl cellulose ethers,
carboxymethyl starch, or xanthomonas (xanthan) gum (XC polymer)
galactomannan gums present in amounts of from about 0.005 to about
0.02 ppg; a filtration control agent, such as processed starch with
biocide, carboxymethyl cellulose, or pre-gelatinized starch,
present in amounts of from about 0.05 to about 0.25 ppg; and a pH
control agent, such as a caustic, such as KOH and MgO to achieve a
pH of the mud, such as eight to twelve or ten.
[0024] Additionally, if the liquid portion 145l is oil or oil
based, one or more solid hydrophilic polymer prills may be added to
the drilling fluid. If water from an exposed formation should enter
the annulus, the prill will absorb the water and swell up, thereby
facilitating removal from the returns by the solids shaker.
[0025] Additionally, the drilling fluid may have properties which
are not normally acceptable in conventional drilling, parameters,
such as viscosity reduced to a level where the fluid could be
weighted up quickly in the event that the well requires hydrostatic
control, relatively low density, and filtration rate not controlled
and tending to be substantially higher than that used in
conventional operations.
[0026] Alternatively, the liquid portion 145l may be pure base oil,
pure water, brine, or water treated with a shale stabilizer, such
as Dionic, NCL-100, or cc300kf (without viscosity additives).
[0027] The liquid portion 145l of the drilling fluid 145f may be
stored in a reservoir, such as one or more tanks 5 or pits. The
tanks 5 may be in fluid communication with one or more rig pumps 10
which pump the liquid 145l portion through an outlet conduit 12,
such as pipe. The outlet pipe 12 may be in fluid communication with
a nitrogen outlet line 27 and a standpipe 28.
[0028] The gas portion 145g of the drilling fluid 145f may be
produced by one or more of the NPUs 20. Each NPU 20 may be in fluid
communication with one or more air compressors 22. The compressors
22 may receive ambient air and discharge compressed air to the NPUs
20. The NPUs 20 may each include a cooler, a demister, a heater,
one or more particulate filters, and one or more membranes. The
membranes may include hollow fibers which allow oxygen and water
vapor to permeate a wall of the fiber and conduct nitrogen through
the fiber. An oxygen probe (not shown) may monitor and assure that
the produced nitrogen meets a predetermined purity. One or more
booster compressors 25 may be in fluid communication with the NPUs
20. The boosters 25 may compress the nitrogen exiting the NPUs 20
to achieve a predetermined injection or standpipe pressure. The
boosters 25 may be positive displacement type, such as
reciprocating or screw, or turbomachine type, such as
centrifugal.
[0029] A pressure sensor (PI), temperature sensor (TI), and flow
meter (FM) may be installed in the nitrogen outlet 27 and in data
communication with a surface controller (SC, not shown). The SC may
monitor the flow rate of the nitrogen and adjust the air
compressors and/or booster compressors to maintain a predetermined
flow rate. Additionally, the SC may monitor a speed of the pump 10
and adjust a speed of the pump 10 to maintain a predetermined flow
rate. Additionally, the outlet 12 may include a FM in communication
with the SC.
[0030] The liquid 145l portion and gas 145g portion may be
commingled at the junction 32 of the outlet lines, thereby forming
the drilling fluid 145f. The drilling fluid 145f may flow through
the standpipe 28 and into the drill string 135 via a swivel (Kelly
or top drive). The drilling fluid 145f may be pumped down through
the drill string 135 and exit the drill bit 140, where the fluid
may circulate the cuttings away from the bit 140 and return the
cuttings up an annulus 110 defined between an inner surface of the
casing 115 or wellbore 100 and an outer surface of the drill string
135. The return mixture (returns) 145r may return to the surface
105 and be diverted through an outlet of a rotating control device
(RCD) 15 and into a primary returns line (PRL) 29. Alternatively,
the drilling fluid may be pumped into the annulus and return
through the drill string (aka reverse circulation).
[0031] The RCD 15 may provide an annular seal around the drill
string 135 during drilling and while adding or removing (i.e.,
during a tripping operation to change a worn bit) segments or
stands to/from the drill string 135. The RCD 15 achieves fluid
isolation by packing off around the drill string 135. The RCD 15
may include a pressure containing housing mounted on the wellhead
40 where one or more packer elements are supported between bearings
and isolated by mechanical seals. The RCD 15 may be the active type
or the passive type. The active type RCD uses external hydraulic
pressure to activate the packer elements. The sealing pressure is
normally increased as the annulus pressure increases. The passive
type RCD uses a mechanical seal with the sealing action
supplemented by wellbore pressure. If the drillstring 135 is coiled
tubing or other non-jointed tubular, a stripper or pack-off
elements (not shown) may be used instead of the RCD 15. One or more
blowout preventers (BOPs) 16-18 may be attached to the wellhead 40.
If the RCD is the active type, it may be in communication with
and/or controlled by the SC. The RCD 15 may include a bleed off
line to vent the wellbore pressure when the RCD is inactive. A
bleed line 54 may be included for removing the RCD 15 for
servicing.
[0032] A PI may be installed in the PRL 29 and in data
communication with the SC. Additionally, a TI (not shown) may be
installed. One or more control valves or variable choke valves 30
may be disposed in the PRL 29. The choke 30 may be in communication
with the SC and fortified to operate in an environment where the
returns 145r contain substantial drill cuttings and other solids.
The choke 30 may be fully open or bypassed during normal drilling
and present only to allow the SC to control backpressure exerted on
the annulus 110 should a kick occur. Alternatively, the choke 30
may be employed during normal drilling to exert a predetermined
back pressure on the annulus to vary bottom hole pressure
independent of the liquid 145l and gas 145g injection rates.
[0033] The drill string 135 may include a drill bit 140 disposed on
a longitudinal end thereof. The drill string 135 may be made up of
joints or segments of drill pipe, casing, or liner threaded
together or coiled tubing. The drill string 135 may also include a
bottom hole assembly (BHA) (not shown) that may include the bit
140, drill collars, a mud motor, a bent sub, measurement while
drilling (MWD) sensors, logging while drilling (LWD) sensors and/or
a check or float valve (to prevent backflow of fluid from the
annulus). The mud motor may be a positive displacement type (i.e.,
a Moineau motor) or a turbomachine type (i.e., a mud turbine). The
drill string 135 may further include float valves distributed
therealong, such as one in every thirty joints or ten stands, to
maintain backpressure on the returns while adding joints thereto.
The drill bit 140 may be rotated from the surface by the rotary
table or top drive and/or downhole by the mud motor. If a bent sub
and mud motor is included in the BHA, slide drilling may be
effected by only the mud motor rotating the drill bit and rotary or
straight drilling may be effected by rotating the drill string from
the surface slowly while the mud motor rotates the drill bit.
Alternatively, if the drill string 135 is coiled tubing, the BHA
may include an orienter to switch between rotary and slide
drilling. If the drill string 135 is casing or liner, the liner or
casing may be suspended in the wellbore 100 and cemented after
drilling.
[0034] The returns 145r may then be processed by a separator 35.
The separator 35 may be a four-phase horizontal separator. An oil
outlet 35o and a water outlet 35w in communication with respective
compartments of the separator 35 may conduct the liquid portion of
the returns 145r to a solids shaker 60. A sparge pump 55 may
deliver a predetermined quantity of the liquid portion 145l of the
drilling fluid 145f from the mud tanks 5 to the solids compartment
of the separator 35 to flush cuttings. The cuttings slurry may be
discharged to the shaker via a solids line 35s. The recombined
liquid 145l and solids may flow through a combined outlet to a
solids shaker 60. Additionally, the separator 35 may include a
level sensor (not shown) in data communication with the SC for
detecting the liquid/mud level in the separator. Additionally, an
FM (not shown) may be disposed in the water 35w and oil outlets 35o
and in fluid communication with the SC.
[0035] The separator 35 may further include a gas outlet 35g to a
flare 45 or gas recovery line. The gas outlet line 35g may include
a FM in data communication with the SC to measure the flow rate of
returned gas. The gas outlet line may further include an adjustable
control valve or choke 37 in communication with the SC which may be
used to control pressure in the separator and/or to control back
pressure exerted on the annulus 110 if erosion of the choke 30
becomes a problem. A pressure relief line 35f may include a
pressure relief valve in communication with the gas compartment of
the separator 35 and lead to the flare 45.
[0036] Alternatively, the separator 35 may be a vertical separator
or a cyclonic separator and may separate two or more phases. For
example, a two-phase separator may be used to separate gas and then
the remaining liquid and cuttings may be discharged to a solids
shaker. Alternatively, the remaining liquid and cuttings may
instead be discharged to a second, lower pressure separator. The
lower pressure separator may be a three-phase separator (gas,
liquid, and solids/slurry) from which the gas may vent to a second
flare or cold vent, the liquids may be discharged to the mud tank,
and the solids/slurry may be discharged to a shaker.
[0037] The solids shaker 60 may remove heavy solids from the liquid
portion 145l and may discharge the removed solids to a solids bin
(not shown). An outlet line of the shaker 60 may lead to a first of
the tanks 5. An outlet of the first tank 5 may feed a centrifuge 65
which may remove fine solids from the liquid 145l and discharge the
removed fines to the bin. Additionally, the solids bin may include
a load cell (not shown) in data communication with the SC. An
outlet line of the centrifuge 65 may discharge the liquid portion
145l into a second one of the mud tanks 5.
[0038] A bypass line 53 may be included to provide the option of
closing the PRL 29 and bypassing the choke 30 and the separator 35.
The bypass line 53 may lead directly to the solids shaker 50. The
bypass line 53 may be used to return to conventional overbalanced
drilling in the event that the wellbore becomes unstable (i.e., a
kick or an unstable formation). One or more secondary lines 51 may
be provided to allow circulation in the event that one or more of
the BOPs 16-18 are closed. The secondary lines 51 may include one
or more chokes 41 and lead to a degasser 42.
[0039] One or more fuel, such as propane, natural gas, or methane,
tanks 45f may be provided to maintain ignition in the flare 45. The
fuel 45f may be a liquid in the tanks and vaporized in a pilot line
45p to the flare 45 by a vaporizer 45v.
[0040] If the drill string 135 is made up of jointed drill pipe or
casing, joints periodically need to be added to the drill string.
Injection of the drilling fluid 145f may be halted to add a joint.
The standpipe 28 may be vented and the float valves may close to
prevent backflow of returns through the drill string 135. The choke
30 may be closed to prevent loss of the dynamic BHP due to halting
circulation of the drilling fluid. Alternatively, only injection of
the gas portion 145g may be halted and injection of the liquid
portion 145l may instead be diverted from the standpipe to a kill
line 13 and into one of the chokes 30,41 so that the choke 30,41
may compensate for the loss of dynamic BHP. Alternatively,
injection of the drilling fluid 145f may be diverted into the kill
line 13 and through the choke 30 to compensate for the loss of the
BHP. Alternatively, a continuous circulation system or continuous
flow subs may be used to maintain circulation while adding joints
to the drill string 135. Alternatively, a safety factor may be
utilized or the formation may be stable so that loss of the dynamic
BHP is not a concern and no attempt to maintain or compensate for
loss of dynamic BHP is necessary.
[0041] Stands may have to be removed or added if the drill string
135 has to be removed or tripped to change the drill bit 140.
During adding or removing stands, the NPUs 20 may be shut down so
that only the liquid 145l is injected through the drill string 135.
For shutdown of the NPUs 20 and/or to prevent overpressure of the
compressors 22, 25, a bleed line 52 may include a branch 52s to the
separator and a branch 52t to the mud tanks 5 and a vent line 56
may lead to atmosphere. The circulation may be continued until the
annulus 110 is filled to a predetermined level, such as partially,
substantially, or completely, with the liquid/mud. Once the annulus
110 is filled to the predetermined level, circulation may be halted
by shutting the rig pumps 10 down. The predetermined level may be
selected so that the exposed formations are near-balanced or
overbalanced. If a stand is being removed, the liquid 145l may be
added via the kill line 13 to maintain the liquid level in the
annulus. Alternatively, if the density of the liquid is
insufficient for overbalancing the exposed formation(s), a higher
density liquid may be used to overbalance the exposed formation(s).
This higher density liquid/mud may be premixed in a kill tank (not
shown) or may be formed by adding weighting agents to the
liquid.
[0042] Various shutoff valves (i.e., gate or ball valves), and
check valves are shown. The shutoff valves may be in communication
with the SC so that they are opened or closed by the SC.
[0043] Alternatively, a dual concentric drill string may be used
instead of the drill string 135. A concentric drill string may be
particularly useful for delicate formations, such as tar sand
formations or coal bed methane formations. A suitable concentric
tubular string is illustrated in FIGS. 3A and 3B of International
Patent Application Pub. WO 2007/092956 (Atty. Dock. No.
WEAT/0730-PCT, hereinafter '956 PCT), which is herein incorporated
by reference in its entirety. The concentric drill string may
include joints assembled together. Each joint may include an outer
tubular having a longitudinal bore therethrough and an inner
tubular having a longitudinal bore there through. The inner tubular
may be mounted within the outer tubular. An annulus may be formed
between the inner and outer tubulars. Drilling fluid may be
injected through the annulus formed between the tubulars and return
to the surface via the inner tubular bore or vice versa. The
delicate formations may then be spared from exposure to the
drilling fluid and the returns.
[0044] Alternatively, an eccentric dual drill string may be used
instead of the concentric dual drill string. A suitable eccentric
drill string is illustrated in FIGS. 5A-5E of the '956 PCT. A
partition is formed in a wall of each joint and divides an interior
of the drill string into two flow paths. A box is provided at a
first longitudinal end of the joint and the pin is provided at the
second longitudinal end of the joint. A face of one of the pin and
box has a groove formed therein which receives a gasket. The face
of one of the pin and box may have an enlarged partition to ensure
a seal over a certain angle .alpha.. This angle .alpha. allows for
some thread slippage. The outer layer of insulation illustrated in
the '956 PCT may be omitted.
[0045] FIG. 2 illustrates a pressure profile comparing an
embodiment of the present invention with prior art drilling
systems. FIG. 2A illustrates controlling injection rates based on
formation changes.
[0046] As typical, the formations exposed to the wellbore 100
exhibit a pore gradient 200p and a fracture gradient 200f. For
analytical convenience, the formation pressure gradients 200f,p are
often converted to an equivalent mud density (EMD) and a bottomhole
pressure gradient of the returns is converted to an equivalent
circulating density (ECD). Conventional overbalanced drilling 245o
uses mud having a density so that the pressure exerted by the
returns 245o on the exposed formations is within a window defined
between the pore 200p and fracture 200f gradients. Some formations
also exhibit a stability gradient 200s. If the ECD of the returns
is less than the stability gradient 200s, the wellbore 100 may
collapse. As discussed above and illustrated, air drilling 245a is
unsuitable for these formations that exhibit a stability gradient
200s due to the negligible hydrostatic contribution of air to the
ECD of the returns 245a. Note, air drilling 245a may be suitable to
drill the wellbore 100 to depth D1 as the exposed formations do not
exhibit the stability gradient 200s. Also, as typical, casing or
liner strings 115s,i are set at or near depths D1, D2 where changes
in the pore 200p and/or fracture 200f gradients occur so that the
bottomhole pressure exerted by the overbalanced returns 245o
(greater than the pore pressure at bottomhole) does not fracture a
formation at a shallower depth.
[0047] The injection rates of the gas portion 145g and the liquid
145l portion of the drilling fluid 145f may be controlled so that
an ECD of the returns 145r is substantially less than the pore EMD
200p in order to maximize the ROP. For example, the ECD of the
returns 145r may be less than or equal two-thirds, one-half, or
one-third the pore EMD 200p. For formations exhibiting a stability
gradient 200s, the injection rates may be controlled to achieve an
ECD 145r equal to or slightly greater than the stability EMD 200s.
Maintaining the ECD slightly greater than the stability EMD 200s
provides a safety factor against wellbore collapse and will
tolerate minor BHP fluctuations, such as those created while adding
joints or stands to the drill string 135.
[0048] At depth D2, the liquid rate 145l may be substantially
decreased and the gas rate 145g may be substantially increased due
to a change in hole size resulting from setting of the intermediate
casing 115i (note, due to the relative scaling of the injection
rates, the decrease in liquid rate is somewhat obscured). The
increase in gas injection rate 145g may be necessary to maintain
the ECD 145r substantially equal to the stability EMD 200s. At
depth D3, a gas kick is experienced, the gas rate 145g may be
reduced correspondingly to a rate that the formation gas enters the
annulus 110 to maintain a constant ECD 145r. When a gas kick is
encountered during conventional overbalanced drilling, drilling is
halted and one of the BOPs 16,18 is closed. The choke 41 is used to
exert back pressure on the annulus to restore the overbalanced
condition. The formation gas is circulated from the wellbore and
the density of the drilling mud is increased to restore the
overbalanced condition (without the choke). The sequence of steps
varies depending on which method (Driller's or Engineer's) is
employed. Once the heavier mud has filled the annulus, drilling may
continue. In contrast, the RCD 15 and the separator 35 of the
drilling system 1 allow drilling to continue through a kick
unabated and without a substantial change in ECD, thereby
maintaining the ROP.
[0049] At depth D4, a formation irregularity, such as sloughing
rock, causes an increase in the stability gradient. The gas rate
145g may be correspondingly reduced so that the ECD 145r is
maintained at or above the increased stability gradient (by the
safety factor). Note, that even after the irregularity is passed,
the ECD 145r may still be maintained at the increased level to
prevent collapse of the irregularity even when the irregularity is
no longer at bottomhole. The method may be halted at depth D5 due
to the beginning of a productive formation (the formations above
depth D5 may be nonproductive).
[0050] Advantageously, controlling the ECD of the returns 145r to
be substantially less than the pore EMD 200p may also eliminate the
need to set one or more of the casing strings 115i,s as sensitivity
to changes in the pore and/or fracture EMDs 200p,f is substantially
reduced or eliminated.
[0051] A liquid volume fraction (LVF) of the drilling fluid may
range from 0.01 to 0.07 or 0.01 to 0.025 at STP or be greater than
or equal to 0.01 at STP. The injection rates may be controlled to
achieve an ECD at a top of an exposed formation or at total depth,
such as 100 to 1,000 kg/m3, 200 to 700 kg/m3, or 250 to 1,000
kg/m3. However, for wellbores with serious stability issues or
substantial gas potential, the ECD may be increased, such as to
1,200, 1,300, 1,500, or 2,000 kg/m3. Alternatively, the injection
rates may be controlled to achieve a predefined LVF at total depth,
such as greater than 0.5. Alternatively, the injection rates may be
controlled so that a first flow regime (discussed below) is
maintained in a lower portion of the annulus, such as along the
BHA, and a second flow regime is maintained in an upper portion of
the annulus, such as from an upper end of the BHA to at or near the
surface.
[0052] Alternatively, the injection rates may be controlled to
achieve an ECD equal to, substantially equal to, or slightly
greater than the pore EMD of the exposed formation. For example, in
certain unstable formations, the stability EMD may be proximate to
the pore EMD. In these instances, to maintain the ECD substantially
equal to the stability EMD, the ECD may need to be greater than the
pore EMD.
[0053] FIG. 3 is a cross-section of an actual wellbore 300
partially drilled with a method, according to another embodiment of
the present invention. FIG. 3A is a table illustrating intervals of
the wellbore 300 drilled with conventional methods and an
embodiment of the present invention. FIG. 3B is a table
illustrating intervals of other wellbores in the same field drilled
with embodiments of the present invention. FIG. 3C is a table
illustrating motors used with embodiments of the present
invention.
[0054] A conductor interval (not shown) was pre-drilled from
surface 105 and conductor casing (not shown) was pre-installed. A
first interval 320 of the wellbore was air drilled. A surface
casing 115s was run-in and cemented into the wellbore 300. A second
interval 330 was drilled according to an embodiment of the present
invention. In this embodiment, the liquid portion 145l of the
drilling fluid was an invert-emulsion oil based mud having a
density of 950 kg/m3. The gas portion 145g of the drilling fluid
145f was nitrogen. The gas injection rate 145g during drilling
ranged between 80-100 m3/min and the liquid rate 145l was 2.4
m3/min so that the ECD ranged between 600-700 kg/m3. A staging gas
rate was used to transition from zero injection once drilling fluid
has ceased, due for example to adding a joint or stand to the drill
string, to the full drilling gas injection rate. A mud motor was
used in the BHA of the drill string. The second interval 330 was
stopped before encountering a formation having potential for
hydrogen sulfide (a.k.a. sour gas).
[0055] A third interval 340 of the wellbore was drilled
conventionally overbalanced. An intermediate casing 115i was then
run-in and cemented into the wellbore 300. A fourth interval 350 of
the wellbore 300 was drilled according to an embodiment of the
present invention. In this embodiment, the mud may have been the
same mud used as the second interval 330 and a mud motor was also
employed. The gas injection was rate was the same as for the
interval 330 and the liquid rate ranged between 1.4-1.6 m3/min so
that the ECD ranged between 600-700 kg/m3. As discussed above, the
reduction in liquid rate is attributable to the reduction in hole
size. The fourth interval 350 was drilled to a depth past the
kick-off point (KOP) 306. The fourth interval 350 was stopped
before encountering a formation having a potential for swelling. A
fifth interval 370 was drilled conventionally overbalanced. A
production liner 115l was run-in and hung from the intermediate
casing 115i using a liner hanger and packer 305. The production
liner 115l was then cemented into the wellbore 300. A sixth
interval 370 of the wellbore to total depth and including the
horizontal production section was drilled using a calcium carbonate
polymer mud and overbalanced due to a potential for sour gas.
[0056] Intervals 380 and 390 were drilled using embodiments of the
present invention for other wellbores in the same field. The mud
used may have been the same as that used for interval 330.
[0057] FIG. 3D illustrates ROPs of similar intervals 330a, b in the
same field air drilled. The intervals 330a,b were drilled at about
the same depth as the interval 330. The ROP for interval 330 was
about ten m/hr and the ROPs for the intervals 330a,b were about
fifteen and nineteen m/hr, respectively. While not exceeding the
ROP of air drilling, the interval 330 is significantly higher than
conventional overbalanced drilling and approaching the ROP achieved
by air drilling. Further, switching from air to conventional
overbalanced drilling for later sections requires a transition time
(i.e., filling the wellbore with mud and switching drill bits)
which is not a disability of one or more embodiments of the present
invention.
[0058] FIG. 4 is a cross-section of an actual wellbore 400
partially drilled with a method, according to another embodiment of
the present invention. FIG. 4A is a table of intervals of the
wellbore 400 drilled with conventional methods and embodiments of
the present invention. FIG. 4C is a table illustrating intervals of
other wellbores in the same field drilled with embodiments of the
present invention. FIG. 4D is a table illustrating motors used with
embodiments of the present invention.
[0059] A conductor interval (not shown) was pre-drilled from
surface 105 and conductor casing (not shown) was pre-installed. A
first interval 420 of the wellbore was drilled overbalanced using a
gel-slurry mud. A surface casing 115s was run-in and cemented into
the wellbore 400. A second interval 430 was drilled, according to
an embodiment of the present invention. In this embodiment, the
liquid 145l portion of the drilling fluid was an invert-emulsion
mineral oil based mud having a density of 900 kg/m3. The liquid
portion 145l of the drilling fluid also had a viscosity equal to
50-55 sec/L, a plastic viscosity less than 12 MPa-s, a yield point
equal to 1-2 Pa, a high pressure high temperature (HPHT) filtration
equal to 10-15 CC/30 min, an activity (Aw) equal to 0.45-0.48, and
an oil-to-water ratio equal to 95/5 percent. The gas portion 145g
of the drilling fluid was nitrogen. The gas injection rate 145g
during drilling was from 50-80 m3/min and the liquid rate 145l
ranged between 1.2-1.5 m3/min so that the ECD was about 300 kg/m3.
The second interval 430 was stopped to install intermediate casing
115i. A third interval 440 of the wellbore to total depth and
including the horizontal production section was drilled
underbalanced.
[0060] FIG. 4B is a table of some of the geological formations
traversed by the wellbore. The table also illustrates the pore
pressure at the top of the formation, and the EMD derived from the
pore pressure.
[0061] Intervals 450 and 460 were drilled using embodiments of the
present invention for other wellbores in the same field. The mud
used may have been the same as that used for interval 430.
[0062] FIG. 5 is a cross-section of an actual wellbore 500
partially drilled with a method, according to another embodiment of
the present invention. FIG. 5A is a table illustrating intervals of
the wellbore 500 drilled with conventional methods and embodiments
of the present invention. FIG. 5B is a table of geological
formations traversed by the wellbore. FIG. 5C is a table
illustrating an interval of another wellbore in the same field
drilled with an embodiment of the present invention. FIG. 5D is a
table illustrating motors used with embodiments of the present
invention.
[0063] A conductor interval (not shown) was pre-drilled from
surface 105 and conductor casing (not shown) was pre-installed. A
first interval 520 of the wellbore was air drilled. The first
interval was stopped due to expected fault zones. A second interval
530 was drilled conventionally overbalanced. A surface casing 115s
was run-in and cemented into the wellbore 500. A third interval 540
was drilled according to an embodiment of the present invention. In
this embodiment, the liquid 145l portion of the drilling fluid 145f
was an invert-emulsion oil based mud having a density of 850 kg/m3.
The liquid portion 145l of the drilling fluid 145f also had a
viscosity equal to 40 sec/L, a plastic viscosity less than 12
MPa-s, a yield point equal to 1-1.5 Pa, an Aw equal to 0.50, an
oil-to-water ratio equal to 95/5 percent, and an electrical
stability greater than 500 volts. The gas portion 145g of the
drilling fluid was nitrogen. The gas injection rate 145g during
drilling ranged between 40-95 m3/min and the liquid rate 145l
ranged between 2.24-2.6 m3/min so that the ECD was about 600 kg/m3.
The third interval 540 was stopped due to intersection with an
aquifer.
[0064] A fourth interval 550 of the wellbore was drilled
conventionally overbalanced. An intermediate casing 115i was then
run-in and cemented into the wellbore 500. A fifth interval 560 of
the wellbore 500 was drilled according to an embodiment of the
present invention. In this embodiment, the liquid 145l portion of
the drilling fluid 145f was an invert-emulsion oil based mud having
a density of 850 kg/m3 The liquid portion 145l of the drilling
fluid 145f also had a viscosity equal to 40 sec/L, a plastic
viscosity less than 12 MPa-s, a yield point equal to 1.5-3.0 Pa, an
Aw equal to 0.50, an oil-to-water ratio equal to 95/5 percent, a
chloride concentration of 300k-340k mg/L, and an electrical
stability greater than 500 volts. The gas portion 145g of the
drilling fluid 145f was nitrogen. The gas injection rate 145g
during drilling ranged between 40-95 m3/min and the liquid rate
145l ranged between 2.24-2.6 m3/min so that the ECD was about 600
kg/m3. The fifth interval 560 was drilled to a depth past the
kick-off point (KOP) 506 and through a hard and abrasive rock
(i.e., sandstone) Formation J. The ROP of was about ten m/hr
through the interval 560. The expected ROP for a conventional
overbalanced drilling method of this formation is about one to two
m/hr.
[0065] The fifth interval 560 was stopped before encountering a
formation having a potential for swelling. A sixth interval 570 was
drilled conventionally overbalanced. A production liner 115l was
run-in and hung from the intermediate casing 115i using a liner
hanger and packer 405. The production liner 115l was then cemented
into the wellbore 500. A seventh interval 580 of the wellbore to
total depth and including the horizontal production section was
drilled using a formate mud and overbalanced due to a potential for
sour gas.
[0066] Interval 590 was drilled using an embodiment of the present
invention for another wellbore in the same field. The mud used may
have been the same as that used for interval 540.
[0067] FIGS. 3-5 also illustrate grouping of the formations by
productivity. As used herein, the term productive formation means a
formation containing hydrocarbon reserves having a net present
value equaling or exceeding the capital investment required to
drill and complete the formation. Conversely, the term
non-productive formation includes formations having nuisance
quantities of hydrocarbon reserves, usually natural gas. One or
more embodiments discussed herein may be employed to drill at least
a portion of a non-productive formation, one non-productive
formation, and/or multiple non-productive formations.
[0068] FIGS. 6A-6H are tables illustrating simulated annulus
profiles of drilling a wellbore while varying gas injection rate
and liquid/mud injection rate, according to other embodiments of
the present invention.
[0069] To select the liquid rate 145l, a minimum liquid rate may be
first selected to achieve a minimum annular velocity to transport
the cuttings from the bit. Bit size may be a primary factor in this
determination. Once the minimum velocity is selected, ECDs may be
modeled using liquid rates greater than or equal to the minimum
rate and varying gas rates. If a motor is used to rotate the bit,
equivalent liquid velocities (ELVs) may also be calculated and
minimum ELV and maximum ELV may be used as a boundary. The target
gradient window may be defined including a minimum, such as the
stability gradient and a maximum, such as a predetermined ratio
above the stability gradient. Once all of the boundaries are set,
the liquid and gas rates may be selected.
[0070] Alternatively, the liquid and gas rates may be selected so
that a velocity of the drilling fluid 145f equals or exceeds the
slip velocity of the cuttings generated at the bit. The gas portion
145g may tend to reduce the viscosity of the drilling fluid 145f
relative to the viscosity of the liquid portion 145l. The degree of
viscosity reduction may be controlled by the gas rate which may
increase the shear rate and therefore decrease the viscosity of
Bingham/Power-Law fluids. The effect on Newtonian fluids may be
less. The increased velocity afforded by adding the gas portion
145g may readily compensate for the loss of viscosity.
[0071] The simulations include gas injection rates of 100, 110,
120, and 150 m3/min at STP. For each gas injection rate, the liquid
injection rate is simulated at 2100 and 2400 l/min (2.1 and 2.4
m3/min). For each simulation, the liquid is plain water and the gas
is nitrogen. Each simulation is conducted for an identical
wellbore. The simulations illustrate annulus pressure profile,
annulus temperature profile, a liquid volume fraction (LVF), gas
velocity, liquid velocity, flow pattern or regime, hydrostatic
head, friction loss, and ECD at total depth. Also illustrated are
gas and liquid transit times, liquid holdup, and motor equivalent
liquid velocity (ELV). The ECDs range from about 400 to about 600
kg/m3. As simulated, the annulus flow regime is bubble flow for a
lower portion of the annulus and slug flow for an upper portion of
the annulus (with a return to bubble flow or annular-mist at the
surface). In one example, the flow LVF at total depth ranges from
about 0.58 to about 0.75. The injection LVFs at STP (calculated
from nominal injection rates) range from 0.0138 to 0.0234. Pressure
drop in the annulus is hydrostatically dominated or substantially
hydrostatically dominated.
[0072] Two or more annulus flow regimes, such as bubble, slug,
transition (froth), annular-mist, turbulent (LVF is equal to or
substantially equal to one), or laminar (LVF is equal to or
substantially equal to one) may be experienced in the annulus for a
vertical or substantially vertical interval. Two or more annulus
flow regimes, such as stratified, wave, elongated bubble, slug,
annular-mist, dispersed bubble (froth), turbulent (LVF is equal to
or substantially equal to one), or laminar (LVF is equal to or
substantially equal to one) may be experienced in the annulus for a
horizontal or substantially horizontal interval. While the
liquid/gas injection ratios may be selected to maximize ROP,
hydraulic impact and horsepower at the bit, the resultant flow
regimes may be adjusted by minor variation in gas/liquid injection
ratio and by variation in surface choke pressure.
[0073] Advantageously, the drilling fluid 145f may be variable in
form as the fluid proceeds through the wellbore 100. Initially,
this form may include a highly compressed mixture as the drilling
fluid moves down the drill string 135, through the bit 140, and by
the BHA. The drilling fluid 145f may then expand as the returns
145r flow up the annulus 110 as the gas 145g may become the primary
phase, thereby creating high fluid velocity. This high velocity may
effectively transport cuttings up the annulus 110 and out of the
wellbore 100.
[0074] Due to the gas portion 145g, the drilling fluid 145f, even
when highly compressed may still be a relatively low viscosity, low
density, and high filtration mixture as compared to conventional
mud. The combination of these parameters has resulted in rates of
excavation increasing by as much as an order of magnitude over
conventional overbalanced drilling systems. Conventional
overbalanced drilling systems cannot maintain such high ROPs as the
cuttings removal rates would not be sufficient to prevent the
cuttings from choking the annulus. The exceptional circulating
properties of the drilling fluid 145f may overcome the limitations
of conventional mud systems by providing exceptionally high fluid
velocities in the annulus and thus removing the cuttings at a rate
high enough to prevent the buildup of cuttings in the annulus.
Further, the use of the drilling fluid 145f may reduce or eliminate
cuttings beds in directional intervals due to the high degree of
fluid turbulence which may be present in the annulus. Such an
increase in ROP may substantially reduce the cost of a drilling
campaign.
[0075] An unexpected result was achieved during field trials: no
wellbore erosion occurred in the annulus. Extremely high
circulation rates of fluids, be they gas or liquid, involving
significant pressure losses between two surfaces may result in a
destabilization of the wellbore due to this pressure loss. In
conventional mud drilling, annular velocities are controlled in the
area of highest pressure drop; which is the narrowest point in the
annulus typically located next to the drilling collars, to ensure
that erosion of the wellbore does not occur. If the circulating
fluid is in laminar flow, then the boundary layer may be such that
erosion potential will be limited. However, if the flow is
turbulent, then the energy may not be smoothly dissipated across
the flow and the effect of erosion can be substantial. During the
tried embodiments, high turbulent annulus flow velocities were
achieved around the drill collars and no erosion occurred. To
verify wellbore integrity, a caliper log was run on one interval
drilled with one of the tried embodiments and the results showed a
well to have a near perfect gage from beginning to end of the
excavation except over a very short interval where a producing
hydrocarbon zone was allowed to discharge into the well while
drilling operations continued unabated.
[0076] The liquid portion 145l may have low viscosity and high
filtrate parameters to further enhance ROP while at the same
providing enhanced wellbore stability; as measured by caliper
logging technology and increased hole cleaning performance. In a
multiphase transitional flow regime fluid optimization of hydraulic
impact and hydraulic horsepower is more readily achieved without
the dangers of hole erosion.
[0077] FIG. 7 is a flow diagram of a drilling system 700, according
to another embodiment of the present invention. Comparing to FIG.
1A, the lines 52,52s,52t, the flare pilot 45f,45v,45p, and the
separator relief 35f have been removed for clarity. A recycle line
727 has been added. The recycle line 727 may include a primary
compressor 722, a booster compressor 725, instruments TI, PI, and
FM, a shut-off valve, and a check valve. The recycle line 727 may
conduct gas discharged from the separator 35 to the compressors
722,725 which may re-pressurize the gas and inject the recycled gas
into the gas outlet 27. The recycled gas may mix with the NPU
nitrogen to form the gas portion 145g of the drilling fluid. The SC
may be in communication with the compressors 722,725 and
instrumentation to control the flow rate of recycled gas into the
outlet 27, such as by controlling the speed of the compressors
722,725 or by further including a flow control valve (not shown) in
the recycle line 727. The SC may vent excess gas to the flare by
controlling the choke 37. The SC may reduce the nitrogen produced
by the NPU 20 accordingly.
[0078] The recycle line 727 may further include a hydrocarbon
sensor and a hydrogen sulfide sensor in communication with the SC.
Upon detection of sour gas, the SC may shut down the compressors
722,725 and close a solenoid operated shut-off valve (not shown),
thereby venting the sour gas to the flare 45. Upon detection of
sweet gas, the SC may still recycle the nitrogen/sweet gas mixture.
The SC may calculate the flow rate of the sweet/sour gas by
performing a mass balance.
[0079] Advantageously, injection of recycled gas may conserve
energy otherwise used to drive the NPU 20. Further, recycling the
gas may further reduce the required capacity of the NPU 20, thereby
reducing the footprint of the drilling system 700.
[0080] While the foregoing is directed to embodiments of the
present invention, other and further embodiments of the invention
may be devised without departing from the basic scope thereof, and
the scope thereof is determined by the claims that follow.
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