U.S. patent number 3,799,268 [Application Number 05/186,994] was granted by the patent office on 1974-03-26 for method and apparatus for evacuating drilling fluids from a well.
This patent grant is currently assigned to Brown Oil Tools, Inc.. Invention is credited to Chudleigh B. Cochran.
United States Patent |
3,799,268 |
Cochran |
March 26, 1974 |
METHOD AND APPARATUS FOR EVACUATING DRILLING FLUIDS FROM A WELL
Abstract
A method of evacuating drilling fluids from between axially
spaced well packers in which a circulating joint is disposed
between the packer in a tubing string penetrating both packers.
Pressure is applied to the tubing string to unblock circulating
ports through the joint, allowing circulation into the area between
packers and out of the well through a shorter tubing string
penetrating only the upper packer. After circulation, pressure is
applied to the long string causing the joint ports to be closed.
The circulating joint comprises a tubular body with circulating
ports through its walls and a sleeve assembly surrounding the body
blocking the ports. Expansible chambers between the sleeve and body
are employed to first unblock the ports and then to block them
again upon selective introduction of pressure to the chambers.
Inventors: |
Cochran; Chudleigh B. (Houston,
TX) |
Assignee: |
Brown Oil Tools, Inc. (Houston,
TX)
|
Family
ID: |
22687181 |
Appl.
No.: |
05/186,994 |
Filed: |
October 6, 1971 |
Current U.S.
Class: |
166/313; 166/127;
166/147 |
Current CPC
Class: |
E21B
34/10 (20130101); E21B 33/124 (20130101); E21B
43/14 (20130101) |
Current International
Class: |
E21B
33/12 (20060101); E21B 43/00 (20060101); E21B
34/00 (20060101); E21B 43/14 (20060101); E21B
34/10 (20060101); E21B 33/124 (20060101); E21b
033/122 (); E21b 033/124 () |
Field of
Search: |
;166/313,127,147,154 |
References Cited
[Referenced By]
U.S. Patent Documents
Primary Examiner: Gay; Bobby R.
Assistant Examiner: Staab; Lawrence J.
Attorney, Agent or Firm: Torres & Berryhill
Claims
I claim:
1. A method of evacuating drilling fluid from a multiple zone well
having upper and lower packer means therein, comprising the steps
of:
a. running a first string of tubing into said well for penetration
of both of said packer means and having circulating joint means
thereon for disposition between said upper and lower packer
means;
b. running a second string of tubing into said well for penetration
of said upper packer means;
c. applying pressure to said circulating joint means, through said
first string of tubing, to open port means therein;
d. circulating fluid through said first and second strings, said
port means and the area between said packer means, displacing
drilling fluid accumulated between said packer means;
e. dropping closure means into said circulating joint means for
engagement with seat means therein;
f. closing said port means independently of said second string of
tubing by applying pressure to said joint means through said first
string; and
g. removing said closure means from said circulating joint means by
increasing the pressure applied to said joint means through said
first string.
2. The method of claim 1 in which both said upper and lower packer
means are completely set prior to said opening of said, port
means.
3. The method of claim 2 in which said upper packer means is
completely set after said running of said second string but prior
to said opening of said port means.
4. A method of evacuating drilling fluids from a multiple zone well
having upper and lower packer means therein comprising the steps
of:
a. running and setting said lower packer means in said well;
b. running a first string of tubing into said well and through said
lower packer means, said first string of tubing having said upper
packer means attached thereto and circulating joint means thereon
for disposition between said lower and upper packer means;
c. running a second string of tubing into said well and through
said upper packer means;
d. setting said upper packer means;
e. applying pressure to said first string of tubing to open port
means in said circulating joint means;
f. circulating fluid through said first and second strings, said
port means and the area between said upper and lower packer means
to displace drilling fluid accumulated between said upper and lower
packer means;
g. dropping closure means into said circulating joint means for
engagement with seat means therein and closing said port means by
applying pressure to said joint means through said first string;
and
h. removing said closure means from said joint means by applying
increased pressure to said joint means, through said first
string.
5. The method of claim 4 in which said closing of said port means
is accomplished while maintaining said second string in a
stationary position.
Description
BACKGROUND OF THE INVENTION
1. Field of the Invention
The present invention pertains to drilling and completion of oil
and gas wells. More specifically, it concerns circulating methods
and apparatus for evacuating drilling fluids from tubing strings
and the space between packers in a multiple completion well.
2. Description of the Prior Art
When completing a multiple zone well, it is necessary to displace
drilling fluid (mud) which remains standing in the well after
drilling operations. In a dual completion well, this requires
circulating fluid down the long string and back up through the
short string. It is desirable to perform this operation after the
tubing strings are secured at the wellhead, so as to be under full
pressure control. In the past, this operation has been performed
prior to setting either the permanent (lower) packer or the
hydraulic (upper) packer. Thus, the circulating fluid passes out of
the longer string back up around the permanent packer and displaces
the drilling fluid between packers through the short string and
around the hydraulic packer through the surrounding casing. After
the drilling fluid has been removed, both the permanent packer and
the hydraulic packer are set. One disadvantage of such a method is
the possibility of a blowout in the lower and/or upper zone prior
to setting the packers. In addition, since the drilling fluid
passes around both packers prior to setting, the distinct
possibility exists that the packer seals will be damaged by the
erosive passage of drilling fluid around the packers. Of course, if
the packers do not properly seal when they are set, an expensive
pulling job may be required.
Attempts have been made to overcome the disadvantage of the former
displacement procedure. For example, a circulating joint has been
attached to the long string for disposition between the permanent
and hydraulic packers. The joint is provided with ports which may
be opened or closed by running a wireline tool into the joint
through the long string. But wireline tools are susceptible to
becoming stuck in the tubing string. This is particularly true when
the string is filled with drilling mud.
Pressure operated apparatus has been recently developed to
eliminate wireline tools. Such apparatus also employs a circulating
joint carried by the long string for disposition between packers
and having ports which may be opened by applying pressure to the
long string. In this method, the permanent packer may be set prior
to circulation and the circulating fluid flows from the long string
into the space between packers, displacing the drilling fluid
through the short string and around the unset hydraulic packer.
After circulation, the circulating sleeve ports are closed by
setting the hydraulic packer and the well is ready for production.
Although such a procedure reduces blowout hazards of the lower zone
and allows running, setting and testing of the permanent packer and
long string before the short string is run, it does not eliminate
the blowout hazards of the upper zone nor the possibility of
damaging the seals of the unset hydraulic packer. Furthermore, the
apparatus for performing this procedure is very complex, requiring,
among other things, extremely close tolerances to operate properly
and precise adjustment of the apparatus for different weight pipes
and distance between packers. The closing of the circulating ports
is also dependent upon the proper setting of the hydraulic packer.
These features result in a rather expensive, delicate and
relatively bulky device.
SUMMARY OF THE INVENTION
The present invention discloses a circulating joint and method of
use which eliminates the problems of the former methods of drilling
fluid evacuation. The joint is attached to the long string and run
into the well for disposition between the lower permanent packer
and the upper hydraulic packer. The joint is also provided with
ports which are closed until the permanent packer and possibly the
hydraulic packer are set. Pressure is then applied to the long
string, causing a pressure chamber in the joint to expand and
uncover these ports. Circulating fluid, such as water, is then
circulated through the long string and the circulating joint ports,
into the area between packers, and back up through the short
string, displacing drilling fluid from the long string and the area
between packers. After the drilling fluid is displaced, a ball
member is dropped into the longer string to seat on a portion of
the circulating sleeve. Increasing pressure is applied to the ball
until the sleeve assembly is displaced from its initial position to
again cover and seal the circulating ports. A further increase in
pressure causes the ball and its corresponding seat to be displaced
from the joint and to be dropped into the bottom of the well,
leaving the well ready for production.
Thus, the circulating joint of the present invention allows setting
of both the permanent and hydraulic packers prior to displacement
of drilling fluids, eliminating hazards of blowout in either zone
and eliminating the possibility of damage to either packer from the
flow of erosive drilling fluids. Both zones may be under complete
pressure protection at all times and the circulating ports in the
circulating joint are closed independently of the short string or
the setting of the hydraulic packer and without wireline tools. The
apparatus for performing such a method is simple and economically
manufactured. Other objects and advantages of the invention will
become apparent from the description which follows.
BRIEF DESCRIPTION OF THE DRAWINGS
In the description of a preferred embodiment of the invention which
follows, reference will be made to the accompanying drawings in
which:
FIG. 1 is a diagrammatic representation of a dual completion well
having long and short strings, a lower permanent packer and an
upper hydraulic packer in set positions, and employing a
circulating joint shown in the port open position, for circulating
fluid through the long string and back up the short string to
displace drilling fluids from the long string and between the
packers, according to a preferred embodiment of the invention;
FIG. 2 is a quarter-sectional elevation view of the circulating
joint of FIG. 1, in its initial closed position;
FIG. 3 is a quarter-sectional elevation view of the circulating
joint of FIGS. 1 and 2, in its port opened position; and
FIG. 4 is a quarter-sectional elevation view of the circulating
joint of FIGS. 1-3, shown in its final closed position.
DESCRIPTION OF A PREFERRED EMBODIMENT
Referring first to FIG. 1, there is shown a well for producing
petroleum fluids from upper and lower subterranean formations or
zones. An outer conduit or casing string 10 extends from the
surface 11 to the bottom 16 of the well hole. The casing string 10
is perforated at 12 and 14 to allow flow of petroleum deposits from
the lower and upper zones, respectively. A wellhead 15 is attached
at the upper end of the casing string 10 and provides support for a
pair of tubing strings, long string 21 and short string 22. The
long string 21 extends downwardly through the casing string 10 past
the upper production zone into an area adjacent the lower
production zone. The short string 22 extends from the wellhead to a
point in the casing string 10 adjacent the upper production
zone.
Normally, the permanent (lower) packer 25 is run into the well, set
and tested first. Then the long string 21 is run into the well with
a hydraulic (upper) dual packer 26 attached thereto. Next, the
short string 22 is run into the well and through the hydraulic
packer 26. Both strings are secured at the wellhead 15. The
hydraulic packer 26 can be set and tested at this point. However,
it might be desirable to leave the packer 26 unset during the
period of drilling fluid displacement.
Attached in the long string at some point between the permanent
packer 25 and hydraulic packer 26 is a circulating joint,
designated generally by the reference number 50. This circulating
joint 50 will be described in more detail hereafter. For present
purposes it is sufficient to state that the circulating joint 50 is
provided with ports which are initially closed during the running
of the tubing strings 21, 22. After the permanent packer 25 has
been set and both strings run in place, pressure may be applied
through the long string 21 causing these ports to be opened, as
will be more fully understood hereafter. Circulating fluid, such as
water, is then circulated through the long string 21, out the
circulating joint ports, into the area of the casing string 10
between permanent packer 25 and hydraulic packer 26, and back up
the short string 22 (see the arrows in FIG. 1). Thus, the drilling
fluid which has accumulated in long string 21 and the area between
packers 25, 26 is displaced from the well. Further pressure is then
applied to the circulating joint 50, as will be explained
hereafter, causing the circulating joint ports to again be closed.
If the hydraulic packer 26 has not already been set, it is set at
this time and the well is ready for production.
Referring also now to FIGS. 2, 3 and 4, the circulating joint 50
will be described in detail. The joint comprises a tubular body
member 52 which is provided at each end with means for connection
in a tubing string. In the particular embodiment shown, the lower
end is provided with male threads 53 and the upper end is provided
with male threads 54 for connection to a threaded collar 55. The
body 52 is provided with three axially spaced sets of radial ports
56, 57, 58. The lower set of ports 58 are the circulating ports
referred to in describing FIG. 1. The intermediate ports 57 and
upper ports 56 are pressure ports, necessary for operating the
circulating joint as described hereafter.
Initially fastened in the bore of tubular body 52 between ports 56
and 57, by a shear screw 61, is a cylindrical spool piece or seat
member 62. The outside diameter of seat member 62 is slightly less
than the upper bore 51 of tubular body 52. Annular seals 63, 64
provide sealing engagement between the seat member 62 and upper
bore area 51. The mid-portion 65 of seat member 62 may be reduced
in diameter. A frustoconical seating surface 68 is provided at the
upper end of seat member 62 for reasons to be shown hereafter.
Surrounding the tubular body member 52, in a sliding fit is a
sleeve assembly, designated generally by the reference number 70.
This sleeve assembly 70 comprises a lower skirt member 80, a seal
carrying sleeve 90, a pressure chamber sleeve 100 and a retaining
sleeve 110. Initially, the entire sleeve assembly is axially
maintained in the position shown in FIG. 2 by a shear connection
119 with tubular body 52. A stop ring 40 assures that upward drag
forces do not disrupt the connection 119. Skirt member 80 is
attached to seal carrying sleeve 90 by a shear screw 81. The
remaining sleeve members 90, 100 and 110 are assembled as an
integral unit by threaded connections 91 and 101. Seals 92 and 102
assure that these are fluid-tight connections.
Mounted around tubular body 52 in an axially spaced relationship
are a pair of seal assemblies 120 and 130. Each seal assembly 120,
130 is provided with internal 121, 131 and external 122, 132 seal
rings. Upper seal assembly 120 is held in place by a pair of
retainer rings 125 and 126 while lower seal assembly 130 is held in
place by a pair of similar retainer rings 135 and 136. The pressure
chamber sleeve 100 is also provided with a seal ring 104. The seal
assemblies 120, 130 and seal ring 104 cooperate with tubular body
52 and the sleeve assembly 70 to form a pair of annular variable
volume or expansion chambers 72, 74 between tubular body 52 and
sleeve assembly 70. The upper chamber 74 communicates with the
upper bore 51 of body 52 through the upper set of ports 56. The
lower chamber 72 communicates with the counterbore area 51a of
tubular body 52 through the intermediate set of ports 57.
In the initial, or running in, position of the circulating joint
shown in FIG. 2, the skirt member 80 blocks passage of fluid from
the interior of body 52. Seal rings 94 and 84 cooperate to form a
pressure chamber 85 communicating with the counterbore 51a of
tubular body 52 through circulating ports 58. After the tubing
string, to which the circulating joint is attached, has been landed
and circulation is desired, the circulation ports 58 must be
opened. This is accomplished by applying pressure to the tubing
string, in which the circulating joint 50 is installed. The
expansion chambers 74 and 72 are exposed to this pressure through
ports 56 and 57, respectively. Since the pressure in these chambers
act in opposite directions on the opposing equal annular surface
areas 106 and 108 of the sleeve assembly 70, the resulting force
tending to break the shear connection 119 is zero, so that the
sleeve assembly components 90, 100 and 110 remain in the position
shown in FIG. 2.
This same pressure also communicates with the chamber 85, partially
formed by skirt member 80. However, in this chamber, the opposing
forces on annular areas 96 and 86 apply a shear stress to the shear
screw 81. As soon as the pressure in the tubing string reaches a
value sufficient to shear this screw 81, say, 1,000 to 1,200 psi,
the skirt member 80 is axially displaced to the position shown in
FIG. 3 where it is stopped by contact with body shoulder 60. If a
sufficient pressure cannot be maintained by the lower production
zone, a ball member may be dropped through the circulating joint
into engagement with a seat member installed at the lower end of
the tubing string, similar to the circulating joint seat member 62.
This would close off the end of the tubing string and allow
pressure to be increased. After the skirt member 80 has been
displaced to the position shown in FIG. 3, the circulating ports 58
are then unblocked and free for passage of drilling fluid and
circulating fluid from the long tubing string into the area
surrounding the long string between permanent packer 25 and
hydraulic packer 26 (FIG. 1). As shown in FIG. 1, the circulating
fluid is pumped through the long string 21, out the circulating
joint ports and back up through the short string 22, displacing the
drilling fluid which has accumulated in the long string and in the
area between packers 25 and 26.
After the drilling fluid has been displaced, it is necessary to
once again seal off the circulating ports 58 to prevent comingling
of production between the two production zones. This is
accomplished by first dropping a rubber ball 140 down the long
string until it engages the seating surface 68 of seat member 62 as
shown in FIG. 4. The ball 140 and seat 62 may be considered to be a
valve. Now, when pressure is applied to the tubing string, chamber
74 is subjected to the same pressure, but chamber 72 is isolated
from that pressure by the closed valve, ball 140 and seat 62, and
is at the lower pressure existing in the counterbore area 51a of
tubular body 52. When the differential pressure between surfaces
106 and 108 is great enough, the shear connection 119, between
sleeve assembly 70 and tubular body 52, fails and allows the
remaining portion of sleeve assembly 70 to be axially displaced
downwardly to the position shown in FIG. 4. A small port 109
equalizes pressure in the annular space 107 between seal assembly
130 and the upper end of seal carrying sleeve 90. To prevent the
entrapment of fluid between the lower end of seal carrying sleeve
90 and skirt member 80, longitudinal slots 59 are provided on the
lower exterior of body member 52. This allows passage of fluid by
the seal ring 84.
The upper seal assembly 120 is provided with a snap ring 127 which
is outwardly biased. As soon as the sleeve assembly 70 is displaced
downwardly a proper distance, this snap ring 127 springs into
engagement with the shoulder 112 of retainer sleeve 110, preventing
upward movement of the sleeve assembly 70 and maintaining it in the
port blocking position shown in FIG. 4. As the sleeve assembly 70
is displaced downwardly it carries a pair of annular seal rings 97,
98 to the position shown, one above and one below the ports 58,
sealing and blocking further passage through circulating ports
58.
Once the circulating ports 58 have again been closed, it is
necessary to remove the ball member 140 and seat member 62. This is
accomplished by increasing the pressure in the tubing string until
shear screw 61 is sheared, allowing the seat member 62 and ball 140
to drop out the end of the tubing string into the bottom of the
well hole. If it had been necessary to place a similar ball in the
bottom end of the string in order to accomplish the initial opening
of circulating ports 58, the ball 140 and seat member 62 would stop
at this point until further pressure is applied to remove that seat
member and ball. In such a case, both sets of seat members and
balls would be dropped into the bottom of the well hole. If the
hydraulic packer 26 (see FIG. 1) had already been set, the well
would now be ready for production. If not, the hydraulic packer 26
would be set at this point and the well would be ready for
production.
The circulating joint of the present invention offers several
alternatives for setting of the hydraulic packer. It could be set
prior to circulation by applying pressure through the short string
22. In such packers, it is common to drop a ball through the short
string so as to allow pressure to be applied to the packer. This
ball could then be pumped back to the surface during the
circulating operations. Another way to set the hydraulic packer 26
would be to apply pressure to the packer through the long string
when the ball 140 is seated on the seat member 62 as shown in FIG.
4. Still another would be to set the packer after circulation and
reclosing of the circulating joint by applying pressure through the
short string 22, with a ball and seat device similar to the ones
(140, 62) used in the circulating joint 50. After setting of the
packer, the ball and seat would be pressured out the bottom of the
short string to clear the string for production. Other alternatives
for setting the hydraulic packer could be used. These are only
examples to illustrate the flexibility of the present
invention.
Thus, it can be seen from the foregoing description, that the
circulating joint of the present invention offers a much improved
method of evacuating drilling fluid from the long string and the
area between packers in a multiple completion well. The circulating
joint is operated by pressure and without the use of wireline
tools. The method is very easy to perform and can be done after
setting of both the permanent packer and hydraulic packers to
prevent damage to packer seals and to maintain all production zones
under full pressure control. The apparatus is simple and its
manufacture is economically attractive. Operation of the
circulating joint is dependent on pressure alone and does not
require manipulation of a tubing string for opening and closing of
circulating ports.
Although only one embodiment of the apparatus of the invention has
been shown herein, several methods of its use have been described.
Further variations of the apparatus and methods disclosed herein
will be apparent to those skilled in the art. It is therefore
intended that the scope of the invention be limited only by the
claims which follow.
* * * * *