Method of replacing a corroded well conductor in an offshore platform

A method of replacing a corroded well conductor positioned in an oil production platform at an offshore location. After shutting in or killing the well, the wellhead is removed and the sections of the casing and tubing strings within the well conductor above the mud line are backed off and removed. The damaged well conductor is cut off above the mud line leaving a stub to which the lower end of a new section of well conductor is connected and bonded by means of a novel connector. Communication between the old and new sections of well conductor is established and the casing and tubing sections are re-installed in the new well conductor and the wellhead is closed.

BACKGROUND OF THE INVENTION 
This invention relates to the replacement of a well conductor in an 
offshore platform having several producing oil and gas wells. An oil well 
is equipped with an inner production tubing position within one or more 
concentric strings of pipe or well casing which in turn are surrounded by 
a large-diameter pipe string, known as a "well conductor" which extends 
from the deck of the platform to several hundred feet into the ocean 
floor. The well conductor generally supports the weight of the wellhead 
and at least a portion of the weight of the strings of tubing and casing 
hung in the well. The well conductor also protects the inner pipe strings 
from wave action and corrosion. 
In the event that a well conductor became corroded, it has been a practice 
to patch it up by welding more metal over the corroded areas. This calls 
for underwater welding which is difficult to carry out and inspect, and is 
not practical on deep platforms which are in 1,000 feet or more of water. 
For severely corroded or damaged well conductors, it has been the practice 
to abandon the well and drill another if there is an extra slot or wellbay 
on the platform. 
SUMMARY OF THE INVENTION 
Rather than attempt to mend or repair damaged or corroded well conductors 
on platforms at offshore locations, a method has been developed to remove 
any or all of a damaged well conductor above the ocean floor and replace 
it with a new upper section of conductor. This is done in a manner such 
that only the well being repaired has to be shut in so that there is no 
loss of production from the other wells on the platform which can keep 
flowing. As it is hazardous to carry out welding operations on a platform, 
the present method can be carried out without welding. 
In practice of this invention, a producing well is shut in or killed, the 
wellhead is opened and the tubing and casing strings are closed or plugged 
and then removed from about 25 feet below the ocean floor or mud line. The 
damaged empty well conductor is cut off about 5 feet above the ocean 
floor. A new well conductor is made up as it is lowered down through the 
platform into register with the stub of the old well conductor sticking up 
from the ocean floor. A connector carried by the lower end of the new 
conductor is stabbed into the open end of the stub and subsequently bonded 
thereto. After removing closure plugs the casing and tubing strings are 
reinstalled in the wellhead and hung from the wellhead which is then 
closed.

DESCRIPTION OF A PREFERRED EMBODIMENT 
Referring to FIG. 1 of the drawing, an offshore platform is generally 
represented by numeral 10 which may comprise a plurality of elongated 
tubular legs 11, which are interconnected by any arrangement of 
cross-bracing members 12. The legs 11 extend substantially vertically from 
the sea bed or ocean floor 13 to a suitable level, say 50 feet, above the 
mean water line 14 where they support one or more operating and/or storage 
decks 15. The deck may be provided with at least one hoist unit 16 for 
handling pipe and other equipment on the platform. 
The upper and lower floors of the deck 15 are provided with one or more 
wellbays or openings 17 therethrough through which a well conductor 18 is 
passed at the start of well drilling operations. A well conductor 18 is 
generally heavy-walled pipe, say, 20 inches in diameter, which is made up 
of 30 or 40 foot sections of pipe which are welded or screw-threaded 
together, in a manner well known to the art, on the deck 15 of the 
platform 10 and then lowered through opening 17. A platform may have from 
1 to 80 well conductors depending on the number of wells to be drilled. 
A deep-water platform 10, say one located in 300 feet of water, may be 
equipped with a series of bellguides 20 which are secured, as by welding, 
to the cross-bracing members 12 of the platform 10 when it is fabricated 
on land. The platform of FIG. 1 is illustrated as being equipped with five 
bellguides 20 which are in vertical alignment and are located at, say, 30, 
75, 125, 175 and 225 feet, respectively, below the mean water level 14 
where the platform is located. If desired, the bellguides 20 may be 
displaced laterally an increasing amount from top to bottom so that a 
centerline passing through the bellguides falls in a downwardly and 
outwardly directed curved line in the event that curved conductors are to 
be used in a manner well known to the art. 
The platform 10 is generally secured to the ocean floor 13 by driving piles 
21 down through the tubular legs 11 into the ocean floor where they may be 
cemented in place. During the drilling of a well through a well conductor 
18, one or more strings of casing and one or more tubing strings are run 
into the well and are hung from and/or supported by a wellhead 22 which 
closes the top of the well and conductor 18 during production operations. 
In FIG. 2 a typical cross section of the tubulars in a well is illustrated 
as comprising the well conductor 18 and two concentric well casings 23 and 
24 which in turn surround a production tubing string 25. 
In a typical well installation, a 20 inch diameter well conductor 18 is 
made up on the platform 10, section by section being connected together in 
end-to-end relationship, and lowered through the wellbay 17 and then down 
through the bell guides 20 to the ocean floor 13. Additional sections of 
pipe are secured to the top of the well conductor 18 as it is driven into 
the ocean floor 13, say to a depth of 250 feet, by the use of a pile 
driver in a manner well known to the art. Well drilling operations are 
carried out through the well conductor 18 down to, say, 2,000 feet. A 
string of casing 23, say 103/4 inches in diameter, is run into the hole, 
hung from the wellhead 22 and cemented in place. Well drilling operations 
are continued to, say, 10,000 feet and another string of casing 24 is run 
into the well, hung from the wellhead 22 and cemented in place. This 
casing string 24 may be 7 inches in diameter and may surround a 21/2 inch 
tubing string, represented by numeral 25. 
It is a general practice to protect offshore platforms against electrolytic 
corrosion either by equiping it with an impressed-current cathodic 
protection system or with sacrificial anodes, or by both. Even though such 
equipment is used, the environmental factors at a platform location may 
change over the years resulting in inadequate protection to well 
conductors on many of the platforms that have been in the water over ten 
years. An inspection of a multi-well platform revealed an excessive amount 
of corrosion on the well conductors 18 where they passed through the 
wellguides 20. At the 30 foot bellguide, about 30% of the well conductors 
were severed and another 20% were severed from 25% to 80%. At the 75 foot 
bellguide, 40% of the well conductors were severed and another 35% were 
partially severed from 15% to 50%, with lesser damage on the other 
conductors and at the deeper bellguide levels on all conductors. 
A typical damaged well conductor 18 is shown in FIG. 3 as having been 
completely severed by corrosion opposite the location of the two uppermost 
bellguides 20 located 30 and 75 feet, respectively, below the mean water 
level. In addition, the well conductor was 50% severed by corrosion 
opposite the bellguide located 125 feet below the water surface, while 
deep corrosion or holes were found in the conductor wall opposite the 
deepest bellguides. 
In some cases, after the well conductor 18 (FIG. 4) was completely severed 
into portions 18a and 18b, the lower portion 18b of the conductor had 
sufficient corrosion at the severance so that the lower severed conductor 
portion 18b came out of the bellguide 20, exposing the 103/4" casing 23 to 
deflection-induced bending and localized stresses caused by upper end of 
conductor portion 18b as it whangs back and forth laterally with wave 
action. At the same time, the casing 23 is subjected to added corrosion as 
sea water is able to enter the annulus between the well conductor 18 and 
the casing 23. 
In view of the fact that the condition of the basic platform may be good 
and the oil field may be produced for many more years, a method was 
developed whereby a damaged well conductor could be repaired in a safe 
manner without shutting down the platform or shutting in the rest of the 
wells. 
A typical well conductor 18 that is to be cut off and replaced is 
diagrammatically illustrated in FIG. 5 as being closed at the top by a 
wellhead 22. Opposite the uppermost bellguide 20, the conductor is badly 
corroded and about 75% severed. Opposite the next lowermost bellguide, the 
conductor is about 40% severed. There is further severe corrosion and 
holes in the conductor opposite all of the bellguides. 
At the start of the repair operation the well is shut in so as to stop the 
flow of fluid from the well. This may be done by closing a valve 26 which 
may be provided in the production tubing string in a manner well known to 
the art. Alternatively, a tubing plug could be run down the tubing 25, as 
by means of a wireline lubicator which would be mounted on the wellhead in 
a manner used on land wells. Flow from the well may also be stopped by 
killing the well, i.e., pumping a heavy fluid down the tubing. 
With flow from the well stopped, the wellhead 22 is opened so that the 
tubing string can be unscrewed, one or more sections at a time, and pulled 
out of the well. The last joint of tubing to be removed would be the one 
Just above a tubing plug or valve 26. The same operation would be carried 
out to remove the upper sections of the casing strings 23 and 24, 
preferably after closure plugs 27 and 28 had been run into and set in 
casings 23 and 24. 
With the upper sections of tubing string 25 and casing strings 23 and 24 
removed to a point well below the mud line 13, the well conductor 18 is 
cut off at any desired location above the mud line, say 5 feet. In shallow 
water, the well conductor may be cut by divers using any suitable cutting 
apparatus. In extremely deep water, inside or outside casing cutters well 
known to the art may be run on a pipe string or wireline to make the cut. 
Alternatively, tools for Jetting an abrasive fluid may be used. If 
desired, the cut may be provided a smooth finish by use of well known 
milling tools. If divers are used, a template may be secured around the 
conductor to aid in providing a smooth horizontal cut which is 
perpendicular to the axis of the conductor. After cutting the conductor, a 
short conductor stub portion 18a extends above the ocean floor as shown in 
FIG. 6. 
FIG. 7 illustrates well arrangement of FIG. 6 after a new section of well 
conductor 30 has been positioned on top of the conductor stub 18a. The new 
conductor section 30 is provided at its lower end with an elongated 
tubular connector member 31 which is of a diameter selected to fit 
telescopically either inside or outside the well stub 18a. If an inside 
stab-type connector is utilized, as shown in FIG. 7, it is essential that 
the distance between the top or shoulder of the conductor stub 18a and the 
top of the next concentric well casing 23 be greater than the length of 
the stab-type connector 31 below its seating shoulder 32. 
One form each of an undershot and an overshot tubular connector, for use in 
the method of the present invention, is shown in FIGS. 8 and 9, 
respectively. The undershot tubular connector of FIG. 8 comprises upper 
and lower tubular portions 31a and 31, respectively, which are connected 
together at point 34, as by welding or screw threads, above a seating 
shoulder 35 which is adapted to seat on the upper cut-off face of the well 
conductor stub 18a. In order to fit in a 20 inch O.D. conductor stub 18a, 
the stab-in connector 31 is made of pipe of a smaller diameter, say 18 
inch O.D., which in turn may be swaged down, as at 36, to a 16 inch O.D. 
tubular, if desired. This allows about a 3 inch annular space 33 between 
the connector 31 and the conductor 18. In order to achieve a strong 
connection between the conductor 18 and the stab-in connector 31, it is 
proposed to pump a cement or other suitable bonding material in the 
annular space 33 which is closed at lower end by flexible wiper cups 37 or 
a slidable seal of any other suitable design. 
The wiper cups 37 may be secured to the lower end of the tubular stab-in 
connector 31 on the outer wall thereof, or may be secured to a drillable 
cementing shoe 39 which is secured to and closes the lower end of 
connector 31. Positioned above the wiper cups 37 and extending through the 
wall of the connector 31 are one or more fluid ports 38 allowing a bonding 
material to flow from the bore 41. The upper end of the annular space 33 
is in communication with the ocean surrounding the well stub 18a through 
suitable fluid ports, for example, by ports 42 through the wall of the 
upper connector portion 31a located, preferably, just above the upper edge 
or seating shoulder of the conductor stub 18a. 
In order to be assured that the tubular connector 31 is concentrically 
positioned within the conductor stub 18 so that bonding material of 
uniform thickness is formed in the annular space 33, a series of tapered 
shims or wedges 43 are secured, as by welding, to the outer surface of the 
tubular connector 31. The shims may be of a thickness so as to come within 
1/8 of an inch of the inner wall of the conductor stub 18 when the 
connector 31 is concentrically positioned within the stub 18. The shims 43 
are spaced apart circumferentially so that vertical flow passages 44 are 
formed between them to allow the bonding material to flow or be forced up 
the annulus 33, through the flow passages 44, to be discharged through 
ports 42. Prior to carrying out the present method, the well conductor 
stub may be suitably cleaned in any well known manner, as by a wire brush 
actuated by means of a motor and operated by a diver or operated at the 
end of a pipe string from the platform, to get a better bonding surface. 
In practicing the method of the present invention, the connector apparatus 
described with regard to FIG. 8 is connected to a new section of well 
conductor 30 on the deck 15 of the platform 10 (FIG. 1) and is lowered 
down the vertical opening 17 from which an old corroded well conductor had 
been removed after it was cut off just above the ocean floor. Additional 
sections of well conductor are connected end-to-end, one at a time, as the 
assembled new well conductor 30 is lowered through the bellguides 20 and 
the stab-in connector 31, at the lower end of the new well conductor, is 
stabbed into and seats on the upper edge of the well conductor stub 18a 
sticking up from the ocean floor (FIGS. 7 and 8). 
A normal cementing operation is now carried out with cement or another 
bonding fluid being pumped down through the new well conductor to be 
followed by a plug and water in any cementing procedure well known to the 
art. On reaching the shoe 39, the flowing bonding fluid is forced out 
fluid ports 38 and upwardly through the annulus 33, past the shims 43 
through flow passage 44, to be discharged out fluid ports 42 into the 
ocean. The bonding material is allowed to harden before the well connector 
is opened to put the old well conductor 18 in fluid communication with the 
new well conductor 30. 
If desired, in waters where divers may be used an additional seal on the 
outside of the conductor may. be formed where the new conductor-connector 
section 31a shoulders on the top of the conductor stub 18a so as to seal 
this point and the ports 42 from the outside. For example, as shown in 
FIG. 7, a sealing channel 49 for holding a hardenable liquid sealant may 
be provided with suitable clamps 50. After clamping the trough or channel 
in place, the diver would fill it with liquid sealant of a type which will 
set up in sea water. 
After the bonding material in the annulus 33 has hardened, a clean-out tool 
or drill is lowered on a pipe string to punch out or drill the friable or 
drillable shoe 39 and any bonding material thereabove (FIG. 8) so as to 
achieve open communication between the old and new well conductors 18 and 
30. The well casing plugs 27 and 28 in casings 23 and 24 are then removed 
and the sections of both casings which were removed from the well prior to 
its repair would be re-run into the well through the new well conductor. 
Subsequently, the tubing string 25 would be re-run in the innermost 
casing. After the wellhead 22 had been closed, the valve 26 in the tubing 
25 would be opened to place the well on production. 
Referring to FIG. 9 of the drawing, a new or replacement well conductor 51 
is shown as being screw-threaded as at 52, to the upper portion 53a of an 
overshot-type tubular connector which is welded, as at 54, to a lower 
downwardly-extending tubular member 53. The lower end of the upper portion 
53a forms a landing surface 55 of a size to mate with the shoulder 56 
formed at the top of the old well conductor stub 18. The diameter of the 
overshot lower portion 53 of the connector is sufficiently large so that 
an annulus 57 at least 1 inch wide, and preferably about 3 inches wide, is 
formed between the inner wall of member 53 and the outer wall of conductor 
stub 18. Because of the large diameter of an overshot type connector, as 
shown in FIG. 9, it can only be used in special repair jobs, such as in 
shallow water where bellguides are not used on a platform. The bellguides 
on a platform are not generally large enough to allow an overshot 
connector to pass through them. 
The lower end of the lower tubular portion 53 is provided with a series of 
spacer or centralizer blocks or shims 58 which are secured, as by welding 
to the inner surface thereof. Additionally, flexible wiper cups 60 are 
mounted on the inner wall of member 53 near the lower end thereof to 
contain a bonding fluid material when it is pumped into the annulus 57. A 
series of fluid ports 61 are provided in the connector wall portion 53a at 
a point above the shoulder 56 formed at the top of conductor stub 18. The 
ports 61 are in communication between the bore 62 of the upper connector 
portion 53a and the annulus 57. 
In securing the overshot connector 53-43a to the conductor stub 18 after it 
has been seated thereon, a removable or drillable cementing plug 63 of any 
well known type would be set in the top of the conductor stub 18. Thus, a 
bonding material, such as cement, would be introduced into the bore 62 of 
the connector 53a above the plug 63, and would flow out the ports 61 into 
the annulus 57 and then down the annulus to the wiper cups 60 to bond the 
connector 53-53a, at the lower end of the new well conductor 51, to the 
conductor stub 18. After the bonding material has hardened, the plug 63 
and any material left in the bore 62 above it may be drilled out. The 
original tubing and casing strings could then be installed in the well and 
the wellhead secured thereto in a manner described hereinabove with regard 
to the stab-in type connector.