Well header for use in frigid environments

A header capable of fluidly connecting a plurality of spaced terminals (e.g. wellheads} to a centralized location in a frigid environment while eliminating or substantially alleviating freezing within the header. The flowpath through the header is such that it forces a relatively warm fluid (e.g. production or injection fluid) to flow through the entire length of the header before the fluid is produced or injected from the header. This allows the relatively warm fluid to continuously transfer heat to the header as it flows therethrough to provide the heat necessary to prevent freezing within the header.

DESCRIPTION 
1. Technical Field 
The present invention relates to a header for distributing and/or 
collecting fluids in a frigid environment and in one aspect relates to a 
header for distributing or collecting fluids to each of several spaced 
wellheads which have been drilled and completed in a frigid environment 
wherein the header has a flowpath designed to prevent freezing within the 
header. 
2. Background 
It is well known that large reservoirs of petroleum (e.g. heavy oil) are 
found in certain frigid areas of the world; e.g. the North Slope area of 
Alaska. As will be readily recognized, the extreme cold temperatures which 
normally exist in these areas significantly add to the problems and costs 
involved in producing and servicing these reservoirs. For example, one 
major cost particular to frigid environments is that involved in 
protecting individual manifolds or "header(s)" which are used to 
distribute and/or collect fluids from freezing up during operation. Such 
headers may be used to service a plurality of wells which, in turn, have 
been drilled and completed at spaced intervals and may be used as (a) a 
production header, i.e. a manifold which collects or "gathers" the fluids 
(i.e. oil, gas, and water) from spaced, producing wells and carry them to 
a centralized point; (b) an injection header, i.e. a manifold which 
carries fluids (e.g. water) from a centralized point to spaced injection 
wells for disposal and/or for repressuring downhole formations as is done 
in typical secondary recovery methods (i.e. water-flood operations); (c) a 
header which gathers production for a separator or which distributes 
injectant from a pump; or (d) any field application where fluids are to be 
distributed or collected between various locations and a centralized 
point. 
In protecting these headers in frigid conditions, it is necessary to 
prevent any substantial portion (e.g. water) of either the production or 
injection fluids from freezing within the header; especially within those 
portions of the header where there is little or no flow (i.e. "dead 
legs"). For example, water, which is almost always a component of the 
fluids flowing through the header, has a tendency to accumulate or collect 
in the dead legs of the header. When this water cools sufficiently to 
freeze, it can block the flowpath through the header which, in turn, can 
severely damage the header or, at a minimum, result in increased operating 
costs due to the efforts required to thaw out the header and return it to 
full operation. 
Currently, there are several approaches to prevent freezing within a header 
in a frigid environment. These approaches include: enclosing the header in 
a heated structure; insulating the header and associated piping; and/or 
strapping an electrical, heating element or "trace" to the outside of the 
header to maintain the temperature within the header at an acceptable flow 
temperature. Another commonly-used technique involves merely displacing 
all production/injection fluids out of the header and associated piping 
and back into the wellbore with a non-freezing or anti-freeze fluid (e.g. 
methanol, diesel, or natural gas) during no-flow conditions. While all of 
the above have merit, each has certain disadvantages. 
For example, insulating the header and the associated laterals leading from 
the header to the respective distribution/collection terminals (e.g. 
wellheads), in addition to adding to the capital costs, may not prevent 
freezing within the header in all situations but may merely slow down the 
freezing process. As to displacing the fluids out of the header with 
anti-freeze fluids, this is expensive and labor intensive in that it must 
be carried out manually and can only be done during no-flow conditions. 
And finally, strapping a heat trace to the outside of the header, in 
addition to the cost involved, is normally inefficient due to the amount 
of heat which is lost directly to the atmosphere surrounding header. That 
is, a large portion of the heat generated by an externally-mounted heat 
trace is immediately lost without ever being conveyed into the header 
where it needed. Accordingly, it can be seen that the need continues to 
exist for a relatively inexpensive header which substantially alleviates 
the freezing problem when the header is used to service a plurality of 
spaced wells in a frigid environment. 
SUMMARY OF THE INVENTION 
The present invention provides a header which is capable of fluidly 
connecting a plurality of spaced terminals (e.g. wellheads) to a 
centralized location and which is constructed to eliminate or 
substantially alleviate the problems associated with freezing in frigid 
environments. The flowpath through the header is such that it forces a 
relatively warm fluid (e.g. production or injection fluid) to flow through 
the entire length of the header before it is produced/injected from the 
header. This allows the relatively warm fluid to continuously transfer 
heat to the header as it flows therethrough to provide the heat necessary 
to prevent freezing within the header. 
More specifically, the header of the present invention is adapted for 
fluidly connecting a plurality of spaced terminals (e.g. wellheads} with a 
centralized location (e.g. a collection point for production wells or a 
supply point for injection wells). The header is comprised of an outer 
conduit which is closed at its outer end and is adapted to extend from the 
centralized location to a point substantially adjacent or beyond the 
furthest terminal. The outer conduit has a plurality of ports along its 
length which are spaced to substantially coincide with each of the 
wellheads. 
An inner conduit is positioned within the outer conduit and extends 
substantially along the length of the outer conduit thereby forming an 
annulus between the two conduits. The outer end of the inner conduit is in 
fluid communication (e.g. the inner end of the inner conduit does not 
extend all the way to the closed end of outer conduit) with the annulus 
thereby defining a flowpath through the header whereby fluids flow through 
both the inner conduit and the annulus. The header is connected to each of 
the terminals whereby fluids can flow from the flowpath within the header 
to the individual terminals. The unique flowpath through the header allows 
the relative warm fluids (e.g. production or injection fluids) to 
continuously transfer heat to the header as they flow therethrough thereby 
preventing or alleviating freezing problems within the header. 
In a first embodiment, a terminal is fluidly connected to a respective port 
in the outer conduit whereby the fluids flow between the terminals and the 
annulus within the header. In another embodiment, individual pipes pass 
through respective ports in the outer conduits and are fluidly connected 
to respective spaced openings in the inner conduits which, in turn, are 
aligned with the ports in the outer conduit whereby fluids flow between 
the inner conduit and the respective terminals.

BEST KNOWN MODE FOR CARRYING OUT THE INVENTION 
Referring more particularly to the drawings, FIG. 1 illustrates the header 
10 of the present invention in an operable position as it distributes or 
collects fluids between a plurality of spaced terminals 11 and a 
centralized point or facility 14. While terminals 11 (only some are 
numbered for clarity) can be any station or structure to which fluids are 
to be distributed and/or collected, they are illustrated in FIG. 1 as 
wellheads of production/injection wells which, in turn, have been drilled 
and completed at spaced locations on the earth's surface 12. As will be 
understood by those skilled in this art, the spacing of the wellheads 11, 
as shown in FIG. 1, is for illustration purposes only and is not 
necessarily to scale. This spacing between wellheads 11 in actual field 
applications may vary from about 8 feet or less up to 120 feet or more. 
As shown in FIG. 1, all of the wellheads 11 are fluidly connected to a 
single manifold or header 10 by means of respective lateral pipes 13. 
Where the wells are producing wells, the production fluids (e.g. oil, gas, 
and/or water) from a particular well flow through its wellhead 11 and 
lateral pipe 13 into header 10. The fluids commingle within the header 10 
and flow through the header to a centralized, location 14 for further 
handling. Where the wells are injection wells, the reverse is true. That 
is, an injection fluid (e.g. water for disposal or for use in 
water-flooding operations) flows from centralized location 14, through 
header 10, and out into each of the wellheads 11 through its respective 
lateral pipe 13. Of course, it should be understood that certain wellheads 
11 can be shut-in when the situation dictates and fluids will be produced 
or injected through only those wellheads that are open (i.e. on-line). 
Where the wells have been completed in a frigid environment, fluids such as 
water has a tendency to "freeze-up" in the header, especially where the 
header may be several tens or hundreds of feet long and have one or more 
"dead legs" or low spots therein where water may accumulate. When freezing 
occurs, the flowpath through the header becomes blocked or severely 
restricted which, in turn, usually results in increased operating costs, 
i.e. damage to the header; time lost in thawing out the header; etc. 
In accordance with the present invention, a header 10 is provided which is 
constructed to eliminate or substantially alleviate the problems 
associated with freezing in frigid environments. Referring now to FIG. 2, 
header 10 is comprised of an outer conduit 15 which has a plurality of 
ports 16 spaced along its length. Each port 16 is adapted to be fluidly 
connected to a lateral pipe 13 which, in turn, leads to a respective 
wellhead 11 (FIG. 1) so ports 16 will be spaced accordingly along outer 
conduit 15. The outer end of outer conduit 15 is closed by a cap or 
closure plate 17 or the like. 
Inner conduit 18 is positioned within outer conduit 15 and extends 
substantially throughout the length of outer conduit 15 to form an annulus 
19 between the outer surface of inner conduit 18 and the inner surface of 
outer conduit 15. As shown, the outer end 18a of inner conduit 18 
terminates just short of plate 17 to provide fluid communication between 
inner pipe 18 and the annulus 19. It should be understood that inner 
conduit could also extend all the way to plate 17 in which case, it would 
have slots or openings therein (not shown) near its outer end to provide 
the necessary fluid communication between inner conduit 18 and annulus 19 
without departing from the present invention. Also, spacers or 
centralizers (not shown) can be used, if required, to "center" inner 
tubing within outer conduit 15. The annulus 19 is closed at the inner end 
of outer conduit 15 by an appropriate sealing means (e.g. plate 20) to 
prevent flow out of annulus 19. 
In operations where header 10 is used as a collection header (e.g. 
production header), production fluids flow from on-line wellheads 11 and 
through their respective lateral pipes 13 into the outer conduit 15 of 
header 10 through their respective ports 16. The relative warm production 
fluids (black arrows 22 in FIG. 2) commingle in the annulus 19 of header 
10 and flow into inner conduit 18 through open inner end 18a. The 
productions fluids 22 then flow through the entire length of inner conduit 
18, which extends substantially throughout the length of outer conduit 15. 
This flow of warm production fluids through the entire length of inner 
conduit 18 and through at least a portion of the annulus 19 continuously 
transfers heat to the header 10, thereby preventing freezing in any part 
of header 10 for so long as at least one well is on line and its flow rate 
is sufficient to provide the necessary heat. 
In operations where header 10 is used as a distribution header (e.g. an 
injection header), the direction of flow is reversed but the results are 
basically the same. That is, a relatively warm injection fluid (white 
arrows 23 in FIG. 2) is flowed from centralized location 14 into and 
through inner conduit 18 of header 10. Fluid 23 exits through the outer 
end 18a of inner conduit 18 into annulus 19 from which the fluid exits 
into lateral pipes 13 through respective ports 16 and into wellheads 11. 
The flowpath through header 10 forces the warm injection fluid to flow 
through the entire length of the inner conduit 18 and through at least a 
portion of annulus 19. This allows the warm fluid 23 to continuously 
transfer heat to the header and prevent freezing within the header so long 
as one or more wells are on line and the flow rate is sufficient to 
provide the necessary heat to prevent freezing. 
FIG. 3 discloses a further embodiment of the present invention. Header 10a 
is comprised of an outer conduit 35 which is closed at its outer end by 
cap or closure plate 37 and which has a fluid opening 33 at its inner end. 
Outer conduit 35 has a plurality of ports 36 spaced along its length. An 
inner conduit 38, which is closed at its inner end 38a and open at its 
outer end 38b, is positioned within outer conduit 35 and has a plurality 
of openings 40 therein which are aligned with ports 36. Individual pipes 
36a are secured in respective openings 40 in inner conduit 38 and extend 
through respective ports 36 in outer conduit 35 to provide fluid 
communication between the interior of inner conduit and respective lateral 
pipes 11 (FIG. 1). 
In operations where header 10a is used as a collection or production 
header, production fluids flow from on-line wellheads 11 and through their 
respective lateral pipes 13 and through their respective pipes 36a into 
the inner conduit 35 of header 10a. The relative warm production fluids 
(black arrows 42 in FIG. 3) commingle in the inner conduit 38 and flow 
through open end 38b of conduit 38 into annulus 39 which is formed between 
the two conduits. The production fluids 42 then flow through the entire 
length of outer conduit 35, out fluid opening 33, and on to centralized 
location 14 (FIG. 1) for handling. 
The flowpath through header 10a causes the warm, produced fluids to 
effectively flow along the entire length of the outer conduit 35 
regardless of the number or location of the on-line, producing wells. This 
allows the warm production fluids to continuously transfer heat to the 
header 10a as they flow therethrough, thereby preventing freezing in any 
part of header 10a for so long as at least one well is on line and its 
flow rate is sufficient to provide the heat necessary. 
In operations where header 10a is used as a distribution or injection 
header, the direction of flow is reversed but the results are again 
basically the same. That is, a relatively warm injection fluid (white 
arrows 43 in FIG. 3) is flowed from centralized location 14 into outer 
conduit 35 of header 10a through fluid opening 33. Fluid 43 flows through 
annulus 39 and into inner conduit 38 through open end 38b from which the 
fluid exits into lateral pipes 13 to wellheads 11 through respective pipes 
36a. The flowpath through header 10 forces the warm injection fluid to 
flow through the entire length of the outer conduit 35 (i.e. through the 
length of annulus 39) thereby allowing the warm fluid 43 to continuously 
transfer heat to the header and prevent freezing within the header so long 
as one or more wells are on line and the flow rate is sufficient to 
provide the heat necessary to prevent freezing in the header.