Note: Descriptions are shown in the official language in which they were submitted.
2~267~
CAVERN WELL PRESSURE TRAP
FIELD OF THE INVENTION
The invention relates to underground storage systems for p~ rd fluids such as
natural gas liquids. More particularly, the invention relates to a pressure trap for the
temporary sealing of a producer well of a subterranean pressurized storage cavern.
BACKGROUND OF THE INVENTION
Manufactured gases and especially natural gas liquids are widely used by
industry and private consumers mainly for heating and energy production. Federalregulations and daily and annual fluctuations in the demand for hydrocarbons require
suppliers of hydrocarbon fuels to m~intAin fuel reserves. l~nllfact~lrers have established
pC Il~ SC.~ of natural gases and other hydrocarbons in which the fuels can be
stored at times of little or no consumption and from which they may be removed to
cover peak dem~n~.
Various types of storage facilities are known. Natural gas liquids can be storedat atmospheric pressure in man made above ground in~ fed containers such as Horton
spheres. However, the use of such tanks is very costly and, thus, of minor economic
interest. In the alternative, natural gas liquids can be stored in natural ~ul,t~.ldnean
caverns, as disclosed in the technical and patent lil~.dlulG (Germain, C.Y. (1980) Les
Roches Salines et le Stockage Souterrain, Bull. Cent. Rech. Explor-Prod. Elf-Aquitaine,
4: 479-493; U.S. patent No. 4,365,978; British patent No. 1,358,053). These natural
caverns are, for example, closed mines, especially salt mines, e~h~l-qted gas fields,
aquifer caverns, porous rocks, or caverns solution mined in salt formations which are
located at sllbst~nti~l depths of several hundred to several thousand meters.
Two general types of subterranean gas storage systems are known. In wet-
operated systems, brine is used as a working fluid to force the stored product out of the
underground cavern. When product is re-injected into the cavern, the brine must be
removed at the same flow rate the product is injected. If the product is delivered
directly from a major pipeline, the injection rate may approach 20,000 bbls/hr. This rate
requires an uneconomical amount of horsepower to inject the product into the cavern
because the product is typically less than half the density of the brine and thedirr~ lial pressure must be overcome by injection pumps. Consequently, some
30 ullde~ ld storage Op~la~ choose the dry- operated storage system where no brine
2102~75
is used to drive product from the cavern. Instead, an electrical submersible pump is - -
used for removal of the stored liquids. When product injection is required, the product
is simply allowed to flow down a large diameter well bore aided by gravity. Dry
operated caverns generally include at least two wells. One is used to inject product into
5 the cavern and is usually drilled such that it enters into the cavern through the cavern
roof and the other is used to produce stored product back to the surface. The producer
well is usually 3 to 30 meters offset from the side wall of the cavern. Communication
from the producer well into the cavern is obtained by jetting a lateral channel or bore -
through the salt formation surrounding the cavern. Stored liquid flows through the
10 lateral channel into a sump of the producer well in which an electrical submersible
pump is installed for the purnping of the stored product to the surface.
It is a problem with dry-operated systems that the submersible pump must be
pulled from the producer well from time to time for service or repl~r~nlrnt The
electrical submersible pumps are usually s1~p~n(~ed in the well by a production tubing
and the entire tubing string must be removed to repair the pumps. To do this, some :
means must be provided to prevent loss of large quantities of the stored p~ssu~ d
product during removal or insertion of the pump and tubing assembly. Of course, the
safest way is to fill the cavern entirely with brine. However, since the caverns are
generally quite large, usually in the range of 200,000 bbls to 500,000 bbls, taking the
20 cavern out of commercial use and rli~pl~r.ing it to brine is very ~1 ensive. In the
all~ livt;, the pump may be repaired or replaced and the well worked over without
taking the cavern out of service by providing a water seal at the lower end of the
producer well casing whereby penetration of stored product into the producer well
casing is prevented. Several trap arrangements are known for the production of a such a
25 water seal.
Morsky et al ((~.~n~(1izln published patent application 2,003,031) disclose a
pressure trap in the form of a U-shaped tube cnn1-~c~ed to the bottom of the producer
well casing so that the tube's free end which extends to a liquid gas layer in the well is
at a higher level than the lowermost point of the tube. Also described is another well
30 seal arrangement for a natural gas liquid (NGL) storage cavity wherein the bottom end
of the well casing is positioned within a protective tube of larger diameter thall the
casing. The lower end of the protective tube is closed, whereas the upper open end is
:' ,' ', . ' . ::' :~: ' ': -, ' ': ,,
: ~ 2 ~ 5
normally located above the water or brine level in the cavity so that the stored liquid
can be pumped from the cavity by way of a submersible pump which is s-l.epen-led in
the casing. To kill the well, the liquid in the casing is forced down with nitrogen gas
and a water seal is placed at the bottom of the casing by filling the protective tube with
5 water or brine up to a level below the tube's upper end. The nitrogen gas is gradually
replaced by water or brine whereby the water level in the production tubing varies
between the upper end of the protective tube and the lower end of the well casing.
When all the nitrogen gas is replaced, the hydrostatic pressure of the water column in
the casing balances with the pressure in the cavern so that no stored liquid can escape
10 from therein.
Miles (U.S. 2,928,249) teaches an arrangement for the sealing of a p~e~ d
storage cavern which allows removal or insertion of a submersible drainage pump for a
dry operated storage system. A water trap is created at the bottom of an off-setproducer well. The well casing extends into a sump located at the bottom of the well
15 and below a lateral channel connecting the well with the storage cavern. A sul)~ ible
pump is suspended in the well casing near the bottom end thereof by way of a
production tubing. The bottom end of the casing is positioned in a protective tube
which has a closed lower end and an upper end which is located near the lateral
channel. For removal or insertion of the pump, the casing and the ~ulrolu~ding tube are
20 filled with an inert fluid which is immi~eible with and of greater density tharl the stored
liquid until the hydrostatic head of the fluid in the casing above the level of the stored
liquid is in balance with the pressure within the cavern.
Bere~uul~y (U.S. 4,417,829) ~ eloses an underground liquid hydrocarbon
storage system wherein the lower end of the producer well casing is received in a pot
25 which has a closed bottom and an upper rim. The water level in the well sump is
i"~d below the rim of the pot by way of drainage pump. To kill the well, the
water level in the well sump is raised to a level above the rim of the pot, wl~ ,l,y the
volume of water in the sump above the rim is in excess of the water volume needed in :
the casing to m~int~in a hydrostatic balance with the storage pressure in the cavern.
30 Thus, even if the pressure in the storage cavern hlcleases enough to force the int~ re
between the water and the stored hydrocarbon to a level below the rim, the stored . :
210267~
product cannot escape through the production casing unless the int~rf~e is forced below
the lower end of the casing.
It is a disadvantage of such conventional traps that the protective tubes or pots
are located outside the casing. Consequently, the well bore of the producer well must
5 be made substantially larger in diameter than the casing to permit setting of the
plvl~;Live tubes or pots at the bottom of the well, which increases well drilling costs.
Also, a much larger amount of sealing material is required to set the casing which
further increases the well installation cost. In addition, prior art prote~;liv~ tubes or pots
cannot be removed and replaced upon failure, for exarnple, due to corrosion, without
10 pulling the complete casing, which is extremely costly and may be impossible in some
situations. Finally, conventional seal arr~ngPn-~nt~ cannot be used for retrofitting
existing production casings without water seal arrangements. Therefore, a well pressure
trap is desired for the sealing of a producer well which can be installed and repaired
more economically than conventional pressure trap ~IAllg~
SUMMARY OF THE INVENTION
It is now an object of the present invention to provide a well pressure trap for the
sealing of a producer well which can be installed more economical than conventional
pressure trap systems.
It is another object of the invention to provide a well pressure trap which can be
20 installed as a retrofit in existing well casings or as a backup to a failed conventional
pressure kap installed outside of the producer well casing.
It is yet a further object of the invention to provide a pressure trap which when
filled with a well killing fluid will allow the safe removal of a fluid purnping~ g~ led in the producer well without the addition of further well killing
25 fluid into the producer well.
Accordingly, the invention now provides a pressure trap for a producer well of asubt~ ~leall plessul;~ed fluid storage system, the producer well being lined with a well
casing having a casing interior colll,llu.licating with a subt~ fluid storage cavity
through a lateral bore, which trap is installed within the casing and not at the outside
30 thereof.
The pressure trap preferably includes a divider means for dividing off a chamberfrom a lower portion of the casing interior, which chamber collllllullicates with and
21~2~7~
extends to a selected level below an entry of the lateral bore into the well casing, and a
passage for fluid communication between the chamber and a remAin~lfAr of the casing
interior, whereby the passage is located below the entry of the lateral bore. The divider
means preferably includes a divider wall for dividing off the chamber from the interior
5 of the well casing, the divider wall having upper and lower ends respectively positioned
above and below the entry of the lateral bore, and a sealing means for sealing the
chamber along the well casing. The passage is preferably positioned sufficiently below
the enky of the lateral bore such that a volume of the chamber below the enky of the
Iateral bore and above a level of the passage is at least as large as a volume of well
10 killing fluid displaced by a fluid pumping arrangement suspendible in the well.
In a preferred embodiment, the divider means is a cylindrical liner having upperand lower ends respectively positioned above and below the entry of the lateral bore,
most preferably a steel tube, and the sealing means is an annular packer positioned
between the liner and the well casing and above the lateral bore. By appropriately
15 selecting the axial length of the liner below the lateral bore, the volume of the annular
chamber between the liner and the casing and below the lateral bore can be made equal
to or larger than the volume of fluid ~1ixpl~ced by the ~ ping ~lal~g~llltlll so that after
the well has been killed, the pumping arrangement can be safely pulled from the well
without additional well killing fluid being added to the producer well. Most preferably,
20 the axial length of the liner is selected so that when the liner is completely filled with
well killing fluid having a higher density as and being immiscible with the pl~ ed
fluid, the hy(llo~l~lic head of the well killing fluid in the liner above the lower end
thereof is equal to or larger than the pressure of the pre~ Pd fluid in the cavern.
In another aspect, the invention provides a method of establishing a pressure kap
25 for a producer well of a subt~ lean pl~ ".i~d fluid storage system, the well being
lined with a well casing having a casing interior communicating with a pl'e~ rd
liquid storage cavern through a lateral bore, co~"l.. ;x;l~g the steps of dividing off a lower : -
portion of the casing interior at an entry of the lateral bore with a divider to form a
chamber communicating with and extPnl1ing to a level below the entry of the lateral
30 bore and providing a passage for fluid communication between the chamber and a
Ir~l~Ai~ f- of the casing interior at a selected level below the enky of the lateral bore.
21Q267~
The invention further provides a method of sealing a producer well of a
~ub~ eall plci,~uli~d fluid storage system, the well being lined with a well casing
having a casing interior co~ ullicating with a ~c~uli~ed liquid storage cavern through
a lateral bore, comprising the steps of providing a pressure trap in accordallce with the
present invention and filling the producer well with a well killing fluid having a higher
density as and being immiscible with the ple~ul;~t;d fluid to a level where a hydrostatic - ~ -
pressure of the column of well killing fluid in the well above the passage for fluid
collllllullication between the chamber and the r~m~in~ r of the casing is equal to a
pressure of the ples~ul;~ed fluid in the cavern.
BRIEF DESCRIPTION OF THE DRAWINGS
The invention will now be further described by way of example only and with
~~relellce to the attached drawings wherein
Figure 1 shows a typical dry-operated subterranean natural gas liquids storage
system;
Figure 2 is a preferred embodiment of the pressure trap in accordallce with the
invention installed in a natural gas liquids storage system as shown in Figure 1.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
A dry-operated ~u~t~ ean natural gas liquids storage system (as illustrated in
Figure 1) generally includes a storage cavern 10, an injection well 12, a~lu-luce. well
14 and a lateral bore or shaft 16 which connects the producer well 14 with the cavern
10. The injection well 12 is provided with an injection well casing 18 which above .
ground is co~ ed to a natural gas pipeline 19 (only partly shown) or another natural
gas liquids source through an injection well tree 20. The injection casing 18 ends in the
roof of the cavern 10. The producer well 14 is provided with a production casing 22 ~ -
which extends from above ground to a sump 24 of the well. An electrical submersible
pump 26 is suspended in the production casing 22 by a production tubing string 28,
whereby the pump is located below an entry 17 of the lateral bore 16 into the
production casing 22. The pump 26 is supplied with operating power in a manner well
known to persons skilled in the art of dry-operated ~ubt~,.ldllean fluid storage systems
and generally through electrical wires fastened to the outside of the production tubing
string 28. The producer well 14 is sealed around the production casing 22 at ground
level by a first plug 50, imm~ t~.ly above the entry 17 of the lateral bore 16 by a
2102~75
second plug 52, and in the sump 24 by a third plug 54, which plugs are generallycement~d plugs. The second and third plugs 52 and 54 are provided to prevent natural
gas liquids escaping through fractures in the formation surrounding the production
casing 22 at and below the lateral bore 16. Natural gas liquids 30 are stored in cavern
5 10 and are overlaid by natural gas liquids vapours 32. Seeped-in ground water or brine
34 collects at the bottom of the cavern due to its higher density. Appropriate pumping
arrangements (not shown) known in the art can be included in the storage system to
prevent seeped-in water from accumulating to a level above the lateral bore 16 and
blocking it. The natural gas liquids 30 flow under the influence of gravity from the
cavern 10 into the sump 24 of the producer well 14 from where they are pumped by the
pump 26 through production tubing 28 and shut-off valve 27 into a supply pipeline 29
(only partly shown). The production tubing 28 extends through a producer well tree 21
which includes a conventional production tubing lifting and s~lcpe.n-1ing a~ gelllent 23
(s.~h~m~tically illustrated), and a brine or water supply pipe 25 with brine shut-off valve
15 31.
Turning now to Figure 2, a preferred embodiment of the pressure trap in
accold~lce with the invention includes a liner 34 and packer 36 combination which
provides for the production of a water seal and is positioned at the bottom end of the
production casing 22. The liner 34 is a cylindrical steel pipe coaxially positioned within
20 the production casing 22 and positioned at the lateral bore 16 in such a way that upper
and lower ends 39 and 40 of the liner are respectively positioned above and below the -~
entry 17 of the lateral bore. The liner 34 divides the production casing 22 into a first
.... . ..
annular chamber 42 which is located between the liner and the production casing 22 and
which co.,...,.~.;c~les with the lateral bore 16, and a second cylindrical chamber 44
inwardly of the liner. The annular chamber 42 is sealed above the lateral bore 16 by the
packer 36 which is a removable packer in this embodiment. The chambers 42, 44 are in
fluid communir~tion around the bottom end 40 of the liner 34 and the second chamber
is in fluid cnmmlmic~tion with the rern~in~l~r of the production casing interior. To
allow fluid collllllunication around the bottom end 40 of the liner 34, the bottom end
must be spaced apart from a floor 46 of the well (see Fig. 1) or a closed lower end 48
of the well casing 22 which is either provided by welding a bottom cover (not shown) to
the casing or by setting a plug (not illustrated) therein. The pressure trap in acculdal~e
2~2675
with the invention is put to use when the pump 26 is to be pulled from the production
casing 22. - -
Prior to the removal of the production tubing 28 and pump 26 combination (see
Figure 1), the well is killed with a well killing fluid (not illustrated) thereby forcing the
5 natural gas liquid back into the cavern with the pressure of the well killing fluid. To
kill the producer well 14, a well killing fluid which has a higher density than the natural -
gas l;quid 30 and is immiscible therewith, in this embodiment water or brine, is pumped
into the production casing 22 through shut-off valve 31 and from supply pipe 25 (see
Fig. 1) until the hydrostatic pressure of the column of liquid in the casing (Lb+Lt) above
10 the bottom end 40 of the liner 34 equals the storage pressure in the cavem 10 (Pc).
Nitrogen can be pumped into the well casing 22 prior to flooding the well with brine.
This will provide additional insurance that all natural gas liquids vapours are forced
downward. The natural gas liquid and vapours are forced down the well into the first,
cylindrical chamber 44, around the bottom 40 of the liner 34 and then travel upward in
the second annular chamber 42 to the entry 17 of and into the lateral bore 16. Once the
last of the natural gas liquids have been pushed into the almular chamber 42, and brine
reaches the bottom end 40 of the liner 34, the well is dead. However, further brine
should be added to force the l~"~ in~ natural gas liquids in the annular chamber 42
back into the cavern 10. This will provide a water seal which is ull~rr~;led by pressure
20 swings in the cavity 10 since the natural gas liquid/brine h.t~,lr~ce 33 in the annular
chamber 42 can move up or down according to a decrease or increase in the cavernpressure without failure to the seal. In order to achieve a most reliable seal, the final
brine level in the first and second charnbers 42, 44 is just below the top of the liner 34.
The natural gas liquid will then be safely contained in the cavern 10. In order to allow
25 the p~ mPnt of a safe water seal at the bottom of the producer well 14 which seal will
permit complete removal of the pump 26 from the killed well without the danger of a
natural gas liquids blowout and without the addition of further well killing fluid, the
volume of the annular chamber 42 is mad~ at least as large as the volume of well killing
fluid displaced by the pump 26 and the production tubing 28. More a~)pru~lialely, the
30 volume of the first chamber 42 is sized such that removing the production tubing 28 and
pump 26 will only allow a small amount of natural gas liquids to enter into the annular
chamber 42. This will not pose a safety threat. Pumping a small amount of additional
210:267~
brine into the production casing, once the pump and tubing combination has been
removed from the casing, sends the natural gas liquids back into the cavern 10.
Furthermore, even if the pressure in the cavern 10 rises due to a pressure transient while
filling the cavern, the volume of brine in the first chamber 42 is sufficiently large to
5 prevent natural gas liquids entering the production casing during workover. The
necess~y volume of the first chamber 42 and the volume of well killing fluid required
can be calculated according to the following pressure trap equilibrium equations.
Pressure Balance Equation
If one assumes that the system is at equilibrium, the pressure balance condition where
10 the hy~usL~Lic pressure in the annular chamber 42 between the production casing 28 and
the liner 34 equates with the hydrostatic pressure inside the production casing and the
liner can be ~f~ s~ed by the following equation:
Pc + Hp-g-Dp + Lp-g Dp + (Lt - Lp) Db-g = Db-Lt g + Lb Db-g (I
Where: g is the metric gravitational constant of 0.00981, Pc denotes the pressure inside
15 the cavern (kPa), Hp is the height of the gas liquid inside the cavern lGr~,lGIlced to the
cavern lateral depth.(m), Dp lepleselll~ the density of the product inside the cavern
(kg/m3), Db is the density of the brine used as the killing fluid (kg/m3), Lp stands for
the length of the natural gas liquids column in the annulus between the production
casing and the liner (m), Lt is the length of the liner (m), and Lb denotes the length of
20 the brine column in the production casing above the packer at the liner top (m).
This can be reduced to:
Lb = Pc/(g Db) + Hp Dp/Db + Lp Dp/Db ~ Lp (II)
Equation II is an expression for the length of the brine column inside the production
casing above the packer 36 at the liner top (Upward is positive).
25 Volume Balance Equation
2 ~
The volume balance condition where the volume of brine in the annular chamber 42between the production casing 22 and the liner 34 balances with the combined volume
of brine and natural gas liquids inside the production casing 22 and the liner 34 can be
expressed as follows:
Lt(Ti 2) + Lbo(Ci2) + Lt(Ci2 - To2) = Lb(Ci2) + Lt(Ti2) + (Lt-Lp) (Ci 2 To2) (III)
It is assumed that the brine volume is fixed and the right half of the equation l~les~
the case where the natural gas liquids are introduced into the annular chamber 42
displacing some of the brine back into the production casing (Both sides have been
divided by PI/4).
10 Ti denotes the internal diameter of the liner 34 (m), Ci is the internal diameter of the
production casing 22 (m), To lel,l.;,elll~ the external diameter of the liner (m), and Lbo
is the original length of the column of brine inside the production casing above the
liner packer 36 when the producer well is killed with brine and the annular chamber 42
between the production casing and the liner is filled with natural gas liquids.
. ,~
15 This reduces to:
.
Lp = (Lb Ci2 - Lbo Ci 2) / (Ci2 - To2) (IV)
b~ Equation II into Equation IV
, . '
Lp = (Pc Ci2/(g Db) + Hp DP Ci2/Db - Lbo Ci2) / (2Ci2 To2 Dp Ci2/Db) (V)
'
Equation V is an ~ res;,;on for the length of the natural gas liquids column in the
annular chamber 42 between the production casing 22 and the liner 34 (Dowll.. rd is
positive). The depth is lcir~lenced to the packer 36 at the liner top.
Lbo = (Pc + Hp g Dp) / (g Db) (VI)
210267a
Although the invention was discussed in detail above with ler~lence to one
pre~erred embodiment only, it will be readily apparent to persons skilled in the art that
certain modifications can be made to the construction of the preferred embodiment
shown in Figure 2 without departing from the scope of the present invention. ForS example~ fluid communication between the first and second chambers 42, 44 need not
n~c.oc~Arily be achieved around the bottom end 40 of the liner 34 below the entry 17 of
the lateral bore 16 but could be provided through openings in the divider wall below the
level of the entry of the lateral bore. The cylindrical liner 34 may be replaced with
other divider means which divide the interior of the production casing 22 at the lateral -
10 bore into the first an second chambers. The chambers may be s~led by a planar or
curved divider wall which is vertically or obliquely positioned in the production casing
22 and ssals off a portion thereof to form a chamber. Communication between that . - -
charnber and the rPmAin~1pr of the production casing 22 can then be achieved by
providing openings or bores in the divider wall below the entry 17 of the lateral bore
15 16. Packers other than the removable packer 36 can be used. Although it is desired to
make the annular chamber 42 suff1ciently large to permit removal of the pump andproduction tubing combination without having to add further well killing fluid, the
combination may be removed in steps with int~rmPdiAte addition of brine, if the
charnber 42 is too small. Brine and water are the preferred well killing fluids, but other
20 fluids known in the art may be used. It will be readily apparent to an art skilled person
that ple~i,~;zed fluids other than natural gas liquids can be stored in the cavern 10.
Furthermore, an art skilled person will ~ ccial~ that a pressure trap in accordd.~ce with
the invention can be used for retrofitting existing producer wells e.lui~l,cd with pressure .
traps installed outside the production casing by placing the liner 34 and packer 36 at an
25 applo~ le level in the casing as desr-ibed above and p-lnrtl-ring the production casing
below the packer 36 to provide a lateral entry for the stored natural gas liquid.
Changes and modifications in the specifically described embodiments can be
carried out without departing from the scope of the invention which is inten-led to be
limited only by the scope of the appended claims.
