CA2120675C - Cavern well pressure trap - Google Patents
Cavern well pressure trapInfo
- Publication number
- CA2120675C CA2120675C CA002120675A CA2120675A CA2120675C CA 2120675 C CA2120675 C CA 2120675C CA 002120675 A CA002120675 A CA 002120675A CA 2120675 A CA2120675 A CA 2120675A CA 2120675 C CA2120675 C CA 2120675C
- Authority
- CA
- Canada
- Prior art keywords
- well
- casing
- lateral bore
- entry
- chamber
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Expired - Lifetime
Links
- 239000012530 fluid Substances 0.000 claims abstract description 67
- 238000003860 storage Methods 0.000 claims abstract description 32
- 238000007789 sealing Methods 0.000 claims abstract description 16
- 238000004891 communication Methods 0.000 claims abstract description 9
- 238000000034 method Methods 0.000 claims abstract description 8
- 238000004519 manufacturing process Methods 0.000 claims description 48
- 230000002706 hydrostatic effect Effects 0.000 claims description 7
- 238000005086 pumping Methods 0.000 claims description 7
- 229910000831 Steel Inorganic materials 0.000 claims description 3
- 239000010959 steel Substances 0.000 claims description 3
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 description 66
- 239000007788 liquid Substances 0.000 description 44
- 239000003345 natural gas Substances 0.000 description 34
- 239000012267 brine Substances 0.000 description 31
- HPALAKNZSZLMCH-UHFFFAOYSA-M sodium;chloride;hydrate Chemical compound O.[Na+].[Cl-] HPALAKNZSZLMCH-UHFFFAOYSA-M 0.000 description 31
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 description 22
- 238000002347 injection Methods 0.000 description 8
- 239000007924 injection Substances 0.000 description 8
- 230000001681 protective effect Effects 0.000 description 6
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 description 5
- 239000007789 gas Substances 0.000 description 5
- 229930195733 hydrocarbon Natural products 0.000 description 5
- 150000002430 hydrocarbons Chemical class 0.000 description 5
- 235000002639 sodium chloride Nutrition 0.000 description 4
- 239000004215 Carbon black (E152) Substances 0.000 description 3
- 230000015572 biosynthetic process Effects 0.000 description 3
- 229910001873 dinitrogen Inorganic materials 0.000 description 3
- 238000005755 formation reaction Methods 0.000 description 3
- 239000000446 fuel Substances 0.000 description 3
- 238000003780 insertion Methods 0.000 description 3
- 230000037431 insertion Effects 0.000 description 3
- 150000003839 salts Chemical class 0.000 description 3
- 230000004323 axial length Effects 0.000 description 2
- 230000005484 gravity Effects 0.000 description 2
- 238000012986 modification Methods 0.000 description 2
- 230000004048 modification Effects 0.000 description 2
- 238000009420 retrofitting Methods 0.000 description 2
- KHOITXIGCFIULA-UHFFFAOYSA-N Alophen Chemical compound C1=CC(OC(=O)C)=CC=C1C(C=1N=CC=CC=1)C1=CC=C(OC(C)=O)C=C1 KHOITXIGCFIULA-UHFFFAOYSA-N 0.000 description 1
- 238000013459 approach Methods 0.000 description 1
- 230000000903 blocking effect Effects 0.000 description 1
- 244000309464 bull Species 0.000 description 1
- 238000010276 construction Methods 0.000 description 1
- 238000005260 corrosion Methods 0.000 description 1
- 230000007797 corrosion Effects 0.000 description 1
- 238000005553 drilling Methods 0.000 description 1
- 239000003673 groundwater Substances 0.000 description 1
- 238000010438 heat treatment Methods 0.000 description 1
- 238000009434 installation Methods 0.000 description 1
- 229910052757 nitrogen Inorganic materials 0.000 description 1
- 230000035515 penetration Effects 0.000 description 1
- 239000011435 rock Substances 0.000 description 1
- 239000003566 sealing material Substances 0.000 description 1
- 239000000243 solution Substances 0.000 description 1
- 230000001052 transient effect Effects 0.000 description 1
- 238000003466 welding Methods 0.000 description 1
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/30—Specific pattern of wells, e.g. optimising the spacing of wells
- E21B43/305—Specific pattern of wells, e.g. optimising the spacing of wells comprising at least one inclined or horizontal well
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
- E21B43/121—Lifting well fluids
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21F—SAFETY DEVICES, TRANSPORT, FILLING-UP, RESCUE, VENTILATION, OR DRAINING IN OR OF MINES OR TUNNELS
- E21F17/00—Methods or devices for use in mines or tunnels, not covered elsewhere
- E21F17/16—Modification of mine passages or chambers for storage purposes, especially for liquids or gases
Landscapes
- Engineering & Computer Science (AREA)
- Mining & Mineral Resources (AREA)
- Life Sciences & Earth Sciences (AREA)
- Geology (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- Filling Or Discharging Of Gas Storage Vessels (AREA)
- Earth Drilling (AREA)
Abstract
A pressure trap for a producer well of a subterranean pressurized fluid storage system, the well being lined with a casing having a casing interior connected with a subterranean pressurized fluid storage cavity through a lateral bore, includes a divider for dividing off a chamber from a lower portion of the casing interior which chamber communicates with and 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 remainder of the casing interior and below the entry of the lateral bore. The divider is preferably a combination of a cylindrical liner having upper and lower ends respectively positioned above and below the entry of the lateral bore, and an annular packer sealing between the liner and the well casing above the entry of the lateral bore. Methods of providing a pressure trap and sealing a producer well are also disclosed. The pressure trap can be installed at lower cost, as a retrofit in existing casings, or as a backup to failed conventional arrangement installed outside the well casing.
Description
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.
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.
Claims (17)
1. A pressure trap for a producer well, the well being lined with a well casing having a casing interior connected with a pressurized fluid cavity through a lateral bore, comprising a divider means for dividing off a chamber from a lower portion of the casing interior which chamber communicates with and 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 remainder of the casing interior and below the entry of the lateral bore.
2. A pressure trap as defined in claim 1, wherein the pressurized fluid cavity is part of a subterranean pressurized fluid storage system.
3. A pressure trap as defined in claim 1, wherein the divider means includes a divider wall for dividing off the chamber from the interior 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.
4. A pressure trap as defined in claim 1, wherein the passage is positioned sufficiently below the entry of the lateral bore such that a volume of the chamber below the entry of the lateral bore and above a level of the passage is at least as large as a volume of a well killing fluid displaced by a pressurized fluid pumping arrangement suspendible in the well.
5. A pressure trap as defined in claim 1, wherein the divider means includes a cylindrical liner having upper and lower ends respectively positioned above and below the entry of the lateral bore and a sealing means positioned between the cylindrical liner and the well casing above the entry of the lateral bore.
6. A pressure trap as defined in claim 4, wherein the passage means is provided by positioning the lower end of the liner spaced apart from one of a group consisting of a bottom of the well, a closed bottom of the well casing, and a plug in the well casing.
7. A pressure trap as defined in claim 5, wherein a length of the liner between the entry of the lateral bore and the lower end is selected such that a volume of the chamber between the entry of the lateral bore and the bottom end of the liner is at least as large a volume of well killing fluid displaced by a pressurized fluid pumping arrangement suspendible in the well.
8. A pressure trap as defined in claim 4, wherein the cylindrical liner is a steel tube and the sealing means is an annular removable packer.
9. A pressure trap as defined in claim 7, wherein the cylindrical liner is coaxially positioned in the well casing.
10. A pressure trap as defined in claim 8, wherein an inner diameter of the liner is larger than an outer diameter of a pressurized fluid pump suspendible in the well casing.
11. A pressure trap as defined in claim 9, wherein a length of the liner between the entry of the lateral bore and the lower end is selected such that a volume of the chamber between the entry of the lateral bore and the bottom end of the liner is at least as large as a volume of well killing fluid displaced by a pressurized fluid pumping arrangement suspendible in the well.
12. A pressure trap as defined in claim 1, wherein the passage is at least one opening provided in the divider means.
13. A method of providing a pressure trap for a producer well, the well being lined with a well casing having a casing interior communicating with a pressurized fluid cavity through a lateral bore, comprising 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 extending to a level below the entry of the lateral bore, and providing a passage for fluid communication between the chamber and a remainder of the production casing and at a selected level below the entry of the lateral bore.
14. A method as defined in claim 13, whrein the pressurized fluid cavity is part of a subterranean pressurized fluid storage system.
15. A method as defined in claim 13, wherein the step of dividing includes the steps of dividing the interior of the well casing at the entry of the lateral bore with a divider into an annular outer chamber and an inner cylindrical chamber, the outer chamber being connected with the lateral bore and extending to a selected level below the entry of the lateral bore and the further step of sealing the outer chamber between the divider and the well casing and above the entry of the lateral bore.
16. A method as defined in claim 14, wherein the step of providing a passage includes positioning a lower end of the divider spaced apart from one of a bottom end of the well, a closed bottom of the well casing and a plug in the well casing.
17. A method of sealing a producer well of a subterranean pressurized fluid storage system, the well being lined with a well casing having a casing interiorcommunicating with a pressurized fluid storage cavity through a lateral bore, comprising the steps of providing a pressure trap as defined in claim 2 and filling the producer well with a well killing fluid having a higher density than and being immiscible with a pressurized fluid stored in the cavity and to a level where a hydrostatic pressure of the column of well killing fluid in the well casing above the passage for fluid communication is equal to the pressure of the pressurized fluid in the cavity.
Priority Applications (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA002120675A CA2120675C (en) | 1994-04-06 | 1994-04-06 | Cavern well pressure trap |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA002120675A CA2120675C (en) | 1994-04-06 | 1994-04-06 | Cavern well pressure trap |
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| CA2120675A1 CA2120675A1 (en) | 1994-08-29 |
| CA2120675C true CA2120675C (en) | 1998-01-06 |
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| CA002120675A Expired - Lifetime CA2120675C (en) | 1994-04-06 | 1994-04-06 | Cavern well pressure trap |
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| CN107842392A (en) * | 2017-10-31 | 2018-03-27 | 清华大学 | A kind of salt cave caisson |
| CN107905844B (en) * | 2017-10-31 | 2019-06-25 | 中国科学院武汉岩土力学研究所 | Halogen method is arranged in salt mine old chamber Quan Caidong space gas injection |
| CN111520133B (en) * | 2019-02-01 | 2023-07-28 | 中国石油化工股份有限公司 | Method for determining hole volume in stratum |
| CN117722233A (en) * | 2023-11-23 | 2024-03-19 | 中能建数字科技集团有限公司 | Capacity expansion method for reconstructing salt cavern into energy storage warehouse |
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Effective date: 20140407 |