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Publication numberUS3627043 A
Publication typeGrant
Publication dateDec 14, 1971
Filing dateJan 17, 1969
Priority dateJan 17, 1969
Publication numberUS 3627043 A, US 3627043A, US-A-3627043, US3627043 A, US3627043A
InventorsBrown William Henry
Original AssigneeBrown William Henry
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Tubing injection valve
US 3627043 A
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Description  (OCR text may contain errors)

United States Patent.

2,144,144 1/1939 Crickmer 166/224 2,293,442 8/1942 Montgomery 166/224 2,773,551 12/1956 Warden et al. 166/75 2,884,067 4/1959 Marken 166/75 3,228,472 H1966 Rhoads, Jr 166/75 Primary Examiner-James A. Leppink Attorney-Ernest Peter Johnson ABSTRACT: An injection valve is provided for admitting inhibiting fluid from the casing annulus. of a gas well into the tubing. The valve consists of a check valve assembly and an elongate, upwardly extending standpipe connecting the valve assembly with a port leading into the tubing. A buffer column of inhibiting fluid is always present [between the valve assembly parts and the corrosive flow within the tubing.

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Patentnd Dec. 14, 1971 2 Sheets-Sheet 2 JI/VENTOR MILL/l)!" HENRY 5194a) TTJBIING INJECTION VALVE FIELD OF INVENTION This invention relates to a valve assembly for use oil wells and to a method for the tubing ofsuch a well.

in gas or introducing inhibiting fluid into PRIOR AM A gas well normally includes, as part of its producing equipment, a string of steel pipe or casing" disposed within the well bore and extending up from the producing rock formation to the ground surface. For example, a string of S-VE-inch outside diameter casing may be suspended from a wellhead in a 7-%-inch well bore. The annular space between the casing and the bore wall is normally filled with cement from the bottom of the well to a point several hundreds or thousands of feet above the production zone. This cement sheath prevents the gas from moving upwardly between the casing and bore wall. Suspended within the casing is an open-ended string of tubing. For example, 2inch or Z-Bh-inch tubing may be suspended within S-Vz-inch casing. The annular space defined between the tubing and casing is commonly referred to as "the casing annulus." The casing and cement sheath are usually perforated at the production zone to enable gas to enter the casing and move into the tubing. In most cases, the tubing carries a production packer which acts to seal off the casing annulus at a point close to but above the perforations. Packing is provided in the wellhead to seal off the upper end of the casing annulus. A valved inlet is provided in the wellhead to provide access into the casing annulus just below this packing. The gas flow, of course, moves up through the tubing to the ground surface and is exhausted therefrom through a valved outlet.

in many wells it is desirable to be able to introduce an inhibiting" fluid into the tubing at a pointjust above the production packer. To clarify the foregoing point, let us consider the case of production wells in a sour gas field. The sour gas contains sulfur in elemental or compound form. When in the production reservoir, this sulphur is dissolved in the gas due to the very high temperature and pressure conditions which prevail there. However, when the sour gas begins to move up through the tubing, its temperature and pressure diminish with the result that sulphur may begin to plate out on the inner surface of the tubing wall. This deposited sulphur gradually builds up. Eventually it plugs the tubing. An expensive cleanout operation must then be carried out. Now, various fluids are known to be helpful in alleviating the problem of sulphur deposition when they are introduced into the gas flow at a point close to the bottom of the well. Two such fluids are gas condensate and carbon disulphide solution. In addition to the injection of sulphur deposition additives to the gas flow, it is also often desirable to inject other inhibiting fluids such as will reduce corrosion of the tubing and formation of hydrates therein.

There are two assemblies commonly used in wells for the injection of inhibiting fluids into the tubing. One involves the provision of a second string of small diameter tubing within the casing. This string is commonly referred to as a macaroni" string. The other assembly involves the provision ofa retrievable valve assembly which controls the opening and closing of a port communicating the casing annulus with the interior of the tubing. These two assemblies and their disadvantages when used within sour gas wells will now be discussed in greater detail.

A macaroni string assembly is illustrated, for example, in US. Pat. No. 2,293,442, issued to Montgomery. A second string of tubing, which might have an outside diameter of 1 inch, extends down from the wellhead to a port which opens into the tubing. A differential pressure-type check valve is disposed at the port to control the entry of fluid therein. Fluid can be pumped into the tubing from the surface.

Use of this assembly involves the use of two tubing strings, a dual wellhead and large casing. These items are expensive. Additionally, there are known difficulties involved in servicing a dual string type of assembly. Finally, the corrosive flow within the tubing attacks the exposed check valve and there is a good possibility that the gas may work its way into the casing annulus, which is a serious problem as will be discussed hcreinbelow.

The retrievable tool assembly involves providing a section of tubing of extra large cross section at the fluid injection point. Parallel nipples extend downwardly from the bottom end of this section. The "main" nipple connects at its bottom end into the remainder of the tubing string. The "side pocket" nipple connects into the main nipple through communicating ports which are located adjacent the bottom ends of the nipples. The side pocket nipple has a slot at its midpoint which communicates with the casing annulus. A retrievable valve tool can be seated, using a wire line, in the side pocket nipple. This tool is provided with packing and valves which act to control the movement of fluid from the casing annulus through the slot and ports into the tubing. Fluid is introduced into the tubing by pumping into the casing annulus and through the tool valves.

There are disadvantages to this assembly when it is used in a sour gas well. Sulfur tends to deposit on top of the tool with the result that the wire line overshot cannot grasp the tools upper end to remove it when required. Furthermore, the raw gas has access to the interior of the tool with the result that the valves become corroded and permit the passage of gas into the casing annulus.

it will have been noted that the importance of preventing raw sour gas from entering the casing annulus has been stressed. This gas is usually highly corrosive. Once in the easing annulus, it may eat through the casing. The formation gas, under enormous pressure, will then have a clear path to the ground surface along the outside of the casing. When this occurs, the well operator is faced with a virtual calamity.

If the gas flow is contained with the tubing, the string can be periodically replaced before corrosion reaches too advanced a condition.

SUMMARY It is an object of this invention to provide a controllable assembly for permitting communication between the casing annulus and the interior of the tubing in a well so that inhibiting fluid can be introduced into the tubing flow, such assembly being particularly well protected from corrosion by the flow. it is another object that this assembly be cheap, simple and long lasting.

it is a further object to provide a valve assembly for controlling communication between the casing annulus and tubing, which is always protected from the tubing flow by a buffer column of inhibiting fluid.

it is another object to provide a new method for introducing inhibiting fluid into the tubing of a gas well at a point adjacent the production packer.

These and other objects are accomplished by the present invention which comprises a normally closed, pressure actuated valve assembly communicating with the casing annulus and connected through a standpipe conduit into the tubing. The valve assembly is adapted to open a permit fluid movement from the casing annulus into the tubing when the annulus is pressured up. At least a segment of the standpipe conduit is substantially vertical and adapted to ensure that an elongate column of inhibiting fluid is always disposed between the tubing flow and the valve assembly. More particularly, the conduit is arranged so that the fluid cannot drain into the tubing with the result that the bufier column is lost. The valve assembly comprises a first valve means, such as a springloaded check valve, and one or more valve means, such as ball check valves, spaced above the first valve means. The valves are connected by conduits, such as nipples, so that a protective column ofliquid extends between them.

By virtue of the foregoing structure, inhibiting fluid may be introduced into the casing annulus to fill and pressure it up to open the valve assembly. Additional fluid may then be pumped into the annulus to force fluid through the valve assembly into the tubing. When the pressure is released, an elongate enclosed column of fluid will be left standing between the tubing opening and the valve assembly to prevent raw gas or other corrosive agents from attacking the assembly.

IN THE DRAWINGS FIG. I is a schematic side view showing the invention as part of the production equipment of a well;

FIG. 2 is a longitudinal sectional view of the spring loaded check valve and two ball check valves;

FIG. 3 is a sectional view showing the tubing opening and the upper end of the standpipe;

FIG. 4 is a partial sectional side'view of an alternative form of the standpipe conduit;

FIG. 5 its sectional top view of the tortuous standpipe conduit bore shown in FIG. 4.

PREFERRED EMBODIMENT Turning now to the embodiment of the invention shown in FIGS. 1 and 2, a string of casing l is shown suspended in a well bore 2. A cement sheath 3 fills the annular space between casing 1 and bore 2. A string of tubing 4 is suspended within casing 1 and a production packer 5 seals off the bottom end of casing annulus 6. Tubing 4 is open ended to permit the flow of gas, emanating from rock formation 7 through perforations 8, to move upwardly. As shown in FIGS. 2 and 3, a standpipe 10 is threaded into opening 9 and a valve assembly 1 l is threaded onto the lower end of standpipe 10.

Valve assembly 11 is comprised of a spring-loaded check valve 12 at its lower end and a plurality of ball check valves I3 threadably connected in series in spaced relation above it.

The inlet of spring-loaded check valve 12 opens into casing annulus 6. The valve itself is conventional in construction and is comprised of the usual housing 13 defining a seat 14 at its bottom end. A ball stem 15 is located within the valve bore 16 and is held against seat 14 by spring 17. Spring 17 is set so that the summation of the pressure within the tubing 4 and the force exerted by the spring 17 is greater than the pressure exerted on bail stem 15 by the hydrostatic head within casing annulus 6. In other words, pressure has to be exerted on the fluid in annulus 6 in order to cause ball stem 15 to lift from seat 14.

The ball check valves 13 are also of conventional design. They comprise a bored housing 18 defining a seat 19 in which a ball 20 is normally seated. These valves act to isolate check valve 12 from the content of standpipe 10. A plurality of them are used in case salt water, which may be produced with the gas, gets into the standpipe, drops through the inhibiting fluid and commences to corrode the top valve. Should the top valve fail, there is still protection afforded to check valve 12 by the remaining check valves 13 and the columns of liquid trapped between them.

Standpipe conduit I0 is shown extending downwardly from threaded opening 10. It provides a column of inhibiting fluid at all times between the valve assembly 11 and the tubing flow. This column should be long enough to ensure isolation; I have successfully used a length of about 8 feet. By intermittently and frequently pressuring up casing annulus 6 and pumping inhibiting fluid into tubing 4, the fluid in standpipe conduit 10 will be frequently changed. To summarize, standpipe conduit 10 retains at all times an enclosed, elongate column of fresh inhibiting fluid extending at least part way between tubing opening 19 and valve assembly 11. This column prevents raw gas flowing through tubing 4 from having access to valve assembly ll. Standpipe conduit 10 is adapted to prevent drainage of this column by gravity into tubing 4.

The standpipe conduit 10 is shown as a single, substantially vertical length. An alternative embodiment comprises a tortuous conduit having a U-shaped segment in it to act as a salt water trap. Such an alternative embodiment is shown in FIGS.

4 and 5.

In this case, a bored block 21 is suitably secured to the exterior surface of tubing 4 (shown in shadow lines). Block 21 defines a conduit having a threaded inlet 24 connected to standpipe 10a. The conduit is formed of upwardly extending leg 26 and a U-shaped section comprised of legs 27 and 28. The legs 26, 27, 28 are connected together and have an outlet 22 opening into tubing 4.

Standpipe conduit 10 and valve assembly 11 are constructed of corrosion-resistant metals. The choosing of such metals will not pose serious problems to those skilled in the art of selection of materials for use in sour gas wells.

The invention will primarily be used in sour gas wells. However, there is nothing to prevent it being used in oil wells for such operations as hot oil treating and chemical injection.

The invention has a number of advantages. It is efiective in protecting the valve assembly from the corrosive agents in the tubing flow. Additionally, in comparison to a macaroni string assembly, it enables one to use larger tubing in casing of a particular size; this results in higher production rates and decreased plugging problems. Finally, it is a simple, cheap structure whose use enables a well operator to make large savings on the well equipment used in conjunction with it.

What I claim as my invention is:

l. A valve assembly, adapted to be used in a well equipped with casing, tubing, and a production packer carried on said tubing adjacent its lower end to seal off the annular space defined between the casing and tubing, said annular space above the packer being filled with fluid, and said tubing defining an opening in its wall at a point above the packer,

said valve assembly comprising:

normally closed first valve means-disposed within the annular space and adapted to open when the pressure within the annular space adjacent the valve means substantially exceeds the pressure within the tubing, said valve means having an inlet communicating the annular space;

one or more normally closed valve means disposed in spaced relation above the first valve means and adapted to open and close when the first valve means opens and closes;

a conduit, connecting each pair of adjacent valve means,

wherein a column offluid can extend between them; and an upward extending standpipe conduit defining a tortuous bore having a U-shaped segment, said conduit connecting the upper most valve means with the tubing opening and providing means wherein a column of fluid can extend at least part way between the said valve means and opening; said valve means and conduits combining to provide an assembly, for controlling communication from the annular space into the tubing, wherein the valve parts can be protected from the tubing flow by columns of fluid trapped thereinabove.

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Referenced by
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US7994101 *Dec 12, 2006Aug 9, 2011Halliburton Energy Services, Inc.treating a metal surface with an aqueous solution containing triphenylphosphine, triethylphosphine, or trimethylphosphine; treating subterranean formations, inhibition of metal corrosion in acidic environments; corrosion resistance
US7994102 *Apr 1, 2008Aug 9, 2011Baker Hughes IncorporatedMethod of treating an alloy surface with an alkyl sarcosinate
US8058211Dec 12, 2007Nov 15, 2011Halliburton Energy Services, Inc.Corrosion inhibitor intensifier compositions and associated methods
US8357640 *May 25, 2011Jan 22, 2013Baker Hughes IncorporatedMethod of inhibiting corrosion with an alkyl sarcosinate
US20110224111 *May 25, 2011Sep 15, 2011D V Satyanarayana GuptaBiodegradable anionic acid corrosion inhibitor comprising sarcosines
U.S. Classification166/325, 417/115
International ClassificationE21B43/12, E21B41/02, E21B41/00
Cooperative ClassificationE21B43/123, E21B41/02
European ClassificationE21B43/12B2C, E21B41/02