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Publication numberUS3393733 A
Publication typeGrant
Publication dateJul 23, 1968
Filing dateAug 22, 1966
Priority dateAug 22, 1966
Publication numberUS 3393733 A, US 3393733A, US-A-3393733, US3393733 A, US3393733A
InventorsChiang-Hai Kuo, Closmann Philip J
Original AssigneeShell Oil Co
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Method of producing wells without plugging of tubing string
US 3393733 A
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Description  (OCR text may contain errors)

y 23, 96 CH lANG-HAI KUO ETAL 3,393,733

METHOD OF PRODUCING WELLS WITHOUT PLUGG'ING OF TUBING STRING Filed Aug. 22, 1966 v 2 Shets-Sheet 2 soLualLm or suLrun I II RESERVOH! runo moors:

' SOLHIIILHVI or sul r ua mu m I E 4 cu 'av O vc:

' I I '1 l 1 1100 I20. JIM I60 I60 200 220 Y, .TEIPERATURE,'"F

m mm or- 5mm mcmnnon SULFUR DEPOSITION; LII 56F 0 I l 1 1 WM 200 300 400 500 B0110! HOLE PRESSURE FIG. 3

INVENTORS CHlANG-HAI KUO PHI IP J. CLOSMANN BY g THEIR AGENT United States Patent METHOD OF PRODUCING WELLS WITHQUT PLUGGING 0F TUBING STRING Chiang-hai Kuo and Philip J. Closmauu, Houston, Tex.,

assignors to Shell Oil Company, New York, N.Y., a corporation of Delaware Filed Aug. 22, 1966, Ser. No. 573,961

6 Claims. (Cl. 1668) The present invention relates to a method of preventing hydrate formation and/or sulfur deposition in the production tubing strings of deep wells, such as are used, for example, in the production of underground oil and gas formations rich in sulfur-containing mixtures of hydrogen sulfide and hydrocarbons. More particularly, the present invention relates to the recovery of sulfur from underground formations in which substantial amounts of elemental sulfur are dispersed in the hydrogen sulfide rich hydrocarbon production zone and at the same time preventing hydrate formation and sulfur depositions in the production tubing string of the producing wells.

It is well recognized by those familiar with oil well production techniques that as the produced fluid flows upwardly through the tubing string certain pressure-temperature conditions may occur such that a phenomenon known as fluid flashing results. The phenomenon of fluid flashing is accompanied by a severe temperature drop and pressure decrease which cause the sudden formation of hydrates that plug the tubing string to the extent that production is substantially reduced, or in many cases, completely prevented.

In most wells the aforementioned hydrates form only at the lower temperatures reached at the upper end of the tubing string. Consequently, in the past, the prevention of hydrate formation has been controlled by the application of heat to the upper end of the tubing string thereby keeping the temperature above the critical level. However, hydrates occur at much higher temperatures in fluids containing hydrogen sulfide than in the production of normal hydrocarbon fluids and, as a result, may plug the tubing string at great depths. For example, hydrates can occur at 120 F. in a fluid containing 70- 80% hydrogen sulfide. Accordingly, prior art methods, such as the application of heat to prevent hydrate plugging, are impractical and ineffective in the production of fluids containing substantial amounts of hydrogen sulfide since there is no effective and economical Way to transmit the amount of heat required to the great depths at which such plugging occurs. The problem becomes even more critical when elemental sulfur is present in fluids such as hydrogen sulfide-hydrocarbon mixtures containing above 50% and generally between 70% and 95% hydrogen sulfide. With fluids of this type their recovery from a producing zone and to the surface is additionally complicated by the tendency of sulfur to deposit throughout the length of the tubing string irrespective of the aforementioned hydrate problems associated with the production of these fluids. As a sulfur-containing hydrogen sulfide-hydrocarbon fluid flows upwardly through the tubing string the pressure on the fluid decreases due to the reduction of the static head in the fluid column. The temperature also tends to decrease. Under these changed pressure-temperature conditions the solubility of Patented July 23, 1968 sulfur in the fluid decreases markedly and tends to come out of solution and crystallize along the tubing string casing, thus causing plugging of the tubing string. Plugging of the tubing string in the production well by hydrate formation and/or sulfur deposition can become so severe as to cause stoppage of the recovery of fluids from the production well, serious economic losses due to work stoppage, replacement of equipment damaged by these formations and loss of recovery of the production fluid or components and derivatives thereof.

An object of the present invention is to produce fluids from underground recovery zones rich in hydrogen sulfide containing water and having dissolved therein sulfur without causing plugging of the tubing string in the production well. Still another object of the present invention is to recover sulfur from producing fluids from underground formations which fluids are hydrogen sulfi-de rich hydrocarbons cqntaining sulfur and possibly water, without causing plugging of the equipment used in the recovery system. Another object of the present invention is to separate from the recovery fluid without plugging the equipment, and after the sulfur has been removed, other components from said fluids, namely the hydrogen sulfide and hydrocarbons and using a portion of said components under specific conditions as antiplugging injection agents in the tubing string of the producing well. Other objects of the present invention will be apparent from the description of the present invention.

Broadly stated, the invention resides in preventing plugging of the tubing string of a production well by sulfur and/0r hydrate formation which comprises injecting, through an injection tubing string in communication With the production tubing string, into the tubing string of the producing well at a predetermined level above the producing zone, an essentially elemental sulfur-free and water-free hot fluid at an elevated pressure and temperature so as to blend the injection fluid with the upward flow of the recovery fluid in the tubing string thereby keeping the sulfur in solution and preventing plugging of the production tubing string by sulfur precipitation or hydrate formation. Specifically, the hot injecting fluid is injected into the tubing string column containing the recovery fluid at a depth and heat-injection rate that are correlated with the temperature gradient in the columnar stream so as to maintain a minimum temperature of above 100 F, to maintain sulfur in a fluid soluble state, to aid in dissolving any sulfur precipitated below the point of injection and to maintain conditions which inhibit hydrate formation. The injecting fluid is one which is miscible with the recovery fluid flowing up the tubing string and is obtained from the reservoir fluid in the producing zone after it has passed through the tubing string of the production well to a surface location at a pressure exceeding atmospheric pressure by dehydrating it, if necessary, thermally converting the dehydrated fluid to a hot fluid from which sulfur is wholly or in part removed. The hot fluid thus obtained, which is essentially a 95% hydrogen sulfide rich hydrocarbon mixture, can be used as the injecting antiplugging fluid or such a fluid can be further processed by enriching the hydrogen sulfide content of the mixture or converting the hydrogen sulfide fluid to suitable derivatives such as hydrogen persulfides or to carbon disulfide and these fluids used as the injecting fluids to prevent plugging of the tubing string.

The elemental sulfur can be recovered from the production fluid at a surface location by various suitable means and the sulfur-free fluid separated therefrom can be heated, compressed and injected into the production stream as described, or the hot sulfur-free fluid can be treated in various ways such as by physical and/ or chemical separation and/ or modification and these fluids when heated are used as the anti-plugging injection fluids. Thus, the sulfur-containing hydrogen sulfide-hydrocarbon fluid from the reservoir production zone can be pumped to a surface location, where, if necessary, it is dehydrated by flowing the produced fluid through a moisture absorber containing drying agents such as calcium chloride, copper sulfate and the like. The dehydrated fluid is passed through a preheater so as to prevent sulfur separation and passed to a separator wherein the pressure and temperature are so controlled as to cause separation of the sulfur from the fluid, recycling the sulfurfree or sulfur-reduced fluid to the preheater, where it is compressed and thereafter injected into the tubing string at a depth and heat-injection rate correlating with the temperature gradient in the columnar stream so that the temperature is above about 100 F. and the sulfur is kept in a dissolved state. Instead of recycling the essentially sulfur-free fluid directly to the preheater and compressor and into the tubing string, the essentially sulfur-free fluid can be either sent to a heat exchanger maintained between 450 and 700 F. wherein any sulful in the fluid reacts with hydrogen sulfide to form hydrogen persulfides which may be used as the anti-plugging injection fluid or the essentially sulfur-free fluid can be sent to a scrubber to recover the hydrocarbons from the hydrogen sulfide using conventional scrubbing liquids, e.g., aqueous amine solutions and the hydrogen sulfide fluid sent to a flasher to separate the scrubbing solution from hydrogen sulfide which can be converted wholly or in part to carbon disulfide and used as the hot anti-plugging injection fluid.

The accompanying drawings are supplied for the purpose of illustrating and not limiting the invention. FIG- URE 1 shows a vertical section of a production Well and tubing string into which is injected anti-plugging injection fluid and a flow diagram for a sulfur recovery system. FIGURE 2 relates to solubility of sulfur in reservoir fluid relative to temperature conditions in the reservoir, and FIGURE 3 relates to the tendency of sulfur to precipitate in tubing strings relative to the bottom hole pressure.

With reference to FIGURE 1, there is shown a vertical section of strata 11 penetrated by production well 12 at ground level 22 passing through producing zone 13. The producing zone 13 is not limited to being sandwiched between spaced layers of impermeable strata 14 but may be contained by other types of layers which form effective confining barriers for producing zone 13.

The well bore 12 of a typical well bore construction is shown having well casing 15 positioned in the bore and secured with cement 16. Producing well casing 15 is closed with gland 17 and is provided with a tubing string 18 extending down casing 15 to a point adjacent the producing zone 13. A conventional sealing packer 19 is positioned in the lower end of casing 15 to close the casing-tubing annulus and stabilize the lower end of the tubing string 18 which extends through the packer 19 to the lower portion of casing 15 which has perfora tions 20 to allow fluids from producing zone 13 to enter casing 15 and flow upwards through tubing string 18. The sealing packer 19 is preferably positioned at or near the upper level of the producing zone to prevent fluid communication between fluid being produced from the producing zone and the interior portion of the casing 15 located above the packer 19. Tubing string 21 extends downwardly from above the casing cover member or gland 17 to a location generally slightly above packer 19 where it communicates with the interior of producing tubing string 18. The hot miscible injecting fluid is introduced into producing tubing string 18 through injection tubing string 21 at a point slightly above packer 19 at a temperature above about 100 F. and pressure sufficiently high to drive the production fluid upward and keep the sulfur in the production fluid dissolved therein.

The hot miscible injection fluid used to prevent plugging of tubing string 18 is derived from the fluids obtained from the production zone 13 on reaching ground level 22 through tubing string 18. One system for distributing and using these fluids is the following. These injection fluids are pumped from tubing string 13 through valved lines 23, 23a and 23b (while closing valved line 24) and through a moisture absorber 26 into valved line 25 in communication with a preheater 27 or, alternatively, by closing valved line 23 and passing the hot fluid directed to preheater 27 through valved line 24 if the producing fluids are essentially devoid of moisture.

However, if the producing fluid contains moisture it is preferable that it be first dehydrated by passing the fluids through valved lines 23, 23a and 2311 through a moisture absorber or dehydration unit 26 containing conventional drying agents such as calcium chloride, copper sulfate and the like, and the dehydrated fluids are then passed through line 25 into preheater 27. Vapors are recovered through line segments 23a, 23b and valved line 54. The preheated dehydrated fluids pass through valved line 28 at about 100 F. into a separator 29 wherein the sulfur is separated from the hydrogen sulfidehydrocarbon mixture by suitable means such as using a cyclone separator or dropping the pressure in separator 29 to below 2000 p.s.i. while raising the temperature from about 100 F. to 200 F. or higher.

The sulfur is removed through line 30 and the hydrogen sulfide-hydrocarbon mixture is passed through open valved lines 31 and 31a while keeping the valve 311) closed to the preheater 27 where the fluid mixture is heated to above 100 F. and through valved line 32 to compressor 33 and injected into injection tubing string 21 which is in communication with compressor 33 through line 34. The elemental sulfur-free fluid injected into tubing string 18 is injected at a temperature above 100 F. and at a minimum pressure of 50-200 p.s.i.

The temperaturepressure conditions to insure maximum efficiency for the producing fluids from recovery zones without sulfur plugging can be determined by reference to FIGURE 2 which shows the solubility of sulfur at different pressures and temperatures in a reservoir fluid containing about hydrogen sulfide and if the reservoir fluid is initially saturated with elemental sulfur, then the amount of sulfur which will precipitate in the tubing string can be determined by the graph curves shown in FIGURE 3 when the wellhead is kept at 2000 p.s.i. and F.

Instead of passing the sulfur-free hydrogen sulfide-hydrocarbon mixture from the separator 29 back to the preheater 27 and thereafter compressing the fluid mixture and using it as the anti-plugging injection fluid, the sulfur-free hydrogen sulfide-hydrocarbon fluid can be passed from separator 29 through valved line 35 into scrubber 36 where the sulfur-free fluid mixture is scrubbed by conventional means, such as treating with aqueous amine solutions, to remove acid gases from the hydrocarbon gases, which gases are removed through line 37 for conventional processing, such as sweetening, and the acid gases are removed through valved line 38 into a flash chamber 39 Where hydrogen sulfide is passed through line 40 and valved line 40a while keeping valved line 40b closed. Alternatively, the acid gases can be recycled from the flasher 39 through line 40 and valved line 40b while keeping valve 40c closed through compressor 39a and into line 39/) and then forcing the recycled sour gas through flasher 39, lines 40, 40a into Compressor 41 where a portion of the compressed hydrogen sulfide is recovered by being passed through line 42 to storage or sulfur recovery not shown. Another portion of the compressed hydrogen sulfide is passed through valved line 43, keeping valved line 45 closed, into heater 44 where the hot compressed hydrogen sulfide is passed directly to injection line 34 through valved line 48 and line 35, while keeping valve 48a closed, or indirectly through compressor 33 which is in communication with heater 44 by valved lines 48 and 32 in which case the valve 32a in line 32 and valve 35a should be closed. Injection line 34 is in communication with injection tubing string 21 and the hot hydrogen sulfide-containing fluid is thereby injected into tubing string 18. Also a portion of the compressed hydrogen sulfide from compressor 41 can be by-passed through valved line 45 into carbon disulfide convertor 46 and blended with hydrogen sulfide from line 43 which is in communication with valved line 47 connected to carbon disulfide convertor 46 and the mixture passed through heater 44 and into lines 48, 32 or through lines 48 and 35 to line 34 connected directly or indirectly to injection tubing string 21. Also the hydrogen sulfide valved line 43 can be bypassed by closing valve 43a and the carbon disulfide formed in convertor 46 passed directly to heater 44 and into line 34 directly through line 35 or indirectly through lines 48 and 32 and compressor 33 and into injection tubing string 21 and used as the hot anti-plugging fluid injected under pressure into tubing string 18. Still another injection fluid can be obtained by directing the essentially sulfur-free hydrogen sulfide fluid from the separator 29 into heat exchanger 49 maintained bet-ween 450 and 700 P. which is in communication with separator 29 by valved line 31, keeping valved line 35 closed wherein hydrogen persulfides are formed and the hot hydrogen persulfide injected into the injection tubing string 21 through valved line 51 in communication with compressor 33 and line 34. Also heat to separator 29 can be supplied from the heat exchanger 49 by closing valve 51a and passing the hot gas through lines 51 and valved line 52 in communication with valved line 28.

The separation of elemental sulfur from the recovery mixture can be accomplished by various other means such as by absorption, water quenching and the like and the elemental sulfur-free recovery fluid heated and used as the anti-plugging injection fluid as described.

The method of preventing plugging of tubing strings in a producing well through which a recovery fluid containing elemental sulfur dissolved in about 75-80% hydrogen sulfide, 13-18% hydrocarbons and the remaining constituents being moisture, carbon dioxide, etc., is illustrated by the following example. From a producing zone a recovery fluid of the composition indicated was forced upwardly through the perforations in the production well casing and up the tubing string by the bottomhole pressure at the producing zone. Into the tubing string at a point slightly above the packer which is positioned in the upper portion of the producing zone a sulfur-free miscible fluid obtained from the production zone after the sulfur has been removed and comprising a compressed mixture of about 80% hydrogen sulfide and about 20% hydrocarbons was injected into the recovery fluid at about l-l20 F. and at a pressure of about 2000 p.s.i. and at a rate so as to blend readily with the upward recovery fluid stream. The sulfur was removed from the recovery fluid by heating said fluid to above 100 F. and forcing said fluid into a separator where the temperature is kept at about 200 F. and the pressure dropped to about 1600 p.s.i. causing essentially all of the sulfur to separate out of solution. The sulfur-free hydrogen sulfide-hydrocarbon mixture was reinjected under pressure into the production tubing string. Successful operation of a production well under these conditions was accomplished without hydrate formation or sulfur plugging of the tubing string or other equipment in the recovery system. Also, when the hydrocarbons are separated from the hydrogen sulfide-hydrocarbon mixture in scrubber 3'6 and flasher 39 and the compressed hydrogen sulfide and/or carbon disulfide used as the anti-plugging injection fluid, the rate of injection can be cut considerably due to the greater solubility of sulfur in such hot fluids. Vaporous components in the recovery fluid are removed through line 54 to storage, not shown.

We claim as our invention:

1. In a method of preventing hydrate formation and sulfur plugging in tubing string of a production well which extends from ground level to an underground producing zone for the production of a sulfur-containing fluid from said zone, said method comprising:

(a) flowing said sulfur-containing fluid from the producing zone upwardly through said production tubing string; and,

( b) injecting into said production tubing string, through an injection tubing string in communication with said production tubing string, at a point Where sul- 'fur and hydrate deposition in the tubing string tend to form due to temperature and pressure drop in the tubing string, a hot sulfur-free fluid miscible with sulfur, said fluid being at a temperature above about F. and at a pressure sufiicient to prevent sulfur precipitation and solidification on the tubing string wall.

2. The method of claim 1 wherein the hot injection fluid is a sulfur-free compressed hydrogen sulfide-hydrocanbon fluid mixture of which 70-80% of said mixture is liquid hydrogen sulfide.

3. The method of claim 1 wherein the hot injection fluid is a sulfur-free carbon disulfide-hydrocarbon mixture miscible with the sulfur-containing fluid flowing upwardly through the production tubing string to ground level.

4. The method of claim 1 including the step of separating above ground level sulfur and water from the remaining production recovery fluid.

5. In a method of preventing hydration formation and sulfur plugging in tubing string of a production well which extends from ground level to an underground producing zone and is in communication with a sulfur-containing hydrogen sulfide-hydrocarbon fluid and recovering separately the sulfur and a mixture of hydrogen sulfide and hydrocarbon fluid, said method comprising:

(a) flowing a sulfur-containing hydrogen sulfide-hydrocarbon fluid mixture of which 70-80% is hydrogen sulfide from the producing zone upwardly through the production tubing string while maintaining pressure and temperature in the producing zone suflicient to accomplish this;

(b) dehydrating and then heating said fluid mixture at above ground level to above 100 F.;

(c) forcing said heated fluid mixture into a separator where the temperature and pressure are maintained at about 200 F. and 1600 p.s.i. thereby causing the sulfur to precipitate and separate from the fluid mixture and separating the precipitated sulfur from the hydrogen sulfide-hydrocarbon mixture;

(d) reheating and compressing the sulfur-free hydrogen sulfide-hydrocarbon mixture; and

(e) injecting a hot sulfur-free fluid selected from the group consisting of the hydrogen sulfide-hydrocarbon mixture and the compressed hydrogen sulfide fluid into the sulfur-containing fluid stream flowing upwardly in the production tubing string, said sulfurfree mixture being injected, through an injection tubing string in communication with the production tubing string at above about 100 F. and under pressure sufficient to keep the sulfur in the sulfur-containing fluid in solution.

6. The method of claim 5 wherein a portion of the sulfur-free hydrogen sulfide in the hydrogen sulfide-hydrocarbon mixture is converted to carbon disulfide and the resulting sulfur-free carbon disulfide-containing fluid is used as the hot injecting fluid.

References Cited UNITED STATES PATENTS OTHER REFERENCES Kennedy, Harvey T., et al.: Equilibrium in the Meth- Frasch 299 5 aneCarbon Dioxide-Hydrogen Sulfide-Suliur Systcm, in Blumenberg 229 5 J. Petroleum Technology, July 1960, pp. 166- 169.

Nor a 166-41 X 2 299 5 X CHARLES E. OCONNELL, Primary Examiner. Monroe 2995 10 IAN A. CALVERT, Assistant Examiner.

Bond et al. 166-8

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Referenced by
Citing PatentFiling datePublication dateApplicantTitle
US3504741 *Jun 27, 1968Apr 7, 1970Mobil Oil CorpUnderwater production satellite
US3531160 *Sep 18, 1968Sep 29, 1970Phillips Petroleum CoProduction of sour gas-sulfur wells employing a sulfur solvent
US3796265 *Jun 7, 1972Mar 12, 1974Eickmeier JMethod for producing high hydrogen sulfide content gas wells
US4017120 *Nov 28, 1975Apr 12, 1977The Dow Chemical CompanyProduction of hot brines from liquid-dominated geothermal wells by gas-lifting
US4033410 *Feb 20, 1976Jul 5, 1977Shell Oil CompanyMonoethanolamine process for sulfur removal from circulating oil used in sour gas wells
US4230184 *Dec 1, 1978Oct 28, 1980Shell Oil CompanySulfur extraction method
US4248717 *May 29, 1979Feb 3, 1981Standard Oil Company (Indiana)Method for removing elemental sulfur from high temperature, high pressure wells and flow lines
US4290900 *May 29, 1979Sep 22, 1981Standard Oil Company (Indiana)Method and composition for removing elemental sulfur from high temperature, high pressure wells and flow lines
US4322307 *Jul 21, 1980Mar 30, 1982Mobil Oil CorporationProcess for alleviating sulfur deposition in sour gas wells
US4896725 *Jun 13, 1988Jan 30, 1990Parker Marvin TIn-well heat exchange method for improved recovery of subterranean fluids with poor flowability
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US7426959Apr 19, 2006Sep 23, 2008Shell Oil CompanySystems and methods for producing oil and/or gas
US7601320Apr 19, 2006Oct 13, 2009Shell Oil CompanySystem and methods for producing oil and/or gas
US7654322Aug 11, 2008Feb 2, 2010Shell Oil CompanySystems and methods for producing oil and/or gas
US7926561Oct 30, 2008Apr 19, 2011Shell Oil CompanySystems and methods for producing oil and/or gas
US8097230Jul 5, 2007Jan 17, 2012Shell Oil CompanyProcess for the manufacture of carbon disulphide and use of a liquid stream comprising carbon disulphide for enhanced oil recovery
US8136590May 17, 2007Mar 20, 2012Shell Oil CompanySystems and methods for producing oil and/or gas
US8136592Aug 8, 2007Mar 20, 2012Shell Oil CompanyMethods for producing oil and/or gas
US8394180Feb 14, 2008Mar 12, 2013Shell Oil CompanySystems and methods for absorbing gases into a liquid
US8430161May 19, 2009Apr 30, 2013Bp Corporation North America Inc.Mitigation of elemental sulfur deposition during production of hydrocarbon gases
US8459368Apr 25, 2007Jun 11, 2013Shell Oil CompanySystems and methods for producing oil and/or gas
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US8656997Apr 14, 2009Feb 25, 2014Shell Oil CompanySystems and methods for producing oil and/or gas
US8722006May 14, 2007May 13, 2014Shell Oil CompanyProcess for the manufacture of carbon disulphide
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Classifications
U.S. Classification166/267, 299/5, 299/7, 166/303, 166/310
International ClassificationE21B43/00, C09K8/532, E21B43/34, E21B43/28, C09K8/52
Cooperative ClassificationE21B43/281, E21B43/34, C09K8/532
European ClassificationC09K8/532, E21B43/28B, E21B43/34