Method of producing wells without plugging of tubing string

July 23, 1968 chiang-hai kuo etal 3,393,733

METHOD OF PRODUCING WELLS WITHOUT PLUGGING OF TUBING STRING

Filed Aug. 22, 1966 2 Sheets-Sheet 1

VAPOR TO _ STORAGE 54

23b

23α

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18α 18-. I7&lt;V I2&lt;S ’WSS

HEAT EXCHANGER ^21²'° 35a>

W² 35

II —

<img file="US3393733A_D0002.tif" />

31b

H,S+HC

31α —51

51α

COMPRESSOR

MOISTURE K ABSORBER

<img file="US3393733A_D0003.tif" />

52b h—31

48α

HEATER

SEPARATOR &lt;48b -48

43α

TO EXCESS CS₂ STORAGE

<img file="US3393733A_D0004.tif" />

CS₂CONVERTER

FIG. I ixi-* SCRUBBER

39b

39α

COMPRESSOR b

40α

<img file="US3393733A_D0005.tif" />

40c

COMPRESSOR

HC

FLASH CHAMBER

EXCESS H₂S TO SULPHUR RECOVERY PLANT

INVENTORS: CHIANG-HAI KUO PHILIP J. CLOSMANN ^BT W W THEIR AGENT

July 23, 1968 chiang-hai kuo etal 3,393,733

METHOD OF PRODUCING WELLS WITHOUT PLUGGING OF TUBING STRING

Filed Aug. 22, 1966 2 Sheets-Sheet 2

<img file="US3393733A_D0006.tif" />

FIG. 2 »000 r- AMOUNT of SULFUR PRECI PITATION

<img file="US3393733A_D0007.tif" />

1000 2000 3000 4000 5000

BOTTOM HOLE PRESSURE

FIG. 3

INVENTORS: CHIANG-HAI KUO PHILIP J. CLOSMANN ^BV:

THEIR AGENT

United States Patent Office p_atenled J/S

3,393,733

METHOD OF PRODUCING WELLS WITHOUT PLUGGING OF TUBING STRING

Chiang-hai Kuo and Philip J. Closmann, 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. 166—8)

The present invention relates to a method of prevent- χθ ing 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 30 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 preven- 35 tion 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 40 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 7080% hydrogen sulfide. Accordingly, prior art methods, such as the application of heat to prevent hydrate plugging, 45 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 5θ 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 additional- ^1,1ly 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 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 hy5 drate 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 15 production well. Still another object of the present invention is to recover sulfur from producing fluids from underground formations which fluids are hydrogen sulfide rich hydrocarbons cqntaining sulfur and possibly water, without causing plugging of the equipment used 20 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 25 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/or 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 70-95% hydrogen sulfide rich hydrocarbon mixture, can be used as the injecting 60 anti-plugging 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.

3,393,733

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. FIGURE 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 perforations 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 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 18 through valved lines 23, 23α 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, 23α and 23b 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 23α, 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 31α while keeping the valve 3U 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 temperature-pressure 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 80% 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 100° 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 40α 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 39α and into line 39b and then forcing the recycled sour gas through flasher 39, lines 40, 40α into

3,393,733 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 48α closed, or indirectly through compressor 33 which is in communication with heater 44 by valved lines 48 and 32 in which case the valve 32α in line 32 and valve 35α 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 43α 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 between 450 and 700° F. 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 51α 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 100-120° 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 36 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.