CA1207269A - Method of treating oil field produced fluids with chlorine dioxide - Google Patents
Method of treating oil field produced fluids with chlorine dioxideInfo
- Publication number
- CA1207269A CA1207269A CA000425969A CA425969A CA1207269A CA 1207269 A CA1207269 A CA 1207269A CA 000425969 A CA000425969 A CA 000425969A CA 425969 A CA425969 A CA 425969A CA 1207269 A CA1207269 A CA 1207269A
- Authority
- CA
- Canada
- Prior art keywords
- oil
- chlorine dioxide
- fluids
- field produced
- produced fluids
- 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
Links
- OSVXSBDYLRYLIG-UHFFFAOYSA-N dioxidochlorine(.) Chemical compound O=Cl=O OSVXSBDYLRYLIG-UHFFFAOYSA-N 0.000 title claims abstract description 74
- 239000004155 Chlorine dioxide Substances 0.000 title claims abstract description 35
- 235000019398 chlorine dioxide Nutrition 0.000 title claims abstract description 35
- 239000012530 fluid Substances 0.000 title claims abstract description 35
- 238000000034 method Methods 0.000 title claims abstract description 19
- 238000000926 separation method Methods 0.000 claims description 6
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 abstract description 30
- 239000000126 substance Substances 0.000 abstract description 21
- 238000011084 recovery Methods 0.000 abstract description 12
- 239000000839 emulsion Substances 0.000 abstract description 10
- 238000011282 treatment Methods 0.000 abstract description 10
- RWSOTUBLDIXVET-UHFFFAOYSA-N Dihydrogen sulfide Chemical compound S RWSOTUBLDIXVET-UHFFFAOYSA-N 0.000 abstract description 9
- 229910000037 hydrogen sulfide Inorganic materials 0.000 abstract description 9
- 239000002245 particle Substances 0.000 abstract description 7
- 239000010802 sludge Substances 0.000 abstract description 7
- MBMLMWLHJBBADN-UHFFFAOYSA-N Ferrous sulfide Chemical compound [Fe]=S MBMLMWLHJBBADN-UHFFFAOYSA-N 0.000 abstract description 6
- 239000007787 solid Substances 0.000 abstract description 6
- 230000003115 biocidal effect Effects 0.000 abstract description 5
- 239000003139 biocide Substances 0.000 abstract description 5
- 239000007864 aqueous solution Substances 0.000 abstract description 3
- 238000005352 clarification Methods 0.000 abstract description 2
- 239000002516 radical scavenger Substances 0.000 abstract description 2
- 230000002441 reversible effect Effects 0.000 abstract description 2
- 239000003921 oil Substances 0.000 description 47
- 229940099041 chlorine dioxide Drugs 0.000 description 27
- 230000015572 biosynthetic process Effects 0.000 description 20
- 238000005755 formation reaction Methods 0.000 description 20
- 230000008901 benefit Effects 0.000 description 8
- XEEYBQQBJWHFJM-UHFFFAOYSA-N Iron Chemical compound [Fe] XEEYBQQBJWHFJM-UHFFFAOYSA-N 0.000 description 6
- 239000010779 crude oil Substances 0.000 description 5
- 238000004519 manufacturing process Methods 0.000 description 5
- 230000001580 bacterial effect Effects 0.000 description 4
- 241000894006 Bacteria Species 0.000 description 3
- 229910052742 iron Inorganic materials 0.000 description 3
- QGZKDVFQNNGYKY-UHFFFAOYSA-N Ammonia Chemical compound N QGZKDVFQNNGYKY-UHFFFAOYSA-N 0.000 description 2
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 description 2
- VTYYLEPIZMXCLO-UHFFFAOYSA-L Calcium carbonate Chemical compound [Ca+2].[O-]C([O-])=O VTYYLEPIZMXCLO-UHFFFAOYSA-L 0.000 description 2
- NINIDFKCEFEMDL-UHFFFAOYSA-N Sulfur Chemical compound [S] NINIDFKCEFEMDL-UHFFFAOYSA-N 0.000 description 2
- 239000005864 Sulphur Substances 0.000 description 2
- OSGAYBCDTDRGGQ-UHFFFAOYSA-L calcium sulfate Chemical compound [Ca+2].[O-]S([O-])(=O)=O OSGAYBCDTDRGGQ-UHFFFAOYSA-L 0.000 description 2
- 239000003054 catalyst Substances 0.000 description 2
- 239000003795 chemical substances by application Substances 0.000 description 2
- 239000007789 gas Substances 0.000 description 2
- 238000011065 in-situ storage Methods 0.000 description 2
- 229940090044 injection Drugs 0.000 description 2
- 238000002347 injection Methods 0.000 description 2
- 239000007924 injection Substances 0.000 description 2
- 235000014413 iron hydroxide Nutrition 0.000 description 2
- NCNCGGDMXMBVIA-UHFFFAOYSA-L iron(ii) hydroxide Chemical compound [OH-].[OH-].[Fe+2] NCNCGGDMXMBVIA-UHFFFAOYSA-L 0.000 description 2
- 231100000614 poison Toxicity 0.000 description 2
- 230000007096 poisonous effect Effects 0.000 description 2
- 230000000638 stimulation Effects 0.000 description 2
- BHMLFPOTZYRDKA-IRXDYDNUSA-N (2s)-2-[(s)-(2-iodophenoxy)-phenylmethyl]morpholine Chemical compound IC1=CC=CC=C1O[C@@H](C=1C=CC=CC=1)[C@H]1OCCNC1 BHMLFPOTZYRDKA-IRXDYDNUSA-N 0.000 description 1
- 240000002129 Malva sylvestris Species 0.000 description 1
- 235000006770 Malva sylvestris Nutrition 0.000 description 1
- 229920001131 Pulp (paper) Polymers 0.000 description 1
- 208000036366 Sensation of pressure Diseases 0.000 description 1
- 238000010795 Steam Flooding Methods 0.000 description 1
- 230000002730 additional effect Effects 0.000 description 1
- 150000001335 aliphatic alkanes Chemical class 0.000 description 1
- 150000001336 alkenes Chemical class 0.000 description 1
- 150000001345 alkine derivatives Chemical class 0.000 description 1
- 229910021529 ammonia Inorganic materials 0.000 description 1
- 238000004061 bleaching Methods 0.000 description 1
- 239000006227 byproduct Substances 0.000 description 1
- 229910000019 calcium carbonate Inorganic materials 0.000 description 1
- 230000000711 cancerogenic effect Effects 0.000 description 1
- 231100000315 carcinogenic Toxicity 0.000 description 1
- 230000008859 change Effects 0.000 description 1
- 235000013351 cheese Nutrition 0.000 description 1
- 150000008280 chlorinated hydrocarbons Chemical class 0.000 description 1
- 238000004140 cleaning Methods 0.000 description 1
- 238000005345 coagulation Methods 0.000 description 1
- 230000015271 coagulation Effects 0.000 description 1
- 150000001875 compounds Chemical class 0.000 description 1
- 230000008030 elimination Effects 0.000 description 1
- 238000003379 elimination reaction Methods 0.000 description 1
- 239000002360 explosive Substances 0.000 description 1
- 239000003925 fat Substances 0.000 description 1
- 238000005188 flotation Methods 0.000 description 1
- 235000013312 flour Nutrition 0.000 description 1
- 230000002401 inhibitory effect Effects 0.000 description 1
- 229910052500 inorganic mineral Inorganic materials 0.000 description 1
- 230000002147 killing effect Effects 0.000 description 1
- 239000007788 liquid Substances 0.000 description 1
- 230000007246 mechanism Effects 0.000 description 1
- 239000011707 mineral Substances 0.000 description 1
- 230000004048 modification Effects 0.000 description 1
- 238000012986 modification Methods 0.000 description 1
- 229910052757 nitrogen Inorganic materials 0.000 description 1
- 230000003647 oxidation Effects 0.000 description 1
- 238000007254 oxidation reaction Methods 0.000 description 1
- 229940086255 perform Drugs 0.000 description 1
- 150000002989 phenols Chemical class 0.000 description 1
- 229920000642 polymer Polymers 0.000 description 1
- 239000002244 precipitate Substances 0.000 description 1
- 150000003139 primary aliphatic amines Chemical class 0.000 description 1
- 230000008569 process Effects 0.000 description 1
- 238000005086 pumping Methods 0.000 description 1
- 230000009467 reduction Effects 0.000 description 1
- 239000003340 retarding agent Substances 0.000 description 1
- 239000004576 sand Substances 0.000 description 1
- 239000008247 solid mixture Substances 0.000 description 1
- 239000000243 solution Substances 0.000 description 1
Landscapes
- Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
Abstract
METHOD OF TREATING OIL FIELD PRODUCED
FLUIDS WITH CHLORINE DIOXIDE
ABSTRACT
In the recovery of oil from wells, the oil re-covered from the wells is combined with other fluids and particles, including water, chemicals and solids.
Disclosed herein is a method for treating the other fluids and particles by preparing an aqueous solution of chlorine dioxide and injecting the chlorine dioxide into the other fluids and particles. The chlorine di-oxide functions as an emulsion breaker, as a reverse emulsion breaker for water clarification, as a bio-cide to oxidize iron sulfide, as a sludge oil treatment and a hydrogen sulfide scavenger.
FLUIDS WITH CHLORINE DIOXIDE
ABSTRACT
In the recovery of oil from wells, the oil re-covered from the wells is combined with other fluids and particles, including water, chemicals and solids.
Disclosed herein is a method for treating the other fluids and particles by preparing an aqueous solution of chlorine dioxide and injecting the chlorine dioxide into the other fluids and particles. The chlorine di-oxide functions as an emulsion breaker, as a reverse emulsion breaker for water clarification, as a bio-cide to oxidize iron sulfide, as a sludge oil treatment and a hydrogen sulfide scavenger.
Description
~7~69 METHOD OF TREATING OIL FIELD PRODUCED
FLUIDS WITH CHLORINE DIOXIDE
BACKGROUND Ox THE INVENTION
Field of the Invention The present invention relates to a method for treating oll field produced fluids with chlorine diox-ide and, mure particularly, to an inexpensive and effic-ient method for treating oil field produced fluids with one multifunction chemical.
ln Descrlption of the Prior Art In the production of crude oil from wells various techniques are used and these techniques are generally categorized as primary, secondary, and tertiary When a well is first drilled, there i5 often significant pres-sure so that the crude oil freely flows. This is thefirst primary recovery technique. Primary recovery also encompasses situations where even though there is in-sufficient pressure for the crude oil to flow freely, it is readily available in the formation and can be pumped through the well bore using any one of the well known and available types of pumping mechanisms.
Most formations are only initially susceptible to primary recovery methods because the formation is somewhat like a wet sponge and it is necessary to apply a force to 12~7;~9 l
FLUIDS WITH CHLORINE DIOXIDE
BACKGROUND Ox THE INVENTION
Field of the Invention The present invention relates to a method for treating oll field produced fluids with chlorine diox-ide and, mure particularly, to an inexpensive and effic-ient method for treating oil field produced fluids with one multifunction chemical.
ln Descrlption of the Prior Art In the production of crude oil from wells various techniques are used and these techniques are generally categorized as primary, secondary, and tertiary When a well is first drilled, there i5 often significant pres-sure so that the crude oil freely flows. This is thefirst primary recovery technique. Primary recovery also encompasses situations where even though there is in-sufficient pressure for the crude oil to flow freely, it is readily available in the formation and can be pumped through the well bore using any one of the well known and available types of pumping mechanisms.
Most formations are only initially susceptible to primary recovery methods because the formation is somewhat like a wet sponge and it is necessary to apply a force to 12~7;~9 l
-2-the oi'l within the formation to drive it to the well bore.
Various techniques have been used to enhance recovery past that which is possible through normal well pressures and these techniques are collectively referred to as "secondary recovery The most common of these tech-niques is water flooding where water is pumped into other wells surrounding the main well so that the water applies a pressure to the oil to help drive the oil to the main well. It is evident that both water and oil are pumped out oE the well.
Steam stimulation (steam flooding) and the injec-tion of various chemicals into the formation are tech-ni~ues generally used in reservoirs of high viscosity oil. These techniques, which are collectively reEerred to as "tertiary recovery"/ are intended to change the mobility (viscosity) of the oil in the formation so that the oil moves more readily to the producing well. Steam stimulation, for example, involves iniection into the well of steam at high temperatures (approximately 500F) in cycles of thousands of cubic meters at a time. The quality of this steam generally ranges from 60 to 80%, meaning that large quantities of liquid water are con-currently injected into the well bore with the-steam.
In any event, water or chemicals are included with the 2S oil that is extracted from the well.
A large number of problems result from the use of massive quantities of water and/or chemicals in the production of crude oil from wells. One of the problems is that of bacterial growth. There are various forms of bacteria in the water which, if not controlled, mul-ti-ply rapidly producing hydrogen sulfide and plugging agents which are both highly corrosive and poisonous.
Another problem results from the need to separate the oil from the water and solids in the produced fluid.
This generally requires the addition of an emulsion breaker to the water/oil/solid mixture. In addition, after the water and oil are separated, it is necessary to clean iL2~72~9 the water and pump back into the formation at least as much water as the amount of oil taken out of the formation to maintain the integrity of the formation and to keep the ground from subsiding. It is not accept-able to pump dirty water back into the formation becauseit will plug up the ace of the formation and inhibit production from the producing well. A secondary reason for cleaning the water prior to reinjecti~n is to inhibit bacterial growth.
Another problem encountered in oil recovery stems from the fact that solids (sand, silt, scale,etc.) also cove out of the formation and are pumped out of the well with the oil. The hydrogen sulfide discussed previously reacts with the iron in the pipes to form iron sulfide which, together with the oil and solids,forms a sludge which ouls the water treating equipment.
another problem is the creation of scale. The dissolved minerals in water precipitate out, creating a deposit and plugging the pipes.
The above problems encountered in the recovery of oil from wells are well known. The existing solutions involve the treatment of each of the problems separately with different chemicals. Some chemicals are used for emulsion breaking, others are used as a biocide to in-hibit bacterial growth others are used for oxidation of the iron sulfide, others are used for sludge oil treatment and others are used for the elimination of hydrogen sulfide. It can be appreciated that the result is a significant cost in the treatment of oil field produced fluids.
~IL207;~
SUMMARY OF THE INVENTION
According to the present invention, these problems are solved by treating oil field produced fluids with a single, multifunction chemical. This chemical can per-form many functions that no other can by itself. Theresult is that proper treatment is achieved at a much lower cost and is much more effective than previous conventional treatments. The single multifunction chemical separates oil and water, prevents formation of sludge and scale, and produces a larger quantity of stable water which can be injected into the formation.
According to the present invention, the chemical used is chlorine dioxide prepared in situ. When used to treat oil field produced Eluids, chlorine dioxide lS functions as an emulsion breaker, as a reverse emulsion breaker for water clarification, as a biocide, to oxidize iron sulfide, as a sludge oil treatment and a hydrogen sulfide scavenger.
~'7~6~
OBJECTS, FEATURES AND ADVANTAGES
It is therefore an object of the present invention to solve the problems encountered heretofore in the treatment of oil field produced fluids. It is a feature 5 of the present invention to solve these problems by treating oil field produced fluids with chlorine dioxide.
An advantage to be derived is the ability to treat oil field produced fluids with one multifunction chemical.
Another advantage is a reduction in the cost of treating oil field produced fluids. Still another advantage is a chemical which will function as an emulsion breaker.
Stil1 another advantage is a chemical which will function to prevent the formation of sludge and scale. Another advantage is a chemical which will produce a large quantity Oe stable water which can be injected into a formation Another advantage is a chemical which will function as a biocide. Another advantage is a chemical which will eliminate hydrogen sulfide.
Still other objects, features and attendant advan-tages of the present invention will become apparent to those skilled in the art from a reading of the following detailed description of the preferred embodiment in accordance therewith.
26~
DESCRIPTION Ox THE PREFERRED EMBODIMENT
In primary, secondary and tertiary recovery of oil from wells, the oil is combined with other fluids and particles, including water, chemicals and solids, and it is necessary to treat the oil field produced fluids for the various reasons discussed hereinbefore.
It is the teaching of the present invention to treat oil field produced fluids with chlorine dioxide.
Chlorine dioxide is known as a biocide and it has found use in the bleaching of wood pulp, fats, oils and flour.
One use of chlorine dioxide as an effective spoilage retarding agent Eor cheeses is described in U.S. patent No. 3,147,124.
Chlorine dioxide i5 customarily prepared in an aqueous solution since, as a gasl it is unstable and, under certain conditions, explosive. Because of its instability, it is generally prepared in situ and used immediately. One method of making stabilized chlorine dioxide is described in U.S. patent No. 2,701,781. Another method of preparing chlorine dioxide suitable for use in the present invention is described in U S. patent Mo. 3,754,079.
It is this inventor's belief that chlorine di-oxide has not been used heretofore in the treatment of oil field produced fluids. It is the teaching of the present invention to inject chlorine dioxide into the water or other oil field produced fluids before and/or after the first stage of the oil/other fluids separa-tion process. Additional quantities of chlorine di-oxide could be injected in subsequent stages of theseparation process, if desired. The chlorine dioxide would be prepared in an aqueous solution and simply added to the oil field produced fluids. When so added, the chlorine dioxide performs multiple functions.
-~C)7~6~
The first vessel downstream of the injection point is typically a clarifier where oil is floated to the top of the vessel and skimmed off In this stage, the chlorine dioxide functions as an emulsion breaker, separating the emulsion and allowing the oil to float to the top more effectively. Furthermore, the chlorine dioxide will react with any iron sulfide to form sulphur and iron hydroxide so that the oil recovered from the clarifier will not be contaminated with iron sulfideO
Both sulphur and iron hydroxide will simply settle to the bottom of the clarifier tank or they will be picked up by subsequent filters.
Still further, chlorine dioxide will kill bacteria, inhibiting the generation of hydrogen sulfide. By killing bacteria, chlorine dioxide will prevent the generation oE slime (plugging agent) so that the oil recovered from the clarifier will he much cleaner and equipment fouling will be mitigated. PreviPusly/ oil reçovered from a clarifier was so contaminated that it was dumped, the sole function of the clarifier being to clean the water.
Now, the oil recovered from the clarifier may be salable.
From the clarifier, water typically goes to a floatation unit where gas i5 bubbled up through the water to help float particles to the top where they are skimmed off At this point in the separation process, the chlorine dioxide will keep the blades of the flotation unit free from slime and help in the coagulation of the suspended particles. That is, the chlorine dioxide will assist in bringing the suspended particles together, making them larger and increasing the efficiency of the separators which remove the solids from the water.
Chlorine dioxide impedes the formation of scale by reacting with iron sulfide. Thus, the iron sulfiae is no longer available to coprecipitate with calcium carbonate and calcium sulfate to form the scale deposit. Also, by reacting with hydrogen sulfide, chlorine dioxide elimin-ates what is otherwise a corrosive and poisonous gas ~2~26g In tertiary recovery, chlorine dioxide finds addi-tional use by being injected even before the first stage of the separation process since it will function to break the emulsions which form in polymer flooding to simplify the separation process.
It is very important in -the treatment of oil field produced fluids that the chemical(s) added will not react with oil and other elements which are found in the oil production process. Chlorine dioxide will not react with most of the components of crude oil and also will not react with ammonia, nitrogen, alkanes, alkenes, alkynes, primary aliphatic amines and unsubsti-tuted aromatics. This eliminates the formation of chlorin-ated hydrocarbons that are carcinogenic and will foul re~iner~ catalysts. Chlorine dioxide will, on the other hand, destroy phenolic compounds that can foul reEinery catalysts. As a result of using chlorine dioxide to treat oil field produced fluids, there is no undesirable build up of conventional chemicals or byproducts. After 2~ reacting completely, only innocuous compounds will remain It can therefore be seen that in accordance with the teachings of the present invention, the problems encountered heretofore in treating oi-l field produced fluids are solved by treating such fluids, in any stage of the recovery process, with one multifunction chemical, namely, chlorine dioxide. Chlorine dioxide separates the oil from the other fluids, prevents the formation of sludge and scale, impedes bacterial growth, scavenges hydrogen sulfide and produces large quantities of stable water which can now be injected back into the formation.
While the invention has been described with respect to the preferred embodiment constructed in accordance therewith, it will be apparent to those skilled in the art that various modifications and improvements may be made without departing from the scope and spirit of the invention. Accordingly, it is to be understood that the invention is not to be limited by the specific ~Z~7Z69 illustrative embodimentt but only by the scope of the appended claims.
Various techniques have been used to enhance recovery past that which is possible through normal well pressures and these techniques are collectively referred to as "secondary recovery The most common of these tech-niques is water flooding where water is pumped into other wells surrounding the main well so that the water applies a pressure to the oil to help drive the oil to the main well. It is evident that both water and oil are pumped out oE the well.
Steam stimulation (steam flooding) and the injec-tion of various chemicals into the formation are tech-ni~ues generally used in reservoirs of high viscosity oil. These techniques, which are collectively reEerred to as "tertiary recovery"/ are intended to change the mobility (viscosity) of the oil in the formation so that the oil moves more readily to the producing well. Steam stimulation, for example, involves iniection into the well of steam at high temperatures (approximately 500F) in cycles of thousands of cubic meters at a time. The quality of this steam generally ranges from 60 to 80%, meaning that large quantities of liquid water are con-currently injected into the well bore with the-steam.
In any event, water or chemicals are included with the 2S oil that is extracted from the well.
A large number of problems result from the use of massive quantities of water and/or chemicals in the production of crude oil from wells. One of the problems is that of bacterial growth. There are various forms of bacteria in the water which, if not controlled, mul-ti-ply rapidly producing hydrogen sulfide and plugging agents which are both highly corrosive and poisonous.
Another problem results from the need to separate the oil from the water and solids in the produced fluid.
This generally requires the addition of an emulsion breaker to the water/oil/solid mixture. In addition, after the water and oil are separated, it is necessary to clean iL2~72~9 the water and pump back into the formation at least as much water as the amount of oil taken out of the formation to maintain the integrity of the formation and to keep the ground from subsiding. It is not accept-able to pump dirty water back into the formation becauseit will plug up the ace of the formation and inhibit production from the producing well. A secondary reason for cleaning the water prior to reinjecti~n is to inhibit bacterial growth.
Another problem encountered in oil recovery stems from the fact that solids (sand, silt, scale,etc.) also cove out of the formation and are pumped out of the well with the oil. The hydrogen sulfide discussed previously reacts with the iron in the pipes to form iron sulfide which, together with the oil and solids,forms a sludge which ouls the water treating equipment.
another problem is the creation of scale. The dissolved minerals in water precipitate out, creating a deposit and plugging the pipes.
The above problems encountered in the recovery of oil from wells are well known. The existing solutions involve the treatment of each of the problems separately with different chemicals. Some chemicals are used for emulsion breaking, others are used as a biocide to in-hibit bacterial growth others are used for oxidation of the iron sulfide, others are used for sludge oil treatment and others are used for the elimination of hydrogen sulfide. It can be appreciated that the result is a significant cost in the treatment of oil field produced fluids.
~IL207;~
SUMMARY OF THE INVENTION
According to the present invention, these problems are solved by treating oil field produced fluids with a single, multifunction chemical. This chemical can per-form many functions that no other can by itself. Theresult is that proper treatment is achieved at a much lower cost and is much more effective than previous conventional treatments. The single multifunction chemical separates oil and water, prevents formation of sludge and scale, and produces a larger quantity of stable water which can be injected into the formation.
According to the present invention, the chemical used is chlorine dioxide prepared in situ. When used to treat oil field produced Eluids, chlorine dioxide lS functions as an emulsion breaker, as a reverse emulsion breaker for water clarification, as a biocide, to oxidize iron sulfide, as a sludge oil treatment and a hydrogen sulfide scavenger.
~'7~6~
OBJECTS, FEATURES AND ADVANTAGES
It is therefore an object of the present invention to solve the problems encountered heretofore in the treatment of oil field produced fluids. It is a feature 5 of the present invention to solve these problems by treating oil field produced fluids with chlorine dioxide.
An advantage to be derived is the ability to treat oil field produced fluids with one multifunction chemical.
Another advantage is a reduction in the cost of treating oil field produced fluids. Still another advantage is a chemical which will function as an emulsion breaker.
Stil1 another advantage is a chemical which will function to prevent the formation of sludge and scale. Another advantage is a chemical which will produce a large quantity Oe stable water which can be injected into a formation Another advantage is a chemical which will function as a biocide. Another advantage is a chemical which will eliminate hydrogen sulfide.
Still other objects, features and attendant advan-tages of the present invention will become apparent to those skilled in the art from a reading of the following detailed description of the preferred embodiment in accordance therewith.
26~
DESCRIPTION Ox THE PREFERRED EMBODIMENT
In primary, secondary and tertiary recovery of oil from wells, the oil is combined with other fluids and particles, including water, chemicals and solids, and it is necessary to treat the oil field produced fluids for the various reasons discussed hereinbefore.
It is the teaching of the present invention to treat oil field produced fluids with chlorine dioxide.
Chlorine dioxide is known as a biocide and it has found use in the bleaching of wood pulp, fats, oils and flour.
One use of chlorine dioxide as an effective spoilage retarding agent Eor cheeses is described in U.S. patent No. 3,147,124.
Chlorine dioxide i5 customarily prepared in an aqueous solution since, as a gasl it is unstable and, under certain conditions, explosive. Because of its instability, it is generally prepared in situ and used immediately. One method of making stabilized chlorine dioxide is described in U.S. patent No. 2,701,781. Another method of preparing chlorine dioxide suitable for use in the present invention is described in U S. patent Mo. 3,754,079.
It is this inventor's belief that chlorine di-oxide has not been used heretofore in the treatment of oil field produced fluids. It is the teaching of the present invention to inject chlorine dioxide into the water or other oil field produced fluids before and/or after the first stage of the oil/other fluids separa-tion process. Additional quantities of chlorine di-oxide could be injected in subsequent stages of theseparation process, if desired. The chlorine dioxide would be prepared in an aqueous solution and simply added to the oil field produced fluids. When so added, the chlorine dioxide performs multiple functions.
-~C)7~6~
The first vessel downstream of the injection point is typically a clarifier where oil is floated to the top of the vessel and skimmed off In this stage, the chlorine dioxide functions as an emulsion breaker, separating the emulsion and allowing the oil to float to the top more effectively. Furthermore, the chlorine dioxide will react with any iron sulfide to form sulphur and iron hydroxide so that the oil recovered from the clarifier will not be contaminated with iron sulfideO
Both sulphur and iron hydroxide will simply settle to the bottom of the clarifier tank or they will be picked up by subsequent filters.
Still further, chlorine dioxide will kill bacteria, inhibiting the generation of hydrogen sulfide. By killing bacteria, chlorine dioxide will prevent the generation oE slime (plugging agent) so that the oil recovered from the clarifier will he much cleaner and equipment fouling will be mitigated. PreviPusly/ oil reçovered from a clarifier was so contaminated that it was dumped, the sole function of the clarifier being to clean the water.
Now, the oil recovered from the clarifier may be salable.
From the clarifier, water typically goes to a floatation unit where gas i5 bubbled up through the water to help float particles to the top where they are skimmed off At this point in the separation process, the chlorine dioxide will keep the blades of the flotation unit free from slime and help in the coagulation of the suspended particles. That is, the chlorine dioxide will assist in bringing the suspended particles together, making them larger and increasing the efficiency of the separators which remove the solids from the water.
Chlorine dioxide impedes the formation of scale by reacting with iron sulfide. Thus, the iron sulfiae is no longer available to coprecipitate with calcium carbonate and calcium sulfate to form the scale deposit. Also, by reacting with hydrogen sulfide, chlorine dioxide elimin-ates what is otherwise a corrosive and poisonous gas ~2~26g In tertiary recovery, chlorine dioxide finds addi-tional use by being injected even before the first stage of the separation process since it will function to break the emulsions which form in polymer flooding to simplify the separation process.
It is very important in -the treatment of oil field produced fluids that the chemical(s) added will not react with oil and other elements which are found in the oil production process. Chlorine dioxide will not react with most of the components of crude oil and also will not react with ammonia, nitrogen, alkanes, alkenes, alkynes, primary aliphatic amines and unsubsti-tuted aromatics. This eliminates the formation of chlorin-ated hydrocarbons that are carcinogenic and will foul re~iner~ catalysts. Chlorine dioxide will, on the other hand, destroy phenolic compounds that can foul reEinery catalysts. As a result of using chlorine dioxide to treat oil field produced fluids, there is no undesirable build up of conventional chemicals or byproducts. After 2~ reacting completely, only innocuous compounds will remain It can therefore be seen that in accordance with the teachings of the present invention, the problems encountered heretofore in treating oi-l field produced fluids are solved by treating such fluids, in any stage of the recovery process, with one multifunction chemical, namely, chlorine dioxide. Chlorine dioxide separates the oil from the other fluids, prevents the formation of sludge and scale, impedes bacterial growth, scavenges hydrogen sulfide and produces large quantities of stable water which can now be injected back into the formation.
While the invention has been described with respect to the preferred embodiment constructed in accordance therewith, it will be apparent to those skilled in the art that various modifications and improvements may be made without departing from the scope and spirit of the invention. Accordingly, it is to be understood that the invention is not to be limited by the specific ~Z~7Z69 illustrative embodimentt but only by the scope of the appended claims.
Claims (3)
1. A method of treating oil field produced fluids comprising the step of:
treating said fluids with chlorine dioxide.
treating said fluids with chlorine dioxide.
2. A method according to Claim 1, wherein said step of treating said fluids with chlorine dioxide comprises:
injecting said chlorine dioxide into said oil field produced fluids prior to the first oil/fluid separa-tion stage.
injecting said chlorine dioxide into said oil field produced fluids prior to the first oil/fluid separa-tion stage.
3. A method according to Claim 1 or 2, wherein said step of treating said fluids comprises:
injecting said chlorine dioxide into said oil field produced fluids subsequent to the first oil/fluid separation stage.
injecting said chlorine dioxide into said oil field produced fluids subsequent to the first oil/fluid separation stage.
Applications Claiming Priority (2)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US40195382A | 1982-07-26 | 1982-07-26 | |
| US401,953 | 1982-07-26 |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA1207269A true CA1207269A (en) | 1986-07-08 |
Family
ID=23589946
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA000425969A Expired CA1207269A (en) | 1982-07-26 | 1983-04-15 | Method of treating oil field produced fluids with chlorine dioxide |
Country Status (2)
| Country | Link |
|---|---|
| CA (1) | CA1207269A (en) |
| MX (1) | MX162439A (en) |
Cited By (9)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US4945992A (en) * | 1986-12-22 | 1990-08-07 | Sacco Frank J | Process for producing or cleaning high pressure water injection wells |
| US5082576A (en) * | 1989-03-21 | 1992-01-21 | Bp Chemicals Limites | Removal of sulfides using chlorite and an amphoteric ammonium betaine |
| US5707546A (en) * | 1991-06-17 | 1998-01-13 | Rio Linda Chemical Co., Inc. | Generation and storage of chlorine dioxide in a non-aqueous medium |
| US7563377B1 (en) | 2005-03-03 | 2009-07-21 | Chemical, Inc. | Method for removing iron deposits in a water system |
| US8609594B2 (en) | 2011-03-22 | 2013-12-17 | Sabre Intellectual Property Holdings Llc | Chlorine dioxide precursor and methods of using same |
| US20140014349A1 (en) * | 2013-04-24 | 2014-01-16 | Sabre Intellectual Property Holdings Llc | Fracturing operations employing chlorine dioxide |
| US9238587B2 (en) | 2013-03-15 | 2016-01-19 | Sabre Intellectual Property Holdings Llc | Method and system for the treatment of water and fluids with chlorine dioxide |
| US20160280988A1 (en) * | 2015-03-24 | 2016-09-29 | Baker Hughes Incorporated | Application of chlorine dioxide to subsurface wells |
| US10442711B2 (en) | 2013-03-15 | 2019-10-15 | Sabre Intellectual Property Holdings Llc | Method and system for the treatment of produced water and fluids with chlorine dioxide for reuse |
-
1983
- 1983-04-15 CA CA000425969A patent/CA1207269A/en not_active Expired
- 1983-06-13 MX MX19763783A patent/MX162439A/en unknown
Cited By (17)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US4945992A (en) * | 1986-12-22 | 1990-08-07 | Sacco Frank J | Process for producing or cleaning high pressure water injection wells |
| US5082576A (en) * | 1989-03-21 | 1992-01-21 | Bp Chemicals Limites | Removal of sulfides using chlorite and an amphoteric ammonium betaine |
| US5707546A (en) * | 1991-06-17 | 1998-01-13 | Rio Linda Chemical Co., Inc. | Generation and storage of chlorine dioxide in a non-aqueous medium |
| US7563377B1 (en) | 2005-03-03 | 2009-07-21 | Chemical, Inc. | Method for removing iron deposits in a water system |
| US8703656B2 (en) | 2011-03-22 | 2014-04-22 | Sabre Intellectual Property Holdings Llc | Chlorine dioxide precursor and methods of using same |
| US8609594B2 (en) | 2011-03-22 | 2013-12-17 | Sabre Intellectual Property Holdings Llc | Chlorine dioxide precursor and methods of using same |
| US9238587B2 (en) | 2013-03-15 | 2016-01-19 | Sabre Intellectual Property Holdings Llc | Method and system for the treatment of water and fluids with chlorine dioxide |
| US10308533B2 (en) | 2013-03-15 | 2019-06-04 | Sabre Intellectual Property Holdings Llc | Method and system for the treatment of water and fluids with chlorine dioxide |
| US10442711B2 (en) | 2013-03-15 | 2019-10-15 | Sabre Intellectual Property Holdings Llc | Method and system for the treatment of produced water and fluids with chlorine dioxide for reuse |
| US20140020899A1 (en) * | 2013-04-24 | 2014-01-23 | Sabre Intellectual Property Holdings Llc | Flooding operations employing chlorine dioxide |
| US8789592B2 (en) * | 2013-04-24 | 2014-07-29 | Sabre Intellectual Property Holdings Llc | Flooding operations employing chlorine dioxide |
| WO2014176333A1 (en) * | 2013-04-24 | 2014-10-30 | Sabre Intellectual Property Holdings Llc | Flooding operations employing chlorine dioxide |
| US8991500B2 (en) * | 2013-04-24 | 2015-03-31 | Sabre Intellectual Property Holdings Llc | Fracturing operations employing chlorine dioxide |
| US8997862B2 (en) | 2013-04-24 | 2015-04-07 | Sabre Intellectual Property Holdings Llc | Flooding operations employing chlorine dioxide |
| US20140014349A1 (en) * | 2013-04-24 | 2014-01-16 | Sabre Intellectual Property Holdings Llc | Fracturing operations employing chlorine dioxide |
| US10526530B2 (en) | 2013-04-24 | 2020-01-07 | Sabre Intellectual Property Holdings Llc | Flooding operations employing chlorine dioxide |
| US20160280988A1 (en) * | 2015-03-24 | 2016-09-29 | Baker Hughes Incorporated | Application of chlorine dioxide to subsurface wells |
Also Published As
| Publication number | Publication date |
|---|---|
| MX162439A (en) | 1991-05-10 |
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| Date | Code | Title | Description |
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| MKEX | Expiry |