CA1172159A - Heavy oil recovery process - Google Patents
Heavy oil recovery processInfo
- Publication number
- CA1172159A CA1172159A CA000381274A CA381274A CA1172159A CA 1172159 A CA1172159 A CA 1172159A CA 000381274 A CA000381274 A CA 000381274A CA 381274 A CA381274 A CA 381274A CA 1172159 A CA1172159 A CA 1172159A
- Authority
- CA
- Canada
- Prior art keywords
- hydrocarbon
- reducing agent
- viscosity reducing
- formation
- process according
- 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
Classifications
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/58—Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids
- C09K8/592—Compositions used in combination with generated heat, e.g. by steam injection
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/60—Compositions for stimulating production by acting on the underground formation
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
Abstract
ABSTRACT OF THE DISCLOSURE
A novel process for recovering hydrocarbon from a hydrocarbon bearing formation is disclosed. The process comprises introducing into the hydrocarbon bearing formation a hydrocarbon viscosity reducing agent selected from an aldehyde, an aldehyde forming compound, hydrazine, chloramine, hydroxylamine, related diimide forming compounds, and compounds forming hydrazine, chloramine and hydroxylamine, and withdrawing the viscosity reduced hydrocarbon from the formation.
A novel process for recovering hydrocarbon from a hydrocarbon bearing formation is disclosed. The process comprises introducing into the hydrocarbon bearing formation a hydrocarbon viscosity reducing agent selected from an aldehyde, an aldehyde forming compound, hydrazine, chloramine, hydroxylamine, related diimide forming compounds, and compounds forming hydrazine, chloramine and hydroxylamine, and withdrawing the viscosity reduced hydrocarbon from the formation.
Description
-5~
FIELD OF THE I~VE~TION
This inven-tion is directed to a novel process for the recovery of heavy petroleum type and solid coal type hydrocarbons from surface and subterranean hydrocarbon bearing or carrying formations or bodies.
In particular, this invention is directed to a process for reducing in situ the viscosity of viscous hydrocarbons in surface and subterranean formations thereby permitting these hydrocarbons to migrate within the formation to collection sites and ba recovered for commercial purposes in an efficient, economical manner.
The process may also have application in the upgrading of heavy oil and residue in oil refineries.
BACKGROUND OF THE INVENTIO~
With depleting conventional petroleum (hydrocarbon) production, and consequent higher prices for petroleum type hydrocarbon, extensive attention is now being directed to "non-conventional" hydrocarbon sources such as tar sand deposits in Alberta, Venezuela, and other countries, shale oil deposits in the United States, carbonate type deposits in northern Alberta, and more conventional formation type heavy oil deposits such as t~ose found around Cold Lake, Alberta and Lloydminster, Saskatchewan. Attention is also being directed to recovering hydrocarbons from coal deposits.
The econornical recovery of hydrocarbons from "non-conventional" sources such as those described above presents a major production problem. The principal problem arises from the high viscosity of the hydrocarbon and the resultant low flowability of the S~
hydrocarbon in the deposit. Highly viscous hydrocarbons do not migrate easily through the deposit formation and hence cannot be readily and economically recovered at collection sites such as the oil wells that are present in conventional oil fields. Low gravity type crudes, eg., 6 API, are not very mobile. To increase the mobility of the hydrocarbons in such deposits, an obvious point of attention has been directed to techniques of reducing the viscosity of the hydrocarbons in such deposits to flowable ranges.
A variety of methods have been and are now being tested ~or reducing the viscosity of such hydrocarbons, ranging from solvent injection using light ends such as napthenes, to steam flocd, which thermally favourably reduces the viscosity of the hydrocarbon, to several variants of an in situ hydrocarbon combustion technique.
The latter techniques (steam flood and in situ combustion) seek to physically or chemically modiy the hydrocarbon in situ to enable enhanced recovery.
Generally speaking, in steam flooding, enhanced hydrocarbon recovery is achieved by physically lowering the viscosity of the hydrocarbon by raising its temperature. It is well known that hydrocarbons generally become less viscous with increased temperature.
A problem with steam flocd recovery is that it relies primarily upon a decrease in hydrocarbon viscosity by causing an increase in temperature of the hydrocarbon but this decline in viscosity may not be
FIELD OF THE I~VE~TION
This inven-tion is directed to a novel process for the recovery of heavy petroleum type and solid coal type hydrocarbons from surface and subterranean hydrocarbon bearing or carrying formations or bodies.
In particular, this invention is directed to a process for reducing in situ the viscosity of viscous hydrocarbons in surface and subterranean formations thereby permitting these hydrocarbons to migrate within the formation to collection sites and ba recovered for commercial purposes in an efficient, economical manner.
The process may also have application in the upgrading of heavy oil and residue in oil refineries.
BACKGROUND OF THE INVENTIO~
With depleting conventional petroleum (hydrocarbon) production, and consequent higher prices for petroleum type hydrocarbon, extensive attention is now being directed to "non-conventional" hydrocarbon sources such as tar sand deposits in Alberta, Venezuela, and other countries, shale oil deposits in the United States, carbonate type deposits in northern Alberta, and more conventional formation type heavy oil deposits such as t~ose found around Cold Lake, Alberta and Lloydminster, Saskatchewan. Attention is also being directed to recovering hydrocarbons from coal deposits.
The econornical recovery of hydrocarbons from "non-conventional" sources such as those described above presents a major production problem. The principal problem arises from the high viscosity of the hydrocarbon and the resultant low flowability of the S~
hydrocarbon in the deposit. Highly viscous hydrocarbons do not migrate easily through the deposit formation and hence cannot be readily and economically recovered at collection sites such as the oil wells that are present in conventional oil fields. Low gravity type crudes, eg., 6 API, are not very mobile. To increase the mobility of the hydrocarbons in such deposits, an obvious point of attention has been directed to techniques of reducing the viscosity of the hydrocarbons in such deposits to flowable ranges.
A variety of methods have been and are now being tested ~or reducing the viscosity of such hydrocarbons, ranging from solvent injection using light ends such as napthenes, to steam flocd, which thermally favourably reduces the viscosity of the hydrocarbon, to several variants of an in situ hydrocarbon combustion technique.
The latter techniques (steam flood and in situ combustion) seek to physically or chemically modiy the hydrocarbon in situ to enable enhanced recovery.
Generally speaking, in steam flooding, enhanced hydrocarbon recovery is achieved by physically lowering the viscosity of the hydrocarbon by raising its temperature. It is well known that hydrocarbons generally become less viscous with increased temperature.
A problem with steam flocd recovery is that it relies primarily upon a decrease in hydrocarbon viscosity by causing an increase in temperature of the hydrocarbon but this decline in viscosity may not be
2:~59 sufficient to yield a readily flowable hydrocarbon to permit enhanced recovery. Another problem is that tremendous quantities of steam are often required, and thus the process can rapidly become uneconomical because of the high cost of generating heat.
The in situ combustion method enhances hydro-carbon production by chemically altering the nature of the hydrocarbon in the formation through various processes such as (1) thermally decomposing the hydro-carbon to form lighter low molecular type hydrocarbonsand coke, ~2) thermally "cracking" the hydrocarbon into lower molecular weight components, (3) dehydrogenating the hydrocarbon ~ith subsequent hydrogenation (wet combustion process), and (4~ dehydrosulphurizing the hydrocarbon.
In the "wet" combustion process, the well known water shift reaction is a likely source of hydrogen which, under the high temperatures and pressures of combustion recovery in the formation, may possibly hydrogenate the hydrocarbon in situ.
The combustion type recovery methods are disadvantageous because they can often result în substantial damage to the hydrocarbon deposits likely by causing degradation of the hydrocarbons to coke, ie. a charring efect. This generated coke deposits in and plugs the pores in the formation, thereby obstructing the migration of the hydrocarbon under pressure.
It has been proposed to chemically alter the hydrocarbon in the reservoir by injecting surface active agents, or other chernical type agents, into the ~7~1~9 reservoir. One technique for hydrocarbon recovery process is disclosed and claimed in United States Patent No. 4,156,462, Joseph C. Allen, assignee Texaco Inc~, granted May 29, 1979. Allen discloses a two-step process for recovering hydrocarbons Erom a subterranean formation. The formation is ~irst heated by injecting steam through an injection well. In a second step, a mixture of carbon monoxide and hydrogen is pressured into the formation by means of the injection well where 0 it i5 postulated that in the heated formation, reaction with the carbon monoxide and steam takes place forming additional hydrogen and carbon dioxide. The hydro-carbons are recovered by means of a production well.
Optionally, after in~ection of the mixture o~ carbon monoxide and hydrogen into the Eormation has been terminated, water may be fur-ther injected into the formation as a drive fluid. The injected water may contain a small amount of a sul~ated interfacial tension reducer.
SVMMARY OF THE INVENTION
The subject invention is directed to a process for recovering hydrocarbon rom a hydrocarbon bearing formation comprising introducing a hydrocarbon viscosity reducing agent into the hydrocarbon formation and with-drawing the viscosity reduced hydrocarbon from the formation. The viscosity reducing agent may be a hydrogenating agent and may chemically interact with the hydrocarbon. There are at least two broad categories o~
viscosity reducing agents. The ~irst group includes any aldehyde ~uch as aceta]dehyde or glyoxal, and ~72~59 specifically formaldehyde, and various formulations of formaldehyde suc~ as:
(a) methanol-water-formaldehyde and its oligomers, HO(CH2O)nEI; and (b) paraformaldehyde, trioxane and tetroxane.
In general terms, any substance that could in principle lead to an aldehyde such as formaldehyde could be used as a viscosity reducing agent in this category.
One example would be formaldoxime and another would be ~; formic acid which is known to decompose under certain conditions to formaldehyde (ref. Encyclopedia of Chemical Technology, 3rd Edition, Wiley-Interscience, 1978).
Another broad class of viscosity reducing agents includes hydrazine, diimide (in-situ), chlor-amine, hydroxylamine and any substances leading to the foregoing.
The viscosity reducing agents of the present invention have the advantage that, unllke gases such as carbon monoxide, hydrogen, carbon dioxide, and the like, the agents are generally liquids or are applied as aqueous solutions. This reduces the tendency for the agents to di6perse or diffuse Erom the formation reservoir. The agents of the invention are water and oil soluble and thus tend to be compatible with the various substances usually present in the formation reservoir.
The invention is directed to a process for recovering hydrocarbon from a hydrocarbon bearing ~.3 7Z315~
formation comprising (a) introducing a hydrocarbon viscosity reducing agent into the hydrocarbon bearing formation, and (b) withdrawing the viscosity reduced hydrocarbon from the formation.
In the process, the viscosity reducing agellt may be a hydrocarbon hydrogenating agent.
The viscosity reducing agent may be selected from the group consisting of an aldehyde, an aldehyde forming compound, hydrazine, chloramine, hydroxylamine, and rela~ed diimide forming compounds.
The viscosity reducing agent may be introduced into the for~ation in association with steam.
The viscosity reducing agent may also be introduced into the formation in association with a suitable mechanism Eor heating the formation.
A hydrocarbon hydrogenation promoting catalyst may be included with the viscosity reducing agent.
The viscosity reducing agent may cause a chemical structural modification to occur in the chemical structure oE the hydrocarbon.
The hydrocarbon viscosity reducing agent may be introduced in the hydrocarbon under conditions external to -the hydrocarbon bearing formation.
DETAILED_DESCRIPTION OF THE INVENTION
The subject invention seems to be successful by striking a balance between various known hydrocarbon recovery techniques by taking advantage of the substantial chemical alteration of the hydrocarbon in formation that is achieved, for example, by the combustion type recovery technique and at the same time eliminating the deleterious effect that such combustion type recovery has on hydrocarbon bearing reservoirs by deposition therein of coke and the like, thereby plugging up the formation. The subject invention is directed to viscosity reducing the hydrocarbon in the reservoir at reasonably moderate temperatures such as 100 - 300C. It is believed that the viscosity reduction in the hydrocarbon is brought about by a hydrogenating reaction, although I offer this as a matter o~ possible explanation rather than as a binding theory. Hydrogenation of hydrocarbons in this low temperature range is difficult and in addition, most catalysts that may be used for such hydrogenation are metal impregnated aluminas which cannot be readily transported to and dispersed into the formation in this temperature range. Such catalysts are also subject to decreased activity caused by sulphur poisoning. Sulphur is commonly found in hydrocarbon bearing formations.
Hydrogenation o~ the hydrocarbon takes place more readily at increased formation temperatures and this can be achieved by steam 100d injection. Unfortunately, steam injection provides an aqueous environment within the formation and many common laboratory-type hydrogenation agents are thus unsuitable in such an environment because they decompose rapidly to hydrogen.
Hydrogenating or viscosity reducing agents which are compatible with aqueous environments include formaldehyde, and modifications thereof, hydrazine and related compounds, and it is believed such agents may be used in this invention.
Z ~ 5 ~3 It has been postulated that the low gravity and high viscosity charactsristic of heavy type oils and hydrocarbons in tar sand type ~ormations is due to high asphaltene and/or resin content in the hydrocarbon. It is thought that asphaltenes are polymeric in nature with large molecular weight units linked together. If these links could be severed, there could be a substantial reduction in viscosity. It has been proposed that sulphur linkages are present in asphaltenes (H.V.
Drushal, "Preprints, Div. Petroleum Chem.", ACS/ 17(4), F92 ~1972)) and cleavage of these linkages would break the polymer into units o siynificantly lower molecular weight thereby enhancing flowability and reducing the viscosity. Relatively mild reducing conditions can lead to as much as a ten-fold reduction in molecular weight o~ the asphaltenes (T. Ignasiak, A.V. Kemp-Jones and O.V. Strauss, "J. Org. Chem.", A2, 312 (1977)).
It is well known that hydrazine is a reducing agent (L.F. Fieser, M. Fieser, "Reagents for Organic Synthesis", John Wiley, New Yor~), and is capable of attacking and cleaving carbon sulphur linkages (V.
GeGrgian, R. ~arrisson, ~. Gubish, "J. Am. Chem. Soc.,"
81, 5834 (1959)).
Formaldehyde can also act as a reducing agent as it breaks down to atomic hydrogen as a likely step in its ultimate decomposition to hydrogen and carbon monoxide ("Encyclopedia o~ Chemical Technology", 3rd Edition, Wiley-Interscience, 1978).
Thus, by treating a heavy oil reservoir, or a coal seam, or even re~inery residue, with a hydroyen-117ZlS9 ating agent such as hydrazine, for example, it should be possible to cleave the sulphide links in the asphaltenes and/or attack resin heteroatoms in the heavy crude to obtain smaller molecular weight units. These smaller units should typically have lower viscosities, which, as discussed previously, is a desirable objective for the economical production of hydrocarbons from heavy oil formations.
~dditionally, a viscosity reducing agent, such as hydrazine, in company with appropriate catalysts, potentially may hydrogenate the high molecular weight aromatic structures, other than asphaltenes, that are found in heavy oils. If this occurs, it should increase the hydrogen content of the produced hydrocarbon, which is usually a desirable result for hydrocarbon upgrading and recovery. Furthermore, in hydrogenating and beneficiating the hydrocarbon in the heavy oil formations, by the use o an agent such as hydrazine, the agent, after reacting with the hydrocarbon should produce nitrogen, and other gases, thereby providing inherent drive pressure in the formation.
The agent, such as hydrazine, should also be capable of reducing the sulphur, oxygen and nitrogen content of the hydrocarbon in the formation and thereby minimize the occurrence of a deleterious emulsion problem in the formation.
In field application, it is contemplated that the invention will be used in conjunction with a steam drive carried out by flooding the hydrocarbon bearing formation with steam. The steam flood would be ~17Z15~a conducted to bring the formation temperature to a desirable level such as 100 - 300C. Once the formation was brought up to desired temperature, an alkaline aqueous sol~tion of a viscosity reducing agent such as hydrazine would be injected. The metals inherently present in the formation reservoir should provide a catalytic e~fect on the various postulated hydrogenation reactions. Should it be found that the hydrogenating agent alone ~as insuf~icient to achieve the desir~d performance, a catalyst such as hydrogen peroxide or a transition metal carbonyl could simultaneously or subsequently be injected into the formation ~o increase effi~iency.
Formaldehyde is another viscosity reducing agent that may be used and characteristically thermally decomposes to hydrogen and hydrogen monoxide. The reaction steps are not compIetely understood but the initial step is believed to be H2CO ~ HCO~ + H-. The resultant HCO- -further breaks down to H- + CO. The resultant CO, say in association with a steam drive, could then react with water to prcduce hydrogen and carbon dioxide. The hydrogen produced could extend the hydrogenation reaction initiated by formaldehyde decomposition in that the hydrocarbon radical initially produced could abstract a hydrogen atom from the hydrogen to thereby form RH2, thereby increasing the hydrogen content. The mechanism and action of formaldehyde in reducing viscosity may be similar to that postulated or hydrazine type viscosity reducing agents though the postulated free radical nature o~ the 2~S~
formaldehyde type viscosity reducing agents may mean that it is less selective, ie. more reactive than hydrazine type agents.
In view of the well-known reac-tivity of formaldehyde with hetero-atom containing hydrocarbons, the formaldehyde may also act to cap the polar hetero-atom sites in the heavy oil.
Laboratory tests on a typical sample of Athabasca tar sand obtained from Northern Alberta, 0 Canada, have been conducted and are detailed below.
Exam~le A sample of Athabasca tar sand, commonly known as "bitumen", was prepared to be used in a simulated "pre-flood" steam 100d. This was done before treating the sample with any viscosity reducing agent. A volume of the tar sand was extracted to yield 29.1 grams of tar sand extract. 35 cc of water was added to a .standard autoclave containing the tar sand extract. The "pre-flood" treatment was carried out for two weeks at 200C. Upon cooling to room temp~rature, the autoclaves were opened. There was a small amount (10~ p5i) of gas pressure. The bulk of the water was removed with a pipatte leaving behind the still viscous bitumen. Two samples were made using this technique.
The first sample was designated BC HY#l. The sample was purged with nitrogen. 30 cc of 37% (w/w) formaldeh~de, 1 gram oE a phase transfer catalyst-PTC-(Bu4NCl), and a few drops of concentrated HCl were added to the autoclave. The autoclave was heated to 200C for nine days and then cooled to room 72~S~ -temperature.
A second sample designated BC HY#2 was purged with helium and then 40 grams o 38% hydrazine in water, l.0 grams of KOH and 1.0 PTC(BU4NCl) were added to the vessel. The autoclave was heated at approximately 200C
for eight days and then removed.
The contents of the two vessels were examined by cooling the autoclaves and contents, then measuring the gas composition and pressure in the vessel at room temperature. The vessels were then opened and the contents were physically removed without the use of solvents. There was excellent separation between water and the oil phase, that is, there was no emulsion. The contents were washed or triturated with water. The viscosity of the recovered oil was measured at about 90C, which is a typical formation temperature near the periphery of a steam flood.
B HY#l Sample (Formald h~e~
The 100 cc (nominal) autoclave (BC HY#l sample3 had a room temperature gas pressure of 600 psi using a psi gauge with an estimated Bourdon tube volume of 20 cc.
The 100 cc (nominal) autoclave ~BC HY#2 sample3 had a room temperature gac pressure of 1500 psi using a gauge with an estimated Burdon tube volume of 20 cc.
The gas analysis of sample BC HY#l (formaldehyde) by the release of gas retained in the vessel indicated greater than 1,000 cc of gas in the system (it was likely around 1,300 - 1,400 cc as a 1.0 ~17Z~59 litre backup reservoir expanded significantly.) Hydrogen analysis (two tests) revealed 15.43 H2 and 15.67% H2 respectively.
Other gases found and percentages thereof are listed as follows:
Component Percentage CH4 4.390 C2 29.540 2 10.480 ~2 34.746 CO 0.020 Total (calculating 15.5 E2) 95.530.
General Comments on Ru BC HY#l While I do not wish to be bound to any theories, the following comments are offered with a view -to possibly assistlng in the understanding of the function and operation of the invention. The analysis shows a very high hydrogen and carbon dioxide content which tends to indicate that under a short time ~rame, there was substantial formaldehyde decomposition. The ~ormaldehyde probably decomposed to hydrogen and carbon monoxide which then by a water shift reaction was converted to more hydrogen and carbon dioxide (the analysis indicates that there was very little carbon monoxide present). If the formaldehyde had been oxidizing due to air remnants in the autoclave, then the product of such an oxidization would be formic acid which might decompose to wa-ter and carbon rnonoxide.
Then, by a water shi~t reaction~ it would convert to hydrogen and carbon dioxide. But, since approximately ~L7;~
0.38 moles of formaldehyde were added, it is difficult to see how sufficient oxygen was available for this process -to take place. While, as explained previ.ously, I do not want to be confined or held -to any theory, it seems likely that carbon dioxide was not formed rom formic acid in -this case but from the formaldehyde decomposition. The presence of significant amounts of 2 and N2 maY indicate some gas sampling error.
BC HY#2 Sam~le (Hydrazine) The release of gas contained in the 100 cc vessel, at room temperature, indicated more than 1,000 cc and was estimated by the previously mentioned method to be at least 1,500 - 1,800 cc. This does not take into account the gas loss on the pressurq measurement and the actual volume could therefore be in the two to three litre range. This would then approach the theoretical nitrogen available from hydrazine decomposition.
The hydrogen analysis on two tests mea~ured 2.25 and 2.19% respectively.
The other gases and respective percentages are set forth in the following column:
ComponentPercentage CH4 1.412 C2 9 . 991 2 1.47g N2 76.590 C0 1.546 Total (calculating 2.23 H2) 93.249.
-~7;~59 General Comments About_the BC HY#2 Run Again, I wish -to emphasize that the following comments are offered as a possible in-terpretation of the mechanism behind the perormance of the invention, and no-t as -the explanation of a binding theory. Since the vessel was purged under helium before sealing, -the gas analysis indicates approximately 80~ nitrogen, which in turn indicates that most of -the hydrazine must have decomposed. The resulting hydrogen was most likely consumed as it only measured 2.24%.
Viscosity Analysis of the BC HY#l and BC HY#2 Samples BC HY#l_Sample Two days after the foregoing gas analyses were conducted, the BC HY~l pressure vessel valve was cracked at room temperature. Gas pressure was still evident notwithstandiny there had been a blow down for purposes of the gas analysis conducted two days earlier. After a few seconds of gas release, bitumen froth carne out of the vessel. This froth was directly collected by a short tube in-to a 125 cc Erlenmeyer flask which was under a nitrogen purge. The frothy bitumen flow ceased after about 3 minutes. ~he vessel was then opened and residual bitumen was scraped out with a spoon-type spatula. This left an aqueous layer which indicated a clear separation of bitumen and water in the vessel.
The aqueous layer had a pH of approximately 5.
The bitumen sample, after settling, and presumably some de-gassing, flowed like 40 W crank case oil at roo~ temperature. Thus, the oil viscosity of the treated bitumen was drastically lower than that of the ~7Z:~S~
Athabasca bitumen sample prior to treatment with formaldehyde.
Viscosity measurements on the sample BC HY#l were conducted on a standard petroleum viscometer.
Table 1 Sample BC HY#l (Formaldehyde) Temp. Viscosity C Time (CPS) 11:56 3600 48 12:02 2720 49 12:06 2500 56 12:07 2440 61 12:10 2280 12:13 1760 12:14 12~0 12:15 880 12:17 540 12:19 320 91 12:21 240 91 12:25 228 91 12:24 220 91 12:35 196a gl 12:45 196 91 1:02 196 a. more sensitive scale It is noteworthy that at 91C, the viscosity of the bitumen is only slightly greater than that of water near its freezing point.
BC HY#2 Sam~le The pressure vessel containing the BC HY~2 extract was valve cracked at room temperature and residual gas was also evident (as with sample BC HY~l above) despite the previous blow down for gas sampling.
Water was at first produced and then a slightly frothy bitumen was expelled. The oil obtained from this sample, after settling, was more viscous than that obtained from sample BC HY#l. It flowed more like 40 W
motor oil at about -25C. However, the viscosity was 1 lL72~9 still relatively low compared to the viscosity of the initial Athabasca bitumen extract. Viscosity measurements on the BC HY#2 were conducted on a standard petroleum viscometer.
Table 2 BC HY#2 (Hydrazine) Temp. Viscosity C Ca 1 (CPS) ___ 10:42 >4000 10:48 2200 72 10:54 1860 8~ 11:00 1720 11:06 1160 11:12 1000 11:14 900 91 11:17 700 91 11:18 740 As will be apparent to those skilled in the art in the light of the foregoing disclosure, many alterations and modifications are possible in the practice of thls invention without departing from the spirit or scope thereof. Accordingly, the scope of the invention i,s to be construed in accordance with the substance defined by the following claims.
The in situ combustion method enhances hydro-carbon production by chemically altering the nature of the hydrocarbon in the formation through various processes such as (1) thermally decomposing the hydro-carbon to form lighter low molecular type hydrocarbonsand coke, ~2) thermally "cracking" the hydrocarbon into lower molecular weight components, (3) dehydrogenating the hydrocarbon ~ith subsequent hydrogenation (wet combustion process), and (4~ dehydrosulphurizing the hydrocarbon.
In the "wet" combustion process, the well known water shift reaction is a likely source of hydrogen which, under the high temperatures and pressures of combustion recovery in the formation, may possibly hydrogenate the hydrocarbon in situ.
The combustion type recovery methods are disadvantageous because they can often result în substantial damage to the hydrocarbon deposits likely by causing degradation of the hydrocarbons to coke, ie. a charring efect. This generated coke deposits in and plugs the pores in the formation, thereby obstructing the migration of the hydrocarbon under pressure.
It has been proposed to chemically alter the hydrocarbon in the reservoir by injecting surface active agents, or other chernical type agents, into the ~7~1~9 reservoir. One technique for hydrocarbon recovery process is disclosed and claimed in United States Patent No. 4,156,462, Joseph C. Allen, assignee Texaco Inc~, granted May 29, 1979. Allen discloses a two-step process for recovering hydrocarbons Erom a subterranean formation. The formation is ~irst heated by injecting steam through an injection well. In a second step, a mixture of carbon monoxide and hydrogen is pressured into the formation by means of the injection well where 0 it i5 postulated that in the heated formation, reaction with the carbon monoxide and steam takes place forming additional hydrogen and carbon dioxide. The hydro-carbons are recovered by means of a production well.
Optionally, after in~ection of the mixture o~ carbon monoxide and hydrogen into the Eormation has been terminated, water may be fur-ther injected into the formation as a drive fluid. The injected water may contain a small amount of a sul~ated interfacial tension reducer.
SVMMARY OF THE INVENTION
The subject invention is directed to a process for recovering hydrocarbon rom a hydrocarbon bearing formation comprising introducing a hydrocarbon viscosity reducing agent into the hydrocarbon formation and with-drawing the viscosity reduced hydrocarbon from the formation. The viscosity reducing agent may be a hydrogenating agent and may chemically interact with the hydrocarbon. There are at least two broad categories o~
viscosity reducing agents. The ~irst group includes any aldehyde ~uch as aceta]dehyde or glyoxal, and ~72~59 specifically formaldehyde, and various formulations of formaldehyde suc~ as:
(a) methanol-water-formaldehyde and its oligomers, HO(CH2O)nEI; and (b) paraformaldehyde, trioxane and tetroxane.
In general terms, any substance that could in principle lead to an aldehyde such as formaldehyde could be used as a viscosity reducing agent in this category.
One example would be formaldoxime and another would be ~; formic acid which is known to decompose under certain conditions to formaldehyde (ref. Encyclopedia of Chemical Technology, 3rd Edition, Wiley-Interscience, 1978).
Another broad class of viscosity reducing agents includes hydrazine, diimide (in-situ), chlor-amine, hydroxylamine and any substances leading to the foregoing.
The viscosity reducing agents of the present invention have the advantage that, unllke gases such as carbon monoxide, hydrogen, carbon dioxide, and the like, the agents are generally liquids or are applied as aqueous solutions. This reduces the tendency for the agents to di6perse or diffuse Erom the formation reservoir. The agents of the invention are water and oil soluble and thus tend to be compatible with the various substances usually present in the formation reservoir.
The invention is directed to a process for recovering hydrocarbon from a hydrocarbon bearing ~.3 7Z315~
formation comprising (a) introducing a hydrocarbon viscosity reducing agent into the hydrocarbon bearing formation, and (b) withdrawing the viscosity reduced hydrocarbon from the formation.
In the process, the viscosity reducing agellt may be a hydrocarbon hydrogenating agent.
The viscosity reducing agent may be selected from the group consisting of an aldehyde, an aldehyde forming compound, hydrazine, chloramine, hydroxylamine, and rela~ed diimide forming compounds.
The viscosity reducing agent may be introduced into the for~ation in association with steam.
The viscosity reducing agent may also be introduced into the formation in association with a suitable mechanism Eor heating the formation.
A hydrocarbon hydrogenation promoting catalyst may be included with the viscosity reducing agent.
The viscosity reducing agent may cause a chemical structural modification to occur in the chemical structure oE the hydrocarbon.
The hydrocarbon viscosity reducing agent may be introduced in the hydrocarbon under conditions external to -the hydrocarbon bearing formation.
DETAILED_DESCRIPTION OF THE INVENTION
The subject invention seems to be successful by striking a balance between various known hydrocarbon recovery techniques by taking advantage of the substantial chemical alteration of the hydrocarbon in formation that is achieved, for example, by the combustion type recovery technique and at the same time eliminating the deleterious effect that such combustion type recovery has on hydrocarbon bearing reservoirs by deposition therein of coke and the like, thereby plugging up the formation. The subject invention is directed to viscosity reducing the hydrocarbon in the reservoir at reasonably moderate temperatures such as 100 - 300C. It is believed that the viscosity reduction in the hydrocarbon is brought about by a hydrogenating reaction, although I offer this as a matter o~ possible explanation rather than as a binding theory. Hydrogenation of hydrocarbons in this low temperature range is difficult and in addition, most catalysts that may be used for such hydrogenation are metal impregnated aluminas which cannot be readily transported to and dispersed into the formation in this temperature range. Such catalysts are also subject to decreased activity caused by sulphur poisoning. Sulphur is commonly found in hydrocarbon bearing formations.
Hydrogenation o~ the hydrocarbon takes place more readily at increased formation temperatures and this can be achieved by steam 100d injection. Unfortunately, steam injection provides an aqueous environment within the formation and many common laboratory-type hydrogenation agents are thus unsuitable in such an environment because they decompose rapidly to hydrogen.
Hydrogenating or viscosity reducing agents which are compatible with aqueous environments include formaldehyde, and modifications thereof, hydrazine and related compounds, and it is believed such agents may be used in this invention.
Z ~ 5 ~3 It has been postulated that the low gravity and high viscosity charactsristic of heavy type oils and hydrocarbons in tar sand type ~ormations is due to high asphaltene and/or resin content in the hydrocarbon. It is thought that asphaltenes are polymeric in nature with large molecular weight units linked together. If these links could be severed, there could be a substantial reduction in viscosity. It has been proposed that sulphur linkages are present in asphaltenes (H.V.
Drushal, "Preprints, Div. Petroleum Chem.", ACS/ 17(4), F92 ~1972)) and cleavage of these linkages would break the polymer into units o siynificantly lower molecular weight thereby enhancing flowability and reducing the viscosity. Relatively mild reducing conditions can lead to as much as a ten-fold reduction in molecular weight o~ the asphaltenes (T. Ignasiak, A.V. Kemp-Jones and O.V. Strauss, "J. Org. Chem.", A2, 312 (1977)).
It is well known that hydrazine is a reducing agent (L.F. Fieser, M. Fieser, "Reagents for Organic Synthesis", John Wiley, New Yor~), and is capable of attacking and cleaving carbon sulphur linkages (V.
GeGrgian, R. ~arrisson, ~. Gubish, "J. Am. Chem. Soc.,"
81, 5834 (1959)).
Formaldehyde can also act as a reducing agent as it breaks down to atomic hydrogen as a likely step in its ultimate decomposition to hydrogen and carbon monoxide ("Encyclopedia o~ Chemical Technology", 3rd Edition, Wiley-Interscience, 1978).
Thus, by treating a heavy oil reservoir, or a coal seam, or even re~inery residue, with a hydroyen-117ZlS9 ating agent such as hydrazine, for example, it should be possible to cleave the sulphide links in the asphaltenes and/or attack resin heteroatoms in the heavy crude to obtain smaller molecular weight units. These smaller units should typically have lower viscosities, which, as discussed previously, is a desirable objective for the economical production of hydrocarbons from heavy oil formations.
~dditionally, a viscosity reducing agent, such as hydrazine, in company with appropriate catalysts, potentially may hydrogenate the high molecular weight aromatic structures, other than asphaltenes, that are found in heavy oils. If this occurs, it should increase the hydrogen content of the produced hydrocarbon, which is usually a desirable result for hydrocarbon upgrading and recovery. Furthermore, in hydrogenating and beneficiating the hydrocarbon in the heavy oil formations, by the use o an agent such as hydrazine, the agent, after reacting with the hydrocarbon should produce nitrogen, and other gases, thereby providing inherent drive pressure in the formation.
The agent, such as hydrazine, should also be capable of reducing the sulphur, oxygen and nitrogen content of the hydrocarbon in the formation and thereby minimize the occurrence of a deleterious emulsion problem in the formation.
In field application, it is contemplated that the invention will be used in conjunction with a steam drive carried out by flooding the hydrocarbon bearing formation with steam. The steam flood would be ~17Z15~a conducted to bring the formation temperature to a desirable level such as 100 - 300C. Once the formation was brought up to desired temperature, an alkaline aqueous sol~tion of a viscosity reducing agent such as hydrazine would be injected. The metals inherently present in the formation reservoir should provide a catalytic e~fect on the various postulated hydrogenation reactions. Should it be found that the hydrogenating agent alone ~as insuf~icient to achieve the desir~d performance, a catalyst such as hydrogen peroxide or a transition metal carbonyl could simultaneously or subsequently be injected into the formation ~o increase effi~iency.
Formaldehyde is another viscosity reducing agent that may be used and characteristically thermally decomposes to hydrogen and hydrogen monoxide. The reaction steps are not compIetely understood but the initial step is believed to be H2CO ~ HCO~ + H-. The resultant HCO- -further breaks down to H- + CO. The resultant CO, say in association with a steam drive, could then react with water to prcduce hydrogen and carbon dioxide. The hydrogen produced could extend the hydrogenation reaction initiated by formaldehyde decomposition in that the hydrocarbon radical initially produced could abstract a hydrogen atom from the hydrogen to thereby form RH2, thereby increasing the hydrogen content. The mechanism and action of formaldehyde in reducing viscosity may be similar to that postulated or hydrazine type viscosity reducing agents though the postulated free radical nature o~ the 2~S~
formaldehyde type viscosity reducing agents may mean that it is less selective, ie. more reactive than hydrazine type agents.
In view of the well-known reac-tivity of formaldehyde with hetero-atom containing hydrocarbons, the formaldehyde may also act to cap the polar hetero-atom sites in the heavy oil.
Laboratory tests on a typical sample of Athabasca tar sand obtained from Northern Alberta, 0 Canada, have been conducted and are detailed below.
Exam~le A sample of Athabasca tar sand, commonly known as "bitumen", was prepared to be used in a simulated "pre-flood" steam 100d. This was done before treating the sample with any viscosity reducing agent. A volume of the tar sand was extracted to yield 29.1 grams of tar sand extract. 35 cc of water was added to a .standard autoclave containing the tar sand extract. The "pre-flood" treatment was carried out for two weeks at 200C. Upon cooling to room temp~rature, the autoclaves were opened. There was a small amount (10~ p5i) of gas pressure. The bulk of the water was removed with a pipatte leaving behind the still viscous bitumen. Two samples were made using this technique.
The first sample was designated BC HY#l. The sample was purged with nitrogen. 30 cc of 37% (w/w) formaldeh~de, 1 gram oE a phase transfer catalyst-PTC-(Bu4NCl), and a few drops of concentrated HCl were added to the autoclave. The autoclave was heated to 200C for nine days and then cooled to room 72~S~ -temperature.
A second sample designated BC HY#2 was purged with helium and then 40 grams o 38% hydrazine in water, l.0 grams of KOH and 1.0 PTC(BU4NCl) were added to the vessel. The autoclave was heated at approximately 200C
for eight days and then removed.
The contents of the two vessels were examined by cooling the autoclaves and contents, then measuring the gas composition and pressure in the vessel at room temperature. The vessels were then opened and the contents were physically removed without the use of solvents. There was excellent separation between water and the oil phase, that is, there was no emulsion. The contents were washed or triturated with water. The viscosity of the recovered oil was measured at about 90C, which is a typical formation temperature near the periphery of a steam flood.
B HY#l Sample (Formald h~e~
The 100 cc (nominal) autoclave (BC HY#l sample3 had a room temperature gas pressure of 600 psi using a psi gauge with an estimated Bourdon tube volume of 20 cc.
The 100 cc (nominal) autoclave ~BC HY#2 sample3 had a room temperature gac pressure of 1500 psi using a gauge with an estimated Burdon tube volume of 20 cc.
The gas analysis of sample BC HY#l (formaldehyde) by the release of gas retained in the vessel indicated greater than 1,000 cc of gas in the system (it was likely around 1,300 - 1,400 cc as a 1.0 ~17Z~59 litre backup reservoir expanded significantly.) Hydrogen analysis (two tests) revealed 15.43 H2 and 15.67% H2 respectively.
Other gases found and percentages thereof are listed as follows:
Component Percentage CH4 4.390 C2 29.540 2 10.480 ~2 34.746 CO 0.020 Total (calculating 15.5 E2) 95.530.
General Comments on Ru BC HY#l While I do not wish to be bound to any theories, the following comments are offered with a view -to possibly assistlng in the understanding of the function and operation of the invention. The analysis shows a very high hydrogen and carbon dioxide content which tends to indicate that under a short time ~rame, there was substantial formaldehyde decomposition. The ~ormaldehyde probably decomposed to hydrogen and carbon monoxide which then by a water shift reaction was converted to more hydrogen and carbon dioxide (the analysis indicates that there was very little carbon monoxide present). If the formaldehyde had been oxidizing due to air remnants in the autoclave, then the product of such an oxidization would be formic acid which might decompose to wa-ter and carbon rnonoxide.
Then, by a water shi~t reaction~ it would convert to hydrogen and carbon dioxide. But, since approximately ~L7;~
0.38 moles of formaldehyde were added, it is difficult to see how sufficient oxygen was available for this process -to take place. While, as explained previ.ously, I do not want to be confined or held -to any theory, it seems likely that carbon dioxide was not formed rom formic acid in -this case but from the formaldehyde decomposition. The presence of significant amounts of 2 and N2 maY indicate some gas sampling error.
BC HY#2 Sam~le (Hydrazine) The release of gas contained in the 100 cc vessel, at room temperature, indicated more than 1,000 cc and was estimated by the previously mentioned method to be at least 1,500 - 1,800 cc. This does not take into account the gas loss on the pressurq measurement and the actual volume could therefore be in the two to three litre range. This would then approach the theoretical nitrogen available from hydrazine decomposition.
The hydrogen analysis on two tests mea~ured 2.25 and 2.19% respectively.
The other gases and respective percentages are set forth in the following column:
ComponentPercentage CH4 1.412 C2 9 . 991 2 1.47g N2 76.590 C0 1.546 Total (calculating 2.23 H2) 93.249.
-~7;~59 General Comments About_the BC HY#2 Run Again, I wish -to emphasize that the following comments are offered as a possible in-terpretation of the mechanism behind the perormance of the invention, and no-t as -the explanation of a binding theory. Since the vessel was purged under helium before sealing, -the gas analysis indicates approximately 80~ nitrogen, which in turn indicates that most of -the hydrazine must have decomposed. The resulting hydrogen was most likely consumed as it only measured 2.24%.
Viscosity Analysis of the BC HY#l and BC HY#2 Samples BC HY#l_Sample Two days after the foregoing gas analyses were conducted, the BC HY~l pressure vessel valve was cracked at room temperature. Gas pressure was still evident notwithstandiny there had been a blow down for purposes of the gas analysis conducted two days earlier. After a few seconds of gas release, bitumen froth carne out of the vessel. This froth was directly collected by a short tube in-to a 125 cc Erlenmeyer flask which was under a nitrogen purge. The frothy bitumen flow ceased after about 3 minutes. ~he vessel was then opened and residual bitumen was scraped out with a spoon-type spatula. This left an aqueous layer which indicated a clear separation of bitumen and water in the vessel.
The aqueous layer had a pH of approximately 5.
The bitumen sample, after settling, and presumably some de-gassing, flowed like 40 W crank case oil at roo~ temperature. Thus, the oil viscosity of the treated bitumen was drastically lower than that of the ~7Z:~S~
Athabasca bitumen sample prior to treatment with formaldehyde.
Viscosity measurements on the sample BC HY#l were conducted on a standard petroleum viscometer.
Table 1 Sample BC HY#l (Formaldehyde) Temp. Viscosity C Time (CPS) 11:56 3600 48 12:02 2720 49 12:06 2500 56 12:07 2440 61 12:10 2280 12:13 1760 12:14 12~0 12:15 880 12:17 540 12:19 320 91 12:21 240 91 12:25 228 91 12:24 220 91 12:35 196a gl 12:45 196 91 1:02 196 a. more sensitive scale It is noteworthy that at 91C, the viscosity of the bitumen is only slightly greater than that of water near its freezing point.
BC HY#2 Sam~le The pressure vessel containing the BC HY~2 extract was valve cracked at room temperature and residual gas was also evident (as with sample BC HY~l above) despite the previous blow down for gas sampling.
Water was at first produced and then a slightly frothy bitumen was expelled. The oil obtained from this sample, after settling, was more viscous than that obtained from sample BC HY#l. It flowed more like 40 W
motor oil at about -25C. However, the viscosity was 1 lL72~9 still relatively low compared to the viscosity of the initial Athabasca bitumen extract. Viscosity measurements on the BC HY#2 were conducted on a standard petroleum viscometer.
Table 2 BC HY#2 (Hydrazine) Temp. Viscosity C Ca 1 (CPS) ___ 10:42 >4000 10:48 2200 72 10:54 1860 8~ 11:00 1720 11:06 1160 11:12 1000 11:14 900 91 11:17 700 91 11:18 740 As will be apparent to those skilled in the art in the light of the foregoing disclosure, many alterations and modifications are possible in the practice of thls invention without departing from the spirit or scope thereof. Accordingly, the scope of the invention i,s to be construed in accordance with the substance defined by the following claims.
Claims (20)
1. A process for recovering hydrocarbon from a hydrocarbon bearing formation comprising:
(a) introducing into the hydrocarbon bearing formation a hydrocarbon viscosity reducing agent selected from the group consisting of an aldehyde, an aldehyde forming compound, hydrazine, chloramine, hydroxylamine, related diimide forming compounds, and compounds forming hydrazine, chloramine or hydroxylamine;
and (b) withdrawing the viscosity reduced hydrocarbon from the formation.
(a) introducing into the hydrocarbon bearing formation a hydrocarbon viscosity reducing agent selected from the group consisting of an aldehyde, an aldehyde forming compound, hydrazine, chloramine, hydroxylamine, related diimide forming compounds, and compounds forming hydrazine, chloramine or hydroxylamine;
and (b) withdrawing the viscosity reduced hydrocarbon from the formation.
2. A process according to Claim 1 wherein the viscosity reducing agent is an aldehyde.
3. A process according to Claim 1 wherein the viscosity reducing agent is formaldehyde.
4. A process according to Claim 1 wherein the viscosity reducing agent is an aldehyde forming compound
5. A process according to Claim 1 wherein the viscosity reducing agent is hydrazine.
6. A process according to Claim 1 wherein the viscosity reducing agent is chloramine.
7. A process according to Claim 1 wherein the viscosity reducing agent is hydroxylamine.
- Page 1 of Claims -
- Page 1 of Claims -
8. A process according to Claim 1 wherein the viscosity reducing agent is a diimide forming compound related to hydrazine.
9. A process according to Claim 1 wherein the viscosity reducing agent is a compound which forms hydrazine, chloramine or hydroxylamine.
10. A process according to Claim 1, 2 or 3 wherein the viscosity reducing agent is introduced into the formation in association with steam.
11. A process according to Claim 4, 5 or 6 wherein the viscosity reducing agent is introduced into the formation in association with steam.
12. A process according to Claim 7, 8 or 9 wherein the viscosity reducing agent is introduced into the formation in association with steam.
13. A process according to Claim 1, 2 or 3 wherein the viscosity reducing agent is introduced into the formation in association with a suitable mechanism for heating the formation.
14. A process according to Claim 4, 5 or 6 wherein the viscosity reducing agent is introduced into the formation in association with a suitable mechanism for heating the formation.
15. A process according to Claim 7, 8 or 9 wherein the viscosity reducing agent is introduced into the formation in association with a suitable mechanism for heating the formation.
16. A process according to Claim 1, 2 or 3 wherein a hydrocarbon hydrogenation promoting catalyst is included with the viscosity reducing agent.
- Page 2 of Claims -
- Page 2 of Claims -
17. A process according to Claim 4, 5 or 6 wherein a hydrocarbon hydrogenation promoting catalyst is included with the viscosity reducing agent.
18. A process according to Claim 7, 8 or 9 wherein a hydrocarbon hydrogenation promoting catalyst is included with the viscosity reducing agent.
19. A process according to Claim 1, 2 or 3 wherein the viscosity reducing agent causes a chemical structural modification to occur in the chemical structure of the hydrocarbon.
20. A process according to Claim 1 or 3 wherein the hydrocarbon viscosity reducing agent is introduced in the hydrocarbon under conditions external to the hydrocarbon bearing formation.
- Page 3 of Claims -
- Page 3 of Claims -
Priority Applications (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA000381274A CA1172159A (en) | 1981-07-07 | 1981-07-07 | Heavy oil recovery process |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA000381274A CA1172159A (en) | 1981-07-07 | 1981-07-07 | Heavy oil recovery process |
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| Publication Number | Publication Date |
|---|---|
| CA1172159A true CA1172159A (en) | 1984-08-07 |
Family
ID=4120383
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA000381274A Expired CA1172159A (en) | 1981-07-07 | 1981-07-07 | Heavy oil recovery process |
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Cited By (2)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN105018049A (en) * | 2014-04-29 | 2015-11-04 | 中国石油化工股份有限公司 | Treating agent for reducing adhesivity of thickened oil in drilling fluid |
| US10214683B2 (en) | 2015-01-13 | 2019-02-26 | Bp Corporation North America Inc | Systems and methods for producing hydrocarbons from hydrocarbon bearing rock via combined treatment of the rock and subsequent waterflooding |
-
1981
- 1981-07-07 CA CA000381274A patent/CA1172159A/en not_active Expired
Cited By (2)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN105018049A (en) * | 2014-04-29 | 2015-11-04 | 中国石油化工股份有限公司 | Treating agent for reducing adhesivity of thickened oil in drilling fluid |
| US10214683B2 (en) | 2015-01-13 | 2019-02-26 | Bp Corporation North America Inc | Systems and methods for producing hydrocarbons from hydrocarbon bearing rock via combined treatment of the rock and subsequent waterflooding |
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