INTERGRATED PROCESS FOR IN-FIELD UPGRADING OF HYDROCARBONS

Info

Publication number: 20090159498
Type: Application
Filed: Dec 20, 2007
Publication Date: Jun 25, 2009
Applicant:
Inventors: Daniel Chinn (Bay Point, CA), Steven F. Sciamanna (Orinda, CA), Zunqing Alice He (San Rafael, CA)
Application Number: 11/960,891

Abstract

A process is provided for in-field upgrading of heavy hydrocarbons such as whole heavy oil, bitumen, and the like using supercritical water.

Description

Description

FIELD OF THE INVENTION

The present invention relates to an integrated process for in-field upgrading of heavy hydrocarbons such as whole heavy oil, bitumen, and the like using supercritical water.

BACKGROUND OF THE INVENTION

Oil produced from a significant number of oil reserves around the world is simply too heavy to flow under ambient conditions. This makes it challenging to bring remote, heavy oil resources closer to the markets. One typical example is the Hamaca field in Venezuela. In order to render such heavy oils flowable, one of the most common methods known in the art is to reduce the viscosity and density by mixing the heavy oil with a sufficient diluent. The diluent may be naphtha, or any other stream with a significantly higher API gravity (i.e., much lower density) than the heavy oil. A diluted, heavy crude with an API of 12 or higher will normally be transportable by pipeline without significant problems.

For a case such as Hamaca, diluted crude oil is sent from the production wellhead via pipeline to an upgrading facility located 120 miles away. Two key operations occur at the upgrading facility: (1) the diluent stream is recovered and recycled back to the production wellhead in a separate pipeline, and (2) the heavy oil is upgraded with suitable technology known in the art (coking, hydrocracking, hydrotreating, etc.) to produce higher-value products for market. Some typical characteristics of these higher-value products include: lower sulfur and nitrogen content, lower metals content, lower total acid number (TAN), lower carbon residuum content, higher API gravity, and lower viscosity. Most of these desirable characteristics are achieved by reacting the heavy oil with hydrogen gas at high temperatures and pressures in the presence of a catalyst. In the case of Hamaca, the upgraded crude is sent further to the end-users via tankers.

These diluent addition/removal processes and hydrogen-addition or other upgrading processes have a number of disadvantages:

1. The infrastructure required for the handling, recovery, and recycle of diluent could be expensive, especially over long distances. Diluent availability is another potential issue.
2. Hydrogen-addition processes such as hydrotreating or hydrocracking require significant investments in capital and infrastructure.
3. Hydrogen-addition processes also have high operating costs, since hydrogen production costs are highly sensitive to natural gas prices. Some remote heavy oil reserves may not even have access to sufficient quantities of low-cost natural gas to support a hydrogen plant. These hydrogen-addition processes also generally require expensive catalysts and resource intensive catalyst handling techniques, including catalyst regeneration.
4. In some cases, the refineries and/or upgrading facilities that are located closest to the production site may have neither the capacity nor the facilities to accept the heavy oil.
5. Coking is often used at refineries or upgrading facilities. Significant amounts of by-product solid coke are rejected during the coking process, leading to lower liquid hydrocarbon yield. Further, the volume of the product from the coking process is significantly less than the volume of the feed crude oil.

SUMMARY OF THE INVENTION

The present invention achieves the advantage of an integrated process for in-field upgrading of heavy hydrocarbons such as whole heavy oil, bitumen, and the like using supercritical water.

In an aspect of the invention, an integrated process for in-field upgrading of hydrocarbons includes:

passing a hydrocarbon feed into an in-field upgrader from a hydrocarbonaceous production source;

mixing the hydrocarbon feed with a fluid comprising water that has been heated to a temperature higher than its critical temperature in a mixing zone to form a mixture;

passing the mixture to a reaction zone;

reacting the mixture in the reaction zone under supercritical water conditions in the absence of externally added hydrogen for a residence time sufficient to allow upgrading reactions to occur;

withdrawing a single-phase reaction product from the reaction zone;

recovering energy from said reaction product for use in the hydrocarbonaceous production source; and

separating the cooled reaction product into gas, effluent water, converted hydrocarbons and unconverted hydrocarbons.

Optionally, the above process for in-field upgrading of hydrocarbons further includes the step of applying distillation to the converted hydrocarbons.

Optionally, the above process for in-field upgrading of hydrocarbons further includes the step of blending a distillation overheads liquid with a distillation bottoms liquid.

Optionally, the above process for in-field upgrading of hydrocarbons further includes the steps of:

passing dregs to dregs processing;

contacting the dregs with a distillation overheads liquid; and

recycling extracted hydrocarbons back with the hydrocarbon feed.

Optionally, the above process for in-field upgrading of hydrocarbons further includes the steps of:

- mixing dregs with a fluid comprising water that has been heated to a temperature higher than its critical temperature in another mixing zone to form another mixture;
- passing the other mixture to another reaction zone;
- reacting and extracting hydrocarbons from the other mixture in the other reaction zone under supercritical water conditions in the absence of externally added hydrogen for a residence time sufficient to allow upgrading reactions to occur; and
- recycling a hydrocarbon product from the other reaction zone to the hydrocarbon feed.

Optionally, the above process for in-field upgrading of hydrocarbons further includes the step of applying distillation to the converted hydrocarbons.

Optionally, the above process for in-field upgrading of hydrocarbons further includes the step of blending a distillation overheads liquid with a distillation bottoms liquid.

Optionally, the above process for in-field upgrading of hydrocarbons further includes the step of recycling the distillation overheads liquid back with the hydrocarbon feed.

Optionally, in the above process for in-field upgrading of hydrocarbons, the hydrocarbonaceous production source is at least one selected from the group consisting of heavy crude oil, tar sands, bitumen, heavy petroleum crude oils, heavy vacuum gas oils, vacuum residuum, petroleum tar, coal tar, oil shale, asphaltenes and mixtures thereof.

Optionally, in the above process for in-field upgrading of hydrocarbons, the water is at least one selected from the group consisting of drinking water, treated or untreated wastewater, river water, lake water, seawater, produced water and mixtures thereof.

Optionally, in the above process for in-field upgrading of hydrocarbons, the water has a temperature in a range of about 374° C. to about 420° C. and a pressure in a range of about 3205 to about 4000 psia.

Optionally, in the above process for in-field upgrading of hydrocarbons, the mixture has an oil/water mass ratio in a range of about 1:1 to about 1:2.

Optionally, in the above process for in-field upgrading of hydrocarbons, the reacting has a residence time in a range of about 8 min to about 30 min.

Optionally, in the above process for in-field upgrading of hydrocarbons, the energy is recovered from the reaction product in a plurality of heat exchangers and steam boilers.

Optionally, the above process for in-field upgrading of hydrocarbons further includes utilizing the recovered energy in an enhanced oil recovery or steam assisted gravity drain process.

Optionally, in the above process for in-field upgrading of hydrocarbons, the dregs processing is conducted in at least one selected from the group consisting of a dregs washer, a mixer-settler unit, and a solids leaching unit.

Optionally, in the above process for in-field upgrading of hydrocarbons, the distillation is conducted in a tray or packed column.

Optionally, in the above process for in-field upgrading of hydrocarbons, the operation, pressure of the mixing is in a range of about 3250 to about 3600 psia and the operating temperature of the mixing is in a range of about 385 to about 420° C.

Optionally, in the above process for in-field upgrading of hydrocarbons, the operating pressure of the reacting is in a range of about 3205 to about 10000 psia and the operating temperature of the reacting is in a range of about 374 to about 1000° C.

Optionally, in the above process for in-field upgrading of hydrocarbons, the operating pressure of the separating is in a range of about 150 to about 3500 psia and the operating temperature of the separating is in a range of about 50 to about 300° C.

Optionally, in the above process for in-field upgrading of hydrocarbons, the separating, is conducted in at least one two-phase separator or three-phase separator.

Optionally, in the above process for in-field upgrading of hydrocarbons, the operating pressure of the distillation is in a range of about 1 to about 50 psia and the operating temperature of the distillation is in a range of about 40 to about 90° C.

DESCRIPTION OF THE DRAWINGS

FIG. 1 is a process flow diagram of an embodiment of the present invention.

FIG. 2 is a process flow diagram of another embodiment of the present invention.

DETAILED DESCRIPTION OF THE INVENTION

So that the above recited features and advantages of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to the embodiments thereof that are illustrated in the appended figures. It is to be noted, however, that the appended figures illustrate only a typical embodiment of this invention and is therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments.

Embodiments describing the process of the present invention are referenced in FIGS. 1 and 2. More specifically, the following embodiments describe the processes for implementing the present invention.

Reactants

Water and hydrocarbons (HC), preferably heavy hydrocarbons are the two reactants employed in a process according to the present invention.

Any heavy hydrocarbon from a hydrocarbonaceous production source can be suitably upgraded by a process according to the present invention. Preferred are heavy hydrocarbons having an API gravity of less than 20°. Also, preferably, the heavy hydrocarbons contain heteroatoms such as nitrogen and sulfur. Among the preferred heavy hydrocarbons are heavy crude oil, heavy hydrocarbons extracted from tar sands commonly called tar sand bitumen, such as Athabasca tar sand bitumen obtained from Canada, heavy petroleum crude oils such as Venezuelan Orinoco heavy oil belt crudes, Boscan heavy oil, heavy hydrocarbon fractions obtained from crude petroleum oils particularly heavy vacuum gas oils, vacuum residuum as well as petroleum tar, tar sands and coal tar. Other examples of heavy hydrocarbon feedstocks which can be used are oil shale, and asphaltenes.

Water

Any source of water may be used in the fluid comprising water in practicing the present invention. Sources of water include but are not limited to drinking water, treated or untreated wastewater, river water, lake water, seawater, produced water or the like.

Mixing

In accordance with the invention, the heavy hydrocarbon feed and a fluid comprising water that has been heated to a temperature higher than its critical conditions (temperature and pressure) are contacted in a mixing zone prior to entering the reaction zone. In accordance with the invention, mixing may be accomplished in many ways and is preferably accomplished by a technique that does not employ mechanical moving parts. Such means of mixing may include, but are not limited to, use of static mixers, spray nozzles, sonic or ultrasonic agitation. The oil and water should be heated and mixed so that the combined stream will reach supercritical water conditions in the reaction zone.

It was found that by avoiding excessive heating of the feed oil, the formation of byproduct such as solid residues is reduced significantly. One key aspect of this invention is to design the heating sequence so that the temperature and the pressure of the hydrocarbons and water will reach reaction conditions in a controlled manner. This will avoid excessive local heating of oil, which will lead to solid formation and lower quality product. In order to achieve better performance, the oil should only be heated up with sufficient water present and around the hydrocarbon molecules. This requirement can be met by mixing oil with water before heating up.

In FIG. 1, water is heated to a temperature higher than critical conditions, and then mixed with oil. The temperature of heavy oil feed should be kept in the range of about 100 to 343° C. to avoid thermal cracking but still high enough to maintain a reasonable pressure drop. The water stream temperature should be high enough to make sure that after mixing with oil, the temperature of the oil-water mixture is still higher than the water supercritical temperature. In this embodiment, the oil is actually heated by water in a direct contact heat exchange. An abundance of water molecules surrounding the hydrocarbon molecules will significantly suppress condensation reactions and therefore reduce formation of coke and solid product.

The required temperature of the supercritical water stream can be estimated based on the reaction temperature and water to oil ratio. Since the heat capacity of water changes significantly in the range near its critical conditions for a given reaction temperature, the required temperature for the supercritical water stream increases almost exponentially with decreasing water-to-oil ratio. The lower the water-to-oil ratio, the higher the temperature of the supercritical water stream. The relationship, however, is very nonlinear since a higher supercritical water stream temperature leads to a lower heat capacity (far away from the critical point).

Reaction Conditions

After the reactants have been mixed, they are passed into a reaction zone in which they are allowed to react under temperature and pressure conditions of supercritical water, i.e. supercritical water conditions, in the absence of externally added hydrogen, for a residence time sufficient to allow upgrading reactions to occur. The reaction is preferably allowed to occur in the absence of externally added catalysts or promoters, although the use of such catalysts and promoters is permissible in accordance with the present invention.

“Hydrogen” as used herein in the phrase, “in the absence of externally added hydrogen” means hydrogen gas. This phrase is not intended To exclude all sources of hydrogen that are available as reactants. Other molecules such as saturated hydrocarbons may act as a hydrogen source during the reaction by donating hydrogen to other unsaturated hydrocarbons. In addition, H₂may be formed in-situ during the reaction through steam reforming of hydrocarbons.

The reaction zone preferably comprises a reactor, which is equipped with a means for collecting the reaction products (syncrude, water, and gases), and a section, preferably at the bottom, where any metal containing compounds/organometallics or solids (the “dreg stream”) may accumulate.

Supercritical water conditions include a temperature from 374° C. (the critical temperature of water) to 1000° C., preferably from 374° C. to 600° C. and most preferably from 374° C. to 420° C., a pressure from 3205 (the critical pressure of water) to 10000 psia, preferably from 3205 to 7200 psia and most preferably from 32.05 to 4000 psia, an oil/water mass ratio from 11:0.1 to 1:10, preferably from 1:0.5 to 1:3 and most preferably about 1:1 to 1:2.

The reactants are allowed to react under these conditions for a sufficient time to allow upgrading reactions to occur. Preferably, the residence time will be selected to allow the upgrading reactions to occur selectively and to the fullest extent without having undesirable side reactions of coking or residue formation. Reactor residence times may be from 1 minute to 6 hours, preferably from 8 minutes to 2 hours and most preferably from 8 to 30 minutes.

Reaction Product Cooling and Heat Integration with Field Production

After the reaction has progressed sufficiently, a single phase reaction product is withdrawn from the reaction zone and cooled in a series of heat exchangers and steam boilers from a temperature of about 380 to 420° C. and pressure of about 3400 to 3600 psia to the final desired condition for phase separation which is preferably no lower than 150° C. and about 3400 psia. The first heat exchanger is a steam boiler, whereby the reaction product is cooled to a temperature of about 300° C. from one zone of the heat exchanger, and 80% quality steam at 900 psia steam is produced from the other zone. This steam (recovered energy from reaction product) is sent to the bitumen production field for steam injection in an enhanced oil recovery (EOR) operation, a steam assisted gravity drain (SAGD) operation, or any other hydrocarbon production operation where steam injection is required. The subsequent cooling steps of the 300° C. reaction product may include any combination of feed-effluent heat exchange steps to preheat inlet water streams, oil streams, and production of lower pressure steam (50 psia, 150 psia, 300 psia) for internal use within the process.

Reaction Product Separation

After cooling, the reaction product stream is separated into gas, effluent water, and upgraded hydrocarbon phases. This separation is preferably done by cooling the stream and using one or more two-phase separators, three-phase separators, or other gas-oil-water separation device known in the art. However, any method of separation can be used in accordance with the invention.

The composition of gaseous product obtained by treatment of the heavy hydrocarbons in accordance with the process of the present invention will depend on feed properties and typically comprises light hydrocarbons, water vapor, acid gas (CO₂and H₂S), methane and hydrogen. The effluent water may be used, reused or discarded. It may be recycled to e.g. the feed water tank, the feed water treatment system or to the reaction zone.

The upgraded hydrocarbon product, which is sometimes referred to as “syncrude” herein may be upgraded further or processed into other hydrocarbon products using methods that are known in the hydrocarbon processing art.

The process of the present invention may be carried out either as a continuous or semi-continuous process or a batch process or as a continuous process. In the continuous process, the entire system operates with a feed stream of oil and a separate feed stream of supercritical water and reaches a steady state; whereby all the flow rates, temperatures, pressures, and composition of the inlet, outlet, and recycle streams do not vary appreciably with time.

While not being bound to any theory of operation, it is believed that a number of upgrading reactions are occurring simultaneously at the supercritical water conditions used in the present process. In a preferred embodiment of the invention, the major chemical/upgrading reactions are believed to be:

Thermal Cracking: C_xH_y+H₂→lighter hydrocarbons
Steam Reforming: C_xH_y+2xH₂O→xCO₂+(2x+y/2)H₂
Demetalization: C_xH_yNi_w+H₂→Ni—HC+lighter hydrocarbons
Desulfurization: C_xH_yS_z+H₂→H₂S+lighter hydrocarbons

The exact pathway may depend on the reactor operating conditions (temperature, pressure, W/O mass ratio), reactor design (mode of contact/mixing, sequence of heating), and hydrocarbon feedstock.

Syncrude Distillation

The syncrude product is sent to a distillation column, which serves to (1) remove light ends from the syncrude prior to storage and transportation, and (2) to provide an overhead liquid stream that is lighter (i.e., higher API) than the syncrude feed. A portion of this overhead liquid stream could be recycled back to the front end of the process to dilute the feed hydrocarbon to ease the process (final API of 12-14). Alternately, this recycle stream may also be used to extract the hydrocarbon liquids from the dregs stream (see below). The remaining portion may be blended back to the bottoms stream of the column. Preferably, the column is heated by feeding in live, steam (150 psia, 188° C.) at the bottom stage of the column. The overhead of the column is cooled by any combination of air and water cooling to achieve a temperature of about 50° C. The column may be a trayed or packed column such as those known in the petroleum refining art.

Dregs Processing

The dregs stream refers to the by-product produced in the supercritical reactor that contains water, unreacted hydrocarbon liquids, coke-like materials, sulfur-containing materials, and metal containing compounds/organometallics. One preferred embodiment of processing the dregs stream is to contact a portion of the overhead liquid stream from the syncrude distillation unit with the dregs stream in a mixer-settler unit. The overhead liquid stream acts as a solvent for extracting the hydrocarbon liquids from the non-hydrocarbon, solid-like portion of the dregs stream. The extracted liquids are recycled back to the front end of the process to mix with the feed hydrocarbon to the supercritical water reactor. The non-extracted stream from the mixer-settlers are concentrated with the solids, and is sent to a reactor solids dryer heated with 300 psia steam. The solids dryer includes a porcupine heater, screw conveyor, or any other solids drying device known in the art. Residual liquids from the non-extracted stream are vaporized, recondensed, and separated to form gaseous products (sent to fuel or flare header), possibly water (sent to water treatment unit), and hydrocarbons (recycled along with the extracted hydrocarbon liquid streams). The solids portion are transported out via a conveyor belt or other solids-transportion method known in the art to a solids cooler, and then stored for eventual disposal or metals reclamation.

The following embodiments are illustrative of the present invention, but are not intended to limit the invention in any way beyond what is contained in the claims which follow.

EMBODIMENT

In an embodiment of the invention illustrated in FIG. 1, a heavy hydrocarbon feed stream 101 and a water feed stream 103, having compositions as shown in TABLES 1 & 2 (Simulated Example Data), are fed to a mixer 130. As described in more detail above, the mixer 130 may include, but is not limited to, static mixers, spray nozzles, and sonic or ultrasonic agitation. The heavy hydrocarbon feed stream 101 and the water feed stream 103 are mixed so that a combined stream 104 will reach supercritical water conditions. The operating pressure of the mixer 130 is in the range of about 3250 to about 3600 psia. The operating, temperature of the mixer 130 is in the range of about 385 to about 420° C. The oil/water mass mix ratio of the mixer 130 is in the range of about 1:0.5 to about 1:3.

The combined stream 104 is fed to a reactor 140. The combined stream 104 has a composition as shown in TABLES 1 & 2. As described in more detail above, the reactor 140 may include, but is not limited to, a reactor which is equipped with a means for collecting reaction products (syncrude, water, and gases), and a section, preferably at the bottom, where any metal containing compounds or solids (the “dreg stream”) may accumulate.

The reactants in the combined stream 104 are allowed to react under temperature and pressure conditions of supercritical water, for a residence time sufficient to allow upgrading reactions to occur.

The operating temperature of the reactor 140 is in the range of about 374° C. to about 1000° C. The operating pressure of the reactor 140 is in the range of about 3205 to about 10000 psia. The oil/water mass ratio is in the range of about 1:0.1 to a about 1:10. The residence time of the reactor is in the range of about 1 min to 6 hrs.

A reactants product stream 105 is cooled and fed to a separator 150. The reactants product stream 105 has a composition as shown in TABLES 1 & 2. As described in more detail above, the cooling may be conducted in a heat exchanger unit that includes, but is not limited to, a shell and tube heat exchanger and a plate heat exchanger. Water is cross heat exchanged with the reactants product stream 105. Due to this heat exchange, the water is vaporized into a superheated steam that may be integrated and used in a Steam Assisted Gravity Drainage (SAGD) process in an oil field.

As described in more detail above, the separator 150 may include, but is not limited to, one or more two-phase separators, three-phase separators, or other known gas-oil-water separation devices.

The reactants product stream 105 is separated into a gas stream 107, a syncrude stream 106, and an effluent water stream 108.

The operating pressure of the separator 150 is in the range of about 150 to 3500 psia. The operating temperature of the separator 150 is in the range of about 50 to 300° C.

The syncrude stream 106 is fed to a separator 160. The syncrude stream 106 has a composition as shown in TABLES 1 & 2. As described in more detail above, the separator 160 may include, but is not limited to, a packed or trayed-type distillation column equipped with a reboiler and condenser, a refluxed column with live steam injection at the bottom, or a vacuum distillation column. The operating pressure of the separator 160 is in the range of about 1 to about 50 psia. The operating temperature of the overhead condenser is in the range of about 40 to about 90° C.

A portion of the overheads diluent stream 109, 111 is combined with a bottoms syncrude stream 110 at a weight percentage in the range of about 0 to about 30%. A combined syncrude stream 112 is then fed to further downstream processes or to storage for further transport.

The overheads diluent stream 109 is also recycled (stream 113) and fed to a dregs processor 170. A dreg stream 114 is also fed to the dregs processor 170. The dreg stream 114 has a composition as shown in TABLES 1 and 2. As described in more detail above, the dregs processor 170 may include, but is not limited to, a dregs washer, a mixer-settler, and a solids leaching unit. The recycle diluent stream 113 from the separator 160 may be used to extract hydrocarbons from the dregs stream 114 in the dregs washer. The operating pressure of the dregs processor 170 is in the range of about 15 to 500 psia. The operating temperature of the dregs processor 170 is in the range of about 25 to 200° C.

Although not shown in the figure, the recycle stream 113 may also be fed directly back into the heavy hydrocarbon feed stream 101. This recycled diluent lowers the density of the heavy hydrocarbon stream 101 from about 5 to 10 to about 11 to 16 API. The combining of the diluent also allows for a reduction in the amount of the water feed stream 103.

A solid dregs stream 115 and a wet dregs stream 116 is output from the dregs processor 170. The wet dregs stream 116 is recycled back to the heavy hydrocarbon feed stream 101 to form 102, at a percentage in the range of about 50 to 100%. The remaining portion of the wet dregs stream may be combined with the syncrude product 112, used for fuel, or sent off to storage and transportation as a separate product stream.

In the tables below, two oil assays (one for the feed and one for the syncrude) are modeled using a set of hydrocarbon pseudocomponents. The notation, Blend 1 refers to the feed while Blend 2 refers to the product. The notation Blend 2 (170 to 265° C.) means that the group of components in Blend 2 have a boiling point range of 170 to 265° C. Non-HC gases refers to H₂, H₂S, CO₂, N₂, O₂, and NH₃. HC-Gases may include methane, ethane, propane, butane, pentane, cyclopentane, cyclohexane, and benzene. Oxygenates include phenol, heptanoic acid, and catechol.

TABLE 1 summarizes only the major streams—some intermediate heat exchange steps, pumping steps, internal recycle streams, and offsite facilities are not shown.

TABLE 1 Summary of Major Streams Only (Compositions in mass %) Stream Non HC BLND1 BLND1 BLND1 BLND 1 BLND 1 BLND 2 BLND 2 BLND 2 BLND 2 No HC Gases 203 to 433 to 654 to 880 to 1101 to 170 to 275 to 383 to 494 to (FIG. 1) H2O Gases (C1-C6) Oxygenate 421 C 649 C 875 C 1096 C 1217 C 265 C 375 C 485 C 634 C 101 <1.0 0 0 0 28.9 35.4 17.6 11.7 6.35 0 0 0 0 102 0.01 0.006 0.226 0.214 24.3 29.8 14.8 9.8 5.3 15.2 0.1 0 0 103 99.4 0.05 0.01 0.55 0 0 0 0 0 0 0 0 0 104 66.4 0.04 0.08 0.44 8.1 9.9 4.9 3.3 1.8 5.0 0.10 0 0 105 67.1 0.52 0.45 0.61 0 0 0 0 0 8.3 8.1 9.2 4.9 106 0.17 0.03 0.4 0.36 0 0 0 0 0 26 28 29.3 15.7 107 3 57.1 37.8 0.23 0 0 0 0 0 1.8 0 0 0 108 99.3 0 0 0.7 0 0 0 0 0 0 0 0 0 109 0.07 0.037 1.4 1.3 0 0 0 0 0 95.2 1.9 0 0 110 0.076 0 0 0 0 0 0 0 0 3.9 36.4 38.8 20.8 111 0.07 0.037 1.4 1.3 0 0 0 0 0 95.2 1.9 0 0 112 0.076 0 0.13 0.13 0 0 0 0 0 12.2 33.3 35.2 18.9 113 0.07 0.037 1.4 1.3 0 0 0 0 0 95.2 1.9 0 0 114 0 0 0 0 28.9 35.4 17.6 11.7 6.4 0 0 0 0 115 N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A 116 0.06 0.03 1.2 1.1 $ 5.7 2.8 1.9 1.0 79.9 1.6 0 0

TABLE 2 Summary of Major Streams Only Stream No. Flowrate Pressure Temp (FIG. 1) (lb/hr) (psia) (° C.) 101 4.43e5 20 90 102 5.47e5 3550 343 103 1.1e6 3600 405 104 1.65e6 3500 393 105 1.63e6 3500 393 106 5.12e5 180 156 107 1.35e4 175 40 108 2.74e5 175 40 109 1.24e5 25 50 110 3.87e5 30 280 111 3.68e4 25 50 112 4.26e5 25 50 113 8.72e4 25 50 114 1.77e4 20 200 115 4.9e3 20 50 116 1.0e5 20 76

OTHER EMBODIMENT

In another embodiment of the invention illustrated in FIG. 2, a heavy hydrocarbon feed stream 201 and a water feed stream 203, having conditions as shown in TABLE 3 (Simulated Example Data), are fed to a mixer 230. As described in more detail above, the mixer may include, but is not limited to, static mixers, spray nozzles, and sonic or ultrasonic agitation. The heavy hydrocarbon feed stream 201 and the water feed stream 203 are mixed so that a combined stream 204 will reach supercritical water conditions. The operating pressure of the mixer 230 is in the range of about 3250 to about 3600 psia. The operating temperature of the mixer 230 is in the range of about 385 to about 420° C. The oil/water mass mix ratio of the mixer 230 is in the range of about 1:0.5 to about 1:3.

The combined stream 204 is fed to a reactor 240. The combined stream 204 has conditions as shown in TABLE 3. As described in more detail above, the reactor 240 may include, but is not limited to, a reactor which is equipped with a means for collecting reaction products (syncrude, water, and gases), and a section, preferably at the bottom, where any metal containing compounds or solids (the “dreg stream”) may accumulate.

The reactants in the combined stream 204 are allowed to react under temperature and pressure conditions of supercritical water, for a residence time sufficient to allow upgrading reactions to occur.

The operating temperature of the reactor 240 is in the range of about 374° C. to about 1000° C. The operating pressure of the reactor 240 is in the range of about 3205 to about 10000 psia. The oil/water volume ratio is in the range of about 1:0.1 to a about 1:10. The residence time of the reactor is in the range of about 1 min to 6 hrs.

A reactants product stream 205 is cooled and fed to a separator 250. The reactants product stream 205 has flow conditions as shown in TABLE 3. The cooling may be conducted in a heat exchanger unit that includes, but is not limited to, a shell and tube heat exchanger and a plate heat exchanger. Water is cross heat exchanged with the reactants product stream 205. Due to this heat exchange, the water is vaporized into a superheated steam that may be integrated and used in a Steam Assisted Gravity Drainage (SAGD) process in an oil field.

As described in more detail above, the separator 250 may include, but is not limited to, one or more two-phase separators, three-phase separators, or other known gas-oil-water separation devices.

The reactants product stream 205 is separated into a gas stream 206, a syncrude stream 208, and an effluent water stream 207.

The operating temperature of the separator 250 is in the range of about 50 to 300° C. The operating pressure of the separator 250 is in the range of about 150 to 3500 psia.

The syncrude stream 208 is fed to a separator 260. The syncrude stream 208 has conditions as shown in TABLE 3. The separator 260 may include, but is not limited to, a packed or trayed-type distillation column equipped with a reboiler and condenser, a refluxed absorber equipped with live steam injection at the bottoms, or a vacuum distillation column. The operating pressure of the separator 260 is in the range of about 1 to about 50 psia. The operating temperature of the overhead condenser is in the range of about 40 to about 90° C.

A portion of an overhead diluent stream 209, 211 is combined with a bottoms syncrude stream 210 at a weight percentage in the range of about 0 to 30%. A combined syncrude stream 212 is then fed to further downstream processes or to storage and eventual transportation.

A portion of the overheads diluent stream 209 is also recycled (stream 213) and combined with the heavy hydrocarbon feed 201, and output as stream 202. This diluent lowers the density of the heavy hydrocarbon stream from about 5 to 10 API to a range of about 11 to 16 API. The combining of the diluent also allows for a reduction in the amount of the water feed stream 203.

A dreg stream 214 is fed to a mixer 270. As described in more detail above, the mixer may include, but is not limited to, static mixers, spray nozzles, and sonic or ultrasonic agitation. The dreg stream 214 and a water feed stream 215 are mixed so that a combined stream 216 will reach supercritical water conditions. The operating pressure of the mixer 270 is in the range of about 3250 to about 3600 psia. The operating temperature of the mixer 270 is in the range of about 385 to about 420° C. The oil/water mass mix ratio of the mixer 270 is in the range of about 1:1 to about 1:10.

The combined stream 216 is fed to a reactor 280. The combined stream 216 has conditions as shown in TABLE 3. As described in more detail above, the reactor 280 may include, but is not limited to, a reactor which is equipped with a means for collecting reaction products (hydrocarbon fraction, water, and gases), and a section, preferably at the bottom, where any metal containing compounds or solids (the “non-hydrocarbon fraction”) may accumulate.

The reactants in the combined stream 216 are allowed to react under temperature and pressure conditions of supercritical water, for a residence time sufficient to allow upgrading reactions to occur.

The operating temperature of the reactor 280 is in the range of about 374° C. to about 1000° C. The operating pressure of the reactor 280 is in the range of about 3205 to about 10000 psia. The oil/water volume ratio is in the range of about 1:0.1 to a about 1:10. The residence time of the reactor is in the range of about 1 min to 6 hrs.

A reactants product stream 218 is recycled back to stream 202. The reactants product stream also includes converted and unconverted hydrocarbons that are extracted in the reactor 280. The reactants product stream 218 has conditions as shown in TABLE 3.

This recycling allows for a number of benefits: (1) the raw crude feed (stream 201) is diluted and made less viscous and less dense, which makes mixing and reaction easier, and (2) reaction product (stream 208) is also diluted with lower-density material, which facilitates eventual separation of hydrocarbons from water in the separator 250.

Another dreg stream 217 is output from the bottom of the reactor 280. The dreg stream 217 includes hydrocarbon solids and metal-containing compounds.

In TABLE 3, flowrates are reported in mbpd, which means thousands of barrels/day at standard liquid conditions. TABLE 3 summarizes only the major streams—some intermediate heat exchange steps, pumping steps, internal recycle streams, and offsite facilities are not shown.

TABLE 3 Summary of Major Streams Only Stream No. Flowrate Pressure Temp (FIG. 2) (mbpd) (psia) (° C.) 201 30 3500 87 202 38.7 3500 83 203 79 3500 405 204 118 3500 393 205 126 3410 150 206 6.2 3410 150 207 114 3410 150 208 41.3 3410 150 209 12.4 115 52 210 27 115 50 211 3.7 105 52 212 31 105 50 213 8.7 105 50 214 1.2 3500 200 215 2.4 3500 390 216 13.4 3490 388 217 13.4 3490 388 218 1.2 100 80

Claims

1. An integrated process for in-field upgrading of hydrocarbons comprising:

passing a hydrocarbon feed into an in-field upgrader from a hydrocarbonaceous production source;

mixing the hydrocarbon feed with a fluid comprising water that has been heated to a temperature higher than its critical temperature in a mixing zone to form a mixture;

passing the mixture to a reaction zone;

reacting the mixture in the reaction zone under supercritical water conditions in the absence of externally added hydrogen for a residence time sufficient to allow upgrading reactions to occur;

withdrawing a single-phase reaction product from the reaction zone;

recovering energy from said reaction product for use in the hydrocarbonaceous production source; and

separating the cooled reaction product into gas, effluent water, converted hydrocarbons and unconverted hydrocarbons.

2. The process for in-field upgrading of hydrocarbons according to claim 1, further comprising the step of applying distillation to the converted hydrocarbons.

3. The process for in-field upgrading of hydrocarbons according to claim 2, further comprising the step of blending a distillation overheads liquid with a distillation bottoms liquid.

4. The process for in-field upgrading of hydrocarbons according to claim 2, further comprising the steps of:

passing dregs to dregs processing;

contacting the dregs with a distillation overheads liquid; and

recycling extracted hydrocarbons back with the hydrocarbon feed.

5. The process for in-field upgrading of hydrocarbons according to claim 1, further comprising the steps of:

mixing dregs with a fluid comprising water that has been heated to a temperature higher than its critical temperature in another mixing zone to form another mixture;

passing the other mixture to another reaction zone;

reacting and extracting hydrocarbons from the other mixture in the other reaction zone under supercritical water conditions in the absence of externally added hydrogen for a residence time sufficient to allow upgrading reactions to occur; and

recycling a reactants product stream from the other reaction zone to the hydrocarbon feed.

6. The process for in-field upgrading of hydrocarbons according to claim 5, further comprising the step of applying distillation to the converted hydrocarbons.

7. The process for in-field upgrading of hydrocarbons according to claim 6, further comprising the step of blending a distillation overheads liquid with a distillation bottoms liquid.

8. The process for in-field upgrading of hydrocarbons according to claim 6, further comprising the step of recycling the distillation overheads liquid back with the hydrocarbon feed.

9. The process for in-field upgrading of hydrocarbons according to claim 1, wherein the hydrocarbonaceous production source is at least one selected from the group consisting of heavy crude oil, tar sands, bitumen, heavy petroleum crude oils, heavy vacuum gas oils, vacuum residuum, petroleum tar, coal tar, oil shale, asphaltenes and mixtures thereof.

10. The process for in-field upgrading of hydrocarbons according to claim 1, wherein the water is at least one selected from the group consisting of drinking water, treated or untreated wastewater, river water, lake water, seawater, produced water and mixtures thereof.

11. The process for in-field upgrading of hydrocarbons according to claim 1, wherein the water has a temperature in a range of about 374° C. to about 420° C. and a pressure in a range of about 3205 to about 4000 psia.

12. The process for in-field upgrading of hydrocarbons according to claim 1, wherein the mixture has an oil/water mass ratio in a range of about 1:1 to about 1:2.

13. The process for in-field upgrading of hydrocarbons according to claim 1, wherein the reacting has a residence time in a range of about 8 min to about 30 min.

14. The process for in-field upgrading of hydrocarbons according to claim 1, wherein the energy is recovered from the reaction product in a plurality of heat exchangers and steam boilers.

15. The process for in-field upgrading of hydrocarbons according to claim 1, further comprising utilizing the recovered energy in an enhanced oil recovery or steam assisted gravity drain process.

16. The process for in-field upgrading of hydrocarbons according to claim 4, wherein the dregs processing is conducted in at least one selected from the group consisting of a dregs washer, a mixer-settler unit, and a solids leaching unit.

17. The process for in-field upgrading of hydrocarbons according to claims 2 or 6, wherein the distillation is conducted in a tray or packed column.

18. The process for in-field upgrading of hydrocarbons according to claim 1, wherein the operating pressure of the mixing is in a range of about 3250 to about 3600 psia and the operating temperature of the mixing is in a range of about 385 to about 420° C.

19. The process for in-field upgrading of hydrocarbons according to claim 1, wherein the operating pressure of the reacting is in a range of about 3205 to about 10000 psia and the operating temperature of the reacting is in a range of about 374 to about 1000° C.

20. The process for in-field upgrading of hydrocarbons according to claim 1, wherein the operating pressure of the separating is in a range of about 150 to about 3500 psia and the operating temperature of the separating is in a range of about 50 to about 300° C.

21. The process for in-field upgrading of hydrocarbons according to claim 1, wherein the separating is conducted in at least one two-phase separator or three-phase separator.

22. The process for in-field upgrading of hydrocarbons according to claims 2 or 6, wherein the operating pressure of the distillation is in a range of about 1 to about 50 psia and the operating temperature of the distillation is in a range of about 40 to about 90° C.