Patent Application
20090321323
The present invention relates generally to producing hydrocarbons. More specifically, the invention relates to methods and systems for upgrading bitumen in a solvent based froth treatment process using electrostatic desalting for optimization of the process.
The economic recovery and utilization of heavy hydrocarbons, including bitumen, is one of the world's toughest energy challenges. The demand for heavy crudes such as those extracted from oil sands has increased significantly in order to replace the dwindling reserves of conventional crude. These heavy hydrocarbons, however, are typically located in geographical regions far removed from existing refineries. Consequently, the heavy hydrocarbons are often transported via pipelines to the refineries. In order to transport the heavy crudes in pipelines they must meet pipeline quality specifications.
The extraction of bitumen from mined oil sands involves the liberation and separation of the bitumen from the associated sands in a form that is suitable for further processing to produce a marketable product. Among several processes for bitumen extraction, the Clark Hot Water Extraction (CHWE) process represents an exemplary well-developed commercial recovery technique. In the CHWE process, mined oil sands are mixed with hot water to create slurry suitable for extraction as bitumen froth.
After extraction, the heavy oil slurry (e.g. bitumen froth) may be subjected to a paraffinic froth treatment process. In such a process, the slurry or froth may be introduced into a froth separation unit (FSU) wherein the froth is separated into a diluted bitumen stream and a tailings stream. The diluted bitumen stream may be directed to a solvent recovery unit (SRU) for flashing or other processing to produce a hot bitumen product stream and a solvent stream. The hot bitumen product stream may be sent to a pipeline for production and the solvent stream may be recycled in the treatment process.
Electrostatic desalters/dehydrators have been utilized in the oil field and at refineries for the purpose of removing contaminants in the oil being processed. This generally results in reduced corrosion and fouling, control of trace metal content, and improved wastewater treatment. See, e.g. S
Methods to optimize the efficiency of settlers can significantly impact the efficiency of heavy hydrocarbon (e.g. bitumen) recovery processes. There exists a need in the art for a low cost method to produce pipeline quality hydrocarbons from heavy oil or bitumen.
In one aspect of the invention, a system of recovering hydrocarbons is provided. The system includes a bitumen froth inlet stream including bitumen, water, solids, and at least one paraffinic solvent; a froth separation unit configured to receive the bitumen froth inlet stream and produce at least a diluted bitumen stream and a first tailings stream; a solvent recovery unit configured to receive the diluted bitumen stream and produce a product bitumen stream and a solvent recycle stream; and at least one electrostatic desalter configured to receive at least one of the diluted bitumen stream and the product bitumen stream and produce a treated bitumen stream. The system may also include a second froth separation unit to produce a second diluted bitumen stream to the electrostatic desalter and a control unit for optimize operation of the desalter in the system.
In another aspect of the invention, a method for recovering hydrocarbons is provided. The method includes providing a bitumen froth inlet stream including a volume of paraffinic solvents, a volume of water, and asphaltenes; settling out at least a portion of the asphaltenes in a froth separation unit to produce at least a first settled out asphaltenes stream (a first tailings stream) and a diluted bitumen stream; separating the volume of paraffinic solvents from the diluted bitumen stream in a solvent recovery unit configured to produce a product bitumen stream and a solvent recycle stream; and treating at least one of the diluted bitumen stream and the product bitumen stream in at least one electrostatic desalter to produce a treated bitumen stream. The method may further include providing a second diluted bitumen stream to the desalter from a second froth separation unit and may also include controlling certain process conditions to optimize the performance of the desalter in the process.
The foregoing and other advantages of the present invention may become apparent upon reviewing the following detailed description and drawings of non-limiting examples of embodiments in which:
In the following detailed description section, the specific embodiments of the present disclosure are described in connection with preferred embodiments. However, to the extent that the following description is specific to a particular embodiment or a particular use of the present disclosure, this is intended to be for exemplary purposes only and simply provides a description of the exemplary embodiments. Accordingly, the disclosure is not limited to the specific embodiments described below, but rather, it includes all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.
The term “asphaltenes” as used herein refers to hydrocarbons which are the n-heptane insoluble, toluene soluble component of a carbonaceous material such as crude oil, bitumen or coal. One practical test to determine if oil is an asphaltene is to test whether the oil is soluble when blended with 40 volumes of toluene but insoluble when the oil is blended with 40 volumes of n-heptane. If so, the oil may be considered an asphaltene. Asphaltenes are typically primarily comprised of carbon, hydrogen, nitrogen, oxygen, and sulfur as well as trace amounts of vanadium and nickel. The carbon to hydrogen ratio is generally about 1:1.2, depending on the source.
The term “bitumen” as used herein refers to heavy oil. In its natural state as oil sands, bitumen generally includes asphaltenes and fine solids such as mineral solids.
The invention relates to processes and systems for recovering hydrocarbons. In one aspect, the invention relates to a system for recovering hydrocarbons. The system may include a plant located at or near a bitumen (e.g. heavy hydrocarbon) mining or recovery site or zone. The plant may include at least one froth separation unit (FSU) having a bitumen froth inlet for receiving bitumen froth (or a solvent froth-treated bitumen mixture) and a diluted bitumen outlet for sending diluted bitumen from the FSU. The plant also includes a solvent recovery unit for separating bitumen from solvent to produce a solvent recycle stream and a bitumen product stream. The plant further includes at least one electrostatic desalter configured to treat either or both of the diluted bitumen stream and the bitumen product stream. Where the desalter is configured to treat the diluted bitumen stream, the SRU will be configured to separate the treated bitumen stream. The plant may also include at least one tailings solvent recovery unit (TSRU), solvent storage unit, pumps, compressors, and other equipment for treating and handling the heavy hydrocarbons and byproducts of the recovery system.
In another aspect, the invention is a process to partially upgrade a bitumen or heavy crude and is particularly suited for bitumen froth generated from oil sands which contain bitumen, water, and asphaltenes. The process includes providing a bitumen froth inlet stream having asphaltenes, paraffinic solvents, and water, settling out at least some of the asphaltenes in a froth separation unit (FSU) to produce a diluted bitumen stream and a tailings stream, separating the solvents from the diluted bitumen stream in a solvent recovery unit (SRU) to produce a bitumen product stream and a solvent recycle stream, and treating either or both of the diluted bitumen stream and the bitumen product stream in an electrostatic desalter to produce a treated bitumen stream. In the case where the treatment is of the diluted bitumen stream, the separation step separates the treated bitumen stream rather than the diluted bitumen stream.
Referring now to the figures,
In one exemplary embodiment of the present invention, the desalters 134 and 142 include a fresh water inlet stream 131a having a control valve and a chemical inlet stream 131b with a control valve (only shown on desalter 134). The streams are connected to the diluted bitumen stream 130 for addition to stream 130. The desalters 134 and 142 also preferably include a mixing valve or other such device 132 for mixing the diluted bitumen stream 130 with either or both of the fresh water inlet stream 131a and the chemical inlet stream 131b. This exemplary embodiment may further include a control unit 138 having input/output lines 139a-139x for obtaining data from sensors in the system 100 and sending control signals to various parts of the plant 100. The control unit 138 is preferably an automated unit, but may include some manual operability such as a manual override, or be completely manually operated. This exemplary embodiment may further include a heating unit to raise the temperature of the diluted bitumen stream 130 (or product bitumen stream 110) to at least about 115 degrees Celsius (° C.) up to about 150° C.
The control unit is configured to receive at least one data input and modify at least one process condition to optimize a composition of the treated bitumen stream 136. The data input may be one or more of the following: a flow rate of the diluted bitumen stream, a flow rate of the fresh water inlet stream, a flow rate of the chemical inlet stream, a composition of the diluted bitumen stream, a composition of chemicals flowing through the chemical inlet, an electrostatic field characteristic, a temperature inside the electrostatic desalter, a mixing valve pressure, mixing valve intensity, a temperature of the diluted bitumen stream, a thickness of an emulsion layer, and any combination thereof. The process condition may be one or more of: the flow rate of the diluted bitumen stream, the flow rate of the fresh water inlet stream, the flow rate of the chemical inlet stream, a solvent content of the diluted bitumen stream, the composition of chemicals flowing through the chemical inlet, the electrostatic field characteristic, the temperature inside the electrostatic desalter, the mixing valve pressure, the mixing valve intensity, the temperature of the diluted bitumen stream, the thickness of an emulsion layer, and any combination thereof.
In another embodiment, the desalters 134 and 142 may be configured as multiple desalting units. The desalting units 134 and 142 may be arranged as a multi-stage train such as a two stage train, or may be operated in parallel, such as by having two parallel single-stage units. Any number of units may be used, which will depend on cost, availability, desired capacity and other operational factors that are best addressed by a person of ordinary skill in the art on a case-by-case basis.
In an exemplary embodiment of the plant 100, the bitumen froth 102 may be mixed with a solvent-rich oil stream 120 from FSU 116 in FSU 104. Additionally, the solvent recycle stream 112 may be mixed with tailings 114 from the first FSU 104 and fed into a second froth separation unit 116. The second FSU 116 produces a solvent rich oil stream 120 and a second tailings stream 118. The solvent rich oil stream 120 is mixed with the incoming bitumen froth 102 and the tailings stream is sent to a tailings solvent recovery unit 122, which produces a third tailings stream 124 and a solvent stream 126. In a conventional paraffinic froth treatment (PFT) plant, the temperature of FSU 104 may be maintained at about 60 to 80 degrees Celsius (° C.), or about 70° C. and the target solvent to bitumen ratio of such prior art systems is about 1.4:1 to 2.2:1 by weight or about 1.6:1 by volume on average. In the disclosed plant 100, the target solvent to bitumen ratio is reduced by 10 to 50% from those listed above. This ratio will vary depending on the solids concentration in the bitumen, types of solvents used, composition of the bitumen, and other factors. However, it is expected that the desalters 134 or 142 are expected to reduce the solids concentration (in parts per million) by about half. This solvent reduction makes operation of the plant 100 more cost efficient, permits utilization of smaller FSU's 104 and 116, and a smaller SRU 108 to treat an equivalent amount of produced bitumen.
The bottom stream 114 from FSU 104 is the tailings substantially comprising water, mineral solids, asphaltenes, and some residual bitumen. The residual bitumen from this bottom stream is further extracted in FSU 116 by contacting it with fresh solvent (from e.g. 112 or 126). The bottom stream 114 of the plant 100 has a lower flow rate than the bottom stream of a conventional PFT plant and the solvent to bitumen ratio is also lower. In addition, FSU 116 may be smaller relative to the amount of bitumen recovered in stream 102.
The solvent-rich overflow 120 from FSU 116 may be mixed with the bitumen froth feed 102. The bottom stream 118 from FSU 116 is the tailings substantially comprising solids, water, asphaltenes, and residual solvent. The bottom stream 118 is fed into a tailings solvent recovery unit (TSRU) 122, a series of TSRUs or by another recovery method. In the TSRU 122, residual solvent is recovered and recycled in stream 126 prior to the disposal of the tailings in the tailings ponds (not shown) via a tailings flow line 124. Exemplary operating pressures of FSU 104 and FSU 116 are respectively about 550 thousand Pascals gauge (kPag) and about 600 kPag mixed pentane solvents. Other solvents may require a higher pressure to prevent boiling or allow for operation at lower pressures. FSUs 104 and 116 are typically made of carbon-steel but may be made of other materials.
Still referring to
In the process 200 solvent 120 is added to the bitumen-froth 102 after extraction and the mixture is pumped to another separation vessel (froth separation unit or FSU 104). The addition of solvent 120 helps remove the remaining fine solids and water. Put another way, solvent addition increases the settling rate of the fine solids and water out of the bitumen mixture. Because of the treatment step 210 of the present process 200, less solvent is used and fewer asphaltenes and other solids are settled out of the bitumen mixture. The treatment step 210 removes many of these solids in addition to dehydrating the bitumen stream, removing salts, and other impurities. In one embodiment of the recovery process 200 a paraffinic solvent is used to dilute the bitumen froth 102 before separating the product bitumen by gravity in a device such as FSU 104. Where a paraffinic solvent is used (e.g. when the weight ratio of solvent to bitumen is greater than 0.8), a portion of the asphaltenes in the bitumen are rejected thus achieving solid and water levels that are lower than those in existing naphtha-based froth treatment (NFT) processes. In the NFT process, naphtha may also be used to dilute the bitumen froth 102 before separating the diluted bitumen by centrifugation (not shown), but not meeting pipeline quality specifications.
As would be expected with any process, the preferred conditions seek to produce the greatest amount of bitumen product 110 with the least amount of expense (e.g. from energy use, chemical use, etc.). Variables that could be configured include, but are not limited to: flow rate of the diluted bitumen stream, flow rate of the fresh water inlet stream, flow rate of the chemical inlet stream, solvent content of the diluted bitumen stream, composition of chemicals flowing through the chemical inlet, electrostatic field characteristics, temperature inside the electrostatic desalter, mixing valve pressure, mixing valve intensity, temperature of the diluted bitumen stream, thickness of an emulsion layer, and any combination thereof. Configuring the preferred conditions may be accomplished by obtaining data 212 related to the process 200 and controlling process steps 214 like those listed above via manual or automated control systems such as controller 138.
Although all types of electrostatic desalters are within the scope of the present disclosure, one preferred type of electrostatic desalter 300 utilizes a combined alternating current (AC)/ direct current (DC) field. Depending on the composition of the bitumen feed 102, it may be preferable to utilize a modulated high voltage DC field with AC (MHVDC/AC) type of desalter, bi-modal field modulation (BFM) type of desalter, or another type. See, e.g. SPE 97786, supra, which is hereby incorporated by reference for further description of these desalter types. The basic electrode 308 configuration is the same for all of these types of desalters.
In operation, the desalter 300 mixes the feed stream 312 and/or 130 with fresh “wash water” 314 and/or 131a and a chemical agent 316 and/or 131b. The combined stream is then mixed in the valve mixer 318 and/or 132 to form an emulsion. In general, the AC field is established between the bottom of the electrodes 308 and the oil/water interface and promotes initial water droplet coalescence. The DC field is generated between each pair of oppositely charged electrodes 308 establishing an electrostatic voltage field between the electrodes 308. This field is a significant factor in the dipole force, electrophoretic force, and the di-electrophoretic force, which are often referred to as “coalescence forces,” which directly affect the amount of separation of water from oil droplets.
Some exemplary factors that affect desalter operation and performance include the feed rate and quality of the feed composition, temperature/viscosity/density relationships, electrical field intensity, wash water rate and quality, flow configuration, emulsion formation (e.g. by pumps, exchangers, valves, and mixers, etc.), control of water level and emulsion layers, demulsifier chemicals addition rate, and others. Treatment of heavy oils having asphaltenes and mineral solids provide additional challenges and may require specific solutions such as increasing the temperature of the desalter to lower the viscosity of the heavy hydrocarbon, increasing the amount of chemical demulsifier to destabilize the solids-stabilized emulsion, and enhanced degassing techniques. Also, sludge drains and mud washing techniques may be utilized to prevent accumulation of solids in the desalter tank 304. Another optional feature is the use of a highly sensitive level probe to sense the water content of the oil/water interface layer. These and other factors and techniques are discussed in greater detail in W
The SRU 408 may be a conventional fractionation vessel or other suitable apparatus in association with other suitable equipment for this purpose in which the solvent 414 is flashed off and condensed in a condenser 416 associated with the solvent flashing apparatus and recycled/reused in the process 400. The solvent free bitumen product 410 is then stored or transported for further processing (e.g. via pipeline) in a manner well known in the art or sent to the electrostatic desalter 300b. Froth treatment tailings component 412 may be passed directly to the tailings solvent recovery unit (TSRU) 430 or may first be passed to a second FSU 420.
In one embodiment, FSU 404 operates at a temperature of about 60° C. to about 80° C., or about 70° C. In one embodiment, FSU 404 operates at a pressure of about 700 to about 900 kPa, or about 800 kPa. Diluted tailings component 412 may typically comprise approximately 50 to 70 wt % water, 15 to 30 wt % mineral solids, and 5 to 25 wt % hydrocarbons. The hydrocarbons comprise asphaltenes (for example 2.0 to 12 wt % or 9 wt % of the tailings), bitumen (for example about 7.0 wt % of the tailings), and solvent (for example about 8.0 wt % of the tailings). In additional embodiments, the tailings may comprise greater than 1.0, greater than 2.0, greater than 3.0, greater than 4.0, greater than 5.0, greater than 10.0 wt % asphaltenes, or about 15.0 wt % asphaltenes.
Still referring to
In the exemplary system of
Flashed solvent vapor and steam (together 434) is sent from TSRU 430 to a condenser 436 for condensing both water 438 and solvent 440. Recovered solvent 440 may be reused in the bitumen froth treatment plant 400. Tailings component 432 may be sent directly from TSRU 430 to a tailings storage area (not shown) for future reclamation or sent to a second TSRU (not shown) or other devices for further treatment. Tailings component 432 contains mainly water, asphaltenes, mineral matter, and small amounts of solvent as well as unrecovered bitumen. A third TSRU (not shown) could also be used in series and, in each subsequent stage, the operating pressure may be lower than the previous one to achieve additional solvent recovery. In fact, more than three TSRU's could be used, depending on the quality of bitumen, pipeline specification, size of the units and other operating factors.
As noted, plant 500 includes many similar components as the plant 400 and to the extent the schematics look the same, they may be considered equivalent. For example, the froth separation portion 501 includes FSU's 404 and 420, but shows a slightly different flow configuration and a heating unit 507. Additional alternative flow schemes are shown between the froth separation portion 501, the solvent recovery portion 503, and the tailings recovery portion 505. These flow lines include additional heaters like 507 as well as separation/accumulation tanks such as 509a and 509b. The solvent recovery portion 503 includes a solvent recovery unit 408 as well as a vacuum system 511 and a steam generation unit 513. These additional units (e.g. 511 and 513) may also be included in plant 100 and plant 400, but were not shown for simplicity. They are shown in plant 500 for illustrative purposes and as just one example of a layout for a process plant for treating bitumen froth. The plant 500 also more specifically contemplates a high temperature bitumen treatment process.
While the present disclosure may be susceptible to various modifications and alternative forms, the exemplary embodiments discussed above have been shown only by way of example. However, it should again be understood that the disclosure is not intended to be limited to the particular embodiments disclosed herein. Indeed, the present disclosure includes all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.
This application claims the benefit of U.S. Provisional Application No. 61/133,270, filed Jun. 27, 2008.
| Number | Date | Country | |
|---|---|---|---|
| 61133270 | Jun 2008 | US |
