Process for upgrading ultralight crude oil and condensates

Abstract

A method comprising the steps of feeding condensate to a splitter unit; directing the resulting naphtha product to a naphtha hydrotreater and the resulting diesel product to a diesel hydrotreater; directing ULSD product from the diesel hydrotreater to ULSD storage and naphtha product from the diesel hydrotreater to the naphtha hydrotreater; directing treated naphtha product from the naphtha hydrotreater to a naphtha splitter; isomerizing the light naphtha product and reforming the heavy naphtha product; sending the isomerate and the reformate to a gasoline separator; directing the products to storage.

Claims

1. A method of upgrading ultralight crude oil and condensates comprising the steps of: feeding a stream of ultralight crude oil to a condensate splitter unit, the stream of ultralight crude oil having one or more of the following attributes: an API gravity between 46 and 58, a sulfur content less than 0.1%, or Reid vapor pressure between 5 and 15 psig; splitting a first stream of NAPHTHA, and a first stream of diesel from the condensate splitter unit; feeding at least part of the first stream of NAPHTHA to a NAPHTHA stabilizer to form a product stream of NAPHTHA; and feeding the first stream of diesel from the splitter unit to a diesel hydrotreater and introducing a stream of hydrogen to form a product stream of ultra-low sulfur diesel.

2. The method of claim 1 further comprising the step of feeding a second stream of NAPHTHA from the diesel hydrotreater to the first stream of NAPHTHA.

3. The method of claim 1 further comprising the step of forming a stream of liquid petroleum gas from the NAPHTHA stabilizer.

4. A method of upgrading ultralight crude oil and condensates comprising the steps of: feeding a stream of ultralight crude oil to a condensate splitter unit, the stream of ultralight crude oil having one or more of the following attributes: an API gravity between 46 and 58, a sulfur content less than 0.1%, or Reid vapor pressure between 5 and 15 psig; splitting a first stream of NAPHTHA, and a first stream of diesel from the condensate splitter unit; feeding at least part of the first stream of NAPHTHA to a NAPHTHA hydrotreater to form a hydrotreated stream of NAPHTHA; and feeding the first stream of diesel from the splitter unit to a diesel hydrotreater and introducing a stream of hydrogen to form a product stream of ULSD ultra-low sulfur diesel; feeding the hydrotreated stream of NAPHTHA to a NAPHTHA splitter unit; splitting a stream of light NAPHTHA and a stream of heavy NAPHTHA from the NAPHTHA splitter; feeding the stream of light NAPHTHA to an isomerization unit to form at least a stream of isomerate; feeding the stream of heavy NAPHTHA to a reformer unit to form at least a stream of reformate; feeding the stream of isomerate and the stream of reformate to a gasoline separator and forming at least a product stream of gasoline.

5. The method of claim 4 further comprising the step of feeding a second stream of NAPHTHA from the diesel hydrotreater to the first stream of NAPHTHA.

6. The method of claim 4 further comprising the step of forming a stream of liquid petroleum gas from the NAPHTHA stabilizer.

7. The method of claim 4 further comprising the step of forming a stream of LPG from the isomerization unit.

8. The method of claim 7 further comprising the step of producing a product stream of LPG from the gasoline separator.

9. The method of claim 4 further comprising the step of forming a stream of LPG from the reformer unit.

10. The method of claim 9 further comprising the step of producing a product stream of LPG from the gasoline separator.

11. The method of claim 1 performed without performing the step of hydrosulferization.

12. The method of claim 1 comprising the step of splitting a first stream of offgas from the condensate splitter unit and introducing the first stream of offgas to a caustic scrubber.

13. The method of claim 12 comprising the step of using the caustic scrubber to convert hydrogen sulfide to form at least one stream of sodium sulfides.

14. The method of claim 1 without splitting a stream of LPG from the condensate splitter unit.

Description

BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS

(1) For an improved understanding of the present invention, and the advantages thereof, reference is made to the following descriptions taken in conjunction with the accompanying figures:

(2) FIG. 1 is a block flow diagram schematic showing a refining system that may be used for upgrading ultralight crude oil and condensates.

(3) FIG. 2A and FIG. 2B are a block flow diagram of a typical refinery for heavier crude oil.

(4) FIG. 3 is a block flow diagram schematic showing an alternative refining system that may be used for upgrading ultralight crude oil and condensates.

DETAILED DESCRIPTION OF THE INVENTION

(5) The present invention provides a process for upgrading ultralight fluid to finished products, said fluid consisting of these typical properties: API gravity between 46 and 58; sulfur content less than 0.1%; Reid vapor pressure between 5 and 15 psig; originating from reservoirs utilizing hydraulic fracturing techniques. The finished products include ultra-low sulfur diesel, meeting conventional industry specifications; low sulfur marine gas oil, meeting conventional industry specifications; low sulfur marine fuel oil, meeting conventional industry specifications; and regular gasoline, meeting conventional industry specifications.

(6) FIG. 1 illustrates one embodiment of the present invention. This embodiment consists of a crude splitter; a hydrogen supply; a gas treater; a diesel hydrotreater; a naphtha stabilizer; boilers; and furnaces. Ultralight fluid is preheated and then desalted to remove inorganic contaminants. The desalted fluid is further heated to produce a vapor/liquid mixture. The fluid is then supplied via line 20 to an atmospheric crude distillation column (“crude splitter”) 22. The crude splitter 22 outputs several streams, including naphtha via line 24, diesel via line 26, offgas via line 28, and bottoms via line 30.

(7) The naphtha (i.e., light hydrocarbon) in line 24 is directed to a naphtha stabilizer (i.e., stripper) 32 and it is joined with additional naphtha carried in line 34 before entering the naphtha stabilizer 32. The naphtha stabilizer stabilizes the naptha by removing the highly volatile, light hydrocarbons thereby reducing the Reid Vapor Pressure “RVP” to an acceptable level and then sent to storage for naphtha sales.

(8) The diesel in line 26 is directed to a diesel hydrotreater 36—which in some embodiments might experience one percent (1%) volume loss—the diesel hydrotreater 36 receives a feed of hydrogen gas from a hydrogen supply 38. In the diesel hydrotreater 36, the diesel from line 26 hydrogen and catalyst to produce several outputs. The diesel hydrotreater 36 outputs several streams, including the naphtha in line 34, ULSD via line 40, offgas via line 42 and a fourth line 44. The fourth line passes accidentally reacted material back and forth between the naphtha stabilizer 32 and the diesel hydrotreater 36.

(9) The offgas in line 28 is directed to a gas treater 46 and it is joined with additional offgas in line 42 and offgas in line 48. The offgas in line 48 is an output from the naphtha stabilizer 32. The naphtha stabilizer 32 outputs several streams, including the offgas in line 48, LPG in line 50, and naphtha in line 52.

(10) The gas treater 46, which takes raw gas as an input, contacts the gas with a caustic solution to remove hydrogen sulfide, and provides low sulfur off gas as output via line 54. The low sulfur off gas as in line 54 is directed to furnaces 56 and boilers 58. Furnaces 56, which take low sulfur off gas as input, provide heat for various process streams such as distillation and catalytic reaction. And boilers 58, which take low sulfur off gas and water as inputs, provide steam 60 as an output.

(11) The bottoms in line 30 are directed to bottoms storage 62 and the bottoms in line 30 are joined with some naphtha in line 24 before entering the bottoms storage 62. Before the entering bottoms storage, the bottoms are cooled and after storage will eventually be sold for marine fuel oil sales—or similar applications.

(12) Other output streams from this embodiment are directed to product storage. The LPG in line 50 is fed to LPG storage 64. The naphtha in line 52 is fed to naphtha storage 66. The ULSD in line 40 is fed to ULSD storage 68.

(13) The supply of ultralight fluid can be adjusted in alternative embodiments. However, it is envisioned that a supply of 10,000 barrels per day (“BPD”) input of ultralight fluid will result in final products in the following proportions: 0 BPD of LPG; 4,432 BPD of naphtha; 4,701 BPD of ULSD; and 5,096 BPD of bottoms, 699 BPD of which are reconstituted crudes.

(14) FIGS. 2A and 2B illustrates the units and their arrangement in a typical refinery for crude oils. Most of the units and products derived therefrom are not required or used in the present invention.

(15) Existing refineries are designed to process heavier crude oil. Such refineries have extraordinary expense and challenges that are avoided with the present invention, which is designed to process light crude oil and condensate. For instance, separate the heavier crude oil into several components using atmospheric distillation, vacuum distillation, naphtha fractionation, LPG fractionation, and solvent deasphalting. By focusing on ultra-light fluid, the present invention separates the light crude oil into a limited number of components using only atmospheric distillation. Stated differently, ultralight fluid is distinguished from heavier crude oil, in part, by the high sulfur content found in heavier crude oil. As a result, existing refineries are forced to remove large amounts of sulfur. Such a refinery is complex and involves: 30-60% gas oil required to be cracked; 5-40% asphalt which must be cooked or sold as high sulfur asphalt or fuel oil; lots of hydrogen; extensive utilities—cooling towers, boilers, BFW treating, waste water treatment, etc.; and end products are typically blended. The present invention only has 5-20% bottoms; no asphalt or fuel oil; minimal blending; minimal tankage; and minimal utilities.

(16) Also with respect to sulfur, existing refineries convert hydrogen sulfide (“H.sub.2S”) to elemental sulfur via Claus sulfur plants, which require tail gas units for environmental compliance. By contrast, the present invention converts hydrogen sulfide to sodium sulfides using a caustic scrubber.

(17) With respect to cracking, existing refineries convert heavy hydrocarbon molecules to lighter hydrocarbon molecules via “cracking” in units such as fluid catalytic crackers and hydrocrackers. The present invention does not “crack” heavy hydrocarbon molecules since these molecules are suited for direct use as marine fuel oil due to low sulfur content.

(18) Existing refineries involve multiple components, which must be balanced. For example, it is not uncommon to find the following components present (with relevant octane levels): FCC gasoline (87); reformate upgraded from 65 (85-98); alkylate (93-98); ethanol/MTBE (115); and Light straight run naphtha (65-75).

(19) As mentioned, existing refineries require large quantities of hydrogen. To meet the demands, existing refineries produce hydrogen via naphtha reforming or steam methane reforming processes and systems. By contrast, the present invention does not produce hydrogen since only a small amount is needed for the small amounts of sulfur. Instead, the present invention calls for a small hydrogen supply.

(20) Existing refineries convert olefinic LPG to alkylate via hydrogen fluoride (“HF”) or hydrogen sulfate (“H2SO4”) alkylation units to produce high octane gasoline. The present invention does not produce gasoline nor does it produce olefinic LPG. Thus, such alkylation units are not necessary.

(21) Existing refineries contain debutanizers, depropanizers, and other LPG equipment to separate the various LPG components into finished products. By contrast, the present invention does not produce LPG as it uses the relatively small amount of LPG contained in the crude oil as an internal fuel source. As discussed below, certain embodiments might produce small quantities of LPG. In those instances, the small quantities do not necessitate debutanizers, depropanizers, and other LPG equipment to separate the various LPG components into finished products. The small quantities of produced LPG are used as an internal fuel source.

(22) Land cost and acquisition—along with related expenses—are extraordinary in existing refineries, which contain extensive tank farms covering up to several hundred acres. The large space is required due to the number of finished products, unfinished products, and feedstock storage. By contrast, the present invention requires only fifteen (15) acres for the process equipment and tanks utilized.

(23) Existing refineries require extensive staffs of operators, maintenance personnel, technical, supervisory, and other support staff: frequently several hundred in number. By contrast, the present invention requires two operators per shift and only a few maintenance personnel.

(24) Existing refineries require up to three years to add or expand process units due to complexity of environmental permitting, the need to fit into existing plot space, and the arduous task of building in a hazardous space. By contrast, the present invention is expected to require only twelve months to design, build, and startup due to the simplicity of environmental permitting and greenfield construction.

(25) Existing refineries cost as much as several billion dollars. By contrast, the present invention costs on the magnitude of fifty million dollars to construct and implement.

(26) The present invention improves several logistics concepts. The present invention is ideally located at, or near, production sites. Hydraulic fracturing requires significant quantities of diesel to fuel equipment required during drilling and completion. Remote locations often see much higher prices due to transportation costs.

(27) If the invention is implemented at a transportation hub, a larger facility could export products via rail, truck, or pipeline. This option is well suited for stringent specifications required for product exports to Mexico.

(28) When the entire facility is designed in modules, it can be assembled under controlled conditions in a fabrication shop. Onsite assembly consists of setting modules on foundation and connecting piping, conduit, etc. Minimal utilities required to support system. Operator staffing is minimal due to advanced process controls.

(29) Catalyst that might be used include: standard cobalt molybdenum or standard nickel molybdenum (hydrotreating catalyst) and catalysts with similar properties.

(30) One of ordinary skill in the art will appreciate a variety of embodiments that capture the spirit of the present invention. For instance, other unit operations may be included and arranged. FIG. 3 shows a flow diagram schematic of another upgrading system generally designated by the numeral 300. This embodiment consists of a crude splitter; a gas treater; a diesel hydrotreater; a naphtha hydrotreater; a naphtha splitter; an isomerization unit; a naphtha reformer; a gasoline separator/splitter; boilers; and furnaces.

(31) Desalted crude oil is heated to produce a vapor/liquid mixture. This ultralight fluid is supplied via line 320 to an atmospheric crude distillation column (i.e., crude splitter) 322. The crude splitter 322 outputs several streams, including naphtha via line 324, diesel via line 326, offgas via line 328, and bottoms via line 330.

(32) The naphtha (i.e., light hydrocarbon) in line 324 is directed to a naphtha hydrotreater 332 and it is joined with additional naphtha carried in line 334 before entering the naphtha hydrotreater 332. The naphtha hydrotreater contacts the naphtha with hydrogen and a catalyst, which as discussed below results in sulfur-free naphtha and raw gas as outputs. The naphtha hydrotreater 332 experiences zero percent (0%) volume loss.

(33) The diesel in line 326 is directed to a diesel hydrotreater 336—which in some embodiments might experience one percent (1%) volume loss—the diesel hydrotreater 336 receives a feed of hydrogen gas from a hydrogen supply 338, which may be provided from a devoted unit/hydrogen supply or as an output from a downstream unit such as a gasoline separator/splitter. In the diesel hydrotreater 336, the diesel from line 326 hydrogen and catalyst to produce several outputs. The outputs are directed via several streams, including the naphtha in line 334, ULSD via line 340, offgas via line 342, and a fourth line 344 containing accidentally reacted material. The fourth line passes fluid back and forth between the naphtha hydrotreater 332 and the diesel hydrotreater 336.

(34) The offgas in line 328 is directed to a gas treater 346 and it is joined with additional offgas in line 342 and offgas in line 348. The offgas in line 348 is an output from the naphtha hydrotreater 332. The naphtha hydrotreater 332 outputs several streams, including the offgas in line 348, and naphtha in line 352.

(35) The gas treater 346, which takes raw gas as an input, contacts the gas with a caustic solution to remove hydrogen sulfide, and provides low sulfur off gas as output via line 354. The low sulfur off gas as in line 354 splits and directed to furnaces 356 and boilers 358. Furnaces 356, which take low sulfur off gas as input, provide heat for various process streams for distillation and catalytic reaction. And boilers 358, which take low sulfur off gas and water as inputs, provide steam 360 as an output.

(36) The bottoms in line 330 are directed to bottoms storage 362 and the bottoms in line 330 are joined with some naphtha in line 324 before entering the bottoms storage 362. Before entering the bottoms storage 362, the bottoms are cooled and after storage will eventually be sold for marine fuel oil sales—or similar applications.

(37) The naphtha in line 352 is fed to a naphtha splitter 364. The naphtha splitter unit 364 consists of a series of distillation columns and enables the successful separation of light naphtha and heavy naphtha. The naphtha splitter 364 outputs liquefied petroleum gas (“LPG”) in line 366 (not shown), sulfur-free light naphtha in line 368, and sulfur-free heavy naphtha in line 370. The sulfur-free light naphtha in line 368, and the sulfur-free heavy naphtha in line 370 are output at a ratio of 1863:2372 by volume, in this particular embodiment.

(38) The sulfur-free light naphtha in line 368 is fed to an isomerization unit 372—which in some embodiments might experience one percent (1%) volume loss. During isomerization, the sulfur-free light naphtha contacts hydrogen fed from line 376 and isomerization catalyst 378 (not shown). The isomerization unit 372 produces isomerate and LPG, which is output in line 380.

(39) The sulfur-free heavy naphtha in line 370 is fed to a naphtha reformer 374—which in some embodiments might experience twelve percent (12%) volume loss. During the reforming process, the sulfur-free heavy naphtha from line 370 contacts hydrogen fed from line 382 and reformer catalyst 384 (not shown). The reformer 374 produces high-octane liquid reformate and LPG, which is output in line 386 and additional hydrogen gas.

(40) The isomerate and LPG in line 380, along with the reformate and LPG in line 386, are both fed to a gasoline separator/splitter 388. The gasoline separator/splitter outputs LPG via line 390, gasoline via line 392, and hydrogen gas via line 394. The hydrogen from line 394 is reused in the process at several unit operations, including the isomerization unit 372, the reformer 374, and the fourth line 344 containing accidentally reacted material.

(41) The bottoms in line 330 are directed to a bottoms storage 362. Before the entering bottoms storage, the bottoms are cooled and after storage will eventually be sold for marine fuel oil sales—or similar applications. Other product streams from this embodiment are directed to product storage. The LPG in line 390 is fed to LPG storage 398. The gasoline in line 392 is fed to gasoline storage 400, where it blends with ethanol from an ethanol supply 402 via an ethanol line 404. The ULSD in line 340 is fed to ULSD storage 406.

(42) The supply of ultralight fluid can be adjusted in alternative embodiments. However, it is envisioned that a supply of 10,000 barrels per day (“BPD”) input of ultralight fluid—along with 500 BPD of ethanol supplied from ethanol supply 402—will result in final products in the following proportions: 110 BPD of LPG; 4,432 BPD of gasoline; 4,701 BPD of ULSD; and 699 BPD of bottoms.

(43) In a further embodiment, bottoms carried away from the crude splitter could be upgraded by way of a hydrocracker. In such an embodiment, the hydrocracker takes the bottoms (i.e., low sulfur marine fuel oil) as an input, contacts the bottoms with catalyst and hydrogen, and provides raw naphtha, liquified petroleum gas, ultra-low sulfur diesel, and ultra-low sulfur marine fuel oil as outputs.

(44) The present invention results in a simpler refinery because of the light condensate feed, and three functions are necessary: separate crude into three streams that boil in gasoline, diesel, and fuel oil ranges; the distillate hydrotreater removes sulfur to meet ULSD specifications; gasoline section removes sulfur and changes octane from low values to high values that meet 87 regular gasoline specifications; and fuel oil meets lower sulfur specifications without further treatment. And by using only LSR and HSR, the user can upgrade LSR to 85-92 octane; not upgrade HSR; avoid twenty percent (20%) shrinkage for HSR; and no shrinkage across the LSR upgrade.

(45) In certain embodiments, the system and process of the invention use advanced technology for optimized results, including: compact heat exchanger technology; high integrity protection methodology; MaxFlux technology, patented by Duke Biofuels, LLC and distributed control technology, patented by Emerson.

(46) In some embodiments the construction and implementation uses modular construction techniques. For instance, pumps, exchangers, control valves, and other equipment may be located on modules, while certain reactors, columns, and tanks can be located on field-constructed foundations.

(47) In certain embodiments where an ULSD hydrotreater is used, three streams are produced: a low sulfur diesel product, which is sent to storage for ULSD sales; a light hydrocarbon stream, which is routed to the splitter for separation into naphtha and vapor/gas; and a hydrogen rich vapor/gas stream which is treated to H2S and used as fuel for the heaters and boilers.

(48) The present invention is described above in terms of a preferred illustrative embodiment in which a specifically described refining plant and method are described. Those skilled in the art will recognize that alternative constructions of such an apparatus, system, and method can be used in carrying out the present invention. Other aspects, features, and advantages of the present invention may be obtained from a study of this disclosure and the drawings, along with the appended claims.