WO2016028192A1

WO2016028192A1 - Raw hydrocarbon refining plant for northern regions

Info

Publication number: WO2016028192A1
Application number: PCT/RU2015/000523
Authority: WO
Inventors: Igor Anatol'evich MNUSHKIN
Original assignee: Mnushkin Igor Anatol Evich
Priority date: 2014-08-19
Filing date: 2015-08-18
Publication date: 2016-02-25
Also published as: RU2556691C1

Abstract

The invention comes under industrial processing of oil and gas condensates with account of the specific economic aspects in northern regions and can be used in the oil refining industry. A raw hydrocarbon refining plant in northern regions comprises feed and product tank farms, a raw hydrocarbon stabilization unit, a stable raw hydrocarbon atmospheric distillation unit, a unit for gas fractionation of hydrocarbon gas delivered from the atmospheric distillation unit and the stabilization unit, a unit for isomerization, hydro-treatment and reforming of the gasoline fraction delivered from the atmospheric distillation unit, which produces high-octane gasolines, a unit of hydro-treatment of the diesel fuel fraction delivered from the atmospheric distillation unit, and its dewaxing, which produces winter or arctic diesel fuel, a unit of sanitary sour gas removal using water as a sour gas absorbent with subsequent disposal of runoffs into absorbing wells for injection in the reservoir, a compounding unit for various raw hydrocarbon streams, a compounding unit for commercial products, such as atmospheric distillation fractionation residue, ballast fractions of rerun units and a portion of the stabilized feedstock, which produces export commercial oil, and a pipeline system which provides an interconnection between process units and connects them with the tank farms.

Description

Raw hydrocarbon refining plant for northern regions

TECHNICAL FIELD

The invention comes under industrial processing of oil and gas condensates with account of the specific economic aspects in northern regions and can be used in the oil refining industry.

PREVIOUS TECHNICAL KNOWLEDGE

The structure of oil refining plants is known for a long time and generally comprises the following units: electric desalting plants for preliminary oil treatment (ELOU), primary crude distillation plants (single-flash pipe stills (AT) and atmospheric-vacuum pipe stills (AVT)), gas fractionation units, oil product reforming units (platforming), thermal cracking units, catalytic cracking units, hydrocracker units, visbreaking units, hydro-treatment units, oil product rerun distillation units, isomerization units, alkylation units, dewaxing units, deasphaltizing units, bitumen units, heavy residue coking units, sour gas adsorption cleaning units, units of adsorption cleaning and drying of process streams, units of thermal and catalytic cleaning of off-gases, waste water treatment units, etc.; specific layout of an oil refining plant usually depends on the quality of original oil and product range. The optimum level of technological structure of an oil refining plant requires a set of production processes determined by the current requirements of the oil product market in combination with achievements in oil refining technology and methods.

An oil refinery is known, comprising a tank farm for reception and storage of crude oil, a process system of units for oil refining and fractionation, production of commercial oil products with possible, at least partial, compounding, auxiliary plants and units, at least one combustible waste disposal system and a tank farm for storage of the separated fractions and commercial oil products (patent of invention RU 2347800 CI, IPC C10G9/00, F16L55/00, applied for on 15.08.2007, published on 27.02.2009). The main drawback of this invention is the absence of a specific set of process units and, consequently, uncertainty of the range of commercial oil products.

An oil refining plant is also known with a separation unit for oil processing and refining, including heavy crude oil, residues of oil refining and petrochemical productions and other liquid organic media, comprising desalination and dehydration processes, as well as fractionation and commercial product production units; at that, the production circuit upstream or downstream of the fractionation unit (before supply to the single-flash or atmospheric-vacuum pipe still), includes a separation unit wherein the feedstock is separated in two portions: the heavy portion of separation - high-molecular high-boiling fractions chiefly containing products with the boiling point of 340-380 °C and higher, which contain the majority of harmful components and admixtures of the feedstock, which are later used for production of heavy commercial products such as bitumen, petroleum pitch, coke, fuel oil, etc., and the light portion of feedstock separation, enriched with the desired fuel fractions and stripped of the harmful admixtures, which is sent for subsequent processing for production of light oil products (gasoline, kerosene, diesel fuel), while the processing depth in the separation unit is increased by the feedstock cracking process (useful model patent RU 69064 Ul, IPC C10G7/00, C10G9/36, applied for on 28.04.2007, published on 10.12.2007). The main disadvantage of this invention is the separation unit where the feedstock is separated into two portions: the heavy portion of separation with the boiling point of 340-380 °C and higher and the light part of feedstock separation, enriched with the desired fuel fractions, because:

• if the separation unit provides only a single flash of the original oil, the quality of separation into two feedstock kinds will be very low with the bulk of the light portion of feedstock (mainly diesel and kerosene components) passing into the heavy portion and a significant amount of heavy, mainly oily, components passing into the light portion, which deteriorates the operation of subsequent process units;

• if the separation unit provides feedstock fractionation on contact devices, the quality of separation into two feedstock kinds will be more efficient, but separation of the light portion in AT or AVT units becomes inefficient and requires complete renovation of these units changing their process conditions;

• operation of the gas fractionation unit with the unit of amine treatment of gases from the separation unit requires preheating of the feedstock to a temperature of about 340-380 °C and at subsequent cooldown of the light and heavy portions of feedstock it will increase production energy consumption by about 30-40 % as compared to the energy consumption by AT or AVT units.

The layout of Khabarovsk Oil Refinery is also known, comprising ELOU-AT and ELOU-AVT units, a gas fractionation unit with a unit of sour gas amine removal with subsequent processing of hydrogen sulphide in the sulphur production unit as per the Claus method, reforming, isomerization and hydro-treatment units, hydrocracker and visbreaking units, a hydrogen production unit, a bitumen unit and a commercial product farm (Schematic diagram of material flows at OJSC Khabarovsk Oil Refinery. The information is given in the electronic form at the website http://khab-npz.ru/shemay The shortcoming of this layout is the strictly assigned plant operation mode at refining of a certain oil kind, transfer to a different oil kind involves significant changes in the production technology and output of nonstandard products in the transition period. Moreover, transportation of commercial fuel products (gasoline, diesel fuel, oil fuel, marine fuel) from Khabarovsk to northern regions with underdeveloped infrastructure and periodicity of fuel delivery by rivers in the short navigation period and via winter roads considerably increases the cost of fuel, thus indirectly causing rising costs of all components of the industrial and the housing public sector in northern regions. For instance, transportation of automotive fuel from Khabarovsk to Yakutsk to the distance of 2500 km on KAMAZ 43118 truck with lifting capacity of 7 tons will require about 2 tons of the transported fuel for the fuel transportation and the return trip.

A layout of an oil refinery for gas condensate processing with sulphur content not more than 400 ppm, producing commercial products in accordance with EURO-5 standards (class 5 according to Technical Regulation), is known, which comprises the following units: a feedstock fractionation unit, an IBP-360 °C fraction hydro-treatment unit, a unit of hydro-treatment product rectification into fractions for subsequent processing, a light gasoline hydroisomerization unit, a hydroisomerizate rectification unit and commercial product compounding unit; besides, a layout of an oil refinery for advanced oil refining is known, producing commercial products in compliance with EURO-5 standard (class 5 according to Technical Regulation), which comprises the following units: ELOU and an atmospheric-vacuum distillation unit, a gasoline fraction hydro-treatment unit, a diesel fraction hydro-treatment and hydrodewaxing unit, a diesel fuel compounding unit, a petrol compounding unit, an isomerization and hydroisomerization unit, a unit of amine treatment of hydrogen-bearing gas using monoethanolamine as the absorbent, a unit of elementary sulphur separation as per the Claus process, a unit of bitumen production by oil tar oxidation, a hydrogen-bearing gas production unit, a vacuum gasoil hydrocracker unit (Gas condensate (oil) processing unit). The information is given in the electronic form at the website http://additive.spb.ru/upgk.html). The drawback of these oil refinery layouts is the plants' narrow feedstock orientation: given significantly differing sets of process units, only a certain kind of raw hydrocarbons is processed - either oil or gas condensate.

A project of gas condensate processing in Kamchatka Region is known, with production volume of about 240.0 thous. tons till 2023, for production of gasoline, kerosene and diesel fractions using a packaged unit of UPNG-40 type with the capacity of one module up to 40.0 thous. t year. Gas condensate processing in a packaged unit will allow producing of about 92.7 thous. tons of straight-run gasoline fractions, about 144.8 thous. tons of diesel fuel till 2023 after plant construction in 2015. The estimated project cost is: RUB 180 mln. (Gas condensate processing in Kamchatka Region. The information is given in the electronic form at the website http://www.australia.mid.ru/invest kamchatka 02.pdf). Shortcomings of this project are:

• high costs of the key assets of the low-duty unit;

· low quality of produced straight-run gasoline fractions and diesel fuel due to the limited number of units in the module;

• absence of consumers of gas fractions separated from gas condensate will necessitate their flaring involving environment pollution;

• the prospects of the use of heavy residues of gas condensate after fuel fraction extraction are unknown.

DISCLOSURE OF INVENTION

Raw hydrocarbon refining for northern regions differs significantly from the similar processes in the central regions of the Russian Federation or in the Far East. First, multiple deposits of raw hydrocarbons - oil of various origins, various gas condensate fields are concentrated in northern regions, characterized by underdeveloped infrastructure, which sets the problem of refining of raw hydrocarbons, composition of which is significantly unsteady, during plant operation. Second, the region's specificity requires production of a specific range of output products on site, in particular, winter and arctic diesel fuel. Third, the marketing requirements make the owners of the raw hydrocarbon processing plan find new, cheaper, sources of feedstock with the composition often different from the previously used one. Fourth, construction and operation of mini oil refineries at each field is less cost-effective than construction of a large plant processing feedstock from the whole region. Fifth, plant transition from one feedstock kind to another, e. g. from oil to gas condensate, requires preliminary study of the technology and formation of a new field of units' operation process variables, which frequently deteriorates the quality of the end commercial products.

The task of the invention was to develop a highly efficient raw hydrocarbon refining plant for northern regions, operating with feedstock of different origins, particularly with oil, gas condensates and their mixtures with easily implemented transition from one feedstock kind to another, output of the commercial product range necessary in northern regions, and a higher level of ecological safety. Given sufficiently high capacity of the plant refining a broad range of raw hydrocarbons, it is possible to additionally enhance the efficiency of the plant's key assets and to reduce the need for scarce highly-qualified personnel in low population"areas. The set task has been solved using the raw hydrocarbon refining plant for northern regions comprising a feed tank farm, an initial raw hydrocarbon stabilization unit with separation of stabilization gas, a unit of atmospheric distillation of stable raw hydrocarbons with separation of hydrocarbon gas, gasoline fraction, diesel fuel fraction and oil fuel from it, a unit of fractionation of hydrocarbon gas separated on the atmospheric distillation unit and the initial raw hydrocarbon stabilization unit, with separation into deethanization gas, liquefied technical mixture of propane and butane, propane and butane, a unit of isomerization of the gasoline fraction separated in the atmospheric distillation unit, a gasoline hydro-treatment unit, a reforming unit producing high-octane gasolines, a unit of hydro-treatment and dewaxing of the diesel fuel fraction separated on the raw hydrocarbon atmospheric distillation unit, a unit of sanitary sour gas removal, a product tank farm and a system of pipelines linking the process units to each other and to the tank farms, additionally comprises a compounding unit of various raw hydrocarbon streams; the sanitary sour gas removal unit uses water as a sour gas absorbent with subsequent disposal of runoffs into absorbing wells for injection in the reservoir; the atmospheric distillation unit fractionation residue and ballast fractions (i. e. the fractions not used further as commercial products) and a portion of stabilized feedstock are delivered the commercial product compounding unit which produces exported commercial oil; the diesel fuel dewaxing unit ensures production of winter or arctic diesel fuel. Inclusion of the compounding unit in the plant layout at the initial production stage allows formation of optimal raw hydrocarbons for the plant on the whole if the raw hydrocarbons delivered to the feed tank farm have different quality. The use of water as an absorbent in the sanitary sour gas removal unit makes it possible to operate this unit without an energy-intensive stripper, usually used when special expensive chemical agents are used as absorbents, e. g. various amines for absorbent recovery, and additionally requiring a unit (within the plant layout) for disposal of sour components, separated from the absorbent during recovery (first of all, hydrogen sulphide, mercaptan, carbon dioxide), and to reduce the plant's key assets by the overall significant simplification of the plant circuit. Sour water produced in the absorber of the sanitary sour gas removal unit, is pumped via wells into the reservoir, contributing to formation of a water encroachment contour. Heavy residues from the bottom of the hydrocracker unit rectification tower are pumped into stable gas condensate with production of commercial oil after mixing to the necessary ratio, which is then pumped via a pipeline to consumers in the central part of the country. The diesel fuel dewaxing unit ensures an optimal diesel fuel range for northern regions: either winter or arctic diesel fuel depending on the season. It is reasonable to use either unstable low-sulphur gas condensate, or unstable light sweetened crude oil, or stable light sweetened crude oil as raw hydrocarbons in northern regions as it extends the range of processed feedstock.

It is also reasonable to use a mixture of unstable condensate and stable and/or unstable oil as raw hydrocarbons, which allows reducing the amplitude of variations of the composition of the processed original raw hydrocarbons and significant stabilization of overall plant operation.

It is also reasonable to ensure that a portion of stabilized raw hydrocarbons be exported as a commercial product (commercial oil), while the remaining portion should be refined in the atmospheric distillation unit.

It is reasonable to perform stabilization and atmospheric distillation of unstable raw hydrocarbons during their refining in a single unit.

The plant layout should include an oil fuel hydrocracker unit for processing of the atmospheric distillation residue and an associated hydrogen production unit producing diesel fuel, gasoline and hydrocarbon gases; at that, the gasoline fractions and unconverted residue of the hydrocracker unit should be pumped into the stabilized feedstock, exported as commercial oil, which allows maintaining the range of output commercial products according to the region's needs.

The gasoline fractions of the atmospheric distillation unit or the ballast fractions of atmospheric distillation and isomerization should be partially or fully injected into an additional commercial product corresponding to pyrolysis stock (naphtha).

The gasoline fractions of the hydrocracker and atmospheric distillation units should be partially or fully compounded into pyrolysis feedstock.

The gaseous hydrocarbon products of the hydrocracker should be delivered to the hydrocarbon gas fractionation unit in a mixture with the atmospheric distillation unit gases.

At the stage of design of the raw hydrocarbon refining plant the individual process units, depending on the range of varying characteristics of raw hydrocarbons and the incoming primary derived products, should be calculated according to the parameters corresponding to the lower or upper boundary of the range of varying characteristics, ensuring the maximum unit efficiency. LIST OF DRAWINGS

Figure 1 shows a schematic of the raw hydrocarbon refining plant for northern regions, comprising tank farms, units and interconnecting pipelines.

100 - feed tank farm,

110 - raw hydrocarbon compounding unit,

120 - stabilization unit and atmospheric distillation unit,

130, 140 - gasoline hydro-treatment unit,

150 - isomerization unit,

160 - sanitary sour gas removal unit,

170 - gas fractionation unit,

180 - diesel fuel dewaxing unit,

190 - diesel fuel hydro-treatment unit,

200 - hydrocracker unit,

210 - hydrogen production unit,

220 - commercial product compounding unit,

230 - product tank farm,

240 - fractionation unit,

250 - reforming unit,

260 - primary distillation unit,

1-57 - pipelines.

BRIEF DESCRIPTION OF DRAWINGS

Raw hydrocarbon streams from various fields, such as oil and gas condensate, are delivered to the raw hydrocarbon refining plant for northern regions via pipelines 1, 2, 3, 4 to the feed tank farm 100, after which the raw hydrocarbon streams are delivered via pipelines 5 and 42 to raw hydrocarbon compounding unit 110, where streams of the same type are mixed, and the common oil stream and the common gas condensate stream are withdrawn via pipelines 6 and 43, respectively, to the stabilization unit and atmospheric distillation unit 120, which is included in the primary distillation unit 260.

The stabilization gas and hydrocarbon gas of atmospheric distillation are delivered via pipelines 8 and 9, respectively, to gas fractionation unit 170 producing the following commercial products: a technical mixture of propane and butane (LHCG), propane, butane fractions, withdrawn via pipelines 25, 26 and 27, respectively. The following intermediate products are also withdrawn from gas fractionation unit 170: fuel gas, separated in two parts: one part, withdrawn via pipeline 23, is delivered to hydrogen production unit 210, the other part, withdrawn via pipeline 21, is delivered to the pyrolysis unit (not shown in Fig. 1), and the C₅ fraction and higher via pipeline 49, delivered for mixing with naphtha separated in hydrocracker unit 200 and withdrawn via pipeline 34, and then in a common stream via pipeline 54 it is mixed with naphtha, which is the pyrolysis unit feedstock (not shown in Fig. 1). Sour gas is also withdrawn from gas fractionation unit 170 via pipeline 22 to sanitary sour gas removal unit 160, where the sour gas absorbent is water delivered via pipeline 24, and the runoffs are withdrawn via pipeline 28 and are injected into absorbing wells (not shown in Fig. 1).

The IBP- 185 °C fraction, separated on the stabilization unit and atmospheric distillation unit 120, comes via pipeline 56 to fractionation unit 240, where it is separated into the 100-185 °C fraction, withdrawn via pipeline 7 to gasoline hydro-treatment unit 130, after which the treated 100-185 °C fraction comes via pipeline 14 to reforming unit 250 with production of high-octane component of EURO-5 gasoline, withdrawn via pipeline 15, into the IBP-85 °C fraction, partially delivered to gasoline hydro-treatment unit 140 via pipeline 17, after which the treated IBP-85 °C fraction comes via pipeline 18 to isomerization unit 150 with production of high- octane gasoline component, withdrawn via pipeline 19, and the ballast fraction (heptane-hexane fraction), withdrawn via pipeline 55 for mixing with naphtha, delivered via pipeline 20 for pyrolysis, into the 85-100 °C fraction, partially sent via pipeline 45 for mixing with naphtha for pyrolysis, and the remaining portion of the 85-100 °C fraction is delivered to commercial product compounding unit 220 via pipeline 16. The layout also provides for supply of the IBP-85 °C fraction via pipeline 29 for mixing with naphtha, delivered as pyrolysis feedstock.

The diesel fuel, withdrawn from the stabilization unit and atmospheric distillation unit 120 via pipeline 13, and a portion of hydrogen, withdrawn via pipeline 50 from hydrogen production unit 210, is delivered to diesel fuel hydro-treatment unit 190, after which the treated diesel fuel is delivered via pipeline 30 to diesel fuel dewaxing unit 180, from which winter diesel fuel and arctic diesel fuel are withdrawn via pipelines 31 and 32, respectively.

The oil fuel, withdrawn from stabilization and atmospheric distillation unit 120, is separated in two streams, one of which is delivered via pipeline 11 to commercial product compounding unit 220, and the other oil fuel stream, being the residue of heavy gas condensate processing, is sent via pipeline 12 to hydrocracker unit 200, into which hydrogen is also delivered via pipeline 40 from hydrogen production unit 210. The hydrocarbon gases, separated in hydrocracking unit 200, are delivered via pipeline 33 for mixing with the atmospheric distillation hydrocarbon gases, after which the single common stream is delivered via pipeline 44 to gas fractionation unit 170. The hydrocracker products - naphtha, diesel fuel, and unconverted residue are withdrawn via pipelines 34, 35, 36, respectively. The circuit provides for delivery of the unconverted residue and naphtha, separated in hydrocracker unit 200, to commercial product compounding unit 220 via pipelines 36 and 37, respectively, as well as the stabilized feedstock and a portion of the IBP- 185 °C fraction via pipelines 10 and 52, withdrawn from stabilization and atmospheric distillation unit 120, and the ballast fraction of isomerization delivered via pipeline 53. The product of commercial product compounding unit 220 is commercial oil, withdrawn to product tank farm 230 via pipeline 41.

The natural gas together with the fuel gas, withdrawn from gas fractionation unit 170, comes to hydrogen production unit 210 via pipeline 38. The extracted hydrogen is separated into several parts and is delivered via pipeline 40 to hydrocracker unit 200, via pipeline 50 to diesel fuel hydro-treatment unit 190, via pipelines 39 and 51 to gasoline hydro-treatment units 140 and 130. Hydrogen extracted on reforming unit 250 is also delivered via pipeline 46 either to gasoline hydro-treatment units 130 and 140, or to diesel fuel hydro-treatment unit 190.

The emitted hydrocarbon gas after gasoline hydro-treatment units 130 and 140 and diesel fuel hydro-treatment unit 190 is delivered to gas fractionation unit 170, via pipelines 47, 57 and 48, respectively.

Example 1. Raw hydrocarbon refining plant for northern regions with feedstock capacity of 2 mln. t/year is located in a region where gas condensate of three types (Table 1) and oil of two types (Table 2) is produced, at that: gas condensate No. 1 is characterized by presence of gasoline fractions only, gas condensate No. 2 is characterized by presence of gasoline and diesel fuel fractions, gas condensate No. 3 is characterized by presence of diesel fractions with an insignificant admixture of heavy (oil fuel) fractions, oil No. 1 contains about 50 % of oil fuel fractions and significant amount of gaseous admixtures, oil No. 2 contains more than 50 % of oil fuel fractions and insignificant amount of gaseous admixtures.

Since the raw hydrocarbon refining plant, situated in this region, can operate in various periods depending on the marketing situation both according to raw hydrocarbon cost and according to the range of output products and must ensure the optimum conditions of feedstock processing in combination with a flexible scheme of its processing already at the plant design stage, for its individual process units depending on the range of varying raw hydrocarbon characteristics, and the incoming initial derived products were designed according to the parameters corresponding to the lower or upper boundary of the range of the varying characteristics of original products (feedstock) for processing, ensuring the maximum unit efficiency. Potential capacity of some units and justification of their efficiency with the use of various region-specific raw hydrocarbon sources as plant feedstock is given in Table 3. Example 2. The raw hydrocarbon refining plant for northern regions with feedstock capacity of 2 mln. t/year receives oil No. 2 with low content of gas components; it allows increasing the plant feedstock capacity to 3 mln. t/year to ensure efficient operation of the oil stabilization unit, after which 1 mln. t/year of stabilized naphtha is sent to the commercial product compounding unit, in which the gasoline fractions and unconverted residue of the hydrocracker unit are added to the stabilized oil with subsequent export of the compound as commercial oil.

Example 3. The raw hydrocarbon refining plant for northern regions with feedstock capacity of 2 mln. t/year receives oils and gas condensates, which after compounding form the initial hydrocarbon processing feedstock not complying with the data of Tables 2 and 3 and having an intermediate fractional composition. In this case, the specific process units, designed according to the parameters corresponding to the lower or upper boundary of the range of varying characteristics of initial products (feedstock) for processing can operate at the following process operation conditions:

· increase in unit efficiency in excess of the design capacity while maintaining the quality of end products;

• maintaining the unit's design capacity with the increase of the quality of end products;

• unit switchover to the circulation mode with mixing of end products and their return to the inlet as feedstock with energy consumption minimization.

Thus, the claimed raw hydrocarbon refining plant for northern regions can operate in various activity periods depending on the marketing situation both according to the cost of raw hydrocarbons and according to the range of output products, ensuring the optimum conditions of feedstock processing in combination with a flexible processing scheme.

Type of field

Parameter

JN°1 J°2 J°3

Fractional composition, °C:

IBP (initial boiling point) 41 43 210

10% 62 83 233

20% 72 91 237

30% 81 98 243

40% 93 112 248

50% 103 133 254

60% 114 153 265

70% 128 183 272

80% 147 223 282

90% 180 287 296

EBP (end boiling point) 250 300 360

Residues and wastes, % wt. 20,0 6,5 1,0

Table 1

Type of field

Parameter

tfo 1 JVo 2

Stripping, % wt. Temperature °C

IBP (initial boiling point) -15,0 77,6

5 79,2 148,5

10 120,3 189,3

30 258,8 295,6

50 376,3 391 ,5

70 485,9 507,9

90 682,2 653,7

95 768,5 731 ,4

EBP (end boiling point) 1062,2 865,9

Table 2

Table 3

Claims

Formula of the invention

1 The raw hydrocarbon refining plant for northern regions comprising a feed tank farm, a hydrocarbon feedstock stabilization unit with release of stabilization gas, a unit of atmospheric distillation of stable raw hydrocarbons with separation of hydrocarbon gas, gasoline fraction, diesel fuel fraction and oil fuel from it, a unit for gas fractionation of hydrocarbon gas delivered from the atmospheric distillation unit and the hydrocarbon feedstock stabilization unit, with separation into deethanization gas, liquefied technical mixture of propane and butane, propane and butane, a unit for isomerization of the gasoline fraction delivered from the atmospheric distillation unit, a gasoline hydro-treatment unit, a reforming unit producing high-octane gasolines, a unit for hydro-treatment and dewaxing of the diesel fuel fraction delivered from the raw hydrocarbon atmospheric distillation unit, a unit of sanitary sour gas removal, a product tank farm and a pipeline system linking the process units to each other and to the tank farms. The plant is noted for comprising a compounding unit for various raw hydrocarbon streams, the sanitary sour gas removal unit uses water as a sour gas absorbent with subsequent disposal of runoffs into absorbing wells for injection in the reservoir; the atmospheric distillation unit fractionation residue, ballast fractions of the rerun units and a portion of stabilized feedstock are sent to the commercial product compounding unit which produces export commercial oil, and the diesel fuel dewaxing unit provides for production of winter or arctic diesel fuel.

2 The raw hydrocarbon refining plant for northern regions, as described in cl. 1, is noted for using unstable sweetened gas condensate as raw hydrocarbons.

3 The raw hydrocarbon refining plant for northern regions, as described in cl. 1, is noted for using unstable light sweetened crude oil as raw hydrocarbons.

4 The raw hydrocarbon refining plant for northern regions, as described in cl. 1, is noted for using stable light sweetened crude oil as raw hydrocarbons.

5 The raw hydrocarbon refining plant for northern regions, as described in cl. 1, is noted for using a mixture of unstable condensate and stable and/or unstable oil as raw hydrocarbons.

6 The raw hydrocarbon refining plant for northern regions, as described in cl. 1, is noted for exporting a portion of stabilized raw hydrocarbons as a commercial product (commercial oil), while refining the remaining portion at the atmospheric distillation unit.

7 The raw hydrocarbon refining plant for northern regions, as described in cl. 1 , is noted for performing stabilization and atmospheric distillation of unstable raw hydrocarbons at a single unit in the course of its processing.

8 The raw hydrocarbon refining plant for northern regions, as described in cl. 1, is noted for its layout which includes an oil fuel hydrocracker unit for processing of the atmospheric distillation residue and the associated hydrogen production unit producing diesel fuel, gasoline and hydrocarbon gases.

9 The raw hydrocarbon refining plant for northern regions, as described in cl. 8, is noted for injecting gasoline fractions and unconverted residue of the hydrocracker unit into the stabilized feedstock exported as commercial oil.

10 The raw hydrocarbon refining plant for northern regions, as described in cl. 1 , is noted for partial or full-scale injection of gasoline fractions of the atmospheric distillation unit or ballast fractions of the atmospheric distillation and isomerization into additional commercial product corresponding to pyrolysis feedstock (naphtha).

11 The raw hydrocarbon material refining plant for northern regions, as described in cl. 1 and 8 is noted for partial or full compounding of gasoline fractions of the hydrocracker and atmospheric distillation units into the pyrolysis feedstock.

12 The raw hydrocarbon material refining plant for northern regions, as described in cl. 1 and 8, is noted for delivery of gaseous hydrocarbon products of hydrocracker to the hydrocarbon gas fractionation unit, mixed with the atmospheric distillation unit gas.

13 The raw hydrocarbon material refining plant for northern regions, as described in cl. 1, is noted for design of individual process units, depending on the range of varying parameters of raw hydrocarbons and the incoming primary processed products, in accordance with the parameters of varying characteristics of the lower or upper range boundaries, which ensures maximum unit efficiency.