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WO2022174880A1 - Desalting technique via suspending salt/solid deposits in flowing condensate - Google Patents

Desalting technique via suspending salt/solid deposits in flowing condensate Download PDF

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Publication number
WO2022174880A1
WO2022174880A1 PCT/EG2021/000005 EG2021000005W WO2022174880A1 WO 2022174880 A1 WO2022174880 A1 WO 2022174880A1 EG 2021000005 W EG2021000005 W EG 2021000005W WO 2022174880 A1 WO2022174880 A1 WO 2022174880A1
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WO
WIPO (PCT)
Prior art keywords
condensate
water
salts
stabilizer
salt
Prior art date
Application number
PCT/EG2021/000005
Other languages
French (fr)
Inventor
Amr Ahmed Amin EL KHASHAB
Adham Mohamed Mahmoud EL MAGHRABY
Mohamed Ahmed REFAAT
Original Assignee
Engineering For The Petroleum And Process Industries (Enppi)
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Engineering For The Petroleum And Process Industries (Enppi) filed Critical Engineering For The Petroleum And Process Industries (Enppi)
Priority to PCT/EG2021/000005 priority Critical patent/WO2022174880A1/en
Publication of WO2022174880A1 publication Critical patent/WO2022174880A1/en

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Classifications

    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D17/00—Separation of liquids, not provided for elsewhere, e.g. by thermal diffusion
    • B01D17/02—Separation of non-miscible liquids
    • B01D17/04—Breaking emulsions
    • B01D17/047—Breaking emulsions with separation aids
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G31/00—Refining of hydrocarbon oils, in the absence of hydrogen, by methods not otherwise provided for
    • C10G31/08—Refining of hydrocarbon oils, in the absence of hydrogen, by methods not otherwise provided for by treating with water
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G53/00—Treatment of hydrocarbon oils, in the absence of hydrogen, by two or more refining processes
    • C10G53/02—Treatment of hydrocarbon oils, in the absence of hydrogen, by two or more refining processes plural serial stages only
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02A—TECHNOLOGIES FOR ADAPTATION TO CLIMATE CHANGE
    • Y02A20/00—Water conservation; Efficient water supply; Efficient water use
    • Y02A20/124—Water desalination

Definitions

  • Hydrocarbon condensate associated with natural gas contains impurities such as water, salts and solids. These impurities usually have serious and expensive impacts on the condensate stabilization units.
  • Condensate stabilization units generally suffers from scale formation and salt depositions in the unit main process equipment such as stabilizer feed heater, condensate stabilizer trays, stabilizer re-boiler and rundown coolers.
  • the root cause of such problem is the deposition of dissolved salts in the water entrained with the feed condensate stream when water evaporates as a result of temperature increase in the unit.
  • Electrostatic desalters is based on the enlargement of fine droplets of the water dispersed in the condensate to form larger drops by means of the polarity of water molecules which will coalesce under a high voltage electric field.
  • the larger drops could be separated from the continuous phase (i.e. condensate).
  • the electric field is provided by electrode grids positioned inside the vessel, between which the condensate/water emulsion is distributed through the inlet header and where coalescence takes place.
  • the larger water droplets are separated by gravity force to the bottom of the desalter.
  • Desalters can process bulk concentrations of water in the inlet stream.
  • Coalescence is also based on the enlargement of fine droplets of the water dispersed in the condensate to form larger drops.
  • Coalescence can be made through a media that usually consists of fibers which are made of metal such as in demister pads or made of glass fiber or polymer as in cartridge coalescers. Moreover, an electric field could also be utilized in coalescers same to electrostatic desalters.
  • This invention is based on injecting chemical only where this chemical shall prevent salt/solids depositions and keep these particles suspended in the hydrocarbon phase within the equipment of the units, then the suspended salts will be dissolved by injecting fresh water with low salt content in the condensate stream, after that the water with its content of dissolved water will be separated from the storage tanks to achieve the condensate product specification without the installation of complicated process equipment.
  • Chemical injection packages are very simple and thus this invention results in huge capital costs saving as well as plot area savings compared to conventional design.
  • Condensate stabilization units reduce the vapor pressure of produced condensate liquids to prevent vaporization due to flashing to stock tank storage conditions or during transport.
  • Hydrocarbon liquid undergoes pressure reduction and is sent to condensate second stage separator (3 phase separator) which is considered the primary water separation step of the feed of the condensate stabilization unit.
  • the separated hydrocarbon liquid is directed to the tube side of stabilizer feed/stabilized condensate heat exchanger and is heated against hot condensate leaving the bottom of the stabilizer.
  • Hot condensate from stabilizer feed/stabilized condensate heat exchanger is directed to the stabilizer tower.
  • the partially cooled condensate from the stabilizer feed/stabilized condensate heat exchanger is further cooled by the condensate rundown cooler and in the condensate/NGL exchanger before being sent to condensate storage.
  • the chemical shall be injected downstream the primary water separation prior to any heating (see figure.2) to protect the condensate stabilization unit from salts deposition resulting from water evaporation through preventing salt/solids depositions and keeping these particles suspended in the hydrocarbon phase.
  • This condensate stabilization unit was operated based on a temporary operation via water injection at different points of the unit (see figure.3) to dissolve the salts and prevent further deposits build-up which lead to repeated unit shutdown for salts removal.
  • this temporary solution resulted in severe corrosion problems in the unit.
  • the utilization of the chemical will be considered successful during the test period in case the salt content in the stabilized condensate from the stabilizer bottom is approximately equal to the amount of salt in the outlet condensate from second stage separator which indicates that no salt deposition has occurred in the system.
  • Location 2 Condensate flowrate and salt content downstream the second stage separator. These parameters were monitored to determine the salt content at the inlet of the unit.
  • This parameter was monitored to ensure that no blockage has taken place due to salt deposition.
  • Location 8 Condensate salt content and water content upstream the condensate storage tank. These parameters were monitored to ensure that the chemical is functioning at different operating temperatures and is keeping the salts suspended in the condensate throughout all the path till the storage tanks. Test sequence (see figure.5)
  • the first sequence has ended, and the second sequence was started.
  • the second sequence has ended, and the third sequence started.
  • the third sequence is typical to the second.
  • This invention is intended to be used in condensate stabilization units or crude distillation units, either new units or existing units, to solve the problem of salt deposition.
  • the first step is to test surfactant chemical to ensure it will function efficiently (i.e. prevent salt/solids depositions via keeping these particles suspended in the hydrocarbon phase) under the operating conditions of the unit and to determine the required dosage rate. Then, design and install a chemical injection package consisting of small chemical storage tank and injection pumps. Brief description Of The Drawing :
  • Figured represents a typical flowsheet of a condensate stabilization unit.
  • Figure.2 represents the chemical injection location in the condensate stabilization unit.
  • Figure.3 represents water injection locations in the condensate stabilization train.
  • Figure.4 represents monitoring and measuring locations
  • Figure.5 represents test sequence.
  • Figure.6 represents the preparation steps of the test sequence.
  • Figure.7 represents the first sequence of the test.
  • Figure.8 represents the field test results obtained before chemical injection.
  • Figure.9 represents the field test results obtained after chemical injection.
  • Figure.10 represents the comparison of economic parameters between invention and conventional designs.

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  • Chemical & Material Sciences (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • Engineering & Computer Science (AREA)
  • General Chemical & Material Sciences (AREA)
  • Organic Chemistry (AREA)
  • Physics & Mathematics (AREA)
  • Thermal Sciences (AREA)
  • Vaporization, Distillation, Condensation, Sublimation, And Cold Traps (AREA)

Abstract

Hydrocarbon condensate associated with natural gas contains impurities such as water, salts and solids. These impurities usually have serious and expensive impacts on the condensate stabilization units. Condensate stabilization units generally suffers from scale formation and salt depositions in the unit main process equipment such as stabilizer feed heater, condensate stabilizer trays, stabilizer re-boiler and rundown coolers. The root cause of such problem is the deposition of dissolved salts in the water entrained with the feed condensate stream when water evaporates as a result of temperature increase in the unit. Conventional designs aim to solve the salt deposition problem via secondary water separation techniques such as desalting and coalescer filters that shall be installed after the primary water separator. However, this invention is based on injecting chemical only where this chemical shall prevent salt/solids depositions and keep these particles suspended in the hydrocarbon phase within the equipment of the units, then the suspended salts will be dissolved by injecting fresh water with low salt content in the condensate stream, after that the water with its content of dissolved water will be separated from the storage tanks to achieve the condensate product specification without the installation of complicated/expensive process equipment.

Description

Desalting Technique via Suspending Salt/Solid deposits in
Flowing Condensate
Background Art :
Hydrocarbon condensate associated with natural gas contains impurities such as water, salts and solids. These impurities usually have serious and expensive impacts on the condensate stabilization units.
Condensate stabilization units generally suffers from scale formation and salt depositions in the unit main process equipment such as stabilizer feed heater, condensate stabilizer trays, stabilizer re-boiler and rundown coolers.
The root cause of such problem is the deposition of dissolved salts in the water entrained with the feed condensate stream when water evaporates as a result of temperature increase in the unit.
Conventional designs aim to solve the salt deposition problem via secondary water separation techniques such as desalting and coalescer filters that shall be installed after the primary water separator.
Electrostatic desalters is based on the enlargement of fine droplets of the water dispersed in the condensate to form larger drops by means of the polarity of water molecules which will coalesce under a high voltage electric field. The larger drops could be separated from the continuous phase (i.e. condensate).
The electric field is provided by electrode grids positioned inside the vessel, between which the condensate/water emulsion is distributed through the inlet header and where coalescence takes place. The larger water droplets are separated by gravity force to the bottom of the desalter. Desalters can process bulk concentrations of water in the inlet stream.
Coalescence is also based on the enlargement of fine droplets of the water dispersed in the condensate to form larger drops.
Coalescence can be made through a media that usually consists of fibers which are made of metal such as in demister pads or made of glass fiber or polymer as in cartridge coalescers. Moreover, an electric field could also be utilized in coalescers same to electrostatic desalters.
The problem of previous Art :
Secondary water separation techniques such as desalting and coalescer filters requires installation of equipment which have high capital cost and needs large plot area.
In case of brown fields, the modifications required for installation of desalters or coalescer filters could be very complicated.
Secondary water separation techniques can achieve salt content as low as 1 PTB (pound per thousand barrel) in the outlet condensate stream, thus eliminating a major part of the problem. However, this very low salt content value will still accumulate in the condensate stabilization system and may lead to periodical shutdowns for cleaning purpose.
Disclosure Of The Invention :
New in the invention:
This invention is based on injecting chemical only where this chemical shall prevent salt/solids depositions and keep these particles suspended in the hydrocarbon phase within the equipment of the units, then the suspended salts will be dissolved by injecting fresh water with low salt content in the condensate stream, after that the water with its content of dissolved water will be separated from the storage tanks to achieve the condensate product specification without the installation of complicated process equipment.
Chemical injection packages are very simple and thus this invention results in huge capital costs saving as well as plot area savings compared to conventional design.
In case of brown fields, the modifications required for installation of chemical injection unit is very simple compared to modifications required for the addition of secondary separation units such as desalters or coalescer filters. Detailed Description:
Condensate stabilization units reduce the vapor pressure of produced condensate liquids to prevent vaporization due to flashing to stock tank storage conditions or during transport.
For a typical condensate stabilization unit (see figured); mixed hydrocarbons from producing wells are gathered and directed to the inlet separator (3 phase separator), to separate gas, hydrocarbon liquid and water.
Hydrocarbon liquid undergoes pressure reduction and is sent to condensate second stage separator (3 phase separator) which is considered the primary water separation step of the feed of the condensate stabilization unit.
The separated hydrocarbon liquid is directed to the tube side of stabilizer feed/stabilized condensate heat exchanger and is heated against hot condensate leaving the bottom of the stabilizer. Hot condensate from stabilizer feed/stabilized condensate heat exchanger, is directed to the stabilizer tower.
The partially cooled condensate from the stabilizer feed/stabilized condensate heat exchanger is further cooled by the condensate rundown cooler and in the condensate/NGL exchanger before being sent to condensate storage.
In this invention; The chemical shall be injected downstream the primary water separation prior to any heating (see figure.2) to protect the condensate stabilization unit from salts deposition resulting from water evaporation through preventing salt/solids depositions and keeping these particles suspended in the hydrocarbon phase.
As a result of the transfer of the removed salts to the condensate; injection of fresh water upstream the condensate storage tank is required to dissolve the suspended salts. Enough time for settling shall be considered in the storage tank to separate salty water before shipping the condensate product. Salty water drainage from the storage tank shall be performed periodically.
No special specific chemical is required to be utilized; Any commercial surfactant achieving the previously described target can be used after being tested which is a mandatory step to ensure the efficient performance of the selected chemical under the operating conditions of the unit.
As a case study to prove the efficiency of the invention; The chemical injection concept has been tested in an operating stabilization unit “owned by one of the Egyptian petroleum sector operating companies” which was suffering from salt deposition problems since the start-up of the facilities.
This condensate stabilization unit was operated based on a temporary operation via water injection at different points of the unit (see figure.3) to dissolve the salts and prevent further deposits build-up which lead to repeated unit shutdown for salts removal. However, this temporary solution resulted in severe corrosion problems in the unit.
The field test has been executed using a selected commercial surfactant and the test results was very impressive as it proved that the selected chemical is working efficiently, eliminating the deposition and accumulation of salt scales inside the unit.
The test aim to measure the salt content in the condensate feed and the outlet condensate from the unit before and after chemical injection.
Below is the detailed description of the test procedure performed:
Test Acceptance Criteria
The utilization of the chemical will be considered successful during the test period in case the salt content in the stabilized condensate from the stabilizer bottom is approximately equal to the amount of salt in the outlet condensate from second stage separator which indicates that no salt deposition has occurred in the system.
Test Failure Criteria
In case the pressure drop across the stabilizer feed heater, the flow control valve or the condensate rundown cooler increases drastically, which indicates severe plugging, together with sharp declination in the performance of stabilizer reboiler, accordingly water injection should be started immediately to avoid condensate stabilization train forced shut down. Moreover, the chemical trial test will be considered failed. Monitored process variables (see figure.4)
• Location 1 : Operating pressure, operating temperature and level of the second stage separator. These parameters were monitored to assure the steadiness of operation during the test.
• Location 2: Condensate flowrate and salt content downstream the second stage separator. These parameters were monitored to determine the salt content at the inlet of the unit.
• Location 3 : Pressure drop across the stabilizer feed heater (tube side).
This parameter was monitored to ensure that no blockage has taken place due to salt deposition.
• Location 4: Pressure drop across Stabilizer feed flow control valve as well as valve opening. These parameters were monitored to ensure that no blockage has taken place due to salt deposition.
• Location 5 : Stabilized Condensate flow rate and salt content downstream the stabilizer tower. These parameters were monitored to determine the salt content at the outlet of the unit.
• Locations 6 & 7: Inlet flowrate, inlet temperature and outlet temperature to/ffom reboiler. These parameters were monitored to ensure the steadiness of the tower operation during the test.
• Location 8: Condensate salt content and water content upstream the condensate storage tank. These parameters were monitored to ensure that the chemical is functioning at different operating temperatures and is keeping the salts suspended in the condensate throughout all the path till the storage tanks. Test sequence (see figure.5)
• Preparation Steps (see figure.6)
The above-mentioned process variables were monitored and measured without water injection (NT) for a period of 10 hours.
Water injection was started for a period of 2 hours then the same process variables were monitored and measured.
• Start of First Sequence (see figure.7)
Water injection was stopped for a period of 10 hours then the same process variables were monitored and measured.
Chemical injection (Cl) was started for a period of 2 hours then the same process variables were monitored and measured every 1 hour.
Chemical injection continued until equalization between the inlet and outlet salt contents is reached and after that readings for in/out salt contents, which should be equal, were taken as 1 reading every 1 hour.
The first sequence has ended, and the second sequence was started.
• Start of Second Sequence
Chemical injection was stopped then the same process variables were monitored and measured for a period of 10 hours.
Chemical injection was started again for a period of 2 hours then the same process variables were monitored and measured every 1 hour. Chemical injection continued until equalization between the inlet and outlet salt contents is reached and after that readings for in/out salt contents, which should be equal, were taken as 1 reading every 1 hour.
The second sequence has ended, and the third sequence started. The third sequence is typical to the second.
The above procedure / sequence for testing the proposed chemical was repeated for 3 to 4 days.
Test Results
Based on the monitored data and laboratory test results obtained during the execution of the field test; It was observed that, without chemical injection, the amount of salts leaving the unit is much lower than the amount of salts in the feed (see figure.8) which indicates that the deficit salt amounts are deposited in the unit. However, after chemical injection, the amount of salts leaving the unit is almost equal to the amount of salts in the feed (see figure.9) which indicates that all salts in the feed condensate leaves the unit with the condensate product and thus there is not salt deposition in the unit.
An economic analysis has been performed based on this case study to illustrate the savings obtained from the chemical injection solution (i.e. the invention) versus the conventional designs (i.e. installation of desalter or coalescing filter).
A comparison of total installed cost (TIC) and total installed cost plus 10 years’ operating cost for different solutions have been estimated with an accuracy of ± 30 % (see. figure.10) and the results reflected the huge savings of the invention.
Figure imgf000010_0001
The Method Of exploiting The Invention :
This invention is intended to be used in condensate stabilization units or crude distillation units, either new units or existing units, to solve the problem of salt deposition.
The first step is to test surfactant chemical to ensure it will function efficiently (i.e. prevent salt/solids depositions via keeping these particles suspended in the hydrocarbon phase) under the operating conditions of the unit and to determine the required dosage rate. Then, design and install a chemical injection package consisting of small chemical storage tank and injection pumps. Brief description Of The Drawing :
Figured : represents a typical flowsheet of a condensate stabilization unit.
Figure.2 : represents the chemical injection location in the condensate stabilization unit.
Figure.3 : represents water injection locations in the condensate stabilization train.
Figure.4 represents monitoring and measuring locations
Figure.5 represents test sequence.
Figure.6 represents the preparation steps of the test sequence.
Figure.7 represents the first sequence of the test.
Figure.8 represents the field test results obtained before chemical injection.
Figure.9 represents the field test results obtained after chemical injection.
Figure.10: represents the comparison of economic parameters between invention and conventional designs.

Claims

Claims The new desalting technique by injecting a surfactant chemical, where the injected chemical prevents deposition of salts and solids particles within condensate stabilization units and keeps these particles suspended in the flowing condensate inside the equipment of the unit, then the suspended salts will be dissolved again by injecting low salinity water and then the water and dissolved salts are separated later through settling in the condensate storage tanks thus achieving the required specifications of the condensate, accordingly this technique avoids the utilization of traditional salt removal techniques which are complicated and expensive to solve the problem of salt deposition/removal in existing condensate stabilization units.
1. Mixed hydrocarbons from producing wells, are gathered and directed to the inlet separator (3 phase separator), to separate gas, hydrocarbon liquid and water.
2. Said hydrocarbon liquid, which is considered the feed of condensate stabilization unit, undergoes pressure reduction and is sent to condensate second stage separator (3 phase separator) which is considered the primary water separation step of the said feed of the said condensate stabilization unit.
3. Chemical is injected in the condensate separated from said second stage separator which shall keep salts suspended in the hydrocarbon phase and prevent them from being deposited in the said condensate stabilization unit.
4. Said condensate is then directed to the tube side of stabilizer feed/stabilized condensate heat exchanger and is heated against hot condensate leaving the bottom of the stabilizer. It is worth mentioning that the temperature at which the condensate is heated varies from one unit to another, however this temperature does not have a direct effect on the efficiency of the injection process, however it is necessary to select an appropriate chemical which works efficiently at the unit operating temperatures. to
5. Hot condensate from said stabilizer feed/stabilized condensate heat exchanger, is directed to the stabilizer tower.
6. The partially cooled condensate from said stabilizer feed/stabilized condensate heat exchanger is further cooled by the condensate rundown cooler and in the condensate/NGL exchanger before being sent to condensate storage tank.
7. Fresh water is injected upstream said condensate storage tank to dissolve said suspended salts.
Settled salty water shall be periodically drained
PCT/EG2021/000005 2021-02-16 2021-02-16 Desalting technique via suspending salt/solid deposits in flowing condensate WO2022174880A1 (en)

Priority Applications (1)

Application Number Priority Date Filing Date Title
PCT/EG2021/000005 WO2022174880A1 (en) 2021-02-16 2021-02-16 Desalting technique via suspending salt/solid deposits in flowing condensate

Applications Claiming Priority (1)

Application Number Priority Date Filing Date Title
PCT/EG2021/000005 WO2022174880A1 (en) 2021-02-16 2021-02-16 Desalting technique via suspending salt/solid deposits in flowing condensate

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Citations (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4581134A (en) * 1984-09-28 1986-04-08 Texaco Inc. Crude oil dehydrator/desalter control system
US20180195010A1 (en) * 2017-01-06 2018-07-12 Saudi Arabian Oil Company Methods and Systems for Optimizing Demulsifier and Wash Water Injection Rates in Gas Oil Separation Plants

Patent Citations (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4581134A (en) * 1984-09-28 1986-04-08 Texaco Inc. Crude oil dehydrator/desalter control system
US20180195010A1 (en) * 2017-01-06 2018-07-12 Saudi Arabian Oil Company Methods and Systems for Optimizing Demulsifier and Wash Water Injection Rates in Gas Oil Separation Plants

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