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.

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.