METHOD OF REDUCING MERCURY IN STABILIZED CONDENSATE

Abstract

The present invention is directed to a method for removing elemental mercury from liquid natural gas comprising changing the stabilizer column operating conditions to beneficially transfer mercury from the stabilized condensate phase to the overhead gas phase, where it may be compressed and recycled with the gas going to the existing feed gas mercury removal units.

Description

FIELD OF THE INVENTION

The field of the invention is the removal of elemental mercury from stabilized condensate in liquified natural gas processes.

BACKGROUND OF THE INVENTION

The well fluids from liquified natural gas processes are known to contain mercury in the stabilized condensate, which tends to partition between the gas, hydrocarbon and produced water phases upon arrival to the onshore inlet separators. Hydrocarbon condensate is sent to a stabilizer column to achieve a minimum Reid Vapor Pressure specification before being stored and eventually sold in cargoes. Due to vapor-liquid-equilibrium, there will always be mercury present in the stabilized condensate. Above a certain concentration, the condensate sells for a significant discount in the marketplace.

Conventional methods of treating the condensate is to install a mercury removal unit (MRU) to remove the mercury to levels below the discount concentration. MRUs are proven technologies for liquid phase mercury removal from condensate and refinery naphtha. The chemistry is based on irreversible complexation between elemental mercury and the copper sulfide groups on the adsorbent to form bound mercury sulfide. The primary disadvantages of the MRU are the need for new equipment and capital costs, operating costs for the disposal of spent adsorbent, operating costs for the makeup of fresh adsorbent and possible downtime and labor costs from the effort to physically replace spent adsorbent with fresh adsorbent.

SUMMARY OF THE INVENTION

A method for removing elemental mercury from liquid natural gas comprising changing the stabilizer column operating conditions to beneficially transfer mercury from the stabilized condensate phase to the overhead gas phase, where it may be compressed and recycled with the gas going to the existing Feed Gas MRUs.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a comparative graph of the favorability of lower stabilizer pressure to remove mercury.

FIG. 2 is a comparative graph of the effect of lower stabilizer pressure on compression requirements.

FIG. 3 is a table of the impact of the Gorgon/Janz ratio on condensate production and mercury distribution.

FIG. 4 is a comparative graph of reboiler temperature at 450 kPa for variable Gorgon/Jansz.feeds, liquid side.

FIG. 5 is a comparative graph of reboiler temperature at 450 kPa for variable Gorgon/Jansz.feeds, gas side.

FIG. 6 is a schematic of the effect of higher boiler temperature on the movement of C4-C6 to the scrub column.

FIG. 7 is a table of the apparent loading of stabilizer trays in simulated conditions.

FIG. 8 is a plot of Gorgon stabilizer Train 2 condy to storage tank (kg/s).

FIG. 9 is a plot of Gorgon stabilizer Train 1 condy to storage tank (kg/s).

FIG. 10 is a plot of Gorgon stabilizer Train 1+Train 2 condy to storage tank (kg/s).

FIG. 11 is a plot of gas flow from slug catcher (kg/s).

DETAILED DESCRIPTION OF THE INVENTION

This process invention is meant to cover a range of operating conditions of feed gases in a facility that produces natural gas and hydrocarbon liquids that contain elemental mercury. The ratio of mercury content from various feed wells determines the reboiler temperature.

While not being limited to the particular gas streams herein, representative liquid natural gas plants (LNG) are those containing two feed streams with differing mercury content, for example from 70% Gorgon/30% Jansz to 30% Gorgon/70% Jansz based on a CO2-free hydrocarbon-gas ratio feed to the gas processing portion of the LNG plant. As the mercury content is higher in Gorgon than in Jansz, the total hydrocarbon liquid and its mercury concentration going to the stabilizer can vary. Gorgon LNG also has two parallel trains of stabilizers, which are designed as 2×100%—this makes it possible to process 100% of the condensate in either stabilizer, 50% of the total condensate in each stabilizer, etc. Lastly, the Gorgon LNG plant is currently equipped with feed gas-phase MRUs on the inlet to each of the three parallel acid gas removal units (AGRU), along with product gas MRUs immediately upstream of each of the three LNG liquefaction units.

Gorgon LNG currently processes its entire condensate production through a single stabilizer (1×100%) operating at a bottoms pressure of 450 kpag and reboiler outlet temperature of 193 C. The stabilized condensate is estimated to have an average mercury content of 565 ppb at the average flowrate of 14.9 kg/s (˜10,000 bpd). Total Gorgon condensate production can vary from as low as 0.77 kg/s (514 bpd) to 43.8 kg/s (29,383 bpd). An embodiment of the invention is a pressure of 500 kpag and 42 C overhead and 520 kpag and 192 C bottoms. An additional embodiment is the reboiler itself having a min/max design temperature of 7 C/250 C for both the shell-side and tube side with design pressure of the reboiler is from full vacuum to 750 kpag on tube-side and 4600 kpag on the shell-side.

An embodiment of the invention is changing the stabilizer column operating conditions to beneficially transfer mercury from the stabilized condensate phase to the overhead gas phase, where it may be compressed and recycled with the gas going to the existing Feed Gas MRUs. The additional mercury added to the Feed Gas MRUs will result in a slight reduction in lifetime for the feed gas MRUs (e.g., 3.8 years life instead of 4 years life; 7.6 years life instead of 8 years life, etc.) and higher horsepower duty on the existing overhead gas compressors. There is also a slight increase in reboiler duty and related utility cost. However, the significant benefit is that no new capital equipment is required in order to treat the stabilized condensate below the discount level—at 20,000 bpd and $4/bbl this is $29 MM/year in benefits.

Another embodiment of the invention is the stabilizer bottoms operating pressure shall be at least 70 kpag below the design pressure (e.g., 450 kpag or less for design pressure of 520 kpag).

Another embodiment is the stabilizer column should be inspected, maintained, and controlled such that the reboiler outlet temperature and bottoms product temperature are within 1 deg C. or less during operation.

A further embodiment comprises two or more feeds that may comprise a mixture wherein the reboiler temperature is adjusted to the percent feed mixture. For example, Janz feed mixture and reboiler outlet temperature based on the Gorgon percentage:

for a 30% Gorgon/70% Jansz feed mixture, the reboiler outlet temperature is 204 C or greater;

for a 50% Gorgon/50% Jansz feed mixture, the reboiler outlet temperature is 199 C or greater;

for a 70% Gorgon/30% Jansz feed mixture, the reboiler outlet temperature is 196 C or greater

The higher reboiler outlet temperatures are achieved by increasing the flowrate of the heat transfer medium (i.e., currently pressurized hot water loop with supply temperature of 220 C)

A preferred embodiment is in the event that that the target reboiler outlet temperature is not easily obtained with 1×100% stabilizer operation, then 2×50% stabilizer operation is utilized. Total mercury in the stabilized condensate is 50 ppb (by mass) or less.

Besides elimination of the mercury discount, the process invention has the following additional advantages:

1. Meeting or exceeding the required Reid Vapor Pressure (RVP) specification on the stabilized condensate

2. Despite higher amounts of C4 to C6 hydrocarbons sent to the overhead stream, no negative impact on the LNG scrub column operation.

Claims

1. A method for removing elemental mercury from a liquified natural gas stream feed comprising changing the stabilizer column operating conditions to transfer mercury from the stabilized condensate phase to the overhead gas phase, where it may be compressed and recycled with the gas going to the existing feed gas mercury removal units.

2. The method of claim 1, wherein the stabilizer column should be inspected, maintained, and controlled such that the reboiler outlet temperature and bottoms product temperature are within 1 deg C. or less during operation.

3. The method of claim 2 wherein the feed consists of a mixture of two or more streams of liquified natural gas.

4. The method of claim 3, wherein the reboiler outlet temperature of the stabilizer column is varied based on the mixture.

5. The method of claim 1, wherein the stabilizer bottoms operating pressure shall be at least 70 kpag below the design pressure.

6. The method of claim 4 wherein the feed mixture is 30% Gorgon/70%, and the reboiler outlet temperature is 204 C or greater.

7. The method of claim 4, wherein the feed mixture is 50% Gorgon/50%, and the reboiler outlet temperature is 199 C or greater.

8. The method of claim 4, wherein the feed mixture is 70% Gorgon/30%, and the reboiler outlet temperature is 196 C or greater.