Plant 11/21  Acid Gas Removal Units

Design Basis

This section discusses the basis used to design the Acid Gas Removal Plants.

Feed Sour Gas

Sour gas at 650 psig and about 60^oF is fed at rates of up to 30 MMscfd to each Amine Plant.  At this design rate, these plants can treat sour gas with up to 0.8 vol% (i.e., 8000 ppm_v) H₂S and 4.0 vol% CO₂.  Somewhat higher acid gas concentrations can be treated at lower sour gas feed rates. Sour gas also contains small quantities of COS and mercaptans.  The estimated concentration of COS is 45 ppm_v and of mercaptans is 52 ppm_v.

Treated Sweet Gas

After passing through the Amine Plant, the sweetened hydrocarbon gas contains less than 0.25 grains H₂S/100 SCF of gas (or <4 ppm_v H₂S), about 100 ppm_v CO₂, and about 5-10 ppm_v COS.  Mercaptan concentration is unaffected since these compounds are not removed in the Amine Plant.

The mercaptans and most of the COS remaining in the treated sweet gas are condensed downstream in the LTS Unit (Plant 12) and treated in Liquids Treating (Plant 17).

The specifications for sales gas are listed below:

            H₂S < 4 ppm_v

            CO₂ < 3 vol%

Organic Sulfur < 3.2 ppm_v (includes Mercaptans)

Total Sulfur < 8 ppm_v (includes H₂S, Mercaptans, and COS)

Amine System

A mixture of 30 wt % diethanolamine (DEA) in water is used to absorb the acidic components from the sour gas.

Although several other amine-based chemicals are available to remove acid gases from natural gas streams, DEA was selected since it:

• Is being used successfully in many other Chevron plants to attain similar H₂S removal.
• Is effective over a wide range of H₂S/CO₂ feed concentrations.
• Is less corrosive than many other amines, requiring only carbon steel construction for most of the equipment.
• Does not undergo significant degradation in the presence of organic acid components or CO₂.
• Removes COS from sour gas (Plants 11 and 21) and from liquid propane (Plant 17).

Plants 11 and 21 may also be converted to use methyldiethanolamine (MDEA), and amine which selectively absorbs H₂S while leaving more of the CO₂ in the gas.  Using MDEA could reduce operating costs by decreasing regeneration steam requirements.

There are potential problems with using MDEA, however.  First, selective absorption of H₂S in the Amine Plants would result in an acid gas concentration much richer in H₂S.  This could create recycle blower limits in the Sulfur Plant.

Second, it is uncertain whether MDEA is as effective as DEA in removing COS from sour gas or from liquid propane (Plant 17).

Waste Streams

There are four intermittent waste streams originating from Plants 11 and 21:

1. Amine blowdown from equipment and line drains are collected in the amine sump and, if unsuitable for reuse, are pumped to a truck for proper offsite disposal.
2. Solids recovered from backwashing the mechanical DEA filters settle out and accumulate in the DEA backwash surge tank, T-1131.  These solids are periodically removed by a vacuum truck for disposal.  Since these solids consist largely of pyrophoric iron sulfide, they may require neutralization prior to removal.
3. Backwash water from the DEA charcoal filters is routed to the produced water tank for disposal.
4. Drainage water is collected in open drains and routed to an impound basin.  This water is generated during equipment wash down or rain storms.

Waste streams from 1 and 2 above will be generated infrequently.  Typically, a responsible, outside waste collector will be contacted to dispose of these wastes in an appropriate manner.  DEA wastes should be analyzed (i.e., for H₂S, pH, % DEA, among others) prior to collection in order to properly classify the waste.  Normally, lean DEA is not classified as a hazardous waste but only requires neutralization before addition to a municipal wastewater treatment plant.

DESIGN BASIS

PLANTS 11 AND 21 – AMINE PLANTS

GAVIOTA GAS PLANT

¹Each of the two Amine Plants has a nominal capacity of 30 MMscfd sour gas.

²Maximum expected sour gas temperature.  Average temperate will be closer to 60^oF.

Process Description

This section discusses the flow scheme of Plant 11.  For simplification and clarity, the remainder of this discussion will refer to Plant 11 equipment and controls only.  This discussion should also be applied to Plant 21.

Plant 21 is identical except for some shared tankage as noted.  Also, Plant 21 equipment and instrument/control numbers begin with 21 instead of 11.

Introduction

There are two main processing steps in the Amine Plants:

1. Raw sour gas is contacted with lean 30 wt% DEA in an absorber column to remove H₂S, CO₂, and COS.  Sweet gas is routed to Plant 12 for liquids recovery and dew point control.
2. The rich DEA containing these acids is regenerated by stripping out the acid gases in a distillation column.  The acid gases are recovered from the regenerator and routed to either Plants 14/24 for sulfur recovery or to Plants 15/25 for incineration, depending on the acid gas flow rate.  Regenerated (lean) DEA is circulated back to the absorber.

Major Process Steps

This section provides a detailed description of the process flow scheme.

Absorption

Raw sour gas is fed to each of the Amine Plants from the intake separator, V-1000, and knockout drum, V-1010C, located in Plant 10.  These streams are combined and fed to Plant 11 at about 650 psig and about 60^oF at rates between 15-30 MMscfd.

The sour gas feed first passes through the centrifugal separator, F-1101 which removes most of the liquid droplets carried over or condensed in the feed lines from Plant 10.  It also recovers the bulk of any larger volume liquid slugs that may be generated during pipeline pigging.

Gas is then sent through the filter separator, F-1102 which removes solids and any remaining liquid mist from the sour gas.  Efficient liquids/solids removal is important to prevent contamination of the DEA with hydrocarbon liquids or solid particulates.  Both can cause foaming problems in the absorber and regenerator.

Hydrocarbon liquids recovered in F-1101 and F-1102 are returned to Plant 10 (V-1010B).

Sour gas passes from F-1102 into the lower section of DEA absorber, C-1110.  Gas flows up the column through the contacting trays and exists overhead.  Lean DEA solution at about 110˚F is pumped from surge tank, T-1140, and fed into the top of C-1110.  DEA flows down the column, contacting the gas stream on each of the 25 trays.  The DEA absorbs the acid gases and leaves the bottom of C-1110 as rich DEA at about 135^oF and 645 psig.  A small amount of hydrocarbon gases are dissolved into the DEA.

The contacting trays in both the absorber and regenerator columns are valve-type trays.

The actual C-1110 bottoms temperature depends on the amount of H₂S and CO₂ in the sour gas, the sour gas and lean DEA feed temperatures, and the flow rate of lean DEA fed to C-1110.  The streams leaving C-1110 are hotter than the feed streams due to the heat of reaction from absorbing the acid gas.

Sweet gas from the overhead of C-1110 passes through the absorber knockout drum, V-1111, to remove entrained DEA and is routed to Plant 12 for liquids recovery and dew point control.  Sweet gas should contain less than 4 ppm_v H₂S, about 100 ppm_v CO₂, and about 5-10 ppm_v COS.   This stream will be at 640 psig and a temperature very close to the lean amine feed temperature (i.e., ~110^oF).

Rich DEA from C-1110 bottoms containing about 5 wt% acid gases, is let down to 75 psig in the DEA flash drum, V-1112, to flash off light hydrocarbon vapors.  These vapors, which also contain small quantities of H₂S and CO₂, are routed to the first-stage compressor knockout drum, V-1010A, in Plant 10 for recycle back into the main gas stream.  DEA from V-1710 DEA settler (Plant 17) is also fed into V-1112 along with an intermittent sour water stream from the Sulfur Plants.

Removal of light hydrocarbons is important prior to DEA regeneration.  Hydrocarbons not removed in V-1112 end up in the recovered acid gas stream from the regenerator.  The heavier hydrocarbons can foul (deactivate) the downstream Sulfur Plant reactor catalyst.

Regeneration

Rich DEA from V-1112 is preheated by regenerated lean DEA in rich/lean heat exchangers, E-1122A, B, and C, and fed to the top of the DEA regenerator, C-1120, distillation column.

C-1120 operates at low pressure (1-16 psig) and high temperature (230-260^oF).  Thus, the desorption reaction, H₂S and CO₂ evolution from the rich DEA is favored.  The DEA flows down C-1120, across the 22 valve trays.  Acid gases are stripped out of solution by steam passing up through these trays.

Steam is generated in E-1120A and B reboilers by vaporizing some of the water out of the lean DEA.  Steam (at 50 psig from the cogeneration units) is used as the primary heating medium in these kettle-type reboilers.  This is supplemented by recovered steam from the Sulfur Plants.

C-1120 overhead vapor consists of water vapor and acid gases.  Most of the water is condensed in E-1121 air-cooled condenser.  The reflux drum, V-1121, separates the wet acid gas from the condensed water.  Sour water is pumped back to the column as reflux and acid gas, at 10 psig and 120^oF, is sent to Plant 14 for sulfur recovery or to Plant 15 for incineration.

As low H₂S rates, acid gas is routed directly to Plant 15 for incineration.  At rates less than 2 tons sulfur/day the Sulfur Plant is limited by turndown constraints.  When producing more than 2 tons sulfur/day, acid gas is routed to one or both Sulfur Plants.

Normally, Plant 11 acid gas will be processed in Plant 14 and Plant 21 gas in Plant 24.  However, a crossover line provides the flexibility to divert some or all of the acid gas to one or the other Sulfur Plant.

Regenerated (lean) DEA at 258^oF (containing about 5000 ppm acid gases) leaves C-1120 bottoms and preheats C-1120 rich DEA feed in E-1122.  Lean DEA is then cooled to 110^oF in air cooler, E-1123, before filtration.

Filtration

A 5% slipstream of lean DEA is filtered by charcoal (i.e., activated carbon) in F-1124 to remove DEA degradation products and liquid hydrocarbons.  These components, if allowed to accumulate in the DEA, would cause foaming in C-1110 and C-1120 and increase equipment corrosion rates in the entire plant.

Only a small slipstream is filtered since this is adequate to control any significant buildup of these contaminants.  Filtering more of the DEA would require a larger filter and would remove more of the corrosion inhibitor or antifoam chemicals which may be periodically added to the DEA.

After charcoal filtration, the whole lean DEA stream is filtered in the Ronningen-Petter mechanical filters, F-1130, to remove solids.  These solids consist largely of iron sulfide scale and iron carbonate precipitate (from corrosion), insoluble degradation products, and particles from the upstream charcoal filters.  Solids larger than about 25 microns are removed in F-1130.   Removal of solids from the DEA helps minimize foaming in C-1110 and C-1120 and erosion/corrosion problems in the entire DEA system.

Filters F-1130 are automatically backwashed when the pressure drop across these units exceeds about 15-20 psi.  DEA from the surge tank, T-1140, is used to backwash F-1130 with the backwash solution being routed to the DEA backwash tank, T-1131.

Backwash solution is periodically pumped from T-1131 through backwash filters, F-1131, to T-1140.  Pump suction is taken using a floating swing arm in T-1131 to allow the larger solids to settle out in this tank.  Solids will accumulate in T-1131 and should periodically be cleaned out by a vacuum truck for proper offsite waste disposal.

F-1131A and B are sock-type filters which remove unsettled solids from the backwash solution.  Socks from these filters must be removed periodically for manual cleaning or replacement.

DEA Storage

Filtered, lean DEA from F-1130 is routed to T-1140 lean DEA surge tank.  T-1140 provides surge volume to accommodate swings in DEA solution inventory and changes in the various DEA liquid levels in Plants 11 and 17.  Tank T-1141 stores concentrated (85 wt%) DEA for solution make-up.

Oil Layer Skimming

Despite precautions again liquid hydrocarbon contamination, hydrocarbon layers may still accumulate in C-1110, V-1112, C-1120, and V-1121.  Skim nozzles are provided on these vessels to allow intermittent skimming of an oil layer.  Skimmed oil is routed to the DEA skim drum, V-1160, where it is allowed to settle and separate into a lighter hydrocarbon phase and heavier DEA phase.  Periodically, the DEA phase is pumped out to V-1112 for reuse or to V-1170 amine sump for disposal.  The hydrocarbon layer is pumped to the oil plant for recovery.

Chemical Addition

Occasionally, the injection of certain chemicals may be required.  Antifoam is injected via shot pot, M-1103 or additive tank, T-1145 to control foaming in C-1110 or C-1120.  Corrosion inhibitor may be required to control corrosion rates.  Caustic may be injected periodically to convert some of the amine-based, heat-stable salts into sodium-based salts.