Plant 3
Oil Plant
The Gaviota Oil Plant is designed to remove free and emulsified water and suspended solids from the crude oil. The Oil Plant also stabilizes the crude by removing light hydrocarbons and H2S. The dry stabilized oil can then be transported. The Oil Plant is sized for 125 MBPD of wet oil – 100 MBPD dry oil plus 25 MPBD produced water.
The Oil Plant is divided into four basic processing sections which include:
There are other facilities associated with the processing sections such as product storage and utility support systems.
The installation consists of three 50,000 BPD (dry oil) trains of heat exchangers electrostatic coalescers, and stabilizer columns. Two trains are on-line while the third serves as a spare. The trains are rotated to equalize service life for equipment in each train. The Oil Plant also has produced-water treating facilities and an outfall line for treated water disposal. The Oil Plant also has a seawater desalination and water treating system and cogeneration facilities to produce water, steam, and electric power for both the Oil and Gas Plants.
Following is a brief functional description of the Oil Plant Systems.
The crude oil arriving onshore contains significant amounts of dissolved light hydrocarbon gases. The crude also contains toxic hydrogen sulfide (H2S), and large amounts (up to 20%) of emulsified formation water.
Wet raw crude from the offshore platforms enters the Oil Plant and is metered for accounting purposes. Then the crude is dehydrated by a two-step process. First, the bulk of the free water is separated from the crude by gravity in the free water knockout vessels. Second, residual free and emulsified water is removed from the crude by heating the crude of 200oF (reducing the crude viscosity) and routing it to an electrostatic coalescer. Dry raw crude contains up to about 1 vol% of water.
Next, the hot dry crude is sent to the Crude Stabilization Section. The Crude Stabilization Section consists of the crude stabilizer and overhead gas compression facilities.
In the crude stabilizer the crude is flashed at low pressure (~3 psig). This reduces the amount of light hydrocarbon components in the crude oil, resulting in a lower vapor pressure; it also reduces the H2S content. The crude may be stripped with sweet fuel gas, if necessary, to reduce the H2S content to the acceptable level.
The stabilized crude from the stabilizer is routed to storage via the raw crude preheaters, where it is cooled to about 135oF.
Two parallel overhead compression trains are provided to handle stabilizer overhead vapors. Each overhead compression train is designed for vapors from two stabilizer trains. One overhead compression train is used as a spare.
Vapors from the stabilizer contain light hydrocarbons, C02, H2S, and water vapor. These vapors are cooled to 120oF, causing some of the vapors to condense. The condensate is recycled back to the electrostatic coalescers, while the cooled vapors are compressed and routed to the Gas Plant. Further cooling and condensation occurs in compressor precooler E-1009 in the Gas Plant. Excess hydrocarbon condensate may be recycled from 1st stage K.O. drum, V-1010A in the Gas Plant back to the coalescers, to avoid overloading the Gas Plant’s Fractionation and Merox treating facilities. The remaining vapors are compressed and cooled, then sweetened in the Acid Gas Removal system.
The purpose of the Crude Stabilization Section is to:
Flash stabilization is used to reduce the crude oil vapor pressure. Light hydrocarbon gases are flashed from the crude in a low pressure crude stabilizer column. The stabilized crude H2S content may be reduced to an acceptable level just by flashing, if the raw crude H2S content is low (<60 ppmw). Otherwise, sweet fuel gas from the Gas Plant is used to strip the H2S out of the crude to guarantee a stabilized crude H2S content of less than 20 ppmw.
All three stabilizer trains are identical and the following discussion is the same for each system.
The raw crude from the electrostatic coalescer, V-2A, enters the Crude Stabilization Section at 200oF and 70 psig. The expected water content is 1.0 Vol%. Produced water may be added to the raw crude to maintain a water content of 1.0 Vol%. Too little water in the crude stabilizer feed may result in salt deposition problems in the stabilizer. Antifoam may be injected into the raw crude if foaming occurs in the stabilizer.
The raw crude tangentially enters the crude stabilizer, V-3A, via the coalescer level control valve. The control valve lets the pressure down from 70 psig to 3 psig. This causes the temperature to drop from 200oF to 179oF. Most of the light ends are flashed off as a result of the pressure letdown. The flashed vapors exit at the top of V-3A.
The flashed crude flows down V-3A and across 20 baffle trays. At the bottom of the stabilizer, stripping gas may be introduced if the stabilized crude H2S is higher than 20 ppmw. Stripping gas is sweet fuel gas from the Gas Plant and is predominantly methane and ethane. H2S is stripped out of the crude as flashing crude vapors and stripping gas (if used) flow up V-3A. The trays provide intimate contacting of upward flowing gas with crude results in efficient stripping.
Stripping gas usage should be minimized since it significantly increases the flashed C5+ rate to the Gas Plant and increases the load on the Oil and Gas Plant compressors.
Stabilized crude from the crude stabilizer is pumped by crude transfer pumps, P-1A and P-2A, to the dry oil surge tank T-1 via parallel crude preheat exchangers, E1A and D. Note there are no spares for P-1A and P-2A; instead, there is an entire spare stabilizer train.
Vapors from the free water K.O. drums (V-1A, B) and electrostatic coalescer, V-2A, are also routed to V-3A. However, there is normally no flow.
The flashed vapor from V-3A is sent to a low pressure drop air-cooled condenser, E-5A, where the vapors are cooled to 120oF. Condensed hydrocarbon liquid and cooled vapor from E-5A are routed to compressor suction scrubber, V-14A.
There are two parallel overhead compression skids. A stabilizer overhead system consists of a suction scrubber, V-14A; two condensate pumps, P-30A and B; recycle cooler, E-14A; and compressor, K-1A, all mounted on a common skid. Each overhead system is designed to handle the cooler overheads from two crude stabilizers. One skid is usually operating while the other is a spare.
1) Suction Scrubber, V-14A
The cooler vapor and liquid from two overhead coolers are collected in a common vessel, V-14A. It operates at 120oF and about 0.5 psig. Liquids condensed in E-5A, B are separated from the vapor in V-14A and pumped by P-30A and B to the electrostatic coalescers, V-2A, B, and C.
2) Overhead Compressor, K-1A
Vapor from V-14A is compressed in K-1A from 0.5 psig to 45 psig. The hot (~200oF) compressor discharge is then routed to the Gas Plant. Gas flow and composition are measured by flow meter skid (K-24) for accounting purposes. A portion of the compressed vapor is cooled to 140oF in E-14A and recycled to V-14A for compressor suction pressure control.
3) Compressor, K-1A, Discharge
Compressed vapor from K-1A is blended with compressed vapors from the vapor recovery system, metered in K-24, and routed to the Gas Plant. This vapor contains light ends as well as significant quantities, of H2S, CO2, and water. The vapor line to the Gas Plant is insulated and steam-traced to prevent condensation. If condensation occurs, it can produce a highly corrosive solution. A low point drain is provided to remove any condensate.
Vapors from the Oil Pant are cooled to 120oF in compressor precooler E-1009 located in the Gas Plant (Plant 10B). The partially condensed vapors enter the compressor 1st stage KO drum V-1010A. Vapors from V-1010A are further compressed in K-1010A or B. Hydrocarbon condensate from V-1010A is normally routed to the condensate surge vessels V-1001A and B in Plant 10A. If sweet gas stripping of the crude oil is required, it may be necessary to recycle a portion of the condensate from V-1010A to electrostatic coalescers, V-2A, B, and C, in the Oil Plant. This recycle may be required to keep from overloading the Gas Plant’s C5+ handling and Merox treating facilities in Plants 10B, 16 and 17.
Stripping gas injection in V-3A should be minimized since it significantly increases the C5+ rate to the Gas Plant. If stripping gas is not required, based on actual operating experience, then the recycle could be eliminated.
If black oil is present in the condensate from V-1010A due to entrainment from the Oil Plant, then all of the condensate from V-1010A will be recycled back to the Oil Plant. This is necessary to prevent the black oil from contaminating the NGL stream which is one of the salable products from the Gas Plant. Entrainment may occur under upset conditions in the Oil Plant.
Crude oil foaming in the crude stabilizers can result in inefficient stripping and carry-over of black oil into V-14A. Foaming can be caused by high crude viscosity (this makes froth breaking difficult), suspended solids, or contaminants carried into the oil system from the offshore platforms.
Foaming is indicated by a higher-than-normal pressure drop and/or pressure fluctuation in V-3A. Other signs are an unusually large amount of liquid in V-14A and its dark liquid color. To prevent foaming, an antifoam compound can be injected into V-3A feed. A non-silicone or low silicone antifoam such as Nalco 2RH-306 should be used. Silicone-based antifoams will foul refinery catalysts after crude is shipped from the Oil Plant.
Antifoam will be supplied in drums or tanks by the chemical vendor. The antifoam is injected into the raw crude via metering pump, P-51. A triple feed pump is used for greater turndown capability.
The antifoam injection rate is initially based on estimates from the antifoam manufacturer and will eventually be determined by operating experience. A preliminary estimate of this rate is 9.9 gph per 50,000 BPOD of crude.
A second injection system may be used to inject a salt dispersant into the raw crude if salt deposition in V-3A or the V-2A level control valve is a problem. Salts, particularly calcium sulfate, may deposit as water is evaporated from the produced water in the raw crude. As water vaporizes in V-3A, the salt concentration in the liquid water increases; and salt deposits will form if the solubility of the salt in water is exceeded. These salts may be carried away with the crude in the form of small crystals or may adhere to internal plant surfaces.
Additional parallel chemical injection systems are also available for injecting corrosion inhibitor, bactericide, polymer, and demulsifier, if necessary.
The Crude Stabilization Section is designed to process a nominal 100,000 BPOD of hot dry (200oF) raw crude from the electrostatic coalescers. There will be initially three crude stabilizer columns (A, B, and C trains) and associated overhead condensers. Each column is capable of processing 50,000 BPOD of dry raw crude. The crude stabilizer design feed rate, including condensate recycles from the overhead compression facilities and the Gas Plant, is 51,500 BPOD of dry raw crude. One column and condenser will be used as a spare.
The overhead compression system consists of a suction scrubber, recycle pump, and compressor mounted on a common skid. This system is designed to handle the cooler overhead vapors from two stabilizers. The overhead compression system will be spared.
Crude Feed Composition
The design case feed is a crude oil mix consisting of 75 LV% Platform Hermosa-type and 25 LV% Platform Hidalgo-type crude with an H2S content of about 150 ppmw. The expected H2S content is about 60 ppmw. About 1.0 Vol% of water is also present in the raw crude from the coalescers.
This section can also process a “base case” raw crude feed consisting of 100% Platform Hermosa-type crude. The base case feed (22.3oAPI) contains fewer butanes and pentanes than the lighter design case feed (24.3oAPI). Hence the heavier base case feed will put less load on the stabilizer overhead system (e.g., E-5, K-1, etc.) than the design case feed. The base case raw crude H2S and water contents are 60 ppmw and 1.0 Vol%, respectively.
Stripping gas, which is sweet fuel gas from the Gas Plant, may be injected into the crude stabilizers to reduce the stabilized crude H2S content if necessary. The design case includes injecting 9.25 MMscfd of stripping gas per stabilizer while the base case includes no stripping gas injection.
Lighter crudes will contain more C1 (methane) to C5 (pentane) hydrocarbons, which will flash in the crude stabilizer. The increased vapor rate will strip more H2S out of the crude. Conversely, a heavier crude will generate less vapor and may require introduction of stripping gas at a relatively low raw crude H2S content.
For two crudes of equal raw crude H2S content, the lighter crude will produce a lower stabilized crude H2S content and a greater amount of overhead vapors. If stripping gas is required to meet the stabilized crude H2S specification, less gas would be required for the lighter crude due to the greater vapor generation.
The Crude Stabilization Section is designed to initially produce about 98,000 BPOD of stabilized crude. The stabilized crude has a vapor pressure of about 10 psia at 130o F and a maximum H2S content less than 20 ppmw. The H2S content is expected to be less than 10 ppmw. A small amount of water, about 0.3 vol%, is present in the stabilized crude. The stabilized crude also may contain small amounts of injected chemicals (e.g., antifoam, corrosion inhibitor, etc.).
The following summarizes the specifications on the stabilized crude:
The flashed light hydrocarbon vapors from the Crude Stabilization Section will contain appreciable amounts of H2S, CO2, and water. Roughly 6.6 MMscfd and 2.7 MMscfd of flashed vapor will be routed to the gas plant per 200,000 BPOD of crude feed in the design and base cases, respectively.
DESIGN BASIS
CRUDE STABILIZATION SECTION
|
Case |
Base |
Design |
|
Crude Type |
100% Platform Hermosa |
75 LV% Platform Hermosa-Type and 25 LV% Platform Hidalgo-Type Crude |
|
I. Raw Crude Rate and Conditions |
|
|
|
Rate, BPOD (Dry Basis) |
200,000 |
100,000 |
|
Temperature, oF |
200 |
200 |
|
Pressure, psig |
70 |
70 |
|
Gravity, oAPI |
22.3 |
24.3 |
|
H2S, ppmw |
60 |
150 |
|
BS and W, Vol% |
1 |
1 |
|
Light End Composition, 1 |
|
|
|
Dry Basis, LV% |
|
|
|
C1 |
0.06 |
0.05 |
|
C2 |
0.06 |
0.05 |
|
C3 |
0.24 |
0.34 |
|
C4 |
1.07 |
1.14 |
|
C5 |
1.72 |
2.42 |
|
Whole Crude TBP,1 T oF |
|
|
|
Dry Basis, LV% |
|
|
|
5 |
154 |
-- |
|
10 |
222 |
211 |
|
30 |
443 |
434 |
|
50 |
668 |
663 |
|
70 |
1,033 |
986 |
|
II Stabilized Crude Rate and Properties |
|
|
|
Rate, BPOD |
96,940 |
98,0301 |
|
Gravity, oAPI |
20.0 |
23.3 |
|
Vapor Pressure at 130oF, psia |
7 |
10.1 |
|
H2S, ppmw |
10 |
10 |
|
BS and W, Vol% |
0.5 |
0.3 |
|
|
|
|
1Raw crude information shown is for crude directly from the oil pipeline. It does not include V-14 and gas plant recycles.