OFFSHORE TOPSIDES-Conclusion Decision trees clarify novel technology applications

John J. MacDonald
Chevron USA Production Co.
Houston

Robert S. Smith
OPC Engineering Inc.
Houston

This conclusion in a series of two articles that began in OGJ, Feb. 17, 1997, p. 42 continues to illustrate decision trees for selecting such equipment as:

• Crude stabilizers

• Cyclone separators

• Emulsion treatment processes

• Hydroclones for primary oil/water separation

• Powered centrifuges for primary oil/water/gas/sand separation.

Crude stabilizers

Fig. 1 [21626 bytes] shows a crude stabilizer integrated into a processing scheme, and Fig. 2 [32504 bytes] illustrates a decision tree for selecting a crude stabilizer.

Based on economics, the following criteria can justify crude stabilizer installations:

• Crude contains H₂S and has an export quality specification of 50-60 ppm H₂S or less.

• A 10-12 Rvp tanker export specification and the compressor interstage condensate cannot be exported.

• Reservoir fluid has a high, greater than 5%, content of middle range components, C₃, C4s, and C₅s.

• No sales outlet for gas; thus, requiring gas flaring or reinjection.

• Low upstream oil/gas separation pressure.

• Low upstream oil/gas separation temperatures.

Stabilizers are not recommended if a pipeline export crude has a relatively high Rvp specification.

The additional operating costs for the stabilizer depend primarily on whether the crude contains H₂S. If H₂S is not present, waste-heat recovery units may be installed. If H₂S is present, waste-heat recovery units cannot be used because of their aluminum and brass construction.

Fired heaters have an additional fuel cost of $500,000/year, based on $0.50/Mcf and 150,000 b/d crude production.

Weight, area

A crude stabilizer with its associated support utilities imposes additional weight and area on an offshore platform (Table 1 [10589 bytes]).

Stabilizers increase by 4-12% the power required on a platform. This additional power is required because of increases in heating medium, cooling water, and sea water. Stabilizers do modestly decrease the low-pressure gas compression requirements.

Also, part of the additional power required is due to the decreased available power, about 2.5%, caused by the waste-heat recovery units supplying heat to the stabilizer reboiler. Turbine alternator sizes should not be affected by this small power increase requirement caused by the waste-heat recovery units.

Utilities

Stabilizers have a major impact in increasing the required heating medium size.

Also, stabilizers potentially can require high rates of water for diluting salt in the crude. This impact may be overcome by removing free water in the stabilizer chimney trays and by antifoulants.

Payback period

Stabilizer economics are less attractive for larger installations. Payback periods relative to a constant 4% C₃ through C₅ composition in the reservoir fluid and a 1,000 scf/bbl GOR as a function of throughput are as follows:

• 50,000 b/d-3.3 years

• 100,000 b/d-6.1 years

• 150,000 b/d-18.4 years.

The increased payback trend is primarily attributed to the need for larger power generation units and the cascading effect of this change on the remaining systems, including the heating medium system.

The payout period at higher flow rates may be decreased by optimizing power generation configurations or having a higher C₃ through C₅ composition.

Stabilizer safety concerns can be overcome by employing a nonhydrocarbon-based heating medium. A stabilizer also reduces safety risk by decreasing gas evolution on a tanker and by using waste-heat recovery units, which reduce turbine exhaust temperatures.

At low flow rates without the unit performing fractionation, stabilizers may be used as a low-pressure, last separation stage.

Maintenance/operation

Maintenance is a concern in stabilizer operations, primarily in regard to the stabilizer reboiler and associated salt build-up. Regular yearly inspections and antifoulants can control this potential problem.

With a storage tanker, operators have the latitude to perform maintenance inspections over a long period without interrupting overall production.

A stabilizer can replace an electrostatic treater or desalter and its associated maintenance of electrical plates caused by fluctuating flow. Also, by removing two crude separation stages (the low-pressure separator and emulsion treater), operators may concentrate on the crude stabilizer and its relatively simple controls. An additional operating concern is the installation of a heating medium heater with its associated safeguard control system.

Operating control differences can be reviewed during the training period for familiarizing operators with a crude stabilizer. Typically, no additional operating personnel are required for stabilizer operations.

Cyclone separators

Cyclone separators can remove bulk contaminants from gas streams containing particulates or entrained liquid (Fig. 3a [15486 bytes]). Cyclones work by injecting the process stream tangentially into a vertical cylindrical separation vessel. The velocity creates high centrifugal forces.

In the cyclone, the gas changes direction and exits a centrally located riser tube while the heavier particles spin around the vessel wall and eventually fall to the bottom and exit from a discharge tube.

Tangential velocity is the main driving force in the separation process. Small separator tubes are, therefore, more effective than one large separation vessel.

As shown in Fig. 3ba [15486 bytes], cyclone separation systems today house many standardized cyclone tubes in a larger containment vessel that acts as a distribution system for incoming gas as well as a collection system for the exiting product streams.

In at least one case, a single, low cost, cyclone separator (about 10-in. diameter) was installed at each well to remove gross sand prior to a filter separation system.

One cyclone separator vendor claims an overall removal efficiency of 99% for a gas stream with a 5% liquid loading at the inlet.

Fig. 4a [73773 bytes] shows a decision tree for selecting a cyclone.

Cyclones cost about 40-50% more per unit weight than standard separators. However, cyclones offer substantial weight and space savings, which can offset their cost/weight differences in many offshore applications.

The units are said to be inefficient during slug flow. The main concern, usually neglected by process designers, is cyclone turndown.

Several proprietary designs are available. One such design is the Cyclotube developed by Perry Equipment Corp.

This design, primarily for gas streams, has four operating compartments (Fig. 3b [15486 bytes]). The first contains a device that induces the incoming gas to rotate. The second compartment is the first-stage separation area. Two ports are in this section. High centrifugal forces sling heavier particles against the wall of the tube and the particles exit through the second port.

Pressure drop at the spinner section exit draws the ejected gas back into the Cyclotube through the first port. Heavy particles ejected through the port settle by gravity in the low-velocity section.

A third, smaller diameter section houses a third port where smaller particles are discharged. The fourth section redirects the flow to the exit.

The advantages of the Cyclotube system over other cyclone separation systems are:

• High turndown capacity

• High separation efficiency over the entire turndown range

• Appropriate for fluids with low surface tension. These liquids tend to wet metal surfaces and travel in the direction of the gas flow, thus thwarting efforts at separation.

• Appropriate for removing salt water from gas streams

• Small footprint area as compared to conventional separators

• Light weight

• Small pressure drop.

Cyclotubes are not recommended for extremely dry gas streams.

Emulsion treatment

Fig. 4b [73773 bytes] illustrates a decision tree for selecting an emulsion treatment.

Dehydrators reduce water content in the crude to meet export quality specifications. Figs. 5a and 5b [46082 bytes] illustrate horizontal and vertical crude oil dehydrators.

During the producing life of a reservoir, water in undesirable quantities may be produced with the crude. With asphaltic crude oils, 25° ±5 API gravity, even initial production could contain water.

A 25° API-range crude is typically classified as marketable if it contains no more than 1% bs&w, although, some California crudes with lower gravity are marketable with a bs&w as high as 5%.

If water in a free form reaches the dehydrator at temperatures less than 130° F., an emulsion will usually form between the oil and water. This emulsion requires more treatment than gravity settling to reduce the crude's water content.

Two types of crude emulsions form. This article discusses the normal type where water is dispersed in oil. The other type is less common and is a reverse emulsion where oil droplets are dispersed in water.

Emulsions form between the producing formation and the storage tanks. Usually, there is enough agitation to disperse the water through the oil. The agitation may be caused by a subsurface pump, gas-lift mixing energy, expansion through a choke, or flow through the tubing and flow line.

During agitation, water forms various sizes of droplets that tend to be spherical. If a film surrounds the droplets, water will remain permanently dispersed throughout the oil. This film prevents the droplets from coming together and forming one large drop, and settling downward through the oil to create a water phase.

Emulsifying agents increase the surface active characteristics of this film. These agents may be:

• Asphaltenes

• Resins

• Heavy paraffinic and naphthenic compounds

• Fine dispersed solids.

Emulsifying agents are all composed of large molecule compounds that form around the water drops, making a thick, tough film. This film needs to be destroyed to break the emulsion.

Demulsifiers

Demulsifier chemical injection takes place, usually, prior to fluid entry into a treating vessel. Demulsifiers are important for successful treating-vessel operations.

Demulsifiers disperse throughout the emulsion and collect on the water/oil interface, causing the emulsifying agent to displace and disperse throughout the oil phase of the mixture.

Demulsifier molecules are small, and consequently the film thickness is less at the water/oil droplet interface than what existed with the original emulsifying agent. The resultant film is much thinner and the bond holding the droplets in dispersion is considerably weaker.

After the demulsifier displaces the emulsifying agent, water drops coalesce. Because less distance separates the drops, the molecular attraction between drops is stronger. Upon droplet contact, this attraction is sufficiently strong to pull the drops together, rupturing the surrounding film and allowing minute water droplets to coalesce into larger drops. These drops then settle out of the oil phase.

Addition of heat

In the dehydrator, the flow first encounters the flow diffuser which separates the bulk liquid from the gas. A gas scrubber processes this relatively cool gas before the gas exits the vessel.

After the diffuser, liquids are processed through a water dropout stage. This allows free water to leave and reduces heat requirements. Heat is beneficial for treating emulsions because it:

• Increases emulsifying agent solubility and agent or agents dispersion in the mixture's oil phase

• Speeds demulsifier solubility at the water drop surface and speeds demulsifier reaction

• Lowers oil and water viscosity

• Adds energy to the system, causing movement of the water drops, largely by thermal currents, that induces collisions and coalescence.

Field tests can determine the temperature for economical water separation. Some light crudes (35° API or greater) may separate water quickly at 85-100° F. But some heavy oils (20-25° API) may require temperatures up to 180° F. If the oil/water mixture properties are unknown, 130° F. is often assumed.

Electrical coalescence

An electrical coalescence step between the emulsion-heating step and oil-settling stage can increase the water-settling rate and possibly lower the treating temperature. Fig. 5c [46082 bytes]creatly accelerates the coalescing rate after the emulsifying agent has been ruptured or displaced to expose the water droplet surface. The most common electrostatic coalescing involves electrodes immersed in the oil.

The electrical field is created by voltages in excess of 10,000 v. This electrical field causes rapid collision between the drops and rapid coalescence. Gravity settling of the water drops allows the dehydrator oil to be withdrawn from the upper section of the oil-settling step.

Horizontal vessels allow installation of a greater electrode area than the same diameter vertical vessels. Horizontal vessels, for a given diameter and shell length, have greater treating capacity.

However, vertical vessels are used for small volumes and where horizontal space limitations exist.

A large, horizontal crude oil dehydrator has about a 14-ft diameter and 75-ft length.

Foam control

Defoaming chemicals are often used if foam is encountered. Heat, such as from the downflow heating step, may further reduce foam.

As liquid is withdrawn from the bottom of the heating step, foam remains on top. Foam deterioration rate will be a limiting factor in dehydrator capacity. Crude oil foam deterioration rates are best determined by field testing.

Treating comparison

Past studies compared heater-treater and electrostatic coalescer performance with a 33-34° API crude. The conventional heater-treater processed about 23,000 bo/d at 130-140° F, while the electrostatic treaters processed the same volume but at a reduced temperature of 90-100° F.

The lower treating temperatures reduced fuel gas consumption by about 230 Mscfd. Gravity improvement varied between 0.3 and 0.5° API, depending on the oil mixture produced by the various offshore fields.

The electric load with the additional equipment was about 11 kw-hr.

Booster pumps

The last production separation stage is often at the bubble point unless the fluid is stabilized. Equipment downstream of the last separation stage creates pressure losses that are normally overcome with a crude booster pump.

The crude booster pump must have adequate lift to overcome the losses and still provide sufficient suction head to the main crude discharge pumps, if necessary. Pressure losses can be due to:

• Emulsion treating vessel

• Liquid control valve on the last separation stage

• Crude metering and prover skid

• Crude export cooler.

If the crude export pressure is not high, (less than 700 psig) and emulsion treating is unnecessary, the designer should consider combining the crude booster pump service with the crude export pump. The combined pumping can be done with a multistage vertical "can" type pump with low NPSH requirements and capable of lifting about 150-200 ft/stage.

If emulsion treatment is required at pressure levels not greater than 30-50 psig, the option of operating at higher pressure would impose a very heavy, costly design on the emulsion treatment vessels. Under these circumstances, a crude booster pump is more economical.

Hydrocyclone separation

Hydrocyclone separation is similar to centrifugal gas/liquid separation except that two liquids with different densities (oil and water) form the mixture.

The density difference of an oil/water mixture is much less than in a gas/liquid mixture. Because of this design criteria, the separator tubes have to be much longer than in cyclones.

Advantages

The advantage of hydrocyclones is that the outlet stream, which in most cases is oil, will have very little entrained water.

Only a few vendors sell hydrocyclones. Vortoil Separation Systems, the oldest in the business, has hydrocyclones for various applications, including dewatering, deoiling, desalting, desanding, and downhole water separation. Its system claims:

• 95-99% oil removal from water streams

• 90% water removal from oil streams

• Light weight

• Small footprint area

• Low maintenance, no moving parts

• Adjustable capacity in the field by adding or removing separator tubes.

Some of the operating parameters with cyclones containing newer internal separation elements (liners) are as follows:

• Solids handling: <=20% solids, exits with water stream

• Maximum water: 30%, (70% oil)

• Crude API gravity: >=10°

• Emulsions: not suitable for handling emulsions

• GOR: 90+% separation efficiency if GOR <= 300 scf/bbl

• Minimum inlet pressure: 25 psig

• Highest operating pressure: 2,250 psig

• Vessel diameter: 6-60 in.

• Number of liners/tubes: 150.

Hydrocyclone sizing

Fig. 4c [73773 bytes] shows a decision tree for selecting hydrocyclones.

Each liner has a 100 b/d capacity at an 8 psi pressure drop and up to 700 b/d capacity at a maximum 450 psi pressure drop. Capacity is a function of pressure drop according to the following function:

Q = (1,600 x DP_{inlet - outlet})0.502

where: Q is in b/d/liner

This equation is valid when the pressure drop ratio, PDR, is met as follows:

PDR = (P_inlet - P_reject)/

(P_inlet - P_outlet) >= 1.7

A 1.7 PDR is the optimum flow condition for this separation system. At a PDR above 1.7, the separation system will work at a reduced separation efficiency. Below 1.7, the system will not work properly.

Powered centrifuges

Fig. 4d [73773 bytes] shows a decision tree for selecting powered centrifuges as primary separation vessels.

Many different industries use powered centrifuges for separating solids from liquids. In the process, the stream enters a rapidly spinning separation basket where high centrifugal forces induce the fluids to separate into distinct layers.

If separating solids from liquids, the liquid product can be forced through a filter cloth. These systems are applicable to oil/water, oil/water/gas, or oil/water/gas/sand service. In these cases, each layer is drawn off with the help of level controllers.

In the past, high maintenance costs, relatively high capital cost, and little operating experience have eliminated centrifuge separation systems from being considered for primary separator in oil and gas operations. However, these systems offer several advantages over conventional separation systems, such as:

• Small footprint area

• Reduced weight

• Very short residence times (2-4 sec), which reduce the amount of hydrocarbons in the process

• Low water content in the outlet oil, normally less than 0.5%

• Low oil content in the outlet water, normally 30-35 ppm

• Elimination of demulsifiers (Savings on chemicals have been known to justify these units.)

• Insensitivity to movement.

A typical module, designed for 50,000 b/d incoming liquids (including water), has the following specifications:

• Three centrifuges, each operating 50% of the time with one assumed to be operating in a wash cycle

• Dimensions: about 13-ft wide by 26-ft long by 16-ft high

• Weight: 16 tons dry, 18 tons wet

• Water cut: 30-90%

• Gas volume fraction: 0-50%

• Oil in water outlet: <= 40 ppm

• Water in oil outlet: <= 0.5%.

Powered centrifuges have undergone onshore testing with a multiphase test-loop in Norway. Field trials are ongoing on the floating production vessel Petrojarl 1 operated by Golar Nor Offshore which is presently at the Blenheim field, U.K.

Also, this technology is being designed for subsea use for extracting water.

Copyright 1997 Oil & Gas Journal. All Rights Reserved.