Crude Oil Processing on Offshore Facilities | Futurist Transhuman News Blog

1.0 PURPOSE

This design guide is prepared to provide basic information and consideration for the process design aspect of Crude Oil Processing for typical offshore facilities. This document provides an overview of separation of crude oil from well fluid for further processing.

This guide covers the overall summary of processing schemes, typical crude specification, and data to help developing a preliminary phase of design.

Specific requirements of Project / Client / Local regulations shall prevail over the contents of this guide.

API Gravity

API gravity is a measure of how heavy or light a petroleum liquid is compared to water. API gravity is defined by the following formula;

Asphaltenes

Asphaltenes are molecular substances in crude oil that are insoluble in low boiling hydrocarbon liquids such as heptane and are also non-distillable. These molecules are made up of aromatic clusters containing a polar heteroatom group. In large molecules the aromatic rings are interconnected by paraffinic groups and by sulphur

Cloud Point

Cloud point is the temperature at which dissolved solids are no longer completely soluble, precipitating as a second phase giving the fluid a cloudy appearance. In the petroleum industry, cloud point refers to the temperature below which wax in crude oil form a cloudy appearance. Cloud point is measured by ASTM D-2500 testing method.

Pour Point

Pour point is the temperature at which the crude oil becomes semi solid and ceases to flow. The pour point is measured by ASTM D-97 testing method.

Reid Vapour Pressure

Reid Vapour Pressure (RVP) is measured by ASTM D-323 testing method. The sample is placed in a chamber at a constant temperature of 100 oF. RVP is slightly lower than the True Vapour Pressure (TVP) at 100 oF.Stabilization

Crude stabilization is a process of removing volatile components from crude oil to reduce its vapour pressure.

BS&W : Basic Sediment & Water

FTHP : Flowing Tubing Head Pressure

GOR : Gas Oil Ratio

PTB : Pounds of salt per thousand barrels of oil

Ppm : Part per million

RVP : Reid Vapour PressureTEG : Triethylene GlycolTVP : True Vapour Pressure

The primary function of a production facility is to separate the product from the wells into saleable products and dispose of the rest in an environmentally friendly manner. The product from the wells typically consists of oil; gas; associated produced water and sediment. Figure 1 shows a typical schematic of oil and gas production.

Figure 1. Typical Oil and Gas Production Schematic

Well fluids enter a separation train where the crude oil, gas, and bulk water are separated. The separation train may consist of several stages of separators. In the separation train, most volatile components of the well fluid will be vaporized. Thus the crude oil will either be stabilized or partially stabilized. Crude stabilization is performed to achieve the specified RVP

After free water removal, produced oil may contain residual emulsified water. The crude oil is then further processed in a dehydration unit to reduce the water content to a value that acceptable for transportation or sales. Dilution water must occasionally be added to reduce the salt content of the residual emulsion to a suitably low level. The addition of dilution water and followed by dehydration is called desalting process.

Gas separated from the separation train enters the gas processing train. The train normally comprises of gas compression system and gas dehydration system. Gas dehydration unit is required to remove water from the gas stream to prevent hydrate and corrosion problem in the pipeline. The most common method for gas dehydration is a TEG contactor unit which is completed with a TEG regeneration system. The TEG (liquid) absorbs water from the gas stream to achieve the specified water content of the export gas.

Compression of the gas to pipeline pressure is normally required to allow economic transport in reasonable small diameter pipeline.

A more complex gas processing train may include gas sweetening system to remove the acid gases which are CO2 and H2S. Both gases are very corrosive when liquid water is present. Gas sweetening usually uses aqueous solution of various chemicals. Therefore a gas sweetening, if required, is normally placed upstream of dehydration unit. However, gas sweetening system is not common for offshore processing facilities. Generally, any sour gas produced from offshore will be further processed in onshore gas plant.

Separated water from the well fluids is directed to the produced water treatment unit to render the water suitable for disposal to the sea. Oil removal is the first treatment for produced water. Oil-water emulsions are difficult to clean up due to the small size of the particles, as well as the presence of emulsifying agents. Hydrocyclone is common equipment for produced water de-oiling purpose.

As an alternate of disposing water into the sea, the produced water could be re-injected into water injection wells. Before re-injection, produced water is usually filtered and treated with biocides. Booster pumps and injection pumps are normally installed for water injection system.This guideline discusses the treatment of the crude oil to meet the product specifications such as vapor pressure, base sediment and water, salt content, and H2S concentration.

Crude oils vary widely in composition and physical properties. Some are almost gas-like materials of 65o API gravity, whereas others are semisolid asphaltic material with API gravities of less than 10o. Light crude are generally more valuable to refineries and are easier to handle than heavy crudes. Heavy crudes are more difficult to produce and sell.

Offshore crude oil product may be stored on the platform in large tanks (i.e. FPSO, FSO) and exported by a tanker, or exported through a pipeline. Typical specifications of crude oil are as follow:

A low vapor pressure is important for stability of the crude during storage and transport, especially if the crude is transported via tanker. A high vapor pressure results in loss of volatile components in storage tanks or tankers. Gases evolved from unstable crude are heavier than air and difficult to disperse. Consequently the risk of explosion is greater. To prevent the release of gas during transport or storage, the vapor pressure specification is usually from 10 to 12 psia RVP.

For pipeline export, the crude oil is sometimes partially stabilized. The true vapor pressure (TVP) of the crude is typically 6.9 Bara at 38 C. This value is considered to retain a large part of C3-C4 components in the liquid stream. The crude oil will be further stabilized at onshore terminal facilities and the C3-C4 can be converted into LPG product. The TVP will be set in conjunction with the operating parameters of the pipelines and must be lower than the proposed arrival pressure at the delivery location. The crude oil must be pumped to ensure pipeline is liquid phase throughout.

The presence of water in the crude oil must be limited for the following reasons;

Shipping emulsified oil wastes costly transportation capacities occupied by water

Mineral salts present in produced water corrode equipment, pipeline, and storage tanks.

Dissolved sediments in water can cause plugging and scaling problems to heat exchangers and column trays in the refinery.

In the Gulf of Mexico, 1% BS & W typically meets offshore crude sales specifications. Other parts of the world require crudes with less than 0.5% water by volume, especially if the crude is loaded offshore to tankers.

Salts can cause severe corrosion in tankers, pipeline, and refining equipment. Salts cake out inside equipment, cause poor flow and plugging, reduce heat transfer rates in exchangers. Under some circumstances chlorides can hydrolyze to HCL, which is extremely corrosive. In addition, some mineral salts can poison expensive catalysts. Therefore the salt concentration in the crude oil must be limited. The salt content in the crude product is typically specified at 10 30 PTB

H2S is removed from crude oil together with flash gas at each separation stage. 50 ppm by volume can normally be achieved using simple separators and heating. Though normally not used in offshore facilities, 20 ppm and lower can normally only be achieved by the use of a re-boiled stripper.

Well fluids are complex mixtures of different compounds of carbon and hydrogen with different densities, vapor pressure and physical characteristics. As the well fluids travel from the reservoir to the production facility, it experiences pressure and temperature reduction. The characteristics of the well stream continuously changes with the evolving gas from the liquid as the pressure reduces. The separation of these phases is one of the basic operations in production, processing and treatment.

The oil production system begins at the wellhead, which includes at the least one choke valve, whose percentage opening determines the flowrate from the wells. Most of the pressure drop between the well flowing tubing head pressure (FTHP) and the separator operating pressure occur across the choke valve.Whenever two or more wells are installed on a wellhead platform, a production manifold as well as test manifold should be installed to gather fluid from the wells prior to be processed in separator or exported via pipeline. The test manifold is provided to allow an individual well to be tested either via a Test Separator or Multiphase Flowmeter (MPFM).

As described earlier, the well-stream may consist of crude oil, gas, condensates, water and various contaminants. The purpose of a separator is to split the flow into desirable fractions. Primary separation of produced water from gas and oil is carried out in production separator. Separators work on the principle of gravity separation.

Following type of separators are generally used in the industry:

A two phase separator is used to separate well fluids into gas and liquid mixtures.

This type of separator is used when the expected outlet streams are gas, oil / condensate, and water.

Figure 2. Typical Three Phase Separator with Internals

A separator can be either horizontal or vertical configuration,

Horizontal separator is preferred for low GOR well fluids and three phase separation.

Table below shows the advantages and disadvantages of horizontal separators:

Advantages

Disadvantages

Provide sufficient residence time for liquid-liquid separation

Only part of shell available for passage of gas

Large liquid surface area for foam dispersion generally reduces turbulence

Larger foot print / plot area

Large surge volume capacity

Liquid level control is more critical

Lend themselves to skid mounting and shipping

More difficult to clean produced sand, mud, wax, paraffin. etc.

Vertical separator is preferred high GOR well fluids and two phase separation

Table below shows the advantages and disadvantages of vertical separators:

Advantages

Disadvantages

Have full diameter for gas flow at top and oil flow at bottom

Not suitable for bulk liquid-liquid separation

Occupy smaller plot area

Occupy more vertical spacing between decks in offshore

Liquid level control is not so critical

More difficult to skid mount and ship

Have good bottom drain and clean out facilities. Can handle more sand, mud, paraffin, wax, etc.

More difficult to reach and service top-mounted instruments and safety devices

Production separators of all types are sized according to the following parameters, to suit product specifications:

Fluid flow rates

Operating Pressure and Temperature

Oil in Water Specification (500-1000 ppm)

Water in Oil Specification (1-3% vol)

Liquid losses to vapor stream (subject to demister type)

Liquid droplet size in gas outlet (150 microns and larger droplets can be removed when internals are not used)

In an oil system, separators are generally sized on the basis of liquid residence time. Particular attention must be given to foam and emulsion forming tendency of the crude oil. Data can be obtained from laboratory analysis or from previous experience. The tendency of crude oil to foam will require

larger separator in order to maintain satisfactory vapor/liquid separation efficiency,

chemical injection,

specialist internals e.g. foam breaker.

Separation between water and oil is subject to the quality of emulsion and the terminal velocity of droplets as given by Stokes Law. Crude oil with high viscosity and density (i.e Heavy Oil), will result in a very low droplet settling velocity and hence will require more residence time and consequently a large vessel size. Where emulsions are formed, de-emulsifying chemicals and heating may facilitate the water removal, although the provision of a separate two phase (oil/water) separator may be required in severe cases.

At the design stage of crude oil separation train, an increased water production should be considered. Separators must be sized for the worst operating case, or alternatively, adjustments may be made to existing separator internals and level control set points in order to change the hold-up times of the two phases.For sizing criteria and calculation of a separator, refer to the company developed guideline and validated spreadsheets.

Dissolved gas in the crude oil must be removed to meet pipeline, storage, or tanker RVP specification. The presence of most volatile hydrocarbons increases the RVP. Removal of the dissolved natural gas components is called oil stabilization.

Crude oil can be stabilized by passing it through multiple separators in series where the volatile components will vaporize. A stabilization column might replace the simple flash-separation stages to achieve the required RVP, but these columns are rarely found offshore.

Stabilization of the crude oil often requires heat to be added or removed at certain points in the processing train. Crude heating may be required for:

Particular attention should be given for high temperature well stream fluids, it may be necessary to cool the crude in order to avoid excessive vaporization resulting in lower than required RVP of the final product specification and loss of potential liquid product.

For crude oils containing wax, care must be taken in assessing skin temperature inside coolers so that wax deposition is avoided. Skin temperatures should be at least 5oC above the crude oil cloud point. When the cooling water supply temperature is below this temperature, a cooling water recycle can be incorporated to raise the cooling water inlet to the required temperature. When the minimum cooling water temperature is marginal for wax deposition, wax inhibitor injection may be considered instead of a cooling water recycle system.

Number of Separation Stage

The well fluid pressure is often reduced in several stages of separation. If the reservoir conditions are such that the reservoir fluid can flow adequately against a wellhead pressure, separation in more than one stage will generally offer an economic advantage. The purpose of multi stage separation is to achieve maximum hydrocarbon liquid recovery, to get the liquid stabilized, and minimize compression power required for the gas stream. Multi stage separation of oil and gas involves a series of separators operating at sequentially reduced pressures, with liquid flowing from first separator to the next lower pressure separator.

When hydrocarbon liquids are removed from separator at equilibrium, the liquid is at its bubble point. With each subsequent pressure reduction, additional vapors are liberated. If the liquids were removed directly from a high pressure separator into a stock tank, the resulting vaporization would cause the loss of some heavier ends. Making pressure reductions in several stages can help reducing these losses. Therefore, increasing number of separation stages can increase the volume of oil recovered in the stock tank.

If the produced gas is to be gathered and compressed to sales transmission pressure, the allowable compression ratios and compression power requirements will usually determine the pressure ratios between the various stages of separation. Therefore, the process engineer must evaluate the number of separation stages, compression requirements, and economics of each specific installation.

A process simulation program such as HYSYS is generally used to design and optimize a crude oil processing system to meet a given crude specification, usually vapour pressure (either TVP or RVP). Selection of a system is based on maximizing the crude output whilst minimizing energy requirement (i.e. heating/cooling loads, compression power, etc.). Equipment size and weight is also a critical criterion.

The off gas from each separation stage can be compressed and treated for use as fuel gas, exported, or flared if quantities are minimal and applicable regulations permit flaring. In designing the oil processing system the gas compression requirements influence the total energy input. Additionally the recycle of hydrocarbon condensate from the gas compression system must be included as this will influence the performance of the system.

The optimum number of separation stages varies with Flowing Wellhead Pressure (FWHP), reservoir composition, off-gas compression requirement, and export specification for crude vapor pressure. A quick assessment of separation stages number based on FWHP is given in the table below:

FWHP, Bara