Oil and Gas Production Basics (Part 2)



This article describes the typical process that takes the product from the wellhead manifolds and delivers stabilized marketable products, in the form of crude oil, condensates or gas. Components of the process also exist to test products and clean waste products such as produced water.

Manifolds & Gathering

Some facility uses subsea production wells. The typical high pressure (HP) wellhead, with its Christmas tree and choke, is located on the sea bed. A production riser (offshore) or gathering line (onshore) brings the well flow into the manifolds. As the reservoir is produced, wells may fall in pressure and become low pressure (LP) wells.


Short pipeline distances are not a problem, but longer distances may cause a multiphase well flow to separate and form severe slugs of liquid with gas in between traveling in the pipeline. Severe slugging may upset the separation process and cause overpressure safety shutdowns. Slugging may also occur in the well as described earlier. Slugging can be controlled manually by adjusting the choke, or by automatic slug controls. Additionally, areas of heavy condensate may form in the pipelines. At high pressure, these plugs may freeze at normal sea temperature, e.g., if production is shut down or with long offsets. This can be prevented by injecting ethylene glycol.



Production Separators

The combined well fluids are fed to the Production Separators where the primary gas separation is performed. SeparaSeparatortors are mostly gravity type which utilizes horizontal vessels to maximize residence time. The retention period to allow proper separation varies based on the computational fluid dynamics (CFD) calculated by process engineers. It is optimized to meet the requirements of oil content in the water outlet and the gas stream as per client’s specification.


Separators has a lot of internals designed to achieve the design output. Such internals includes, but not limited to, slug catchers, weir plates, anti-motion baffles, demisters, vortex breakers, cyclonic device and many more. Stages of separation depends on various considerations, and can be based on economic and technical justifications.


Since it separates oil, gas and water, it is mostly called a three-phase separator. A typical illustration is provided above for your reference.


Once the fluids enter the sepaSeparator2rators, it hits the baffle slug catcher located at the inlet to reduce the effect of slugs (large gas bubbles or liquid plugs). Upon entering the separator, a retention time is calculated to allow gas to bubble out at the top, and the water to settle below the oil. Gas then passes thru a demister to prevent liquid particles coming out and ensure that the gas stream meets the requirement. This is further treated and compressed.


The crude oil coming out undergoes some more processes before it gets stored for further downstream treatment. If the separated oil contains unacceptable salts and water content, these are then removed by electrostatic desalter and coalescer. The coalescer and desalter units act as the final stage of stabilisation for the crude.


The incoming crude oil stream enters the bottom of these coalescer vessels, flows through a riser pipe, and then enters the distributors. The coalescer is completely filled with liquid: water at the bottom and oil on top. Internal electrodes form an electric field to break surface bonds between conductive water and isolating oil in an oil-water emulsion. When crude oil enters the two electrical fields, the electrical charges in each water droplet are separated. That is, the negative charges concentrate to one end of the droplet and the positive charges to the other end. Each droplet becomes an induced dipole a particle carrying two equal but opposite electrical charges, electrical poles. Since the electrical charges on each droplet are separated, the negative poles of droplets are attracted to the positive poles of other droplets. Almost immediately after the crude oil enters the electrical field the water droplets begin to combine, or coalesce as opposite electrical charges attract on another.


The coalescing action created by the attraction of the water droplets to one another creates larger and larger droplets, until finally, water droplets are large enough to fall out of the crude by force of gravity. Large droplets fall through the crude oil and into the bottom of the coalescer vessel and exits  through an effluent water disposal line.


Treated oil gets collected through a collector pipe near the top of the vessel.


Water Treatment

Normally, water produced from the process is quite huge. These must be treated and cleaned before discharge to sea or re-injected to the injection wells. Often, this water still contains small portions of oils which needs to be lowered to meet acceptable environmental regulations and sand particles bound to the oil/water emulsion.


A typical water treatment system consists of hydrocyclones, filters and storage tanks or degassing drums.


Produced water enters the hydrocyclone, a centrifugal separator that removes oil drops. The hydrocyclone creates a standing vortex where oil collects in the middle and water is forced to the side.


Media Filters are designed for oily water / suspended solids filtration. As the produced water passes through the media bed, oil and solids are efficiently retained in the bed, and can then be easily backwashed out of the media bed with the use of an internal or external fluidising media scrubbing system.


Treated Water Tank are sometimes injected with chemicals like Oxygen Scavenger at the inlet and Biocide at the outlet recommended to reduce the risk of corrosion in the water injection equipment and for the reduction of microbial growth leading to souring of the wells.


Gas Treatment and Compression

The gases collected have several purposes. Some are utilized for onboard power generation, some are used for gas reinjection and some is exported.


Gas compression is required for raising the pressure of the gas to a suitable pressure for re-injection back into the reservoir. However, these has to be treated and dehydrated to remove liquids before going into the compressor. The separated gas may contain mist and other liquid droplets. If liquid droplet enter the compressor, they will erode the fast rotating blades. A scrubber is designed to remove small fractions of liquid from the gas.

There are various types of gas-drying equipment available, but the most common suction (compressor) scrubber is based on dehydration by absorption in triethylene glycol (TEG). Glycol dehydration is used to remove water from the gas stream to achieve an outlet water content acceptable to specification. This is accomplished by absorption of the water vapour by a glycol stream.


The feed gas flows first into the inlet gas filter, then into the contactor tower which incorporates structured packing and a mist eliminator. The lean TEG flows in from the top of the column and contacts in a counter-current manner with the feed gas, absorbing the water from the rising natural gas to the desired level. The dried gas then flows to the top of the contactor tower where it passes through mist eliminators where any entrained glycol is dropped off.




The water-rich glycol exits at the bottom of the tower then goes to a TEG regeneration skid where it is pre-heated using reflux condenser and glycol / glycol heat exchanger before entering the Flash Drum where free water and associated gas is separated. It is then further treated to remove water and achieve a TEG purity of about 99.5% before pumping it back again to the contactor tower.



Metering, Storage and Export

Fiscal Metering

The final stage before the oil and gas leaves the platform consists of storage, pumps and pipeline terminal equipment.


Partners, authorities and customers all calculate invoices, taxes and payments based on the actual product shipped out. Often, custody transfer also takes place at this point, which means transfer of responsibility or title from the producer to a customer, shuttle tanker operator or pipeline operator.


For liquid metering, turbine meters with dual pulse outputs are most common. The instruments and actuators are monitored and controlled by a flow computer. If the interface is not digital, dual pulse trains are used to allow direction sensing and fault finding.


To obtain the required accuracy, the meters are calibrated. The most common method is a prover loop. A prover ball moves though the loop, and a calibrated volume is provided between the two detectors. When a meter is to be calibrated, the four-way valve opens to allow oil to flow behind the ball. See below video.



Gas metering is similar, but instead, analyzers will measure hydrocarbon content and energy value as well as pressure and temperature. The meters are normally orifice meters or ultrasonic meters. The pressure differential over the orifice plate as well as pressure and temperature, is used in standard formulas to calculate normalized flow. Different ranges are accommodated with different size restrictions.


The term ultrasonic in this context refers to the production of mechanical vibrations, resulting from electrical energy, operating at frequencies in the range 10 kHz to 100 kHz. Ultrasonic processing involves the use of an ultrasonic energy field to generate cavitation effects in liquids. Cavitation manifests itself by the appearance of micro-bubbles within the liquid. The cavitational processes produced by the ultrasonic field are affected by many factors such as the field frequency, liquid tensile strength, liquid purity, pressure and temperature. These allow the cavitation process to be controlled, and so the process can be “optimised” when used as a processing technology.


Gas metering is less accurate than liquid, typically ±1.0% of mass. There is usually no prover loop, the instruments and orifice plates are calibrated in separate equipment instead.



On most production sites, oil and gas are piped directly to a refinery or tanker terminal. On platforms without a pipeline, oil is stored in onboard storage tanks to be transported by shuttle tanker. On some floaters, a separate storage tanker is used. For onshore, fixed roof tanks are used for crude, floating roof for condensate.

The next part will be about Midstream Process Section, please stay tuned.


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