Content – Energy distribution
Onshore oil and gas production is often economically viable in very small quatities from a few dozen barrels of oil a day and upward.
Oil and gas is produced from several million wells worldwide. Gas networks may become large, with production from thousands of wells, long distance apart, feeding through a gathering network into a processing plant.
The flexibility on how to produce onshore wells is large. For wells that do not freely flow by themselves sucker rod pumps (donkey pumps) together with simple holding tanks and tanker trucks (for transportation to a refinery) may be used.
Many onshore wells have a huge capacity producing thousands of barrels every day.
Through periods of high oil and gas prices, “unconvential” production of oil and gas plays a more significant role. This would include production of heavy oils, tar sand and shale oil and gas all requiring complex production processing methods (such as heating and heavy fracturing) compared to more traditional oil and gas resources.
Offshore oil and gas ecovery is carried out from a wide range of facilities including subsea (at the seabed) installations with pipeline connections running directly to shore terminals.
Some of the most common offshore structures used for oil and gas production are:
Gravity base platforms (Condeep) – These are typically concrete structures with storage capability in concrete storage cells permanently placed on the sea bottom. The platforms are resting on the sea bottom primarily due to gravity but also having skirts penetrating the sea bottom for increased stability. The gravity-based platforms are used at waterdepths between 100 metres – 350 metres.
Steel jacket platforms – These are steel truss structures resting on the sea bottom fixed by piles or suchtion anchors. The steel jacket platforms are used in a wide range of water depths spanning from a few metres to almost 500 metres.
Guyed and compliant tower platforms – These are slender steel truss structures supported by a spud can foundation and kept upright by steel wires or chains and or flotation elements. The wires or chains are held in place by weights and piles. The guyed tower or compliant tower platforms are used in water depths from shallow waters to more than 600 metres.
Jack up rig
A jackup rig is a mobile unit that operates as a fixed structure at location. It consists of a buoyant hull fitted with movable legs. At location the legs are lowered and penetrating or resting at the seabed such that the hull is raised above the sea surface. The hoisting system for the platform legs is normally of the rack and pinion type. The buoyant hull enables transportation between locations.
Floating production platforms are often the choice deep-water production where it is not possible to use fixed structures or for reservoirs with a short production profile such that the unit may be moved and used at another location. Floating production units have subsea wellheads and completions due to the movements of the units.
FPSO (Floating production, storage and offloading) – The term is normally used for ship shaped floating (with some exceptions such as the Sevan, barrel shaped unit) production units (often oil tankers converted into production and storage wessels).
Tension leg platform – A semisubmersible structure made of large vertical columns connected to large pontoons, thethered to the seafloor by vertical, pile secured tendons. The tendons are made from hollow high tensile strength steel pipes that maintain the structure in tension by the excess buoyancy of the platform. The tension leg platforms have limited vertical motion due to the tension loaded tendons. The tension leg platforms are used in water depths from shallow waters to more than 600 metres.
Semi-submersible platforms – A semisubmersible platform is a mobile structure made of large vertical columns connected to large pontoons, ballasted at location and moored by traditional mooring linesand anchors. For ultra deep waters, alternative mooring lines or mooring lines with buoyancy elements needs to be used due to the heavy weight of the mooring lines. This permits more lateral and vertical motion and is generally used with flexible risers and subsea wells. The semi submersible platforms are used in water depths from shallow waters to more than 1000 metres.
SPAR – The classic spar consists of a single vertical floating cylindrical hull, supporting a fixed deck. The cylinder is normally weighted at the bottom to lower the center of gravity of the platform and provide stability. Spars are permanently anchored to the seabed by way of a spread mooring system composed of either a chain-wire-chain or chain-polyester-chain configuration. There are three primary types of spars; the classic spar, truss spar, and cell spar. The spar platforms have storage capacity within the cylinder and are used both as production and storage units as well as only storage units.
The truss spar has a shorter vertical cylinder than a classic spar and has a truss structure connected to the bottom of the cylinder.
The cell spar, has a large central cylinder surrounded by smaller cylinders of various lengths. At the bottom of the longest cylinders is the ballasting material located.
The spar platforms are used in water depths from 300 metres to 1000 metres.
|Cell Spar||Truss Spar|
Subsea production systems – A subsea production systems is one or more wellheads located at the sea floor. If there is more than one well the wells are normally connected at a cenrtral location at the sea floor by one or more manifolds and if there are several wellheads at the same location they normally are placed within a wellhead template. Even if recent developments includes some subsea processing and handling equipment the most common configuration is that the oil and gas is transported by a pipeline and a riser to a fixed or mobile offshore platform for stabilization and processing to enable transportation to shore for refining and distribution. Subsea fields, pending on the composition and condition of the produced hydrocarbons, may be directly connected to a shore terminal if the distance (tie back distance) is not too far (current maximum around 250 km) or if subsea stabilization and processing is possible.
Subsea production systems allow one production platform to service many wells spread over a large area.
Subsea systems do not have the ability to drill, only to extract and transport and are used in water depths from 500 and more.
Subsea production systems are controlled from the surface through an umbilical providing power (hydraulic and electrical), transmitting communication signals, and in some cases providing chemicals.
Main production components
Wellhead and (christmas) tree – The wellhead is placed on top of the casing string with its primary purpose, providing suspension and pressure seals for the casing strings that run from the bottom of the hole sections to the surface pressure control equipment.
While drilling the pressure control is in addition to the hydrostatic head of the drilling fluids provided by a BOP (blowout preventer).
After completion of the well the surface pressure control is provided by the Christmas tree, installed on top of the wellhead, with isolation valves and choke equipment to control the flow of well fluids. The Christmas tree also allow for a number of operations relating to production and well workover. Well workover refers to various technologies for maintaining the well and improving its production capacity.
Onshore or on topside structures offshore where a wellhead is located on dry land or above the sea on a production platform, it is called a surface wellhead (or dry wellhead), if located at the seafloor it is referred to as a subsea wellhead.
Choke and production manifold – The choke valve is a device incorporating an orifice used to control the flow rate and downstream pressure. Chokes can be of the fixed or adjustable type or a mix of both.
Typically oil and gas producing wells may have two choke valves in series, one non-regulating choke valve and one regulating choke valve downstream to the non-regulating choke valve.
The production manifold is an arrangement of piping and valves used to gather, control, commingle and distribute fluid and gas flow from several wells into the test or 1st stage separator or gas threatment plant. Onshore fields will often have wells spread over a wide area where the well streams are gathered into the production maniforld and production facilities through a network of pipes. Similarily will subsea wells be tied togehetr by a subsea manifold and the well stream transported to the production manifold and production facilities through one or more subsea flow lines and risers.
Each well might be connected to ore than one production manifold enabling routing and commingling well streams based on their pressure and flow rates to the relevant separation stage.
Test manifold – The purpose of the test manifold is to be able to route the stream from individual or several wells into the test separator (used to analyse the well stream for quantiy and composition).
Injection manifold – The purpose of the injection manifold is to enable injection of substance into a production well or into an injection or disposal well.
Processing and treatment plant – An oil and gas production plant is a facility, which performs processing of production fluids and gases from the wells in order to separate out key components and prepare them for export including “drying” of wet gas.
Typical production fluids are a mixture of oil, gas and produced water. Most permanent offshore platforms or gathering of platforms (field centras) have full oil production facilities on board. Smaller wellhead platforms and subsea wells must normally export the raw production fluid or gas to the nearest production facility, which may be on a nearby offshore processing platform or an onshore terminal
Separation – The main purpose of the separation is to stabilize the well stream fro export by separating oil, gas and water including removal of any solids.
Separator – The gravity separator is the main component used to separate oil, gas and water. This is normally carried out in stages (2 – 3) by large horizontal vessels where gas will be realeased due to pressure reduction and taken out from the upper part, water and solids will settle and be drained from the bottom and the oil taken out in the mid section. A certain holding time is required (typically 5 minutes) for the water and solids to settle and the separator to function efficiently.
Test separator – The main purpose of the test separator is to separate the well flow from one or more wells to analyse the flow and composition of the well stream under various conditions. In some cases the test separator is also used for production. This might be production of fuel gas or for producing a well that deviates a lot in pressure from the other wells.
Production separators (1st stage) – An oil and gas separator typically consists of following main components.
- An inlet device for priliminary phase separation
- Slug catcher or baffles downstream the inlet component (reducing the effect of large gas bubbles and liquid plugs) to improve flow distribution
- Separation enhancement device located in the primary separation (gravity settling) section for major phase separation
- Mist extraction device located in gas space to further reduce liquid content in the bulk gas stream
- Coalescing plates
- Various weirs to control the liquid level or interface level
- Vortex breaker to prevent gas carryunder at outlet of liquid phase
- Liquid level/interface detection and control, etc.
- Gas, oil, water outlet
- Pressure relief devices
Production separators (2nd stage) – The second stage separator is similar to the 1st stage separator but the pressure and temperature will be lower (1 MPa and less that 100oC) such that it might also be fed from the low-pressure manifold, the water content will now normally be below 5%. Depending on the local conditions oil heaters may be installed prior to the 2nd stage separator.
Production separators (3rd stage) – The final separator is a two-phase separator or a flash drum. The pressure is now reduced to atmospheric pressure of around 100 kPa, so that the last heavy gas components can boil out. Furhter heating may be necessaryto obtaining proper separation.
Colescers – In addition to providing the separator vessels with coalesching plates mechanical or selctrostatic coalescers are used after the third stage separator for final removal of water. The water content can be reduced to below 0.1%.
Desalter – If the salt conetent (ie. sodium,calcium or magnesium chlorides) of the separated oil is too high an electrostatic desalter, placed between ne of the separation stages to reduce the salt content.
Sand cyclone – Most wellstreams contain amounts of water (“water cut”). The wtare needs to be cleaned before disposal or injection. First step after the separators would normally be to remove sand by the use of a sand cyclone which ses centrifugal forces to remove the sand.
Hydrocyclone – When have been removed from the produced water the hydrocyclone is used to further purify the water by remove oil droplets by the use of centrifugal forces.
Water degassing drum – The final stage of cleaning the water is to remove gas and any remaining oil. This is done by the use of a degassing drum. Dispersed gas slowly rises and pulls remaining oil droplets to the surface by flotation. The surface oil film is drained, and the produced water can be discharged to sea. Recovered oil in the water treatment system is typically recycled to the third stage separator.
Heat exhangers – When processing oil heat exhangers are often used to heat the oil to enable efficient separation. The produced gas either directly from the well (if it is a pure gas well) or from the separators needs to be cooled to enable compression (low temperature means less energy to compress). Heat exchangers come as plate heat exchangers as well as tube and shell heat exchangers.
Scrubbers – After cooling of the gas it is routed through the scrubber, which is used to remove any liquids from the gas. There are various types of crubbers available; the most common is the suction scrubber, which is based on dehydration by absorption in triethylene glycol (TEG). The suction scrubber consists of many gas traps forcing the gas through the layers of glycol, flowing from the bottom to the top. The glycol flow the opposite direction from to top to the bottom. The rich glycol (which have absorbed the liquid), is recycled by boiling out the glycol.
Gas compressors – In oil and gas production compressors of various types and different purposes are used. Examples are:
- Flash gas compressors
- Gas lift compressors
- Reinjection compressors
- Booster compressors
- Vapor-recovery compressors
- Casinghead compressors
Most gas compressors are driven by gas turbines or electrical motors and in some cases reciprocating engines or steam turbines if thermal energy is available. The main operating parameters for a compressor are the flow and pressure differentials.
Flash gas compressors – Flash gas compressors are used to compress gas that is released or “flashed” from a hydrocarbon liquid due to pressure drop (ie. during separation). The compressed gas may then be transferred to the gas treatment system and exported for sale, therby thye need for flaring the gas is avoided or reduced.
Gas lift compressors – Gas lift compressors are frequently used in oil handling facilities where compression of formation gases to be injected into the well stream for gas lift purposes to increase the flow for maintaining or enhanceing the production.
Reinjection compressors – Reinjections compressors are used when reinjection of natural gas into the reservoir is employed to enhance or to maintain oil production. Reinjection compressors also are used for underground storage of natural gas.
Booster compressors – Boosteer compressors are used to restore pressure when gas transmission through pipelines results in pressure drop due to friction losses. Booster compressors also are used in fields that are experiencing pressure decline.
Vapor recovery compressors – Vapor recovery compressors are used to gather gas from tanks and other low-pressure equipment in the plant. Often the gas from a vapor recovery compressor is routed to a flash gas, gas lift, or booster compressor for further compression.
Casinghead compressors – Casing head gas compressors are used to enhance the production from pumping oil wells by reducing the annulus pressure allowing gas and fluids to flow more easily into the well bore.
Often the compressor discharge is routed to either a booster or flash gas compressor or to a low-pressure gathering system. Like vapor recovery compressors.
Meeters – Fiscal metering is necessary to enable correct distribution of cost and income related to production and sales of oil and gas accurate metering is required. Often several parties (partners, authorities and customers) have interest in and are involved in the fiscal metering. The location of the metering system is often where a change in responsibility or title takes place.
Fiscal metering systems may be as simple as a dipstick and manual records but for larger and more complex plants sofisticated equipment ans analysing tools are being used. Typically: for oil and other liquids configurations of turbine meters or positive dissplacements meters in a combination wirth valves would be used to measure the flow. For gas hydrocarbon content, energy value, temperature and pressure would be masured by orifice or ultrasonic devices.