An oil production plant is a facility which processes production fluids from oil wells in order to separate out key components and prepare them for export. Typical oil well production fluids are a mixture of oil, gas and produced water. An oil production plant is distinct from an oil depot, which does not have processing facilities.
Oil production plant may be associated with onshore or offshore oil fields.
Many permanent offshore installations have full oil production facilities.Magnus Process Flow Diagrams 1983; NW Hutton Process Flow Diagrams 1987; Shearwater Process Flow Diagrams 2005 Smaller platforms and subsea wells export production fluids to the nearest production facility, which may be on a nearby offshore processing installation or an onshore terminal. The produced oil may sometimes be stabilised (a form of distillation) which reduces vapour pressure and sweetens "sour" crude oil by removing hydrogen sulphide, thereby making the crude oil suitable for storage and transport. Offshore installations deliver oil and gas to onshore terminals which may further process the fluids prior to sale or delivery to oil refineries.
Onshore oil production The configuration of onshore oil production facilities depends on the size of the oil field. For simple fields comprising a single well or a few wells, an oil storage tank may be sufficient. The tank is emptied periodically by road tanker and transferred to an oil refinery. For larger production rates a rail tanker transfer facility may be appropriate. For larger fields a full three-phase processing facility is required. Three-phase separators separate the well fluids into its three constituent phases: oil, gas and produced water. Oil may be transferred by road or rail tanker or by pipeline to an oil refinery. Gas may be used on the site to run gas engines to produce electricity or can be piped to local users. Excess gas is burned in a ground flare. Produced water may be re-injected into the reservoir. Small fields can use portable integrated packages, like vapor-tight tanks.
See for example: Wytch Farm
Offshore oil processing options There is a wide variety of options for the processing of produced oil. These range from minimal offshore processing with all produced fluids sent to an onshore facility, to full offshore processing to make products to a specification suitable for sale or use with no further onshore processing. The decision on what facilities to provide depends on a number of factors:
the optimal size of the offshore installation whether an onshore terminal is required or available what export routes (pipelines, tankers) are available the project constraints in terms of cost, schedule, and resources the impact or implications for future projects
The Gulf of Mexico and the North Sea are two mature producing areas that have taken different approaches to the facilities provided. These are summarised in the following table:Adapted from Bothamley 2004 +Offshore oil installation characteristic – Gulf of Mexico and North SeaParameterGulf of Mexico continental shelfGulf of Mexico deepwaterNorth SeaOil processingOil production, barrels oil per day (BOPD)< 20,000 (<3,180 m3/day)50,000 – 250,000 (7,949 – 39,746 m3/day)50,000 – 250,000 (7,949 – 39,746 m3/day)Individual well flow rate, BOPD (m3/day)< 3,000
(<477 m3/day)10,000 – 35,000
(1,590 – 5,564 m3/day)10,000 – 25,000
(1,590 – 3,975 m3/day)Wellhead temperature °F (°C)90 – 110 (32 – 43 °C)110 – 200 (43 – 93 °C)150 – 230 (65 – 110 °C)Separation train(s)11–21 – 2Separation stage(s)4 – 53 – 51 – 3Export oil water content, % by volume< 1< 1< 2Export oil Reid Vapor pressure, psi< 11< 11< 150 (true vapor pressure)Export oil pressure, psi (bar)1,000 – 1,500 (69 – 103 bar)1,500 – 3,000 (103 – 207 bar)1,500 – 2,800 (103 – 193 bar)Gas processingGas rate, MMSCFD (million standard cubic feet per day)< 5050 – 40050 – 300Gas compressionReciprocating compressorsScrew, centrifugal compressorsCentrifugal compressorsGas dehydrationTri-ethylene glycol (TEG)TEG, enhanced regenerationTEG, enhanced regenerationExport gas water content, lb/MMSCF72 – 42 – 4Export gas pressure, psi (bar)1,000 – 1,200 (69 – 93 bar)1,500 – 3,000 (103 –207 bar)2,000 – 2,700 (138 – 186 bar)Support Facilities and utilitiesProcess heatingDirect fired, hot oilHot oilHot oilProcess coolingAir cooled heat exchangerAir cooled heat exchanger, water cooled heat exchangerSeawater, TEG/water cooling mediumProduced water treatmentSkim tank, induced gas flotation (IGF)Hydrocyclones, IGFHydrocyclones, degasserWater injectionOccasionalFrequentFrequent
Export options The export options for oil and gas and the deployment around the world are as follows:
Stabilised crude oil Reid Vapor Pressure RVP < 11 psi (0.76 bar) Basic Sediment & Water BS&W < 1% by volume) Gulf of Mexico, Canada East Coast, West Africa, Indonesia. Unstabilised wet crude True vapour pressure 150 psia (10.3 bara) BS&W 2% North Sea, Azerbaijan, Gulf of Suez, Trinidad.
Gas disposal may take one or more of the following routes: +Gas disposal routesDisposal routeGas processingLocation deploymentDehydrationHydrocarbon dewpointGulf of Mexico facilitiesNorth Sea facilitiesDeployed elsewherePipelineYesYesFewSomeIndonesiaPipelineYesNoMostMostMost areasPipelineNoNoFewFewGulf of Suez, TrinidadGas reinjectionYesYesFewSomeCanada East Coast, West AfricaFlaringNoNoFewFewSeveral isolated fields and FPSO production In the Central and Northern North Sea gas is delivered to St Fergus or Teesside terminals by a small number of large diameter (36 inch, 91.4 cm) gas pipelines. These operate at 1600 – 2500 psig (110 – 172 bar) in the dense phase i.e. above the critical pressure. Operation in the dense phase provides a number of advantages:
it is more efficient to transport gas at high pressure over long distances it eliminates the problem of multiphase flow it eliminates the need to treat gas by hydrocarbon dewpointing
These advantages are offset by the additional compression required and thicker walled, more expensive, pipelines are necessary.
Plant configuration A further consideration is the number of separation trains and the number of stages of separation. Trains of process facilities operate in parallel, and stages are operated in a sequential series. The number of trains depends on flowrates, the availability of plant, and the available plot area. Single trains are capable of handling 150,000 to 200,000 barrels of oil per day (23,847 – 31,797 m3/day). Vessel sizes can be up to diameter and up to long. Vessels on Gulf of Mexico deepwater installations are diameter and long.
The number of stages of separation depends on:
wellhead pressure the gas/oil ratio the vapor pressure specification of the crude oil export stream
First stage separators in the Gulf of Mexico typically operate at 1500 to 1800 psi (103.4 to 124.1 bar), they operate as 2-phase liquid and vapour separators with a liquid residence time of 1 to 2 minutes. Produced water is removed in the low pressure (LP) 3-phase separator. This operates at 150 –250 psi (10.3 – 17.2 bar).
In the North Sea first stage separators generally operate at < 750 psi (< 51.72 bar). These are operated as 3-phase (vapour, oil and water) separators and are sized to provide 3 – 5 minutes of liquid residence time. Pressures are set to maximise gas separation at as a high a pressure as possible. Up to 5 stages of separation are common in the Gulf of Mexico and up to 4 stages on platforms in the North Sea.
The throughput, number of trains, separation stages and first stage separator pressure for a range of historic offshore installations is shown in the table.Matthew Hall Engineering Offshore company publicity brochure, April 1991 +Processing plant on offshore installationsInstallationLocation°API GravityOil production, BOPDGas production, m3/dayInlet separator pressure, barNo. of trainsNo. of stagesBrent CNorth Sea38150,0008,500,0009.634Claymore ANorth Sea30180,0005.913Cormorant ANorth Sea3560,000900,0003013Statfjord ANorth Sea38300,0008,500,0006924MurchisonNorth Sea36164,0001,300,0004513BuchanNorth Sea33.570,000600,0001013MagnusNorth Sea39140,0002,500,0002822Brae ANorth Sea33/35, 41/45, 33100,000 + 12,000 NGL4,250,00024823Namorado ISouth America40,000640,00023Namorado IISouth America60,000420,000Cherne ISouth America50,000120,0001Bayan ASouth China Sea60,0002722Brae BNorth Sea33/35, 41/45, 3375,00011,300,00010314Ship ShoalGulf of Mexico12,0004,2509013Forties EchoNorth Sea3767,000300,000EiderNorth Sea3453,00014 – 29.311Seillean (Cyrus)North Sea3615,0006,000,0001712East BraeNorth Sea33/35, 41/45, 33120,00017,000,00010213GannetNorth Sea38/4356,0004,000,00018 – 7041NelsonNorth Sea40145,00091TiffanyNorth Sea33.6105,0003,250,0001712
Materials of construction A range of materials of construction are used for oil processing plant. Carbon steel is extensively used as it is inexpensive. However, it is unsuitable for corrosive service where a number of corrosion resistant alloys and other materials are required. The table illustrates typical materials for service on a plant that processes sour fluids.Marathon Brae B Materials of construction schematic dated 2000 System or plantMaterial of constructionFlowlines and manifolds (sweet service)Carbon steelFlowlines and manifolds (sour service)Alloy 825Flowlines and manifolds (high H2S)DuplexSeparators (sweet)Carbon steelSeparators (sour)Carbon steel clad with Alloy 825Condensate separatorsCarbon steelCondensate separators (sour high pressure)Carbon steel clad with 316 stainless steelCondensate separators (sour low pressure)316 stainless steelOil pumping and exportCarbon steelGas compressionCarbon steelGas compression piping (sour)316 stainless steelGas compression vessels (sour)Carbon steelDehydrated gasCarbon steelGas exportCarbon steelFlare and ventCarbon steelFlare (sour or cold service)316 stainless steelGas injectionCarbon steelSeawaterGRPSeawaterCuniferFirewaterGalvanised steelSeawater for heat exchangersTitaniumInjection waterCarbon steelDrainsCarbon steelFresh waterCopperAirCarbon steelCooling and heating mediaCarbon steelFuel gasCarbon steel
Process description
The oil train
The production plant can be considered to begin after the production wing valve on the oil well Christmas tree. The reservoir fluids from each well are piped through a flowline to a choke valve, which regulates the rate of flow and reduces the pressure of the fluids. The flowlines from each well are gathered together at one or more inlet manifolds. These are provided for each train or operate at different pressures to match the wellhead pressure with various separator pressures. High pressure manifolds are routed into a first stage separator, which separates the three fluid phases. Produced water, the densest phase, settles out at the bottom of the separator, oil floats on the top of the produced water phase, and gas occupies the upper part of the separator. The separator is sized to provide a liquid residence time of 3 to 5 minutes which is sufficient for light crude oil (>35° API) as produced in the North Sea. In the Gulf of Mexico the first stage separator operates as a 2-phase (gas and liquid) vessel, it is sized to provide a liquid residence time of 1 to 2 minutes.
Sand and other solids from the reservoir will tend to settle out in the bottom of the separators. If allowed to accumulate the solids reduce the volume available for oil/gas/water separation reducing efficiency. The vessel may be taken offline and drained down and the solids removed by digging out by hand. Or water sparge pipes in the base of the separator used to fluidize the sand which can be drained from the drain valves in the base.