Oil production plant - Wikipedia - Recent changes [en]

{{Short description|Facility which processes production fluids from oil wells}}

{{Short description|Facility which processes production fluids from oil wells}}

An '''oil production plant''' is a facility which processes [[production fluid]]s from [[oil well]]s in order to separate out key components and prepare them for export. Typical oil well production fluids are a mixture of [[crude oil|oil]], [[natural gas|gas]] and [[produced water]]. An oil production plant is distinct from an [[oil depot]], which does not have processing facilities.

An '''oil production plant''' is a facility which processes [[production fluid]]s from [[oil well]]s in order to separate key components and prepare them for export. Typical oil well production fluids are a mixture of [[crude oil|oil]], [[natural gas|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.

Oil production plant may be associated with onshore or offshore oil fields.

{{See also|Separator (oil production)|l1='''Separator (oil production)'''}}

{{See also|Separator (oil production)|l1='''Separator (oil production)'''}}

The production plant can be considered to begin after the production wing valve on the [[oil well]] [[Christmas tree (oil well)|Christmas tree]]. The [[Petroleum reservoir|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.<ref name="Surface"/> 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 (oil production)|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.<ref name="endress">{{Cite web|url=https://www.apsc.endress.com/en/industry-expertise/oil-gas-marine/separation-process-oil-gas|title=Three phase separation|access-date=11 February 2019}}</ref> 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.

The production plant can be considered to begin after the production wing valve on the [[oil well]] [[Christmas tree (oil well)|Christmas tree]]. The [[Petroleum reservoir|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.<ref name="Surface"/> 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 (oil production)|separator]], which separates the three fluid phases. [[Produced water]], the densest phase, settles 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.<ref name="endress">{{Cite web|url=https://www.apsc.endress.com/en/industry-expertise/oil-gas-marine/separation-process-oil-gas|title=Three phase separation|access-date=11 February 2019}}</ref> 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.  

Sand and other solids from the reservoir will tend to settle 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 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.  

[[File:Well test separator.svg|thumb|Two stage oil separation train]]

[[File:Well test separator.svg|thumb|Two stage oil separation train]]

Oil from the first stage separator may be cooled or heated in a [[heat exchanger]] to aid further separation. North Sea fields tend to operate at higher temperatures so heating may not be required. Gulf of Mexico fields tend to operate at lower temperatures so heat is required to achieve export vapor and [[BS&W]] specifications. Typical operating temperatures are {{convert|140|–|160|F|C}}.<ref name="Offshore"/>

Oil from the first stage separator may be cooled or heated in a [[heat exchanger]] to aid further separation. North Sea fields tend to operate at higher temperatures so heating may not be required. Gulf of Mexico fields tend to operate at lower temperatures so heat is required to achieve export vapor and [[BS&W]] specifications. Typical operating temperatures are {{convert|140|–|160|F|C}}.<ref name="Offshore"/>

==== Hydrocarbon dewpointing ====

==== Hydrocarbon dewpointing ====

The export hydrocarbon [[Dew point|dew-point]] specification (typically 100 barg at 5&nbsp;°C<ref name="enquest">{{Cite web|title=Northern Leg Gas Pipeline specification|url=https://www.enquest.com/fileadmin/content/statements_reports_presentations_and_general_PDFs/Enquest/ICOP/NLGP2018.pdf|access-date=10 February 2019}}</ref>) may be met by chilling the gas to remove the higher alkanes ([[butane]], [[pentane]]s, etc.). This may be done by a [[Vapor-compression refrigeration|refrigeration]] system, or passing the gas through a [[Joule–Thomson effect|Joule-Thomson]] valve, or through a [[Turboexpander|turbo-expander]] to condense out and separate liquids. The [[Natural-gas condensate|natural gas liquids]] (NGL) produced may be spiked into the oil export fluids where high vapor pressure fluids are exported.<ref name=":0" /> Alternatively NGL fractionating columns may be used to produce a fluid for separate export. NGL fractionation columns are installed in Nkossa West Africa and Ardjuna Indonesia.<ref name="Offshore"/>

The export hydrocarbon [[Dew point|dew-point]] specification (typically 100 barg at 5&nbsp;°C<ref name="enquest">{{Cite web|title=Northern Leg Gas Pipeline specification|url=https://www.enquest.com/fileadmin/content/statements_reports_presentations_and_general_PDFs/Enquest/ICOP/NLGP2018.pdf|access-date=10 February 2019}}</ref>) may be met by chilling the gas to remove the higher alkanes ([[butane]], [[pentane]]s, etc.). This may be done by a [[Vapor-compression refrigeration|refrigeration]] system, or passing the gas through a [[Joule–Thomson effect|Joule-Thomson]] valve, or through a [[Turboexpander|turbo-expander]] to condense and separate liquids. The [[Natural-gas condensate|natural gas liquids]] (NGL) produced may be spiked into the oil export fluids where high vapor pressure fluids are exported.<ref name=":0" /> Alternatively NGL fractionating columns may be used to produce a fluid for separate export. NGL fractionation columns are installed in Nkossa West Africa and Ardjuna Indonesia.<ref name="Offshore"/>

==== Gas sweetening ====

==== Gas sweetening ====

'''Heating medium''' is generally heated by waste heat recovery from power generation gas turbine exhausts. The temperature required is generally not more than {{convert|400|°F|°C|abbr=on}} and mineral oil based fluids are used.<ref name="Offshore"/> Pressurised hot water, steam, and glycol/water mixtures are also used although temperatures are generally limited to < {{convert|300|°F|°C|abbr=on}}. On smaller installations electric heating elements may be the most appropriate option for heating fluids.<ref name="Offshore"/>

'''Heating medium''' is generally heated by waste heat recovery from power generation gas turbine exhausts. The temperature required is generally not more than {{convert|400|°F|°C|abbr=on}} and mineral oil based fluids are used.<ref name="Offshore"/> Pressurised hot water, steam, and glycol/water mixtures are also used although temperatures are generally limited to < {{convert|300|°F|°C|abbr=on}}. On smaller installations electric heating elements may be the most appropriate option for heating fluids.<ref name="Offshore"/>

'''Process cooling''' may be performed using air, seawater (known as direct cooling), or cooling medium comprising a 30% glycol (TEG)/water mixture and known as indirect cooling.<ref name="Offshore"/> North Sea installations are generally quite crowded and do not have space for the extensive plot area required for air cooled heat exchangers. Water cooled heat exchangers occupy a relatively small plot area. North Sea installations are often provided with [[Water injection (oil production)|water injection]] facilities. These require large volumes of seawater to be lifted. The incremental cost of using the seawater for cooling is therefore considerably reduced. Furthermore, the reduced solubility of air in warmed water is an advantage as air has to be stripped out of injection water. The cold North Sea water temperature reduces the size of heat exchangers. Indirect cooling medium cooling is less likely to have corrosion issues than direct seawater cooling which may require more expensive metals such as Copper alloys, [[Titanium]] or [[Inconel]]. Cooling medium systems have a lower [[Capital expenditure|CAPEX]]. The clean fluid allows printed circuit heat exchangers to be used which offer space and weight savings.<ref name="Offshore"/>

'''Process cooling''' may be performed using air, seawater (known as direct cooling), or cooling medium comprising a 30% glycol (TEG)/water mixture and known as indirect cooling.<ref name="Offshore"/> North Sea installations are generally quite crowded and do not have space for the extensive plot area required for air cooled heat exchangers. Water cooled heat exchangers occupy a relatively small plot area. North Sea installations are often provided with [[Water injection (oil production)|water injection]] facilities. These require large volumes of seawater to be lifted. The incremental cost of using the seawater for cooling is therefore considerably reduced. Furthermore, the reduced solubility of air in warmed water is an advantage as air has to be stripped of injection water. The cold North Sea water temperature reduces the size of heat exchangers. Indirect cooling medium cooling is less likely to have corrosion issues than direct seawater cooling which may require more expensive metals such as Copper alloys, [[Titanium]] or [[Inconel]]. Cooling medium systems have a lower [[Capital expenditure|CAPEX]]. The clean fluid allows printed circuit heat exchangers to be used which offer space and weight savings.<ref name="Offshore"/>

==See also==

==See also==