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Three-Phase Oil–Water–Gas Separators

in general, to the separation of any gas–liquid system such as gas–oil, gas–water, and gas–condensate systems. In almost all production operations, however, the produced fluid stream consists of
three phases: oil, water, and gas.
Generally, water produced with the oil exists partly as free water and partly as water-in-oil emulsion. In some cases, however, when the water– oil ratio is very high, oil-in-water rather than water-in-oil emulsion will form. Free water produced with the oil is defined as the water that will settle and separate from the oil by gravity. To separate the emulsified water, however, heat treatment, chemical treatment, electrostatic treatment, or a combination of these treatments would be necessary in addition to gravity settling.Therefore, it is advantageous to first separate the free water from the oil to minimize the treatment costs of the emulsion.
Along with the water and oil, gas will always be present and, therefore, must be separated from the liquid. The volume of gas depends largely on the producing and separation conditions. When the volume of gas is relatively small compared to the volume of liquid, the method used to separate free water, oil and gas is called a free-water knockout. In such a case, the separation of the water from oil will govern the design of the vessel. When there is a large volume of gas to be separated from the liquid (oil and water), the vessel is called a three-phase separator and either the gas capacity requirements or the water–oil separation constraints may govern the vessel design. Free-water knockout and three-phase separators are basically similar in shape and components. Further, the same design
concepts and procedures are used for both types of vessel.

read also Gas - Oil Separators

Three-phase separators may be either horizontal or vertical pressure vessels similar to the two-phase separators However, three-phase separators will have additional control devices and may have additional internal components. In the following sections, the two types of separator (horizontal and vertical) are described and the basic design equations are developed.

Horizontal Three Phase Separators
Horizontal-Three-Phase-Separators

Three-phase separators differ from two-phase separators in that the liquid collection section of the three-phase separator handles two immiscible liquids (oil and water) rather than one. This section should, therefore, be
designed to separate the two liquids, provide means for controlling the level of each liquid, and provide separate outlets for each liquid. figure above show schematics of two common types of horizontal three-phase separators. The difference between the two types is mainly in the method of controlling the levels of the oil and water phases. An interface controller and a weir provide the control. The design of the second type , normally known as the bucket and weir design, eliminates the need for an interface controller.
The operation of the separator is, in general, similar to that of the two-phase separator. The produced fluid stream, coming either directly from the producing wells or from a free-water knockout vessel, enters the separator and hits the inlet diverter, where the initial bulk separation of the gas and liquid takes place due to the change in momentum and difference in fluid densities. The gas flows horizontally through the gravity settling section (the top part of the separator) where the entrained liquid droplets, down to a certain minimum size (normally 100 mm), are separated
by gravity. The gas then flows through the mist extractor, where smaller entrained liquid droplets are separated, and out of the separator through the pressure control valve, which controls the operating pressure of the
separator and maintains it at a constant value. The bulk of liquid, separated at the inlet diverter, flows downward, normally through a downcomer that directs the flow below the oil–water interface. The flow of the liquid through the water layer, called water washing, helps in the coalescence and separation of the water droplets suspended in the continuous oil phase. The liquid collection section should have sufficient volume to allow enough time for the separation of the oil and emulsion from the water. The oil and emulsion layer forming on top of the water is
called the oil pad. The weir controls the level of the oil pad and an interface controller controls the level of the water and operates the water outlet valve. The oil and emulsion flow over the weir and collect in a separate compartment, where its level is controlled by a level controller that operates the oil outlet valve.
The relative volumes occupied by the gas and liquid within the separator depend on the relative volumes of gas and liquid produced. It is a common practice, however, to assume that each of the two phases occupies 50% of the separator volume. In such cases, however, where the produced volume of one phase is much smaller or much larger than the other phase, the volume of the separator should be split accordingly between the phases. For example, if the gas–liquid ratio is relatively low, we may design the separator such that the liquid occupies 75% of the separator volume and the gas occupies the remaining 25% of the volume. The operation of the other type of horizontal separator differs only in the method of controlling the levels of the fluids. The oil and emulsion flow over the oil weir into the oil bucket, where its level is controlled by a simple level controller that operates the oil outlet valve.

read also Two-Phase Gas - Oil Separation

The water flows through the space below the oil bucket, then over the water weir into the water collection section, where its level is controlled by a level controller that operates the water outlet valve. The level of the liquid in the separator, normally at the center, is controlled by the height of the oil weir. The thickness of the oil pad must be sufficient to provide adequate oil retention time. This is controlled by the height of the water weir relative to that of the oil weir.

Vertical Three-Phase Separators 

3 phase vertical separatorthe horizontal separators are normally preferred over vertical separators due to the flow geometry that promotes
phase separation. However, in certain applications, the engineer may be forced to select a vertical separator instead of a horizontal separator despite the process-related advantages of the later. An example of such applications is found in offshore operations, where the space limitations on the production platform may necessitate the use of a vertical separator.
The produced fluid stream enters the separator from the side and hits the inlet diverter, where the bulk separation of the gas from the liquid takes place. The gas flows upward through the gravity settling sections which are designed to allow separation of liquid droplets down to a certain minimum size (normally 100 mm) from the gas. The gas then flows through the mist extractor, where the smaller liquid droplets are removed. The gas leaves the separator at the top through a pressure control valve that controls the separator pressure and maintains it at a constant value.
The liquid flows downward through a downcomer and a flow spreader that is located at the oil–water interface. As the liquid comes out of the spreader, the oil rises to the oil pad and the water droplets entrapped in the oil settle down and flow, countercurrent to the rising oil phase, to collect in the water collection section at the bottom of the
separator. The oil flows over a weir into an oil chamber and out of the separator through the oil outlet valve. A level controller controls the oil level in the chamber and operates the oil outlet valve. Similarly, the water out of the spreader flows downward into the water collection section, whereas the oil droplets entrapped in the water rise, countercurrent to the water flow, into the oil pad. An interface controller that operates the water outlet valve controls the water level.

The use of the oil weir and chamber in this design provides good separation of water from oil, as the oil has to rise to the full height of the weir before leaving the separator. The oil chamber, however, presents some problems. First, it takes up space and reduces the separator volume needed for the retention times of oil and water. It also provides a place for sediments and solids to collect, which creates cleaning problems and may hinder the flow of oil out
of the vessel. In addition, it adds to the cost of the separator.Liquid–liquid interface controllers will function effectively as long as there is an appreciable difference between the densities of the two liquids.

In most three-phase separator applications, water–oil emulsion forms and a water–emulsion interface will be present in the separator instead of a water–oil interface. The density of the emulsion is higher than that of the
oil and may be too close to that of the water. Therefore, the smaller density difference at the water–emulsion interface will adversely affect the operation of the interface controller. The presence of emulsion in the separator takes up space that otherwise would be available for the oil and/or the water. This reduces the retention time of the oil and/or water and, thus results in a less efficient oil–water separation. In most operations where the presence of emulsion is problematic, chemicals known as deemulsifying agents are injected into the fluid stream to mix with the
liquid phase. Another method that is also used for the same purpose is the addition of heat to the liquid within the separator. In both cases, however, the economics of the operations have to be weighted against the technical constraints.

Separation Theory 
in general, valid for three-phase separators. In particular, the equations developed for separation of liquid
droplets from the gas phase, which determined the gas capacity constraint, are exactly the same for three-phase separators.
Treatment of the liquid phase for three-phase separators is, however, different from that used for two-phase separators. The liquid retention time constraint was the only criterion used for determining the liquid capacity of two-phase separators. For three-phase separators, however, the settling and separation of the oil droplets from water and of the water droplets from oil must be considered in addition to the retention time constraint. Further, the retention time for both water and oil, which might be different, must also be considered.
In separating oil droplets from water, or water droplets from oil, a relative motion exists between the droplet and the surrounding continuous phase. An oil droplet, being smaller in density than the water, tends to move vertically upward under the gravitational or buoyant force, that the droplet settling velocity is inversely proportional to the viscosity of the continuous phase. Oil viscosity is several magnitudes higher than the water viscosity. Therefore,
the settling velocity of water droplets in oil is much smaller than the settling velocity of oil droplets in water. The time needed for a droplet to settle out of one continuous phase and reach the interface between the two phases depends on the settling velocity and the distance traveled by the droplet. In operations where the thickness of the oil pad is larger than the thickness of the water layer, water droplets would travel a longer distance to reach the water–oil interface than that traveled by the oil droplets. This, combined with the much slower settling velocity of the water droplets, makes the time needed for separation of water from oil longer than the time needed for separation of oil from water. Even in operations with a very high water–oil ratio, which might result in having
a water layer that is thicker than the oil pad, the ratio of the thickness of the water layer to that of the oil pad would not offset the effect of viscosity. Therefore, the separation of water droplets from the continuous oil phase would always be taken as the design criterion for three-phase separators.
The minimum size of the water droplet that must be removed from the oil and the minimum size of the oil droplet that must be removed from the water to achieve a certain oil and water quality at the separator exit depend largely on the operating conditions and fluid properties. Results obtained from laboratory tests conducted under simulated field conditions provide the best data for design. The next best source of data could be obtained from nearby fields. If such data are not available, the minimum water droplet size to be removed from the oil is taken as 500 mm.
Separators design with this criterion have produced oil and emulsion containing between 5% and 10% water. Such produced oil and emulsion could be treated easily in the oil dehydration facility.

Retention Time

Another important aspect of separator design is the retention time, which determines the required liquid volumes within the separator. The oil phase needs to be retained within the separator for a period of time that is sufficient for the oil to reach equilibrium and liberates the dissolved gas.
The retention time should also be sufficient for appreciable coalescence of the water droplets suspended in the oil to promote effective settling and separation. Similarly, the water phase needs to be retained within the separator for a period of time that is sufficient for coalescence of the suspended oil droplets. The retention times for oil and water are best determined from laboratory tests; they usually range from 3 to 30 min, based on operating conditions and fluid properties. If such laboratory data are not available, it is a common practice to use a retention time of 10 min
for both oil and water.

References:
1. Oil and gas Production Handbook.
2. Oil and Gas Field Processing – King Fahd University of Petroleum and Minerals.

Gas–Oil Separators part. 2

Inlet Diverters
Inlet diverters are used to cause the initial bulk separation of liquid and gas. The most common type is the baffle plate diverter, which could be in the shape of a flat plate, a spherical dish, or a cone. Another type, is the
centrifugal diverter; it is more efficient but more expensive. The diverter provides a means to cause a sudden and rapid change of momentum (velocity and direction) of the entering fluid stream. This, along with the difference in densities of the liquid and gas, causes fluids separation.

Inlet Divertor

Wave Breakers
In long horizontal separators, waves may develop at the gas–liquid interface. This creates unsteady fluctuations in the liquid level and would negatively affect the performance of the liquid level controller. To avoid this, wave breakers, which consist of vertical baffles installed perpendicular to the flow direction, are used.

Defoaming Plates
Depending on the type of oil and presence of impurities, foam may form at the gas–liquid interface. This results in the following serious operational problems:
1. Foam will occupy a large space in the separator that otherwise would be available for the separation process; therefore, the separator efficiency will be reduced unless the separator is oversized to allow for the presence of foam.
2. The foam, having a density between that of the liquid and gas, will disrupt the operation of the level controller.
3. If the volume of the foam grows, it will be entrained in the gas and liquid streams exiting the separator; thus, the separation process will be ineffective. The entrainment of liquid with the exiting gas is known as liquid carryover. Liquid carryover could also occur as a result of a normally high liquid level, a plugged liquid outlet, or an undersized separator with regard to liquid capacity. The entrainment of gas in the exiting liquid is known as gas blowby. This could also occur as a result of a normally low liquid level, an undersized separator with regard to gas capacity,
or formation of a vortex at the liquid outlet.
Foaming problems may be effectively alleviated by the installation of defoaming plates within the separator. Defoaming plates are basically a series of inclined closely spaced parallel plates. The flow of the foam through such plates results in the coalescence of bubbles and separation of the liquid from the gas.
In some situations, special chemicals known as foam depressants may be added to the fluid mixture to solve foaming problems. The cost of such chemicals could, however, become prohibitive when handling high production rates.

Separator

Vortex Breaker
A vortex breaker, similar in shape to those used in bathroom sink drains, is normally installed on the liquid outlet to prevent formation of a vortex when the liquid outlet valve is open. The formation of a vortex at the liquid outlet may result in withdrawal and entrainment of gas with the exiting liquid (gas blowby).

Sand Jets and Drains
As explained previously , formation sand may be produced with the fluids. Some of this sand will settle and accumulate at the bottom of the separator. This takes up separator volume and disrupts the efficiency of
separation. In such cases, vertical separators will be preferred over horizontal separators. However, when horizontal separators are needed, the separator should be equipped with sand jets and drains along the bottom of the separator. Normally, produced water is injected though the jets to fluidize the accumulated sand, which is then removed through the drains.

Design Principles and Sizing of Gas–Oil Separators
In this section, some basic assumptions and fundamentals used in sizing gas–oil separators are presented first. Next, the equations used for designing vertical and horizontal separators are derived. This will imply finding the diameter and length of a separator for given conditions of oil and gas flow rates, or vice versa.

Assumptions
1. No oil foaming takes place during the gas–oil separation (otherwise retention time has to be drastically increased as explained earlier).
2. The cloud point of the oil and the hydrate point of the gas are below the operating temperature.
3. The smallest separable liquid drops are spherical ones having a diameter of 100 mm.
4. Liquid carryover with the separated gas does not exceed 0.10 gallon/MMSCF (M¼1000).

Fundamentals
1. The difference in densities between liquid and gas is taken as a basis for sizing the gas capacity of the separator .
2. A normal liquid (oil) retention time for gas to separate from oil is between 30 s and 3 min. Under foaming conditions, more time is considered (5–20 min). Retention time is known also as the residence time (¼V/Q, where V is the volume of vessel occupied by oil and Q is the liquid flow rate).
3. In the gravity settling section, liquid drops will settle at a terminal velocity that is reached when the gravity force Fg acting on the oil drop balances the drag force (Fd) exerted by the surrounding fluid or gas.
4. For vertical separators, liquid droplets (oil) separate by settling downward against an up-flowing gas stream; for horizontal ones, liquid droplets assume a trajectory like path while it flows through the vessel (the trajectory of a bullet fired from a gun).
5. For vertical separators, the gas capacity is proportional to the cross-sectional area of the separator, whereas for
horizontal separators, gas capacity is proportional to area of disengagement (LD) (i.e., length  diameter).

Settling of Oil Droplets
In separating oil droplets from the gas in the gravity settling section of a separator, a relative motion exists between the particle, which is the oil droplet, and the surrounding fluid, which is the gas. An oil droplet, being much greater in density than the gas, tends to move vertically downward under the gravitational or buoyant force, Fg.
The fluid (gas), on the other hand, exerts a drag force, Fd, on the oil droplet in the opposite direction. The oil droplet will accelerate until the frictional resistance of the fluid drag force, Fd, approaches and balances Fg; and, thereafter, the oil droplet continues to fall at a constant velocity known as the settling or terminal velocity.

read also:
 Gas – Oil Separators Part.1
2-phase Gas Oil Separation

References:
1. Petroleum and Gas Field Processing – H. K. Abdel-Aal and Mohamed Eggour.
2. Oil & Gas Production Handbook. 

Gas–Oil Separators part. 1


Commercial Types of Gas–Oil Separator

Based on the configuration, the most common types of separator are horizontal, vertical, and spherical, Large horizontal gas–oil separators are used almost exclusively in processing well fluids in the Middle East, where the gas–oil ratio of the producing fields is high. Multistage GOSPs normally consists of three or more separators.

The following is a brief description of some separators for some specific applications. In addition, the features of what is known as ‘‘modern’’ GOSP are highlighted.

GOSP

Test Separators

These units are used to separate and measure at the same time the well fluids. Potential test is one of the recognized tests for measuring the quantity of both oil and gas produced by the well in 24 hours period under
steady state of operating conditions. The oil produced is measured by a flow meter (normally a turbine meter) at the separator’s liquid outlet and the cumulative oil production is measured in the receiving tanks.

An orifice meter at the separator’s gas outlet measures the produced gas. Physical properties of the oil and GOR are also determined. Equipment for test units.

Modern GOSPs
Safe and environmentally acceptable handling of crude oils is assured by treating the produced crude in the GOSP and related crude-processing facilities. The number one function of the GOSP is to separate the associated gas from oil. As the water content of the produced crude increases, field facilities for control or elimination of water are to be
added. This identifies the second function of a GOSP. If the effect of corrosion due to high salt content in the crude is recognized, then modern desalting equipment could be included as a third function in the GOSP design.

horizontal separator internal design
Horizontal Separator

One has to differentiate between ‘‘dry’’ crude and ‘‘wet’’ crude. The former is produced with no water, whereas the latter comes along with water. The water produced with the crude is a brine solution containing salts (mainly sodium chloride) in varying concentrations.
The input of wet crude oil into a modern GOSP consists of the following:

 

 

1. Crude oil.
2. Hydrocarbon gases.
3. Free water dispersed in oil as relatively large droplets, which will separate and settle out rapidly when wet crude is retained in the vessel.
4. Emulsified water, dispersed in oil as very small droplets that do not settle out with time. Each of these droplets is surrounded by a thin film and held in suspension.
5. Salts dissolved in both free water and in emulsified water.

التصميم الداخلي لعازلة أفقية
vertical separator internal design

The functions of a modern GOSP could be summarized as follows:
1. Separate the hydrocarbon gases from crude oil.
2. Remove water from crude oil.
3. Reduce the salt content to the acceptable level [basic sediments and water]
It should be pointed out that some GOSPs do have gas compression and refrigeration facilities to treat the gas before sending it to gas processing plants. In general, a GOSP can function according to one of the following process operation:
1. Three-phase, gas–oil–water separation .
2. Two-phase, gas–oil separation
3. Two-phase, oil–water separation
4. Deemulsification
5. Washing
6. Electrostatic coalescence
To conclude, the ultimate result in operating a modern three-phase separation plant is to change ‘‘wet’’ crude input into the desired outputs.

 

Controllers and Internal Components of Gas–Oil Separators

Gas–oil separators are generally equipped with the following control devices and internal components.

Liquid Level Controller
The liquid level controller (LLC) is used to maintain the liquid level inside the separator at a fixed height. In simple terms, it consists of a float that exists at the liquid–gas interface and sends a signal to an automatic diaphragm motor valve on the oil outlet. The signal causes the valve to open or close, thus allowing more or less liquid out of the separator to maintain its level inside the separator.

Pressure Control Valve
The pressure control valve (PCV) is an automatic backpressure valve that exists on the gas stream outlet. The valve is set at a prescribed pressure. It will automatically open or close, allowing more or less gas to flow out of the separator to maintain a fixed pressure inside the separator.

Pressure Relief Valve
The pressure relief valve (PRV) is a safety device that will automatically open to vent the separator if the pressure inside the separator exceeded the design safe limit.

Mist Extractor

The function of the mist extractor is to remove the very fine liquid droplets from the gas before it exits the separator. Several types of mist extractors are available:

mist extractor mist extractor

1. Wire-Mesh Mist Extractor
: These are made of finely woven stainless-steel wire wrapped into a tightly packed cylinder of about 6 in. thickness. The liquid droplets that did not separate in the gravity settling section of the separator coalesce on the surface of the matted wire, allowing liquid-free gas to exit the separator. As the droplets size grows, they fall down into the liquid phase. Provided that the gas velocity is reasonably low, wire-mesh extractors are capable of removing about 99% of the 10-mm and larger liquid droplets. It should be noted that this
type of mist extractor is prone to plugging. Plugging could be due to the deposition of paraffin or the entrainment of large liquid droplets in the gas passing through the mist extractor (this will occur if the separator was not properly designed). In such cases, the vane-type mist extractor, described next, should be used.

2. Vane Mist Extractor: This type of extractor consists of a series of closely spaced parallel, corrugated plates. As the gas and entrained liquid droplets flowing between the plates change flow direction, due to corrugations, the liquid droplets impinge on the surface of the plates, where they coalesce and fall down into the liquid collection section.

3. Centrifugal Mist Extractor: This type of extractor uses centrifugal force to separate the liquid droplets from the gas.
Although it is more efficient and less susceptible to plugging than other extractors, it is not commonly used because of its performance sensitivity to small changes in flow rate.

read also:
 Gas – Oil Separators Part.2
2-phase Gas Oil Separation

References:
1. Petroleum and Gas Field Processing – H. K. Abdel-Aal and Mohamed Eggour.
2. Oil & Gas Production Handbook.

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Surface Facilities in Oil & Natural Gas Production Part.1

المنشآت السطحية لأنتاج النفط والغاز الطبيعي – الجزء الأول

Surface Facilities in Oil & Natural Gas Production Part.1

أن آبار النفط أو الغاز تنتج مزيج من الغازات الهيدروكاربونية والمكثفات، أو النفط ، والماء مع بعض المعادن الذائبة و كمية من الأملاح وبعض الغازات الأخرى، مثل النتروجين، ثاني أوكسيد الكربون (CO2)، وربما كبريتيد الهيدروجين (H2S)، والمواد الصلبة، بما في ذلك الرمل والشوائب من تآكل الأنابيب.

من أجل الحصول على النفط والغاز بكميات تجارية ليتم بيعها، يجب فصلها عن الماء والمواد الصلبة وبيعها ونقلها عبر خط أنابيب أو الشاحنات أو السكك الحديدية، أو ناقلات النفط الى المستخدم النهائي أما تصدير الغاز فيقتصر عادة على خطوط الأنابيب ولكن يمكن أيضا أن يشحن في الشاحنات او الناقلات وعربات السكك الحديدية بعد ضغطه وتحويله الى الغاز الطبيعي المسال (LNG). 

أن الهدف من هذه المنشآت هو انتاج النفط الذي يلبي مواصفات المستهلك والتي تحدد الحد الأقصى المسموح به من الماء والأملاح، أو غيرها من الشوائب. وبالمثل، لا بد من معالجة الغاز لتلبية مواصفات المستهلك من نسبة بخار الماء المسموحة ونقطة الندى Dew Point  للحد من التكثيف أثناء النقل.  أما الماء المنتج Produced Water فيجب أن يكون مطابقاً للمواصفات البيئية للتخلص منها في المحيط في حالة الآبار البحرية Off-Shore wells أو الحقن الى المكمن بالشكل الذي يضمن عدم حصول أنسداد في مسامات المكمن. كما يمكن أستخدامه لاستخدامات أخرى، مثل تجهيزه الى المراجل الحرارية Boilers  أو أستخدامه لأغراض الري أو ماء للشرب في بعض الأحيان .

وتسمى هذه المعدات بين الآبار وخطوط الأنابيب، أو غيرها من نظام النقل Transportation System تسمى منشأت سطحية لحقول النفط. 

أن المنشأت السطحية لحقول النفط تختلف عن المصافي أو مصانع المواد الكيميائية في أمور كثيرة. حيث تكون أبسط منها، وتتألف من وحدات الفصل Phase Separation وتغير درجة الحرارة وتغييرات الضغط، ولكن تختلف معها في التفاعلات الكيميائية لصنع جزيئات جديدة. 

وفي المصافي يجب معرفة معدل التدفق المغذي للمصفى ومكوناته قبل التصميم. أما في الحقول النفطية فأن المكونات يتم تقديرها إستناداً الى  اختبارات الأنتاج من الآبار الاستكشافية Exploration Wells أو من آبار موجودة في حقول مشابهة.

وتقدر معدلات التدفق التصميمية من سجلات الآبار ومن خلال محاكاة المكامن Reservoir Simulation . وحتى لو كانت التقديرات جيدة، فأن معدلات التدفق (الغاز والنفط، والماء) والضغوط ودرجات الحرارة تتغير طوال عمر المكمن مع تقادم الآبار وحفر آبار جديدة.

ويتم مراعاة أقصى معدل تخميني للتدفق عند التصميم على أساس عدد الآبار، ومخططات الإنتاج Production Profile ومجموع النفط أو الغاز التي يمكن أن تنتج من المكمن.

أن معدلات الإنتاج الفعلي للمنشآة النفطية ستزيد مع إكمال الآبار وصولاً الى المعدلات التصميمية. ويتم الحفاظ على هذا المعدل لأطول فترة ممكنة من خلال حفر آبار إضافية  وبعد ذلك تبدأ معدلات النفط والغاز بالتراجع، وأنتاج الماء في الزيادة، بالأضافة الى أنخفاض ضغوط الجريان مع استنزاف عمر المكمن. لذا يجب تصميم المعدات في المنشآة النفطية للتعامل مع مدى واسع من معدلات التدفق ، ودرجات الحرارة والمكونات المتغيرة.

تعريف لبعض المصطلحات :

النفط الخام Crude Oil هو مجموعة الهيدروكربونات السائلة المنتجة من المكمن.

المكثفات Condensate هي السوائل الهيدروكربونية المتكثفة من الغاز بأنخفاض الضغط ودرجات الحرارة عند أنتاج الغاز من المكمن خلال الأنبوب والصمام الخانق في الآبار. وتكون المكثفات عادة أفتح لونا وأقل في الوزن الجزيئي واللزوجة من النفط الخام. ويمكن أن يكون للنفط الخام الخفيف خصائص مشابهة للمكثفات.

وتتكون الهيدروكربونات من العديد من العناصر المختلفة أو جزيئات من الكربون وذرات الهيدروجين. بدءا من ذوات الوزن الجزيئي الأقل ، وهي الميثان CH4 الإيثان(C2H6) والبروبان (C3H8) والبيوتان (C4H10)، البنتان (C5H12)، الهكسان (C6H14) صعوداً. وبصعود نسبة ذرات الكربون إلى ذرات الهيدروجين فأن الجزيئات تصبح “أثقل” ويكون لها ميل أكبر في الوجود كسائل بدلا من الغاز.

المنشأت السطحية في حقول النفط Oil Field Facility هي عبارة عن مجموعة من المعدات التي تستخدم لفصل السوائل المنتجة من البئر النفطي أو الغازي الى مكونات مختلفة يمكن بعد ذلك بيعها وإرسالها إلى معمل معالجة الغاز Gas Plant أو المصفى Refinery للمزيد من المعالجة. 

محاكاة العملية Process Simulation وهي حسابات تتم عادة بواسطة برنامج كمبيوتر يتنبأ بالمكونات المنتجة من البئر ويتفاعل هذا البرنامج مع التغيرات في الضغط ودرجة الحرارة التي يتم معالجتها في هذه المنشآة. 

وهذا ليس تفاعل كيميائي، بل تغير بسيط في الأطوار من خلال تحول السوائل إلى بخار قد تتكثف الى سائل. ومع تقليل الضغط وزيادة درجة الحرارة فأن الجزيئات الأخف وزنا مثل الميثان والإيثان تميل إلى التحول الى الطور البخاري أما معظم الجزيئات الأثقل فتستقر على شكل سوائل.

 

أن الرواسب والماء (BS & W) هو النسبة المئوية للماء والشوائب الموجودة في النفط. ويجب أن تتراوح بين 0.1 الى 3% ، وتصل النسبة الى 1% حجماً في خليج المكسيك Gulf of Mexico .

نقطة الفقاعة bubblepoint هو الضغط التي تبدأ فيه أول قطرة من السائل الهايدروكاربوني بالظهور في الطور السائل بصعود درجة الحرارة أو خفض الضغط. أن نقطة الفقاعة للسوائل الهيدروكاربونية دالة لدرجة الحرارة والضغط، ومكونات السائل.

 ضغط ريد البخاري Reid Vapor Pressure هو الضغط الذي يبدأ فيه الهيدروكربون السائل بالتحول الى بخار في ظل ظروف محددة. ويمكن قياس ذلك في الحقل وفقا لقاياسات الجمعية الأمريكية للأختبارات والمواد القياسية ASTM وأحتساب النتائج في ضغط أقل من الضغط البخاري الحقيقي.

نقطة الندى للهيدروكاربونات Hydrocarbon Dewpoint : هي النقطة التي يبدأ فيها تكثف الهيدروكاربونات السائلة من عينة الغاز عندما يتم خفض درجة الحرارة أو يتم زيادة الضغط، ويعتمد ذلك على تركيب الغاز. ويتم تعيين نقطة ندى الماء لخطوط أنابيب الغاز  للسيطرة على تكون الهيدرات لهيدرات والحيلولة دون التآكل .

الهيدرات Hydrates : هي بلورات شبيهة بالثلج تتكون في وجود الغازات الهيدروكربونية والماء . ويمكن أن تتشكل الهيدرات في درجات حرارة أعلى من درجة الأنجماد للماء ويمكن أن تتسبب في حصول أنسدادات في المعدات وخطوط الأنابيب.

وظيفة المنشآت النفطية :

العمليات الرئيسية Main Process

وهي عبارة عن عمليات فصل النفط والغاز والماء والمواد الصلبة ، ومعالجة النفط للوصول الى المواصفات التسويقية (على سبيل المثال، BS & W، محتوى الماء والأملاح، وضغط البخار ..ألخ) وقياس ونمذجة النفط لتحديد نوعه ومن ثم نقله الى واسطة النقل (أنبوب التصدير – الناقلة البحرية – الشاحنات – أو سكك الحديد).

كما يجب أن تتم معالجة الغاز لأغراض البيع أو التخلص منه (التي كانت تتم في الماضي عن طريق حرقه ) أما الآن فالغاز الذي لا يمكن نقله فيتم كبسه لغرض إعادة الحقن في المكمن. قد تتضمن معالجة الغاز فصله من السوائل فقط ، أو قد تشمل عمليات الكبس والتجفيف Dehydration  وإزالة غازات H2S و CO2، أو معالجة الغاز لتحويله الى غاز سائل ليسهل نقله.

 العمليات الثانوية Secondary Process :

 بالإضافة إلى معالجة النفط والغاز الطبيعي لأغراض البيع، فهناك معالجة الماء المنتج والذي يجب معالجته للتخلص من المواد الصلبة للتمكن من تصريف هذا الماء وعادة ما تتضمن المعالجة إزالة المواد الهيدروكربونية الذائبة وبالإضافة إلى فصل النفط عنه باتخدام قاشطات Skimmers أو مرشحات filters أو وحدات إزالة الايونات deionization  ووحدات الضخ Pumping Stations.

 

وإذا كان المطلوب معالجة المواد الصلبة فقد تشمل ماء الغسيل Wash Water وتحريك المواد الصلبة لإزالة النفط ومن ثم فصل الماء منها.

المنظومات المساعدة Auxiliary Systems :

 بالإضافة إلى العمليات الرئيسية والثانوية يجب توافر المنظومات المساعدة مثل عمليات التسخين والتبريد التي قد تحتاجها المنشآة النفطية . وعادة ً تكون هناك حاجة لعمليات التسخين لعملية لمعالجة النفط وغيرها ، اما عملية التبريد فتكون مطلوبة في محطات كبس الغاز مثلاً.

وإذا لزم الأمر، يمكن تشغيل المنشآت النفطية بدون الطاقة الكهربائية حيث أن توليد الطاقة والكهرباء يكون ضمن نفس المنشآة بالأضافة الى توفير مستلزمات السكن للعاملين في هذه المنشآة النفطية.

أن جميع المنشآت النفطية تتطلب نظم السلامة، بما في ذلك أجهزة ومعدات السلامة ومنظومات التوقف الأضطراري Shut Down systems ومتحسسات الكشف عن الحريق والغاز Fire & gas detectors ومعدات مكافحة الحريق، وسائل الإخلاء، مثل قوارب النجاة في المنصات البحرية ومعدات أخرى اعتمادا على الموقع ومدى تعقيد المنشأة .

المصادر :

Petroleum Engineering Handbook – Part 3 – Kenneth E. Arnold

Surface Production Operations – Ken Arnold/ Maurice Stewart