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Flares

 

 

Introduction

flareFlaring is a volatile organic compound (VOC) combustion control process in which the VOCs are piped to a remote, usually elevated, location and burned in an open flame in the open air using a specially designed burner tip, auxiliary fuel, and steam or air to promote mixing for nearly complete (> 98%) VOC destruction. Completeness of combustion in a flare is governed by flame temperature, residence time in the combustion zone, turbulent mixing of the components to complete the oxidation reaction, and available oxygen for free radical formation.

Combustion is complete if all VOCs are converted to carbon dioxide and water. Incomplete combustion results in some of the VOC being unaltered or converted to other organic compounds such as aldehydes or acids.

The flaring process can produce some undesirable by-products including noise, smoke, heat radiation, light, SO , NO , CO, and an additional source of ignition where not desired. However, by proper design these can be minimized.

 Flare Types

Flares are generally categorized in two ways: (1) by the height of the flare tip (i.e., ground or elevated), and (2) by the method of enhancing mixing at the flare tip (i.e., steam-assisted, air assisted, pressure-assisted, or non-assisted). Elevating the flare can prevent potentially dangerous conditions at ground level where the open flame (i.e., an ignition source) is located near a process unit. Further, the products of combustion can be dispersed above working areas to reduce the effects of noise, heat, smoke, and objectionable odors.

In most flares, combustion occurs by means of a diffusion flame. A diffusion flame is one in which air diffuses across the boundary of the fuel/combustion product stream toward the center of the fuel flow, forming the envelope of a combustible gas mixture around a core of fuel gas. This mixture, on ignition, establishes a stable flame zone around the gas core above the burner tip. This inner gas core is heated by diffusion of hot combustion products from the flame zone.

Cracking can occur with the formation of small hot particles of carbon that give the flame its characteristic luminosity. If there is an oxygen deficiency and if the carbon particles are cooled to below their ignition temperature, smoking occurs. In large diffusion flames, combustion product vortices can form around burning portions of the gas and shut off the supply of oxygen. This localized instability causes flame flickering, which can be accompanied by soot formation.

As in all combustion processes, an adequate air supply and good mixing are required to complete combustion and minimize smoke. The various flare designs differ primarily in their accomplishment of mixing.

steam assisted flare

Steam-Assisted Flares

Steam-assisted flares are single burner tips, elevated above ground level for safety reasons, that burn the vented gas in essentially a diffusion flame. They reportedly account for the majority of the flares installed and are the predominant flare type found in refineries and chemical plants. To ensure an adequate air supply and good mixing, this type of flare system injects steam into the combustion zone to promote turbulence for mixing and to induce air into the flame.

 

 

Air-Assisted Flares

Some flares use forced air to provide the combustion air and the mixing required for smokeless operation. These flares are built with a spider-shaped burner (with many small gas orifices) located inside but near the top of a steel cylinder two feet or more in diameter. Combustion air is provided by a fan in the bottom of the cylinder. The amount of combustion air can be varied by varying the fan speed. The principal advantage of the air-assisted flares is that they can be used where steam is not available. Although air assist is not usually used on large flares (because it is generally not economical when the gas volume is large. the number of large airassisted .flares being built is increasing.

 Non-Assisted Flares

The non-assisted flare is just a flare tip without any auxiliary provision for enhancing the mixing of air into its flame. Its use is limited essentially to gas streams that have a low heat content and a low carbon/hydrogen ratio that burn readily without producing smoke .These streams require less air for complete combustion, have lower combustion temperatures that minimize cracking reactions, and are more resistant to cracking.

 Pressure-Assisted Flares

Pressure-assisted flares use the vent stream pressure to promote mixing at the burner tip. Several vendors now market proprietary, high pressure drop burner tip designs. If sufficient vent stream pressure is available, these flares can be applied to streams previously requiring steam or air assist for smokeless operation. Pressure-assisted flares generally (but not necessarily) have the burner arrangement at ground level, and consequently, must be located in a remote area of the plant where there is plenty of space available. They have multiple burner heads that are staged to operate based on the quantity of gas being released. The size, design, number, and group arrangement of the burner heads depend on the vent gas characteristics.

Enclosed Ground Flares

An enclosed flare’s burner heads are inside a shell that is internally insulated. This shell reduces noise, luminosity, and heat radiation and provides wind protection. A high nozzle pressure drop is usually adequate to provide the mixing necessary for smokeless operation and air or steam assist is not required. In this context, enclosed flares can be considered a special class of pressure-assisted or non-assisted flares. The height must be adequate for creating enough draft to supply sufficient air for smokeless combustion and for dispersion of the thermal plume. These flares are always at ground level.

Enclosed flares generally have less capacity than open flares and are used to combust continuous, constant flow vent streams, although reliable and efficient operation can be attained over a wide range of design capacity. Stable combustion can be obtained with lower Btu content vent gases than is possible with open flare designs (50 to 60 Btu/scf has been reported), probably due to their isolation from wind effects. Enclosed flares are typically found at landfills.

 Applicability

Flares can be used to control almost any VOC stream, and can handle fluctuations in VOC concentration, flow rate, heating value, and inerts content. Flaring is appropriate for continuous, batch, and variable flow vent stream applications. The majority of chemical plants and refineries have existing flare systems designed to relieve emergency process upsets that require release of large volumes of gas. These large diameter flares designed to handle emergency releases, can also be used to control vent streams from various process operations. Consideration of vent stream flow rate and available pressure must be given for retrofit applications. Normally, emergency relief flare systems are operated at a small percentage of capacity and at negligible pressure. To consider the effect of controlling an additional vent stream, the maximum gas velocity, system pressure, and ground level heat radiation during an emergency release must be evaluated. Further, if the vent stream pressure is not sufficient to overcome the flare system pressure, then the economics of a gas mover system must be evaluated, If adding the vent stream causes the maximum velocity limits or ground level heat radiation limits to be exceeded, then a retrofit application is not viable.

Many flare systems are currently operated in conjunction with base load gas recovery systems. These systems recover and compress the waste VOC for use as a feedstock in other processes or as fuel. When baseload gas recovery systems are applied, the flare is used in a backup capacity and for emergency releases. Depending on the quantity of usable VOC that can be recovered, there can be a considerable economic advantage over operation of a flare alone.

Streams containing high concentrations of halogenated or sulfur containing compounds are not usually flared due to corrosion of the flare tip or formation of secondary pollutants (such as SO ). If these vent types are to be controlled by combustion, thermal incineration, followed by 2 scrubbing to remove the acid gases, is the preferred method.

Factors Affecting Efficiency

The major factors affecting flare combustion efficiency are vent gas flammability, auto-ignition temperature, heating value (Btu/scf), density, and flame zone mixing.

The flammability limits of the flared gases influence ignition stability and flame extinction. The flammability limits are defined as the stoichiometric composition limits (maximum and minimum) of an oxygen-fuel mixture that will burn indefinitely at given conditions of temperature and pressure without further ignition. In other words, gases must be within their flammability limits to burn. When flammability limits are narrow, the interior of the flame may have insufficient air for the mixture to burn. Fuels, such as hydrogen, with wide limits of flammability are therefore easier to combust.

For most vent streams, the heating value also affects flame stability, emissions, and flame structure. A lower heating value produces a cooler flame that does not favor combustion kinetics and is also more easily extinguished. The lower flame temperature also reduces buoyant forces, which reduces mixing.

The density of the vent stream also affects the structure and stability of the flame through the effect on buoyancy and mixing. By design, the velocity in many flares is very low; therefore, most of the flame structure is developed through buoyant forces as a result of combustion.

Lighter gases therefore tend to burn better. In addition to burner tip design, the density also directly affects the minimum purge gas required to prevent flashback, with lighter gases requiring more purge.

Poor mixing at the flare tip is the primary cause of flare smoking when burning a given material. Streams with high carbon-to-hydrogen mole ratio (greater than 0.35) have a greater tendency to smoke and require better mixing for smokeless flaring. For this reason one generic steam-to-vent gas ratio is not necessarily appropriate for all vent streams. The required steam rate is dependent on the carbon to hydrogen ratio of the gas being flared. A high ratio requires more steam to prevent a smoking flare.

Gas Transport Piping

Process vent streams are sent from the facility release point to the flare location through the gas collection header. The piping (generally schedule 40 carbon steel) is designed to minimize pressure drop. Ducting is not used as it is more prone to air leaks. Valving should be kept to an absolute minimum and should be “car-sealed” (sealed) open. Pipe layout is designed to avoid any potential dead legs and liquid traps. The piping is equipped for purging so that explosive mixtures do not occur in the flare system either on start-up or during operation.

Knock-out Drum

knockout-drum

Liquids that may be in the vent stream gas or that may condense out in the collection header and transfer lines are removed by a knock-out drum. The knock-out or disentrainment drum is typically either a horizontal or vertical vessel located at or close to the base of the flare, or a vertical vessel located inside the base of the flare stack. Liquid in the vent stream can extinguish the flame or cause irregular combustion and smoking. In addition, flaring liquids can generate a spray of burning chemicals that could reach ground level and create a safety hazard. For a flare system designed to handle emergency process upsets this drum must be sized for worst-case conditions (e.g., loss of cooling water or total unit depressuring) and is usually quite large. For a flare system devoted only to vent stream VOC control, the sizing of the drum is based primarily on vent gas flow rate with consideration given to liquid entrainment.

Liquid Seal

Process vent streams are usually passed through a liquid seal before going to the flare stack. The liquid seal can be downstream of the knockout drum or incorporated into the same vessel. This prevents possible flame flashbacks, caused when air is inadvertently introduced into the flare system and the flame front pulls down into the stack. The liquid seal also serves to maintain a positive pressure on the upstream system and acts as a mechanical damper on any explosive shock wave in the flare stack.(51 Other devices, such as flame arresters and check valves, may sometimes replace a liquid seal or be used in conjunction with it. Purge gas also helps to prevent flashback in the flare stack caused by low vent gas flow.

Flare Stack

flare stackFor safety reasons a stack is used to elevate the flare. The flare must he located so that it does not present a hazard to surrounding personnel and facilities. Elevated flares can be self supported (free-standing), guyed, or structurally supported by a derrick.

Self-supporting flares are generally used for lower flare tower heights (30-100 feet) but can be designed for up to 250 feet. Guy towers are designed for over 300 feet, while derrick towers are designed for above 200 feet Free-standing flares provide ideal structural support. However, for very high units the costs increase rapidly. In addition, the foundation required and nature of the soil must be considered.

Derrick-supported flares can be built as high as required since the system load is spread over the derrick structure. This design provides for differential expansion between the stack, piping, and derrick. Derrick-supported flares are the most expensive design for a given flare height.

The guy-supported flare is the simplest of all the support methods. However, a considerable amount of land is required since the guy wires are widely spread apart. A rule of thumb for space required to erect a guy-supported flare is a circle on the ground with a radius equal to the height of the flare stack.

Burner Tip

The burner tip, or flare tip, is designed to give environmentally acceptable combustion of the vent gas over the flare system’s capacity range. The burner tips are normally proprietary in design. Consideration is given to flame stability, ignition reliability, and noise suppression. The maximum and minimum capacity of a flare to burn a flared gas with a stable flame (not necessarily smokeless) is a function of tip design. Flame stability can be enhanced by flame holder retention devices incorporated in the flare tip inner circumference. Burner tips with modern flame holder designs can have a stable flame over a flare gas exit velocity range of 1 to 600 ft/sec. The actual maximum capacity of a flare tip is usually limited by the vent stream pressure available to overcome the system pressure drop. Elevated flares diameters are normally sized to provide vapor velocities at maximum throughput of about 50 percent of the sonic velocity of the gas subject to the constraints of CFR.

Pilot Burners

EPA regulations require the presence of a continuous flame. Reliable ignition is obtained by continuous pilot burners designed for stability and positioned around the outer perimeter of the flare tip. The pilot burners are ignited by an ignition source system, which can be designed for either manual or automatic actuation. Automatic systems are generally activated by a flame detection device using either a thermocouple, an infra-red sensor or, more rarely, (for ground flare applications) an ultra-violet sensor.

Well Control

Basically, all formations penetrated during drilling are porous and permeable to some degree. Fluids contained in pore spaces are under pressure that is overbalanced by the drilling fluid pressure in the well bore. The borehole pressure is equal to the hydrostatic pressure plus the friction pressure loss in the annulus. If for some reason the borehole pressure falls below the formation fluid pressure, the formation fluids can enter the well. Such an event is known as a kick. This name is associated with a rather sudden

flowrate increase observed at the surface.

A formation fluid influx (a kick) may result from one of the following reasons:

  • abnormally high formation pressure is encountered
  • lost circulation
  • mud weight too low
  • swabbing in during tripping operations
  • not filling up the hole while pulling out the drillstring
  • recirculating gas or oil cut mud.

If a kick is not controlled properly, a blowout will occur.A blowout may develop for one or more of the following causes:

  • lack of analysis of data obtained from offset wells
  • lack or misunderstanding of data during drilling
  • malfunction or even lack of adequate well control equipment

 SURFACE EQUIPMENT

A formation gas or fluid kick can be efficiently and safely controlled if the proper equipment is installed at the surface. One of several possible arrangement of pressure control equipment is shown in Figure. The blowout preventer (BOP) stack consists of a spherical preventer (i.e.,Hydril) and ram type BOPs with blind rams in one and pipe rams in another with a drilling spool placed in the stack.

A spherical preventer contains a packing element that seals the space around the outside of the drill pipe. This preventer is not designed to shut off the well when the drill pipe is out of the hole. The spherical preventer allows stripping operations and some limited pipe rotation.

wellhead

Hydril Corporation, Shaffer, and other manufactures provide several models with differing packing element designs for specific types of service. The ram type preventer uses two concentric halves to close and seal around the pipe, called pipe rams or blind rams, which seal against the opposing half when there is no pipe in the hole. Some pipe rams will only seal on a single size pipe; 5 in. pipe rams only seal around 5 in. drill pipe. There are also variable bore rams, which cover a specific size range such as 3½ in. to 5 in. that seal on any size pipe in their range.

Care must be taken before closing the blind rams. If pipe is in the hole and the blind rams are closed, the pipe may be damaged or cut. A special type of blind rams that will sever the pipe are called shear blind rams.

These rams will seal against themselves when there is no pipe in the hole, or, in the case of pipe in the hole, the rams will first shear the pipe and then continue to close until they seal the well.

A drilling spool is the element of the BOP stack to which choke and kill lines are attached. The pressure rating of the drilling spool and its side outlets should be consistent with BOP stack. The kill line allows pumping mud into the annulus of the well in the case that is required. The choke line side is connected to a manifold to enable circulation of drilling and formation fluids out of the hole in a controlled manner.

Driller A degasser is installed on the mud return line to remove any small amounts of entrained gas in the returning drilling fluids. Samples of gas are analyzed using the gas chromatograph.

If for some reason the well cannot be shut in, and thus prevents implementation of regular kick killing procedure, a diverter type stack is used rather, the BOP stack described above. The diverter stack is furnished with a blow-down line to allow the well to vent wellbore gas or fluids a safe distance away from the rig. Figure bellow shows a diverter stack arrangement.

Read also about Drilling Bits

WHEN AND HOW TO CLOSE THE WELL

While drilling, there are certain warning signals that, if properly analyzed, can lead to early detection of gas or formation fluid entry into the wellbore.

  1. Drilling break. A relatively sudden increase in the drilling rate is called a drilling break. The drilling break may occur due to a decrease in the difference between borehole pressure and formation pressure. When a drilling break is observed, the pumps should be stopped and the well watched for flow at the mud line. If the well does not flow, it probably means that the overbalance is not lost or simply that a softer formation has be encountered.
  2. Decrease in pump pressure. When less dense formation fluid enters the

borehole, the hydrostatic head in the annulus is decreased. Although reduction in pump pressure may be caused by several other factors, drilling personnel should consider a formation fluid influx into the wellbore as one possible cause. The pumps should be stopped and the return flow mud line watched carefully.

  1. Increase in pit level. This is a definite signal of formation fluid invasion into the wellbore. The well must be shut in as soon as possible.
  2. Gas-cut mud.Whendrilling through gas-bearing formations, small quantities

of gas occur in the cuttings. As these cuttings are circulated up, the annulus, the gas expands. The resulting reduction in mud weight is observed at surface. Stopping the pumps and observing the mud return line help determine whether the overbalance is lost.

If the kick is gained while tripping, the only warning signal we have is an increase in fluid volume at the surface (pit gain). Once it is determined that the pressure overbalance is lost, the well must be closed as quickly as possible. The sequence of operations in closing a well is as follows:

  1. Shut off the mud pumps.
  2. Raise the Kelly above the BOP stack.
  3. Open the choke line
  4. Close the spherical preventer.
  5. Close the choke slowly.
  6. Record the pit level increase.
  7. Record the stabilized pressure on the drill pipe (Stand Pipe) and annulus pressure gauges.
  1. Notify the company personnel.
  2. Prepare the kill procedure.

If the well kicks while tripping, the sequence of necessary steps can be given below:

  1. Close the safety valve (Kelly cock) on the drill pipe.
  2. Pick up and install the Kelly or top drive.
  3. Open the safety valve (Kelly cock).
  4. Open the choke line.
  5. Close the annular (spherical) preventer.
  6. Record the pit gain along with the shut in drill pipe pressure (SIDPP) and shut in casing pressure (SICP).
  1. Notify the company personnel.
  2. Prepare the kill procedure.

Depending on the type of drilling rig and company policy, this sequence of operations may be changed.

Read also Drilling Rotating Equipment

 KICK CONTROL PROCEDURES

There are several techniques available for kick control (kick-killing procedures).

In this section only three methods will be addressed.

  1. Driller’s method. First the kick fluid is circulated out of the hole and hen the drilling fluid density is raised up to the proper density (kill mud density) to replace the original mud. An alternate name for this procedure is the two circulation method.
  2. Engineer’s method. The drilling fluid is weighted up to kill density while the formation fluid is being circulated out of the hole. Sometimes this technique is known as the one circulation method.
  3. Volumetric method. This method is applied if the drillstring is off the bottom.

The guiding principle of all these techniques is that bottomhole pressure is held constant and slightly above the formation pressure at any stage of the process. To choose the most suitable technique one ought to consider

(a) complexity of the method,

(b) drilling crew experience and training,

(c) maximum expected surface and borehole pressure.

(d) Time needed to reestablish pressure overbalance and resume normal drilling operations.

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.

Geologic Classification of Petroleum Reservoirs

 

Petroleum reservoirs exist in many different sizes and shapes of geologic structures. It is usually convenient to classify the reservoirs according to the conditions of their formation as follows:

A reservoir formed by folding of rock layers.
Figure 1

1. Dome-Shaped and Anticline Reservoirs:

These reservoirs are formed by the folding of the rock layers as shown in Figure 1. The dome is circular in outline, and the anticline is long and narrow. Oil and/or gas moved or migrated upward through the porous strata where it was trapped by the sealing cap rock and the shape of the structure.

 

2. Faulted Reservoirs:

A cross section of a faulted reservoir.
Figure 2

These reservoirs are formed by shearing and offsetting of the strata (faulting), as shown in Figure 2. The movement of the nonporous rock opposite the porous formation containing the oil/gas creates the sealing. The tilt of the petroleum-bearing rock and the faulting trap the oil/gas in the reservoir.

 

 

3. Salt-Dome Reservoirs:

Section in a salt-dome structure
figure 3

This type of reservoir structure, which
takes the shape of a dome, was formed due to the upward
movement of large, impermeable salt dome that deformed and
lifted the overlying layers of rock. As shown in Figure 3,
petroleum is trapped between the cap rock and an underlying
impermeable rock layer, or between two impermeable layers of
rock and the salt dome.

 

 

4. Unconformities:

A reservoir formed by unconformity.
figure 4

This type of reservoir structure, shown in Figure 4, was formed as a result of an unconformity where the
impermeable cap rock was laid down across the cutoff surfaces of the lower beds.

 

 

 

5. Lense-Type Reservoirs:

In this type of reservoir, the petroleum bearing porous formation is sealed by the surrounding, nonporous formation. Irregular deposition of sediments and shale at the time the formation was laid down is the probable cause for this abrupt change in formation porosity.

6. Combination Reservoirs:

In this case, combinations of folding, faulting, abrupt changes in porosity, or other conditions that create the trap, from this common type of reservoir.

Reservoir Drive Mechanisms
At the time oil was forming and accumulating in the reservoir, the pressure energy of the associated gas and water was also stored. When a well is drilled through the reservoir and the pressure in the well is made to be lower than the pressure in the oil formation, it is that energy of the gas, or the water, or both that would displace the oil from the formation into the well and lift it up to the surface. Therefore, another way of classifying petroleum reservoirs,
which is of interest to reservoir and production engineers, is to characterize the reservoir according to the production (drive) mechanism responsible for displacing the oil from the formation into the wellbore and up to the surface. There are three main drive mechanisms:

I. Solution-Gas-Drive Reservoirs:
Depending on the reservoir pressure and temperature, the oil in the reservoir would have varying amounts of gas dissolved within the oil (solution gas).
Solution gas would evolve out of the oil only if the pressure is lowered below a certain value, known as the bubble point pressure, which is a property of the oil. When a well is drilled through the reservoir and the pressure conditions are controlled to create a pressure that is lower than the bubble point pressure, the liberated gas expands and drives the oil out of the formation and assists in lifting it to the surface.
Reservoirs with the energy of the escaping and expanding dissolved gas as the only source of energy are called solution-gas-drive reservoirs.
This drive mechanism is the least effective of all drive mechanisms; it generally yields recoveries between 15% and
25% of the oil in the reservoir.

II. Gas-Cap-Drive Reservoirs:
Many reservoirs have free gas existing as a gas cap above the oil. The formation of this gas cap was due to the presence of a larger amount of gas than could be dissolved in the oil at the pressure and temperature of the reservoir. The excess gas is segregated by gravity to occupy the top portion of the reservoir.
In such a reservoirs, the oil is produced by the expansion of the gas in the gas cap, which pushes the oil downward and fills the pore spaces formerly occupied by the produced oil. In most cases, however, solution gas is also
contributing to the drive of the oil out of the formation.
Under favorable conditions, some of the solution gas may move upward into the gas cap and, thus, enlarge the gas cap and conserves its energy. Reservoirs produced by the expansion of the gas cap are known as Gas-cap-drive
reservoirs. This drive is more efficient than the solution-gas drive and could yield recoveries between 25% and 50% of the original oil in the reservoir.

III. Water-Drive Reservoirs:
Many other reservoirs exist as huge, continuous, porous formations with the oil/gas occupying only a small portion of the formation. In such cases, the vast formation below the oil/gas is saturated with salt water at very high pressure. When oil/gas is produced, by lowering the pressure in the well opposite the petroleum formation, the salt
water expands and moves upward, pushing the oil/gas out of the formation and occupying the pore spaces vacated by the produced oil/gas. The movement of the water to displace the oil/gas retards the decline in oil, or gas pressure, and conserves the expansive energy of the hydrocarbons.
Reservoirs produced by the expansion and movement of the salt water below the oil/gas are known as water-drive
reservoirs. This is the most efficient drive mechanism; it could yield recoveries up to 50% of the original oil.

References:
Petroleum and Natural Gas Field Processing
 -H. K. Abdel-Aal and Mohamed Aggour

Petroleum Reservoirs Books 2

Applied Reservoir Engineering,
   
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Principles of Applied Reservoir Simulation
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Basic-Applied-Reservoir-Simulation
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Applied Drilling Engineering SPE Series
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Basic Applied Reservoir Simulation – Ertekin Turcay
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Principles of Applied Reservoir Simulation Third Edition
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     Handbook of Porous Media
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Carbonate Sedimentology and Sequence Stratigraphy
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production operation vol 1 (well completions, workover, and stimulation)   Download 

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Determination of Oil and Gas Reserves
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Reservoir Fluids
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Unconventional Gas Reservoirs
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Permeability
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Reservoir Geology Introduction
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An Improved approach for Sandstone Reservoir Characterization
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Hydraulic Design of Reservoir Outlet Works
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Petroleum Reservoir Traps
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Integrated Reservoir Analysis
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World Atlas of Oil and Gas Basins  112 MB
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Determination of Oil and Gas Reserves
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Advanced Formation Evaluation
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Integrated Formation Evaluation
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Permeability Estimation – Various Sources and their Interrelationship
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Porosity and Permeability Estimation using Neural Network Approach from Well Log
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Complex Lithology Evaluation
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     Carbonate Reservoir Characterization
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a boundary integral method applied to water coning in oil reservoirs
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Density and Porosity of Oil Reservoirs and Overlaying Formations
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Reservoir Quality Prediction in Sandstones and Carbonates
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Quantitative Methods in Reservoir Engineering
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Permian Basin in the US, 2013 – Oil and Gas Basin Analysis and Forecasts to 2020
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Solution PVT Gas
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Seismic Stratigraphy, Basin Analysis and Reservoir Characterization
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    Production Strategy for Thin-Oil Columns in Saturated Reservoirs
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   Major Oil Reservoir in Permian Basin
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Applied Reservoir Engineering – Smith  Vol-1   66 MB
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this section is for petroleum books such as petroleum production – petroleum industry – petroleum engineering – oil well – gas well and many other books related to oil and natural gas industry.

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Introduction to the Global Oil and Gas Business
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ABB Oil and Gas Production Handbook
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Original Oil and Gas Guide
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Introduction to Petroleum Business
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Handbook of Oil and Gas Operations-Vol II-Drilling – Christopher Franklin
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  Kurdistan Oil Report ” towards growth peak”

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Handbook of petroleum exploration and production
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Dictionary of Petroleum Engineering
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How Gas Detector Works

كيف تعمل متحسسات الغاز؟
 How Gas Detector Works?


Gas Detector تقوم متحسسات الغاز Gas Detectors بفحص تركيز غازات معينة في الهواء وبتقنيات مختلفة ، مما يمنع حدوث التسمم للأشخاص أو الحرائق للمعدات والمحطات الصناعية ، وتستعمل عادة لأغراض السلامة الصناعية. يتم تصنيعها على شكل محمول Portable Gas Detectors أو ثابت Fixed Type Gas Detectors للحصول على المراقبة المستمرة للمعمل والمعدات وتعمل على إعلام الفني أو المهندس بوجود نسب عالية من الغازات من خلال مؤشرات سمعية أو بصرية تنبه بوجود نسب عالية أو خطرة من هذه الغازات كما هو الحال في أشارات التحذير Alarms في المحطات.
وهو وسيلة للتنبيه من حالات حدوث تسرب في الغاز داخل المعمل . كما يوجد نوع ثالث من المتحسسات يمكن تثبيته بشكل مؤقت في الأماكن التي تحتوي على متحسسات ثابتة تم سحبها لأغراض الصيانة أو المعايرة.

أما المتحسسات الأصغر (المتنقلة) فيمكن استخدامها للأختبار في الهواء الجوي في مكان معين ، وذلك لتعقب تسربات الغاز ، أو إعطاء أنذار مبكر لوجود الغازات القابلة للإشتعال عند إجراء أعمال حارة مثل اللحام أو القطع في مساحات مغلقة أو شبه مغلقة في مناطق خطرة.

لقد كانت متحسسات الغاز في السابق تقوم بكشف نوع واحد من الغازات فقط ، في حين تقوم المتحسسات الحديثة بتحسس العديد من الغازات المختلفة في موقع العمل في وقت واحد ، كما يمكن استغلال بعض الوحدات في مراقبة وتحسس الغازات الخطرة مناطق عمل محددة ، أو وحدات صناعية معينة ، حيث ترتبط هذه المتحسسات ببعضها لتكوين منظومة متكاملة للحماية من الغازات الخطرة.

 وبما أن هذه المتحسسات تقيس نسب الغازات الخطرة فأن المتحسس يقوم بإرسال إشارة معينة الى منظومة السيطرة ، وعند وصول تركيز الغاز الى نسبة معينة يقوم بإرسال إشارة تنبيه Alarm لتنبيه المستخدم ، وعند وصوله الى نسبة خطرة تقوم بأصدار أصوات عالية بالنسبة للمتحسسات الشخصية ، وتقوم بإيقاف الوحدة الصناعية في حال أستخدمت فيها ، وأغلب متحسسات الغاز تعمل بهذه الطريقة ولكن بتقنيات مختلفة.

تقوم متحسسات الغاز بقياس نسب الغازات بوحدات مختلفة وهي:

  – النسبة الحجمية % volume ratio

 – أدنى نسبة للأنفجار للغازات القابلة للاشتعال Lower Explosion Limit % LEL

 – التراكيز بوحدات ppm أو mg/m3 ويستخدم للغازات السامة.

gas detectorالتقنيات المستخدمة في متحسسات الغاز Gas Detector technologies

 يمكن تصنيف متحسسات الغاز وفقاً لنوع الغاز الذي تتحسس به الى نوعين :

  1. متحسسات الغازات القابلة للأشتعال  Combustible gas detectors

  2. متحسسات الغازات السامة Toxic Gas Detectors

كما يمكن تصنيفها وفقاً للتقنية التي تعمل بها ، حيث يمكن تحسس الغازات القابلة للأشتعال بنوعين هما:

   1. المتحسسات التي تعمل بالعامل المساعد Catalytic Sensors

    2. المتحسسات التي تعمل بالأشعة تحت الحمراء Infrared Sensors

    في حين حيث يمكن تحسس الغازات السامة بنوعين هما:

   1. الطرق الألكتروكيمياوية Electrochemical Sensors .

  2. استخدام تقنية أوكسيدات المعادن شبه الموصلة Metal Oxide Semiconductors MOS.

طرق قياس الغازات القابلة للإشتعال Combustible Gases Measurement

   المتحسسات التي تعمل بتقنية العامل المساعد Catalytic Sensors:

   وهي تمثل النوع الأكثر شيوعاً من متحسسات الغاز التي يتم أنتاجها اليوم ، وتستعمل لتحسس الغازات الهيدروكاربونية ، وتعمل عن طريق أكسدة العامل المساعد ، وتكون المتحسسات من هذا النوع مصنوعة من ملف تمت معالجته بالبلاتينيوم ، وعند تلامس الغاز القابل للأشتعال مع سطح العامل المساعد فأنه يتأكسد وتتغير مقاومة الملف من خلال الحرارة المتحررة ، وتقوم دائرة كهربائية بقراءة التغير في المقاومة. ويمكن أن يتسمم العامل المساعد عند تلامسه مع كبريتيد الهيدروجين.

المتحسسات التي تعمل بتقنية الأشعة تحت الحمراء Infrared Sensors or IR Sensors:

 وتعمل بواسطة منظومة من المرسلات والمستقبلات  لتحسس هذا النوع من الغازات وخاصة الغازات الهيدروكاربونية ، حيث تكون المرسلات مصدر الضوء والمستقبلات هي متحسسات الضوء ، إذا كان الغاز ضمن مدى الرؤية فأنه سيتداخل مع طاقة البث الضوئي بين المستقبلة والمرسلة ، وبهذا تكون حالة الضوء هي التي تحدد وجود الغاز ونوعه.

طرق قياس الغازات السامة Toxic Gases Measurement

 المتحسسات الألكترو كيمياوية Electrochemical Sensors:

 

 أو ما يعرف بالخلايا والتي تستخدم بشكل كبير في تحسس غازات أول أوكسيد الكاربون carbon monoxide أو الكلورين chlorine أو أكاسيد النتروجين nitrogen oxides حيث تعمل عن طريق أشارات الأقطاب الكهربائية عند تحسس الغاز ، وتكون حساسة جداً فتقوم بإعطاء اشارات تحذير عن طريق التيار الكهربائي. وتكون هذه المتحسسات غالباً بشاشة عرض digital display.

تقنية أوكسيدات المعادن شبة الموصلة Metal Oxide Semiconductors MOS :

وتستخدم ايضاً لتحسس غاز  أول أوكسيد الكاربون وتعمل من خلال غشاء لتحسس الغاز مصنوع من القصدير أو أوكسيدات التنكستن tungsten oxides ، حيث يتفاعل هذا الغشاء الحساس مع الغازات  مما يسبب حدوث قدحة في الجهاز تجعله يطلق أشارة تحذير عند تحسس هذه الغازات ، وتكون المتحسسات التي تعتمد على هذه التقنية من أكفأ المتحسسات بسبب قابليتها على العمل في مناطق قليلة الرطوبة بالأضافة الى أنها قادرة على تحسس مدى واسع من الغازات بما فيها الغازات القابلة للأشتعال.

   وكما تبين في أعلاه فأن هناك العديد من أنواع متحسسات الغاز تستخدم في الصناعة ، ولكن أختيار المتحسس يعتمد على العوامل التالية:

 – نوع الغاز الذي سيتم تحسسه.

 – التركيز المتوقع للغاز.

 – هل سيتم تثبيت المتحسس أم سيكون متحركاً؟

 

 – وجود أنواع أخرى من الغازات التي قد تؤثر على المتحسس أو تسبب تضرره.

 عند تحديد حدود الأنذار Alarms للمتحسسات الثابتة ، يجب أخذ الأمور التالية بنظر الأعتبار:

  – المعايير الصناعية.

 – أقل نسبة للتركيز الذي يسبب الأنفجار low Explosion limit للغاز.

 – حجم التسرب المتوقع في المصنع ومدة وصوله الى الحالة الخطرة.

 – وجود الأشخاص في الموقع.

 – المدة المطلوبة للتجاوب مع هذا الأنذار.

 – الاجراءات الواجب أتخاذها بعد هذا الأنذار.

 – مدى سمية هذا الغاز.

 

وفي بعض المصانع تقوم متحسسات الغاز بعمل توقف أضطراري Emergency Shutdown عند وصول الغاز الى نسب خطرة.

استخدامات متحسسات الغاز :

   لها الكثير من الأستخدامات المختلفة بدءأ من البيوت وورش اللحام وأنتهاءاً بالمعامل العملاقة والمفاعلات النووية كما يستخدم ايضاً في معامل معالجة الماء الصناعي ، وتكون متحسسات الغاز أكثر كفاءة ً في المناطق المحصورة محدودة الحركة السكانية ، والتي قد تحتوي على خزانات أو أوعية.

 ورغم أن متحسسات الغاز هي تقنية يُعتمد عليها ، وأن بعض الموديلات منها قد تستمر بالعمل لأكثر من 5 سنين إلا أنها تعمل بشكل صحيح فقط عند القيام بصيانتها بشكل دوري ، وفحص البطاريات ومن ثم معايرة الجهاز.

أن معايرة الجهاز هي من أحسن الطرق لضمان عمل المتحسس وقراءته في المستوى المحدد من الغاز ، ويعتمد عمر متحسسات الغاز على كمية الغازات التي تتعرض اليها، حيث أن المتححسات المُشبعة بالغازات لن تتمكن من تحسس نسب الغاز الخطرة ، لذا يفضّل إجراء معايرة دورية على كل متحسسات الغاز. 

 

المصادر:

– the selection & use of flammable gas detectors

Surface Facilities in Oil & Natural Gas Production Part.3

المنشآت السطحية لأنتاج النفط والغاز الطبيعي – الجزء الثالث

 مثال لمنشآة غازية Gas Facility

في الشكل التالي نجد منشأة مثالية لمعالجة الغاز المصاحب. 

التسخين Heating :

أن آبار الغاز غالبا ما تكون عالية الضغط ذات ضغط أغلاق الأنابيب Shut-in tubing pressure يتراوح بي 5000 إلى15000 رطل لكل بوصة مربعة psi، وضغط جريان يزيد على 3000 رطل لكل بوصة مربعة. ويجب تخفيض هذا الضغط إلى ضغط مناسب لخط الأنابيب عند النقطة التي يتدفق الغاز فيها من خلال الصمام الخانق wellhead choke . وعندما يتم تخفيض ضغط الغاز فأن درجة حرارة الغاز تنخفض مما يؤدي الى تكثف السوائل وتكون الهيدرات Hydrates وهي مواد صلبة بلورية مكونة من جزيئات النفط والغاز والماء وتتشكل في وجود الغازات الهيدروكاربونية والماء في درجات الحرارة أعلى من نقطة أنجماد الماء. وهذه الهيدرات يمكن أن تسبب حصول أنسدادات في المامات الخانقة والتضيقات لذلك فأن الغاز يحتاج الى تسخين ، ويمكن ذلك من خلال أمرار الغاز في حمام مائي water bath للحفاظ على الماء من التجمد.

ويمكن منع تشكل الهيدرات عن طريق حقن مادة مذيبة Solvent مثل الميثانول في خط الجريان. وتطبق هذه الطريقة في الآبار البحرية حيث لا تتوفر أمكانية للتسخين أما الآبار ذات معدلات التدفق العالية فأن أستخدام الميثانول يكون غير مجد أقتصادياً ويجعل التسخين الخيار الأفضل.

Gas facilityGas facility

العزل Separation

توفر العازلة مساحة كافية للغاز للتحرر من النفط. ويتم تعيين ضغط العازلة أعلى من ضغط خط الأنابيب بحيث يمكن للغاز أن ينتقل الى الوحدات التالية من التبريد والمعالجة والتجفيف ومعالجة الغاز، حيث يحصل فرق ضغط pressure drop بين كل وحدة وأخرى للوصول إلى ضغط خط الأنابيب المطلوب.

التبريد Cooling

إذا كانت درجة حرارة الغاز مرتفعة لن يكون من الضروري تسخين الخط قبل عازلة HP . وإذا بقيت درجة الحرارة عالية فإن الغاز الساخن قد يسبب مشاكل التآكل بالإضافة إلى ذلك، فإن الغاز الساخن يحمل المزيد من بخار الماء، مما يستوجب منظومة تجفيف Dehydration اكبر وأكثر تكلفة بكثير مما لو تم تبريدها ، لذلك فمن الضروري في بعض الأحيان نصب وحدة لتبريد الغاز gas cooler للغاز الخارج من عازلة المرحلة الأولى ، ويمكن أستخدام التبريد بالهواء Aerial Cooler أو التبريد المباشر بالماء.

معالجة الغاز Gas Treating

 أن الغاز الطبيعي يحتوي العديد من الشوائب ، مثل H2S وCO2 والتي تسمى الغاز الحامضي Acid Gases .

 أن الغاز الذي يحتوي على غاز H2S يسمى Sour Gas وإذا كان الغاز لا تحتوي على غاز H2S أو إذا تمت إزالة H2S يسمى الغاز الحلو Sweet Gas . وتسمى هذه العملية ب(التحلية) Sweetening .

 أن H2S غاز شديد السمية.أما CO2 يمكن أن يشكل حامض قوي يسبب التآكل بوجود الماء ويمكن أن يسبب تسرباً خطراً. وهناك طريقة مشتركة لإزالة H2S وCO2 من الغاز الطبيعي وهي منظومة الأمين Amine System التي يستخدم فيها برج تلامس Contactor Tower ذو الصواني Trays أو الحشوة المنتظمةStructured Packing لتمرير الغاز الحامضي خلال الأمين السائل وتحقيق التلامس بينهما وبالتالي امتصاص غاز H2S وبعض من CO2. وبعدها يتم إعادة تنشيط الأمين في برج نزع Stripping tower حيث يتم إزالة H2S وCO2 من الأمين. وهناك طرق أخرى تستعمل المذيبات Solvents بطريقة الأمتزاز Adsorption

 تجفيف الغاز Gas Dehydration 

تستعمل لتجنب تكثف الماء في خط أنابيب الغاز مما يؤدي الى مشاكل التآكل وتكون الهيدرات Hydrates ، أن مواصفات خطوط الأنابيب تحدد عادة كمية بخار الماء في الغاز. وهناك مواصفات قياسية في معظم خطوط أنابيب الغاز في جنوب الولايات المتحدة تحدد هذه الكمية بـ 7 باوند ماء لكل مليون قدم مكعب قياسي من الغاز (LBM / MMscf. وهذا يتوافق مع نقطة الندى للماء بحوالي 32 درجة فهرنهايت في 1000 رطل / عقدة مربعة ، وفي المناطق الشمالية أو في المياه العميقة جدا التي تنخفض فيها درجات الحرارة خارج الأنابيب يمكن أن تكون النسبة أقل من ذلك حيث تصل الى 4 باوند لكل مليون قدم مكعب قياسي (حوالي نقطة ندى صفر درجة فهرنهايت في 1000 رطل / عقدة مربعة .

غالبا ما يتم إزالة الماء من الغاز باستخدام منظومات التجفيف بالكلايكول ، كما توجد طرق آخرى مثل التجفيف بالمواد المجففة الصلبة بأستخدام طريقة الامتزاز Adsorption، أو التجفيف بالأغشية .أن أغلب منظومات التجفيف عادة ما تستخدم تراي أثيلين كلايكول triethylene Glycol لامتصاص بخار الماء من الغاز. ويتم هذا في برج التلامس حيث يتدفق الكلايكول الجاف الى البرج وينزل خلال الصواني ليتلامس مع الغاز.

أن الغاز الجاف الذي يخرج من البرج يستخدم لتبريد الكلايكول المشبع قبل أن يدخل البرج ومن ثم يذهب الغاز الى منافذ البيع أو إلى مزيد من المعالجة للحصول على الغاز الطبيعي المسال. أما الكلايكول الرطب، الذي يخرج من الجزء السفلي من البرج فيتم تنشيطه في عملية مستمرة حيث يدخل الكلايكول إلى العازلة لإزالة الهيدروكاربونات المتكثفة ، ومن ثم يتم يتم تسخينه وإدخاله الى مرشحات filters قبل إرسالها إلى المسخنة reboiler أو وحدة تنشيط الكلايكول Glycol Regeneration حيث يتم تسخين الكلايكول إلى 390 – 400 درجة فهرنهايت ويتبخر الماء الموجود فيه حيث يتم تصريفه مباشرة الى الجو أو تبريده وتكثيفه لفصل كمية صغيرة من الأبخرة الهيدروكربونية من الماء. ثم يتم تبريد الكلايكول الساخن خلال مبادل حراري بواسطة الكلايكول البارد القادم من برج التلامس. وهذا المبادل يجعل العملية أكثر كفاءة ويسخن الكلايكول الذاهب الى المسخنة تسخيناً أولياً مما يقلل من صرفيات الطاقة.

معالجة الغاز Gas Processing :

يمكن معالجة الغاز الجاف لاسترداد المزيد من السوائل الهيدروكاربونية لتكوين الغاز الطبيعي المسال LNGs أو غاز البترول المسال LPG .أن الغاز الطبيعي المسال هو مجموعة من السوائل الهيدروكربونية مثل الإيثان والبروبان والبيوتان والغازولين الطبيعي والتي يمكن فصلها عن الغاز الطبيعي بعد فصل المكونات الهيدروكربونية الأثقل في درجة حرارة المحيط. أما غاز البترول المسال LPG فهو خليط من المواد الهيدروكربونية وبشكل أساسي البيوتان والبروبان والتي يمكن نقلها في صورة سائل تحت الضغط أو في درجات حرارة منخفضة جدا. وأمكانية تحويلها إلى الغاز عند تخفيض الضغط. أن الغاز الطبيعي المسال هو سائل معظمه من غاز الميثان الذي تم تسييله مما يجعل من السهل نقله في الانابيب .أن  العمليات الأكثر شيوعا التي تستخدم لفصل سوائل الغاز الطبيعي أو غاز البترول المسال هي الامتصاص ، والتبريد وغيرها ،  أما الغاز الخامل المتبقي  يمكن أستخدامه كوقود ، أو يعاد حقنه في المكمن.

عملية التركيز Stabilization: ويتم فيه إزالة الهيدروكربونات الخفيفة من السائل إما من خلال تقليل الضغط مما يؤدي الى تحرر العناصر الأخف أو من خلال عملية مركبة من خفض الضغط والتسخين. حيث يتم إزالة معظم الماء أثناء الفصل. والمكثفات الناتجة المستقرة ذو ضغط بخار منخفض جدا مما يجعل من الممكن تخزينه في خزانات لغرض شحنه تحت الضغط الجوي بواسطة الشاحنات والقطارات والمراكب أو السفينة بدون تنفيس البخار. في كثير من الأحيان فأن هناك تحديدات لضغط البخار لأغراض النقل.

عملية الكبس Compression:

أن المركبات الأخف التي يتم إزالتها في الطور الغازي خلال عملية التركيز تكون بضغط أقل من خط الغاز الرئيسي. وهذه المركبات يجب أن تضغط إلى ضغط عال بحيث يمكن معالجتها مع بقية الغازات.

التصميم الآمن Design Safety:

 إذا كانت منظومة السيطرة Process Control تعمل بشكل صحيح ، وقيام المشغلين باستخدام جميع الصمامات اليدوية Manual Valves بشكل صحيح ، فلن تكون هناك حاجة لنظام السلامة. ولكن تم الأخذ بنظر الأعتبار عطل وحدات السيطرة ، أو حدوث تسرب في الصمامات ، أو ارتكاب الأخطاء البشرية. وهنا تبرز أهمية منظومات السلامة  لمنع الضغط الزائد ، حدوث تضرر في المعدات ، حالات التسرب ، التلوث ، الحرائق أو إصابة الأفراد فهناك طريقة منهجية لضمان أن جميع معدات السلامة الضرورية في مكانها. ويوجد مستويان للحماية في منظومة السلامة: الابتدائي والثانوي.

الحماية الابتدائية Primary Protection :

 وهو عادة جهاز استشعار أو متحسس على المعدات يكشف عن حالة غير مرغوب فيها .على سبيل المثال، قد تحتوي المعدة على متحسس مستوى أو ضغط أو حرارة للكشف عن القيم غير المرغوب بها سواء كانت عالية جدا أو منخفضة جدا استناداً إلى الظروف التشغيل الأعتيادية. وعندما يتم الكشف عن حدث غير مرغوب فيه، لا بد من إيقاف تشغيل المعمل بشكل آمن لأيقاف التدفق الى هذه المعدة.

الحماية الثانوية Secondary Protection :

 في حالة فشل الحماية الأولية في العمل أو عملها ببطء شديد لتصحيح مشكلة ما ، فلابد من تواجد الحماية الثانوية والتي تتألف من صمام أمان PSV لمنع تراكم الضغط الزائد. وقد تم تصميم هذا الصمام للفتح وخفض الضغط الزائد في الأوعية أو الأنابيب من خلال أنبوب تجميع يسمى Relief Header والذي يقوم بنقل السوائل أو الغازات  إلى وعاء آمن لاسترجاعها أو التخلص منها. كما تتألف الحماية الثانوية تتألف من أجهزة الاستشعار مثل تلك التي تستخدم في الحماية الأبتدائية .

اوعلى سبيل المثال فأن العازلة Separator لها ضغط تصميمي Design Pressure أو ما يسمى (أعلى ضغط تشغيلي مسموح به) Maximum Allowable Working Pressure MAWP والذي يكون أكبر بما فيه الكفاية من الضغوط التشغيلية لمنع حدوث تقلبات صغيرة في العمل والتي تسبب الضغط الزائد داخل الوعاء. على سبيل المثال في عملية العزل على عدة مراحل Multi-Stage separation process يكون الضغط التشغيلي لكل عازلة أقل من ضغط الخط الداخل اليها. وهذا يسمح بخفض الضغط التصميمي أيضا. وعندما حصول التدفق من الضغط التصميمي الأعلى الى الضغط التصميمي الأقل فقد يؤدي هذا الى صعود ضغط خط الدخول وبالتالي يتوجب وضع ضغود تصميمية مختلفة للعازلات HP- MP – LP والأنابيب المرتبطة بها. مما يسبب حالة من الجيوب الغازية تعرف عادة باسم Gas Blowby وتحصل هذه الحالة عند فتح صمام تصريف السوائل (صمام السيطرة على المستوى) فتحة كاملة ، فإن السائل يتدفق من العازلة حتى يتعادل الضغط بين العازلتين ويجعل الضغط الداخل الى العازلة الثانية أعلى من ضغطها التصميمي. 

ويجب تصميم أنظمة السلامة لحماية المنظومة من الحالة المبينة في أعلاه. لذا تجهّز صمامات التنفيس عن الضغط Relief Valve من أجل حماية الأوعية من الضغط الزائد الناتج عن أنسداد خط التصريف لأي سبب كان. لذا يجب التحكم بكمية الجيوب الغازية أو منع حدوثها حيث يجب أحتساب التدفق إعتماداً على ضغط الدخول الى العازلة وعلى كمية التدفق في حالة فتح صمام التحكم فتحة كاملة ، كما يجب أخذ كمية التدفق عبر صمام الأمان عند الفتح بنظر الأعتبار . وفي حالة وجود فرق ضغط عالي بين العازلتين فأن هذا يؤدي الى زيادة الجيوب الغازية.

 

بالأضافة الى منطومات الحماية الأبتدائية والثانوية تتوفر منظومات توقف أضطراري Emergency Shut Down تتألف من متحسسات الغازات المشتعلة Combustible Gas detectors ومتحسسات الحريق Fire Detectors ومتحسسات الدخان Smoke Detectors ، بالأضافة الى منظومة تجميع السوائل الهيدروكاربونية التي تتسرب من أي نقطة من المنظومة ، مما يؤدي الى حدوث التوقف الأضطراري بالشكل الذي يضمن سلامة المنشآة النفطية أو الغازية.

المصادر :
Petroleum Engineering Handbook – Part 3 – Kenneth E. Arnold
Surface Production Operations – Ken Arnold/ Maurice Stewart

Natural Gas to Liquids GTL

GTL:

  • GTL means Gas to Liquids.
  • A whole range of fuels can be produced from Natural gas by partial oxidation to synthesis gas (a mixture of H2 and CO) and subsequent conversion of this gas • 1993 – Shell pioneered the GTL business at their Shell Middle Distillate Synthesis Plant in Bintulu.
  • In this plant Naphtha, Kerosene and Fischer Tropsch Diesel (FTD) were produced apart from other specialized products

how to convert natural gas to NGLGas to Liquids: A New Frontier for Natural Gas:

  • The relatively high world crude oil prices have drawn attention to the potential for developing previously uneconomical natural gas reserves, such as associated gas or stranded gas.
  • Converting these resources to liquids – either to liquefied natural gas (LNG) or to petroleum liquid substitutes, such as diesel, naphtha, motor gasoline, or other products (such as lubricants and waxes) by employing “gas to liquids” (GTL) technology – could provide a way to bring these gas resources to market.
  • GTL has recently become attractive as an option for monetizing stranded gas and complementing traditional commercialization opportunities such as LNG or pipeline transportation.

Gas to Liquid – Commercial Viability

NGL commercial

Gas to Liquids: Economics

  • The economics of GTL continue to improve with advances in technology and scale.

–        Capital costs have dropped significantly, from more than $100,000 per barrel of total installed capacity for the original plants to a range of $25,000 to $30,000 per barrel of capacity today.

–        Moreover, Royal/Dutch Shell has commented that it expects to be able to reduce the costs to below $20,000 per barrel.

–       By comparison, the costs associated with conventional petroleum refining are around $15,000 per barrel per stream day after several decades of technology improvements.

  • The high oil prices of recent years have made transportation fuels produced through GTL technology commercially viable.
    •          Few companies release the detailed costs of their GTL conversion technologies.
    •          According to ConocoPhillips, assuming that the cost of natural gas is $1.00 per million Btu, GTL fuel is cost competitive with diesel fuel at world oil prices above $20 per barrel.

GTL – FTD – Advantages:

  • Among the different GTL products, the diesel fraction is highly valued in the downstream market because of its unique properties that meet environmental regulations

–        The GTL fuel reduces emissions relative to conventional diesel, as it contains near-zero sulfur and aromatics.

–        GTL fuel also exhibits a high cetane number that enhances engine combustion performance

–        Because they are compatible with existing vehicle engines and fuel distribution infrastructures, GTL fuels are the most cost-effective in reducing emissions among the non-conventional fuels

Gas to Liquid Plants

At present, worldwide there are at least 9 commercial GTL projects at various stages of planning and development

  • for the period 2009 to 2012 that could bring to market an additional capacity of 580 thousand barrels per day.
  • More than 19 additional proposed projects could double that capacity beyond 2012
  • Initiated by companies operating in gas-rich countries – Qatar, Iran, Russia, Nigeria, Australia, and Algeria – where natural gas can be developed at a cost of less than $1.00 per million Btu.

Gas to Liquids – Major Initiatives

  • Qatar’s North Field, with an estimated 900 trillion cubic feet of natural gas reserves, and the adjoining South Pars field in Iran with an estimated 500 trillion cubic feet of reserves, are the cheapest natural gas resources in the world
  • For other countries, such as Nigeria and Algeria, GTL complements their LNG industries
  • offers promise for use in Nigeria to convert natural gas that would otherwise be flared.
  • Challenges

–        Huge capital investments

–        Project financing

–        Availability of qualified contractors and operators

Gas to Liquids –  Major Initiatives – Qatar

  • Qatar NGL projectsSix of the nine confirmed GTL projects are located in the state of Qatar as joint ventures

–        Based on an integrated development and production sharing agreement (DPSA) with major international oil companies.

–        Foreign companies have favored this approach, because it gives them an opportunity to book part of the gas reserves on their balance sheet and support their upstream and downstream activities

–        By 2011, Qatar is set to produce about 394,000 barrels of GTL products per day or 68% of total planned GTL capacity

  • Have established a favorable climate in terms of transparent business and investment policies.
  • Stable tax regulations
  • Enforcement of formal agreements
  • Government’s willingness to protect foreign investors through its legislature.
  • Stable political climate
  • Developed infrastructure and Service
  • Provides guarantees for the safety of foreign employees
  • Potential for future development through expansion of existing facilities.
    • Qatar reached agreements with a group of financial institutions to fund their gas-related projects in exceed $60 billion

    –        Developed a master plan to expand its port

    –        Double the size of Ras Laffan Industrial city from 39 square miles to 77 square miles,

    –        Accommodate 7 GTL projects, 16 LNG trains, 5 gas processing plants, 6 to 7 ethylene plants, and a variety of other gas-related industries.

    –        By 2012, Qatar must produce nearly 25 billion cubic feet of natural gas per day to support its commitments.

    –        10.3 bcf/day to produce 77 millions metric tons of LNG p. a

    –        4 bcf/day for the 394,000 barrels per day of GTL

    –        5 bcf/day for petrochemical, local power, and industrial projects

    –        2 bcf/day for exports through the Dolphin pipeline.

Effective and Relative Permeability

Mustafa AbdulSattar

          When there is only one type of fluid flowing through porous media, the permeability for this case is called “absolute permeability.” However, when there is more than one type of fluids present in a rock, a permeability of each fluid to flow is decreased because another fluid will be moving in the rock as well.  A new term of permeability called “effective permeability” is a permeability of a rock to a particular fluid when more than one type of fluid is in a rock

Reservoir consists of three fluids (gas, oil, and water) so these are commonly used abbreviations for effective permeability for each fluid.

  • kg = effective permeability to gas
  • ko = effective permeability to oil
  • kw = effective permeability to water

Normally, it is common to state effective permeability as a function of a rock’s absolute permeability. Relative permeability is defined as a ration of effective permeability to an absolute permeability of rock. The relative permeability is widely used in reservoir engineering. These functions below are the relative permeability of gas, oil, and water.

  • krg = kg ÷ k
  • kro = ko ÷ k
  • krw = kw ÷ k

k = absolute permeability

Oil-water relative permeability
Fig.1
relative permeability As water saturation (Sw) decreases
Fig.2

Relative permeability is normally plotted as a function of water saturation in a rock . Figure 1 demonstrates a plot of oil-water relative permeability curves.

As water saturation (Sw) decreases, relative permeability of oil (Kro) decreases and relative permeability of water increases (Krw). If water saturation is

below connate water saturation (Swc), only oil will flow, but water will not flow (Figure 2)

When water saturation (Sw) in a rock is equal to connate water saturation (Swc), water starts to flow (Figure 3) Water starts to flow at Swc

permeability when water saturation
Fig.3


Oil flow continues to decrease and water flow continues to decrease because the water saturation goes up. If water saturation (Sw) is between connate water saturation (Swc) and 1 minus Sor (irreducible oil saturation), both oil and water flow (Figure 4).

Once water saturation in a rock increases to 1 minus Sor (irreducible oil saturation), oil will not flow, but only water will flow. Beyond this point oil will not move at all but water will continue to increase as water saturation (Sw) in a rock increases (Figure 5).

permeability curve
Fig.4
permeabilty when there is no oil flow
Fig.5

Well Pressure Control

Basically all formations penetrated during drilling are porous and permeable to some degree.
Fluids contained in pore spaces are under pressure that is overbalanced by the drilling fluid pressure in the well bore.
The borehole pressure is equal to the hydrostatic pressure plus the friction pressure loss in the annulus. If for some reason the borehole pressure falls below the formation fluid pressure, the formation fluids can enter the well. Such an event is known as a kick. This name is associated with a rather sudden flowrate increase observed at the surface.

SURFACE EQUIPMENT
A formation gas or fluid kick can be efficiently and safely controlled if the proper equipment is installed at the surface. One of several possible arrangement of pressure control equipment . The blowout preventer (BOP) stack consists of a spherical preventer (i.e.,Hydril) and ram type BOPs with blind rams in one and pipe rams in another with
a drilling spool placed in the stack.
A spherical preventer contains a packing element that seals the space around the outside of the drill pipe. This preventer is not designed to shut off the well when the drill pipe is out of the hole. The spherical preventer allows stripping operations and some limited pipe rotation.

Hydril Corporation, Shaffer, and other manufactures provide several models with differing packing element designs for specific types of service. The ram type preventer uses two concentric halves to close and seal around the pipe, called pipe rams or blind rams, which seal against the opposing half when there is no pipe in the hole. Some pipe rams will only seal on a single size pipe; 5 in. pipe rams only seal around 5 in. drill pipe. There are also variable bore rams, which cover a specific size range such as 312 in. to 5 in. that seal on any size pipe in their range.
Care must be taken before closing the blind rams. If pipe is in the hole and the blind rams are closed, the pipe may be damaged or cut. A special type of blind rams that will sever the pipe are called shear blind rams.
These rams will seal against themselves when there is no pipe in the hole, or, in the case of pipe in the hole, the rams will first shear the pipe and then
continue to close until they seal the well. A drilling spool is the element of the BOP stack to which choke and kill lines are attached. The pressure rating of the drilling spool and its side outlets should be consistent with BOP stack. The kill line allows pumping mud into the annulus of the well in the case that is required. The choke
line side is connected to a manifold to enable circulation of drilling and formation fluids out of the hole in a controlled manner.
A degasser is installed on the mud return line to remove any small amounts of entrained gas in the returning drilling fluids. Samples of gas
are analyzed using the gas chromatograph.
If for some reason the well cannot be shut in, and thus prevents implementation of regular kick killing procedure, a diverter type stack is used rather, the BOP stack described above. The diverter stack is furnished with a blow-down line to allow the well to vent wellbore gas or fluids a safe distance away from the rig.

WHEN AND HOW TO CLOSE THE WELL
While drilling, there are certain warning signals that, if properly analyzed, can lead to early detection of gas or formation fluid entry into the wellbore.
1. Drilling break. A relatively sudden increase in the drilling rate is called a drilling break. The drilling break may occur due to a decrease in the difference between borehole pressure and formation pressure. When a drilling break is observed, the pumps should be stopped and the well watched for flow at the mud line. If the well does not flow, it probably means that the overbalance is not lost or simply that a softer formation has be encountered.
2. Decrease in pump pressure. When less dense formation fluid enters the borehole, the hydrostatic head in the annulus is decreased. Although reduction in pump pressure may be caused by several other factors, drilling personnel should consider a formation fluid influx into the wellbore as one possible cause. The pumps should be stopped and the return flow mud line watched carefully.
3. Increase in pit level. This is a definite signal of formation fluid invasion into the wellbore. The well must be shut in as soon as possible.
4. Gas-cut mud. When drilling through gas-bearing formations, small quantities of gas occur in the cuttings. As these cuttings are circulated up, the annulus, the gas expands. The resulting reduction in mud weight is observed at surface.
Stopping the pumps and observing the mud return line help determine whether the overbalance is lost.
If the kick is gained while tripping, the only warning signal we have is an increase in fluid volume at the surface (pit gain). Once it is determined that the pressure overbalance is lost, the well must be closed as quickly as possible. The sequence of operations in closing a well is as follows:
1. Shut off the mud pumps.
2. Raise the Kelly above the BOP stack.
3. Open the choke line
4. Close the spherical preventer.
5. Close the choke slowly.
6. Record the pit level increase.
7. Record the stabilized pressure on the drill pipe (Stand Pipe) and annulus pressure gauges.
8. Notify the company personnel.
9. Prepare the kill procedure.
If the well kicks while tripping, the sequence of necessary steps can be given below:

  1. Close the safety valve (Kelly cock) on the drill pipe.
    2. Pick up and install the Kelly or top drive.
    3. Open the safety valve (Kelly cock).
    4. Open the choke line.
    5. Close the annular (spherical) preventer.
    6. Record the pit gain along with the shut in drill pipe pressure (SIDPP) and shut in casing pressure (SICP).
    7. Notify the company personnel.
    8. Prepare the kill procedure.
    Depending on the type of drilling rig and company policy, this sequence of operations may be changed.

A formation fluid influx (a kick) may result from one of the following
reasons:
• abnormally high formation pressure is encountered
• lost circulation mud weight too low
• swabbing in during tripping operations
• not filling up the hole while pulling out the drill string
• recirculating gas or oil cut mud.
If a kick is not controlled properly, a blowout will occur.
A blowout may develop for one or more of the following causes:
• lack of analysis of data obtained from offset wells
• lack or misunderstanding of data during drilling
• malfunction or even lack of adequate well control equipment

References:
1. Drilling Equipment and Operation.
2. drilling Operation.