300 level report

7/31/2019 300 Level Report

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DEDICATION

This report is dedicated to God Almighty, who has made my dreams comethrough. To my Family, I say thank you all.


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CERTIFICATION

This is to certify that the students Industrial Work Experience Scheme[SIWES] was carried out by Ighoraye Gilda Akwekwe, at Chevron NigeriaLimited, Lagos and was duly supervised.


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CONTENTS

Dedication------------------------------------------------------------------------Certification-----------------------------------------------------------------------Abstract-----------------------------------------------------------------------------

Chapter 1-------------------------------------------------------------------------- 4Gas Wells--------------------------------------------------------------------------5Gas Properties---------------------------------------------------------------------6Gas Lifts---------------------------------------------------------------------------7Well Head and Manifold---------------------------------------------------------8

Chapter 2-------------------------------------------------------------------------- 9

Initial Separation Process------------------------------------------------------- 10Vertical Two-Phase Separators--------------------------------------------------11Horizontal Two-Phase Separators-----------------------------------------------12Comparison of Two- Phase Separator Types-----------------------------------13Horizontal Three-Phase Separators---------------------------------------------14Vertical Three- Phase Separators------------------------------------------------15Potential Operating Problem-----------------------------------------------------16


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ABSTRACT

This report is designed to serve as a summary of my experience throughoutthe successful period of my Industrial attachment at Chevron NigeriaLimited as required by Igbinedion University Okada, Edo State. I achievedpractical understanding of what was only theoretical trained in theUniversity.


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INTRODUCTION

Produced wellhead fluids are complex mixture of different compounds of hydrogen and carbon, all with different vapor pressures, and other physicalcharacteristics. As a well stream flows from the hot, high pressure petroleumreservoir, it experiences pressure and temperature reductions. Gases evolvefrom the liquids and the well stream changes in character.

The job of a production facility is to separate the well stream into threecomponents, typically called phases

OILGASWATER

And process these phases into some marketable products or dispose of themin an environmentally acceptable manner. Separators are used to separategas from liquid or water from oil.Usually the separated gas is saturated with water vapor and must bedehydrated to an acceptable level. This is normally done in a glycoldehydrator.

The oil and emulsion from the separators must be treated to remove water.Most oil contracts specify a maximum percent of basic sediment and water(BS&W) that can be in crude. Typical direct-fired heater-treaters are usedfor removing water from the oil and emulsion being treated.

Water treating can be done in horizontal or vertical skimmer vessels,floatation units, cross-flow coalesces/separators and hydro cyclones. Thewater that is produced with crude oil can be disposed of overboard in mostoff shores areas, or evaporated from pits in some locations onshore.

Any solids produced with the well stream must also be separated, cleaned,

and disposed off in a manner that does not violate environmental criteria.Facilities may include sedimentation basins or tanks, hydro cyclones, filters,etc.

Production facilities must also accommodate accurate measuring andsampling of the crude oil, done automatically by Lease Automatic CustodyTransfer (LACT) unit.


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CHAPTER ONE

GAS WELLS

Most oil wells in the early stages of their lives flow naturally to the surfaceand are called flowing wells. Flowing production means that the pressure atthe well bottom is sufficient to overcome the sum of losses occurring alongthe flow path to the separator. When this criterion is not met, natural flowends and the well die.

Wells may die for two main reasons either their flowing bottom holepressure drops below the total pressure losses in the well, or the oppositehappens and pressure losses in the well become greater than the bottom holepressure needed for moving the well stream to the surface.

The first case occurs when a gradual decrease in reservoir pressure takesplace because of the removal of fluids from the underground reservoir. Thesecond case involves an increasing flow resistance in the well generallycaused by

(a) An increase in the density of the flowing fluid as a result of decreased gas production or

(b) Various mechanical problems like a small tubing size, down whole

restrictions, etc. Surface conditions, such as separator pressure orflow line size, also directly impact total pressure losses and canprevent m well from flowing.

Artificial lifting methods are used to produce fluids from wells already deador to increase the production rate from flowing wells; and several liftingmechanisms are available to choose from. One widely used type of artificiallift method uses a pump set below the liquid level in the well to increase thepressure so as to overcome flowing pressure losses that occur along the flowpath to the surface.Other lifting methods use compressed gas, injected periodically below theliquid present in the well tubing and use the expansion energy of the gas todisplace a liquid slug to the surface. The mechanism works on a completelydifferent principle: instead of increasing the pressure in the well, flowingpressure losses are decreased by a continuous injection of high pressure gas


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into the well stream. This enables the actual bottom hole pressure to movewell fluids to the surface.

Preparing the Well for Installation

GAS PROPERTIES

The ability to calculate the performance of a gas producing system,including reservoir and the piping system, requires knowledge of many gasproperties at various pressures and temperatures. If the natural gas is incontact with liquids, such as condensate or water, the effect of the liquids ongas properties must be evaluated

IDEAL GASESThe understanding of the behaviors of gases with respect to pressure andtemperature changes is made clear by first considering the behavior of gasesat conditions near standard conditions of pressure and temperature; that is:

P = 14.7 psia = 101.325 kPa (SPE uses 100kPa)

T = 60F = 520R = 288.72K (SPE) uses 288KAt these conditions the gas is aid to behave ideally, and most of the earlygases was conducted at conditions approaching these conditions. An ideal

gas is defined as one in which:(1) The volume occupied by the molecule is small compared to thetotal gas volume

(2) All molecular collisions are elastic and(3) There are no attractive or repulsive forces among the molecules.

The basis for describing ideal gas behavior comes from the combinationof some of the so-called gas laws proposed by early experiments.

Early Gas Laws

Boyles Law. Boyle observed experimentally that the volume of an ideal gasis inversely proportional to the pressure for a given weight or mass of gaswhen temperature is constant. This may be expressed as

V 1 \ P or PV = constant


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Char les Law. While working with gases at low pressure, Charles observed

that the volume occupied by a fixed mass of gas is directly proportional to

its absolute temperature, or

V T or V \ T = constant.

Avogadros Law . Avog adros law states that under the same conditions of temperature and pressure.

As any amount of solids can reduce the life of your system (except for gaslift), it is important to remove as much as you can prior to Start-up. Youneed to ensure that you displace the well to the lowest sand content as

possible, to the smallest particle size Possible and at velocities that willeffectively transport solids.Some of the methods being used are described as follows:

Tubing Bailer : Stroking a large tubing pump-like bailer in the Verticalsection of the well with tailpipe hanging below in the Horizontal sectionpumps the sand to surface. Shallow wells with long horizontal sectionsrequire multiple replace outs of the pump, but was the cheapest cleanoutmethod.

Tubing Driven PCP : Rotating the tubing turns a bit and PCP effectivelylifts sand and fluid to surface, but requires high torque tubular (buttressthread).

Dual Concentric Coiled Tubing with Jet Pump : Nowsco (Canada) hasdeveloped a 2,100 m (6,900 ft) concentric CT system where the power fluidis pumped down the inner CT to power a jet pump. Sand and wellborefluids are produced up the annulus between the two coil tubing strings. Thiscontinuous system is used mainly for high rate long horizontal section well.

Gas LiftGas lifting uses natural gas compressed at the surface and injected in thewell stream at some down hole point. In continuous flow gas lift, a steadyrate of gas is injected in the well tubing, aerating the liquid and thusreducing the pressure losses occurring along the flow path. Due to thisreduction in flow resistance of the well tubing, the wells original bottom


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hole pressure becomes sufficient to move the gas/liquid mixture to thesurface and the well starts to flow again. Therefore continuous flow gaslifting can be considered as the continuation of flowing production.

In intermittent gas lift, gas is injected periodically into the tubing stringwhenever a sufficient length of liquid has accumulated at the well bottom. Arelatively high volume of gas injected below the column pushes that columnto the surface as a slug. Gas injection is then interrupted until a new liquidslug of the proper column length builds up again. Production of well liquids,therefore, is done by cycles. The plunger-assisted version of intermittent gaslift uses a special free plunger travelling in the well tubing to separate theupward-moving liquid slug from the gas below it.These versions of gas lift physically displace the accumulated liquids fromthe well, a mechanism totally different from continuous flow gas lifting.

GAS LIFT SURFACE FACILITIES(Figure 1.1 ) shows the main elements of a surface gas lift system, beginningwith production at the wellhead and ending with the injection of gas into thecasing annulus or tubing.Starting at the wellhead, produced fluids travel first to the separator. Theseparator gas is usually re-used as lift gas. If more gas is produced than isneeded for gas lift, the excess gas is either sold or re-injected into theformation.

Moving downstream, there is a point where outside supply may be added tothe system if the gas from the separator is not sufficient to meet the demand.Both the separator gas and the outside makeup gas flow through a scrubber,where impurities are removed.

The gas next moves to the compressor, where gas pressure is raised todesired levels. The compressor must provide the appropriate dischargepressure and volume needed at both average and peak rates. Some of the gasreaching the compressor is normally used as fuel.

Downstream of the compressor, gas is metered and various controls areintroduced before the gas is injected into the annulus.In the case of continuous injection, the control is normally a choke in serieswith a pressure regulator.For intermittent gas injection, a time-cycle controller or choke is the mostcommon form of control.


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GAS LIFT SURFACE FACILITIESIt is clear that the surface system consists of a number of individualcomponents, each of which must be designed to provide the quantities andpeak demands of gas for the gas lift system at the desired injection pressures.It is also easy to see that the ideal gas lift system, especially with respect tothe compressor operation, is one that has a constant suction pressure andconstant discharge pressure on the compressor.

This is easy to achieve in continuous flow operations, because of thecontinuous supply of gas available from the separator and because of theneed to continuously inject gas. Intermittent systems are more complicatedwith intermittent injection and production - the duration of which may varyfor each well.Control is more difficult with time-cycle control than for choke control

because with the choke, the annulus serves as a storage chamber between liftcycles.

Data CollectionThe first step in designing surface facilities for a gas lift installation is tocollect the following data:l Number and location of wells requiring gas liftl Gas lift valve design for each welll Whether continuous or intermittent injection will be usedl Gas volumes needed (along with estimates of peak demand)l Availability of gas supply from the separator or external supplyl Location of sales gas linesl Pressure required at the point of injection into the welll Pressure of the separator or supply gasl Sizing of the compressorl Auxiliary control and metering system required for the surface system.Calculating Compressor HorsepowerThe compressor is a major component of a gas lift system. Compressors areavailable in many different sizes and horsepower ratings to handle different

gas lift operating conditions.An approximation for determining a compressors brake horsepower (bhp),is given by the equation(1)where n = number of stagesQ = gas throughput capacity, MMCFD (106SCF/D)(Pdischarge/Psuction ) = overall absolute compression ratio


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1.05 =correction factor for pressure drop and gas cooling between stages(For a single-stage compressor, the correction factor reduces to 1.0)

The quantity , which represents the absolute compression ratio per stage,should not be greater than 4.

Example:Find the horsepower needed to move 2500 MCFD (2.5 MMCFD) through a2-stage compressor with 50 psi suction pressure and 200 psi dischargepressure.First, find the absolute compression ratio per stage:Continue with Equation 1 as follows:bhp = 1.05x 23 x 2 x 2 x 2.5 = 241.5 hp => use a 250 hp compressorTo solve the problem using a single stage compressor , the solution would

be:bhp = 1.00 x 23 x 1 x 2.5 .4 = 230 hp.

Design Safety Factors

For the surface gas lift system to have enough capacity, it is customary toestimate a mainline pressure that is approximately 100 psi higher than iscalled for in the design. This additional pressure will accommodateunexpected line losses. In addition, the compressor delivery volume isusually increased by10% to account for volume losses and the fuel neededfor compression.

SUMMARY OF DESIGN PROCEDURES

We may summarize the procedure for designing a surface system for gas liftinstallation as follows:1. Begin by laying out the entire surface system, including the wells,gathering lines, stock tanks, separators, and other items of equipment that

materially affect gas lift operations.2. Specify the wells that will use either continuous or intermittent gaslift. Also consider the time during which each well will use gas lift.3. Design the gas lift system for each well, specifying the pressures, thevolume, the cycles, and the expected life of the gas lift operation for thatwell. This is a key element of the design because it provides the pressures,volumes, and cycles to which the system must respond over time.


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4. Make production estimates, including the gas volumes and pressures thatwill be available from the separator. These volumes and pressures serve asinput for the compressor calculations.5. Specify the gas sales and makeup volumes needed, along with theiravailability.6. Design the balance of the surface system, including the gathering linesand the control system.7. Design the system compressor. A reasonably accurate measure of therequired horsepower can be calculated; however, it is advisable to discussthese estimates with the manufacturer to ensure that the final design willmeet the needs of the gas lift system.8. Finally, remember to include a volume safety factor of 10% and apressure safety factor of 100 psi.

This procedure can be used in a preliminary design of a gas lift system. Thispreliminary design should be reviewed with the representatives of a gas liftequipment manufacturer. The optimized final design will be one thatsatisfies all the requirements of the system without being over-designed.

Comparison of Lift Methods

Although there are some other types of artificial lift known, their importanceis negligible compared to those just mentioned. Thus, there are a multitudeof choices available to an Engineer when selecting the type of lift to be used.

Some of the possible types may be ruled out by field conditions such as Well depth, Production rate Fluid properties, etc.

Still in general, more than one lifts systems turns out to be technicallyfeas ible. It is then the production engineers responsibility to select the typeof lift that provides the most profitable way of producing the desired liquidvolume from the given well(s). After a decision is made concerning thelifting method to be applied, a complete design of the installation for initialand future conditions should follow.


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WELL HEAD AND MANIFOLD

The production system begins at the wellhead, which should include at leastone choke, unless the well is on artificial lift. Most of the pressure dropbetween the well flowing tubing pressure (FTP) and the initial separatoroperating pressure occurs across this choke.

On offshore facilities and other high-risk situations, an automatic shutdownvalve should be installed on the wellhead. Block valves are needed so thatmaintenance can be performed on the choke if there is a long flow line.

Whenever flows from two or more wells are commingled in a centralfacility, it is necessary to install a manifold to allow flow from any one well

to be produced into any of the bulk or test production system.

Well Selection Before taking fluid samples, it is essential to follow proper well selectionand conditioning procedures. This includes sampling wells at the appropriatestage of production. We may sample non-retrograde gas reservoirs at anytime during their production. We may sample retrograde reservoirsperiodically throughout their lives as well, but only those samples taken

before reservoir pressure falls below the dew point line are representative of the original reservoir fluid. Because windowed cell studies are necessary todetermine whether a reservoir fluid is retrograde or wet gas, all wells thatproduce liquid hydrocarbons should be sampled early in their productionlives.

In large reservoirs, fluid composition may vary with location. Samplesshould therefore come from several wells throughout the field.Gas wells, with few exceptions, are sampled at the surface (unlike some oilwells, which are sampled down hole).

The wells selected for sampling must have relatively constant productionrates, without periodic interruptions due to fluid loading. They must haveproperly sized tubing strings, pumps or other lifting devices to keep themUnloaded at sampling conditions . (Sampling conditions may not necessarilybe identical to producing conditions.)


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This ensures that the sample container contents are equivalent to the fluidentering the well from the reservoir. The wells being sampled must haveappropriate sample points, either at the wellhead (for dry gas wells), or at theseparator (for wells that produce liquids). These sample points should belocated in pipe sections having a constant flow rate and minimumturbulence. Gas samples should come from taps located at the top of ahorizontal pipe section, and NGL samples should come from vertical pipesections if NGL is collected from a horizontal section, a static mixer shouldbe installed upstream of the sample point.

Liquid-producing wells must have adequate metering capacity to allow foraccuracy in subsequent mathematical or physical recombination. To achievethese objectives, it may be necessary to set a test separator at the well Priorto sampling.

The engineer should review well logs and completion records to confirm thatthe sample comes from the expected source.

The individual components of the electrical submersible centrifugalpumping are listed as follows:

Motor:The electrical submersible motor is usually a 3-phase, induction type, whichis oil-filled for cooling and lubrication. A high starting torque enables themotor to reach full load operating speed of approximately 3500 RPM in lessthan 15 cycles thus reducing drag on the power supply. The well fluid servesas the cooling agent. Therefore, the unit is installed above the perforations.

Protector:The protector is located between the pump and motor. Its main purpose is toisolate the motor from the well fluid. The protector is designed to allowpressure equalization between the intake pressure and the motor's internalpressure. The unit will permit expansion or contraction of the motor oil dueto thermal expansion. Two mechanical seals provide dual protection as a

barrier against fluid migrating along the shaft. The protector also houses amarine-type thrust bearing which absorbs axial loading from the pump.

Intake (and perhaps a Gas Separator): The pump intake is a bolt-on section between the protector and the pump. Itmay also have a gas separator which is designed to separate a greater portionof any free gas in the produced fluid.


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Pump:Submersible pumps are multi-staged centrifugal pumps. Each stage consistsof a rotating impeller and a stationary diffuser. The type of stage useddetermines the volume of fluid that the pump can deliver. The number of stages determines the total head generated and horsepower required. Eachstage contributes its share of the total head developed.

Power Cable:Power to the motor is transmitted by an electrical cable especially designedfor oil field application. A range of conductor sizes permits efficientmatching to motor requirements. Round and flat cables are available, andflat cable is usually used where clearance is a problem.Figure 1.3 Submersible Centrifugal Pumping Unit.


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CHAPTER TWO

INITIAL SEPARATION PROCESS

Because of the multi component nature of the produced fluid, the higher thepressure at which the initial separation occurs, the more liquid will beobtained in the separator. This liquid contains some light components thatvaporize in the stock tank downstream of the separator. If the pressure forinitial separation is too high, too many light components will stay in theliquid phase at the separator and be lost to gas phase at the tank. If thepressure is too low, not as many of these light components will be lost to thegas phase. Figure 2

This phenomenon can be calculated using flash equilibrium techniques. Thetendency of any one component in the process stream to flash to the vaporphase depends on its partial pressure. The partial pressure of a component ina vessel is defined as the number of molecules of that component in thevapor space divided by the total number of molecules of all components inthe vapor space times the pressure in the vessel.

Thus, if the pressure in the vessel is high, the partial pressure for thecomponent will be relatively high and the molecules of that component will

tend toward the liquid phase. As the separator pressure is increased, theliquid flow rate out of the separator increases.

The problem with this is that many of these molecules are the lighterhydrocarbons (methane, ethane, and propane), which have a strong tendencyto flash to the gas state at stock-tank conditions (atmospheric pressure).

In the stock-tank, the presence of these large numbers of molecules creates alow partial pressure for the intermediate-range hydrocarbons (butanes,pentane, and heptanes) whose flashing tendency at stock tank conditions isvery susceptible to small changes in partial pressure.

Thus by keeping the lighter molecules in the feed to the stock tank, wemanage to capture a small amount of them as liquids, but we lose to the gasphase many more of the intermediate-range molecules. That is why beyond


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some optimum point there is actually a decrease in stock-tank liquids byincreasing the separator operating pressure.

2.1Vertical Two-Phase Separators

Figure 2.1 is a simplified schematic of a typical vertical separator.In this configuration the flow stream enters the vessel through an inlet on theside. As for the horizontal separator, an inlet diverter does the initial grossseparation of liquid and gas. The liquid flows down to the liquid collectionsection of the vessel and through this section to the liquid outlet. As themixture reaches equilibrium at the separator pressure and temperature,evolved gas bubbles raise upward, counter to the direction of the liquidFlow, and eventually reach the vapor space. The level controller and liquid

dump valve operate the same as in a horizontal separator, sensing liquidlevel and adjusting it accordingly.

In a vertical separator, the gas flows over the inlet diverter and thenvertically upward toward the gas outlet, rather than horizontally. In thegravity-settling section the liquid drops fall vertically, counter to the upwardgas flow. Upon reaching the top of the vessel, the gas goes through thecoalescing/mist eliminator section before it leaves the vessel, extractingadditional liquids. Pressure is maintained as in a horizontal separator, using aVertical Two-Phase Separators pressure controller to adjust gas flow andregulate vessel pressure.

2.2Horizontal Two-Phase SeparatorsFigure 2.2 is a simplified schematic of a typical horizontal separator.

The fluid enters the separator and hits an inlet diverter which produces asudden change in the fluid's velocity and direction. The initial gross

separation of liquid and vapor occurs at this point. The force of gravitycauses the heavier liquid droplets to fall out of the gas stream to the bottomof the vessel, where the liquid is collected. This liquid collection sectionholds the liquid during the appropriate retention time required to letdissolved gas evolve out of the oil and rise to the vapor space. This sectionalso provides a surge volume, if necessary, to handle intermittent slugs of liquid. The separated liquid then leaves the vessel through the liquid dump


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valve, which is regulated by a level controller. The level controller senseschanges in liquid level and controls the dump valve accordingly.

The separated gas flows over the inlet diverter and then horizontally throughthe gravity-settling section above the liquid. As the gas flows through thissection, small drops of liquid that were entrained in the gas and notseparated by the inlet diverter are separated out by gravity and fall to thegas-liquid interface. Some of the drops are of such small diameter that theyare not easily separated in the gravity-settling section.

However, before the gas leaves the vessel it passes through a coalescingsection or mist eliminator. In this section, metal vanes, wire mesh, or closelyspaced plates are used to coalesce the very small droplets of liquid and causethem to fall into the liquid-collection section.

The pressure in the separator is maintained by a pressure controller. Thepressure controller senses changes in the pressure in the separator and sendsa signal to either open or close the pressure control valve accordingly. ByControlling the rate at which gas leaves the vapor space of the vessel thepressure in the vessel is controlled.Normally, horizontal separators are operated half full of liquid to maximizethe surface area of the gas-liquid interface. However, in places such as theMiddle East, where very large separators are found, these vessels may beoperated considerably less than half full.

Comparison of Two-Phase Separator Types

Horizontal separators are normally more efficient at handling large volumesof gas. This is because in the gravity settling section of the vessel the liquiddroplets fall perpendicular to the direction of gas flow and thus are moreeasily settled out of the continuous gas phase. Also, since the gas-oilinterface surface area is larger in a horizontal separator than a vertical

separator of the same capacity, it is easier for the gas bubbles, which comeout of solution as the liquid approaches equilibrium, to reach the vaporspace. So, speaking strictly from a gas-liquid separation standpoint,horizontal separators would be preferred. However, they do have severaldrawbacks that could lead to preference for a vertical separator in certainsituations.


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Horizontal separators are not as efficient as vertical separators in thehandling of produced solids. The liquid dump of a vertical separatorcan be placed at the center of the bottom head so that solids will notbuild up in the separator but will be flushed to the next vessel in thefacility. Alternatively, a drain could be placed at this location so thatthe sand, clay, and so forth, could be;

removed periodically, while clean liquid left the vessel at a slightlyhigher elevation;

In a horizontal vessel, it is necessary to place several drains along thelength of the vessel, spaced at very close intervals. Attempts tolengthen the distance between drains, by providing sand jets in thevicinity of each drain to fluidize the solids while the drains are inoperation, are expensive and have been only marginally successful infield operations;

Horizontal vessels require more plan area than a vertical vessel withthe same capacity. While this may not be of importance at a landlocation it could be very important on offshore production platforms,where space is at a premium. On the other hand, horizontal vesselsmay fit more easily in cramped lower decks and underneath heliports;

Small and moderate size horizontal vessels generally have less liquidsurge capacity, that is, they handle large slugs of liquid less efficientlythan vertical separators. The geometry of a horizontal vessel requiresany high-liquid-level shutdown device to be located close to thenormal operating level. In a vertical separator the shutdown could beplaced much higher, allowing the level controller and dump valvemore time to react to the surge. In addition, surges in horizontalvessels can create internal waves that might activate a high-levelsensor.

All of these factors cause the horizontal separator to function erraticallywhen slugs of liquid are present in the flow stream. These problems are notnecessarily severe in the case of large horizontal separators; particularlythose operated less than half full.

It should be pointed out that vertical vessels also have somedrawbacks that are not process-related but must be considered inmaking a selection. These are:

The relief valve and some of the controls may be difficult to servicewithout special ladders and access platforms.


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The vertical vessel may have to be removed from a productionequipment package (often called a "skid") when height restrictions foroverland truck transportation require it to be shipped horizontally.

In general, however, horizontal vessels are the most economical for normaloil-gas separation, particularly where there may be problems-withemulsions, foam, or high gas-oil ratios. Vertical vessels work mosteffectively in either low gas-oil ratio applications or in very high gas-oilratio applications (such as compressor scrubbers) where only liquid mists arebeing removed from the gas.

2.3Horizontal Three-Phase SeparatorsThree-stage separation

Three phase separators in the oil and gas production industry are used toseparate gas, oil and water phases .Three-phase separation involves gas/liquid separation like two phases, butalso involves liquid/liquid separation.This section concentrates on the design concepts involved in liquid/liquidseparation. When oil and water are mixed with some intensity and thenallowed to settle, a layer of relatively clean free water will appear at thebottom. The growth of this water layer with time will follow a curve asshown in Figure 2.3

After a period of time, ranging anywhere from three minutes to twentyminutes, the change in the water height will be negligible. The waterfraction, obtained from gravity settling, is called " free water ." It is normallybeneficial to separate the free water before attempting to treat the remainingoil and emulsion layers. Flow to the separator may be directly from aproducing well or wells. In this case, significant amounts of gas may bepresent and are separated from the oil. Three phase separators are designedto separate the free water phase from the oil and the gas phase from the

oil . If the flow to the separator originates in upstream separators operating athigher pressures, then the three-phase separator will need to handle only theflash gases. Separators in this service are often called free water knockouts .

The basic design aspects of three phase separation are identical to thosediscussed for two phase separation. The only additions are that more concernis placed on liquid-liquid settling rates, and that some means of removing the


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Free water must be added.

Because of the multi component nature of the produced fluid, it can beshown by flash calculations that the more light components will be stabilizedinto the liquid phase. This can be understood qualitatively by realizing thatin a stage separation process the light hydrocarbon molecules that flash areat relatively high pressure, keeping the partial pressure of the intermediatehydrocarbons lower at each stage.

Figure 2.3(a) is a schematic of a horizontal three-phase separator.

The fluid enters the separator and hits an inlet diverter. This sudden changein velocity and direction is responsible for the initial gross separation of

liquid and vapor, as explained in the discussion on two-phase separators. Insome designs, the inlet diverter contains a down comer that directs the liquidflow below the gas-oil interface and to the vicinity of the oil-water interface.The size of the liquid-collecting section of the vessel must provide sufficienttime for the oil and emulsion to form a layer or "oil pad" at the top. The freewater settles to the bottom.Figure 2.3(a) shows a typical horizontal separator with an interfacecontroller and weir

The weir maintains the oil level and the interface controller maintains thewater level. The oil is skimmed over the weir and the level of the oilDownstream of the weir is controlled by a level controller that operates theoil dump valve. The produced water flows from the vessel upstream of theoil weir. An interface level controller senses the height of the oil-waterInterface. The controller sends a signal to the water dump valve, thusallowing the correct amount of water to leave the vessel so that the oil-waterinterface is maintained at the design height.Evolved gas flows horizontally through the vessel and out through a misteliminator to a pressure controlled valve that maintains vessel pressure.

The level of the gas-oil interface can vary depending on the relativeimportance of gas-liquid separation. The most common configuration is avessel that is operated half full, giving the maximum amount of gas-oilsurface area.

Figure 2.3(b) shows an alternate configuration known as a "bucket and weir"design.


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This design eliminates the need for a liquid interface controller. Both the oiland water flow over weirs where level control is accomplished by a simpledisplacer float. The oil overflows the oil weir into an oil bucket where itslevel is controlled by a level controller that operates the oil dump valve. Thewater flows under the oil bucket and then over a water weir. The leveldownstream of this weir is controlled by a level controller that operates thewater dump valve.The height of the oil weir controls the liquid level in the vessel. Thedifference in height of the oil and water weirs controls the thickness of theoil layer as it floats on top of the water layer, due to specific gravitydifferences. It is critical to the operation of the vessel that the water weirheight be sufficiently below the oil weir height so that the oil pad thicknessallows sufficient oil retention time. If the water weir is too low and the

difference in specific gravity is not as great as anticipated, then the oil padcould grow in thickness to a point where oil will be swept under the oil boxand out the water outlet. Normally, either the oil or the water weir isadjustable so that changes in oil-water specific gravities or flow rates can beaccommodated.

If we compare these two types of horizontal three-phase separators, we seethat interface control has the advantage of being easily adjustable to handleunexpected changes in the specific gravity or flow rates of oil or water.However, in heavy oil applications or where large amounts of emulsion orparaffin are anticipated, the interface level may be difficult to sense. In sucha case, the bucket and weir design is recommended.


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Water Droplet Size in Oil

It is difficult to predict the water droplet size which must be settled out of the oil phase to coincide with the rather loose definition of "free oil." Unlesslaboratory or nearby field data is available, good results have been obtainedby sizing the oil pad such that water droplets 500 microns and above settleout. If this criterion is met, the emulsion to be treated by downstreamequipment should contain less than 5 to 10 percent water. In heavy crude oilsystems, it is sometimes necessary to design for 1000 micron water dropletsto settle. In such cases, the emulsion may contain as much as 20 to 30percent water.

Oil Droplet Size in Water

It can be seen that the separation of oil droplets from the water is easier thanthe separation of water droplets from the oil. The oil's viscosity is often onthe order of 5 to 20 times that of water. Therefore, the terminal settlingvelocity of an oil droplet in water is much larger than that of a water dropletin oil. The primary purpose of three-phase separation is to prepare the oil forfurther treating. Field experience indicates that oil content in the produced

water from a three phase separator, sized for water removal from oil, can beexpected to be between a few hundred and 2,000 mg/l. This water willrequire further treating prior to disposal and the reader should refer to thepresentation on Treating Oil from Produced Water.

Occasionally, the viscosity of the water phase may be as high as, or higher,than the liquid hydrocarbon phase viscosity. For example, large glycoldehydration systems usually have a three phase flash separator. Theviscosity of the glycol/water phase may be rather high. In cases like this, thesettling equation should be applied to removing oil droplets of

approximately 200 microns from the water phase.

If the retention time of the water phase is significantly less than the oilphase, then the vessel size should be checked for oil removal from the water.For these reasons, the equations are provided so the water phase may bechecked. However, the separation of oil from the water phase rarely governsthe vessel size, and may be ignored for most cases.


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Retention Time

A certain amount of oil storage is required in the separator to ensure that theoil reaches equilibrium and flashed gas is liberated. An additional amount of storage is required to ensure that the free water has time to coalesce intodroplet sizes sufficient to fall in accordance with Equation (1). It is commonto use retention times ranging from three minutes to thirty minutes,depending upon laboratory or field data. If this information is not available,an oil retention time of five minutes is suggested for design. Generally, theretention time must be increased as the oil gravity or viscosity increases.

Similarly, a certain amount of water storage is required to ensure that mostof the droplets of oil entrained in the water have sufficient time to coalesceand rise to the oil/water interface. It is common to use retention times for the

water phase ranging from three minutes to thirty minutes dependingupon laboratory or field data. If this information is not available, a waterretention time of five minutes is recommended for design.

SELECTION CRITERIA

Horizontal separators are normally more efficient at handling large volumesof gas than vertical separators. In the gravity-settling section of the vessel,

the liquid droplets fall perpendicular to the gas flow, and, thus, are moreeasily settled out of the gas-continuous phase. Also, since the interface areais larger in a horizontal separator than a vertical separator, it is easier for thegas bubbles, which come out of solution as the liquid approachesequilibrium, to reach the vapor space. Thus, from a pure gas/liquidseparation viewpoint, horizontal separators would be preferred. However,they do have several drawbacks, which could lead to a preference for avertical separator in certain situations.

Horizontal separators are not as good as vertical separators in handlingsolids . The liquid dump of a vertical separator can be placed at the center of the bottom head so that, solids will not build up in the separator but continueto the next vessel in the process. As an alternate, a drain could be placed atthis location so that solids could be disposed off periodically while liquidleaves the vessel at a slightly higher elevation. In a horizontal vessel, it isnecessary to place several drains along the length of the vessel. Since thesolids will have an angle of repose of 45 to 60, the drains must be spaced


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at very close intervals. Attempts to lengthen the distance between drains, byproviding sand jets in the vicinity of each drain to fluidize the solids whilethe drains are in operation, are expensive and have been only marginallysuccessful in field operations.

Horizontal vessels require more plan area (horizontal cross-section) toperform the same separation as vertical vessels. While this may not be of importance at an onshore location, it could be very important offshore. If several separators are used, however, this disadvantage may be overcome bystacking one horizontal separator on top of another.

Most horizontal vessels have less liquid-surge capacity . For a given changein liquid surface elevation, there is typically a larger increase in liquidvolume for a horizontal separator than for a vertical separator sized for the

same flow rate.

However, the geometry of most horizontal vessels causes any high-levelshutdown device to be located close to the normal operating level. In verylarge diameter (greater than 1.8 m (6 ft)) horizontal vessels and in verticalvessels, the shutdown could be placed much higher, allowing the levelcontroller and dump valve more time to react to the surge. In addition,surges in horizontal vessels could create internal waves, which couldactivate a high level sensor prematurely.

Care should be exercised when selecting small-diameter horizontalseparators. The level controller and level switch elevations must beconsidered. The vessel must have a sufficiently large diameter so that thelevel switches may be spaced far enough apart, vertically, to avoid operatingproblems. This is particularly important if surges in the flow or slugs of liquids are expected to enter the separator.

It should be pointed out that vertical vessels have some drawbacks which arenot process-related and which must be considered in making a selection. Forexample, the relief valve and some of the controls may be difficult to servicewithout special ladders and platforms. The vessel may have to be removedfrom a skid for trucking due to height restrictions.

Overall, horizontal vessels are most economical for normal oil-gasseparation, particularly where there may be problems with emulsions, foam,or high gas-oil ratios (GOR). Vertical vessels work most effectively in low-GOR applications. They are also used in some very high-GOR applications,


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such as scrubbers in which only fluid mists are being removed from the gasand where extra surge capacity is needed to allow a shutdown to activatebefore liquid is carried out the gas outlet (e.g., compressor suction scrubber).

The advantages of horizontal separators are:

They are generally more efficient at handling large volumes of gas; They fit more easily in cramped deck space with a low ceiling; Their safety relief valves and controls are generally more accessible

(except in the case of very large vessels) ; They may not require disassembly for overland truck transportation.

The disadvantages of horizontal separators are:

They are generally not as efficient as vertical separators in thehandling of produced solids; They require more plan area than a vertical vessel with the same

capacity and this could be a problem when space is at a premium; They generally have less liquid surge capacity.

2.4Vertical Three-Phase Separators

The flow stream enters the vessel through the side as in the horizontalseparator, and once again the inlet diverter separates the bulk of the gasFigure 2.4 a down comer is required to transmit the liquid through the oil-gas interface so as not to disturb the oil-skimming action taking place. Achimney is needed to equalize the gas pressure between the lower liquid-collection section and the upper gravity-settling section.

The spreader, or down comer outlet, is located beneath the oil-waterinterface. As the oil rises from this point, any free water trapped within the

oil phase separates out. The water droplets flow downward and any oildroplets trapped in the water phase tend to raise countercurrent to the waterflow.Sometimes a cone bottom three-phase separator is used. This design isapplicable when you anticipate that sand production will be a majorproblem. Normally, the cone is shaped at an angle between 45 and 60


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because produced sand has a tendency to rest on steel at angles less than 45.Figure 2.41If a cone is installed it could be part of the pressure-containing walls of thevessel or, for structural reasons, it could be installed inside the vesselcylinder. In such a case, a gas-equalizing line would have to be installed toInsure that the vapor behind the cone was always in pressure equilibriumwith the vapor space.The first method(a) Is for level control alone. A regular displacer float is used to control thegas-oil interface and to regulate a control valve for dumping oil from the oilsection. An interface float is used to control the oil water interface and toregulate a water outlet control valve. Because no internal baffling or weirsare used, this system is the easiest to fabricate and is best for handling sandand solids production.

Method (b) uses a weir to maintain the gas-oil interface level in a constantposition. This results in a better separation of water from the oil, since all theoil must raise to the height of the oil weir before leaving the vessel.Its disadvantages are that the oil box takes up space and increases the cost of fabrication. In addition, collected sediment can be difficult to drain from theoil box and a separate low-level shutdown may be required to guard againstthe oil dump valve failing.The third method (c) uses two weirs, which eliminates the need for aninterface float. The interface level Figure 2.42 is controlled by the height of the external water weir relative to the oil weir or outlet height. This is similarto the Bucket and weir design for horizontal separators. The advantage of this system is that it eliminates the need for an interface level control; thedisadvantage is that it requires additional external piping and space.

As in two-phase separation, in three-phase separation the flow geometry in ahorizontal vessel is more favorable from a process standpoint. However, asbefore, there may be no process-related reasons for selecting a verticalVessel for a specific application.

Figure 2.43(a) and Figure 2.43 (b) show the three different methods of control that are often used on vertical three-phase separators.

POTENTIAL OPERATING PROBLEMSFoamy Crude


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The major causes of foam are impurities, other than water, in the crude oilthat are impractical to remove before the stream reaches the separator. Foampresents no problem within a separator if the internal design assuresadequate time or sufficient coalescing surface for the foam to "break."

Foaming in a separating vessel is a threefold problem. Mechanical control of liquid level is aggravated because any control device must deal withessentially three phases instead of two. Foam has a large volume-to-weightratio; therefore, it can occupy a large amount of the vessel space, otherwiseused for liquid collection or gravity settling. In an uncontrolled foam bank, itbecomes impossible to remove separated gas or degassed oil from the vesselwithout entraining some of the foamy material in either the liquid or gasoutlets.

It is possible to determine foaming tendencies of oil with laboratory tests.Service companies can run laboratory tests on oil samples to qualitativelydetermine oils foaming tendency. One such test is ASTM D 892, whichinvolves bubbling air through the oil. Alternately, the oil may be saturatedwith its associated gas and then expanded in a glass container. This secondtest more closely models the actual separation process. Both of these testsare qualitative. There is no standard method for measuring the amount of foam produced or the difficulty in breaking the foam. Foaming is notpossible to predict ahead of time without laboratory tests. However, foamingshould be expected where CO 2 is present in even small amounts (one percentto two percent). It should be noted that the amount of foam is dependent onthe pressure drop to which the inlet liquid is subjected, as well as thecharacteristics of the liquid at separator condition.

In some cases, the effect of temperature may be found to be quitespectacular. Changing the temperature at which foamy oil is separated hastwo opposite effects on the foam. The first effect is to change the oilviscosity. That is, an increase in temperature will decrease the oil viscosity,making it easier for the gas to escape from the oil. The second effect is to

change the gas-oil equilibrium. A temperature increase will increase theamount of gas, which evolves from the oil.

It is difficult to predict the effects of temperature on foaming tendencies, butsome general trends can be identified. For heavy oils with a low GOR, anincrease in temperature will typically decrease foaming tendencies.Similarly, for light oils with a high GOR, temperature increases typically


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decrease foaming tendencies. However, for light oils with a low GOR, atemperature increase may increase foaming tendencies. Oils in this lastcategory are typically rich in mid-range components, which will evolve tothe gas phase when the temperature increases. Therefore, increasing thetemperature significantly increases the gas evolution, and, thus, the foamingtendencies.

Foam-depressant chemicals are available that often will do a good job inincreasing the capacity of a given separator. However, in sizing a separatorto handle particular crude, the use of an effective depressant should not beassumed because characteristics of the crude and of the foam may changeduring the life of the field. Also, the cost of foam-depressants for high-rateproduction may be prohibitive. Sufficient capacity should be provided in theseparator to handle the anticipated production without use of a foam

depressant. Ideally foam depressants are used once in operation to allowmore throughput than the design capacity.

Paraffin

Separator operation can be adversely affected by an accumulation of

paraffin. Coalescing plates in the liquid section and mesh-pad mist extractorsin the gas section are particularly prone to plugging by accumulations of paraffin. Where it is determined that paraffin is an actual or potentialproblem, use of vane-type or centrifugal mist extractors should beconsidered. Man ways, hand holes and nozzles should be provided to allowsteam, solvent or other types of cleaning of the separator internals.

Sand

Sand can be very troublesome in separators by causing cutout of valve trim,plugging of separator internals and accumulation in the bottom of theseparator. Special hard trim can minimize effects of sand on the valves.Accumulations of sand can be alleviated by the use of sand jets and drains inhorizontal separators, and cone bottoms in vertical separators.

Plugging of the separator internals is a problem that must be considered inthe design of the separator. A design that will promote good separation and


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have a minimum of traps for sand accumulation may be difficult to attain,since the design that provides the best mechanism for separating the gas, oil,and water phases probably will also provide areas for sand accumulation. Apractical balance for these factors is the best solution.

Carryover and Blow by

Carryover and blow by are two common operating problems. Carryoveroccurs when free liquid escapes with the gas phase. It can be an indication of high liquid level, damage to vessel internals, foam, plugged liquid outlets, orexceeding the design rate of the vessel.

Blow by occurs when free gas escapes with the liquid phase, and it can be anindication of vortexing or level control failure. This is a particularly

dangerous problem. If there is a level control failure and the level dumpvalve is open, the gas flow entering the vessel will exit the liquid line andwill have to be handled by the next vessel in the process. Unless that vesselis designed for the gas blow by condition, it can be over-pressured.

Liquid Slugs

Two phase flow lines and pipelines tend to accumulate liquids in low spots

in the lines. When the level of liquid in these low spots raises high enough toblock the gas flow then the gas will push the liquid along the line as a slug.Depending on the flow rates, flow properties, length and diameter of theflow line, and the elevation change involved, these liquid slugs may containlarge liquid volumes.

Situations in which liquid slugs may occur should be identified prior to thedesign of a separator. The normal operating level and the high-levelshutdown on the vessel must be spaced far enough apart to accommodate theanticipated slug volume. If sufficient vessel volume is not provided, then theliquid slugs will trip the high-level shutdown.

When liquid slugs are anticipated, slug volume for design purposes must beestablished. Then the separator may be sized for liquid flow-rate capacityusing the normal operating level. The location of the high-level set pointmay be established to provide the slug volume between the normal level andthe high level. The separator size must then be checked to ensure that


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sufficient gas capacity is provided even when the liquid is at the high-levelset point. This check of gas capacity is particularly important for horizontalseparators because, as the liquid level rises, the gas capacity is decreased.For vertical separators, sizing is easier as sufficient height for the slugvolume may be added to the vessel seam-to-seam length.

Often the potential size of the slug is so great that it is beneficial to install alarge pipe volume upstream of the separator. The geometry of these pipes issuch that they operate normally empty of liquid, but fill with liquid when theslug enters the system. This is the most common type of slug catcher usedwhen two phase pipelines are routinely pigged.

Two-Phase vs. Three-Phase Separators

The high intermediate-stage separators are two-phase, while the low-pressure separator is three-phase. This is called a free -water knockout(FWKO) because it is designed to separate the free water from the oil andemulsion, as well as separate gas from liquid.

The choice depends on the flowing characteristics of the wells. If largeamounts of water are expected with the high-pressure wells, it is possiblethat the size of the other separator could be reduced if the high-pressureseparator was three-phase.

This would normally be the case for a facility where individual wells areexpected to flow at different tubing pressures (FTPs). In some instances,where all wells are expected to have similar FTPs at all times, it may beadvantageous to remove the free water early in the separation scheme.


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Figure 1.1


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Diagrams

Figure 1.2 Pumping System Components


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Figure 2


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Figure 2.1 a vertical two Phase separator


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Figure 2.2 A Horizontal three Phase Separator


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2.3 Schematic and plot showing growth of water layer with Time.


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2.3(a) A Schematic showing a Horizontal three phase separator


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Figure 2.3 (b) A bucket and Weir design


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Figure 2.4 showing a typical configuration of vertical three phase separator


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Figure 2.42 Interface level Control for a three phase vertical Separator.


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Figure 2.43(a)


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Figure 2.43(b)


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CONCLUSION

Oil, Gas, and Water when mixed together are in Phases but can be separatedby different methods.When Separated, they are been processed.


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RECOMMENDATION

This report project is not to be appreciated by only Engineering andTechnology Students. It can also be of great value to students or researchersin other fields.


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REFERENCE

Chevron Nigeria Limited, Lagos.

300 level report

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