Surface on the side of the wellhead. These are

Surface facilities Surface facilities encompass the equipment between the wellsand the pipeline or other transportation method. The purpose of the surfacefacility is to remove impurities and contaminants from the oil/gas, remove otherliquids and solids, and prepare the oil/gas to meet the sales requirements ofthe purchaser. Surfacefacilities involve several units that function differently to processhydrocarbons so as to be ready for sales, these facilities involve: WELLHEADThe wellhead isthe equipment at the surface that provides support for the tubulars inside thewell, a pressure seal between the tubulars, and a means of controllingproduction from the well. Typically, the wellhead consists of a casing head foreach casing string, a tubing head, and a christmas tree.

For each string ofpipe in the well, casing, or tubing, some means of support and pressure sealingmust be provided. This is the function of the casing and tubing heads.The christmas tree provides the necessary valving and chokes tocontrol the production from a well capable of flowing.Normally,wellhead & christmas tree are located on the platform and can be easilyoperated by man, called surface wellhead or dry tree.

However, for deep wateror when platform installation is considered not cost-effective, wellhead &Christmas tree may be located on the seabed, called subsea wellhead or wettree.The following figure shows a typical wellheadfor a flowing well. Notice that a choke is provided to control the rate ofproduction from the well in addition to the tubing wing valve, which providesfor a complete shut-off of the production.

The choke can be either fixed orvariable in size. The choke is nothing more than a small orifice, usually from1/8 to 3/4 in. in diameter, that restricts the flow rate.

Typical wellhead for a flowing well with a single-wing,single-completion threaded manifold.  Other valves are present on the side of the wellhead. These arecalled casing valves and they provide access to the various annuliibetween casing strings and tubing. Normally, the wellhead is fitted withpressure gauges for monitoring pressure within the different annulii and in thetubing.The flow rate from either an oil well or a gas well can be easilyestimated from the wellhead pressure if the wellhead pressure is at least twicethe flowline pressure. For an oil well, the Gilbert equation is commonly used:       where·      q =gross liquid flow rate (bbl/day)·      Ptf =flowing tubing head pressure (psia)·      R =gas to liquid ratio (MSCF/bbl)·      S =choke size (1/64 in.)For a gas well, the following equation is used: where·       q =gas flow rate (MSCF/day)·       Ptf =flowing tubing head pressure (psia)·       d =choke size (in.

)·       G =gas specific gravity·       T =wellhead temperature (°R)  SEPARATIONFACILITIES: Onceoil and gas are brought to the surface, our main goal becomes that of transportationof the oil and gas from the wellhead to the refinery (for final processing) inthe best possible form. All equipment and processes required to accomplish thisare found at the surface production facility. Hence, all surface productionstarts right at the wellhead. Starting at the wellhead, the complex mixture ofproduced fluids makes its way from the production tubing into the flow line.Normally, many wells are drilled to effectively produce the hydrocarbonscontained in the field. From each of these wells emerge one or more flow linesdepending on how many layers are being produced simultaneously. Depending onthe physical terrain of the area and several other environmental factors, eachof the flow lines may be allowed to continue from the wellhead to a centralprocessing facility commonly referred as a production platform or a flowstation.

If not, all the flow lines or several of them empty their contentsinto a bigger pipeline called a bulk header, which then carries the fluids tothe production platform. The combination of the wellhead, the flow lines, bulkheaders, valves and fittings needed to collect and transport the raw producedfluid to the production platform is referred to as the gathering system.  Thegathered fluids must be processed to enhance their value.

First of all, fluidsmust be separated into their main phases; namely, oil, water, and natural gas.The separation system performs this function. For this, the system is usuallymade up of a free water knock-out (FWKO), flow line heater, and oil-gas(two-phase) separators. We will be looking at the design of this lastcomponent.Thephysical separation of these three phases is carried out in several steps.Water is separated first from the hydrocarbon mixture (by means of the FWKO), andthen the hydrocarbon mixture is separated into two hydrocarbon phases (gas andoil/condensate). A successful hydrocarbon separation maximizes production ofcondensate or oil, and enhances its properties.

In field applications, this isaccomplished by means of stage separation. Stage separation of oil and gas iscarried out with a series of separators operating at consecutively reducedpressures. Liquid is discharged from a higher-pressure separator into thenext-lower-pressure separator. The purpose of stage separation is to obtainmaximum recovery of liquid hydrocarbons from the fluids coming from thewellheads and to provide maximum stabilization of both the liquid and gas effluents.

 Usuallyit is most economical to use three to four stages of separation for thehydrocarbon mixture. Five or six may payout under favorable conditions, when —for example — the incoming wellhead fluid is found at very high pressure.However, the increase in liquid yield with the addition of new stages is notlinear. For instance, the increase in liquids gained by adding one stage to asingle-stage system is likely to be substantial. However, adding one stage to athree or four stage system is not as likely to produce any major significantgain. In general, it has been found that a three stage separating system is themost cost effective.   Underthe assumption of equilibrium conditions, and knowing the composition of thefluid stream coming into the separator and the working pressure and temperatureconditions, we could apply our current knowledge of VLE equilibrium (flashcalculations) and calculate the vapor and liquid fractions at each stage.

However, if we are looking at designing and optimizing the separation facility,we would like to know the optimal conditions of pressure and temperature underwhich we would get the most economical profit from the operation. In thiscontext, we have to keep in mind that stage separation aims at reducing thepressure of the produced fluid in sequential steps so that better and morestock-tank oil/condensate recovery will result. The design of a particularseparator depends on the nature of the flow stream to be separated. Since weare more concerned with  gas wells,  separators usually separate a small amount ofliquid from the gas.

In an oil well, the separation may involve a small amountof gas for the amount of liquid. In general, the well stream separator mustseparate the mostly liquid fluids from the mostly gas fluids. In addition, itmust separate liquid hydrocarbon from liquid water and remove most of theentrained liquid mist from the gas.To accomplish the separation, theseparator is usually designed to control and dissipate the well stream flowingenergy.

Once gas and liquid velocities are slow enough, gravity causes theliquid to settle and the gas to rise. The size of the vessel must be such thatadequate time is allowed for this settling to occur before the fluid leaves theseparator. If water is to be separated from oil, then the liquid residence timedepends on the volume of the fluid being handled and the specific gravity ofthe two liquids. Many times, a mist extractor composed of vanes, mesh pads, ora cyclonic passage is used to remove residual liquid droplets from the gasstream.  There are three types ofseparators: vertical , horizontal, and spherical .Horizontal separators are found in both the single tube and double tube design.1.    VerticalSeparator Thewell stream enters the separator through the tangential inlet, which imparts acircular motion to the fluids.

A Centrifugal and gravity force providesefficient primary separation. A conical baffle separates the liquidaccumulation system from primary section to ensure a quiet liquid. Surfacereleasing solution gas. The separated gas travels up ward through the secondaryseparation section where the heavier entrained liquid particles settle out. Thegas flows through the mist extractor and particles accumulate until sufficientweight to fall into the liquid accumulation section. Sediments enter theseparator and accumulate in the bottom and flushed out through the drainconnection.

 Advantages of the verticalseparator include·       Good for predominantly liquidstreams·       Can handle producing stream surgeswithout carryover·       Occupies little space (smallfootprint)·       Easily cleaned of sand and mud      2. Horizontal separator Singletube the well stream enters through the inlet and strikes an angle baffle ordished deflector and strikes the side of the separator, producing maximumprimary separation. Horizontal divider plates separate the liquid accumulationand gas separation section to ensure quick removal of solution gas. Theseparated gas passes through the mist extractor where liquid particles whereliquid particles 10 micron and larger size are removed. Doubletube consist of an upper separator section and lower liquid chamber. The mixedstream of oil and gas enters the upper tube. Liquid fall through the firstconnecting pipe into the liquid reservoir and wet gas flows through the uppertube where the entrained liquid separate owing to difference in density and toscrubbing action of mist extractor. Advantages of the horizontalseparator are:·       Good for predominantly gas streams·       Easy to fabricate, ship, andinstall·       Low profile                                  Vertical Separator                                                                      Horizontal Separator   3.

Spherical separator: Theincoming well stream is split by the inlet flow diverter and directedtangentially against the wall of the separator. The liquid streams cometogether after flowing 180o around the vessel wall and then fall into theaccumulation section to remain there until released. Thegas stream is travelling through the large diameter and loses particles due toits reduced velocity. Then, the gas passes through mist extractor. For the spherical separator, theadvantages are·       Good for high pressure gas wells·       Compact, small size  Factorsaffecting separation?Operating pressure: a change in pressure effects changes in the gas and liquiddensities, velocity and flowing volume. The net effect on an increase inpressure is an increased gas capacity of the separator.?Temperature: it affects the actual flowing volume and densities of the gas andliquid. The net effect of an increase of temperature is a decrease in capacity.

?Well stream crude oil composition     Spherical separator Separationprocess results two streams, oil stream and gas stream ( besides water streamwhich is treated chemically before being disposed or used for tertiary recoverymethods) each of these two streams take a treatment path before being stored ortransported.    OILTREATMENT FACILITIES No separation is perfect, there is always somewater left in the oil. Water content can range from less than 1% water to morethan 20% water in the oil by volume. The lower the (API) gravity  the less efficient the separation.To get the last of the water out of the oil,the oil is processed through an oil treater or a treating system. A treater issimilar to a separator, but with special features to help separate the waterfrom the oil. Treaters or treating systems usually provide heat to reduce oilviscosity and large settling sections to allow the water time to settle fromthe oil, and may provide an electrostatic grid to promote coalescing of thewater droplets.

After being treated, oil is transported throughflowlines to be stored in storage tanks. GASTREATMENT FACILITIES HYDRATEINHIBITOR FACILITIES Under normal production conditions,natural gas is saturated with water . Water as a vapor is not the major problem.

However, when water combineswith the gas molecules, e.g. methane, ethane, propane and forms solid hydratessuch as CH4.7H20, C2H6.8H2Oand C3H8.18H2O , then it becomes a problem.Hydrates form ice-like solids when free water combines with the components of agas stream Hydrateformation is undesirable because:1-Causeplugging of flow lines, equipment and instruments.

2-Resultin unnecessary maintenance and lost production.3-Causephysical damage.4-Acceleratecorrosion.  Methodsof preventing hydrates formation 1-    Addingheat to assure that the temperature is always above the hydrate formationtemperature ( indirect heaters are used to heat gas streams  at the well head and in pipelines)2- Lowering the hydrate formationtemperature with chemical inhibition3- Dehydrating the gas so that watervapor will not condense into free water.4- Design the process so that ifhydrates form they can be melted before plug equipment:         i-Reduce pressure drops by minimizingline lengths and restrictions.       ii-Check the economics of insulatingpipe in cold areas.  CHEMICALINJECTION Methanol(MeOH) and monoethylene glycol (MEG) are the two chemicals most commonlyinjected into gas streams to inhibit hydrate formation.

 Methanolworks well as a hydrate inhibitor because of the following reasons: • Itcan attack or dissolve hydrates already formed.• Itdoes not react chemically with any natural gas constituents.• Itis not corrosive.• Itis reasonable in cost.• Itis soluble in water at all concentrations.  Thefollowing figure shows a simplified schematic of a typical methanol injection  system. This system inhibits hydrateformation at a choke or pressure-reducing valve.

A gas-driven pump injects themethanol into the gas stream upstream of the choke or pressure-reducing valve. The temperature controllermeasures the  temperature in the gasstream and adjusts the power-gas control valve. The power-gas control valvecontrols the flow of power gas, which controls the methanol injection rate.  GASSWEETNING FACILITIES •       In addition toheavy hydrocarbons and water vapor, natural gas often contains othercontaminants that may have to be removed.

Carbon dioxide (CO2) , hydrogensulfide(H2S) , and other sulfur compound such as mercaptans are compounds thatmay require  complete or partial removalfor acceptance by gas purchaser. •        These compounds are known as “acid gases”.H2S combined with  water forms a weakform of sulfuric acid, while CO2 and water forms carbonic acid, thus the term acid gas.

 •        Natural gas with H2S or other sulfur compoundspresent is called “sour gas” ,while gas with  only CO2 is called  “sweet” . •        Hydrogen sulfide, carbon dioxide, mercaptansand other  contaminants are often foundin natural gas streams. H2S is a highly toxic gas that is corrosive to carbonsteels.

CO2 is also   corrosive to equipment and reduces the Btuvalue of gas. Gas sweetening processes remove these contaminants so the gas issuitable for transportation and use. Methods toremove acidic components There are many methods that may beemployed to remove acidic components (primarily H2S and CO2) from hydrocarbonstreams. The available methods may be broadlycategorized as those depending on chemical reaction, absorption, or adsorption:  yChemicalreaction process•       Aqueous alkanolamineprocesses•       Alkaline saltprocess(hot potassium carbonate) ySolidbad absorption•       Iron sponge•       MolecularsievesyPhysicalsolvent processes•       Shell sulfinol•       SelexolyDirectconversion of H2S to sulfur•       Claus process  ProcessSelectionEach of the previous treatingprocesses has advantages relative to the others for certain applications , therefore, in selection of the appropriateprocess, the following facts should be considered: uThetype acid contaminants present in the gas stream.uTheconcentrations of each contaminant and degree of removal desired.uThevolume of gas to be treated and temperature and pressure at which the gas isavailable.uThefeasibility of recovering sulfur.

uThedesirability of selectively removing one or more of the contaminants   without removing others.uThepresence and amount of heavy hydrocarbons and aromatics in the gas.  a schematicillustration of gas sweetning by chemical reaction             After sweetning, sweet gas moves todehydration process.

  GAS DEHYDRATION Dehydration is the act or process ofremoving water  from gases or liquids, Removing waterfrom natural gas streams helps prevent the following: • Line blockages • Accelerated corrosion• Hydrate formation and condensationof free water in processing and transportation                              facilities  Techniques for dehydrating natural gas, associated gas condensate and  natural gas liquids (NGLs),include: ·       Absorption using liquid desiccants,·       Adsorption using solid desiccants, ·       Dehydration with CaCl2,·       Dehydration by refrigeration,·       Dehydration by membrane permeation,·       Dehydration by gas stripping, and·       Dehydration by distillation.      Liquiddehydration systems absorption using liquid desiccants  Absorption: Theassimilation of one material into another.In natural gas dehydration, the useof an absorptive liquid to selectively remove water vapor from a gas stream. Desiccant; Asubstance used in a dehydrator to remove water and moisture. Liquiddesiccants : A typical cycle includes contacting the liquid desiccant with thegas stream and then stripping the water from the desiccant.

   PROCESS FLOWDIAGRAM FOR GLYCOL DEHYDRATION UNIT  DESCRIBING THEGLYCOL DEHYDRATION PROCESS Wet inlet gas enters the bottom ofthe contactor while lean glycol enters the top. As the wet gas stream flowsupward, it contacts the downward flowing lean glycol. During this contact, theglycol absorbs water from the gas stream.Dry outlet gas leaves the top of thecontactor and rich glycol exits the bottom.

The rich glycol enters the top ofthe stripping column and counter currently contacts steam rising  from the reboiler. The rich glycol then enters thereboiler, which boils the water out of the glycol. The lean glycol leaves thebottom of the reboiler and enters the surge tank for  storage. The pump raises the glycol to systempressure, preparing it for another dehydration cycle. Dry gas then flows in a flowline to be connected to gas network andfractionated LPG flows in another discrete flowline to LPG storage tanks.