Tiếng anh chuyên ngành Thiết bị dầu khí (Petroleum equipment)

Unit Drilling Rigs Rigs are generally categorized as onshore (land) or offshore (marine) Onshore rigs are all similar, and many modern rigs are of the cantilevered mast, or "jackknife" derrick type This type of rig allows the derrick to be assembled on the ground, and then raised to the vertical position using power from the drawworks, or hoisting system These structures are made up of prefabricated sections that are moved onto the location by truck, barge, helicopter, etc., and then placed in position and pinned together by large steel pins Some cantilevered land rigs have their mast permanently attached to a large truck to enhance their portability Figure shows a typical large land rig with a drilling mast Figure 1: Drilling rig Offshore drilling rigs fall into one of several categories, each designed to suit a certain type of offshore environment: • Barge rigs • Submersible rigs • Jack-up or self-elevating rigs • Semisubmersible rigs • Drillships • Structure rigs BARGE RIG: The barge rig is most often a flat-bottomed vessel with a shallow draft, equipped with a derrick and other necessary drilling equipment It is usually towed to the location and then has its hull filled with water, which allows it to rest on the bottom, providing a solid support for drilling activities Obviously, this type of rig is only used in relatively shallow, swampy areas such as the river deltas of West Africa, the inland waters of the Louisiana swamps, or the shallows of Lake Maricaibo, Venezuela Barge rigs are generally capable of drilling in water depths of less than 12 ft (3.7 m), or, in the case of a posted barge, perhaps to 20 ft (6.1 m) A posted barge has a lower hull that rests on the bottom and an upper deck that is sup ported by posts from the lower hull SUBMERSIBLE RIG: A submersible rig is a larger version of a posted barge, and is capable of working in water depths of 18 ft to 70 ft (5.5 m to 2.14 m) Often the hull of a submersible rig will have steel floats or "bottles" that can be filled with water (ball lasted) to help stabilize the vessel on bottom JACK-UP RIG: This is a self-elevating drilling rig, illustrated in Figure , designed to operate in depths from 30 ft to 350 ft (9 m to 107 m) After being towed to the location (or in some cases being self-propelled), the legs are lowered by electric or hydraulic jacks until they rest on the seabed and the deck is level, supported perhaps 60 ft (18 m) above the waves Most jack-up rigs have three to five legs, and are either vertical or slightly angled for stability The legs may have steel feet, called "spud cans," or they may be attached to a large steel mat When moving to a location the legs are raised high above the deck, creating a some what cumbersome vessel that must move at slow speeds and only in good weather The derrick, or mast, on a jack-up may be located over a drilling slot indented in one side of the structure, or the drill floor may be cantilevered over the side of the deck, allowing the rig to service wells on stationary platforms, or caissons, offshore SEMISUBMERSIBLE RIG: Unlike the other offshore vessels, the semisubmersible drilling rig does not rest on the seafloor This rig is a floating deck supported by submerged pontoons and is kept stationary by a series of anchors and mooring lines, and, in some cases, position-keeping propellers "Semis" can either move under their own power or must be towed to their location They have a water-depth-operating range of 20 ft to 2000 ft (6 m to 600 m), and differ from each other principally in their hull configuration and their number of stabilizing columns Most types have a rectangular deck; others may be wedge shaped, pentagonal, or even triangular The two most usual hull arrangements are a pair of parallel pontoons or an individual pontoon at the foot of each stabilizing column The columns and pontoons are ball lasted to provide a low center of gravity, adding to the semi's stability Although the semi can operate in deeper water than a jack-up, it is still limited by the capabilities of the mooring equipment and the "riser" (the conduit that connects the drill floor to the sub-sea equipment located at the borehole on the seafloor) DRILLSHIPS: Drillships are most often utilized for extremely deep water drilling at remote locations A "floater" like the semisubmersible, a drillship must maintain its position at the drilling location by anchors and mooring lines, or by computer-controlled dynamic positioning equipment A series of controllable pitch propellers, or "thrusters," shift position and speed to maintain the ship over the wellbore The drilling slot, or "moon pool," is through the ship's midsection, as shown in Figure and Figure Most drillships have greater storage capacity than other types of rigs, allowing efficient operation at remote locations STRUCTURE RIGS: Structure rigs are mounted on a fixed drilling and production platform, with all necessary auxiliary equipment secured on the deck The derrick and substructure are usually capable of skidding to different positions on the platform structure; following the drilling and completion of multiple wells, the rig may be dismantled and removed during the production phase of the program Subsequent remedial work on these platforms may require the rig to be replaced In some cases, the configuration of wells on the platform allows a jack-up rig to service the location Permanent drilling and production structures vary widely in design and capabilities A few of the most common designs are : • piled-steel platforms • concrete gravity structures • caisson-type monopod structures • guyed towers • tension leg platforms Each drilling rig operates four basic fuctions: hoisting, rotating, circulating, and controlling that are corresponding to the four systems installed on the rig Unit Hoisting system I Reading comprehension The mast and the substructure it sits upon support the weight of the drillstem and allow vertical movement of the suspended drillpipe The substructure also supports the rig floor equipment and provides workspace for its operation The drillstring must be removed from time to time; the length of drillpipe section that can be disconnected and stacked to one side of the derrick is determined by the height of the mast A joint of drillpipe is about 30 ft (9.1 m) long, and a mast that will allow the pulling and stacking of pipe, in three-joint sections (90 ft or 27.4 m), is about 140 ft (42.7 m) high The drawworks is a spool or drum upon which the heavy steel cable (drilling line) is wrapped From the drawworks, the line is threaded through the crown block at the top of the mast and then through the traveling block, which hangs suspended from the crown block ( Figure ) By reeling in or letting out drill line from the drawworks drum, the traveling block and suspended drillstem can be raised or lowered In order to safely manage the movement of such a heavy load with precision, the driller relies on an electrical or hydraulic brake system to control the speed of the traveling block and a mechanical brake to bring it to a complete stop The drawworks also features an auxiliary axle, or "catshaft," with rotating spools on each end called "catheads." One spinning cathead is used to provide power to tighten the drillpipe joints via a cable from the cathead to the rotary tongs The other cathead is for "breaking out" or loosening the pipe joints when the pipe is being withdrawn in sections The wire rope drilling line that is spooled onto the drawworks drum undergoes a certain degree of wear as the block is raised and lowered in the derrick For this reason the line is routinely "slipped" (moved onto the drawworks drum) and replaced with a new section from the continuous spool on which it is stored The line is clamped at the storage spool end by a deadline anchor The hook is attached to the traveling block and is used to pick up the drillstem via the swivel and kelly when drilling, or with elevators when tripping into or out of the hole Unit Rotating system I Reading comprehension The swivel allows the drillstem to rotate while supporting the weight of drillstring in the hole and providing a pressure-tight connection for the circulation of drilling fluid The drilling fluid enters the swivel by way of the "gooseneck," a curved pipe connected to a high pressure hose Connected to the swivel is the kelly, a three-, four-, or six-sided 40 ft (12.2 m) length of hollow steel, which is used to transmit the rotary movement of the rotary table to the drillstring (The term drillstem refers to the kelly and attached drillpipe, drill collars, and bit The term drillstring refers to the drillpipe and drill collars However, most folks in the oil patch disregard these rules and use whichever they please!) The kelly cock is a special valve on the end of the kelly nearest the swivel, which can be closed to shut in the drillstem A lower kelly cock is also available on the bottom end of the kelly to perform the same function when the upper kellycock is not accessible The flat sided-kelly fits through a corresponding opening in the kelly drive bushing, which in turn fits into the master bushing set into the rotary table The rotary table is turned by the rig's power source, the table turns the bushings, the kelly bushing turns the kelly, the kelly turns the drillpipe, and so on down to the bit Note that in place of this conventional rotating system, many modern rigs have gone to the use of power swivels and top-drive units Unit Circulating system I Reading comprehension Circulation of a drilling fluid to carry cuttings up the hole and cool the bit is an important function of any rotary drilling rig The heart of the circulation system is the mud pump (or pumps), which is powered by the rig's prime power source, as are the rotary table and drawworks Mud pumps are positive displacement pumps that push a volume of drilling mud through the system with each stroke of their pistons The output of a mud pump can be determined from the piston and cylinder sizes, the number of strokes per minute, and type of piston arrangement The mud pumps pump the drilling fluid from the mud pit or tanks up the stand-pipe to a point on the derrick where the rotary hose connects the standpipe to the swivel This flexible, high-pressure hose allows the traveling block to move up and down in the derrick while maintaining a pressure-tight system The circulating drilling mud moves through the swivel, kelly, drillpipe, and drill collars, exiting through the bit at the bottom of the hole The mud moves up the annular space between pipe and hole (or casing), carrying the drilled rock in suspension At the surface, the mud leaves the hole through the return line and falls over a vibrating screen called the shale shaker This device screens out the cuttings and dumps some of them into a sample trap and the rest into the reserve pit Once cleaned of large cuttings, the mud is returned to a mud tank, from which it can be once again pumped down the hole Fine particles are removed by centrifugal force by flowing the mud through desanders, desilters, or a centrifuge A degasser is used to remove small amounts of gas picked up in the mud from the subsurface formations Unit Controlling system I Reading comprehension Controlling the subsurface pressures encountered while drilling is an important part of the operation One of the purposes of the drilling mud is to provide a hydrostatic head of fluid to counterbalance the pore pressure of fluids in permeable formations However, for a variety of reasons the well may "kick"; that is, formation fluids may flow into the wellbore, upsetting the balance of the system, pushing mud out of the hole, and exposing the upper part of the hole and equipment to the higher pressures of the deep subsurface If left uncontrolled, this can lead to a "blowout," with the formation fluids forcefully erupting from the well, often igniting, and endangering the crew, the rig, and the environment The blowout preventers are a series of powerful sealing elements designed to close off the annular space between the pipe and hole where the mud is normally returning to the surface By closing off this route, the well can be "shut-in" and the mud and/or formation fluids forced to flow through a controllable choke, or adjustable valve This choke allows the drilling crew to control the pressure that reaches the surface and to follow the necessary steps for "killing" the well and restoring a balanced system Figure shows a typical set of blowout preventers, including the annular preventer, which has a rubber sealing element that is hydraulically squeezed to conform tightly to the drillpipe in the hole Figure BOP system Also shown are ram type preventers These include pipe rams, which close around the pipe with rubber-lined steel sealing elements, and blind rams, which seal off the wellbore when there is no pipe in the hole Shear rams are a type of blind ram that can crimp the pipe in two with a powerful hydraulic force to seal off the hole Blowout preventers are opened and closed by hydraulic fluid stored under 1500 to 3000 psi (10,000 to 20,000 kPa) in an accumulator The choke manifold houses the series of positive and/or adjustable chokes that are usually controlled from a remote panel on the rig floor Often, a rig that is encountering frequent gas kicks will also have a mud-gas separator, which saves the drilling mud that is expelled along with a large flow of formation gas, and separates the gas for safe flaring at some distance from the rig When a kick (influx of formation fluid) occurs, rig operators or automatic systems close the blowout preventer units, sealing the annulus to stop the flow of fluids out of the wellbore Denser mud is then circulated into the wellbore down the drill string, up the annulus and out through the choke line at the base of the BOP stack through chokes (flow restrictors) until downhole pressure is overcome Once “kill weight mud” extends from the bottom of the well to the top, the well has been “killed” If the integrity of the well is intact, drilling may be resumed Alternatively, if circulation is not feasible it may be possible to kill the well by "bullheading", forcibly pumping, in the heavier mud from the top through the kill line connection at the base of the stack This is less desirable because of the higher surface pressures likely needed and the fact that much of the mud originally in the annulus must be forced into receptive formations in the open hole section beneath the deepest casing shoe Exploitable reservoirs of oil and gas are increasingly rare and remote, leading to increased subsea deepwater well exploration and requiring BOPs to remain submerged for as long as a year in extreme conditions As a result, BOP assemblies have grown larger and heavier (e.g a single ram-type BOP unit can weigh in excess of 30,000 pounds), while the space allotted for BOP stacks on existing offshore rigs has not grown commensurately Thus a key focus in the technological development of BOPs over the last two decades has been limiting their footprint and weight while simultaneously increasing safe operating capacity 10 place with cement If only one string of casing is used to complete the well, the production casing is held by cement all the way to the producing formation Normally , it is the surface casing that is completely cemented in At the bottom of the string, the production casing, like the surface casing, is cemented in place In a two casing-string completion, the production casing is run inside the surface casing To support the production casing from the surface, a casing head is used The casing head has a bowl which supports the casing hanger This casing hanger supports the production casing The casing head screws into or is welded onto the top of the surface casing Or, at the well head, the weight of the production casing is actually supported by the surface casing Some wells are completed with three casing strings An intermediate casing string may be set inside the surface casing Then the production casing is set inside the intermediate casing The intermediate casing is longer than the surface casing but shorter than the production casing It is used when formation pressures and drilling depths make three casing strings necessary When an intermediate casing string is used, it is supported at the top by a casing head set on the surface casing Then, to support the production casing from the surface, a second casing head is used A well completed with three casing strings has two casing heads The uppermost casing head supports the production & intermediate casing The lowermost casing head sits on the surface casing and supports the cemented in place casing in a well completed with three casing strings Finally, The surface casing is usually: - supported by a casing head - cemented in place Unit Fishing jobs I Reading comprehension Sometimes, items of drilling equipment get lost in the borehole When an item of equipment is lost in the hole, it’s called a ‘fish’ A lost item is also called ‘junk’ Drilling cannot continue until the fish or junk is recovered from the hole To recover the lost item, a fishing job is necessary Special fishing tools are used for latching on to the fish and hoisting it up to surface There are many types of fishing tools For example, there is a type of fishing tool called a ‘junk basket’, and there is another type called a ‘spear’ Look diagram below As you can see, these fishing tools are very different The spear is used the bore of the lost pipe The diameter of the spear, therefore, must be smaller than the diameter of the pipe in the hole When the spear enter the pipe, its teeth pull out, and grip the inner sides of the tightly Then it is usually possible to hoist the fish out of the borehole The junk basket is used for latching on to smaller pieces of junk It’s used for recovering lost bit cutters, for example The bottom part of the basket is a shoe with hardfaced teeth The shoe has a hole in its centre The fish is forced through the hole and enter the barrel of the basket Spring-loaded fingers prevent the fish from dropping out of the barrel and falling back into the well Before a fishing job can begin, the string must be tripped out of the hole First, the kelly is broken out and is set in the rathole Then the string is broken out in stands and the stands are stood back on the rig floor When all of the stands are stood back, the fishing can begin The toolpusher usually takes charge of the fishing operation Unit Wellhead I Reading comprehension A wellhead consists of pieces of equipment mounted at the opening of a well to manage the extraction of hydrocarbons from an underground formation It prevents the leakage of oil or natural gas out of the well, and also prevents blowouts caused by high pressure Formations that are under high pressure typically require wellheads that can withstand a great deal of upward pressure from the escaping gases and liquids These wellheads must be able to withstand pressures of up to 20,000 pounds per square inch (psi) The wellhead consists of three components: the casing head, the tubing head, and the 'christmas tree.’ The casing head consists of heavy fittings that provide a seal between the casing and the surface The casing head also serves to support the entire length of casing that is run all the way down the well This piece of equipment typically contains a gripping mechanism that ensures a tight seal between the head and the casing itself The tubing head is much like the casing head It provides a seal between the tubing, which is run inside the casing, and the surface Like the casing head, the tubing head is designed to support the entire length of the casing, as well as provide connections at the surface, which allow the flow of fluids out of the well to be controlled The 'christmas tree' is a piece of equipment that fits on top of the casing and tubing heads, and contains tubes and valves that control the flow of hydrocarbons and other fluids out of the well It commonly contains many branches and is shaped somewhat like a tree, thus its name, ‘christmas tree.’ The christmas tree is the most visible part of a producing well, and allows for the surface monitoring and regulation of the production of hydrocarbons from a producing well A typical Christmas tree is about six feet tall When selecting a well, head the casing size, weight and thread must be known The inner string is tubing and most of the time will be 3/8" in diameter The tubing string must be suspended by slips or hangers and set in tension at the surface on all standard RFI systems The casing head pressure rating (2000 to 3000psig) must be properly selected and the side outlets are most often 2" LP size and the packing material, either nitrile or other seal/o-ring materials, must be properly selected The diagram below describes a typical DGWS (downhole gas and water separation) wellhead configuration This configuration prevents excessive tubing pressure build- up if a failure downhole occurs Unit Packers I Reading comprehension A production packer is an equipment used to provide a seal between the outside of the production tubing and the inside of the casing, liner, or wellbore wall It also functions as a casing protection, a medium to separate multiple zones etc., Based on its primary use, packers can be divided into two main categories: production packers and service packers Production packers are those that remain in the well during well production and service packers are used temporarily during well service activities such as cement squeezing, acidizing, fracturing and well testing etc., In wells with multiple reservoir zones, packers are used to isolate the perforations for each zone In this situation, a sliding sleeve would be used to select which zone to produce Packers may also be used to protect the casing from pressure and produced fluids, isolate sections of corroded casing, casing leaks or squeezed perforations, and isolate or temporarily abandon producing zones In waterflooding developments in which water is injected into the reservoir, packers are used in injection wells to isolate the zones into which the water must be injected A production packer is designed to grip and seal against the casing ID Gripping is accomplished with metal wedges called "slips." These components have sharpened, carburized teeth that dig into the metal of the casing Sealing is accomplished with large, cylindrical rubber elements In situations where the sealed pressure is very high (above 5,000 psi), metal rings are used on either side of the elements to prevent the rubber from extruding A packer is run in the casing on production tubing or wireline Once the desired depth is reached, the slips and element must be expanded out to contact the casing Axial loads are applied to push the slips up a ramp and to compress the element, causing it to expand outward The axial loads are applied either hydraulically, mechanically, or with a slow burning chemical charge Most packers are "permanent" and require milling in order to remove them from the casing The main advantages of permanent packers are lower cost and greater sealing and gripping capabilities In situations where a packer must be easily removed from the well, such as secondary recoveries, re-completions, or to change out the production tubing, a retrievable packer must be used To unset the tool, either a metal ring is sheared or a sleeve is shifted to disengage connecting components Retrievable packers have a more complicated design and generally lower sealing and gripping capabilities, but removal and subsequent servicing, they can be reused after There are three types of packers: mechanical, hydraulic set and permanent packer All packers fall into one or a combination of these Mechanical Set Packers: These are set by some form of tubing movement, usually a rotation or upward /downward motion They are used best in shallow low pressure wells that are straight, and not designed to withstand pressure differences unless a hydraulic hold down is incorporated Tension Set packers: set by pulling a tension on the tubing, slacking off releases the packer This type of packer is good for shallow wells with moderate pressure differences Rotation Set packers: used to set the packer to mechanically lock it in; an left hand turn engages and a right hand turn retrieves it Hydraulic Set packers: use fluid pressure to drive the cone behind the slips Once set they remain set by the use of either entrapped pressure or a mechanical lock They are released by picking up the tubing They are good for used in deviated/ crooked holes where tubing movement is restricted or unwanted The tubing can be in neutral tension Inflatable rubber/Balloon packers: Use fluid pressure to inflate a balloon and set the packer They can’t withstand high pressure differentials and are only used in specialty applications and in wells where the casing or open holes are collapsed Permanent packers: Run and set on an electric wireline, drill pipe or tubing They are good in wells that have high pressure differentials or large tubing load variations and can be set precisely They can be set the deepest Cement packer : In this case the tubing is cemented in place inside the casing or open hole This type of packer is cheap Unit Pumps and pumping system I Reading comprehension Pumps are classified as either "kinetic" or "positive displacement" pumps In a kinetic pump, energy is added continuously to increase the fluid's velocity within the pump to values in excess of those that exist in the discharge pipe Passageways in the pump then reduce the velocity until it matches that in the discharge pipe From Bernoulli's law, as the velocity head of the fluid is reduced, the pressure head must increase Therefore, in a kinetic pump, the kinetic or velocity energy of the fluid is first increased and then converted to potential or pressure energy Almost all kinetic pumps used in production facilities are centrifugal pumps in which the kinetic energy is imparted to the fluid by a rotating impeller generating centrifugal force In a positive displacement pump, the volume containing the liquid is decreased until the resulting liquid pressure is equal to the pressure in the discharge system Most positive displacement pumps are reciprocating pumps where the displacement is accomplished by linear motion of a piston in a cylinder Rotary pumps are another common type of positive displacement pump, where the displacement is caused by circular motion A pump distinguishes from other pumps by its basic parameters The basic pump parameters to be considered belong to two groups of hydraulic and rotational variables The hydraulic variables consist of head, capacity (or flow), and efficiency Head is simply a pressure unit that is commonly used in hydraulic engineering that is expressed in feet of pumped fluid (or in meter) That is to say, it is the pressure that is exerted from the weight of a height of a given liquid; hence the unit of feet (meters in the metric system of units) And It’s usually denoted as H The capacity of a pump is the amount of liquid conveyed per unit time It is actually the volumetric rate of flow Other common terms for capacity are flow rate and discharge rate The classical English unit is gallons per minute (gpm) The metric equivalents are liters per minute (R/min) or cubic meters per second (m³/sec) Capacity will be denoted as Q Efficiency is a measure or indication of the amount of loss The term entropy is used to define unavailable or lost energy; entropy is ever increasing We must be careful when we discuss efficiency because there are no less than four efficiencies involved in centrifugal pump systems These are (1) hydraulic efficiency, (2) mechanical efficiency, and (3) drive efficiency The overall pump operational efficiency (4) is the product of the three preceding efficiencies The rotational (maybe they should be referred to as mechanical) variables are power, speed, and impeller diameter In physics, power is defined as work per unit time In the field of engineering, power is defined as the ability to work Units for power are the horsepower (hp) and the kilowatt (kw) With centrifugal pumps we deal with the former; the unit of horsepower is commonly used interchangeably with, and taken to mean the variable of power Here again we must be careful When we discuss horsepower there exists no less than three different horsepowers involved in centrifugal pump systems These are (1) hydraulic horsepower, (2) brake horsepower, and (3) drive or motor horsepower Hydraulic horsepower, sometimes referred to as water horsepower (WHP), is the power imparted to the liquid by the pump Rotational Speed Rotational speed is the scalar quantity of the dynamics term known as angular velocity Rotational speed is generally referred to simply as speed The unit of revolutions per minute (rpm) is used in conjunction with speed And the last is impeller Diameter, this is the simplest variable to define In order to make a selection of the pumps required for a specific installation, it is necessary to first determine the purposes of pumps to be used, then the desired flow rate or head The NPSH (net possitive suction head) available should be determined, and if a centrifugal selection is possible, a system head-flow-rate curve should be developed Usually, centrifugal pumps are used for production and transportation while possitive displacement or piston pumps are mainly used for drilling operations basing on the advantages and disadvantages of each type of pump 20 Unit Gathering center I Reading comprehension After the crude has been brought to the surface, the next step is to process it into the form in which it will be sent on to the refinery Through the flowlines, production from the various wellheads in the field is directed to the gathering centre Offshore, for reasons of space and cost, the gathering centre is the production platform itself At the gathering centre, the oil is treated to bring it up to pipeline and refinery specification Water and dissolved salts can seriously corrode chokes, valves and pipe walls, and must therefore be removed from the crude before it is transported Dehydration and desalination can be accomplished by electrical precipitation, heating, and washing with fresh Reservoir crude also has to be treated to separate associated gas Separation of the gas may be a single-stage or a multi-stage operation, depending on the gas/oil ratio In single-stage separation, only one oil-gas separator is used Separators can be vertical, inclined, or horizontal Natural gas may also require treatment at the gathering centre, particulary if it contains water vapour When a high-pressure gas is expanded to a lower temperature, considerable cooling takes place If the gas contains water vapour, this cooling can cause the formation of hydrates, and these may plug chokes, valves and pipelines The gas is dehydrated in a large steel vessel known as a ‘scrubber’, in which the water is removed by the absorbing action of glycol Natuaral gas frequently contains considerable amounts of the corrosive and highly toxic acid gas H2S (hydrogen sulphide), and treatment must be avaiable for this as well as for water vapour Trunk lines connect the gathering centre to the refinery or tanker terminal Many kilometres of large-diameter pipeline (eg, 26’’ or 32’’ OD) may be required Problems inside the lines must be prevented, or quickly corrected when they occur The devices which test, log, clean and unblock oil pipelines are know as ‘pigs’ Each type of pig is usually reffered to by a special name One type of rig, for example, is known as a ‘rabbit’ In product pipelines, pigs can be used to separate two or more different oil products which are being sent at the same time through a single line Unit Separators I Reading comprehension The function of an oil production facility is to separate the oil well stream into three components or “phases” (oil, gas, and water), and process these phases into some marketable products or dispose of them in an environmentally accept-able manner In mechanical devices called “separators”, gas is flashed from the liquids and “free water” is separated from the oil These steps remove enough light hydrocarbons to produce a stable crude oil with the volatility (i.e., vapor pressure) to meet sales criteria An oil and gas separator generally includes the following essential components and features: A vessel that includes (a) primary separation device and/or section, (b) secondary “gravity” settling (separating) section, (c) mist extractor to remove small liquid particles from the gas, (d) gas outlet, (e) liquid settling (separating) section to remove gas or vapor from oil (on a three-phase unit, this section also separates water from oil), (f) oil outlet, and (g) water outlet (three-phase unit) Adequate volumetric liquid capacity to handle liquid surges (slugs) from the wells and/or flowlines Adequate vessel diameter and height or length to allow most of the liquid to separate from the gas so that the mist extractor will not be flooded A means of controlling an oil level in the separator, which usually includes a liquid-level controller and a diaphragm motor valve on the gas outlet A backpressure valve on the gas outlet to maintain a steady pressure in the vessel Pressure relief devices Separators work on the principle that the three components have different densities, which allows them to stratify when moving slowly with gas on top, water on the bottom and oil in the middle Any solids such as sand will also settle in the bottom of the separator The functions of oil and gas separators can be divided into the primary and secondary functions which will be discussed later on Separators are classified as “two-phase” if they separate gas from the total liquid stream and “three-phase” if they also separate the liquid stream into its crude oil and water components The classification of oil and gas separators include : - Classification by operating configuration : Oil and gas separators can have three general configurations: vertical, horizontal, and spherical - Classification by function : The three configurations of separators are available for twophase operation and three-phase operation In the two-phase units, gas is separated from the liquid with the gas and liquid being discharged separately In three- phase separators, well fluid is separated into gas, oil, and water with the three fluids being discharged separately - Classification by operating pressure : Oil and gas separators can operate at pressures ranging from a high vacuum to 4,000 to 5,000 psi Most oil and gas separators operate in the pressure range of 20 to 1,500 psi - Cassification by application : separators may be classified as test separator, production separator, low temperature separator, metering separator, elevated separator, and stage separators (first stage, second stage, etc.) There are several new concepts currently under development in which the fluids are degassed upstream of the primary separator These systems are based on centrifugal and turbine technology and have additional advantages in that they are compact and motion insensitive, hence ideal for floating production facilities The methods listed are some of the ways in which oil is separated from gas in separators : Density Difference (Gravity Separation) ; impingement ; Change of Flow Direction ; Change of Flow Velocity and Centrifugal Force Because of higher prices for natural gas, the widespread reliance on metering of liquid hydrocarbons, and other reasons, it is important to remove all nonsolution gas from crude oil during field processing Methods used to remove gas from crude oil in oil and gas separators are: settling , agitation, heat and centrifugal force Unit Pipeline I Reading comprehension The first pipeline was built in the United States in 1859 to transport crude oil Through the one-and-a-half century of pipeline operating practice, the petroleum industry has proven that pipelines are by far the most economical means of large scale overland transportation for crude oil, natural gas, and their products, clearly superior to rail and truck transportation over competing routes, given large quantities to be moved on a regular basic Nowadays, offshore pipeline is the unique means of efficiently transporting offshore fluids, i.e., oil, gas, and water Offshore pipelines can be classified into categories as follows: -Flowlines transporting oil and/or gas from satellite subsea wells to subsea manifolds; -Flowlines transporting oil and/or gas from subsea manifolds to production facility platforms; -Infield flowlines transporting oil and/or gas between production facility platforms; -Export pipelines transporting oil and/or gas from production facility platforms to shore; -Flowlines transporting water or chemicals from production facility platforms, through subsea injection manifolds, to injection wellheads The further the downstream from the subsea wellhead, as more streams commingle, the larger the diameter of the pipelines Of course, the pipelines are sized to handle the expected pressure and fluid flow To ensure desired flow rate of product, pipeline size varies significantly from project to project To contain the pressures, wall thicknesses of the pipelines range from 3/8 inch to 11⁄2 inch Design of marine pipelines is usually carried out in three stages: conceptual engineering, preliminary engineering, and detail engineering During the conceptual engineering stage, issues of technical feasibility and constraints on the system design and construction are addressed Potential difficulties are revealed and non-viable options are eliminated Required information for the forthcoming design and construction are identified The outcome of the conceptual engineering allows for scheduling of development and a rough estimate of associated cost The preliminary engineering defines system concept (pipeline size and grade), prepares authority applications, and provides design details sufficient to order pipeline In the detail engineering phase, the design is completed in sufficient detail to define the technical input for all procurement and construction tendering Before designing an offshore pipeline, the design engineers need to understand the environments in which the pipeline will be installed and operated What is the water depth? What are the water currents? How big are the waves? All those parameters will affect the mechanical design of the pipeline system The fluids inside the pipeline will also influence the pipeline design Is it single-phase or multiphase? Are the fluids corrosive? How much sand will be in the fluids? What are the operating pressures and temperatures? All these will influence the pipeline metallurgy selection A list of the data that will affect the pipeline design follows: - Reservoir performance - Fluid and water compositions - Fluid PVT properties - Sand concentration - Sand particle distribution - Geotechnical survey data - Meteorological and oceanographic data Once design is finalized, pipeline is ordered for pipe construction and coating and/or fabrication Upon shipping to the site, pipeline can be installed There are several methods for pipeline installation including S-lay, J-lay, reel barge, and tow-in methods Pipeline operation starts with pipeline testing and commissioning Operations to be carried out include flooding, cleaning, gauging, hydrostatic pressure testing, leak testing, and commissioning procedures Daily operations include flow assurance and pigging operations to maintain the pipeline under good conditions Flow assurance is defined as an operation that generates a reliable flow of fluids from the reservoir to the sales point The operation deals with formation and depositions of gas hydrates, paraffin, asphaltenes, and scales that can reduce flow efficiency of oil and gas pipelines Because of technical challenges involved, this operation requires the combined efforts of a multidisciplinary team consisting of scientists, engineers, and field personnel Technical challenges in the flow assurance operation include prevention and control of depositions of gas hydrates, paraffin (wax), asphaltenes, and scales in the oil and gas production systems It has been noted that the deposition of inorganic solids arising from the aqueous phase (i.e., scale) also poses a serious threat to flow assurance Gas hydrate plugging problems can occur in deepwater drilling, gas production, and gas transportation through pipelines The potential for hydrocarbon solid formation and deposition adversely affectng flow assurance in deepwater production systems is a key risk factor in assessing deepwater developments To reduce this risk, a systematic approach to defining and understanding the thermodynamic and hydrodynamic factors impacting flow assurances required Flow assurance engineering has been known as an operation that does not directly make money, but costs a great deal in pipeline operations, if not managed correctly II Practice: Choose a word from these words and expressions to complete the paragraph below Pipeline operation gather fields field System capacity running declined production shore The Cuu Long gas ………… system, with length of 116 km, has been put into ……………since 1995 to transport and ………….associated gas from oil …………such as Bach Ho, Rang Dong, Phuong Dong, Ca Ngu Vang, Su Tu Den/Su Tu Vang/Su Tu Trang, Rong, Doi Moi, etc to……… This pipeline ………has delivery ……….of about bcma per year, but it is now ………….around 60 to 70 percent of the capacity due to …………….the gas ……….in Cuu Long Basin ... it is still limited by the capabilities of the mooring equipment and the "riser" (the conduit that connects the drill floor to the sub-sea equipment located at the borehole on the seafloor) DRILLSHIPS:... Unit Fishing jobs I Reading comprehension Sometimes, items of drilling equipment get lost in the borehole When an item of equipment is lost in the hole, it’s called a ‘fish’ A lost item is also... the drilling location by anchors and mooring lines, or by computer-controlled dynamic positioning equipment A series of controllable pitch propellers, or "thrusters," shift position and speed to