Surface Facilities

Crude Oil ProcessingNatural gas processingSurface Gathering SystemsSeparatorsLiquid StorageSingle phase flow in pipesTwo phase flow in pipes

Crude Oil Processing

In oil production processing, the individual phases (gas, liquid hydrocarbon, liquid water, and solids) should be separated from each other as early as practical. Individual streams can then be treated with less technical difficulty and more economically. Lab and field tests performed before construction can identify and minimize future production and processing problems such as scaling, foaming, emulsion formation, wax deposition, and hydrate formation.

Gas ProcessingGas processing begins with treating, if necessary, to remove the acid gases—hydrogen sulfide and carbon dioxide. Both gases are very corrosive when liquid water is present and hydrogen sulfide is most toxic. Environmental regulations almost always prohibit the release of significant amounts of hydrogen sulfide to the surroundings. Conversion to elemental sulfur is becoming increasingly necessary. Gas sweetening usually uses aqueous solutions of various chemicals. Therefore, sweetening will precede dehydration. Dehydration is often necessary to prevent theformation of gas hydrates, which may plug high-pressure processing equipment or pipelines at high pressure and at temperatures considerably higher than 32°F (0°C).

Gas that contains considerable amounts of liquefiable hydrocarbons (ethane or propane and heavier) can produce condensate upon compressing or cooling. The condensate may cause difficulty in pipelining or subsequent processing. Field processing to remove these natural-gas liquids (NGL), sometimes referred to simply as condensate, may be economical or may be required to meet a hydrocarbon dew-point specification. In remote locations such processing is generally avoided if possible. Recovered condensate may, in turn, have to be stabilized by removing dissolved gaseous components to obtain a transportable product.

Final disposal of the gas stream depends on the situation. Early in the life of a remote field, before the availability of a pipeline, the gas may simply be flared. It is becoming more common to conserve the gas by compression and reinjection into the formation with a view to its eventual recovery and sales. Conservation is often demanded by law; permits to flare are usually

temporary and granted only during the initial start-up of production. Environmental restraints may also prevent flaring especially if the gas contains any hydrogen sulfide.

The common situation is to flow the natural gas into a pipeline for sales. Gas pipelines have operating pressure levels of the order of 700—1000 psia to allow economical transport in pipes of reasonably small diameter. Compression of the gas to pipeline inlet pressure may be required.

Oil ProcessingAfter free water removal, produced oil often contains excessive residual emulsified water. Treating, also called dehydration, is required to reduce the water content to a value acceptable for transportation or sales. Dehydration should be accomplished using the most economic com-bination of four factors or techniques; namely, residence time, chemical addition, heat, and electrostatic fields. Dilution water must occasionally be added to reduce the salt content of the residual emulsion (i.e., the sales crude oil) to a suitably low level. Desalting is usually performed in the refinery;. Desalting is sometimes performed in the field.Hydrogen sulfide in crude oil is limited to reduce handling and transportation difficulties because of its extreme toxicity and corrosiveness. Gas stripping or heating is usually used for hydrogen sulfide removal or sweetening.

Crude oil stabilization refers to lowering the vapor pressure to a value that will allow safe handling and transport. Vapor pressure control is obtained by stage separation, reboiled distillation, or a combination of the two. During stabilization some of the more volatile hydrocarbons are removed as vapor and this gas phase entrains hydrogen sulfide and other volatile sulfur compounds from the sour crude oil. Additional sweetening may not be required.

Water ProcessingProduced water (usually saline) is a waste material, but processing is often necessary to render the water suitable for disposal to the surroundings. Often additional water, frequently sea water, is also processed for waterflooding. Oil removal is the first treatment for produced waters. Oil-in-water emulsions are difficult to clean up due to the small size of the particles, as well as the presence of emulsifying agents. Suspended solids may also be present in the water. Types of equipment used for removing oil and solids include:• Oil skimmer tanks• Plate coalescers• Air flotation tanks• Hydrocyclones• Filtration units

Before reinjection, the produced water is usually filtered, deaerated if necessary, and treated with biocides. The major goal, of course, is to prevent reservoir plugging. Dissolved oxygen is removed either by chemical scavengers, by gas or vacuum stripping, or by catalytic reaction with hydrogen. This reduces the corrosivity of the water dramatically and inhibits growth of aerobic slime-forming bacteria in the wellbore. Then the water is sterilized either by ultraviolet radiation or additional biocide injection to kill bacteria and other micro-organisms. Micro-organisms can cause corrosion, plugging of lines and reservoir formation rock, and they can also produce H2S in the formation. Scale inhibitors are also added before injection into the formation. In a massive

waterflood (over 400,000 bwpd), treatment of injection and produced waters represents a major cost that often exceeds that of treating the crude oil.

Sand TreatmentSand and other solid material may gather in any of the previously mentioned equipment in locations where the velocity and turbulence in the liquid stream is low, such as in the bottom of tanks or on coalescer plates. Removal of the sand by some type of jetting nozzle or similar arrangement may be necessary. Sand removal is sometimes carried out by centrifugal cone desanders. The sand itself may have adhering oil or emulsion that requires washing before discharge to the surroundings.

Natural Gas Processing

Hydrocarbon condensate, liquid water and solids should be separated from the gas stream as early as practical. Then the individual streams can be treated with less difficulty.The first unit operation is the physical separation of the distinct phases, which are gas and possibly liquid hydrocarbon, liquid water, and/or solids. The temperature and pressure of the gas stream dictates whether liquid hydrocarbon and/or water are present. Phase separation usually occurs in a pressure vessel provided for that purpose. Gas leaves from the top of the vessel and liquid from the bottom. If a three-phase separator is needed, special internal elements are required to permit separation of the water and hydrocarbon liquids. Solids fall to the bottom and must be removed by special techniques. Mist extractors—wire mesh, vanes, or baffles—are sometimes used to reduce liquid entrainment in the gas stream. In gas processing, natural gas/liquid phase separation is generally not too difficult, and entrainment of one phase in the other is not excessive. Slug catchers are required in some gathering systems or at the terminus of offshore pipelines where large slugs of liquid may occur at random intervals.

The next step in processing is treating, if necessary, to remove the acid-gas components hydrogen sulfide and carbon dioxide; the former is toxic and both are corrosive. Hydrogen sulfide removal must be essentially complete, while the extent of carbon dioxide removal depends on the intended use for the gas. If the gas is to be cooled to cryogenic temperatures (less than, say, -100°F), CO2 removal to a few tenths of a percent may be required to prevent formation of solid CO2. Also, if the heating value of the gas is too low, partial CO2 removal may be required. In some cases the gas is compressed prior to treating.

Treating processes frequently consist of countercurrent contacting of the gas in an absorber with a chemical or physical solvent—most often a water solution of an ethanolamine. Therefore treating precedes dehydration.

The side stream from treating consists mainly of H2S and/or C02. Environmental regulations usually limit venting or flaring H2S to the surroundings, so conversion to elemental sulfur is necessary. The primary conversion process is the Claus process, in which one-third of the H2S is burned to SO2 and then reacted with the remaining H2S to form elemental sulfur and water vapor. Sulfur recovery is a big business, and many plants recover 500 to 1000 tons a day. Carbon dioxide is usually vented to the atmosphere but sometimes is recovered for CO2 floods.

Dehydration is often necessary to prevent formation of gas hydrates, ice-like substances that may form and plug processing equipment or pipelines at high pressure, even at temperatures considerably higher than 32°F (0°C). The two principal dehydration methods are glycol contacting and solid-desiccant adsorption. Methanol or glycol also can be injected to prevent hydrate formation.

Gas containing considerable amounts of liquefiable HC (ethane, propane and heavier) produces condensate upon cooling or compressing and cooling. If condensation would occur in the transportation, processing, or use of the gas, it may be better to remove the condensate at or near the wellhead.

In some cases the potential NGL are sufficiently valuable to justify their recovery, quite apart from other considerations. Normally, condensate is fractionated into the NGL products in a central facility rather than in the field. Recovered condensate may have to be stabilized by partial removal of dissolved gaseous components to obtain a liquid product with low-enough vapor pressure to be transported safely.

If the wellhead pressure is low, the natural gas must often be compressed to permit pipeline transport. Transport is commonly done at high pressure levels (700-1000 psig) to reduce the pipeline diameter. Pipelines may operate at very high levels (above 1000 psig) to keep the gas in the dense phase and thus prevent condensation and two-phase flow. Compression also may be required as a necessary step in condensate recovery.

The final destination of the finished gas stream depends on the project. Natural gas or associated gas is usually injected into a pipeline for sales. Early in the life of a remote field, before the availability of a gas pipeline, separator gas may be flared temporarily. The ability to flare depends on governmental regulations as well as the field location. More and more, separator gas is being conserved by compression and reinjection into the formation for eventual recovery and sales. Also, in gas condensate reservoirs, the gas is often reinjected, or "cycled," to prevent condensation of valuable liquid hydrocarbons in the reservoir.

Surface Gathering Systems

Hydrocarbons must be separated from each other and from water before they may be processed into usable petroleum produces. The equipment used for field processing is expensive and is often installed so that several wells are served by a single process facility. The fluids produced from one or more wells are collected in a gathering system and transported to the separation facilities. The gathering system may consist of a single flowline from a well to its separation equipment or many flowlines, headers, and process facilities.

Usually the wells are drilled according to specific geographical spacing. Depending on ownership of mineral rights and regulations, wells are drilled within areas called leases. The petroleum produced from different leases must be kept separate. Lease restrictions and economics determine the arrangement of gathering systems and the equipment used.

Types of Gathering SystemsOne type of gathering system is a radial gathering system. The flowlines in this system converge at a central point where facilities are located. Flowlines are usually terminated at a header, a pipe large enough to handle the flow of all flowlines.

Another gathering system is an axial or trunk-line gathering system. This gathering system is usually used on larger leases, or where it is not practical to build the process facilities at a central point. The remote headers are simply smaller versions of those used in radial systems.Leases are equipped to process fluids through equipment large enough to handle all wells simultaneously. To measure the production of individual wells simultaneously, a very complex process and metering facility is required. However, unless some method is provided, all fluid is measured at once; no information on individual wells can be gained.Regulations and good operating practices require that oil, gas, and water production rates be measured for individual wells. Most leases are equipped so that all but one well on a lease are routed through the large process equipment, and the production from this equipment represents the entire lease.

The fluids from one well are routed through other equipment so that the flow rates for that well may be measured singly.To measure the fluid from a well separately, a method must be provided for routing fluids to the production facility (the equipment used for all wells at once) or the test facility (the system for a single well). This selection is made in a well test header. To test a single well, the test valve is opened and the production valve closed. All other well's production valves are open and test valves closed.When test and production facilities are used with a trunk-line gathering system, both test and production trunk lines are required. The type of gathering system used on an individual lease is determined on the basis of economics. A radial system requires many feet of comparatively small pipe for flowlines. The cost of this pipe may be small in comparison to the cost of the larger pipe required for trunk lines, and the total cost of many long flowlines may be less than that of the same number of short flowlines and one or two long, large trunk lines. The latter is particularly true of the thick pipe used for high-pressure gas production leases.

Another consideration in determining the type of gathering system is the use to which the surface land is put. If the land is rugged pasture land, the flowlines may be laid on the surface and left there permanently. If the land is under cultivation or a populated area, the pipe must be buried 3-5 feet deep to assure it is below the maximum operating depth of earthworking equipment (like farm machinery). In these areas the flowlines may be required to be buried beneath or adjacent to roads or streets. The length, installation cost, and maintenance costs of the gathering system are influenced by land use, and these factors determine the gathering system type.

Oil Treating and separationRarely is clean oil, ready for sale into a pipeline, produced from an oil well. Generally, what comes out of the well is a mixture of oil, water, gas, and even sand or solid material. Foreign material, such as water and sand, must be separated from the oil and gas before they can be sold. This process is known as oil treating or oil dehydration, in which water is removed from the oil. The amount of this foreign material is referred to as the BS&W, or basic sediment and water, content of the oil. Normally, the BS&W content must be less than one percent before the oil will be acceptable for sale into a pipeline.

Separators and free-water knockout drums are used for simple separation of oil and water.

SeparatorsA separator is a simple device, which basically utilizes the force of gravity to separate oil-gas mixtures. In a vertical separator, the oil and gas mixture enters at the center of the vessel. The oil, which is heavier than the gas, falls to the bottom of the vessel and is taken off through the fluid line. The lighter gas rises to the top and is removed for separate sale.

The oil level control is used to maintain a certain fluid level in the separator, so gas cannot escape out the bottom of the vessel. The float is connected to a control device that closes the valve on the oil flow line when the oil level drops below a designated point. After the vessel fills to a certain level, the float again rises and allows the oil valve to open and the oil to flow out of the vessel.Separators are commonly used with high pressure wells involving large volumes of fluid, or in offshore production operations, where high pressure flowing oil and gas wells usually require separation of the gas and oil for shipment in different pipelines.

Free-Water KnockoutsAnother simple device used to separate oil, water, and gas is the free-water knockout drum. Oil, water, and gas from the well flow into the vessel through an inlet valve and then are allowed to slow down in the large settling chamber. Here, any free water mixed with the oil settles to the bottom of the vessel and is drawn off and disposed of. The oil is removed through a separate line and sent to additional oil processing equipment. The natural gas, which rises to the top of the vessel, is extracted through a third line.

The vessel is called a free-water knockout, because it is designed to eliminate only water which has not been emulsified with the oil, that is, water which is free to separate by itself. Water which has been emulsified, or dispersed into very fine drops within the oil, will not separate by itself and will not be eliminated by the free-water knockout. This water must be further processed by a device which can supply heat to the emulsion and force it to separate. In principle, free-water knockouts are almost identical to separators, although free-water knockouts are larger and are generally placed horizontally. As with separators, the oil and water outlets are controlled by level control valves, which prevent the vessel from draining completely and keep the gas trapped in the top of the vessel. Free-water knockouts are most commonly used for low pressure wells, but they can be used to handle high volumes of fluid.

Steel TanksSteel storage tanks are available in two forms: (1) small tanks (500 barrels or less), and (2) large tanks (1000 barrels or more). Solid sediment produced with oil and water usually accumulates in tanks because this is the first place where fluid is stopped long enough for the solids to settle. The shape of the tank bottom is important in the movement of solids. Flat-bottom tanks (Figure 7-3) were the first tank shapes developed. When solids present no problems in a facility, flat bottom tanks are satisfactory for use. Cone-bottom tanks (Figure 7-4) are used most often for permanent storage facilities because they are better suited for handling solids. As solids settle from liquids, they drift to the center of the bottom of the tank. Since the solids are always located in the same place, it is easier for them to be recovered or at least kept suspended in the liquid. Periodically, solids must be removed from tanks. Solids may be pumped out with some liquids, or people may enter the tank and scoop up the solids.

On many production leases, storage requirements do not remain fixed for long periods of time. Sometimes a water tank is required for several months but then not required again for several years. Many production facilities are built using temporary or portable tanks. That is, tanks are used for a time and then moved to another site. Flat bottom tanks are usually used for temporary applications because they can be installed with a minimum of site preparation.

Site PreparationStorage tanks are very heavy when filled with liquid (a 500-barrel tank filled with water weighs more than 80 tons). The earth on which a tank sits must be carefully prepared to be able to withstand this load without shifting.Most permanent storage facilities are built on a pad or raised surface. It is easier to form the tank base on a raised surface than at ground level. The tank pad must be formed of firm material that has been leveled and thoroughly compacted. Then as the weight of a tank bears down on the pad, the pad is not likely to shift.The tank pad must correspond to the shape of the tank bottom exactly. If the base under a tank is uneven, the weight of liquid will exert uneven forces on the tank bottom and sides. The sides of storage tanks are not designed to withstand vertical forces, only lateral forces. Therefore, the tank base must be shaped to correspond to the bottom of the tank.In populated areas and critical storage areas tank dikes are often required by law but should be used as a part of sound operating practice. A tank dike, shown in Figure 7-6, is a raised earthen structure with a volume at least as large as the tank's. The dike's purpose is to contain the contents of a tank in the event of a massive leak and keep the liquid from running into populated areas or polluting the surrounding ground. These dikes are particularly effective if a tank ruptures and the contents ignite. The burning liquid is restricted to a small area where it can be extinguished easily.

The tank dike is sometimes constructed with fire fighting in mind. A pipeline equipped with spray nozzles is run around the dike and connected to a water or foam supply. This design provides for sprays on the tanks to extinguish a fire or cool the tank to prevent fire.Tank dikes may be made of earth shaped with earth working machinery. This earth is usually covered with asphalt to prevent erosion. The dike may also be constructed of concrete for sturdy and permanent application.

Ancillary EquipmentIn addition to the body of the tank which actually contains the liquid, there are several pieces of equipment associated with storage tanks that improve or augment the operation of the tank system.Sumps. Sumps (Figure 7-8) are sometimes used with tanks to allow a place for solids to accumulate and to allow a place to pump liquids. The sump is simply a large-diameter cylinder (12-36 inches) at the bottom of the tank. Liquids are pumped out of the tank from a suction line in the sump.

Risers. Risers are sometimes used to force liquids to enter or exit a tank from a level different from the level at which the liquid enters the tank. Siphons. Sometimes siphon lines (Figure 7-10) are used to remove liquid from the bottom of a tank. The siphon line utilizes the same physical principles as common applications of siphoning.Spreaders. When liquid enters a tank (like a gun-barrel tank), the liquid is expected to enter as a spray instead of a liquid stream. A spreader, such as the one in Figure 7-11, makes liquid enter over a wide area. Spreaders are used to make incoming liquids mix with stored liquid or aerate incoming liquids.Roll Lines. Even though solids do accumulate in the bottom of tanks, it is sometimes undesirable to allow them to do so. A roll line (Figure 7-12) is a thin pipe which is routed around the inside circumference of a tank. The pipe is perforated so when gas is injected into the tank, it agitates the tank's contents.Agitators. An agitator is a propeller or fan inside the tank. The propeller is rotated by an external electric motor. Agitators are used to move liquids within the tank and agitate solids and liquids.Thief Hatch. Access to the tank's interior is necessary to determine its contents. Tanks are equipped with thief hatches which allow access, but which seal the tank when closed. A thief hatch is a pressure-actuated device which can be opened but which also acts as a seal and an over-pressure protection device. Because tanks have large areas exposed to internal pressures, the internal pressure must be kept lower than a few ounces per square inch to keep from rupturing the thin metal walls and deck.Pressure Relief Valves. Although thief hatches serve as high-pressure relief valves, their adjustment is somewhat unpredictable. Relief valves are used when the venting pressure is critical. One application of relief valves is when vapor recovery units are used. The internal pressure is maintained as high as possible when vapor recovery units are used to provide maximum suction pressure, but it is important that a relief valve be used to keep the pressure from becoming excessive.Walk and Stair. Occasionally, it is necessary to reach the top of tanks to adjust valves or sample the contents. Walkways and stairs are necessary to reach and safely work at the top of the tanks.

Single Phase Flow in Pipes

Single phase flow can be characterized as being laminar or turbulent depending on the value of a dimensionless group NRe. The NRe is the ratio of the inertial forces to the viscous forces in a flowing fluid, and for flow in a circular pipe is given by

When the flow is laminar, the fluid moves in distinct laminae, with no fluid motion transverse to the bulk flow direction. Turbulent flow, on the other hand, is characterized by eddy currents that cause fluctuating velocity components in all directions. The pressure drop over a distance L, of single phase fluid flow in a pipe can be obtained by solving the mechanical energy balance equation which in differential form is:

+dWs=0

For an incompressible fluid with no shaft work, this equation becomes:

ff is the fanning friction factor that can be read from a moody friction factor

diagram as a function of NRe and relative roughness .

For single phase flow of compressible fluid in a horizontal pipeline the mechanical energy balance equation can be integrated assuming average values of Z and T (for details refer to the text, Economides).In oilfield units of T( in R), P (in psi), q in (MSCF/d), D (in inch), L (in ft) the pressure drop for horizontal gas flow in circular pipes is calculated from:

The equation is implicit in p and must be solved iteratively.

Two Phase Flow in PipesIdentification of flow regime and application of the appropriate pressure gradient correlation are two important aspects of two phase flow.Flow regime: The manner in which two phases are distributed in the pipe significantly affects other aspects of two phase flow such as pressure drop and slippage between phases. The flow regime or flow pattern is a qualitative description of the phase distribution. The flow regime does not affect the pressure drop as significantly in horizontal flow as it does in vertical flow because there is no potential energy contribution to the pressure drop in horizontal flow.

However, the flow regime is considered in some pressure drop correlations and can affect production operations in other ways. Most important, the occurrence of slug flow necessitates

designing separators or sometimes special pieces of equipment (slug catchers) to handle the large volume of liquid contained in a slug. Particularly in offshore operations, where gas and liquid from subsea completions are transported significant distances to a platform, the possibility of slug flow, and its consequences, must be considered.

Figure 10-1 (Brill and Beggs, 1978) depicts the commonly described flow regimes in horizontal gas-liquid flow. These can be classified as three types of regimes: segregated flows, in which the two phases are for the most part separate; intermittent flows, in which gas and liquid are alternating; and distributive flows, in which one phase is dispersed in the other phase.Segregated flow is further classified as being stratified smooth, stratified wavy (ripple flow), or annular. Stratified smooth flow consists of liquid flowing along the bottom of the pipe and gas flowing along the top of the pipe, with a smooth interface between the phases, This flow regime occurs at relatively low rates of both phases. At higher gas rates, the interface becomes wavy,

and stratified wavy flow results. Annular flow occurs at high gas rates and relatively high liquid rates and consists of an annulus of liquid coating the wall of the pipe and a central core of gas flow, with liquid droplets entrained in the gas.The intermittent flow regimes are slug flow and plug (also called elongated bubble) flow. Slug flow consists of large liquid slugs alternating with high-velocity bubbles of gas that fill almost the entire pipe. In plug flow, large gas bubbles flow along the top of the pipe, which is otherwise filled with liquid.

Flow regimes in horizontal flow are predicted with flow regime maps. One of the first of these and still one of the most popular is that of Baker and Scott. There are a number of other flow regime maps (refer to the text and also Beggs and Brill)

In which:

Gl and Gg are mass fluxes of liquid and gas, respectively (lbm/hr-ft2)

Densities are in lbm/ft3, viscosity in cp and surface tension in dynes/cm.

Pressure gradient Correlations. Over the years numerous correlations have been developed to calculate pressure gradient in horizontal gas-liquid flow. Dukler correlation is one of the most commonly used correlations.

The dukler correlation is based on empirical correlations of friction factor and liquid holdup. The pressure gradient again consists of friction and kinetic energy contributions.

For complete formulation refer to the text (Economides).

References:

Francis S. Manning, Richard E. Thompson, Oilfield Processing. Volume two: Crude Oil. PennWell Books, Tulsa, 1995.

Francis S. Manning, Richard E. Thompson, Oilfield Processing. Volume one: Natural Gas. PennWell Books, Tulsa, 1991.

George V. Chilingarian, John O. Robertson, Jr., Sanjay Kumar, Surface Operations in Petroleum Production I, Elsevier Developments In Petroleum Science 19A, New York, 1987

George V. Chilingarian, John O. Robertson, Jr., Sanjay Kumar, Surface Operations in Petroleum Production II, Elsevier Developments In Petroleum Science 19B, New York, 1987

D.R. Skinner, Introduction to Petroleum Production. Vol 2. Fluid Flow, Artificial Lift, Gathering Systems, and Processing., Gulf Publishing Company, Huston, 1982.

Francis A. Guiliano, Introduction to Oil and Gas Technology. International Human Resources Development Corporation, Huston, 1981.

Brill J.P., Beggs, H.D., Two-phase Flow in Pipes., University of Tulsa, Tulsa, 1978