Surface facilities encompass the equipment between the wells
and the pipeline or other transportation method. The purpose of the surface
facility is to remove impurities and contaminants from the oil/gas, remove other
liquids and solids, and prepare the oil/gas to meet the sales requirements of
facilities involve several units that function differently to process
hydrocarbons so as to be ready for sales, these facilities involve:
The wellhead is
the equipment at the surface that provides support for the tubulars inside the
well, a pressure seal between the tubulars, and a means of controlling
production from the well. Typically, the wellhead consists of a casing head for
each casing string, a tubing head, and a christmas tree. For each string of
pipe in the well, casing, or tubing, some means of support and pressure sealing
must be provided. This is the function of the casing and tubing heads.
The christmas tree provides the necessary valving and chokes to
control the production from a well capable of flowing.
wellhead & christmas tree are located on the platform and can be easily
operated by man, called surface wellhead or dry tree. However, for deep water
or when platform installation is considered not cost-effective, wellhead &
Christmas tree may be located on the seabed, called subsea wellhead or wet
The following figure shows a typical wellhead
for a flowing well. Notice that a choke is provided to control the rate of
production from the well in addition to the tubing wing valve, which provides
for a complete shut-off of the production. The choke can be either fixed or
variable in size. The choke is nothing more than a small orifice, usually from
1/8 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 are
called casing valves and they provide access to the various annulii
between casing strings and tubing. Normally, the wellhead is fitted with
pressure gauges for monitoring pressure within the different annulii and in the
The flow rate from either an oil well or a gas well can be easily
estimated from the wellhead pressure if the wellhead pressure is at least twice
the flowline pressure. For an oil well, the Gilbert equation is commonly used:
gross liquid flow rate (bbl/day)
flowing tubing head pressure (psia)
gas to liquid ratio (MSCF/bbl)
choke size (1/64 in.)
For a gas well, the following equation is used:
gas flow rate (MSCF/day)
flowing tubing head pressure (psia)
choke size (in.)
gas specific gravity
wellhead temperature (°R)
oil and gas are brought to the surface, our main goal becomes that of transportation
of the oil and gas from the wellhead to the refinery (for final processing) in
the best possible form. All equipment and processes required to accomplish this
are found at the surface production facility. Hence, all surface production
starts right at the wellhead. Starting at the wellhead, the complex mixture of
produced fluids makes its way from the production tubing into the flow line.
Normally, many wells are drilled to effectively produce the hydrocarbons
contained in the field. From each of these wells emerge one or more flow lines
depending on how many layers are being produced simultaneously. Depending on
the physical terrain of the area and several other environmental factors, each
of the flow lines may be allowed to continue from the wellhead to a central
processing facility commonly referred as a production platform or a flow
station. If not, all the flow lines or several of them empty their contents
into a bigger pipeline called a bulk header, which then carries the fluids to
the production platform. The combination of the wellhead, the flow lines, bulk
headers, valves and fittings needed to collect and transport the raw produced
fluid to the production platform is referred to as the gathering system.
gathered fluids must be processed to enhance their value. First of all, fluids
must be separated into their main phases; namely, oil, water, and natural gas.
The separation system performs this function. For this, the system is usually
made 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 last
physical separation of these three phases is carried out in several steps.
Water is separated first from the hydrocarbon mixture (by means of the FWKO), and
then the hydrocarbon mixture is separated into two hydrocarbon phases (gas and
oil/condensate). A successful hydrocarbon separation maximizes production of
condensate or oil, and enhances its properties. In field applications, this is
accomplished by means of stage separation. Stage separation of oil and gas is
carried out with a series of separators operating at consecutively reduced
pressures. Liquid is discharged from a higher-pressure separator into the
next-lower-pressure separator. The purpose of stage separation is to obtain
maximum recovery of liquid hydrocarbons from the fluids coming from the
wellheads and to provide maximum stabilization of both the liquid and gas effluents.
it is most economical to use three to four stages of separation for the
hydrocarbon 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 not
linear. For instance, the increase in liquids gained by adding one stage to a
single-stage system is likely to be substantial. However, adding one stage to a
three or four stage system is not as likely to produce any major significant
gain. In general, it has been found that a three stage separating system is the
most cost effective.
the assumption of equilibrium conditions, and knowing the composition of the
fluid stream coming into the separator and the working pressure and temperature
conditions, we could apply our current knowledge of VLE equilibrium (flash
calculations) 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 under
which we would get the most economical profit from the operation. In this
context, we have to keep in mind that stage separation aims at reducing the
pressure of the produced fluid in sequential steps so that better and more
stock-tank oil/condensate recovery will result.
The design of a particular
separator depends on the nature of the flow stream to be separated. Since we
are more concerned with gas wells, separators usually separate a small amount of
liquid from the gas. In an oil well, the separation may involve a small amount
of gas for the amount of liquid. In general, the well stream separator must
separate the mostly liquid fluids from the mostly gas fluids. In addition, it
must separate liquid hydrocarbon from liquid water and remove most of the
entrained liquid mist from the gas.
To accomplish the separation, the
separator is usually designed to control and dissipate the well stream flowing
energy. Once gas and liquid velocities are slow enough, gravity causes the
liquid to settle and the gas to rise. The size of the vessel must be such that
adequate time is allowed for this settling to occur before the fluid leaves the
separator. If water is to be separated from oil, then the liquid residence time
depends on the volume of the fluid being handled and the specific gravity of
the two liquids. Many times, a mist extractor composed of vanes, mesh pads, or
a cyclonic passage is used to remove residual liquid droplets from the gas
There are three types of
separators: vertical , horizontal, and spherical .
Horizontal separators are found in both the single tube and double tube design.
well stream enters the separator through the tangential inlet, which imparts a
circular motion to the fluids. A Centrifugal and gravity force provides
efficient primary separation. A conical baffle separates the liquid
accumulation system from primary section to ensure a quiet liquid.
releasing solution gas. The separated gas travels up ward through the secondary
separation section where the heavier entrained liquid particles settle out. The
gas flows through the mist extractor and particles accumulate until sufficient
weight to fall into the liquid accumulation section. Sediments enter the
separator and accumulate in the bottom and flushed out through the drain
Advantages of the vertical
Good for predominantly liquid
Can handle producing stream surges
Occupies little space (small
Easily cleaned of sand and mud
2. Horizontal separator
tube the well stream enters through the inlet and strikes an angle baffle or
dished deflector and strikes the side of the separator, producing maximum
primary separation. Horizontal divider plates separate the liquid accumulation
and gas separation section to ensure quick removal of solution gas. The
separated gas passes through the mist extractor where liquid particles where
liquid particles 10 micron and larger size are removed.
tube consist of an upper separator section and lower liquid chamber. The mixed
stream of oil and gas enters the upper tube. Liquid fall through the first
connecting pipe into the liquid reservoir and wet gas flows through the upper
tube where the entrained liquid separate owing to difference in density and to
scrubbing action of mist extractor.
Advantages of the horizontal
Good for predominantly gas streams
Easy to fabricate, ship, and
3. Spherical separator:
incoming well stream is split by the inlet flow diverter and directed
tangentially against the wall of the separator. The liquid streams come
together after flowing 180o around the vessel wall and then fall into the
accumulation section to remain there until released.
gas stream is travelling through the large diameter and loses particles due to
its reduced velocity. Then, the gas passes through mist extractor.
For the spherical separator, the
Good for high pressure gas wells
Compact, small size
Operating pressure: a change in pressure effects changes in the gas and liquid
densities, velocity and flowing volume. The net effect on an increase in
pressure is an increased gas capacity of the separator.
Temperature: it affects the actual flowing volume and densities of the gas and
liquid. The net effect of an increase of temperature is a decrease in capacity.
Well stream crude oil composition
process results two streams, oil stream and gas stream ( besides water stream
which is treated chemically before being disposed or used for tertiary recovery
methods) each of these two streams take a treatment path before being stored or
No separation is perfect, there is always some
water left in the oil. Water content can range from less than 1% water to more
than 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 is
similar to a separator, but with special features to help separate the water
from the oil. Treaters or treating systems usually provide heat to reduce oil
viscosity and large settling sections to allow the water time to settle from
the oil, and may provide an electrostatic grid to promote coalescing of the
After being treated, oil is transported through
flowlines to be stored in storage tanks.
Under normal production conditions,
natural gas is saturated with water .
Water as a vapor is not the major problem. However, when water combines
with the gas molecules, e.g. methane, ethane, propane and forms solid hydrates
such as CH4.7H20, C2H6.8H2O
and C3H8.18H2O , then it becomes a problem.
Hydrates form ice-like solids when free water combines with the components of a
formation is undesirable because:
plugging of flow lines, equipment and instruments.
in unnecessary maintenance and lost production.
of preventing hydrates formation
heat to assure that the temperature is always above the hydrate formation
temperature ( indirect heaters are used to heat gas streams at the well head and in pipelines)
2- Lowering the hydrate formation
temperature with chemical inhibition
3- Dehydrating the gas so that water
vapor will not condense into free water.
4- Design the process so that if
hydrates form they can be melted before plug equipment:
i-Reduce pressure drops by minimizing
line lengths and restrictions.
ii-Check the economics of insulating
pipe in cold areas.
(MeOH) and monoethylene glycol (MEG) are the two chemicals most commonly
injected into gas streams to inhibit
works well as a hydrate inhibitor because of the following reasons:
can attack or dissolve hydrates already formed.
does not react chemically with any natural gas constituents.
is not corrosive.
is reasonable in cost.
is soluble in water at all concentrations.
following figure shows a simplified schematic of a typical methanol injection system. This system inhibits hydrate
formation at a choke or pressure-reducing valve. A gas-driven pump injects the
methanol into the gas stream upstream of
the choke or pressure-reducing valve. The temperature controller
measures the temperature in the gas
stream and adjusts the power-gas control valve. The power-gas control valve
controls the flow of power gas, which controls the methanol injection rate.
In addition to
heavy hydrocarbons and water vapor, natural gas often contains other
contaminants that may have to be removed. Carbon dioxide (CO2) , hydrogen
sulfide(H2S) , and other sulfur compound such as mercaptans are compounds that
may require complete or partial removal
for acceptance by gas purchaser.
These compounds are known as “acid gases”.
H2S combined with water forms a weak
form of sulfuric acid, while CO2 and water
forms carbonic acid, thus the term acid gas.
Natural gas with H2S or other sulfur compounds
present is called “sour gas” ,while gas with only CO2 is called “sweet” .
Hydrogen sulfide, carbon dioxide, mercaptans
and other contaminants are often found
in natural gas streams. H2S is a highly toxic gas that is corrosive to carbon
steels. CO2 is also corrosive to equipment and reduces the Btu
value of gas. Gas sweetening processes remove these contaminants so the gas is
suitable for transportation and use.
remove acidic components
There are many methods that may be
employed to remove acidic components (primarily H2S and CO2) from hydrocarbon
The available methods may be broadly
categorized as those depending on chemical reaction, absorption, or adsorption
process(hot potassium carbonate)
conversion of H2S to sulfur
Each of the previous treating
processes has advantages relative to the others
for certain applications , therefore, in selection of the appropriate
process, the following facts should be considered:
type acid contaminants present in the gas stream.
concentrations of each contaminant and degree of removal desired.
volume of gas to be treated and temperature and pressure at which the gas is
feasibility of recovering sulfur.
desirability of selectively removing one or more of the contaminants
without removing others.
presence and amount of heavy hydrocarbons and aromatics in the gas.
illustration of gas sweetning by chemical reaction
After sweetning, sweet gas moves to
Dehydration is the act or process of
removing water from gases or liquids, Removing water
from natural gas streams helps prevent the following:
• Line blockages
• Accelerated corrosion
• Hydrate formation and condensation
of 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.
dehydration systems absorption using liquid desiccants
assimilation of one material into another.In natural gas dehydration, the use
of an absorptive liquid to selectively remove water vapor from a gas stream.
substance used in a dehydrator to remove water and moisture.
desiccants : A typical cycle includes contacting the liquid desiccant with the
gas stream and then stripping the water from the desiccant.
DIAGRAM FOR GLYCOL DEHYDRATION UNIT
GLYCOL DEHYDRATION PROCESS
Wet inlet gas enters the bottom of
the contactor while lean glycol enters the top. As the wet gas stream flows
upward, it contacts the downward flowing lean glycol. During this contact, the
glycol absorbs water from the gas stream.
Dry outlet gas leaves the top of the
contactor and rich glycol exits the bottom. The rich glycol enters the top of
the stripping column and counter currently contacts steam rising from the reboiler.
The rich glycol then enters the
reboiler, which boils the water out of the glycol. The lean glycol leaves the
bottom of the reboiler and enters the surge tank for storage. The pump raises the glycol to system
pressure, preparing it for another dehydration cycle.
Dry gas then flows in a flowline to be connected to gas network and
fractionated LPG flows in another discrete flowline to LPG storage tanks.