Oil & Gas Production

1. PRODUCTION
Introduction
In the petroleum industry, production is the phase of operation that deals with bringing well
fluids to the surface and preparing them for their trip to the refinery or processing plant.
Production begins after drilling is finished.
The first step is to complete the well. That is, to perform whatever operations are necessary to
start the well fluids flowing to the surface. Routine maintenance operations, such as replacing
worn or malfunctioning equipment, known as servicing, are standard during the well’s
producing life. Later in the life of the well, more extensive repairs, known as workovers, may
also be necessary to maintain the flow of oil and gas.
The fluids from a well are usually a mixture of oil, gas, and water, which must be separated after
coming to the surface. Production also includes disposing of the water and installing equipment
to treat, measure, and test the oil and gas before they are transported away from the wellsite.
If a well does not flow on its own after washing in, swabbing, and stimulation, it needs an
artificial means of lifting oil to the surface. When the hydrocarbons do flow out of the well, they
go through a pipe called flow line to a storage tank and gas separators.
Hence, Production is a combination of operations: bringing fluids to the surface; doing whatever
is necessary to keep the well producing; and taking fluids through a series of steps to purify,
measure, and test them.
Wellhead
The wellhead includes all equipment on the surface that supports the various pipe strings, seals
off the well, and controls the paths and flow rates of reservoir fluids. All wellheads have at least
one casing-head and casing hanger, usually a tubing head and tubing hanger, and a Christmas
tree.
Casing-head
Each string of casing usually hangs from a casing-head, a heavy steel fitting at the surface. Metal
and rubber seals in the casing-head prevent fluids from moving within the wellhead or escaping
to the atmosphere. Each casing-head has a place for a pressure gauge to warn of leaks.
Tubing Head
The tubing head supports the tubing string, seals off pressure between the casing and the inside
of tubing, and provides connections at the surface to control the flowing liquid or gas. The
tubing head stacks above the uppermost casing-head. It has outlets to allow access to the
annulus for gauging pressure or connecting valves and fittings to control the flow of fluids.

2. Christmas Tree
High-pressure wells usually have a group of valves and fittings called a Christmas tree. Low-
pressure wells may also have Christmas trees. These trees are less complex than high-pressure
ones but serve the same purpose: to regulate, measure, and direct the flow of fluids from the
well.
Pressure gauges on the Christmas trees measure pressure both in the casing and in the tubing.
Valves on the tree can be opened and closed to control the flow of fluids from the well. The
main valve is the master valve just above the tubing head. Opening the master valve allows the
fluid to flow to the rest of trees, and closing it shuts off the flow of reservoir fluids entirely.
Another important part of the Christmas tree is the choke. The choke restricts the line through
which well fluids enter the tree. The size of the choke’s opening is usually adjustable. When a
worker turns a control handle, the opening of an adjustable choke changes size.
Gas Lift
The term gas lift covers a variety of methods by which a gas is used to increase the production
of a well or to restore production to a well that has stopped flowing, a dead well. The
completion crew installs gas-lift valves on the production tubing. The valves allow a gas to be
forced into the annulus to pass into the tubing and into the liquid there.
When the natural gas enters the liquid in the tubing, the gas makes this liquid column much
lighter, it exerts less pressure on the bottom of the well. With the pressure lower at the bottom,
the pressure remaining in the reservoir becomes sufficient to push reservoir fluids to the surface
through the tubing. Depending on the producing characteristics of the well and the arrangement
of the gas-lift equipment, gas may be injected continuously or intermittently.
Surface Handling of Well Fluids
Oil and gas are usually salable as they come from the wellhead. Typically, a well stream is a high-
velocity, turbulent, constantly expanding mixture of hydrocarbon liquids and gases mixed with
water and water vapor, solids such sand and shale sediments, and sometimes contaminants
such as carbon dioxide and hydrogen sulfide.
Several steps are necessary to get the oil, water and gas ready to transport to their next stops.
The well stream is first passed through a series of separating and treating devices to remove the
sediments and water, to separate the liquids from the gases, and to treat the emulsions for
further removal of water, solids, and undesirable contaminants.
For oil production, the facility is typically a two or three-phase separator; for gas production, the
facility may be a gas plant, a compressor station or simply a transport pipeline; and, for injection
wells, the surface transport of interest is from the water treating/pumping facility to the wells.
In addition to flow through pipes, flows through fittings and chokes are important
considerations for surface transport.

3. The oil is then stabilized, stored, and tested for purity. Finally, the oil is shipped to a further
pipeline (proof) metering station before it is transported to the export pipeline. The water is
recycled through the treatment plant where any oil is recovered for reuse. Then the water is
centrifuged and heated to separate out the solids. After the water is stripped out of oxygen, it is
stabilized, stored, and tested for purity. Finally, the water is transported to the injection
pipeline. The gas is tested for hydrocarbon content and impurities, and gas pressure is adjusted
to pipeline or other transport specification.
Separating Liquids from Gases
The primary activity in surface processing facilities is separating the produced fluids into streams
of oil, gas, and water for sale and disposal. A “two-phase” horizontal vessel separates fluids into
liquids and gas. This separation is accomplished largely by gravity segregation. The lighter
element, gas, is removed from the top of the tank and enters the gas gathering system. The
heavier liquids sink to the bottom of the tank and are then sent into the oil-water dehydrator
that uses centrifugal and gravity forces to separate the liquids into oil-water emulsion and water
& solids.
Multistage Separation
Production fluids pass through more than more than one separator to separate more gas than
liquids. In the three-stage separation, the well fluids pass through a high pressure horizontal
separator for the first stage of separation. In the first stage, the fluids are often under pressure
as they leave the well.
The liquid resulting from the first stage has lost some of its pressure, and is then sent into a
medium pressure horizontal separator for the second stage of separation.
The second separator removes more gas from the liquid because the lower pressure allows
more of the hydrocarbons to vaporize. The liquid resulting from the second stage has lost some
of its pressure, and is finally sent into a low pressure horizontal separator for the third stage of
separation in which most of the gas is removed from the liquid because the lowest pressure
allows most of the hydrocarbons to vaporize.
Treating Oilfield Emulsions
Treating facilities may use a single process or a combination of processes to break down an
emulsion, depending upon the emulsion being treated. To break down a water-in-oil emulsion,
the properties of emulsifying agent must be neutralized or destroyed so that the droplets of
water can come together. Treatments that do this use chemicals, heat, or electricity, along with
gravity.

4. Chemical Treatment
The emulsion that remains after separation from the gas and free water is piped into special
tanks, or vessels, for chemical treatment. Chemicals called demulsifiers are added to the
emulsion in order to make the droplets of water merge. When droplets merge, they get bigger,
and big, heavy water drops settle out faster than small, light ones. A bottle test helps determine
the best chemical to use as a demulsifier for treating an emulsion.
Heat Treatment
The emulsion enters the heat exchanger in which heat is transferred from the hot water to the
cold emulsion causing a change in temperature of the two fluids and a pressure drop across the
heat exchanger. When the emulsion is heated, it becomes more viscous, and the water and oil
molecules move about rapidly, causing the water droplets to strike each other. When the force
and frequency of the collision are great enough, the film of emulsifier that surrounds each
droplet breaks, and the water drops merge and separate form the oil.
Treatment with electricity
Electricity is used in conjunction with heat and chemicals. The film around the water droplets
formed by the emulsifier is composed of molecules that have a positive and negative end, very
much like a bar magnet. When an electric current disturbs this film of polar molecules, the
molecules rearrange themselves. The film is no longer stable, and adjacent water droplets
coalesce freely until large drops form and settle out by gravity.
Dehydration and Desalting
Salts, which are impurities in some crudes, break down refinery processing and foul and corrode
the equipment. They must be removed, along with any water in the crude, at the beginning of
refinery processing, before distillation takes place. When the salts are suspended in the water,
they can be removed by heating the oil and allowing the water-salt solution to settle out.
However, if the oil and water are in the form of stable emulsion that resists separation, chemical
or an electric current must be used to break the emulsion and allow the water- salt solution to
separate from the oil.
The two most typical methods of crude-oil desalting are chemical and electrostatic separation:
In chemical desalting, water and chemical surfactant (demulsifiers) are added to the crude,
heated so that salts and other impurities dissolve into the water or attach to the water, and
then held in a tank where they settle out.
Electrical desalting is the application of high-voltage electrostatic charges to concentrate
suspended water drops in the bottom of the settling tank. Surfactants are added only when the
crude has a large amount of suspended solids. Both methods of desalting are continuous. The
desalted crude is continuously drawn from the top of the settling tanks and sent to the crude
distillation (fractionating) tower.

5. The feedstock crude oil is heated to reduce viscosity and surface tension for easier mixing and
separation of the water. The temperature is limited by the vapor pressure of the crude-oil
feedstock. In both methods other chemicals may be added. Ammonia is often used to reduce
corrosion. Caustic or acid may be added to adjust the pH of the water wash. Wastewater and
contaminants are discharged from the bottom of the settling tank to the wastewater treatment
facility.
Safety Considerations
The potential exists for a fire due to a leak or release of crude from heaters in the crude-
desalting unit. Low boiling point components of crude may also be released if a leak occurs.
Because this is a closed process, there is little potential for exposure to crude oil unless a leak or
release occurs. Hydrogen sulfide will be present where elevated operating temperatures are
used when desalting sour crudes. There is the possibility of exposure to ammonia, dry chemical
demulsifiers, caustics, and/or acids during this operation.
Depending on the crude feedstock and the treatment chemicals used, the wastewater will
contain varying amounts of chlorides, sulfides, bicarbonates, ammonia, hydrocarbons, phenol,
and suspended solids.
Corrosion Considerations
Inadequate desalting can cause fouling of heater tubes and heat exchangers throughout the
refinery. Fouling restricts product flow and heat transfer and leads to failures due to increased
pressures and temperatures.
Corrosion, which occurs due to the presence of hydrogen sulfide, hydrogen chloride, organic
acids, and other contaminants in the crude oil, also causes equipment failure. Neutralized salts
(ammonium chlorides and sulfides), when moistened by condensed water, can cause corrosion.
Over-pressuring the unit is another potential hazard that causes failures.
Moreover, it is a known fact that high water content could lead to untold damage within a few
days if not checked. The water content must be controlled and monitored to within acceptable
levels as the water contamination will cause corrosive wear and change the bearing geometry.
Obstruction of the oil film formation which is needed for the correct functioning of the
crosshead bearing can cause excessive wear and scuffing (erosion/corrosion/abrasion) which in
turn will mean immediate maintenance and additional unwanted repair or replacement costs.
Injection Water
The injected water must be clear, stable, and similar to the water in the formation where it is
being injected. It also must not be severely corrosive and must be free of materials that may
plug the formation. If the water is severely corrosive, it may contain additives to lessen
corrosion, or corrosion-resistant equipment may be used. Softening, filtering, chemical treating,
stabilizing, and testing are common water-treatment processes.

6. Storing Crude Oil
Oil, water-cut oil, and water produced by the well move from the wellhead or separator through
the treating facilities and finally into a group of stock tanks for storage, or tank battery. The total
storage capacity of a tank battery is usually three to seven days’ production. Since the battery
has two tanks, one tank can be filling while oil is being run from another.
Measuring Oil in the Tank
Before the tank battery is put into operation, each tank is strapped, or calibrated. An automatic
tank gauge, a newer method of measuring, consists of a steel gauge line contained in a housing.
A float on the end of the line rests on the surface of the oil in the tank. The other end of the line,
which is coiled and counterbalanced on the outside of the tank, runs through a reading box that
shows the height of oil in the tank.
Tank Construction
Tanks are usually constructed of either bolted or welded steel. They have a bottom drain outlet
for draining off sediment and water (BS&W). Oil enters the tank at the top at an inlet opening.
The pipeline outlet is usually 1 foot above the bottom of the tank; the space below this outlet
provides room for the collection of S&W. A metal seal closes the pipe line outlet valve when the
tank is being filled and is similarly locked in the open position when the tank is being emptied.
Oil Sampling
To assure that the pipeline company will accept the oil, the operator should sample and test the
oil in the same manner as the pipeline company. Because the procedures for taking samples and
making water and sediment tests vary from field to field and company to company, both the
operator and the pipeline must agree on them.
Many methods exist for sampling oil. Sampling can be done either automatically or manually.
Frequently, a sampler manually samples the oil in lease stock tanks. Thief sampling is considered
the most common way to sample the oil in lease stock tank. In thief sampling, the sampler
lowers a thief, around tube about 15 inches long, into a tank to any level within a half inch of the
bottom of the tank. The thief has a spring-operated sliding valve that can be stripped, thus
trapping the sample.
Although manual sampling methods are more common, automatic sampling devices connected
to the pipeline are also used. These devices allow oil to flow into the sample container over a
certain period of time at a constant rate. Field Sampling is usually sent to the laboratory for
testing.

7. Oil Measurement and Testing
The operator usually measures the volumes of oil, gas, and salt water produced by each lease
every 24 hours. When measuring crude oil, the volume must be corrected for any S&W present.
Since the volume varies according to temperature, the volume must also be corrected to a
standard base temperature of 60 F. These requirements call for a series of tests for
temperature, density, and S&W content.
Temperature Measurement
Temperature is usually measured with a special thermometer that is lowered into the oil on a
line and then withdrawn to observe the reading.
Gravity and S&W Measurement
The S&W content and the API gravity (specific gravity, or density, measurement) of oil in stock
tanks are measured from samples taken from the tanks. A sampler takes samples by using a
thief or similar device. Different buyers require different levels of cleanliness. Generally, the
maximum S&W content is 1%.
A centrifuge test, also called a shake-out test, determines the S&W content of the samples. The
test uses a glass container that is graduated so that the percentage of S&W can be read directly.
A hydrometer measures the API gravity of the oil. The technician pours the crude into a cylinder
with accurate levels marked on it and drops the hydrometer into it. It floats at a certain level in
the crude (the higher it floats, the lighter the oil). The markings on the cylinder show the API
gravity in API deg at 60 F.
LACT Units
The development of lease automatic Custody transfer (LACT) has changed the process of
measuring, sampling, testing, and transferring oil from a time-consuming business that required
many hours and was error-prone into an efficient measuring and recording system that leaves
lease personnel free to do other operations. Despite the complexities of gauging and testing
crude oil in the field, automatic equipment can perform the following tasks:
 Measure and record the volume of the oil.
 Determine and record the temperature of the oil.
 Verify the accuracy of flow-meters and provide for calibration when necessary.
 Measure and record the API gravities of the oil produced.
 Switch well production from a full tank to an empty and switch the oil from a full tank to the
pipe line system.
 Detect the presence of water in the oil stream and calculate the percentage.
 In case of excessive water, divert the flow into special storage where it is held for treatment.
 Switch well production from a full tank to an empty and switch the oil from a full tank to the
pipe line system.

8. Pump Station Operation
Pumps move the oil into and through the pipeline at a pump station. Functionally, pump
stations are gathering stations, trunkline stations, or a combination of both. A gathering station
is located in or near an oilfield and receives oil through a pipeline gathering system from the
producers’ tanks. The gathering station may include one or more pumps and may move several
thousand barrels of oil daily from various producers’ tanks and gathering station tanks. Pumping
units usually consist of electric-drive reciprocating or centrifugal pumps.
From the gathering station, oil is relayed to a trunkline station. Having a much greater capacity,
the trunkline station relays the oil to refineries or shipping terminals. Since the pressure
gradually drops as the oil moves through the line, booster pump stations are spaced along the
trunkline as needed. Tank farms along the line serve as receiving and holding stations.
A special set of lines and valves called manifold regulates the oil that enters and leaves the tank
farms and the pump stations. A manifold is an accessory system of piping that divides the flow
into several parts, combines several flows into one, or reroutes the flow to any one of several
possible destinations.
Regulations
Pipeline companies must file monthly forms to show the quantity of oil taken from each lease.
The Syrian government imposes stringent controls on various aspects of the pipeline industry.
Oil pipelines are classified as common carriers and therefore operate under the Syrian Company
of Transportation (SCOT).