The typical process flow diagram (PFD) of oil and gas processing for
most of fixed or floating offshore production. Two sections consists
crude oil stabilisation and associated gas compression.
This section is continue to discuss the gas processing part in offshore
production platform. The HP-MP-LP Separators separate gas from oil. The
gas from LP and MP Separators will be recompressed by small compressor
driven by electric motor. The re-compressed gas co-mingle with the gas
from HP Separator. The gas send to HP Compression train for sale gas,
gas lift or gas injection.
The HP Compression train included gas scrubber, gas cooler, anti-surge
recycle and driver (gas turbine, steam turbine or electric motor). The
gas compressed to higher pressure via several stages of compressors.
Each compressor is driven by same shaft. Number of stage compressor is
depended on final discharge pressure and compression ratio of
compressor. The common compression ratio is maximum 4.
The imperial practice is equal compression ratio of each stage HP Compressor due to high efficiency and cost effective.
The gas treatment system allocate at interstage HP compression train.
They are Gas Dehydration, Mercury Removal, Gas Sweetening, Hydrocarbon
Dew-point Control Unit, or Natural Gas Liquid Recovery Unit. The gas
treatment system depend on gas export requirements.
The treated gas is exported via gas flowline or LNG/CNG tanker to onshore processing plant.
Oil Rig / Offshore Structure
Type of design offshore platform subjects to water depth, geology
condition and cost effective solution. The various types of offshore
platform shown as below:
- Fixed Steel Structure
- Compliant Tower
- Jack-up Platform
- Concrete Gravity Base Structure
- Tension Leg Platform (TLP)
- Semi-submersible Vessel
- Floating Production System
- Spar Platform
1. FIXED STEEL STRUCTURE
The
traditional offshore structure consists of weld steel, tubular
framework or jacket to support the topside facilities. Piles driven into
the seafloor secure the jacket.
Modern design with bridge linked jackets tending to favour a separate
well head platform, processing platform and accommodation platform due
to safety concern.
The Fixed Steel Structures are restricted to shallow water developments with water deep about 1500 ft.
2. COMPLIANT TOWER
Compliant towers are similar to fixed platforms in that they have a
steel tubular jacket that is used to support the topside facilities.
Unlike fixed platforms, compliant towers yield to the water and wind
movements in a manner similar to floating structures. Like fixed
platforms, they are secured to the seafloor with piles. The jacket of a
compliant tower has smaller dimensions than those of a fixed platform.
Compliant towers are designed to sustain significant lateral deflections
and forces, and are typically used in water depths ranging from 1,500
to 3,000 ft.
3. JACK-UP PLATFORM
The Jack-up Platform consists of a triangular shaped (sometimes
rectangular), box section barge fitted with three (sometimes four)
moveable legs which enable the vessel to stand to the seabed in water
depths of up to approximately 120 m (400 ft).
4. CONCRETE GRAVITY BASE STRUCTURE
The Concrete Gravity Base Structure have been constructed using a base
manufactured from reinforced concrete. The design of base includes void
spaces or caissons to provided the structure with a natural buoyancy
which will enable it to be floated to field development location. Once
on location the void spaces are flooded on the seabed whilst the topside
modules are lifted into place. The void spaces then used as storage
compartments for crude oil, or filled with permanent iron ore ballast.
The colossal weight of concrete structures obviates the need to install
foundation piles, hence the name gravity base structure.
5. TENSION LEG PLATFORM (TLP)
A Tension Leg Platform (TLP) is a buoyant platform held in place by a
mooring system. The TLP’s are similar to conventional fixed platforms
except that the platform is maintained on location through the use of
moorings held in tension by the buoyancy of the hull. The mooring system
is a set of tension legs or tendons attached to the platform and
connected to a template or foundation on the seafloor. The template is
held in place by piles driven into the seafloor. This method dampens the
vertical motions of the platform, but allows for horizontal movements.
TLPs are used in water depths from 1500 ft to 7000 ft.
The "conventional" TLP is a 4-column design which looks similar to a
semisubmersible. Proprietary versions include the Seastar and MOSES mini
TLPs; they are relatively low cost, used in water depths between 600
and 4,300 feet (200 and 1,300 m). Mini TLPs can also be used as utility,
satellite or early production platforms for larger deepwater
discoveries.
6. SEMI-SUBMERSIBLE VESSEL
These platforms have twin hulls (columns and pontoons) of sufficient
buoyancy to cause the structure to float, but of weight sufficient to
keep the structure upright. Semi-submersible platforms can be moved from
place to place; can be ballasted up or down by altering the amount of
flooding in buoyancy tanks; they are generally anchored by combinations
of chain, wire rope and/or polyester rope during drilling and/or
production operations, though they can also be kept in place by the use
of dynamic positioning. Semi-submersibles can be used in water depths
from 200 to 10,000 feet.
7. FLOATING PRODUCTION SYSTEM
FPSO (floating production, storage, and off-loading) vessel is converted
from liquid cargo vessel or new built. FPSO equipped with processing
facilities and moored to a location.
Basically, Floating Production Systems are ideal solution for
- The field is small and marginal
- The field is isolated and an established pipeline infrastructure does not exist
- The field is located in very deep water where it would not be possible to install a conventional fixed platform
A major advantage of FPSO lies in the fact that they can simply lift
anchors and depart to pastures new when oil production reaches a
commercially unprofitable level.
You may interest:
FPSO - Armada Perkasa (youtube)
The Making of FPSO TGT1 (youtube)
The Making of Armada Sterling FPSO (youtube)
New Round FPSO
FPSO Contractor Fleet Size
BP Scheihallion FPSO Offstation (youtube)
8. SPAR PLATFORM
SPAR is a deep-draft floating caisson, which is a hollow cylindrical
structure similar to a very large buoy. Its four major systems are hull,
moorings, topsides, and risers. The spar relies on a traditional
mooring system (that is, anchor-spread mooring) to maintain its
position. About 90 percent of the structure is underwater. Historically,
spars were used as marker buoys, for gathering oceanographic data, and
for oil storage. The spar design is now being used for drilling,
production, or both. The distinguishing feature of a spar is its
deep-draft hull, which produces very favorable motion characteristics
compared to other floating concepts. Low motions and a protected
centerwell also provide an excellent configuration for deepwater
operations. Water depth capability has been stated by industry as
ranging up to 10,000 ft.
The upper section is compartmentalized around a flooded centerwell
containing the different type of risers. This section provides the
buoyancy for the spar. The middle section is also flooded but can be
economically configured for oil storage. The bottom section (keel) is
compartmentalized to provide buoyancy during transport and to contain
any field-installed, fixed ballast. Approximate hull diameter for a
typical GOM spar is 130 feet, with an overall height, once deployed, of
approximately 700 feet (with 90% of the hull in the water column).
The first Spars were based on the Classic design. This evolved into the
Truss Spar by replacing the lower section of the caisson hull with a
truss. The Truss Spar is divided into three distinct sections. The
cylindrical upper section, called the “hard tank,” provides most of the
in-place buoyancy for the Spar. The middle truss section supports the
heave plates and provides separation between the keel tank and hard
tank. The keel tank, also known as the “soft tank,” contains the fixed
ballast and acts as a natural hang-off location for export pipelines and
flowlines since the environmental influences from waves and currents
and associated responses are less pronounced there than nearer the water
line.
Artificial Lift
Production wells are free flowing. When a well pressure has declined to
the point at which the well no longer produces by its natural pressure.
Some artificial methods are: (Beam pump, Electrical Submerged pump and
Gas lift)
Beam PumpsAlso
called as Donkey Pumps ,are most common artificial lift system used in
land based. A motor drives a reciprocating beam, connected to a polished
rod passing into the tubing via a stuffing box. The sucker rod
continues down to the oil level and is connected to a plunger with a
valve.
On each upward stroke, the plunger lifts a volume of oil
up and through the wellhead discharge. On the downward stroke it sinks
(it should sink, not be pushed) with oil flowing though the valve.
Advantages:
- Can be used for wide range production capabilities
- Can produce most wells to depletion at limited rates and depths
- Highly reliable and relatively easy to analyse by using several different means
- Corrosion and scale problems easily treated
- Can produce high temperature or viscous oil
- Low cost production operation
Disadvantages:
- Installation not suitable for crooked hole work
- Depth and volume limited by rod weight and strength
- High gas-oil ratio wells as well as sand and paraffin content in production fluids
- Weight and size can prohibit use in offshore installations
Electrical Submerged Pumps (ESPs)
A motor driven centrifugal pump with rotating blades on a shaft on the bottom of tubing.
Advantages:
- Can
be operated in deviated or directionally drilled wells although
recommended operating position is in straight section of well
- Can be operated in deep wells with small casings
- Very efficient and economical
Disadvantages:
- Narrow producing range
- Large volumes of gas can be destructive to the pump
- Run life adversely impacted by poor quality electric power supply
Gas Lift
High pressure gas is
injected into
the production fluids within the tubing string. Leads to decrease in
the weight of the fluid column and permits the well to flow.
When
the gas lift is started up, several gas lift valves must operate in
sequence. During the unloading process, the fluid in the annulus between
the tubing and the casing is displaced, along with the high pressure
injection gas,
through the top gas lift valve into the tubing bore.
Advantages:
- Simple to operate
- Equipment used is relatively inexpensive
- Flexible
- Both high volumes and low volumes can be produced
- Effective handling of corrosion and high gas-oil ratio production
- Low operating costs
- Lower failure rate
Disadvantages:
- Source of high pressure gas must be available
- Not cost effective when used for one-well lease or small fields
- Not very effective for producing deep wells where there is high drawdowns or low bottomhole pressures
- Accurate gas measurements are not easily obtained
- Surging flow can be a source of operating problems with surface equipment
Gas Compression at Offshore (Part 1)
The main purpose of gas compression at offshore are below:
- Gas Export
- Gas Injection to well
- Gas lift
- Fuel gas
Compressors are generally classified as reciprocating or centrifugal
machines. Reciprocating compressors are generally very robust design.
However centrifugal compressors have fewer moving parts and reliable.
Reciprocating Compressor
Reciprocating
compressor use positive displacement principle. Generally,
reciprocating compressor has low speed compared with a centrifugal
compressor
Single acting compressor
Double acting compressor
Double acting compressor has suction and discharge stoke at same time.
For every cylinder stoke, one side of compressor discharges compressed
gas while the other opposite side is on the suction stoke and vice
versa.
Oil
has been used for lighting purposes for many thousands of years. In
areas where oil is found in shallow reservoirs, seeps of crude oil or
gas may naturally develop, and some oil could simply be collected from
seepage or tar ponds.
Historically, we know the tales of
eternal fires where oil and gas seeps ignited and burned. One example is
the site where the famous oracle of Delphi was built around 1,000 B.C.
Written sources from 500 B.C. describe how the Chinese used natural gas
to boil water. The oil was produced from bamboo-drilled wells in China.
The well reach 1000 meters deep.
In western history, it was not until
1859 that "Colonel" Edwin Drake drilled the first successful oil well,
with the sole purpose of finding oil. The Drake Well was located in the
middle of quiet farm country in northwestern Pennsylvania, and sparked
the international search for an industrial use for petroleum.
Photo: Drake Well Museum Collection, Titusville, PA
These wells were shallow by modern
standards, often less than 50 meters deep, but they produced large
quantities of oil. In this picture of the Tarr Farm, Oil Creek Valley,
the Phillips well on the right initially produced 4,000 barrels per day
in October, 1861, and the Woodford well on the left came in
at 1,500 barrels per day in July, 1862.
The oil was collected in the wooden
tank pictured in the foreground. As you will no doubt notice, there are
many different-sized barrels in the background. At this time, barrel
size had not been standardized, which made statements like "oil is
selling at $5 per barrel" very confusing (today a barrel is 159 liters).
But even in those days, overproduction was something to be avoided.
When the "Empire well" was completed in September 1861, it produced
3,000 barrels per day, flooding the market, and the price of oil
plummeted to 10 cents a barrel. In some ways, we see the same effect
today. When new shale gas fields in the US are constrained by the
capacity of the existing oil and gas pipeline network, it results in
bottlenecks and low prices at the production site.
Soon, oil had replaced most other fuels for motorized transport. The
automobile industry developed at the end of the 19th century, and
quickly adopted oil as fuel. Gasoline engines were essential for
designing successful aircraft. Ships driven by oil could move up to
twice as fast as their coal-powered counterparts, a vital military
advantage. Gas was burned off or left in the ground.
Despite attempts at gas transportation as far back as 1821, it was not
until after World War II that welding techniques, pipe rolling, and
metallurgical advances allowed for the construction of reliable long
distance pipelines, creating a natural gas industry boom. At the same
time, the petrochemical industry with its new plastic materials quickly
increased production. Even now, gas production is gaining market share
as liquefied natural gas (LNG) provides an economical way of
transporting gas from even the remotest sites.
With the appearance of automobiles and more advanced consumers, it was
necessary to improve and standardize the marketable products. Refining
was necessary to divide the crude in fractions that could be blended to
precise specifications. As value shifted from refining to upstream
production, it became even more essential for refineries to increase
high-value fuel yield from a variety of crudes. From 10-40% gasoline for
crude a century ago, a modern refinery can get up to 70% gasoline from
the same quality crude through a variety of advanced reforming and
cracking processes.
1 barrel (42 gallons) crude oil breakdown to various products in gallon
Chemicals derived from petroleum or natural gas – petrochemicals – are
an essential part of the chemical industry today. Petrochemistry is a
fairly young industry; it only started to grow in the 1940s, more than
80 years after the drilling of the first commercial oil well.
During World War II, the demand for synthetic materials to replace
costly and sometimes less efficient products caused the petrochemical
industry to develop into a major player in modern economy and society.
Products Flow Chart of Petroleum Based Feedstocks
Before then, it was a tentative, experimental sector, starting with basic materials:
- Synthetic rubbers in the 1900s
- Bakelite, the first petrochemical-derived plastic, in 1907
- First petrochemical solvents in the 1920s
- Polystyrene in the 1930s
And it then moved to an incredible variety of areas:
- Household goods (kitchen appliances, textiles, furniture)
- Medicine (heart pacemakers, transfusion bags)
- Leisure (running shoes, computers...)
- Highly specialized fields like archaeology and crime detection
With oil prices of $100 a barrel or more, even more difficult-to-access
sources have become economically viable. Such sources include tar sands
in Venezuela and Canada, shale oil and gas in the US (and developing
elsewhere), coal bed methane and synthetic diesel (syndiesel) from
natural gas, and biodiesel and bioethanol from biological sources have
seen a dramatic increase over the last ten years. These sources may
eventually
more than triple the potential reserves of hydrocarbon fuels. Beyond
that, there are even more exotic sources, such as methane hydrates, that
some experts claim can double available resources once more.
With increasing consumption and ever-increasing conventional and
unconventional resources, the challenge becomes not one of availability,
but of sustainable use of fossil fuels in the face of rising
environmental impacts, that range from local pollution to global climate
effects.
Reference sources:
Oil and gas production handbook:
An introduction to oil and gas production,
transport, refining and petrochemical
industry
-
When I was young process engineer, I learnt sizing of pressure relief valve, include inlet line sizing rule:
API RP 520 Part II (Ed 2003), section 4.2 recommends that
the
total non-recoverable pressure loss between the protected equipment and
the pressure relief valve should not exceed 3 percent.
WHY?
In API RP 520, section 4.2 "PRESSURE-DROP LIMITATIONS AND PIPING CONFIGURATIONS"
"Excessive pressure loss at the inlet of a pressure-relief
valve can cause rapid opening and closing of the valve, or
chattering. Chattering will result in lowered capacity and
damage to the seating surfaces."
"When a pressure-relief valve is installed on a line directly
connected to a vessel, the total non-recoverable pressure loss
between the protected equipment and the pressure-relief
valve should not exceed 3 percent of the set pressure of the
valve except as permitted in 4.2.3 for pilot-operated pressure relief
valves."
"Keeping the pressure loss below 3 percent becomes progressively
more difficult at low pressures as the orifice size of a
pressure-relief valve increases. An engineering analysis of the
valve performance at higher inlet losses may permit increasing
the allowable pressure loss above 3 percent."
Clearly, the API guideline is to avoid the PSV chatter.
In 2007, API is responded that the 3% rule is under investigation:[1]
In March 2010 Ballot outlines: [2]
- Typical blowdown set by the manufacturer for PRVs is 7 to 12% of the set pressure
- Original basis of 3% inlet pressure loss was related to blowdown settings in the range of 4 - 5 %
- A suitable margin relative to the blowdown shall be specified by the user
- When exceeding 3% inlet loss, an engineering analysis shall include but is not limited to the following:
a. Verification from the manufacturer the
minimum blowdown value for the PRV model based on the manufacturer’s
standard setting.
b. Prior to any increase in blowdown to
allow for higher inlet pressure drop, the manufacturer shall be
consulted to make sure that an increase in blowdown is possible.
c. Re-evaluation of the flow capacity of
the valve taking into consideration the reduction in pressure at the
inlet to the valve.
d. The user shall conduct a thorough review
of the valve’s inspection/maintenance records and obtain experience
from Operations, to identify any indications of chatter
History of Inlet Pressure Drop
- API RP 520 introduced maximum PRV inlet pressure drop in 1963
- API sponsored 1940’s work at University of Michigan by Sylvander and
Katz “The Design and Construction of Pressure Relieving Systems”
- University of Michigan Press (1948) pages 72-73 excerpts:
- “Pressure drop through inlet piping has a two-fold importance in
relief system design. First, flow capacity varies with the pressure drop
available. Second, the operating characteristics of many relief devices
indicate that improper pressure drop on the inlet side may cause
intermittent operation.“
- “For a relief valve having approximately 4 per cent blow-down (that
is, the valve will snap shut when the pressure has decreased to 4 per
cent below the opening or set pressure), these recommendations are made:
- Combined pressure loss of 3% maximum related to PRVs with 4% blowdown (margin of 1%)
In Spring 2011Metting [3]
In November 2011, Hydrocarbon Processing featured a Special Report [5]
Title : "Relief Device Inlet Piping: Beyond the 3 Percent Rule"
Current status, (3/7/2013), API RP520 Part 2, 6th Ed Committee Draft [4]
PSV Inlet Pressure Loss Criteria:
The total non-recoverable
pressure loss between the protected equipment and the pressure-relief valve should not exceed 3 percent of
the pressure relief valve set pressure except as noted below:
- Thermal relief valves
- Remotely sensed pilot operated relief valves
- keeping the pressure loss below 3 percent becomes progressively more difficult at low pressures as the orifice size of a pressure relief valve increases
- An engineering analysis is performed for the specific installation
Reference link
1.
API replied
2.
Spring 2010 API CRE Meeting
3.
Spring 2011 API Meeting Minutes
4.
API RP520 Part 2, 6 Ed, Committee Draft
5.
Relief Device Inlet Piping: Beyond the 3 Percent Rule, Hydrocarbon Processing, Novmber 2011 issue
Gas Density Calculation (Estimation)
Quick estimation of gas density
Density = P/(RT) (kg/m3)
P= Pressure (Pa)
R= Individual gas constant (J/kg.K) = Ru/MW
T= absolute temperature (K)
Ru= Universal gas constant (8314.472 J/kmol.K)
MW= Gas Molecular weight
Example:
Air molecular weight = 29 kg/kmol
Pressure = 1 bara = 100,000 Pa
