The final stage before the oil and gas leaves the platform consists of storage, pumps and pipeline terminal equipment.

Fiscal metering

Partners, authorities and customers all calculate invoices, taxes and payments based on the actual product shipped out. Often, custody transfer also takes place at this point, which means transfer of responsibility or title from the producer to a customer, shuttle tanker operator or pipeline operator. Although some small installations are still operated with a dipstick and manual records, larger installations have analysis and metering equipment.

To make sure readings are accurate, a fixed or movable prover loop for calibration is also installed. The illustration shows a full liquid hydrocarbon (oil and condensate) metering system. The analyzer instruments on the left provide product data such as density, viscosity and water content. Pressure and temperature compensation is also included.

For liquids, turbine meters with dual pulse outputs are most common. Alternatives are positive displacement meters (pass a fixed volume per rotation or stroke) and coriolis mass flow meters. These instruments cannot cover the full range with sufficient accuracy. Therefore, the metering is split into several runs, and the number of runs depends on the flow. Each run employs one meter and several instruments to provide temperature and pressure correction. Open/close valves allow runs to be selected and control valves can balance the flow between runs. The instruments and actuators are monitored and controlled by a flow computer. If the interface is not digital, dual pulse trains are used to allow direction sensing and fault finding.

To obtain the required accuracy, the meters are calibrated. The most common method is a prover loop. A prover ball moves though the loop, and a calibrated volume is provided between the two detectors (Z). When a meter is to be calibrated, the four-way valve opens to allow oil to flow behind the ball. The number of pulses from it passes one detector Z to the other and is counted. After one loop, the four-way valve turns to reverse flow direction and the ball moves back, providing the same volume in reverse, again counting the pulses. From the known reference volume, number of pulses, pressure and temperature the flow computer can calculate the meter factor and provide accurate flow measurements using formulas from industry standard organizations such as API MPMS and ISO 5024. The accuracy is typically ± 0.3% of standard volume.

Gas metering is similar, but instead, analyzers will measure hydrocarbon content and energy value (MJ/scm or BTU, Kcal/scf) as well as pressure and temperature. The meters are normally orifice meters or ultrasonic meters. Orifice plates with a diameter less than the pipe are mounted in cassettes. The pressure differential over the orifice plate as well as pressure and temperature, is used in standard formulas (such as AGA 3 and ISO 5024/5167) to calculate normalized flow. Different ranges are accommodated with different size restrictions.

Orifice plates are sensitive to a buildup of residue and affect the edges of the hole. Larger new installations therefore prefer ultrasonic gas meters that work by sending multiple ultrasonic beams across the path and measure the Doppler effect.

Gas metering is less accurate than liquid, typically ±1.0% of mass. There is usually no prover loop, the instruments and orifice plates are calibrated in separate equipment instead.

LNG is often metered with mass flow meters that can operate at the required low temperature. At various points in the movement of oil and gas, similar measurements are taken, usually in a more simplified way. Examples of different gas types are flare gas, fuel gas and injected gas, where required accuracy is 2-5% percent.

Storage

On most production sites, oil and gas are piped directly to a refinery or tanker terminal. Gas is difficult to store locally, but occasionally underground mines, caverns or salt deposits can be used to store gas.

On platforms without a pipeline, oil is stored in onboard storage tanks to be transported by shuttle tanker. The oil is stored in storage cells around the shafts on concrete platforms, and in tanks on floating units. On some floaters, a separate storage tanker is used. Ballast handling is very important in both cases to balance the buoyancy when oil volume varies. For onshore, fixed roof tanks are used for crude, floating roof for condensate. Rock caves are also used for storage.

Special tank gauging systems such as level radars, pressure or float are used to measure the level in storage tanks, cells and caves. The level measurement is converted to volume via tank strapping tables (depending on tank geometry) and compensated for temperature to provide standard volume. Float gauges can also calculate density, and so mass can be established.

A tank farm consists of 10-100 tanks of varying volume for a typical total capacity in the area of 1-50 million barrels. Storage or shuttle tankers normally store up to two weeks of production, one week for normal cycle and one extra week for delays, e.g., bad weather. This can amount to several million barrels.

Accurate records of volumes and history are kept to document what is received and dispatched. For installations that serve multiple production sites, different qualities and product blending must also be handled. Another planning task is forecasting for future received and delivered products. This is for stock control and warehousing requirements. A tank farm management system keeps track of all stock movements and logs all transport operations that take place.

Marine loading

Loading systems consist of one or more loading arms/jetties, pumps, valves and a metering system. Tanker loading systems are complex, both because of the volume involved, and because several loading arms will normally interact with the tanker’s ballast system to control the loading operation. The tanks must be filled in a certain sequence; otherwise the tanker’s structure might be damaged due to uneven stresses. It is the responsibility of the tanker’s ballast system to signal data to the loading system and to operate the different valves and monitor the tanks on board the ship.

Midstream facilities

Raw natural gas from the well consists of methane as well as many other smaller fractions of heavier hydrocarbons, and various other components. The gas has to be separated into marketable fractions and treated to trade specifications and to protect equipment from contaminants.

Gathering

Many upstream facilities include the gathering system in the processing plant. However, for distributed gas production systems with many (often small) producers, there is little processing at each location and gas production from thousands of wells over an area instead feed into a distributed gathering system. This system in general is composed of:

•         Flowlines: A line connecting the wellpad with a field gathering station (FGS), in general equipped with a fixed or mobile type pig launcher.

•         FGS is a system allowing gathering of several flowlines and permits transmission of the combined stream to the central processing facility (CPF) and measures the oil/water/gas ratio. Each FGS is composed of:

ü  Pig receiver (fixed/mobile)

ü  Production header where all flowlines are connected

ü  Test header where a single flow line is routed for analysis purposes (GOR Gas to oil ratio, water cut)

ü  Test system (mainly test separator or multiphase flow meter)

ü  Pig trap launcher

•         Trunk line – pipeline connecting the FGS with the CPF. Equipped with a pig receiver at the end.