As with other solids-depositing issue, impediment can be more cost energetic than removal. One key to wax-deposition impediment is heat. Electric heaters can be employed to increase the crude oil temperature as it enters the wellbore. The limitations are the subsistence costs of the heating system and the opportunity of electrical power. As with hydrates, sustain a completely high production level may also keep the upper-wellbore temperature over the WAT. In extension, high flow amount tend to minimize wax adherence to metal exterior because of the shearing action of the flowing fluid. isolate pipelines are also an option to minimize, if not cancel, the problem, but the cost can be prohibitive for long pipelines.

Wax deposition can be  stopped , postponed, or decrease by the use of dispersants or crystal modifiers. As with asphaltenes, paraffin-wax aspects differ from well to well. Chemicals that are operative in one system are not consistently successful in others, even for wells within the same source. “For this reason it is of basic importance to install a good correlation between oil composition and paraffin inhibitors efficiency, leading to an adequate product selection for each special case, eluding extremely costly and inefficient ‘trial-and-error’ operations.”[1]

When molecular-weight hydrocarbons vaporize, the dissolved waxes begin to form insoluble crystals. The deposition process involves two obvious stages: nucleation and growth. Nucleation is the making of paraffin clusters of a critical size (“nuclei”) that are invariable in the hydrocarbon liquid. This indissoluble wax itself tends to disband in the crude.

http://petrowiki.org/index.php?title=Wax_problems_in_production & printable=yes can be lessened by making some device in the separator like sand removal ,sand detector….etc Sand control hints to managing/minimizing sand and fine production within petroleum production. Sand and fine produced with oil and gas can cause erosion and wear of production facilities/equipments, resulting in production downtime, expensive mends, and potentially loss of containment (serious safety risk).

Sand control methods may be sorted as mechanical and chemical. Mechanical methods of sand control enjoin to sand production by stopping the formation with liners, screens or gravel sieve. Larger formation sand grains are stopped, and they in revolve cease smaller formation sand grains. Chemical control methods involve in injecting consolidating materials as resins into the formation to cement the sand grains. Here we are discussing the most important control measures which are in practice.

Method for sand controlling are

Resin InjectionScreen with Gravel Pack

Slotted Liners or screen without Gravel Packhttp://www.jmcampbell.com/tip-of-the-month/2014/12/troubleshooting-gas-liquid-separators-removal-of-liquids-from-the-gas/

http://www.fabcoproducts.com/vane-mist-extractors.html

A separator operates over unceasing, comparatively a batch, process. This shows that the inlet stream continuously flows into the separator and that the gas and liquid must be evacuated at the similar rate.

Regarding liquids, this is concluded via a level controller and level valve. The common level controller consists of a float on a spring. As the liquid level in the separator increases, the float rises until it closes a switch, which then opens the level valve to let some liquid goes out. When the level falls back down to the normal operating level, the switch accessible again and makes the level valve locked. A two-phase separator employs a single liquid-level controller and level valve; a three-phase separator will have both an oil outlet with an oil-level controller and level valve and a water outlet with a water-level controller and level valve.

If the level valves control the liquid get out of the separator, how is the gas controlled? Because the liquid is incompressible and the liquid level in the separator stays quietly constant, the gas is contained in an approximately constant volume. As more gas goes into the separator, the pressure increases. A pressure controller is mounted on the separator-gas space or on the outlet-gas piping. The controller gives a signal to the pressure-control valve in the gas-outlet piping which tells it to open when the pressure is higher than the set point. Pressure-control valves are normally modulating, which shows that they gradually open wider as the pressure increases to a value higher than the set point and close as the pressure falls to a value lower than the set point.

In short, whatever amount of liquid comes into the separator, an equal amount must exit in to the level-control valve. The level controller senses whether the liquid level is high or low and sets the level valve appropriately. Whatever amount of gas that appear in the inlet of the separator, an equal amount of gas must exit through the pressure-control valve. The pressure controller senses pressure in the separator, opening the pressure-control valve if the pressure gets higher than the desired set point and closing

it if the pressure gets lower than desired. If the inlet stream shuts off, the outlet valves would all close, maintaining the pressure and level in the separator.

Detailed information on instrumentation and controls, including control-valve selection.

Design safety

If the process-control system operates correctly, operators use all manual valves correctly, and nothing breaks, there is no need for a safety system. However, controllers malfunction, valves leak, and operators make mistakes. The safety system is there to prevent:

• overpressure and possible rupture of equipment

• leaks

• pollution

• fire

• injury to personnel

• damage to equipment

RP 14C[1] provides a systematic way to ensure that all necessary safety equipment is in place. Two levels of protection normally exist in a safety system: primary and secondary.

Primary protection

The primary protection is usually a sensor or switch on the equipment that detects the undesirable event. For example, equipment may have a pressure, level, or temperature switch to detect values that are too high or too low, based on the normal operating ranges. Once the undesirable event is detected, a safety shutdown system is required to shut down flow into the affected equipment.

Secondary protection

In the event the primary protection fails to operate or operates too slowly to correct a problem, there is secondary protection consisting of a pressure safety valve (PSV) to prevent overpressure. A PSV is designed to open, relieving overpressure in a vessel or piping through “relief header” piping that directs the relieved fluids to a safe place for retrieval or disposal. Alternatively, secondary protection may consist of redundant sensors or switches, such as those used for primary protection, which may be located

on downstream equipment or on the equipment in question.

A separator with a given operating pressure will have a “design” pressure or “maximum allowable working pressure” (MAWP) sufficiently greater than the operating pressures to prevent small fluctuations in the process from causing overpressure of the pressure vessel. As an example, in the staged-separation process, the operating pressure of each downstream separator will be lower than that of the separator flowing into it. This allows the system-design pressure to be reduced as well. When a higher-design-pressure system flows into a lower-design-pressure system, there is potential for overpressuring the downstream, lower-pressure-rated system. With multistage separators, the different operating pressures often lead to a different design pressure for the HP, IP, and LP separators and their associated piping. This introduces a hazard commonly referred to as “gas blowby.” For example, if the liquid-level valve were to stick open, the liquid would flow out of the separator and the gas would “blow by” the liquid-control valve until the pressure equalized between the upstream and downstream separators. This equalized pressure could be higher than the design pressure of the downstream separator.

Safety systems must be designed to protect the lowest-pressure system in situations like the one outlined previously. Relief valves are normally provided on pressure vessels to protect against overpressure caused by “blocked discharge,” which occurs when all outlets to the vessel are closed because of blockage or system shutdown. Relief valves must also be adequately sized to protect against overpressure caused by blowby. The gas-blowby rate may exceed the HP-system inlet flow rate for a short time because the HP separator is being blown down, in an uncontrolled manner, to the lower-pressure system. The flow rate must be calculated based on the upstream pressure, the control valve capacity at full open, any other flow restriction in the piping, and the downstream-vessel relief-valve set pressure. The calculated flow can then be used to adequately size the relief valve.

In addition to primary and secondary protection for the process, an emergency support system is used to minimize the effects of escaped hydrocarbons. This system includes combustible gas detectors, fire detectors, smoke detectors, a containment system to collect leaking liquid hydrocarbons, and an emergency shutdown system to provide a method for the process-control system to initiate a platform shutdown. An in-depth discussion is presented in Safety systems.