Lifting

For any given type of heat pump, a higher COPhp leads to better economics. Having a better COPhp and hence better economics means working across a small temperature lift with the heat pump. The... 

This problem is solved in the reactor shown in Fig. 10.6. Ethylene and chlorine are introduced into circulating liquid dichloroethane. They dissolve and react to form more dichloroethane. No boiling takes place in the zone where the reactants are introduced or in the zone of reaction. As shown in Fig. 10.6, the reactor has a U-leg in which dichloroethane circulates as a result of gas lift and thermosyphon effects. Ethylene and chlorine are introduced at the bottom of the up-leg, which is under sufficient hydrostatic head to prevent boiling. 

The level of injector fouling is most often illustrated in terms of residual flow (RF) expressed as a percentage of the flow under new conditions for a given needle lift. An RF on the order of 20% for a lift of 0.1 mm is a good compromise. This level may not be achieved with certain aromatic or naphthenic diesel fuels. The best recourse is then detergent additive addition. 

In order to effectively lift the cuttings out of the hole a certain viscosity needs to be achieved, yet the fluid must remain pumpable. If the mud circulation stops, for instance... 

There will be some uncertainty as to the well initials, since the exploration and appraisal wells may not have been completed optimally, and their locations may not be representative of the whole of the field. A range of well initials should therefore be used to generate a range of number of wells required. The individual well performance will depend upon the fluid flow near the wellbore, the type of well (vertical, deviated or horizontal), the completion type and any artificial lift techniques used. These factors will be considered in this section. 

The end of field life is often determined by the lowest reservoir pressure which can still overcome all the pressure drops described and provide production to the stock tank. As the reservoir pressure approaches this level, the abandonment conditions may be postponed by reducing some of the pressure drops, either by changing the choke and separator pressure drops as mentioned, or by introducing some form of artificial lift mechanism, as discussed in Section 9.7. 

The objective of any artificial lift system is to add energy to the produced fluids, either to accelerate or to enable production. 

Artificial lift systems are mostly required later in a field s life, when reservoir pressures decline and therefore well productivities drop. If a situation is anticipated where artificial lift will be required or will be cost effective later in a field s life, it may be advantageous to install the artificial lift equipment up front and use it to accelerate production throughout the field s life, provided the increased revenues from the accelerated production offset... 

The following types of artificial lift are commonly available today ... 

Gas lift systems aim at lightening the liquid column by injecting gas into it, essentially stimulating natural flow. A gas lift string contains a number of valves located along the string. These valves are only required to kick-off the lifting process under normal... 

Operating conditions all gas lift valves apart from the bottom orifice valve are closed. The energy to the system is delivered by a compressor. The performance of the system is monitored by observing flowrates and the casing and tubing pressures. 

Figure 9.18 provides an overview of the application envelope and the respective advantages and disadvantages of the various artificial lift techniques. As can be seen, only a few methods are suited for high rate environments gas lift, ESP s, and hydraulic systems. Beam pumps are generally unsuited to offshore applications because of the bulk of the required surface equipment. Whereas the vast majority of the world s artificially lifted strings are beam pumped, the majority of these are stripper wells producing less than 10 bpd. 

To prepare gas for evacuation it is necessary to separate the gas and liquid phases and extract or inhibit any components in the gas which are likely to cause pipeline corrosion or blockage. Components which can cause difficulties are water vapour (corrosion, hydrates), heavy hydrocarbons (2-phase flow or wax deposition in pipelines), and contaminants such as carbon dioxide (corrosion) and hydrogen sulphide (corrosion, toxicity). In the case of associated gas, if there is no gas market, gas may have to be flared or re-injected. If significant volumes of associated gas are available it may be worthwhile to extract natural gas liquids (NGLs) before flaring or reinjection. Gas may also have to be treated for gas lifting or for use as a fuel. 

After passing through several stages of processing, gas pressure may need to be increased before it can be evacuated, used for gas lift or re-injected. Inter-stage pressure increases may also be required for further processing, particularly where wellhead pressure is low. Gas is compressed to increase its pressure. 

The hardware items with which the processes described in Section 10.1 are achieved are called facilities, and are designed by the facilities engineer. The previous section described the equipment items used for the main processes such as separation, drying, fractionation, compression. This section will describe some of the facilities required for the systems which support production from the reservoir, such as gas injection, gas lift, and water injection, and also the transportation facilities used for both offshore and land operations. 

Injection gas pressures are usually much higher than lift-gas or gas pipeline pressures and special care has to be taken to select compressor lubricants that will not dissolve in high pressure gas. Such a situation could lead to inadequate lubrication and may impair well injectivity. 

The legs of the platform can be used as settling tanks or temporary storage facilities for crude oil where oil is exported via tankers, or to allow production to continue in the event of a pipeline shut down. The Brent D platform in the North Sea weighs more than 200,000 tonnes and can store over a million barrels of oil. Topside modules are either installed offshore by lift barges, or can be positioned before the platform is floated out. 

Typically, a Subsea Field Development or Subsea Satellite Development would consist of a cluster of special subsea trees positioned on the seabed with produced fluids piped to the host facility. Water injection, as well as lift gas, can be provided from the host facility. Control of subsea facilities is maintained from the host facility via control umbilicals and subsea control modules. 

An example of an application of CAO is its use in optimising the distribution of gas in a gas lift system (Fig. 11.3). Each well will have a particular optimum gas-liquid ratio (GLR), which would maximise the oil production from that well. A CAO system may be used to determine the optimum distribution of a fixed amount of compressed gas between the gas lifted wells, with the objective of maximising the overall oil production from the field. Measurement of the production rate of each well and its producing GOR (using the test separator) provides a CAO system with the information to calculate the optimum gas lift gas required by each well, and then distributes the available gas lift gas (a limited resource) between the producing wells. 

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