Wellheads

The vapor pressure of a crude oil at the wellhead can reach 20 bar. If it were necessary to store and transport it under these conditions, heavy walled equipment would be required. For that, the pressure is reduced (< 1 bar) by separating the high vapor pressure components using a series of pressure reductions (from one to four flash stages) in equipment called separators , which are in fact simple vessels that allow the separation of the two liquid and vapor phases formed downstream of the pressure reduction point. The different components distribute themselves in the two phases in accordance with equilibrium relationships. 

The water content of crude oils at the wellhead is usually small as shown in Table 8.12 it generally increases during transport and storage and can attain 3%. 

During production sodium chloride can deposit in layers on tubing walls after partial vaporization of the water due to the pressure drop between bottomhole and wellhead when these deposits become important large enough, the diameter of the well tubing is reduced. 

The production phase commences with the first commercial quantities of hydrocarbons ( first oil ) flowing through the wellhead. This marks the turning point from a cash flow point of view, since from now on cash is generated and can be used to pay back the prior investments, or may be made available for new projects. Minimising the time between the start of an exploration campaign and first oil is one of the most important goals in any new venture. 

Routine production tests are performed, approximately once per month on each producing well, by diverting the production through the test separator on surface to measure the liquid flowrate, water cut, and gas production rate. The wellhead pressure (also called the flowing tubing head pressure, FTHP) is recorded at the time of the production test, and a plot of production rate against FTHP is made. The FTHP is also recorded continuously and used to estimate the well s production rate on a daily basis by reference to the FTHP vs production rate plot for the well. 

Having reached the wellbore, the fluid must now flow up the tubing to the wellhead, through the choke, flowline, separator facilities and then to the export or storage point each step involves overcoming some pressure drop. 

In gas field development, the recovery factor is largely determined by how low a reservoir pressure can be achieved before finally reaching the abandonment pressure. As the reservoir pressure declines, it is therefore common to install compression facilities at the surface to pump the gas from the wellhead through the surface facilities to the delivery point. This compression may be installed in stages through the field lifetime. 

Multiplex wellhead high-pressure control pump valve... 

Though the type of processing required is largely dependent upon fluid composition at the wellhead, the equipment employed is significantly influenced by location whether for example the facilities are based on land or offshore, in tropical or arctic environments. Sometimes conditions are such that a process which is difficult or expensive to perform offshore can be exported to the coast and handled much more easily on land. 

Section 10.1 will consider the physical processes which oil and gas (and unwanted fluids) from the wellhead must go through to reach product specifications. These processes will include gas-liquid separation, liquid-liquid separation, drying of gas. 

Before designing a process scheme it is necessary to know the specification of the raw material input (or feedstock) and the specification of the enc/procfucf desired. Designing a process to convert fluids produced at a wellhead into oil and gas products fit for evacuation and storage is no different. The characteristics of the well stream or streams must be known and specifications for the products agreed. 

The quality and quantity of fluids produced at the wellhead is determined by hydrocarbon composition, reservoir character and the field development scheme. Whilst the first two are dictated by nature the latter can be manipulated within technological and market constraints. 

In addition to fluid properties it is important to know how volumes and rates w change at the wellhead over the life of the well or field. Production profiles are required for oil, water and gas in order to size facilities, and estimates of wellhead temperatures and pressures (over time) are used to determine how the character of the production stream will change. If reservoir pressure support is planned, details of injected water or gas which may ultimately appear in the well stream are required. 

Multi-stage separation may also be constrained by low wellhead pressures. The separation process involves a pressure drop, therefore the lower the wellhead pressure the less scope there is for separation. 

If high wellhead pressures are available over long periods, cooling can be achieved by expanding gas through a valve, a process known as Joule Thomson (JT) throttling. The valve is normally used in combination with a liquid gas separator and a heat exchanger, and inhibition measures must be taken to avoid hydrate formation. The whole process is often termed low temperature separation (LTS). 

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. 

Providing the land surfaoe above a reservoir is relatively flat, it is generally cheaper to drill and maintain a vertical well than to access a reservoir from a location that requires a deviated borehole. In unpopulated areas such as desert or jungle looations It is common to find that the pattern of wellheads at surface closely reflects the pattern In which wells penetrate the reservoir. However, in many eases constraints will be planed on drill site availability as a result of housing, environmental concerns or topography. In such conditions wells may be drilled in clusters from one or a number of sites as elose as possible to the surface location of the reservoir. 

The first function of a wellsite is to accommodate drilling operations. However, a wellsite must be designed to allow access for future operations and maintenance activity, and in many cases provide containment in the event of accidental emission. Production from a single wellhead or wellhead cluster is routed by pipeline to a gathering station, often without any treatment. In such a case the pipeline effectively becomes an extension of the production tubing. If a well is producing naturally or with assistance from a down... 

Production Tubing Figure 10.25 Single wellhead arrangement... 

The most basic subsea satellite is a single Subsea Wellhead with Subsea Tree, connected to a production facility by a series of pipelines and umbilicals. A control module, usually situated on the subsea tree, allows the production platform to remotely operate the subsea facility (i.e. valves, chokes). 

Monitoring and control of the production process will be performed by a combination of instrumentation and control equipment plus manual involvement. The level of sophistication of the systems can vary considerably. For example, monitoring well performance can be done in a simple fashion by sending a man to write down and report the tubing head pressures of producing wells on a daily basis, or at the other extreme by using computer assisted operations (CAO) which uses a remote computer-based system to control production on a well by well basis with no physical presence at the wellhead. 

The purpose of the surface facilities is to deliver saleable hydrocarbons from the wellhead to the customer, on time, to specification, in a safe and environmentally acceptable manner. The main functions of the surface facilities are... 

Whether on land or offshore, the principle of satellite development is the same. A new field is accessed with wells, and an export link is installed to the existing (host) facility. Development is not always easier on land, as environmental restrictions mean that some onshore fields have to be developed using directional drilling techniques (originally associated with offshore developments). A vertical well can be drilled offshore away from the host facility, and the well completed using a subsea wellhead. 

The composition of natural gas at the wellhead depends on the characteristics of the reservoir and is highly variable with respect to both the constituents present and the concentrations of these constituents. Compositions of various natural gases are given in Table 4. 

Table 4. Wellhead Compositions of North American Natural Gases ...

Because of the wide variation in the composition of natural gas as it is recovered at the wellhead and because natural gas can be used over a wide range of hydrocarbon contents, any specification for natural gas is usually broadly defined. However, the natural gas obtained at the wellhead usually undergoes some type of treatment or processing prior to its use for safety, economic, or system and material compatibiUty reasons. 

Figure 2 shows the acquisition price for U.S. natural gas at the wellhead, together with the acquisition prices of cmde oil in both the international market and the U.S. domestic market (21). On a cost per unit energy basis, natural gas has been priced lower than cmde oil by factors ranging from 1.4 to 3.5 for the period shown. 

In 1988, the U.S. Department of Energy completed a study iadicatiag that more than 1.42 x 10 of gas was recoverable at a wellhead price... 

Sulfur Compounds. Various gas streams are treated by molecular sieves to remove sulfur contaminants. In the desulfurization of wellhead natural gas, the unit is designed to remove sulfur compounds selectively, but not carbon dioxide, which would occur in Hquid scmbbing processes. Molecular sieve treatment offers advantages over Hquid scmbbing processes in reduced equipment size because the acid gas load is smaller in production economics because there is no gas shrinkage (leaving CO2 in the residue gas) and in the fact that the gas is also fliUy dehydrated, alleviating the need for downstream dehydration. 

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