Wellhead fluids

T. J. Lechner-Fish and S. L. Ryder, Analysis of simulated petroleum wellhead fluids using multidimensional gas clir omatogr aphy , Am. Lab. 29 33X-33EE (1997). 

PRODUCED WELLHEAD FLUIDS are complex mixtures of hydrogen and carbon compounds with differing densities, vapor pressures and other characteristics. The wcllstrcam undergoes continuous pressure and temperature reduction as it leaves the reservoir. Gases evolve from liquids, water vapor condenses and part of the well stream changes from a liquid to bubbles, mist and free gas. Gas carries liquid bubbles and the liquid carries gas bubbles. Physical separation of these phases is one of the basic operations in production, processing and treatment of oil and gas. 

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. 

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. 

Special operating conditions such as start up of a shut-in well must be considered in sizing the heater. The temperature and pressure conditions found in a shut-in well may require additional heater capacity over the steady state requirements. It may be necessary to temporarily install a heater until the flowing wellhead temperature increases as the hot resei voir fluids heat up the tubing, casing, and surrounding material. 

The injection well was cased to a depth of about 1495 m (4900 ft) and extended into dolomite to a total depth of 1617 m (5300 ft). Injection began in the early 1960s and averaged around 340 L/min (90 gal/min). The natural fluid level was 60 m (200 ft) below the wellhead, and wastes were injected using gravity flow that is, the pressure head of the well when filled to the surface with fluid was sufficient to inject fluids without pumping under pressure.181... 

Hydraulic fracturing is a method of stimulating production of oil or gas from rock formations. A fluid is pumped under conditions of high pressure and high rate Into the formation to fracture it. The fluid also carries sand or a similar proppant material into the fractures. When the pumping is stopped and the hydraulic pressure is released at the wellhead, the fracture partially closes on the sand leaving a highly permeable channel for the oil or gas to flow back to the well. 

Blowout - A blowout is a high pressure release of hydrocarbons, which may or may not ignite, that occurs when a high pressure oil or gas accumulation is unexpectedly met while drilling and the mud column fails to contain the formation fluid that is expelled through the wellhead bore. 

Blowout - A uncontrolled flow of gas, oil or other well fluids from a wellbore at the wellhead or into the formation, caused by the formation pressure exceeding the drilling fluid pressure. It usually occurs during drilling on unknown reservoirs. 

Gos from the wellhead with its associated condensate is first cooled in the Production Cooler. This cooler is o shell ond tube heat exchanger with the process fluid on the tube side and cooling water on the shell side. 

A common example of flash vaporization is the separation of gas and liquid in surface equipment in an oil or gas field.1 The fluid from the wellhead is brought to equilibrium in a separator at separator temperature and pressure. This fluid is called separator feed. 

In addition to line burial and the addition of heat at the wellhead, insulation of exposed areas near the wellhead maintained higher pipeline temperatures, thereby reducing the amount of methanol needed for hydrate inhibition. Figure 8.6 displays the temperature increase in the buried and heated pipeline when exposed pipes were insulated. A combination of the methods causes the pipeline fluid to be outside the hydrate formation region (to the right of the curve marked 0 wt% MeOH), and methanol addition is no longer needed. 

Emulsions may be encountered throughout all stages of the process industries. For example, in the petroleum industry (see Chapter 11) both desirable and undesirable emulsions permeate the entire production cycle, including emulsion drilling fluid, injected or in situ emulsions used in enhanced oil-recovery processes, wellhead production emulsions, pipeline transportation emulsions, and refinery process emulsions [2], Such emulsions may contain not just oil and water, but also solid particles and even gas, as occur in the large Canadian oil sands mining and processing operations [2-4],... 

Whether corrosive constituents are removed at the oil or gas well or just before they enter cross country lines is a matter of economics (i.e., cost of the line, ease of replacement, etc). When dehydration or gas purification is not performed at the wellhead, severe corrosion may occur. Laboratory data on the corrosion rate vs partial pressure of carbon dioxide (Figure 4.5 in Chapter Four) often do not give a good estimate of the corrosiveness of the fluid because variables other than carbon dioxide partial pressure also affect metal loss. When the gas contains less than 15% oil (corrosion is low when there is more than 15% oil in the gas) and velocities are high, the chemical composition of the water, rather than the carbon dioxide partial pressure, appears to control the corrosion. The pH of the system calculated from the water composition has been used to determine whether or not a well is corrosive. To date, however, there is not a one-to-one correlation between the in situ pH and corrosiveness. 

An injection test is run using water as a test fluid. At a wellhead pressure of 700 kPa (100 psia), a water injection rate of 16 m3/day... 

At the wellhead there is a choke valve, and the fluid pressure drops to the actual injection pressure. There is a Joule-Thomson temperature drop associated with this pressure drop, but because the acid gas is in the liquid phase, the temperature drop is quite small. 

Most sampling takes place at the wellhead rather than down-hole. The fluids are therefore subjected to major reductions in temperature and pressure, to gas loss and to exposure to oxidizing conditions during sampling. The special methods that must be used in sample collection, preservation, and field and laboratory determinations of chemical components and isotopes in formation waters are detailed in Lico et al. (1982) and Kharaka et al. (1985). 

This chapter will briefly review the nature and the consequential sources of oil-field emulsions encountered in the handling of produced fluids recovered at a wellhead and subsequently processed (Le., ""broken ) at central treatment facilities. The principal factors and agents commonly employed in the separation of both the oil and the water phases found in these produced-fluid streams will be discussed. Subsequently, this chapter will describe sampling and testing techniques that assist in characterizing a process stream s composition and thus in evaluating the effectiveness of a particular separation process. Finally, the major components of a typical oil-field emulsion-treatment facility will be described. Selection and design criteria of appropriate separation equipment will also be presented. 

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