Page 122 - Compression Machinery for Oil and Gas

Centrifugal Compressors Chapter 3 109

Most oil wells produce oil, gas, and water. This mixture is separated at the
surface. Initially, the oil well may produce mostly oil with a small amount of
water. Overtime, the percentage of water increases. This produced water varies
in quality from very briny to relatively fresh. Where this water cannot be used
for other purposes, it may be reinjected into the reservoir—either as part of a
waterflooding project or for disposal (returning it to the subsurface).
Gas or condensate reservoirs produce lighter hydrocarbons than oil wells. In
all cases, the hydrocarbons produced are hydrocarbon mixtures, with a high pro-
portion of methane. Often other gases, like nitrogen or CO 2 are present, and the
gas is frequently saturated with water.
These natural gas wells do not produce oil but usually some amount of
heavier, liquid hydrocarbons, which are called condensate. In addition to con-
densate, natural gas liquids (ethane, propane, and butane) are removed at a gas
processing plant, along with other impurities, such as hydrogen sulfide and car-
bon dioxide as well. Natural gas liquids often have significant value as petro-
chemical feedstock. Natural gas wells also often produce water, but the volumes
are much lower than is typical for oil wells. Gas from gas wells is compressed
and either fed to a gas plant or a pipeline. Usually, more than one well in a geo-
graphic area are piped via “flow lines” to a booster compressor or even multiple
booster compressors in an inlet compression station. The compressor station is
usually close to the well head, and upstream of the gas plant. The gas usually
comes from a number of wells, which often produce at different pressure levels.
The applications usually have low suction pressures (0.3–2MPa), and the gas is
compressed to about 7–10MPa. Therefore, compression is accomplished in
stages, with cooling of the gas between stages. A typical scenario involves small
compressors close to the wellhead feeding to centrally located larger compres-
sor stations. The inlet pressures vary with the dynamics of the reservoirs. A gas
gathering system usually starts off with a relatively low ratio (1.25–1.5 range)
and high flows. The reservoirs usually decline in ability to produce and require
lower pressures to maintain volume flow rates. Eventually, the losses of the
gathering system well tubing and flow line piping dominate and no amount
of compression will maintain the flow rate. Many reservoirs under compression
will draw down to near vacuum at the wellhead prior to abandonment. This
leads to booster compression requirements of high rotation and low flow, usu-
ally utilizing all the possible horsepower installed in the initial operating case.
Ideally, this is following a constant horsepower, rising pressure ratio and falling
volume scenario.
The usual strategy for designing booster compression facilities is to consider
the reservoir pressure versus flow decline curve and to plan an economically
optimized life of field compression scheme. This may involve justifying to
invest in compressor configurations that allow higher pressure ratio (thus usu-
ally a larger number of impellers), and lower flow future aerodynamic
components.