To study continuous- and intermittent-flow gas-lift wells, it is necessary to evaluate the facilities that the well fluids must pass through to reach the storage point. This paper deals with surface back-pressure and its effect on continuous-and intermittent-flow gas lift. Particular emphasis is placed on inadequate-sized flowlines for continuous flow and intermittent slugs produced against surface chokes.Numerous field tests on continuous-flow gas-lift wells show the resulting increase in production due to reducing surface wellhead pressure. A method is presented to predict and apply surface back-pressure.Controlled experimental tests show the results of producing intermittent slugs against varying surface choke sizes. A means of calculating the weighted average bottom-hole pressure is given for an intermittent cycle. This average pressure increases considerably as the surface choke size is decreased. These calculations show when a chamber installation should be considered for intermittent lift.
One of the reasons gas-lift studies are made difficult is that the system concerned starts at the sand face at the bottom of the well and does not end until the storage facilities are reached. The whole system must be considered in the study because any alteration in the system, from one end to the other, will affect the drawdown at the sand face and the corresponding fluid production rate of the well. This paper deals particularly with surface back-pressure and its effect on production rates.Serious loss of production occurs when gas-lift wells are produced against excessive back-pressures at the surface. Surface back-pressure is considered to be that pressure found inside the christmas tree, just upstream from the flow-wing. This excessive back-pressure is generally caused by:
high separator pressure;
choke in the christmas tree or flowline;
restrictions in flowline such as paraffin, scale deposits, crimped flow line, etc; and
a nonstreamlined christmas tree incorporating a large number of sharp bends.
Numerous field and experimental tests were conducted in actual gas-lift wells for both continuous and intermittent flow to show the effect of these restrictions. It has long been known that the production of fluids from a gas-lift well may be materially reduced by producing this fluid against a surface restriction or against high surface back-pressure. It has also been a matter of education in some instances to show why this additional back-pressure reduces the total output of produced fluids (oil, gas and water).Admittedly, there are some instances wherein a well must be treated very carefully and, in turn, excessive pressure drawdown must be avoided. This is particularly true for wells that are known to produce sand and for wells that are producing with high solution gas-oil ratios. In some wells excessive drawdown has created a gas phase around the wellbore, which in turn increases the permeability to gas and, hence, reduces the oil production.It is not the purpose of this discussion to deal with those wells in these two categories; rather, it is assumed we are dealing with wells of the type where a maximum drawdown is necessary to obtain maximum fluid production. In turn, it is desired to produce these fluids with a minimum amount of injection gas.
It is common practice throughout the oil field to increase the fluid production rates from continuous-flow gas-lift wells by streamlining wellheads, enlarging, shortening and streamlining flowlines, and reducing separator pressures.In turn, this reduces the surface back-pressure on the well. Although this is common practice, it is known that a large percentage of continuous-flow gas-lift wells are still being excessively choked to as much as one-half of their efficient production capabilities by excessive back-pressures.