Gas lifting large volume wells
Authors: Bechthold H.D. , Kilgore D. 
Published: December 2007

Gas lifting large volumes of fluid in excess of 4,000 b/d presents a different continuous flow lift problem than with most wells that are lifting volumes of fluid under 4,000 b/d by continuous lift flow method.

This paper will assist oil operators in designing compressor systems. It will show the necessity of having proper gas pressure and volume to lift large volume fluid wells. You must ascertain if the proper volume of gas is available to lift large volumes of fluid and if the well itself is capable of lifting large volumes of fluid.

METHOD

Producing fluids in excess of 4,000 b/d presents a different continuous flow gas lift problem for the producer as compared to wells producing less than 4,000 b/d. The biggest problem that the producer is confronted with is the design of his compressor system and distribution lines. He must design installations that will allow him to lift from the deepest point in the well and at the same time have enough gas volume on hand to lift these wells continuously. His next problem: Is his well capable of producing the required volumes of fluid? He must be able to distribute the gas pressure and volume to each well. Each well will require different pressures as well as different volumes of gas depending on his designed maximum pressure.

As with all continuous flow gas lift wells considerably more data is required to design a properly spaced gas lift installation than to design a well for intermittent lift. Volumes of fluid in excess of 4,000 b/d require more accurate information. Too many times the producer does not have this information available and must rely on information from a drill stem test or information from one well only. This one well will furnish information to the designer that may not apply to other wells. The gas lift designer can only do his best with what data he has and hope for the best. See Table 1 for necessary data required to design a continuous flow gas lift installation for 7,400 b/d.

The designer must then start his gas lift installation using the information furnished him by the producer. At this point the most desirable installation would be to start with the desired flowing bottom hole pressure and using the gradients of the well fluids and gas fluid ratios showing the flowing pattern of the well from bottom up. This allows the designer to see how the well behaves at the lower section particularly below the lowermost gas lift valve. See Fig. 1 for example.

Next the designer must calculate a flowing gradient using published gradient curves in which he has the most confidence that will be as close to this well's flowing behaviour. This generally has to be done by computer to get the best results. See Figs. 2 and 3 for examples. The separator pressure and flow line length and size will determine the pressure required at the wellhead to flow the desired amount of liquid.

At this point the designer can determine the required gas pressure needed to lift this well properly. Where the two points meet (1) the flowing calculated gradients and (2) the well's flowing behaviour pattern determines the deepest point the well can be lifted with this flowing hole pressure. This could change in tmle and valves will be needed to be placed below the point for future lifting. At the point where these two lines cross, the designer will take a 100–150 p.s.i. difference to be able to enter the tubing string. This determines the pressure needed at the surface to be able to enter the tubing string and lift the well. This example tells us we will need 1,680 p.s.i. pressure at 7,500 ft. See Fig. 4 for example. The designer must then back calculate to determine the surface pressure needed to get the desired pressure at the point of lift.

To determine the volume of gas required to lift the well can be calculated by subtracting from the calculated flowing gradient the formation gas liquid ratio, the difference will be the required amount of injected gas. If, for example, the well produces 3,700 barrels of oil with 3,700 barrels of water at an oil ratio of 300:1 and the calculated flowing gradient shows an 800:1 ratio needed, then the difference of 650:1 will be the required amount of injected gas. This means a total of 4,801,000 cu. ft. gas per day at a pressure of 1,450 as determined by Fig. 4.

The problems now begin to mount up because the next well may produce 75 per cent. water or more which reduces the amount of gas available from the formation and will require more injected gas and may require a different gas pressure. Normally a gas compressor is installed at a central location so that the operator can distribute the gas to all wells on gas lift. If each well requires different pressures to be lifted then the compressor must be sized so that the well requiring the most pressure can be lifted. Pressures must be dropped throughout the distribution lines so that less pressure is applied to other wells.