Honing Gaslift for Maximum Production

by John Murphy

Well before all recoverable oil is extracted from a producing reservoir, the loss of formation gas volume can rob it of its ability to produce. That is because, besides being a valuable hydrocarbon in its own right, reservoir gas is the engine that makes oil flow.

Within the formation, gas under pressure mixes with the liquid oil, reducing its density, making it lighter and easier to move. At the same time, the gas acts as a propellant, charging the well fluids and forcing them through the formation to the lower-pressured well bore and then to the surface.

When this energy source is dissipated through production, significant amounts of liquid hydrocarbon are often stranded in the formation. Recovering these additional reserves, often more than what was naturally produced, requires technical intervention, or secondary recovery methods. Depending on such factors as locale and the availability of electricity, gas, and surface space, a number of methods can be tapped to force the reluctant oil to the surface. But given that the oil will move to the well bore, albeit at a reduced velocity from its virgin, gas-charged state, and a reliable source of gas, the most efficient secondary recovery method is often a system of valves and gas injection, collectively called gas lift.

Fundamentally, gas lift installations deliver pressurized natural gas from a surface source, down the casing annulus and into, or beneath, a column of fluid in the production tubing. In general, for any given well, the deeper the point at which the gas enters the tubing, the injection point, the higher its production rate.

Therefore, achieving maximum injection depth is crucial to any gas lift installation and is determined by a number of factors, the most important being: the height to which the fluid column will rise on its own; fluid gradient: fluid gas-oil ratio; and the supply gas pressure available. In offshore applications particularly, the surface facility size is also a major concern as the cost of adding more facilities to handle more fluid is often prohibitive.

At the same time, a decision must be made between one of two available gas lift injection methods—intermittent or continuous, depending on the condition of the reservoir at the time gas lift is initiated. "Bottom hole pressure pretty much determines it," said Weatherford manager Mike Juenke from his offices in Lafayette. "In a continuous injection well, the flowing bottom hole pressure has to be high enough to sustain an aerated liquid column to the surface and maintain a desired production rate. If your static bottom hole pressure falls to a level where it can no longer support the column of fluid you have to go to intermittent."

In continuous injection, by far the more common of the two systems, the valve is located somewhere along the tubing string to constantly feed gas into the column of fluid, or "aerate" it, to reduce its density and the hydrostatic pressure it is imposing on the formation. The formation's natural pressure is then able to lift the lightened column of fluid.

But should the formation be so pressure-depleted that it cannot lift even a lightened column of fluid, a valve is placed along the tubing that remains closed until a predetermined amount of fluid has moved from the reservoir into the well bore. At that point, the valve is opened and gas is injected beneath the column of fluid, propelling it to the surface and out.

"Intermittent is analogous to a projectile," said Camco's Herb Meyer. "Gas is sent into the casing, allowing the normally closed gas lift valve to open and send enough gas under the slug to actually lift it."

Optimizing gas lift systems is done through a combination of rule of thumb, hard and fast reservoir mechanics, and iteration. In either system gas injection volumes and pressures must be so balanced as to lift the maximum amount of fluid without adding so much as to be circulating gas to no effect.

The latter problem is particularly thorny with intermittent systems that must account for a third variable, the cycle. The cycle is the amount of time between gas lift valve opening and closing. The cycle could be four or five times a day or every few minutes and is first determined generally by known variables of fluid density and column height, and then zeroed in by iteration.

"The man in the pickup truck lets [the well] cycle on a certain amount of time while checking production," Myers said. "Then he starts changing it to see if production increases and keeps doing that until production starts to fall and that is optimum."

The cycle is most often controlled by one of two methods. The gas lift valve itself is positioned along the tubing either in a side pocket or, in slim hole applications, centralized in the tubing. The valve is held closed by a spring or nitrogen dome charge while the fluid moves into the tubing. At predetermined time intervals, a surface valve is automatically opened, gas floods the annulus creating a pressure greater than that holding the gas lift valve closed. The downhole valve opens and a slug of gas pushed at high velocity through a relatively large port in the valve lifts the fluid to the surface like a piston.

A secondary, less popular method for controlling the opening of the down hole valve, is to install a small bean choke on the gas feed line at the surface. The rate at which the gas is fed into the annulus is then a function of the size of the opening through the choke. If the operator determines the valves are opening too often, he merely changes to a smaller choke size and extends the time it takes the backside to pressure up sufficiently to off seat the choke valve. Inversely, of course, the operator can shorten the time between injections by using a larger choke.

Juenke says that a good rule-of-thumb for cycling time is to kick the gas off when the hydrostatic pressure from the fluid column is equal to about 80% of the well's static bottom hole pressure. "After that you begin to decrease the drawdown from outside to inside the well bore and the feed in from the formation is slowed," he said. "On the other hand if you over-inject you are injecting gas without waiting for any input (of fluid from the reservoir) and you are using time putting gas in the tubing you really don't need."

The world of gas lift is full of practical, time-honored rules of thumb for optimization. For instance, fluid should travel up the production tubing at about 1,000 ft/min. And when beginning to set the cycle time, a good starting place is to set the interval at about three min per 1,000 ft per cycle. For instance, in a 10,000-ft well, a good beginning cycle would be about 30 minutes.

In a phenomenon known in the industry as fallback, gas lifted fluid traveling up the well bore will cling to the tubing sides and then slip back down the hole to become part of the next fluid column. "With slippage, or fallback, five percent per 1,000 ft is considered good," said Meyers. "That means in a 10,000-ft well though, half of what is lifted will fall back to become part of the next slug."

Due to the make up of the oil, defects in the production tubing or other variables, the amount of fall back can render the project untenable. In those instances, an interface known as a plunger is placed between the gas and the fluid. The plunger is a solid cylinder that works as a wiper along the walls of the tubing to minimize oil left on the wall. It also prevents gas from filtering through the oil instead of remaining beneath it as a carrying mechanism.

Gas lift can be used alone or in conjunction with other secondary methods. When a formation is so weak for instance, that it will no longer push fluid through the formation, tertiary methods such as gas-, chemical- or water-flood may be introduced to push the oil to the well bore where intermittent gas injection will then lift it to the surface.