Staged plunger lift will pull liquids from wells that standard plunger lift systems can’t handle. (Graphic courtesy of International Lift Systems LLC)
With plunger lift being a highly recognized method of artificial lift for unloading wellbore fluids from oil and gas wells, many new and old equipment designs are being introduced or re-introduced into the plunger lift market. Several novelty-type designs have been tested and have had narrow operating windows. Most apply only during certain periods of the well’s economic depletion cycle.

Free cycling of a plunger is probably the oldest plunger lift methodology that has gained high recognition over the past 5 years but has the narrowest operating window of all plunger lift methodologies. Due to the narrow operating window of most of the new and old designs, that window has forced International Lift Systems to think out of the box for new designs and methodologies of producing the wells via the use of plunger lift. One of the most recent equipment designs and methodologies that promises to widely open the operating window of plunger lift is staged plunger lift (SPL).

This article presents a study of the application of SPL to wells that did not previously meet the operating criteria for plunger lift. It also addresses extending the economic depletion of wells currently being produced by plunger lift.

Application
As reservoir pressure depletes, the removal of liquids from the well bore becomes less efficient. The accumulation of these liquids creates hydrostatic head pressure on the formation. This increased back-pressure on the formation dramatically decreases production and increases flowing bottomhole pressures. If the problem is not addressed within a reasonable time frame, the well will eventually load up and die. A plunger lift system is normally installed to remove the liquids from the well bore to reduce the hydrostatic head pressure on the formation face.

Plunger lift is a cyclic method of production, requiring open time for the plunger to travel to surface with the liquids and the well to be allowed to continue to flow, to produce gas until liquid loading starts to re-occur. Then a close cycle is initiated to allow the plunger to fall to the bottom of the well and to build pressure that will be used to force the plunger and accumulated liquids to surface on the next open cycle. The amount of gas and pressure required to achieve a successful plunger cycle depends on the amount of fluid that is being lifted, tubing size, sales line pressure and the depth from which it is being lifted. Several wells have difficulty meeting the gas and pressure inflow criteria required to make each cycle successful. That is where SPL applications begin.

When reviewed by the company’s reservoir engineering department, SPL has also decreased the economic depletion pressure point of high gas-liquid ratio (GLR) wells, which are being considered for economic depletion with the use of plunger lift.

SPL is being applied to many new and existing plunger lift systems. SPL has shown significant results when applied to wells meeting the following criteria:

• Scenario 1: Existing Plunger Lift Installation
- Wells that are nearing economic depletion with high GLR;
- Wells that fail periodically to run the plunger due to pipeline pressure fluctuation; and
- Wells with high pipeline
pressure.
• Scenario 2: New Plunger Lift Installations
- Wells with high pressure and low GLR; and
- Wells that fail to meet the criteria requirements to run a plunger from the end of tubing (EOT).

We will address these scenarios individually.

Scenario 1.1
SPL has been applied to many wells that were considered to be nearing economic depletion. Several of the wells have been run on plunger lift since liquid loading started to occur many years ago. Static casing pressures of these wells did not exceed 150 psig. The wells had gotten to a point that the reservoir and limited annulus storage (when available) could not supply the inflow of gas required to maintain a differential pressure across the plunger as it traveled up the tubing. This caused erratic plunger performance and erratic daily production rates. After installing SPL in the wells, the plunger runs became consistent and the production stabilized.

The increase in plunger lift performance was caused as the amount of fluid being lifted to surface per plunger cycle was reduced by 50% and was being lifted from approximately 60% of the actual tubing depth. This forced the gas inflow rate requirement to be reduced by almost 50% and the time required to maintain the inflow rate to be reduced by 40%. This caused the well to be cycled twice as many times per day as it was previously being cycled from bottom. As a result the average operating casing pressure went from 100 psi to 60 psi.

After reviewing the performance it became apparent that the operator could considerably lower its bottomhole economic depletion pressure, and this showed a significant increase in recoverable reserves on a P/Z plot.

Scenario 1.2 and 1.3
Common causes of erratic plunger performance are fluctuating pipeline pressures and high pipeline pressure.

As pipeline pressures increase on low-pressure systems or remain high on main line systems, it causes the plunger lift system to operate at a lower differential pressure across the plunger. This in return reduces the fluid lift capabilities because of lower differential pressure across the plunger and increases the gas and pressure inflow rate required due to the super-compressibility of gas. Again, the SPL system has produced significant performance changes when installed on wells producing into these types of systems.

Scenario 2.1
Plunger lift has always been considered as a viable lift method in high GLR wells but not considered as a viable method for wells that produced at or below a 3 Mcf/1 bbl fluid GLR.
The lift company, during intense performance studies, selected some wells that were far from meeting the required GLR to run plunger lift consistently.

One such well was so economically marginal and remote that a pipeline was not run to the well. The lease operator would shut the well in for 14 days and produce it for 1 day. The well would produce 400 b/d with a 10% oil cut and vent 90 Mcf/d of gas. The static reservoir pressure was near 4,700 psig. The lift company decided to test the outer limits of the SPL system and designed a multiple SPL system for the well. The well responded remarkably well, stabilized at an average daily production rate of 250 b/d of liquids and maintained the daily oil cut of 10%. The technical team does not consider this type of well to be an outer boundary limit for the SPL system and has reviewed data on many wells with similar producing characteristics in which the operator declined to attempt a plunger lift system. This particular well had some very intriguing data from a transient reservoir analysis that encouraged the engineering department to attempt the installation.

Scenario 2.2
The company worked with a client to review possible artificial lift methods for a low GLR reservoir at 13,500 ft (4,116 m). Swab testing proved the wells to produce at a 2 Mcsf of gas/1 bbl of oil GLR and rates of 30 bbl of oil and 60 Mcf per day of produced gas. The client was adamant about installing the wells on reciprocating rod lift; the pump company’s engineering department campaigned against it due to possible pumping unit torque conditions that would be recognized on the pumping unit itself and the difficulty in designing a rod string to handle the lift capabilities needed, as well as the harmonic balancing act required to make it work. The company then convinced the client to try a multiple SPL system. The multiple SPL system stabilized and maintained production rates of 30 b/d of oil and 30 Mcf/d of produced gas. The produced gas was decreased due to the shut-in on arrival cycle method used. This in return utilized all formation gas drive to lift fluid instead of being exhausted up the annulus as a reciprocating rod lift system would do. The client then studied the recoverable reserves and realized that the multiple SPL system would recover more oil from the formation by utilizing all formation gas to drive the oil to surface than any other form of artificial lift.

The SPL system widens the operating window of plunger lift applications from both operational and economical standpoints.

SPL is not a novelty or short-term product. SPL will be considered as a piece of the plunger lift suite of products as long as the world continues its quest for hydrocarbons.