Millions of Dollars Saved with Gas Assisted Plunger Lift Optimization

Case Study: Millions of dollars saved with Gas Lift and Plunger Lift Optimization Apps

This case study examines the results of a successful broad scale implementation of Plunger lift and Gas Lift optimization apps on over 1000 liquid rich natural gas wells in the Montney formation in Western Canada.  The results are impressive, millions of dollars saved by minimizing the amount of injection gas used, while also reducing operator interventions and down-time.

Summary

A large liquid rich gas producer in the Montney was looking for cost effective and scalable solution to add Plunger Lift, Gas Lift and GAPL control to hundreds of existing wells and all new wells going forward.  The existing automation equipment was heavily utilized and not to be physical altered.  A software only solution left the physical devices undisturbed to minimize operational disruption and cost of change.  

A several well pilot successfully proved the concept.  The solution was rolled out to over 1000 new and existing wells over the last few years.  The results were excellent with the following benefits realized:

1. Injection gas optimization.  Millions of dollars saved by reducing injection gas usage to the minimum required to maintain production.

2. Automated Operations.  Gas lift injection automatically responds to various changes in flowing conditions, minimizing operator intervention and downtime.

This producer purchased processed injection gas from a third party so the costs per unit of injection gas were known. The proven injection gas usage savings across the entire field totaled millions of dollars per year in savings.

Problems with downstream facilities were causing continuous production upsets. This caused dozens of wells to shut-in on a regular basis. Traditional gas lift control requires a manual well start up procedure to bring wells back online.  This producer learned they could let the application bring wells back online automatically, with no operator intervention, significantly reducing the time and complexity of bringing a field back online.  The reduction in production down-time after a downstream upset is tremendously valuable.

Technical Background

Plunger and gas artificial lift technologies have been used by the oil and gas industry for decades.  Plunger lift originated to help gas wells remove water to maximize production and up-time by cycling the production valve.  Gas lift originated to help oil wells produce more oil as reservoir pressures decline by injecting gas into the casing to reduce the hydrostatic pressure of the oil.  

Combining these two technologies is referred to as Gas Assisted Plunger Lift (GAPL), or Plunger Assisted Gas Lift (PAGL).  Gas lift injection control follows along with the plunger cycle and employs specific control and optimization methods for each step in the cycle.

With the PLC Shift GAS LIFT app and the PLC Shift PLUNGER LIFT app, we provide the following control modes:

1. Pre-arrival injection.  Gas is injected while the plunger is travelling up the tubing to ensure the plunger arrives consistently and on time.  This injection rate can be optimized in real-time to use the least amount of injection gas to achieve these results.

2. Post-arrival injection. Gas is injected after the plunger arrives, similar to continuous gas lift injection.  The injection rate can be optimized in real-time to use the least amount of injection gas required to maintain the production flow rate above the calculated critical flow rate of the well.

3. Shut-In Injection.  Gas is injected during the shut-in step to add energy to well to help the upcoming plunger arrival cycle.  This is controlled by the desired casing pressure increase.

Variable Injection Mode

Variable Injection is a unique control mode that reduces injection gas usage while maintaining production in real-time.  The algorithm conditions a wet gas meter flow rate and compares this value to a real-time calculated critical flow rate for the well.  If the flow rate is above the critical flow rate, injection gas is reduced, if the rate falls below critical, injection gas is increased.  The application outputs a real-time injection valve position. The transfer function between the measured gas flow rate and injection flow rate is not a simple on-off control, but uses a PID to allow for fine tuning. This reduces overshoot, oscillations and reduced lift gas usage.

Case Study Results

Numerous cost savings and operational benefits were realized.  The most compelling is a massive reduction in injection gas used during gas lift operations.

Variable Injection Example #1

The green pen is combined well gas production rate. 

The blue pen is combined injection gas rate.

This trend shows how the 'Variable Injection' mode was used to reduce injection gas by 90%, while maintaining well production through slug flow conditions.  This real-world example shows the combined production rates and injection rates from two wells.  One well had a continuous injection rate of 15 e3m3/day throughout the test.  The second well utilized 'Variable Injection' mode.

Point 8 on the trend identifies the start of the test where the control mode was switched from manual injection to the variable mode. You can see an immediate decline in injection gas usage and the algorithm searching for the ideal rate, eventually settling on a steady rate of 20 e3m3/day for two weeks until a change is made at which the system responds with a new injection rate.  The net injection rate for the well under test at the beginning of the test was 55 e3m3/day (70 – 15).  The optimized rate was automatically determined to be 5 e3m3/day (20 – 15).  This is a reduction of injection gas usage of 90% while maintaining production.

Variable Injection Example #2

In this example, the well does not need gas lift initially as there was enough energy in the well to produce fluids. Several hours later production begins to decline as the well loads up, and gas is automatically injected to bring production back to the target rate. This also prevents the well from loading up.

Variable Injection Example #3

 This example demonstrates a well with a very noisy flow measurement due to high liquid content across the orifice meter.  In this case, the algorithm in the app conditions the input signal and reliably responds with injection gas as the well begins to load up.  Once the well returns to a normal flow the injection gas is backed off.

Variable Injection Example #4

This example demonstrates how injection gas is automatically applied during a period of high static pressure (backpressure) on the pipeline. When static pressure drops, the injection gas is no longer needed and automatically reduces to zero.   Production is maintained without manual operator intervention.

Gas Assisted Plunger Lift Example #1

Plungers are added to wells to help bring liquids to the surface and remove wax buildup.  Gas lift can be used to help the plunger rise and to automatically maintain normal plunger arrival times. In this example the plunger was not arriving properly, and the gas lift injection rate was automatically incremented until the plunger arrived and normal operation resumed.  Injection gas usage was then reduced back to a minimum.  The well did not load up and costly down-time was prevented, all without any manual operator intervention.

Gas Assisted Plunger Lift Example #2

A closer examination of the 'Pre-arrival Injection Optimization' feature demonstrates an automatic reduction of injection gas to zero with consistent normal plunger arrivals.