Learn about artificial lift methods that can extend a well's life.
by Bob Bishop

It’s a fact of oil field life – despite the hopes, dreams and abilities of the operator – that no matter how prolific a gas or oil well is, it will eventually enter a decline stage. When this inevitable decline occurs, the onus falls on the production company to evaluate the return volumes, along with the rate of decline, and then make an educated decision regarding whether or not the well can still be made viable.

The key indicator that decline in production is looming is evidence that the well is no longer producing at its critical velocity. When this dip below critical velocity takes place, it is inevitable that the well will eventually stop producing. When the loss of critical velocity occurs, it is time for the operator to begin monitoring the rate of decline before determining the well’s future. In many cases, the best option for the operator is to approve a capital outlay for an artificial lift system that can help recovery rates rebound. The other alternative – for wells that are not economically feasible to resuscitate – is to simply allow that low or non-producing well to die a quiet death.

If it appears that artificial lift can be an effective way to return a well to its past production glories, the operator must determine which form of artificial lift is the best for the particular well. This article will highlight the varieties of artificial lift systems that should be considered by oil field operators whose wells may be experiencing production declines but still have the potential to be reliable and profitable producers.

Tune Up Declining Wells

Operators who choose to incorporate artificial lift in declining wells must first accept this fact of oil field life: typically, no artificial lift method or system will ever increase a well’s recovery rate to a level that exceeds its initial production rate. Instead, the operator should view the use of artificial lift as a form of “tune-up” for the well, or a proven way to return the well’s production to the original production curve, or even create a new curve that allows production to decline at a slower rate than was being experienced.

After accepting that artificial lift is not a miracle cure-all that will coax wells into new heights of return, there are a few physical well characteristics that also must be acknowledged and considered. Chief among them is the amount of fluid and the gas-to-liquid ratio (GLR) that is produced by a well on a daily basis. This requires accepting the fact that no two wells – or oil-and-gas-producing regions – are the same. The amount of produced fluids can range from less than 10 barrels a day in some wells to more than 2,000 barrels a day in others, with GLRs of 1:1 to more than 10,000:1, sometimes in the same field or region.

The downhole pressure in the reservoir is another critical piece of the puzzle. Again, there can be large variations in this pressure depending on where the well is located. Some low-pressure reservoirs can see pressure rates as low as 200 psi (14 bar), while some wells can have excessively high pressures of up to 10,000 psi (700 bar). Specific artificial lift systems have been developed with certain pressure levels in mind, with optimized production rates not achievable if the selected system is not compatible with the levels of downhole pressure.

Other things to consider before settling on artificial lift system are the levels of paraffin, scale and sand produced by the well during recovery operations. The best way to prevent the buildup of paraffin and scale is to find an artificial lift system that has the ability to keep the tubing clean. Controlling and collecting any carbon dioxide (CO2) and hydrogen sulfide (H2S) that is produced by the well is also a crucial consideration, with stainless-steel materials usually required as a way to prevent corrosion within the well’s tubing and casing.

Finding The Best Solution

After assessing the conditions that have begun to hamper the well’s production rate and knowing that these conditions will have to be successfully addressed if the pre-decline production rate is to be fully recovered, the next task becomes determining the method of artificial lift that is best equipped to return production to previous levels.

Knowing the varying challenges that oil field operators face when trying to resuscitate a well, the developers of artificial lift systems have created a number of different technologies, all of which possess the ability to revitalize declining wells, if used properly:

  • Enhanced Annular Velocity (EAV) Systems: These systems use specifically sized tubing and gas lift valves above a packer in conjunction with a selectively sized injection string and internally mounted gas lift valves below. Injected gas flows into the annulus, travels through the crossover-flow adapter and into the injection string. When the deepest point of injection is reached, the gas exits the injection string, mixes with the produced gas and fluids, and moves up the annular area. The fluid and gas then flow through the adapter and into the production tubing. This method of operation allows the EAV system to maintains adequate velocity of flow below the packer, which ensures that no harmful fluid accumulations, heading or liquid loading will occur.
  • EAV systemFigure 1. An EAV system (Images and graphics courtesy of Dover Artificial Lift)
  • Dip Tubes: This equipment is used to lower the flowing bottom-hole pressure in wells with long perforated intervals and a large casing. It uses a crossover-flow adapter and mini wellbore below the packer to facilitate the deepest point of gas injection without applying any additional backpressure on the formation. A typical installation might have 2-3/8 inch tubing above the packer, an adapter with a 2-7/8” tailpipe below the packer and a 1 or 1-1/4 inch internal injection string inside the tailpipe. In this configuration, compressed gas travels through the annulus and crossover-flow adapter into the injection string. The gas then exits a gas lift valve and mixes with the produced fluid and residual gas in the injection string’s tailpipe annulus. The fluid and gas then flow through the adapter and into the production tubing. During operation, the injection-gas pressure is contained in the injection string, isolating it from the perforated interval and optimizing recovery rates.
  • horizontal dip tubeFigure 2. Horizontal dip tube
  • First Responder Bypass Plunger: Features a two-piece plunger that has been designed to make more trips in a flowing well with faster fall times for continuous fluid removal, which is an ideal way to increases daily production for younger wells that may be experiencing declines. The sleeve portion is held in the lubricator over a rod by the well’s flowing pressure while the ball falls to the bottom of the well. As liquid loading begins in the well, the reduced flow allows the sleeve to fall. When the sleeve reaches the bottom, the ball seats in the sleeve, creating a seal. Pressure builds, causing the ball and sleeve to travel together while lifting fluid to the surface. At the surface, the rod in the lubricator separates the ball from the sleeve, and the process begins again.
  • first responder plungersImage 1. First responder plungers
  • Multi-Stage Plunger Tools: Multi-stage plunger systems have been created for use in wells with low gas levels and high liquid levels that are having trouble lifting them to the surface. These systems use more of the well’s own energy to help lift liquids and increase productivity. During the first cycle, the lower plunger carries the fluids up the tubing. Upon shut-in, the ball check engages, which holds the fluids until the upper plunger falls from the surface through the liquid and settles at the tool. Simultaneously, the lower plunger falls back to the bottom. During the ensuing cycle, the upper plunger delivers fluids from the tool to the surface, while the lower plunger delivers more fluid to the tool. This creation of two plunger lift systems in one allows the well to produce liquids in different stages, which allows for the production of larger volumes while utilizing its own energy.
  • multi-stage plunger toolImage 2. Multi-stage plunger tools

Most of these artificial lift methods have been available to oil field operators for about a decade and have developed a proven track record. In fact, once a successful form of artificial lift is identified, operators will typically stay loyal to it for years. The challenge, of course, is identifying and implementing the one that works best for the specific well conditions while being aware that any new technologies that are developed may prove to be an even better solution for a particular well or group of wells.

Knowing that, keep in mind that the first responder bypass plunger is an artificial lift technology that can be installed on almost any flowing well that is approaching critical velocity. The other three technologies – EAV, dip tubes and multi-stage plunger tools – are considered “secondary” artificial lift methods that can be used to try to squeeze additional production out of marginal or hard-to-produce wells.

In Summation

When a well reaches its inevitable decline stage, the operator faces a decision that usually has two possible outcomes: do nothing and let the well head into retirement, or try to return the well to its previous production levels through the use of an artificial lift method. The unique characteristics of all wells play a significant role in determining which method of artificial lift will be most efficient and reliable. The trick is selecting the right one for the right well, knowing that the perfect solution will go a long way in reaching the highest levels of return and profitability for wells that are still viable, but have begun to age.