Identify artificial-lift methods for Gulf Coast wells
As much as every oilfield operator might dream that a high-producing oil or gas well will experience remarkable recovery rates for years with no noticeable drop-off in production, every well will peak and then enter a decline stage, whether steadily or precipitously. When the inevitable decline occurs, it falls on the oilfield production company to determine if, or how, the well can be resuscitated.
When a well’s production rate drops below critical velocity, it is almost inevitable that it will eventually stop producing. The actual rate of decline and ensuing production must be taken into consideration when determining a well’s ultimate future. With today’s commodity prices, many operators are faced with spending money on artificial-lift systems that can improve recovery rates or simply choosing not to address low or non-producing wells before moving on to the next project, where the entire process begins again.
Another factor that may influence the well’s viability is its location. The Gulf Coast region is close to major pipelines and processing facilities, thereby enjoying premium commodity prices. This area spans the southern tip of Texas along the Mexico border, encompassing the Eagle Ford Shale play, heads east through Houston, then culminates in the inland waters and land around Louisiana, including the Tuscaloosa Shale play. The topography in most of this area is coastal plains, differing, for instance, from that found in the Bakken or Permian Basin region.
In addition to the type of land formations encountered during the drilling process, wells in the Gulf Coast region can be prone to producing paraffin, scale, and sand, as well as having high levels of entrained carbon dioxide (CO2) and hydrogen sulfide (H2S) in some areas. Knowledge of these conditions—as well as their effect on production rates—will help determine the best drilling methods, surface equipment, and systems to use to maximize initial production rates.
They also will play a critical role in indicating which artificial-lift methods should be used to revive wells that have seen declines in production. The following highlights the forms of artificial lift that should be considered by Gulf Coast operators whose wells are experiencing production declines.
The first challenge for the operator of wells that have seen a decline in production is to understand that typically no artificial-lift method will increase a well’s recovery rate to a level that exceeds its initial production rate.
Instead, the operator should look at the use of artificial lift as a kind of "tune-up" for the well, or a way to return its production to the original production curve, or even create a new curve that allows production to decline at a slower rate than expected.
There are a few physical challenges that must be addressed and overcome by Gulf Coast operators. Chief among them is the amount of fluid and the gas-to-liquid ratio (GLR) that is produced by a well daily. This can range from less than 10 barrels a day to more than 2,000 barrels a day and GLRs from 1:1 to more than 10,000:1, sometimes in the same play, such as in the Eagle Ford Shale.
Another piece in the puzzle is the pressure of the reservoir. Again, there can be large variations in pressure, depending on where the well is located. Some low-pressure reservoirs can have pressure rates as low as 200 psi (14 bar), while some wells—especially those situated in the Haynesville Shale—can have pressure rates up to 10,000 psi (700 bar).
As mentioned, the levels of paraffin, scale, and sand that are produced also will play a role in determining the type of artificial-lift method to deploy. The best way to prevent the buildup of paraffin and scale is to find an artificial-lift system that can keep the tubing clean. Collecting and controlling any CO2 and H2S that is produced also is a critical consideration, with stainless-steel materials usually required to prevent corrosion within the well’s tubing and casing.
After determining the conditions that are hampering a well’s production rate, and knowing that they will need to be addressed if that rate is to be fully recovered, the next step is identifying the best artificial-lift method for optimal production.
With that in mind, several artificial-lift technologies have risen to the fore in instances when the operator’s need is to revitalize declining wells:
First-responder bypass plunger: Designed to operate in a flowing well and make more trips with faster fall times for continuous fluid removal, the two-piece bypass plunger increases daily production for younger wells. 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 (see figure 1).
Enhanced annular-velocity (EAV) system: EAV systems use properly-sized tubing and gas-lift valves above a packer and a selectively-sized injection string with 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 obtained, the gas exits the injection string, mixes with the produced gas and fluids, and flows up the annular area. The fluid and gas then flow through the adapter into the production tubing. The EAV system maintains adequate velocity of flow below the packer to ensure that there are no fluid accumulations, heading, or liquid loading (see figure 2).
Dip tubes: Dip tubes are ideal for lowering the flowing bottom-hole pressure in wells with long perforated intervals and large casing. A crossover-flow adapter and mini-wellbore below the packer are used to facilitate the deepest point of gas injection without applying any additional backpressure on the formation. A typical installation might have 2-3/8-in." tubing above the packer, an adapter with a 2-7/8-in." tailpipe below the packer and a 1-" or 1-1/4-in." internal-injection string inside the tailpipe. 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 gas in the injection string, tailpipe annulus. The fluid and gas then flow through the adapter 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 (see figure 3).
Multi-stage plunger tools: For wells with low gas but high liquid levels, efforts aimed at their lift to the surface can benefit from a multi-stage plunger system. 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. Creating two plunger-lift systems in one allows the well to produce liquids in stages, which allows it to produce larger volumes while utilizing its own energy (see figure 4).
Most of these artificial-lift methods have been available to oilfield operators for about a decade and have a proven track record in the Gulf Coast area. In fact, once a successful form of artificial lift is identified, its users will typically stay loyal to it for years. The trick, of course, is identifying and implementing the one that works best for the specific conditions and application, while still being aware that new technologies may prove to be even better for a well.
It’s inevitable that a well’s recovery rate will decline at some point. When this happens, the operator has two choices: do nothing or try to return the well to its previous production levels by using an artificial-lift method. In the Gulf Coast region, the unique characteristics of the formation itself play a significant role in determining which method of artificial lift will be most efficient and reliable. Selecting the right one for the right well will go a long way in optimizing returns and profitability for wells that have begun showing their age.
Bob Bishop is the director of Gas Lift for Dover Artificial Lift, Houston. Dover Artificial Lift is part of the Energy segment within Dover Corp.