Operators add tools to existing oil and gas wells to enhance production and extend the flowing life of the well. In a 2014 case study in the Four Corners area, one type of downhole, vortex technology tool—in conjunction with gas lift—saw beneficial increases in oil and gas production, along with enhanced water removal.
While the vortex technology is a deliquification tool, it works in conjunction with many artificial lift solutions. In simple terms, artificial lift is the application of external energy to lift production, whereas deliquification improves formation efficiency by removing the liquids that are limiting production. The downhole tool develops a "tornado in a pipe" (see Figure 1). This process forces heavier liquid-bearing components to the outside of the tubing string.
These components then travel in a helical pattern. At the same time, lighter gas is pulled to the center of the vortex to travel at substantially higher velocities. By eliminating the slip between liquid droplets and gas, the efficiency of this vortex flow reduces the flowing tubing pressures with a lower pressure drop caused by friction and reduces the critical rate required to lift liquids to the surface. The reduction in flowing pressures and critical rate translates to more efficient processes with reduced slugging and improved oil production, particularly in deviated wells. These tools also require a lower critical velocity to continuously unload liquids from the wellbore, extending the free-flowing life of a well.
With the benefits of directional drilling, horizontal wells have become the norm in many formations. While production has been substantially increased by using directional drilling, this method of recovery also created new load up issues. This is because many deliquification technologies (which increase recovery by using the energy of the well) and artificial lift technologies (which increase recovery by adding an energy source) cannot function efficiently in deviated portions of horizontal wells. Deploying a downhole tool at the end of tubing in the lateral section of a producing well helps organize the three-phase flow of oil, gas, and water while reducing bottom hole flowing pressure. Originally used to help clean out frac sand in deviated gas wells, these tools have been in continuous operation in gas wells (typically 4,800 feet deep) in northern Colorado since 2006. The tool was also added to the end of tubing in several deviated gas wells in central Texas at 7,000 to 9,000 feet deep, with the tool landed at 80 to 95 degrees of inclination. These Texas wells saw 2 to 3 times greater removal in water with reduced slugging and lower flowing pressures. Wells experienced gas production that consistently increased 20 to 30 percent and greater water removal when the tool was added. However, this benefit of increased water removal and gas production occurred during a period of falling gas prices. At this time, gas prices were low enough that operators had little motivation to increase gas lift efficiency. Since that time, higher oil prices have renewed interest in rich natural gas technology solutions. Reported challenges with production in deep laterals in producing oil wells created a new opportunity to revisit these end-of-tubing tools.
Gas Lift Case Study
A major independent oil and gas company used the tool in several of its wells in northern New Mexico. Five wells in two different producing formations were selected for this 2014 trial. The objective of the trial was to see if production could be enhanced by adding tubing extending into the curve section and if adding the tool would help move slugs of liquids sitting in the bottom of the lowest part of the wellbore. The horizontal wells were produced with a combination of gas lift and a two-part plunger to manage paraffin accumulation before the trial. The company reported problems with the plungers' descent, noting that they would not fall past 20 to 30 degrees of deviation. They also reported significant liquid loading in the horizontal portion of the well causing higher-than-expected tubing and casing pressures. During a planned workover of each well, the new tool was landed at the end of tubing at different degrees of inclination in the lateral portion of the five wells. Four of the five wells had gas lift valves installed, and tubing was run farther into the lateral, increasing the measured depth by an average of 500 feet. The tools were landed at the end of tubing and set at 80 degrees of inclination. Previously, the end of tubing was set at only 40 to 50 degrees in the lateral section. Finally, the gas lift valves were removed on the fifth well, and this well was operated as a "poor-boy" gas lift for comparison.
One of the five wells was discounted by the operator early in the trial because of reported problems with a hot oil treatment some months earlier. The data was still gathered for comparison. In the first two wells, oil production increased by an average of 58 percent. The remaining three wells all saw a beneficial flattening of the long-term decline curve but no increase in daily production. The increased oil recovered from these first two wells produced an additional 8,658 barrels in the analyzed two-and-a-half-month period following the installation. Water removal increased by as much as 700 percent while flowing tubing and casing pressures reduced substantially and 42 percent lower respectively. In gas lift operations, these wells typically recover less gas than the gas that is injected to lift and produce the oil. With the addition of the downhole tools, injection rates were reduced by up to 50 percent, and four out of five wells (including the well on poor-boy gas lift) moved to a net recovery of gas from net injection. The two wells that saw the greatest increase in oil production (57.4 and 58.3 percent), also saw the highest rise in gas rates (76 and 95 percent). Water removal in these two wells also increased substantially at 600 and 700 percent respectively. Even in the well that had previous operational problems following a hot oil treatment, production was more even and the decline curve had flattened. Other longer term benefits included stable and lower flowing tubing and casing pressures.
Table 1 provides a detailed look behind the numbers for three of the wells that were the subject of this study. These wells are comparable since they are all in the same formation, with similar depths and completions (7-inch casing and 2 7/8-inch tubing), and were all operated with gas lift valves. Well D was produced with poor boy gas lift and the downhole tool. Oil production decreased from 84 to 66 barrels per day (bpd), but showed an improved long-term decline curve. Water removal increased from 13 to 18 bpd, a 38 percent increase. Produced gas rates increased slightly from 361 to 370 thousand cubic feet per day (mcf/d). In percentage terms, gas recovery increased from 90 percent of injected gas to an average of 135 percent of injection gas rate recovered. Flowing tubing pressures remained similar at 102 psi on average (compared to 117 psi previously). Well E was discounted from the trial by the operator. However, this well's data was still analyzed. Oil, gas and water were all down marginally, although the long-term oil production curve showed improvement. This well continues to produce only 88 percent of the injected gas. Flowing tubing pressures reduced on average from 244 to 139 psi, and operators saw a noticeable smoothing of the pressure spikes that had been observed before the tool's installation.
Downhole tools offer a cost-efficient technology solution to manage and optimize liquids recovery from horizontal wells with long laterals. With no moving parts, no maintenance requirements and no chemicals, this solution is available in all tubing and casing sizes and provides well optimization benefits along with several monetizable opportunities.