Enhancing well efficiency through gas lift in the U.S. with qualified oilfield chemicals
As the global oil and gas industry continues to prioritize improved oil recovery and maximizing production from existing wells, operators must engage with solutions that cost-effectively support these objectives. Not only is this a point of interest from a profitability standpoint but also for reaching sustainability goals.
Gas lift systems can handle a range of rates and operational characteristics, including the multiphase production flows associated with high gas-to-oil ratios and solids contents typical of many unconventional wells. Another key advantage in utilizing gas lift is its inherent versatility to adapt to rapidly changing conditions during early well life by adjusting injection volumes, and its ability to maintain lifting efficiency well into the decline curve. However, gas lift mimics the natural reservoir environment, creating a differential pressure between the reservoir and the wellbore to reduce flowing tubing pressure and lift fluids to surface.
There is another important enabler behind gas lift’s emergence as the artificial lift system of choice for many operators: the abundance of available injection supplies in horizontal tight oil plays. Significant amounts of associated gas are produced along with liquids in even the “oiliest” of basins. In the Permian, for example, data from the U.S. Energy Information Administration shows that while oil production has jumped from 1.5 MMbpd to nearly 6 MMbpd over the past 10 years, daily gas output has likewise soared by four-fold to 24 Bcf during the same period. In the Eagle Ford and Bakken, operators produce 7 Bcfgd and 3 Bcfgd, respectively, along with a combined 2.5 MMbopd.
There are high volumes of gas held in the wings of tight reservoirs that can be used to optimize the production of the higher-value oil, and this is one of the few limitations of gas lift, ensuring there is an adequate supply of injection gas available. In practice, local infrastructure capabilities and operating economics (more injection means higher cost) often impose practical constraints. Although the build-out of in-basin infrastructure has greatly expanded pipeline access points, distance to a buy-back gas source remains a factor in some development areas. Because of their high GORs and water cuts, tight oil wells on gas lift may have a greater tendency for slugging, which can be compounded by steep decline curves, compression inefficiencies, or suboptimal injection depths or volumes.
This is particularly true in North America, where unconventional resource plays are entering a more mature phase of infill development. As operators have increasingly shifted their attention away from drilling new leases toward fully developing acreage between existing producing wells, the challenge has become increasing estimated ultimate recoveries (EURs). In tight oil reservoirs, such as the Wolfcamp, recovery rates during primary production are commonly estimated in the single digits.1 Reflecting the old industry adage, “the best place to find oil is in an oil field,” operators are zeroing their focus on maximizing the performance of existing producing wells and improving EURs.2
Improving the bottom-line performance of a well on gas lift is largely a balancing act between maintaining the most favorable injection rate and achieving the desired reservoir drawdown to optimize the production rate, and avoiding problems that disrupt either injection or production. Getting that balance exactly right requires cross-functional solutions, based on enhancing the interactions between the gas lift equipment, chemical program, injection controls, and completion parameters in a dynamic downhole environment that is continually changing from the moment first injection commences.
Even the best designed gas lift system can be impacted negatively by corrosion, paraffin, scale, and organic solids. Experience shows that when a gas lift system fails, odds are it’s because a gas lift valve has failed, due to corrosion. Corrosive fluids and gases can not only damage valves, but degrade tubular integrity, allowing the influx of injected gas at points other than the valves. Additional common root causes of system failures are solids and debris, paraffin, and scale inside valves and tubulars that restrict or block flow.
The majority of gas lift wells require chemical treatment, typically consisting of corrosion inhibitor, scale inhibitor, paraffin solvent, biocide, and flow improver applied on a continuous basis. However, because the physical downhole conditions encountered in gas lift wells are distinct from other forms of lift, it is critical to use chemical products and delivery systems suited specifically for the application.
One challenge when using conventional chemicals in gas lift is a phenomenon known as “gunking.” It occurs as temperature and pressure gradients change with depth, stripping out solvent carrier compounds. Ultimately, these compounds can solidify into a film-like consistency and plug valves and mandrels. The potential for gunking is exacerbated by the Joule-Thomson cooling effect of the higher-pressure lift gas, as it flows into the lower-pressure tubing. The temperature drop also promotes paraffin deposition inside tubing at gas injection points, particularly when inhibitors are slipstreamed into the lift gas or injected down the casing annulus.
MAXIMIZING CHEMICAL EFFECTIVENESS
To mitigate these potential problems, using gas lift-qualified chemical packages is a recommended best practice. Regardless of the chemical delivery method, qualification maximizes chemical effectiveness and reduces the risk of corrosion, scale, and paraffin-related failures. In wells with severe conditions, such as high percentages of hydrogen sulfide or carbon dioxide, corrosion-resistant polymer coatings, nickel plating, and specialty metallurgies can be used with qualified chemicals to add additional safeguards to gas lift tools, Fig. 1.
Qualification consists of rigorous laboratory and field testing to assure compatibility and effectiveness under simulated pressure, temperature, and reservoir fluid conditions. To illustrate the qualification process, consider an example from a condensate-rich shale play where horizontal wells on gas lift were experiencing paraffin blockages. Paraffin deposition was occurring primarily at the injection valve, where the lift gas—already at a significantly lower temperature than reservoir fluids—was subject to abrupt Joule-Thomson cooling. In this field, paraffin was frequently plugging gas lift valves, even though high concentrations of conventional paraffin inhibitors were being continuously slipstreamed with the lift gas.
Qualification testing of produced fluid samples identified a product consisting of a mixture of highly aromatic solvents and inhibitors suitable for gas lift. The inhibitor prevented paraffin formation at even low concentrations, and the dispersants effectively broke up already-formed paraffin. Following qualification, the inhibitor was successfully implemented field-wide in the horizontal wells to eliminate paraffin deposition, saving significant chemical costs, optimizing gas lift production, and reducing downtime and the need for well cleanouts.
The design of the gas lift system, including the placement of mandrels, valves and packers, is vital to determining the most appropriate chemical delivery method. There are three options for delivering qualified chemicals downhole: injecting through a small-diameter capillary line, slipstreaming into the injected gas, or treating down the backside. The most effective option, however, is usually installing a capillary string inside production tubing or banded externally to the outside of tubing.
Capillary delivery distributes precise dosages of chemicals exactly where needed (usually below the bottom-most valve) to treat the entire wellbore—not just the segment contacted by lift gas—to keep wells operating at peak performance. It is imperative to select the right capillary alloy material, based on analyses of the produced fluid and gas constituents. Also, mirroring gas lift chemical qualification, treatment programs should only use chemicals designated “capillary-qualified” through lab and field testing.
In addition to injecting chemicals for treating paraffin, corrosion and scale, injecting a gas lift flow improver (GLFI) as part of a qualified chemical program can enhance system performance and increase well productivity. As with production chemicals, GLFIs should be qualified for the particular gas lift application.
GLFIs are foaming surfactants added to the lift gas, along with production chemicals. They are formulated with a unique chemical composition that generates a stable foam in the presence of oil and disperses gas in a continuous liquid phase. The foam reduces hydrostatic head pressure, fluid density, and bottomhole pressure and alters the gas-liquid interface to increase the lifting force of the gas while lowering the critical velocity needed to carry fluids to the surface.
SUCCESSFUL PREVENTION AND REMEDIATION
In a recent project in the Delaware basin, an operator was experiencing steep natural production declines, high water cuts, and slugging on gas lift wells. They were employing multiple chemical products for paraffin control, using batch applications for rod pump wells and continuous applications for gas lift and surface operations. Infrastructure constraints and the cost associated with buying back additional gas volumes limited the ability to increase injection into each well. Paraffin typically deposits on the rods and tubing of wells, and if not sufficiently controlled, can cause sales oil to be off specification. To mitigate these paraffin issues, the operator had been combining hot oiling with chemical injections. This necessitated hot oiling operations on every well 1-2 times per quarter, leading to significant cost expenditures.
ChampionX evaluated newly developed paraffin products to reduce the number of chemicals and the frequency of remediation. As an alternative to increasing injection rates in the high water-cut wells, the operator elected to field-test a gas lift flow improver (GLFI) program on multiple wells in the field. This was deployed alongside chemicals for treating paraffin, corrosion and scale, to improve system performance and increase productivity, while keeping in line with the operator’s KPIs. A pilot program was proposed to address rod pump wells experiencing severe paraffin issues and requiring frequent hot oiling treatments. Following the initial trial, the customer suggested expanding the program to other wells in the area, including gas lift wells, gas lift-assisted plunger wells, and rod pumps with paraffin problems, Fig. 2.
Field bottle tests were conducted to compare the newly developed paraffin dispersant to the incumbent product in various doses, to assess emulsion tendency and water clarity. Results showed that the chemicals provided a sharper interface, no emulsion formation, and cleaner water. This indicated that a switch would be advantageous in both batch and continuous surface and gas lift treatments.
A significant production increase was observed for most of the trial wells. An added benefit was decreased slugging on wells where bottomhole pressures exceeded bubble point pressures. Table 1 summarizes the field trial results for seven wells, for which data were available. The application of GLFI resulted in a 30% average increase in total fluid production, ranging between 25 bpd and 137 bpd. To confirm that GLFI injection was responsible for the positive production responses, the GLFI was turned off on one well. The result was a sharp decrease in total fluid output. When GLFI injection was turned back on, production again increased. Using a GLFI provided the operator with a 50% reduced dosage, eliminated the need for hot oiling, enhanced system performance and increased productivity.
As these field results show, when integrated as part of a cross-functional solution encompassing the downhole tool design, the chemical delivery method, and automated gas injection rate controls, chemical packages qualified for the job at hand can help operators get the most out of their wells while ensuring long-term gas lift system operation.
REFERENCES
- https://netl.doe.gov/sites/default/files/2020-12/Benefits-DOE-Tight-Oil-R%26D.pdf
- https://www.researchgate.net/publication/346623273_Surfactant-EOR_in_tight_oil_reservoirs_Current_status_and_a_systematic_surfactant_screening_method_with_field
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