An innovative gas processor combines multiple technologies into a single unit to increase the gas handling efficiency of ESPs in unconventional wells.
JAMES RHYS-DAVIES and JESSICA STUMP, NOV
Producing multi-phase fluids using artificial lift is challenging, and pumps are designed to operate with high liquid fractions. However, high gas-liquid ratios (GLR) create a harsh environment for artificial lift, leading to pump inefficiencies and downtime.
Unconventional wells present an additional complication for high GLR operations. Steep production decline curves and various horizontal wellbore geometries result in transient production modes. The swift decline in bottomhole pressure in unconventional wells causes them to drop below the bubblepoint (the pressure at which gas starts to separate from the liquid) within six to 18 months of initial production. Moreover, the nature of horizontal drilling, with features like undulations, toe-up and toe-down configurations, causes production to fluctuate from high liquid ratios to high gas ratios.
Gas interference is one of the most costly and time-consuming challenges in unconventional ESP applications. The root of gas interference problems lies in the inherent characteristics of many unconventional wells. These plays often exhibit high GLR, with associated free gas volumes that can overwhelm traditional separation and handling equipment. This gas dominance can prevent operators from reducing pump intake pressure (PIP)—a critical parameter for optimizing artificial lift systems and maximizing production.
Addressing these challenges and maximizing production from unconventional wells with ESPs amidst declining reservoir pressure and increasing GLRs requires a paradigm shift in artificial lift technology. A new gas processing system has been developed to enhance the gas handling capabilities of traditional ESPs, thereby increasing uptime, production and drawdown.
GAS PROCESSING EVOLUTION
Advances in gas handling technologies for ESPs include equipment such as gas separators, vortex gas separators and gas handling pump stages. These technologies help the well continue producing fluid, as well as prevent ESP shutdowns, due to gas interference. Their purpose is to separate and compress the gas before it enters the main production pump.
A typical centrifugal ESP installation in an unconventional well consists of, from top to bottom: production pumps, a gas handler, one or two gas separators, protectors/seals, motors and a sensor. Fluid enters the gas separator, where the liquid and gas are separated. The gas handling pump further compresses any remaining gas in the fluid to reduce the gas void fraction (GVF) entering the production pumps, Fig. 1.
Traditional centrifugal ESP pump stages consist of rotating impellers and stationary diffusers, stacked to increase pressure incrementally. As the centrifugal impeller spins, it forces all the heavy liquid outward, while the lighter gas stays near the center of the impeller. This separation can result in gas becoming trapped, or locked, within the pump. Gas locking disrupts fluid flow, significantly reducing the efficiency and reliability of the ESP. This condition not only risks operational shutdowns, but it also threatens equipment integrity, due to mechanical wear and the potential overheating of the motor.
ENHANCING GAS HANDLING
NOV’s Artificial Lift Systems developed the Integrated Gas Processor (IGP) to improve the gas management of an ESP system and minimize production downtime. This multi-module gas processing system replaces the gas handling pump and gas separators, combining multiple technologies into a single unit to increase gas handling efficiency, Fig. 2. A patented, flangeless threaded connection system connects the three modules to form one monolithic unit. These flangeless connections reduce pinch points that can restrict flow and cause pressure drops within the system.
The IGP operates differently from traditional gas handling equipment. Fluid enters a high-volume flow intake and goes into the lower module, where proprietary Contra-Helical Pump (CHP) stages compress and condition (homogenize) the gas and liquid. Unlike a traditional centrifugal pump, the CHP provides two flow paths that allow gas to flow into both the rotor and stator. The primary flow path is the helical flow, while the secondary flow path is the fluid vortex, generated within the rotor and the stator vanes. As a result, the CHP can ingest and condition a higher amount of gas as it moves through the pump. Moreover, conditioning the gas provides buoyancy to the production fluid, increasing overall lift efficiency.
Then, the more homogenized gas-liquid mixture enters the center module that features a dual-chambered gas separator, which is strategically positioned to reduce gas recirculation and enhance gas separation efficiency. An inducer rotates the fluid at high speed, causing the high-density liquid to move to the outer diameter, while the low-density gas concentrates toward the inside diameter. A crossover component diverts the free gas to the exit ports and out into the annulus of the well, between the IGP and casing wall, and directs the liquid into the next stage of separation. This process repeats in the second stage of separation, further reducing the GVF and directing the fluid into the upper module.
Typical gas separators have intake ports that are about 2 ft (0.6 m) below the gas exit ports. However, the IGP separates these ports by about 8 ft (2.4 m) to minimize the potential for gas recirculating into the system. Additionally, the length of the gas separator provides greater retention time, enabling it to remove the gas more efficiently, Fig. 3.
Finally, the fluid enters the upper module for further compression and conditioning, before moving into the primary production pump. Both CHP and centrifugal style stages are available for the upper module.
CASE STUDIES
Field studies of the IGP have yielded compelling results, showcasing its ability to outperform traditional ESP gas handling systems and gas lift methods in various challenging and harsh environments. Across the Permian basin, the IGP has consistently proven to be able to handle high gas content, reduce downtime, increase drawdown and enhance operational efficiency, resulting in substantial improvements in production and operating cash flow.
Oil production from a well in the Delaware basin had stagnated, with gas interference preventing the reduction of PIP. For this high GLR application, the operator required increased oil production and decreased PIP. After removing the competitor pumps, similar-sized NOV ESPs were installed, with an IGP instead of tandem gas separators and gas handlers.
The IGP exceeded the previous gas handling equipment, leading to a rapid rise in fluid production. Oil production rose 153%, from 136 bpd to 344 bpd, while gas production increased 224%, from 202 Mscfd to 654 Mscfd. Water production also increased 316%, from 417 bpd to 1,734 bpd, which led to a 14% reduction in the GLR, from 365 scf/bbl to 315 scf/bbl. Meanwhile, the PIP immediately dropped 11%, from 579 psi to 514 psi, Fig. 4.
Lower gas recirculation resulted in a significant increase in liquid production and a decrease in GLR. Consequently, the primary production pump operated more efficiently, enhancing overall performance by increasing uptime.
Another operator in the Delaware basin wanted to draw down their wells further and more efficiently. However, due to the amount of gas this Wolfcamp formation in New Mexico is known to produce, the operator was limited to gas lift systems. NOV’s Artificial Lift Systems incorporated the IGP into the ESP system, encountering up to 70% free gas at the intake and an average GLR of 2,700 scf/bbl.
The IGP outperformed the operator’s initial production target by 10%. As a result, the operator captured more than $500,000 in additional oil production over a six-month period. Moreover, the IGP outperformed the offset gas lift analog data by 35%. In comparison, the operator garnered $675,000 in additional oil production in a formation where most operators had given up on producing with an ESP. Instead, they would default to gas lift as the primary artificial lift method for this Wolfcamp Zone.
In addition, a well in the Bone Spring formation, in New Mexico’s Delaware basin, suffered many ESP failures throughout the year, resulting in numerous, costly gas-related shutdowns. Infrastructure constraints and the cost of changing meant gas lift was not viable. Once again, an ESP with an IGP proved that it could surpass standard gas-handling equipment used in conventional wells with low volume and high GLRs.
The new gas processing system handled high amounts of gas, impacting the well’s operational efficiency considerably and boosting cash flow. In addition to reducing downtime 32%, the system increased average production 50% to 600 bpd, captured $450,000 in additional oil production per month, and drew down the well by a further 20%.
Meanwhile, in the Midland basin, an operator needed a solution to produce its second and third-run ESPs in depleted Wolfcamp A & B applications. In this instance, the GLRs had increased to a level where standard ESP gas handling systems were ineffective.
For the study, three wells—with high gas content applications—were equipped with IGPs, and six wells used conventional ESP equipment, such as tandem gas separators and a gas handling pump. Due to the IGP’s ability to handle and separate high amounts of gas more efficiently and remain running longer, the three wells produced 50% more fluid, on average, at an incrementally lower intake pressure than the six wells with conventional ESP gas handling equipment. As a result, the system enabled the ESP pump equipment to last longer, enhancing reliability, minimizing shutdowns and lowering operational costs.
CONCLUSION
As global energy demand rises and lateral lengths increase, maximizing production from unconventional plays will require robust and advanced ESP technologies that can withstand harsher environments and increasingly higher GLRs.
More than 120 IGPs have been installed in unconventional wells across the U.S., tackling the persistent challenge of gas interference. By integrating critical gas handling functions into a single, modular and optimized system, the proven IGP is poised to drive a new era of enhanced production, as well as substantial improvements in operational safety, efficiency and reliability. WO
JAMES RHYS-DAVIES is technical director at NOV, where he supports business development and the growth of Artificial Lift Systems’ products globally. He has held various engineering and product development positions over the last 16 years, with a specialty in gas handling and sand handling ESP technologies.
JESSICA STUMP is a senior writer at NOV. She has written about the energy industry for more than 14 years. Ms. Stump has a journalism degree from Texas Tech University.