After several years of market fluctuations and design iterations, Centrilift, a division of Baker Hughes, has developed Thermo-Coil, an entirely new technology to de-liquify natural gas wells and substantially boost production.

In the late 1990s, the company had developed a heater cable designed for deployment in oil wells to prevent pipes freezing in the permafrost of Alaska. The cable was very effective in this application, but the service company’s engineers, in conjunction with an operator, realized natural gas well deliquification was potentially an entirely new market for heater cable.
The Thermo-Coil system inhibits liquid loading in gas wells, allowing operators to increase production and overall recoverable reserves. (Graphic courtesy of Baker Hughes Centrilift)
As natural gas reservoirs begin to deplete, a process known as liquid loading negatively impacts production. Water enters the well bore in vapor form at high bottomhole temperatures and low bottomhole pressure. As this “wet gas” moves up the production tubing, it cools, and liquid water droplets condense within the flow stream. It has been generally accepted in the industry that as long as the velocity of flow steam is above the “critical velocity” required to lift these water droplets, they will be carried out of the well along with the production gas. However, as the well begins to deplete, bottomhole temperatures and pressures fall, causing liquids to accumulate in the well and eventually resulting in complete loss of production.

Company experts began looking into the basic idea of heating the production tubing to prevent water condensation in gas wells based on the success of heating hydrates in Alaska. A patent search revealed that this concept had been disclosed in the 1960s, but the method proposed at that time was inefficient and not particularly practical.

To test the concept of heating the gas stream above the water dew point to keep the liquids in a vapor state, in 2001 the service company mounted the three-conductor, flat-resistive heater cable to the outside of the production tubing in a well in East Texas. The results were encouraging. The test demonstrated a 500 Mcf/d increase in production, a 600% gain, while extending the overall life of the well by nearly 5 years.

However, several design and economic issues were also identified during the field test. Installing the cable to the outside of the production tubing required shutting in the well with heavy kill fluids. This presents a risk that the well may not recover. Plus, strapping the cable to the production tubing was time-consuming. It took 3 days to complete the installation, which drove up the overall costs. With gas prices dropping below US $2.00/Mcf, at the time and the necessary power requirement for the heater cable, the economics were not justified.

Rebounding gas prices re-invigorated the project in 2004 when the first iteration of Thermo-Coil was produced. Based on those earlier tests, design engineers determined that encasing the cable conductors in 3¼4-in. coiled tubing (CT) would allow for live well deployment — eliminating the risk associated with killing the well, dramatically lowering the installation time and reducing energy loss to the formation. Higher gas prices and the design solutions incorporated in the technology concept once again attracted the service company’s industry partner.

The operator had a field with relatively high production rates and gas flow rates above critical velocity, which led their production engineers to conclude that water in the bottom of the well was impeding production. The solution appeared to be a typical electrical submersible pumping (ESP) system. A service company analyst, however, felt condensing liquids suspended in the flow stream all along the length of the production tubing and causing excessive pressure drop was the likely culprit of declining production, and he convinced the operator to lower a downhole video camera into a well to determine exactly what conditions were present.

The video clearly showed significant amounts of liquid suspended in the production tubing in the form of water slugs, proving that flow rates well above critical velocity can be insufficient to produce liquids from a well.

This discovery meant that the service company’s technology was ideal for higher volume, deeper gas wells, which in the past had very few options to enhance production. Plunger systems, the most prevalent gas well deliquification method, are limited by low bottomhole pressure, well depth and the amount of liquid in the production tubing. In addition to extending the well depth limits by preventing liquid accumulation along the production tubing, the heating system allows a well to operate at significantly lower bottomhole pressure, which increases production rates and extends the life of the well.

The market for the technology is essentially wells deeper than 8,000 ft (2,440 m) with production of about 1 MMcf/d of gas or greater, bottomhole pressure of less than 150 psi and a demonstrated production decline on depletion drive.

The heating system heats the well 80°F to 100°F (27°C to 38°C) above the temperature profile of the well — just enough to keep liquids in a vapor form and increase the solubility of the liquids, allowing the gas to carry the liquids out of the well. The element is composed
of three conductors encased in special high-temperature insulation. CT is laser welded around the cable conductors, and it is this welding process that presented the biggest challenges to product development. Over about an 11-month period and after several design iterations, service company engineers determined the best metallurgy composition for the coiled tubing and developed a patented manufacturing process for welding the CT. In addition to the manufacturing process, Centrilift holds patents on the live well deployment system and the heater cable itself.

Several field tests of the new design were conducted, and these tests documented incremental gas production increases of 465%, 660% and 850%. However, additional lessons learned during these field trials have led to further system refinements.

The company found in one of the field tests that the chemical composition of the liquids in the well can have a detrimental impact on the coiled tubing covering the cable. H2S, CO2, chlorides and other chemicals in the liquids can corrode the coiled tubing, so the company had to develop some way to protect the heating system from these harmful elements.

The system now addresses that issue by running the coil inside a separate CT string and filling the space with oil for excellent heat transfer. This configuration provides two advantages. The operator can now monitor the oil level in the system and, should a leak occur, an on-site team can pull the cable and proactively service the system. Secondly, chemicals in the wellbore liquids are no longer an issue since the outer CT can be constructed of alloys designed to withstand the chemicals.

Of course, the downhole cable is only one part of the system. Equally important to the success of the technology is the application software. Heat transfer in a gas well environment is complex with conduction, convection, radiation, time, flow rate and the thermophysical properties of the gas and formation all interacting and interdependent. The thermophysical properties of the gas are also dependent on the composition of the gas as well as temperatures and pressures, which change along the well depth and cross section. The electrical properties of the coil system are dependent on its operating temperature, which also varies along its deployed length.

The service company team developed computer software that accurately models the well environment, analyzes the heat transfer and establishes the electrical power requirements. Surface control systems were necessary to provide several controls and protections, including voltage control, current limit, disconnect, lightning protection, safety shutdowns, ground fault and remote monitoring.

These issues are addressed with the service company’s Electrospeed II variable speed drives (VSDs). The VSD provides control of the downhole system, allowing for adjustments for well conditions and power issues. The VSD as well as an internal fault system provide system protection from lightning strikes. An additional fault system is built into the system in the event the cable would ever short to the outer metal. The company can also install its espGlobal monitoring technology on the system to provide operators with real-time remote monitoring capabilities.

The heating system has been installed in several wells in Texas, resulting in significant production increases. For example, one well was experiencing a significant production drop due to declining bottomhole pressure and liquid loading. The 10,000-ft (3,050-m) well was nearing abandonment pressure and with available gas lift technology was unable to maintain flow.

The service company and the operator conducted a flowing pressure survey that clearly showed the pressure drop in the well bore was due to condensing fluids. The heating system was installed, and production increased from 200 Mcf/d to 1.9 MMcf/d. The system also has extended the life of the well by lowering the bottomhole pressure necessary for production using this technology.