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Over the last three years, E&Ps have drilled five times more unconventional and tight gas wells than conventional wells, and about 85% of natural gas production in the U.S. comes from those wells. But emerging subsurface compression technology is causing production companies to rethink strategies for extracting natural gas.

This new artificial lift solution can overcome liquid loading issues and increase the production and recoverable reserves of both existing conventional and unconventional wells. This article examines the issues and technology and provides a detailed comparative analysis of drilling versus subsurface compression in terms of economics, return on investment (ROI) and environmental impacts. 

An analysis reveals the use of a subsurface compressor for artificial lift in an existing conventional well can provide 28% more gas and condensate than from a newly drilled and completed unconventional well within the initial 10 years of production at 4% of the capital costs and with 75% less emissions per scf of gas produced. Also, forestalling premature abandonment will delay the high capital costs of safely capping these aging conventional wells, ranging anywhere from $50,000 to $100,000 per well.

Interestingly, 96% of oil wells in the U.S. use artificial lift, and 50% of those wells employ electric submersible pumps (ESPs). Unlike oil wells, however, there has been no economically feasible artificial lift technology for natural gas wells until the recent introduction of dependable subsurface compressors.  

All gas wells are affected by liquid loading at one point or another, whether the liquid is condensate or water. The current methods to alleviate liquid loading, such as various types of pumps, can only remove the vertical liquid column in the wellbore to preserve the life of the well, but they do not stimulate more production. Wellhead compressors can also help to extend the life of a gas well, but they are not effective in every well and require high maintenance. Although, wellhead compressors provide volumetric flow, mass flow decreases and, in some cases, increase condensation in the wellbore. Velocity strings also can be effective, but only for a short amount of time. As the diameters of the string are decreased, the friction forces dominate and restrict the flow.

In contrast, new Subsurface Compressor System (SCS) technology increases gas production and recoverable reserves by decreasing bottomhole flowing pressure and causing higher reservoir drawdown. It also carries liquids to the surface by creating higher gas velocities throughout the vertical and horizontal wellbores and prevents vapor condensation by increasing the temperature of the gas when exiting the compressor.

An SCS is the only dynamically controlled downhole tool that can maximize gas and condensate production, recoverable reserves, gas-in-place recovery efficiency and liquid unloading at the same time. All of these benefits can be realized in any type of formation and wellbore geometry in both the onshore and offshore environments.

Subsurface Compressor System-Upwing Energy
This graphic shows a downhole high-speed SCS driven by a hermetically sealed permanent magnet motor. (Source: Upwing Energy).

Attractive alternative to drilling

Economically and environmentally, it makes more sense to increase the production and reserves of existing conventional wells through subsurface compression than to drill more unconventional wells. For comparison purposes, the analysis below is based on a wet unconventional shale well that will produce 3.2 Bcf within its initial 10-year life (not EUR) with a condensate yield of 30 bbl/MMscf. The example also includes a typical conventional well that was drilled in the early 2000s and is producing 574 Mscf/d of gas and 20 bbl/MMscf of condensates with the help of a wellhead compressor. It is important to note that these types of wells typically stop producing within days when the wellhead compressor is removed.  

Table 1 presents a comparison of a conventional well’s performance with and without an SCS. For this example, the well does not have a wellhead compressor when producing with the SCS. The analysis is based on the drawdown the SCS provides on the reservoir and the increase in the velocity of the gas that helps carry the liquids to the surface. The simulation results are based on previous trials conducted with the SCS and still being conducted in different regions and formations. For this example, the SCS requires 80 kW of power, and the well requires a workover operation.  

Current State

With SCS

Incremental Change (%)

Natural Gas Rate (Mscf/d)




Condensate Rate (bbl/d)




NGL Rate (bbl/d)




Abandonment Pressure (Psia)




Recovery Factor (%)




Table 1. The data display the current state and SCS implementation comparison for a conventional well in the Frio Formation/El Paistle Field in the Gulf Coast Basin. (Source: Upwing Energy)

Table 2 presents an analysis of 10 years of operation comparing the costs of installing the SCS into a conventional well producing for 20 years versus drilling and completing a new unconventional shale well. 




Unconventional Horizontal Shale Gas Well

Conventional Gas Well with SCS 


Initial Costs: Drilling/Completion





Initial Emissions due to Drilling and Completion

t CO2e




Total water utilized (drill and frack)





10-year production





CO2e /scf

g CO2e/scf




Cum. condensate production (10 y)





Total revenue (10 years) after royalties before taxes





All in costs over total production




Table 2. An unconventional horizontal shale gas well is compared to a conventional gas well with SCS. (Source: Upwing Energy) 

Table 2 notes:


U.S. Energy Information Administration, 2016 trends in U.S. Oil and Natural Gas Upstream costs, Marcellus Drilling News. SCS initial costs include the workover, wellhead modifications and ESP cable.


U.S. Department of Energy, Greenhouse Gas Emissions and Fuel Use within the Natural Gas Supply Chain. Kleinfelder West Inc., Air Emissions Inventory Estimate for a Representative Oil and Gas Well in the Western United States for the Bureau of Land Management. Environmental Science & Technology, Modeling the Relative GHG Emissions of Conventional and Shale Gas. Production. Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas industry, by US Environmental Protection Agency Climate Change Division.


API, Website. Center for Western Priorities, the process and impacts of oil and gas development in the West. Retrieved April 2021.


Ladlee & Karabin, Decline Curve Development, Geology and Production Practices. MPDI Journal, Production Patterns of Eagle Ford Shale Gas, Analysis Using 1,084 wells. 


Based on $2.70/mscf, $55/bbl for condensate, $22/bbl for NGL


All costs (initial F&D and operational) divided over 10 years of production for both cases.

Based on this analysis, the SCS can provide the following benefits:

  • Require 96% less capex;
  • Produce 28% more gas and condensate within the initial 10 years;
  • Generate 75% less emissions per scf of gas produced; and
  • Cost 62% less per scf produced.

When comparing the total costs (initial and operational) as well as CO2e emissions per scf produced within the initial 10 years, the results are very convincing toward utilizing artificial lift to increase production and recoverability from existing assets where significant capital has already been deployed and the historical performance of the well enables the performance with the SCS to be modeled with a high level of accuracy.  

It should be pointed out that the SCS can be equally impactful for unconventional horizontal shale wells based on trials that have taken place in the New Albany Shale formation. The SCS modeling capabilities for unconventional wells are still under development. 

Applying subsurface compression to the Gulf Coast Basin and beyond

If subsurface compression were applied to all of the existing wells in the Gulf Coast Basin, regardless of well type, 32,125 MMscf/d (162%) more natural gas could be produced and 77,212 Bcf (111%) more reserves gained with minimal cost and emissions, as shown in Table 3 and 4. Although the analysis for unconventional and tight gas is not discussed in detail in this article, the projections with SCS shown in the tables below do take into account specific modeling per formation type. 

Reserves (Bcf)

Current State

With SCS

Incremental Change









Tight Gas




Total Reserves




Table 3. Current state and SCS implementation reserves are compared for the entire Gulf Coast Basin. Current state data are from the IHS Database. (Source: Upwing Energy)

Production (MSCFD)

Current State

With SCS

Incremental Change









Tight Gas




Total Production




Table 4. Current state and SCS implementation production are compared for the entire Gulf Coast Basin. Current state data are from the IHS Database. (Source: Upwing Energy)

That is only for the Gulf Coast Basin, which represents approximately 18% of the total U.S. production and 14% of the total U.S. reserves. The SCS will be significantly more impactful for the natural gas industry when factoring in all the U.S. basins as well as the South American, Middle Eastern and Asian markets and offshore segments. Many of these conventional wells are already producing at significantly lower volumes due to liquid loading and do not have a sustainable solution. 


In the short term, subsurface compressors increase cash flow and generate an attractive ROI by increasing instantaneous gas production significantly (20% to 200%-plus). Long term, they increase the recoverable reserves 20% to 70%-plus by postponing abandonment and preventing liquid loading and formation damages like condensate banking by lowering downhole flowing pressure. By increasing the gas relative permeability and drainage area through the creation of higher gas velocities, subsurface compressors can reduce the number of unconventional wells drilled to minimize environmental footprints. For unconventional wells, in addition to reducing the number of wells drilled, the SCS eliminates the need for the refracturing or CO2 injection methods practiced today. 

This comparison highlights the need to obtain more from existing gas assets as economically as possible and is not intended to discourage existing activities in the unconventional segment. With new artificial lift technologies coming to the market, such as the SCS, along with the current economics and regulations, the industry will find a balance between drilling and exploiting existing assets.  

References available. Contact Ariana Hurtado at for more information.