In an unconventional gas well, the reservoir is hydraulically fractured and can be as far as 25,000 ft. from the wellhead. Gas production in unconventional wells declines much faster than that of conventional wells in the initial production years.
Our Upwing Subsurface Compressor Systems™ (SCS) are the only method of artificial lift that can increase gas, condensate, and natural gas liquids production from unconventional wells by dramatically increasing the drawdowns in the wellbore. The higher kinetic energy and fluid velocity at the intake of the compressor will eliminate liquid loading in the horizontal sections of a multi-stage fractured well. While the higher kinetic energy (pressure and velocity) and added thermal energy at the discharge of the compressor will avoid liquid loading and condensation in the vertical section of the well. The lowered downhole flowing pressure and efficient liquid unloading will enable operators to improve recoverable reserves, extend the life of gas wells, and fundamentally change the methodology of producing unconventional resources, significantly improving economics.
Liquid-Rich Shale Gas
Shale gas is natural gas that is trapped in shale formations, which are primarily comprised of fine-grained sedimentary rocks dominated by shales. Natural gas produced from shale is often referred to as “unconventional,” which refers to the reservoir in which it is found. Unconventional reservoirs are laterally continuous and regionally extensive hydrocarbon accumulations without an apparent seal or trap and often extend beyond the spill point of conventional structures.
Currently, the production of gas from unconventional resources has surpassed the production from conventional fields in the United States. Approximately 67% of the gas reserves identified in the United States are in unconventional reservoirs. However, the estimated ultimate recovery of the original gas in place is only around 15 to 20%. In addition, the production of unconventional horizontal and multi-staged fractured wells is known to drop by 75% to 90% in the first few years of the life of the well. Liquid loading in the horizontal sections of the well and condensate banking in the reservoir have been identified as the two major causes of declining production rates and limited ultimate recovery.
Upwing’s SCS can uniquely provide solutions to the combined issues of liquids in the horizontal sections of the well and liquids in the formation. Operation of the SCS in a gas well creates a low-pressure zone at the compressor inlet at the bottom of the wellbore, thus lowering the bottom hole well pressure. This drawdown in the wellbore actively induces more gas flow from the formation to the wellbore. With higher gas flow rates and lower bottom hole flowing pressures, the increase in the velocity of the gas stream carries more liquids out of the wellbore, thus removing liquids from the vertical and horizontal sections of the well.
Upwing’s SCS has demonstrated that it can lower bottom hole pressures well below current abandonment pressures; this will increase the gas velocity to ensure there is no liquid loading in the horizontals, increase the positive coupling effects within the reservoir and overcome the capillary effects that are causing blockages within the formation.
Coalbed methane reservoirs are continuous unconventional hydrocarbon accumulations that contain gas entrapped by adsorption on organic macerals in coal seams. In some accumulations, a portion of the coalbed methane is stored as free gas in micropores and fractures or as solution gas in groundwater. Coalbed methane traps are regional in scale and contain giant, in place hydrocarbon volumes.
Coalbed methane reservoirs behave as dual porosity systems that have different gas storage and flow characteristics, partially dependent on varying geological parameters. Gas storage occurs by sorption, compression and solution, and mass transfer is driven by both concentration and pressure gradients. The critical desorption pressure is used to determine the amount of drawdown that is required before gas can be produced from the reservoir.
In coalbed methane reservoirs, downhole compression increases well flow potential by increasing drawdown close to the perforations like in conventional formations. However, to maximize coalbed methane production, the non-linear relationship between pressure and molar concentration of adsorbed gas must be realized. Because of that nonlinearity, any incremental pressure decrease will result in desorption of significantly more gas than is released directly from the open pore space. Since downhole compression creates suction close to the reservoir, Upwing’s Subsurface Compressor System™ is the only technology that provides the lowest bottom hole flowing pressure for a given tubing head pressure.
Moreover, production of natural gas from coalbed methane reservoirs, particularly at lower reservoir pressures, causes the rock matrix to shrink with reservoir depletion, thus increasing average reservoir permeability with time. As a result, any additional reduction in bottom hole flowing pressure will extend the distance to which the drawdown can be transmitted. With larger and farther drawdown, gas production will increase and stabilize, therefore enlarging the size of the proven undeveloped reserves.
Coalbed methane desorption behavior has a major impact on ultimate hydrocarbon recovery. Absorbed gas has much greater density than associated free gas, and the volume of gas stored on the surface area is much larger than accommodated in the open pore space. Coalbed methane recovery is, therefore, primarily the recovery of desorbing gas (i.e. lowering reservoir pressure reduces molecular bonds to organics and transfers adsorbed gas into the fracture system). Therefore, the highest gas recovery from coalbed methane reservoirs can only be realized by reducing reservoir pressure to the lowest possible level. Downhole compression with Upwing’s SCS facilitates the lowest reservoir abandonment pressure, thus maximizing recoverable reserves.