Production Gain

In conventional reservoirs, downhole compression increases gas production by increasing drawdown close to the perforations. Effective drawdown is accompanied by higher mass flow rate from the reservoir. Larger mass flow rates can only be achieved by downhole compression, where the gas is denser due to the downhole pressure. Furthermore, increasing suction pressure close to the perforation without the pipe friction loss associated with surface compression will result in even higher drawdown on the formation.

Another benefit of the SCS is the higher gas velocity due to suction. A small increase in pressure drop by suction will significantly change the velocity of the gas and the ability to lift liquids. At lower reservoir pressure and rates, a small diameter tubing is usually required for the efficient removal of produced liquids, however the higher friction loss associated with this tubing compromises its benefits. Upwing’s SCS produces gas at its maximum well flow potential by compressing the gas near the reservoir and without the increased frictional losses that result from the smaller tubing.

Liquid Loading Mitigation

The SCS mitigates the issue of liquid loading in gas wells by increasing gas velocity at the compressor intake and by adding thermal energy to the streams at the compressor discharge. The improved liquid lift efficiency will increase the gas and condensate production rates on the surface. In the meantime, higher liquid sweeping also removes the liquid blockage of gas flows. The increased thermal energy of the compressed gas stream prevents water condensation and paraffin deposition, particularly in condensate rich formations. In gas wells with low reservoir pressure and without active aquifer presence, it is feasible to rely on the thermal energy from compression to deliquefy such wells.

Moreover, as the reservoir pressure is reduced as it matures, gas at lower pressures can hold significantly more water vapor. The net effect of producing wells at lower bottom hole pressures by the SCS could result in lower residual water saturation near the wellbore and eliminate any water invading and blocking the pores of the gas-producing formation rocks.

Reservoir Recoverability

The Upwing Subsurface Compression System™ aids in the delivery of proven developed reserves and increases the size of undeveloped reserves by providing lower abandonment pressure that enhances hydrocarbon recovery significantly. In parametric studies conducted, the SCS increased recoverable reserves by 20 to 70+%.

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 rich 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%. 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 has demonstrated deliquification of the horizontal sections of an unconventional shale well. 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.

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Coalbed Methane

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 higher gas 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 reservoir recoverability.