Ultimate recovery from unconventional reservoirs still has a long way to come. Unconventional reservoirs are described as wells produced in low permeability (tight) formations composed as tight sands, carbonates, coal, and shale. Although tight gas and coal bed natural gas are valuable sources of energy, wells produced from low permeability shale formations (shale gas) promise over 1,744 trillion cubic feet (tcf) of recoverable gas, which comprises the majority of unconventional oil and gas reserves. Shale is a sedimentary rock comprised of consolidated clay-sized particles. These are deposited as mud along with organic matter such as plants, animal remains, and the like. The end result is a rock formation with a permeability of 0.01-0.00001 millidarcies. In its natural state, this permeability prevents the migration of oil and gas within the formation over periods less than geologic expanses of time, and was initially thought to be uneconomical to produce. With the advancement of horizontal drilling and multistage hydraulic fracturing in the late 1990s, shale oil and gas reservoirs became economical to produce.
As compared to conventional oil wells, many shale gas wells are characterized by a higher gas-oil ratio (GOR). Although there are some benefits to producing high GOR wells, there are also some drawbacks. In shale gas, the migration of oil through the rock fractures is primarily due to Poiseuille flow of the shale gas, i.e. pressure-driven flow of gas carries the oil when equalizing pressure. The pressure driving this flow is due to the natural pressure gradient that is created by “uncorking” the well at the surface, causing the less dense gas to evacuate the reservoir and rise up the well bore. When this process carries substantial liquid condensates, the specific gravity of the mixture in the well-bore creates a fluid column that pushes back on the reservoir; thus, we can define the bottom-hole flowing pressure (BHFP) as the pressure at the bottom of a flowing well, and the flowing tubing head pressure (FTHP) as the pressure at the surface of a flowing well.
While gas gathering systems at the surface often operate at 40-100 psi, wellhead compression can be employed to reduce this FTHP, also improving the minimum BHFP and ultimately reducing well abandonment pressure resulting in higher recovery and increased reserves. At the surface, a facility can at most draw down the well by pulling a vacuum from atmospheric pressure. While this technology can help reduce the abandonment pressure, the hydrostatic pressure gradient in the tubing is still tied to the specific gravity of the fluid in the tubing, and can only be altered moderately by well-head compression. Low gas pressures, temperatures, and velocities in the tubing will result in liquid dropout in the tubing, which can become suspended in the tubing. This liquid loading impedes production from the well and impact its economic viability, resulting in abandonment. Ultimately, the abandonment pressure depends greatly on GOR, water production, well depth, etc. and is likely several hundred psi.
In many cases, the specific gravity of the fluid in the tubing is decreased by implementing artificial gas lift. Artificial lift describes the process of compressing dry gas and inserting it into the annulus. The dry gas passes down the annulus and mixes with the oil in the production zone of the tubing. This reduces the density of the fluid in the tubing, thus decreasing the BHFP. This process requires access to gas, surface power and compression equipment, and can be quite costly. Ultimately, this process is quite effective, and is often economical for wells whose production has been impeded by poor natural tubing flow.
Another option that has been proposed to attain better control of high GOR production is downhole gas compression. This concept is not new but its application to unconventional oil-and-gas is still in the early stages of development. While promising, continued development of this technology is likely required for successful implementation in the field. Potential issues with a downhole application include multiple challenges associated with multiphase compression (variability in performance, reliability, and mechanical loads), low specific load capacity of magnetic bearings, changing aerodynamic requirements from reservoir maturation, overall system complexity and cost, and autonomous tool installation.
Various figures are included herein which illustrate aspects of embodiments of the disclosed inventions.
In a first embodiment, referring generally to
Housing 10 is further typically configured to be deployable within a 4.5 inch casing but the casing can be as small as around 3.5 inches or larger than 4.5 inches.
Referring additionally to
In embodiments aerodynamically designed, gas-bearing supported, multi-stage centrifugal compressor 11 comprises turbine 20 which may comprise a hybrid gas turbine comprising a heat transfer technology optimized for high cycle efficiency of recuperation, intercooling, or turbine blade cooling over a range of operating conditions typical of a load following demand at a compressor station.
In embodiments, compressor 11 is configured to be powered with a turbo charger which may be powered with a high-pressure gas source.
In certain embodiments, referring additionally to
Referring additionally to
High speed electric motor 21 may comprise a plurality of 2-pole motors arranged in series.
Referring back to
In the operation of exemplary methods, referring back to
In embodiments, electric submersible pump (ESP) 30 may be present or otherwise deployed in hydrocarbon well 100 and operatively connected to high-speed downhole motor-driven artificial-lift gas compressor 11. Once connected, ESP 30 may then be used to aid with recovery of hydrocarbons from hydrocarbon well 100.
In certain embodiments, high-speed downhole motor-driven artificial-lift gas compressor 11 may be reconfigured with one or more gas and water separators 32,33. In these embodiments, electric submersible pump (ESP) 30 may be deployed and used to inject water downhole into a water zone or waterflood zones to increase production and reserves. This can result in very little water being produced to the surface requiring water disposal. For areas where gas sales are not available, ESP 30 may be used to inject both water and gas downhole, which may reduce a need for surface water handling and disposal and gas injection.
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The foregoing disclosure and description of the inventions are illustrative and explanatory. Various changes in the size, shape, and materials, as well as in the details of the illustrative construction and/or an illustrative method may be made without departing from the spirit of the invention.
This application claims priority through U.S. Provisional Application 62/827,683 filed on Apr. 1, 2019.
Number | Date | Country | |
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62827683 | Apr 2019 | US |