Methane gas may be produced in the mining of coal. Coal formations naturally produce methane gas. For example, methane gas may be produced by dewatering activities of the mining process. Methane gas that is contained in the coal formation may be biogenic (generated by biologic organisms) or organic (generated by organic decomposition of coal) origin.
Recovery of the methane gas present in coal formations is a major source of methane gas for the modern coal bed methane (CBM) industry. The recovery of such methane gas from coal formations frequently involves the removal of water from the coal bed, so as, for example, to provide a reduction of pressure within the formation. The water may often be found within the coals and typically may be under pressure that increases with depth below the surface. Methane gas can be contained in the formation, for example in solution with the formation water (either free flowing or interstitially within the rock) or adsorbing to the surface of the rock. In mining operations, it may be necessary to remove the water prior to collecting the ore. The removal of water may liberate the methane from the water or the formation by reducing the pressure under which the water is found.
In well operations, it may be necessary to pump water from the coal aquifer when the well is completed for a coal bed methane well to produce gas. Although other factors, including formation characteristics, well drilling methods, and pumping rates may play a role in production, it may be that the removal of water is possibly the most important well production factor. Traditional techniques to remove water from the well bore may include the use of a submersible pump. The pump may be placed at a depth to maximize gas flow.
The process of obtaining the maximum gas flow is often referred to as well optimization and may involve many factors. Well optimization may occur when the intake of the pump is set at a depth in the well to allow the maximum gas to be produced. If the intake is set too high in the well, water from the formation may not be sufficiently produced. In some instances, the weight of the water with reference to static water level (SWL) may prohibit the gas from desorbing from the coal and water. If the intake is set too low, water from the formation may not be sufficiently produced and the water may no longer float the coal fractures (keeping them open), possibly negatively affecting gas desorption or possibly inhibiting the flow of gas out of the coal seam. The pumping rate of the water may be used to fine tune the static water level in the well bore and may be tied to many geologic factors. Water production rates may vary from 1 gallon per minute to several hundred gallons per minute, again depending possibly on geologic conditions such as coal permeability and the thickness of the coal itself
Produced water of coal bed methane production may be discharged to the land's surface, possibly along ephemeral drainages, tributaries and reservoirs. The quality of the produced water may vary from better than some bottled waters to poor, possibly depending on proximity of the coal bed methane well to the coal aquifer recharge area. Water qualities of coal bed methane wells in some regions typically may be better than the shallow aquifer systems that may often be used by agricultural concerns for purposes such as stock watering. However, water quality problems may occur after the water reaches the surface and travels for any distance. Surface soils may often contain salts (cations and anions) which the water may possibly dissolve as it moves along through these surface soils. At some point in the drainage, these salts may begin to accumulate, thus possibly reducing the discharged water quality. This issue may heretofore have been the subject of many studies exploring how this process may occur and the amount of time and distance over which this effect may become apparent.
The discharged water may become impaired because the discharged water may acquire salts along its path to tributaries. This impaired water may ultimately commingle with unimpaired water and may eventually degrade the fresh water supply. In an effort to monitor the amount of impaired water entering the fresh water system, governmental agencies have developed regulatory rules such as requirements for coal bed methane producers, for example permit requirements. One such permit requirement involves acquiring a National Pollution Discharge Elimination System (NPDES) permit. However, the NPDES permit acquisition process may involve significant drawbacks for coal bed methane producers, including the possibility of a substantial time and financial investment for the producer in obtaining the permit and the possibility of a denial of the permit.
In addition, environmental interests have expressed the concern that coal bed methane industry practices waste limited fresh groundwater resources. It is typically suggested that water produced by coal bed methane processes should be re-injected back into the ground. However, traditional re-injection methods may not have been economically viable to re-inject a high volume of produced water from a large number of wells. The drilling costs of each well may detract from economic viability of traditional re-injection methods. Furthermore, some formations may already contain a substantial amount of water, thus requiring large pump pressures to exceed the fracture rate of these formations in order to inject the additional waters. Traditional re-injection methods, furthermore, may be cost prohibitive given surface equipment and processes required.
Attempts may have been made to re-inject produced water into a principal drinking water aquifer where aquifer capacity may be available from a number of supply wells. However, facility and treatment costs may be prohibitively expensive. Other traditional re-injection techniques involve drilling an additional well or wells near an existing coal bed methane well for re-injection into a shallow aquifer system, but again these attempts may not have been economically viable due to the added costs of the additional wells as well as equipment and pumping costs to reinject the water back into the formations. Yet other attempts have involved using the produced water for irrigation, but the expenses involved in irrigation (for example, the capital outlay for an irrigation system and the treatment of soils to prevent souring) may have been so high as to be economically unsustainable. Still attempts may have involved the use of large leach-fields to dispose of water, but it may have been that relatively low permeability soils such as tight clay soils hindered the percolation process.
Other water removal attempts have been made in the context of brine water produced from conventional oil and gas reservoirs. For example, U.S. Pat. No. 3,363,692 discloses the use of a conventional beam pump or possibly pressure from the formation itself to move brine water mechanically into a shallower brine formation. However, this technique may be dependent on certain pressure ranges to work properly and may perhaps require a time cycle controller to switch a valve when water reaches a set height or time. Another patent, U.S. Pat. No. 5,816,326, discloses the use of a conventional beam pump to move brine water mechanically into a brine formation. This technique, however, appears to require the use of two mandrels to isolate perforations adjacent to a porous formation and perforated tubing to allow brine water to exit the tubing string.
The technologies of the above referenced patents and other similar technologies may also be limited in application to brine water disposal for oil and gas reservoirs and not particularly addressing the complexities of redistribution of fresh water into a fresh water system or the corresponding environment. Furthermore, the complexities associated generally with oil and gas reservoirs and traditional production equipment may actually lead those in the field away from thoughts of more efficient and less mechanically complex techniques, and particularly given the differences in the production environment.
It may be that previous attempts have been made to avoid the possible need of obtaining an NPDES permit for discharging water to the ground surface. It may also be that use of re-injection, irrigation and percolation may allow for different permitting requirements less stringent than, for example, the NPDES permit. Accordingly, a need may exist to avoid the NPDES permit system altogether, thus possibly streamlining the permit procedure and potentially reducing costs.
Water may also have a role in the secondary and tertiary recovery of oil and gas. Secondary and tertiary recovery is the recovery of oil or gas, or combinations thereof, in production-depleted reservoirs exhibiting low pressure or low flow rates, such that production is not economical or too much gas or water is present. The formation pressure, volume of product, product displacement, or fluid flow may be reduced for various reasons. In some optimal oil fields, it may sometimes be estimated that approximately 30 percent of the oil may be removed by pumping the wells (primary recovery), thus leaving perhaps 70 percent of the oil as unrecoverable. Secondary recovery, including traditional lift systems and injection methods, is typically implemented to maintain pressure and sustain production at viable rates.
Tertiary recovery or enhanced recovery alters the original oil properties and further maintains formation pressure and may be able to increase production by perhaps about 15% percent. Tertiary recovery may comprise techniques such as chemical or water flooding, miscible displacement, and thermal recovery. Examples include forms such as water flood, nitrogen flood, fire flood and steam flood. Each such technique may be reservoir dependent, and often the choice of technique may be based upon economics and availability. For example, if there is no readily available source of CO2 near the production facility (miscible displacement), it may be that a CO2 flood may not be economically viable.
Water injection and water flooding may be common forms of secondary and tertiary recovery, perhaps due to the typical availability of large quantities of water during production. Water may be acquired perhaps by drilling a water supply well or possibly by using by-product water from existing operations. This water may typically need to be treated, perhaps by chlorination, to some standard prior to being re-injected. Injection wells may often be other existing wells, perhaps which may have diminishing production or possibly which may be optimally located for the flooding operation. However, sometimes new wells may be drilled in an area to serve solely as injection wells.
The principal in traditional water flooding may be to move the oil or other recoverable substance that may be contained within a reservoir formation to the pumping bore of a production well and to maintain formation pressure. To accomplish this technique, water may be pumped into the reservoir formation, perhaps so as to displace the trapped oil or other recoverable substance and possibly to move it towards a production well. The amount of pressure involved in driving the water within the reservoir formation may be highly variable. Such pressure may rely primarily on the transmissivity of the reservoir formation. Such pressure also may be influenced by the casing size of the well bore and the number and type of perforations made in the casing. Water flooding may typically require surface facilities such as one or more storage tanks (tank batteries), treatment facilities, pumping equipment and pipelines to be constructed. Such surface facilities may ultimately increase the operating cost of the field, perhaps reducing the economic viability of the operation.
The foregoing problems regarding conventional techniques represent a long-felt need for an effective solution. Actual attempts to meet the need to dispose or treat produced water may have been lacking in one or more aspects, for example as previously described. Those skilled in the art may not have fully appreciated the nature of the problems and challenges involved. As a result, attempts to meet these needs may not have effectively solved one or more of the problems or challenges here identified. These attempts may even have taught practices diverging from the technical directions taken in the present invention. The present invention could be considered an unexpected result of new approaches to conventional techniques that have been taken by some in the field.
USPTO Backgrounds
USPTO Backgrounds