US20150083407A1

US20150083407A1 - Method of removing wellbore fluid from well and water removal well

Info

Publication number: US20150083407A1
Application number: US14/495,515
Authority: US
Inventors: Bruce Harrison STORM
Original assignee: Shell Oil Co
Current assignee: Shell USA Inc
Priority date: 2013-09-25
Filing date: 2014-09-24
Publication date: 2015-03-26
Also published as: CA2864963A1; AU2014233548A1

Abstract

A method for removal of fluid from a subterranean formation is provided, the method including the steps of: providing a wellbore from the surface to within the formation: providing a pump in the wellbore capable of removing fluid from the wellbore to a surface location; establishing a pump performance function as pump curves; measuring at least one variable that establishes where the pump is operating on the pump curve; determining the differential pressure across the pump from the measured variable and the digital power and the flow rate; determining the suction side pressure from the differential pressure across the pump and the vertical height of the annular fluid column of the fluid column above the pump; determining the suction side fluid level from the suction side pressure and the fluid density.

Description

RELATED CASES

This application claims the benefit of U.S. Provisional Application No. 61/882,121, filed on Sep. 25, 2013, which is incorporated herein by reference.

BACKGROUND

The invention relates to a method of removing wellbore fluid from a wellbore and a wellbore for removing fluid from a formation. In particular, the present invention may be utilized to produce methane from coal bed methane seams by removal of water from the formation
Coal bed methane is typically produced by pumping water from a coal bed methane seam to reduce the hydrostatic pressure, and thereby permit methane adsorbed on the coal to be released. Typically the seams from which methane may be produced by this method are fairly shallow, at depths from three hundred to eight hundred meters. The wellbores provided to accomplish this are generally simple and inexpensive, but removal of water is a significant cost Generally, pumps are provided in ratholes that extend below the coal seam, and the pumps are operated until the liquid level in the wellbore is low. The pump is then shut down, and the liquid level is allowed to build. At some time the pump is turned on again to again lower the level of the water in the wellbore. Constantly starting up and shutting down the pump results in short lifes of the pumps, and having to operate with more than a minimal amount of water in the wellbore can reduce production of methane. Operators therefore attempt to optimize profits by allowing water levels to build for a time period, but not to an extent where excessive production is lost because of additional hydrostatic pressure being put on the coal.
U.S. Pat. No. 6,446,601 to Ocondi suggests a system for controlling the liquid level in a coal bed methane wellbore utilizing a variable speed electric driven submersible pump. Flow rates of pumped liquids and produced gas are monitored along with liquid level in the wellbore to control the speed of the variable speed pump, and to turn the pump on and off as necessary, to optimize production of gas from the wellbore. The system suggested by Ocondi requires a level measurement within the wellbore, and transmission of a level signal to the surface where that level measurement may be utilized in the control scheme. A large number of coal bed methane wells need to be provided for a commercial development, and therefore the cost of each well is important to the economics of the development. Elimination of the wellbore liquid level measurement and the equipment needed to transmit the signal from that sensor to the surface would help reduce the cost of the well and be a desirable improvement.

SUMMARY OF THE INVENTION

A method for removal of fluid from a subterranean formation is provided, the method comprising the steps of: providing a wellbore from the surface to within the formation: providing a pump in the wellbore capable of removing fluid from the wellbore to a surface location; establishing a pump performance function as pump curves; measuring at least one variable that establishes where the pump is operating on the pump curve; determining the differential pressure across the pump from the measured variable and the power; determining the suction side pressure from the differential pressure across the pump and the vertical height of the fluid column above the pump; determining the suction side fluid level from the suction side pressure and the fluid density.
The method of the present invention provides that a submersible pump can be controlled using variables that are readily measured at the surface, avoiding any requirement to measure a liquid level in the wellbore.
In one embodiment, the power being consumed by the pump is determined by measured current and optionally voltage, and the differential pressure across the pump is inferred based on pump performance data. Pump performance data could be digitized, or expressed as, for example, a polynomial so that the process could be automated and incorporeated into a continuous control scheme. A measured pressure at the surface for the suction side of the pump (normally the annulus) and the discharge side (liquid line at the well head) could then be used to determine the liquid level at the suction of the pump. In some embodiments of the present invention, the data used to control the liquid level, along with measured methane production, may be used to vary the liquid level to optimize the point to which the liquid level in the wellbore is controlled.
In another embodiment of the present invention, a variable speed pump may be utilized to avoid cycling the pump between running and being shut down, along with minimizing or avoiding energy loss across a control valve for the liquid discharge.
In another embodiment of the present invention, the differential pressure across the pump may be inferred from pump performance data and a measured flow rate of pumped liquids.

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 is an explanary drawing of a pump curve as head as a function of speed and power

FIG. 2 is a schematic drawing of the well of the present invention.

DETAILED DESCRIPTION

FIG. 1 is an exemplary pump curve figure. Line 1 shows a function of head in the vertical axis as a function of flow rate on the horizontal axis for a particular speed. Lines 2 through 4 show the same curves for progressively lower speeds. Line 10 shows pump horsepower on the vertical axis as a function of flow rate on the horizontal axis, again for one pump speed. Lines 11 through 13 show the same curves for progressively lower speeds. Line 20 shows system efficiency as a function of flow rate for one pump speed, and lines 21 through 23 show this function for progressively lower pump speeds. Curves like this are available for commercially available pumps from the manufactures or marketers of the pumps.
The pump curves like those shown in FIG. 1 could be expressed, for example, as polynomials where power and head are given as a function of flow rate and speed, or alternately, the head could be determined as a function of flow rate and power consumption. These functions could be determined, for example, by performing a least squares fit to pump performance data obtained from the pump manufacture or vendor or obtained by measured performance for the specific model of pump utilized. Obtaining or creating a digital model of the pump performance enables a computer, programmable logic controller, or other automated means to convert easily measured parameters to determine the head of wellbore fluid above the suction of the down hole pump without having to use a down-hole level measurement and transmitter.
Hydraulic power required to pump fluid at a specified rate depends on the pressure against which the submersible pump is required to work, or the differential pressure across the pump that the pump provides. In the case of a submersible pump, the differential pressure across the pump is dictated by the difference in the level of the fluid columns on the input and output sides of the pump, the density of the fluid, the pressure applied to the top of each fluid column, and any pressure resulting from flow friction.
The pressure drop resulting from flow friction in the output tubular may be calculated from the fluid properties (density and viscosity), geometry of the tubular (length and diameter) and the flow rate by methods well known in the art. For relatively short flow lines with low viscosity fluid, the friction effects are minor and in some embodiments may be ignored with little effect on subsequent calculations.
In one embodiment, the pressure applied to the top of the annular fluid column, or the suction side of the submersible pump, is close to that applied to the top of the outlet fluid column, or the discharge of the submersible pump. In this example, the submersible pump maybe pumping fluids from the wellbore to a separator at the surface which is at essentially the same pressure as vapor in the annulus of the wellbore. This could be the case if, for example, a vapor space above a liquid level in a separator vessel at the surface is in communication with the same system that compresses methane production. Additionally, friction effects from the flow of the fluids being pumped through the tubular extending from the submersible pump discharge to the wellhead are relatively small. In this embodiment, the differential pressure across the pump is given by the product of the fluid density, the acceleration due to gravity and the difference in the height of the fluid columns on either side of the pump. Hence, the height of the annular fluid column, or above the suction of the pump, may be determined from the differential pressure across the pump and the height of the fluid column above the submersible pump outlet.
This differential pressure across the pump may be calculated by first measuring the power consumed by the motor in driving the submersible pump. If the submersible pump is powered by an electric motor, this may be accomplished by measuring both the voltage and the current and determining the power as the product of the measured voltage and current. In cases where a constant voltage power supply is utilized, the power may be determined by measuring the current and multiplying the measured current by the fixed voltage. Other methods of determining the supplied power are known in the art for other power sources. For example, fuel consumption may be used to determine the input power for an internal combustion engine.
The next step involves measuring the output flow rate of the pump, and from pump curves, determining the efficiency for the pump at this flow rate. The system efficiency is defined as the ratio of output power to input power and is generally determined from manufacturer supplied pump curves. In some cases, the system efficiency may be taken to be nearly constant over a relevant range of operating conditions.
The hydraulic power may then be calculated by multiply the electrical power by the efficiency.
The differential pressure across the pump is calculated by dividing the hydraulic power by the flow rate.
The hydraulic head may be determined by dividing the differential pressure across the pump by the product of the fluid density and the acceleration due to gravity.
The height of the annular fluid column is then given by subtracting the hydraulic head from the depth of the pump where the depth of the pump is taken from the suction of the pump to the elevation of the discharge of the pump at the surface. The height of the annular fluid column could alternatively be taken with reference to any reference elevation, so long as the same reference elevation is used to measure the depth of the pump.
Thus the height of the annular fluid column is determined based on measured flow rate, measured electrical power use, and determining the efficiency from pump curves, and variables that can generally assumed to be constant such as liquid density and the height of liquid above the discharge of the pump.
There are a number of permutations on the ordering of the steps which lead to the same results as the above method. Further, there are a number of additional corrections that could be made, for example, by measuring and inputting into the calculations variables such as the pressures at, for example, the wellhead, for the discharge and suction side of the pump, or takng into account frictional pressure drop of the fluids flowing through the tubular.
In another embodiment, the differential pressure across the pump may be determined by measuring the flow rate of well fluids, and knowing the density of the well fluids, and then determining the differential pressure across the pump directly from pump curves. The difference between this differential pressure across the pump, after conversion to the equivelant height of liquid, and the known height of liquid between the pump outlet and the surface, would correspond to the height of the annular fluid column, or the liquid above the suction of the submersible pump. As with the previously described embodiment, this result could also be corrected for differences between the pressure in the annulus and the pressure above liquids at the surface, or frictional pressure loss of the wellbore fluids being pumped through the tubular.
A correction could also be made for the additional pressure exerted by the head of the vapor column above the suction of the pump. This could be a small correction. For example, a one thousand foot head of methane at a pressure of twenty two pounds per square inch absolute and at 20° C. would add a pressure of 0.44 pounds per square inch pressure to the suction of the downhole pump, or about one foot of water at standard conditions. If data such as the gas temperature, pressure and composition are available, then this correction could be made based on the actual conditions. When the temperature, pressure, and compositions of gas in the annulus of the wellbore do not change significantly over time, typical values for the unavailable variables could be used to calculate a constant correction due to the head of the vapor column on the suction of the pump.
For a constant speed pump, the above method arrives at the head of liquid in the wellbore using the efficiency from the pump curves, the measured flow rates and the measured pressure in the vapor space in the wellbore and the pumped fluid pressure at the surface.
Refering now to FIG. 2, an example of a wellbore of the present invention is shown. A well 201 is shown extending through a coal seam, 202 with a rat hole exending into formation below the coal seam 203, and through overburden 204. A surface casing, 205 may be cemented with cement 206 to a depth below aquifers to protect water supplies. Often wells in coal bed methane production services are provided with cemented casings below this depth, but are provided with an uncemented liner 207. An annulus around the uncemented liner may be sealed by, for example, packers 208. A plurality of packers could be provided, and the packers could be, for example, swellable polymers that expand upon contact with water.
An electrical submersible pump 209 may be provided, preferably below the level of the coal seam within the wellbore. The electrical submersible pump may be suspended by a tubular 210 from a wellhead 211, and provided electrical power by a power cable 212 that extends through the wellhead 211 through, for example, a packer 213, from, for example, a transformer 214 which converts power line voltage power, 217, to voltages capable of being transmitted to the electrical submersible pump. The transformer may be equipped with a meter and transmitter for current 215 and voltage 216 for determination of electrical power being consumed by the electrical submersible pump 209.
The wellbore 201 may contain a liquid level 218, which is at a height of the annular fluid column 219 above the suction of the submersible pump 209, to be measured and controlled by the present invention. When the present invention is applied to a coal bed methane production well, the liquid level is lowered from a normal equiblibrium level, which could be the water table of the overburden, thus lowering the pressure excerted on the coal within the coal seam 202. As a result of the lower pressure, methane that is adsorbed on the surface of the coal is released and produced through the annulus of the wellbore 220 and through the wellhead 211, via a nozzle 221, in the wellhead. The rate at which methane is produced is typically measured by, for example, an orfice meter 222. The methane production 223 is typically increased by minimizing the liquid level in the wellbore to the constraints of the requied net positive suction head required for reliable operation of the pump 209, to permit maxium release of methane from the coal seam. A shut-in valve 224 could be provided in the gas production line to permit isolation of the well.
When operating, the electrical submersible pump 209 pumps well fluids through the tubular 210 and through the wellhead 211 to a liquid production line 225. When the present invention is practiced in a coal bed methane production well, the well fluid is mostly water, potentially contining dissolved methane and possibly other contaminates such as carbon dioxide, hydrogen sulfide, and heavier hydrocarbons. Pressure of the pump discharge at the surface may be measured by pressure transmitter 226, and the flow rate of the wellbore liquids being pumped may be measured by flow transmitter 227. The liquids being pumped could be routed to a separator 332, where a liquid level 333 could be maintened allowing additional methane to escape 334 from the pumped liquids, producing a degassed pumped liquid stream 335. In this embodiment, the depth of the pump 336 would be the distance from the liquid surface in the separator to the suction of the pump, or another point of reference which is used to determine the height of the annular fluid column 219.
In some embodiments, the liquid production line 225 may be provided with a flow control valve 228. When a flow control valve 228 is provided, the depth of the pump would need to consider the distance between the suction of the pump and the elevation of the sensor for the pressure transmitter 226, of distance 337, plus the pressure measured by the pressure transmitter. The pressure measured by the pressure transmitter would be converted to a height of liquids by dividing the pressure by the product of the density of the wellbore fluids and the acceleration of gravity.
A controller 229 may be provided to control the height of the annular fluid column 219 of liquids within the wellbore. The controller utilizes inputs from variables that are measured at the surface to control the height of the annular fluid column 219 of liquids within the wellbore. There are different combinations of variables that could be utilized within the scope of the present invention, and there are different control variables within the scope of the present invention. Height of the annular fluid column 219 of liquids in the wellbore may be controlled by turning on and off the electrical submersible pump 209. This method of control is not preferred because it may result in the height of the annular fluid column 219 increasing above a minimal height of the annular fluid column while the pump is not operating, possibly resulting in a hydrostatic pressure on the formation that exceeds the optimal operating pressure. In the application of a coal bed methane production well, this may result in marginally reduced production from the well. Further, constantly turning on and off electrical pumps is detrimental to the service life of the pump.
The height of the annular fluid column 219 could be controlled by controlling the flow control valve 228 for the liquid production. When the flow of liquid production is controlled to control the height of the annular fluid column 219, the controller 229, could also maintain a minimum flow rate. In this embodiment control signal 230 goes to flow control valve 228 to control the positon of the flow control valve to maintain the height of the annular fluid column of liquid. The height of the annular fluid column of liquid may be controlled directly from the height of the annular fluid column determined by the present invention, or the height of the annular fluid column determined by the present invention could reset a set point for the flow rate measured by flow transmitter 227, and the flow rate measured by flow transmitter 227 controlled.
Maintenance of a minimum flow rate may be desirable to prevent the pump from over heating or prevent the pump from being damaged or causing the life of the pump to be shorted by operation at less than desired flow rates. Minimum rates could be maintained by, for example, shutting down the pump when minimum height of the annular fluid column are reached, and then starting the pump back up after a predetermined time period. Alternatively, the minimum flow rate could be maintained by recycling some produced fluids back into the wellbore.
When a variable speed pump is utilized, the speed of the pump may be controlled to control the height. Typically, variable speed motors are controlled by changing the frequency of alternating current provided to the electrical motor. In this embodiment, transformer 214 maybe a variable speed well level controllers are commercially available, for example, from Yaskawa. The iQpump drive, from Yaskawa, is for example, an exemplary variable speed pump controller.
Controller 229 could utilize as inputs, for example, one or more of the current 215 and voltage 216 for determination of electrical power being consumed by the electrical submersible pump 209, annulus pressure 230, pressure of the pump discharge at the surface as measured by pressure transmitter 226, and the flow rate of the wellbore liquids being pumped as measured by flow transmitter 227. The controller could then provide a control signal 231 which would, for a constant speed pump, control the position of the flow control valve 228. In the practice of the present invention, where a variable speed pump is utilized, the control signal could control the speed of the variable speed pump by reseting the input to the variable speed well level controller 214.
Controller 229 could provide additional functions. For example, when input to the controller indicates that the pump is cavitating or has insufficient suction head pressure, the control system could be overridden to shut down the pump. An indication that the pump is cavating could be, for example that power consumption decreasing below a predetermined threshold, In this embodiment, the height of liquids in the annular fluid column to which the controller is set to control could be reset to a height slightly, for example, two meters to twenty meters, above the height deterimined at the point that cavitation is detected. Other indications that the pump may be cavitating could be rapid changes in current to the pump motor, or fluctuations in the rate wellbore fluids are being pumped. Preventing the pump from operating in a cavitation mode, or operating with insufficient suction head, could inproe the reliability and useful life of the pump, and also avoid energy costs incurred when the wellbore contains insufficient liquids to be pumped.
In an application of the present invention to a coal bed methane well, the controller 229 could also consider the rate at which methane being produced, as measured by orfice meter 222 along with in the cost of disposing wellbore fluid removed from the wellbore, to optimize the height of the annular fluid column 219. The pump 209 could be placed in a rat hole below the coal seem by a distance of at lease the net positive suction head requirement of the pump, and thus enable operation with the level of wellbore fluid below the entire coal seam. This would result in maximum rates of methane release from the coal seam, but may not result in maximum profit from the operation. Pumping and disposal of wellbore fluid from coal seams is a significant operating cost, and the lower the level of wellbore fluid is carried in the wellbore, the more wellbore fluid would need to be pumped and disposed. Therefore there may be an optimum height of the annular fluid column, 219, which would result in a maximum difference between the value of produced methane and cost of pumping and disposing of wellbore fluid. The controller could, on a regular basis, change the set point to which the height of the annular fluid column 219 is maintained, and determine if the change in value of methane production exceeded the change in the cost to pump and dispose of wellbore fluid. If the incremental change in the height of the annular fluid column 219 resulted in a greater net profit, then the set point could be reset to the new set point for the height of the annular fluid column 219.
Controller 229 could also be configured to maintain the flow rate of wellbore fluid being pumped to a rate that exceeds minimum rates for the pump. Generally, pumps have minimum rates below which they will suffer short services lifes at least partilly because of higher operating temperatures. If this minimum rate cannot be achieved without the height of the annular fluid column 219 falling below a minimum, as required for example, by net positive suction head requirements, then the controller could cause the pump to shut down for a predetermined time. The pump could be restarted after, for example, a predetermined time. Pumping would be resumed at a rate that would exceed the minimum rates established for the pump. The predetermined time period could be reset by the controller based on the height of the annular fluid column measured at the time the pump is restarted.
When the present invention is practiced in a coal bed methane production application, letting the liquid level in the wellbore raise too high results in excessive loss of methand production due to the increased hydrostatic pressure on the coal seam. Starting the pump up too soon will result in excessive cycles of starts and stops for the pump, and shorten the service life of the pump. The controller could be provided with, for example a ratio between the resulting difference in height of the annular fluid column 291 and shut down times for reseting the predetermined time the pump is shut down so the controller may maintain a near optimum balance between lost production and decreases in pump service lifes.
The present invention utilizes performance curves supplied by the manufacture or vendor although the performance of pumps may deterioriate over time for many reasons. The present invention may therefore include a step of calibrating the pump curves occasionally by utilizing an independent means to measure the height of the annular fluid column 219 and adjusting the pump curves to match the current measured performance.
The height of the annular fluid column 219 could be occasionally determined manually by an accustic level measuring device which could be connected to the wellbore at the surface. These devices are know and commercially available, for example, LMSA 500 portable liquid level monitoring sysgem is an example of an acceptable portable sysgem available from EPG Companies, 19900 County Road 81, Maples Grove, Minn. 55311. Mobrey MSP900FH ultrasonic level sensor is also an acceptable system.
The recalibration could also be used to correct the height of the annular fluid column for small variables such as the pressure on the suction caused by the head of vapor in the annulus of the well.

Claims

What is claimed is:

1. A method for removal of fluid from a subterranean formation comprising the steps of:

providing a wellbore from the surface to within the formation:

providing a pump in the wellbore capable of removing fluid from the wellbore to a surface location;

establishing a pump performance function as pump curves;

measuring at least one variable that establishes where the pump is operating on the pump curve;

determining a differential pressure across the pump from the at least one measured variable;

determining a pressure of liquid pumped by the electric driven pump at a know height of the annular fluid column above the suction of the electric driven pump;

determining a height of the annular fluid column of liquid above the suction of the pump from the differential pressure across the pump, the know height of the annular fluid column above the suction of the electric driven pump, and the pressure of liquid pumped by the electric driven pump at a know height of the annular fluid column above the suction of the electric driven pump.

2. The method of claim 1 further comprising the step of selecting a target height of the annular fluid column of liquid above the suction of the pump to which the pump is to maintain.

3. The method of claim 2 further comprising the step of adjusting the output flow rate of the pump to a flow rate which maintains the level of fluid in the wellbore essentially at the target height of the annular fluid column of liquid above the suction of the pump.

4. The method of claim 3 wherein the electric pump is a variable speed electric pump and the step of adjusting the output flow rate of the pump is accomplished by adjusting the frequence of electricity to the variable speed electrical pump.

5. The method of claim 1 further comprising measuring the pressure in an annulus of the wellbore and determining the height of the annular fluid column of liquid above the suction of the pump from the differential pressure across the pump, the know height of the annular fluid column above the suction of the electric driven pump, and the pressure of liquid pumped by the electric driven pump at a know height of the annular fluid column above the suction of the electric driven pump, and the pressuer in the annulus of the wellbore.

6. The method of claim 1 further comprising the step of determining the height of the annular fluid column of liquid above the suction of the pump by independent means in order to calibrate the calculation of the height of the annular fluid column of liquid above the suction of the pump.

7. The method of claim 1 further comprising the step of producing methane from the subterranean formation.

8. The method of claim 1 wherein the subterranean formation is a coal containing formation.

9. A wellbore comprising:

an electric driven pump;

a current measuring device effective to measure the current to the electric driven pump and produce a signal corresponding to the current

a pressure measuring device effective to measure the pressure of liquid pumped by the electric driven pump and produce a signal corresponding to this pressure:

a memory device containing relationships between current, and the head produced by the pump; and

a controller to control the electric driven pump to maintain a predetermined height of the annular fluid column of liquid above the suction of the pump according to the relationship between the current, the variable frequency, and the head produced by the pump and the measured pressure of liquid pumped by the electric driven pump.

10. The wellbore of claim 9 further comprising a sensor for measuring methane flow rate from the wellbore wherein the controller resets the predetermined height of the annular fluid column of liquid above the suction of the pump to maximize net profit.

11. The wellbore of claim 9 wherein the pump is a variable speed electric driven pump, and the controller controls the frequency of alternating current to the variable speed electric driven pump.

12. The wellbore of claim 9 further comprising a control valve in the wellbore fluid production line from the electric driven pump wherein the controller controls the position of the control valve.

13. The wellbore of claim 9 further comprising:

a recycle line from the discharge of the electric driven pump back to the suction of the electric driven pump;

a control valve in the recycle line; wherein the controller controls the control valve in the recycle line to maintain the height of the annular fluid column of liquid above the suction of the pump.

14. The wellbore of claim 13 wherein the controller also controls the valve in the recycle line to maintain a predetermined minimum flow rate of liquids through the electric driven pump.