Patent Application
20140305652
The embodiments disclosed herein relate to the field of horizontal well fluid removal. More particularly, the disclosed embodiments relate to the removal of well fluid accumulated within the sumps or other liquid accumulation portions of the horizontal section of an oil and/or natural gas well using pressurized gas delivered from the surface.
The accumulation of liquids in oil and natural gas wells restricts the flow of hydrocarbons from the producing formation into the bore hole. Reduced flow occurs when hydrostatic pressure exerted on the face of the producing formation reduces pressure drawdown, and liquids accumulated across from producing zones causes a reduction in gas or oil flow by saturating pore spaces with water or other liquids.
During the initial production period of a horizontal gas well, the gas velocity in the entire wellbore is sufficient to remove liquids from the well unassisted. As productivity naturally declines, there will eventually be insufficient pressure to overcome the hydrostatic head created by fluid accumulation in the vertical and horizontal sections of the well bore. Another contributing factor to gas well productivity decline is the accumulation of formation water or liquid hydrocarbons in the horizontal well bore across from gas productive perforations. This fluid accumulation will cause a reduction in gas relative permeability by saturating the pore throats near the wellbore with liquids. Similar effects occur in oil wells where water accumulates in the horizontal section, increasing hydrostatic pressure and decreasing oil relative permeability.
To maximize the returns from an oil/gas well, it is important to remove any restrictions to flow caused by wellbore liquids accumulation. When a well rate falls due to liquid loading, it is often necessary to periodically install mechanical equipment to remove liquid from the bore hole and reduce the hydrostatic head. This operation decreases the economic efficiency of the well, requires additional supervision, maintenance and equipment.
Several methods have been devised for removal of liquids from a bore hole, each having their own particular advantages and disadvantages. Usually a plunger is installed when a gas well has difficulty flowing naturally. This method lifts liquids from low rate gas wells by allowing the well to build pressure between flow cycles and lift complete slugs of liquid with each plunger stroke. The drawback to this technique is that during shut-in periods, accumulated liquids are driven back into the formation by pressure building in the tubing. Because the gas flow is intermittent, wellbore damage occurs during each shut-in period. Finally, a plunger cannot work consistently if the surface build-up pressure is not at least twice the line pressure that the well flows into. This method is not applicable for wells with significant deviation from a substantially vertical and linear wellbore configuration that restricts the free-fall of the plunger to the bottom of the well.
Another method of removing liquids is by pumping the liquid out of the casing with a long sucker rod operated by a pump jack at the surface. This method is not applicable for wells with significant deviation from a substantially vertical and linear wellbore configuration (also known as “doglegs”) that restrict the ability of the rod string to naturally fall on the downstroke. Deviations in the wellbore will cause wear on the rods and tubing during the upstroke. A modification of the sucker rod pumping method involves rotating progressive cavity pumps which use rotating rods and do not require a vertical return. This method also has drawbacks since rotating sucker rods will wear and break due to alternating bending stresses around the curves in a horizontal well. Downhole electric pumps use no rods but are inefficient in low liquid rate horizontal wells due to short run lives, gas locking and high equipment costs.
A method better suited for curved wellbores is known by those skilled in the art as “gas lift.” This widely used method involves injecting gas down one flow path with the intent of lightening the fluids returning up another flow path. This gasification reduces the density of the produced fluids and facilitates the flow to the surface as long as reservoir pressure remains high enough to lift the gasified column of fluid.
“Continuous” and “intermittent” are the two classes of gas lift. In continuous gas lift installations, lift gas is continuously injected into the annulus, flowing down to a port at the bottom of the well, and returning up a second conduit with the produced fluids. For intermittent gas lift installations, the well is produced without injecting gas until liquid accumulation causes a reduction in flow capacity. Then, gas is injected into the annular space to re-start flow. Lift gas is removed once the well can flow unassisted.
Chamber lift is a specialized form of intermittent gas lift where an accumulation chamber is used to collect a designated volume of liquid in a fixed chamber, one side of a concentric string, or the bottom of a U-tube in a vertical wellbore. This accumulated liquid is periodically circulated to the surface using pressurized gas introduced into one conduit of the u-tube or concentric string at the surface, forcing the liquids up the other side.
A device patented by Buckman discussed in U.S. Pat. No. 5,006,046 is a downhole U-tube designed exclusively for vertical wells and is actuated with pressure in the flowing wellbore. Since the system is driven by formation pressure, a high formation pressure is required to lift a complete slug of liquid to the surface. High formation pressure is rarely present in mature gas wells.
The typical lack of high formation pressure was addressed by Reitz (U.S. Pat. Nos. 6,672,392 and 7,100,695) using one small conduit fully contained within a second, larger concentric conduit with the liquid intake port at the extreme end. Using high pressure gas delivered at the surface, this device is designed to lift liquids from the bottom of a vertical wellbore. This method may be applied to horizontal wells but the method is limited by the amount of liquid that can be accumulated per cycle since the liquid intake is at the bottom of the device and no liquid accumulation is possible toward the toe of the wellbore. The Reitz disclosures also do not provide a means of venting gas bubbles that will limit liquid accumulation. Furthermore, the amount of liquid that can be collected is limited to the volume that can be contained in the relatively small diameter pipe over a few hundred feet of length.
Another enhancement to the Buckman system was described by Lima in U.S. Pat. No. 5,671,813 where two production strings are used to lift a vertical well using a circulating mechanical interface. This system is limited by the inability to lift from around the heel of a horizontal well since the liquid intake is at the extreme end of the apparatus, and the only area for accumulation of liquids is again the amount that can be lifted by reservoir pressure toward the wellhead.
One embodiment includes an apparatus and method for removing liquid from a horizontal well using multi-conduit tubing, associated with one or more liquid intake port(s) and vent port(s) positioned at selected locations along the tubing, and surface supplied pressurized gas. The disclosed system and method embodiments include a multi-conduit tubing run into a wellbore. One or more liquid intake ports are placed at liquid accumulation points along the primarily horizontal section of the wellbore. One or more vent housings are placed at gas accumulation points along the primarily horizontal section of the wellbore.
In use, pressure is released in all conduits to allow accumulated water in the wellbore to flow naturally into at least two of the conduits through intake check valves. While the multi-conduit is filling, trapped gas in the conduit can be vented to the surface through a vent line, allowing complete or “best possible” fillage of the horizontal section of the multi-conduit.
Once sufficient time has been provided for liquid inflow to fill the conduits, pressurized gas is injected in one or more conduits, forcing check valves closed at the intake ports and lifting the accumulated liquid slugs up the remaining un-pressurized conduit(s). If liquid sweep is insufficient, small spheres can be introduced with the pressurized gas at the surface and circulated back to the surface, pushing a slug of accumulated liquid.
In some embodiments, timer or sensor controlled valves are connected to each of the conduits at the surface so that gas can be intermittently injected into the conduit(s) to circulate liquids to the surface. A mechanism may be provided for opening and closing the valves. When the valves are open to a low pressure slug catcher or liquid collection tank, liquid will accumulate in the multi-conduit through the openings at the sumps in the horizontal sections of the wellbore. Alternately, when high pressure gas valves are open to part of the multi-conduit, gas will force the liquid through the remaining conduits and out of the well.
Certain specific embodiments disclose a system for removing liquid from a wellbore generally as described above. The system comprises a multi-conduit including at least two pipes extending into the wellbore from the surface of the wellbore and at least one intake port in fluid communication with at least one pipe of the multi-conduit. The intake port includes a liquid passage extending from the interior of the multi-conduit to the exterior of the intake port and a check valve operatively associated with the liquid passage providing for the liquid passage to be closed when pressure inside the multi-conduit exceeds pressure outside the liquid passage. This check valve configuration provides for the liquid passage to be open when the pressure outside the liquid passage exceeds the pressure inside the multi-conduit. The system also includes a connection between at least two pipes of the multi-conduit providing for fluid communication between the two pipes.
In selected system embodiments, the connection comprises one or more vent housings positioned in fluid communication with the multi-conduit providing for fluid communication between at least two pipes of the multi-conduit. Multiple vent housings with one vent housing being positioned at the end of the multi-conduit opposite the surface of the wellbore can be used as well.
In certain embodiments, the multi-conduit comprises a first fluid accumulation pipe in fluid communication with the liquid passage of at least one intake port; a second fluid accumulation pipe in fluid communication with the liquid passage of at least one intake port and a vent pipe in fluid communication with the first fluid accumulation pipe and the second fluid accumulation pipe at one or more vent housings. Additionally, the system may include one terminal vent housing located at the end of the multi-conduit opposite the surface of the wellbore and providing for fluid communication between the first fluid accumulation pipe, the second fluid accumulation pipe and the vent pipe; and one or more in-line vent housings located between the end of the multi-conduit opposite the surface of the wellbore and the surface of the wellbore and providing for fluid communication between the first fluid accumulation pipe, the second fluid accumulation pipe and the vent pipe.
System embodiments may also include a pressurized gas source such that the fluid accumulation pipe or pipes and the vent pipe or pipes may be selectively pressurized by the application of a pressurized gas.
The apparatus described herein may be implemented in any desired configuration; however, typically at least one intake port is operatively positioned in a horizontal portion of a wellbore at a location where liquid accumulates. Similarly, at least one of the vent housing(s) is typically operatively positioned in a horizontal portion of a wellbore at a location where gas accumulates.
The intake port or ports may optionally include a back-flush port positioned adjacent to the liquid passage and extending from the multi-conduit to the exterior of the intake port, wherein the back-flush port is oriented such that liquid flowing through the back-flush port when the pressure in the multi-conduit exceeds the pressure outside the liquid passage clears debris from the liquid passage.
Various methods of removing liquid from a wellbore using the apparatus described above are also disclosed herein. Also disclosed are various embodiments of an intake port as described above.
Unless otherwise indicated, all numbers expressing quantities of ingredients, dimensions reaction conditions and so forth used in the specification and claims are to be understood as being modified in all instances by the term “about”.
In this application and the claims, the use of the singular includes the plural unless specifically stated otherwise. In addition, use of “or” means “and/or” unless stated otherwise. Moreover, the use of the term “including”, as well as other forms, such as “includes” and “included”, is not limiting. Also, terms such as “element” or “component” encompass both elements and components comprising one unit and elements and components that comprise more than one unit unless specifically stated otherwise.
As described below, the multi-conduit 24 may be implemented with a substantially parallel array of two or more pipes or tubes. For ease of description, the multi-conduit 24 is generally described herein as being a parallel array of three pipes. Thus, reference is made to the two outside pipes and possibly one inside pipe of a multi-conduit 24 in the present disclosure and figures. It is important to note that the various embodiments disclosed herein can be implemented with multi-conduit elements having any number of pipes or tubes arranged in any desired fashion.
The intake ports 34 will include holes 42, created through the housing in one or more of the outside lines 28, 30 where liquid can enter the multi-conduit 24. Check valve balls 44 and seats 46 are threaded into or otherwise attached to the housing just below each of the holes 42 in the outside lines to provide a precise and durable one-way seal. The intake port embodiments disclosed herein could be implemented with alternative check valve types or configurations.
Optionally, a back-flush port 48 can be included with an intake port 34, in fluid communication with the outside lines and used to automatically flush debris from the entrance of the intake port check valves on each pressurization cycle.
Referring back to
Produced gas may be continuously removed from the casing 22 or tubing through production valve 66. Gas can flow directly to the sales line 68 or to a compressor suction manifold 70 where wellhead gas is boosted to gathering system pressure. Produced gas can be removed from the wellbore while the multi-conduit is being filled or while it is being evacuated to the surface as described in more detail below.
After the multi-conduit 24 is full of liquid, selected valves 72 at the surface 64 are opened, supplying highly-pressurized lift gas to one or more of the pipes of the multi-conduit 24. The vent line can also be pressurized to assist liquid lift by opening the appropriate valve 72 with opposite valve 74 closed. Pressurized gas can be supplied by centrally compressed lift gas or by on-site compression through compressor 70 and compressed gas storage 78. Valve 80 may be used to divert high pressure sales gas to use as lift gas stored for intermittent cycles. With pressurized gas quickly working down one side of the multi-conduit (28 or 30) and the vent-line 32, pressure in the multi-conduit 24 will increase, automatically forcing the check valves closed in the port housing(s) 34. The increased pressure on one side of the multi-conduit 24 and the gas vent line 32 will send the accumulated liquid slug toward the opposite, evacuated side of the multi-conduit 24. Thus, the gas behind one side of the conduit will push the slug ahead of it, while the vent line will add gas to the liquid slug as it traverses around the U-tube 52, decreasing the density of the liquid slug as it works its way to the surface. For particularly deep wells, pressurized gas can be supplied to the entire liquid slug with multiple gas delivery points in the vent line 32.
With valve 72 open, the high pressure gas slug circulating toward the surface will drive a fluid slug up the remaining low pressure (outside) conduit toward the surge tank 84. Liquid is removed from the surge tank 84 for disposal or sales through dump valve 82. Valve 88 leading to a gas booster suction 90 and vent valve 86 will cooperate to maintain pressure in the surge tank 84 and evacuated conduit at or near atmospheric pressure during the liquid slug production phase.
Another embodiment of the system 10 consists of all elements noted above but with additional connections and valves to allow reversed flow through the various conduits when compared to the normal operation. Yet another embodiment consists of all the elements in the system described above but with circulating spheres within the multi-conduit 24 that are used to provide a more complete sweepage of liquid slugs to the surface.
Operation
Referring to
Wells best suited for the lift methods and apparatus as disclosed herein are horizontal wells that exhibit liquid loading behaviors or reduced production rates due to liquid accumulation in the wellbore. Since wells with plungers or sucker rod pumps remove liquid only from the vertical portion of the wellbore, these wells are also good candidates for the described methods. Even those wells that consistently unload the vertical production tubing will have liquid loaded horizontal sections due to the lower velocities in the larger ID horizontal section.
Candidate wells can be selected based on their inability to flow consistently and other liquid loading indicators. Referring to
The apparatus may be installed using a coiled tubing unit or other suitable means to place the multi-conduit 24 within the borehole. The multi-conduit is run into the horizontal section as far as possible to create the largest possible capture volume for liquid. If surface gas injection pressure is too low to evacuate an aerated column of liquid, a shorter installation may be optimal.
During normal operation, liquid is allowed to fill the multi-conduit through the intake ports. The amount of time needed to fill the conduit will be a function of the flow restriction in the intake check valves, the wellbore pressure at the sump locations and the minimum pressure that can be achieved in the evacuated multi-conduit. If the liquid production rate from the formation is low, the conduit may not fill completely. Once the optimal time has been determined to have passed, pressurized gas is supplied to the multi-conduit by operating selected valves 72 and 74. High pressure gas flows to two conduits: one side of the multi-conduit, for example pipe 28 or 30, but not both and the vent line 32 if used. The high pressure gas in these two lines forces the intake port check valves (elements 44 and 46 or an alternative check valve) closed and any fluids within the system are then forced up the remaining unpressurized line. The vent line 32 is pressurized to prevent it from filling with liquid and to provide gas to the liquid slug as it passes by the vent housings 52. The lift gas provided by the vent line decreases the density of the liquid slug being circulated to the surface.
After sufficient high pressure gas charge is supplied to the multi-conduit, valves 72 are closed to preserve lift gas for the next cycle. Meanwhile the pressurized gas in one conduit will force the accumulated liquid around the terminal U bend into the low pressure conduit and to the surface. The valve 74 connected to the low pressure conduit typically remains open to allow the liquid slug to be emptied into the surge tank 84. Lift gas produced with the liquid is re-compressed through a booster compressor and sent to sales or the gathering system.
After the complete slug is produced, the pressure in the entire system is bled down through surge tank valve 88 and perhaps tank vent valve 86. With the pressure in the conduit now lower than the pressure in the fluids opposite the intake ports 34, intake port check valves will open and a new slug of fluids will accumulate in the multi-conduit 24.
For wells that require lifting large slugs or that have low injection pressure, significant lift gas can be delivered from the vent line 32 throughout the length of a long slug enabling any size slug to be lifted. Alternatively, if large slugs are only experienced occasionally, pressure can be exerted on all multi-conduit pipes, forcing part of the liquid slug out the conduits through the intake port back-flush ports 48. A third alternate method of removing an occasional large slug is to circulate both liquid and gas down one side of the multi-conduit, thus generating a higher bottom-hole pressure to lift the liquid up the other side.
When the need arises to remove the multi-conduit 24, circulating ports in the mandrels can be opened to circulate completion fluids and remove any debris that might constrain the movement of the multi-conduit.
A typical 0.5 inch ID multi-conduit may be installed in a 4000 foot deep well with a 4000 foot horizontal section making a total well length of 8000 ft of wellbore. Using a typical 0.1 psi/ft gradient for an aerated fluid column, 400 psi lift gas pressure would be required to displace a column of aerated liquid to the surface. Using a multi-conduit unit volume of 0.5 barrels/1000 linear feet, a full charge of 2 barrels of liquid could be lifted on each cycle. Although the volume of lift gas required to unload liquid to the surface on each cycle depends on vent mandrel rates, approximately 200 scf of 400 psia lift gas will be required per cycle. Thus, the disclosed system and apparatus can result in a lift gas to liquid lifted ratio of 100 scf/bbl.
The required time per cycle will be dependent on well-specific parameters, but using reasonable fillage and unloading times, lifting up to 100 barrels of liquid per day is possible.
Various embodiments of the disclosure could also include permutations of the various elements recited in the claims as if each dependent claim was a multiple dependent claim incorporating the limitations of each of the preceding dependent claims as well as the independent claims. Such permutations are expressly within the scope of this disclosure. While the embodiments disclosed herein have been particularly shown and described with reference to a number of alternatives, it would be understood by those skilled in the art that changes in the form and details may be made to the various configurations disclosed herein without departing from the spirit and scope of the disclosure. The various embodiments disclosed herein are not intended to act as limitations on the scope of the claims. All references cited herein are incorporated in their entirety by reference.
This application is a continuation of U.S. patent application Ser. No. 13/652,752, filed on Oct. 16, 2012, which claims the benefit under 35 USC §119(e) of U.S. Provisional Patent Application No. 61/550,651, filed Oct. 24, 2011, the contents of which are herein specifically incorporated by reference in their entireties.
| Number | Date | Country | |
|---|---|---|---|
| 61550651 | Oct 2011 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 13652752 | Oct 2012 | US |
| Child | 14316087 | US |
