Self-cleaning packer system

A collapsible packer for use in a well includes a deployment assembly, a retraction assembly and a sealing assembly extending between the deployment assembly and the retraction assembly. The deployment assembly may include a spring and a degradable stop configured to offset the force applied by the spring. The degradable stop can be manufactured from a material that dissolves when contacted by fluid in the well. The retraction assembly may by hydraulically or spring energized.

FIELD OF THE INVENTION

This invention relates generally to oilfield equipment, and in particular to surface-mounted reciprocating-beam, rod-lift pumping units, and more particularly, but not by way of limitation, to beam pumping units used in connection with wells that produce significant sand and other sediments.

BACKGROUND

Hydrocarbons are often produced from wells with reciprocating downhole pumps that are driven from the surface by pumping units. A pumping unit is connected to its downhole pump by a rod string. Although several types of pumping units for reciprocating rod strings are known in the art, walking beam style pumps enjoy predominant use due to their simplicity and low maintenance requirements.

In many wells, a high gas-to-liquid ratio (“GLR”) may adversely impact efforts to recover liquid hydrocarbons with a beam pumping system. Gas “slugging” occurs when large pockets of gas are expelled from the producing geologic formation over a short period of time. Free gas entering a downhole rod-lift pump can significantly reduce pumping efficiency and reduce running time. System cycling caused by gas can negatively impact the production as well as the longevity of the system.

Many rod pump systems include separators that discharge gas and sand into the annulus of the well. Discharging gas and sand into the annulus generally improves the performance of the downhole pump. Over time, however, the sand accumulates in the annulus around downhole components, particularly in lateral portions of the well. The sand deposits may frustrate efforts to retrieve the downhole pumping components from the well. Packers, plugs and other zone isolation devices are especially vulnerable to sand packing. There is, therefore, a need for an improved packer system that overcomes these and other deficiencies of the prior art.

SUMMARY OF THE INVENTION

In one aspect, embodiments of the present invention include a collapsible packer for use in a well. The packer includes a deployment assembly, a retraction assembly and a sealing assembly extending between the deployment assembly and the retraction assembly. The deployment assembly may include a spring and a degradable stop configured to offset the force applied by the spring. The degradable stop can be manufactured from a material that dissolves when contacted by fluid in the well.

In some embodiments, the retraction assembly may include a pressure housing, a retraction piston inside the pressure housing, an orifice extending through the pressure housing, and a rupture plate covering the orifice. The rupture plate is configured to rupture and open the orifice when exposed to external fluid pressure exceeding a predetermined rupture pressure. In other embodiments, the retraction assembly includes a retraction spring that is captured by a shear pin that is connected to a velocity tube or other tubular extending through the collapsible packer. The shear pin is designed to breaks under shear stress created by attempting to remove the tubular from the deployed collapsible packer. When the shear pin fails, the retraction spring releases the compression applied to the sealing assembly to allow the collapsible packer to collapse.

In another aspect, the invention includes a method for deploying and removing a packer in a well. The method includes the steps of providing a packer having a deployment assembly, a sealing assembly and a retraction assembly, connecting the packer to a tubular body and placing the packer and tubular body at a desired location in the well. The method continues with the steps of activating the deployment assembly to expand the sealing assembly, activating the retraction assembly to collapse the sealing assembly, and removing the collapsed packer and tubular body from the desired location in the well.

WRITTEN DESCRIPTION

FIG. 1shows a beam pump100constructed in accordance with an exemplary embodiment of the present invention. The beam pump100is driven by a prime mover102, typically an electric motor or internal combustion engine. The rotational power output from the prime mover102is transmitted by a drive belt104to a gearbox106. The gearbox106provides low-speed, high-torque rotation of a crankshaft108. Each end of the crankshaft108(only one is visible inFIG. 1) carries a crank arm110and a counterbalance weight112. The reducer gearbox106sits atop a sub-base or pedestal114, which provides clearance for the crank arms110and counterbalance weights112to rotate. The gearbox pedestal114is mounted atop a base116. The base116also supports a Samson post118. The top of the Samson post118acts as a fulcrum that pivotally supports a walking beam120via a center bearing assembly122.

Each crank arm110is pivotally connected to a pitman arm124by a crank pin bearing assembly126. The two pitman arms124are connected to an equalizer bar128, and the equalizer bar128is pivotally connected to the rear end of the walking beam120by an equalizer bearing assembly130, commonly referred to as a tail bearing assembly. A horse head132with an arcuate forward face134is mounted to the forward end of the walking beam120. The face134of the horse head132interfaces with a flexible wire rope bridle136. At its lower end, the bridle136terminates with a carrier bar138, upon which a polish rod140is suspended. The polish rod140extends through a packing gland or stuffing box142on a wellhead144. A rod string146of sucker rods hangs from the polish rod140within a tubing string148located the in the casing150of a well152.

Turning toFIGS. 2A and 2B, shown therein is a depiction of the well152. As depicted, the well152has a vertical portion (V) and a lateral portion (L). A subsurface pump154is disposed in the well casing150and configured to lift fluids from the well152to the surface through the tubing string148. The subsurface pump154can be configured as a rod pump that includes a traveling valve156and a standing valve158. The rod string146is connected to the traveling valve156. In a reciprocating cycle of the beam pump100, well fluids are lifted by the traveling valve156within the tubing string148during the upstroke of the rod string146.

The subsurface pump154further includes an intake separator160, a velocity tube162and a collapsible packer164. InFIG. 2A, the intake separator160is connected between the velocity tube162and the standing valve158. Generally, the intake separator160expels sand and gas into the annular space between the well casing150and the subsurface pump154. The gas tends to rise through the well152, while the solid particles fall back into the lower and lateral portions of the well152. The intake separator160may employ cyclonic mechanisms to separate the sand and gas components of the fluid entering the standing valve158.

InFIG. 2B, the intake separator160is configured as a two-step separation system that includes a perforated joint166and a gas mitigation canister168. Gases, liquids and solids delivered to the perforated joint166through the velocity tube162are expelled into the annulus surrounding the subsurface pump154. Sand and other solids fall to the lower portions of the well152, while the gases and liquids rise. The gas mitigation canister168has an open top170to permit liquids to enter the gas mitigation canister168. There, the liquids are drawn into the standing valve158through an inlet tube172. In this way, the gas mitigation canister168and perforated joint166rely on gravity to reduce the fraction of gas and solids drawn into the standing valve158.

As depicted inFIGS. 2A and 2B, the velocity tube162extends around the heel into the lateral portion (L) of the well152. The velocity tube162includes an open end174that permits the introduction of fluids into the velocity tube162. The collapsible packer164is positioned around the velocity tube162at a desired location in the well160to prevent or reduce the movement of fluids in the annular space between the velocity tube162and the well casing150. Although the collapsible packer164is depicted as being deployed in the lateral portion (L) of the well152, it will be appreciated that in other embodiments, the collapsible packer164can be deployed in the vertical portion (V) or heel of the well152. Although a single collapsible packer164is depicted inFIGS. 2A and 2B, it will be understood that additional collapsible packers164could also be deployed within the well152.

Turning toFIGS. 3A, 3B and 3C, shown therein are cross-sectional depictions of the collapsible packer164in various stages of operation. The collapsible packer164includes a deployment assembly176, a retraction assembly178and a sealing assembly180disposed between the deployment assembly176and the retraction assembly178. The deployment assembly176and retraction assembly178are connected to the velocity tube162at a desired location. The deployment assembly176includes a spring housing182, a deployment spring184, a deployment piston186, a stop188and a deployment piston sleeve190. It will be appreciated that although shown in cross-section inFIGS. 3A-3C, each of these components may have a substantially cylindrical form that surrounds the velocity tube162.

The deployment piston186, stop188and deployment spring184are each contained within the spring housing182. The deployment piston186is connected to the deployment piston sleeve190, which extends through the spring housing182to the sealing assembly180. The collapsible packer164may include a single deployment spring184or multiple deployment springs184within the spring housing182. Initially, as depicted inFIG. 3A, the movable deployment piston186is captured and held stationary within the spring housing182between the stop188and the deployment spring184. In this way, the stop188opposes the force applied to the deployment piston186by the deployment spring184. In some embodiments, the spring housing182includes ports (not shown) that expose the stop188to fluids in the well152. In other embodiments, the opening in the spring housing182that permits movement of the deployment piston sleeve190is sufficiently large to allow fluids from the well150to enter into the spring housing182.

The stop188is constructed from a material that dissolves or disintegrates in the presence of fluids in the well152. Suitable materials of construction should be selected based on the predicted chemistry, temperature, pressure, composition and condition of the fluids in the well152. Materials of construction generally include, but are not limited to, oxo-degradable polymers, polymers with hydrolysable backbones (e.g., aliphatic polyesters) including hydrolysable polymers produced from animal sources (e.g., collagen and chitin). In other embodiments, the material of construction may be chosen from biodegradable polymers including polylactide (PLA), poly-L-lactide (PLLA), and polyglycolic acid (PGA). Additionally, powders or nanoparticles of reactive transition metals such as manganese can be dispersed within the aforementioned polymers or other suitable polymer matrices to create degrading polymer composite materials. It will be further appreciated that the stop188may also be manufactured from metals and metal alloys that are designed to react with water, acids, brines and dissolved oxygen that may be present in the well152. In a preferred embodiment, the stop188would be manufactured from high-strength engineered composite materials that degrade by electrolytic processes, such as the composite materials commercialized by Baker Hughes Incorporated under the IN-TALLIC® brand, which have been used in other downhole components such as isolation plugs for hydraulic fracturing.

In each case, the stop188is manufactured and configured to degrade over a desired period. The stop188is configured to deteriorate over a period that provides sufficient time to properly place the collapsible packer164within the well152. As the stop188deteriorates, the deployment spring184pushes the deployment piston186and deployment piston sleeve190toward the sealing assembly180. As depicted inFIG. 3B, the stop188has completely deteriorated and the deployment piston186and deployment piston sleeve190have been completely deployed.

The sealing assembly180includes a flexible seal192captured between first and second end flanges194,196. In exemplary embodiments, the flexible seal192is constructed from an elastomer sleeve composed of a high-strength rubber such as nitrile rubber (NBR), hydrogenated nitrile rubber (HNBR), a fluoroelastomer or perfluoroelastomer. These rubber materials and composites thereof can be formulated to be inert to fluids present in well152and maintain sealing force under the buckling load created between end flanges194and196. The flexible seal192is configured to buckle outward (as depicted inFIGS. 3B and 4B) when placed under compression between the first and second end flanges194,196. The flexible seal192may include a cross-sectional profile and contour that facilitates a substantially parabolic buckling mode. To further encourage the outward buckling of the flexible seal192, the first and second end flanges194,196may include a buckling force ramp198that directs the compressive force into the flexible seal192at an outward angle to promote a parabolic expansion of the flexible seal192against the well casing150.

In the embodiment depicted inFIGS. 5A and 5B, the flexible seal192is configured as an expandable “bellows” or encased coil spring which has relatively smaller sealing diameter in a laterally expanded state and a larger sealing diameter in a laterally compressed state. The benefits of using a bellow shape for the flexible seal192include having multiple sealing surfaces between collapsible packer164and well casing150. This configuration will ensure seal integrity and provides redundancy in the event of partial failure of the sealing material. The basic concept for sealing comprises multiple flexible seals in the shape of a bellows and configured to buckle outward and expand under a compressive load produced by the deployment assembly176and to retract when the compressive load is removed by the retraction assembly178.

The retraction assembly178offsets the force transferred through the expanding flexible seal192from the deployment spring184. In a first embodiment depicted inFIGS. 3A-3C, the retraction assembly178includes a pressure housing200, a retraction piston202, a retraction piston sleeve204, rupture plates206and orifices208. The retraction piston202is captured within the pressure housing200and separates the pressure housing200into a first chamber210and a second chamber212. The retraction piston sleeve204extends from retraction piston202to the second end flange196of the sealing assembly180. The orifices208connect with the first chamber210and are initially blocked by the rupture plates206.

During manufacture, the first chamber210and second chamber212are filled with fluid and pressurized around the retraction piston202. The fluid pressure within the first chamber210prevents the retraction piston202from moving outward when exposed to the force of the deployment spring184through the flexible seal192. The rupture plates206are configured to fail when exposed to an external rupture pressure in the well152. The rupture pressure can be achieved by forcing fluids into the well152under elevated pressure. In exemplary embodiments, the rupture pressure is achieved by forcing a pressurized nitrogen mixture or other gas mixture into the well152. When the pressure in the well152exceeds the predetermined rupture pressure, the rupture plates152will fail, thereby opening the orifices208and placing the first chamber210in fluid communication with the well152. When the induced rupture pressure is released, the pressurized fluid in the first chamber210of the pressure housing200will be released through the orifices208into the well152. The pressure within the second chamber212creates a pressure gradient across the retraction piston202that forces the retraction piston202, retraction piston sleeve204and second end flange196outward to remove the compressive force on the flexible seal192. It will be appreciated that spring force captured in the expanded flexible seal192will assist in driving the retraction piston202into a retracted position.

As shown inFIG. 3C, the retraction piston202has been pushed outward and the flexible seal192has returned to an unstressed, collapsed state. In this condition, the collapsible packer164and velocity tube162can be more easily retrieved from the sand-impacted well152.

In a second embodiment depicted inFIGS. 4A-4C, the retraction assembly178is spring-driven and includes a retraction spring214in a retraction spring housing216. A first end of the retraction spring214is connected to a retraction spring piston218that is also connected to the flexible seal192. A second end of the retraction spring214is temporarily held in place by a shear pin220. It will be appreciated that a plurality of shear pins220can be used to secure the second end of the retraction spring214. The collapsible packer164may include a single retraction spring214or multiple deployment springs214within the retraction spring housing216.

During assembly, the shear pin220extends through the retraction spring housing216into the velocity tube162. The shear pin220prevents the second end of the retraction spring214from moving backward within the retraction spring housing216. When the deployment assembly176activates and exerts a compressive force on the flexible seal192, the retraction spring214is compressed against the shear pin220, as illustrated inFIG. 4B. In this deployed state, deployment spring182and retraction spring214provide balanced and offsetting forces that are calculated to force the flexible seal192to buckle outward against the well casing150.

When it is time to remove the subsurface pump154, it is pulled in a direction outward from the well152. Because the collapsible packer164remains expanded, it opposes the withdrawal of the velocity tube162. The movement of the velocity tube162relative to the stationary collapsible packer164creates a shear force about the shear pin220, which fails when exposed to shear stress that exceeds its maximum shear strength. Once the shear pin220fails, it allows the retraction spring214to expand within the retraction spring housing216, as shown inFIG. 4C. This reduces the compressive forces supplied by the retraction spring214and allows the flexible seal192to collapse. This facilitates the removal of the subsurface pump154from the well152.

Thus, the exemplary embodiments provide a method and mechanism for selectively installing, remotely expanding, remotely collapsing and retrieving a packer from a well. It is to be understood that even though numerous characteristics and advantages of various embodiments of the present invention have been set forth in the foregoing description, together with details of the structure and functions of various embodiments of the invention, this disclosure is illustrative only, and changes may be made in detail, especially in matters of structure and arrangement of parts within the principles of the present invention to the full extent indicated by the broad general meaning of the terms in which the appended claims are expressed. It will be appreciated by those skilled in the art that the teachings of the present invention can be applied to other systems without departing from the scope and spirit of the present invention.