FIELD OF THE INVENTION

This disclosure relates generally to oil or gas producing wells, and more particularly to deviated wells having a gas vent system for removing gas from the wellbore.

BACKGROUND

The use of directionally drilled wells to recover hydrocarbons from subterranean formations has increased significantly in the past decade. With advancements in drilling technology, it is now possible to accurately drill wells with multiple horizontal deviations. Horizontal wells are particularly prevalent in unconventional shale plays, where vertical depths may range up to about 10,000 feet with lateral sections extending up to another 10,000 feet with multiple undulations. The geometry of the wellbore along the substantially horizontal portion typically exhibits slight elevation changes, such that one or more undulations (i.e., “peaks” and “valleys”) occur. In at least some known horizontal wells, the transport of both liquid and gas phase materials along the wellbore results in unsteady flow regimes including terrain-induced slugging, such as gas slugging.

Fluids that have filled the wellbore in lower elevations impede the transport of gas along the length of the wellbore. This phenomenon results in a buildup of pressure along the length of the substantially horizontal wellbore section, reducing the maximum rate at which fluids can enter the wellbore from the surrounding formation. Continued inflow of fluids and gasses cause the trapped gas pockets to build in pressure and in volume until a critical pressure and volume is reached, whereby a portion of the trapped gas escapes past the fluid blockage and migrates as a slug along the wellbore. Furthermore, at least some known horizontal wells include pumps that are designed to process pure liquid or a consistent mixture of liquid and gas. Not only does operating the pump without pure liquids cause much lower pumping rates, but it may cause damage to the pump or lead to a reduction in the expected operational lifetime of the pump.

To cope with this type of terrain-induced slugging, one conventional technique includes the utilization of a gas vent tube, situated within the wellbore, that includes multiple mechanical valves distributed at various gas tube access points throughout the length of the wellbore. Each mechanical valve within the wellbore, for this conventional technique, is capable of remaining closed in the presence of liquid and opening passage to the gas tube vent in the absence of liquid. In this conventional manner, those mechanical valves located in a “valley” or at a relatively lower elevation horizontal wellbore undulation are configured to remain closed, preventing the ingress of liquid into the gas vent tube. On the other hand, those mechanical valves located at a “peak” or at a relatively higher elevation horizontal wellbore undulation are configured to automatically open to allow gas to enter the gas vent tube and escape to the surface. These mechanical valves may be passive valves or may be active valves that include one or more sensors (e.g., fluid sensors) to assist in determining the actuation of one or more valves. However, the reliability of mechanical valves, especially when thousands of feet under the surface, is problematic. Moreover, the utilization of active mechanical valves in a gas vent tube becomes even more cumbersome since a power supply and power delivery to each downhole active valve is required.

Similarly, another conventional technique includes replacing each mechanical valve with a gas-permeable membrane barrier that only allows the passage of gas, as opposed to liquid. The gas-permeable membrane may be pressure differential induced or merely allow gas molecules of particular sizes passage through the membrane. However, similar to a mechanical valve, gas-permeable membranes face reliability issues such as fouling (i.e., micro-passages for gas molecules become blocked by sand and debris) especially when situated in the harsh environment thousands of feet downhole. The pressure differentials across a gas-permeable membrane may also cause issues with reliability and purging the gas vent tube may require a much higher volume and pressure of gas due to purge gas leaking out of each gas-permeable membrane.

Thus, current methods reducing gas slugging in deviated wells has proven ineffective or undesirable. There is, therefore, a continued need for an improved gas slug avoidance system. It is to these and other deficiencies in the prior art that the present invention is directed.

SUMMARY OF THE INVENTION

In one aspect, the present invention includes a gas mitigation system for controlling the amount of gas that reaches a submersible pumping system deployed in a wellbore. The gas mitigation system includes a well zone isolation device disposed in the wellbore upstream from the submersible pumping system. The well zone isolation device includes an upstream side and a downstream side. The gas mitigation system further includes a back pressure control module and a gas vent line extending from the back pressure control module through the well zone isolation device. The back pressure control module is configured to maintain a gas collecting region adjacent the upstream side of the well zone isolation device. A liquid intake line extends through the well zone isolation device from an area of the wellbore adjacent the downstream side of the well zone isolation device to an area of the wellbore upstream from the gas collecting region.

In another aspect, the present invention includes a wellbore production system configured to efficiently produce liquid hydrocarbons from a wellbore. The wellbore production system includes a submersible pumping system deployed in the wellbore and a gas mitigation system. The gas mitigation system includes a well zone isolation device disposed in the wellbore upstream from the submersible pumping system. The well zone isolation device includes an upstream side and a downstream side. The gas mitigation system further includes a back pressure control module and a gas vent line extending from the back pressure control module through the well zone isolation device. The back pressure control module is configured to maintain a gas collecting region adjacent the upstream side of the well zone isolation device. A liquid intake line extends through the well zone isolation device from an area of the wellbore adjacent the downstream side of the well zone isolation device to an area of the wellbore upstream from the gas collecting region.

In yet another aspect, the present invention includes a method for mitigating gas slugging in a well in which a submersible pumping system is deployed. The method begins with the steps of installing a well zone isolation device in a region of the well upstream from the submersible pumping system, wherein the well zone isolation device includes a downstream side and an upstream side adjacent a gas collecting region. The method continue with the step of providing a liquid intake line that extends through the well zone isolation device from an area of the wellbore adjacent the downstream side of the well zone isolation device to an area upstream of the gas collecting region. The method also includes the step of providing a gas vent line that extends from a back pressure control module through the well zone isolation device to the gas collecting region. The method continues with the step of manipulating the back pressure control module to adjust the pressure of the gas in the gas vent line to maintain the volume and pressure of gas in the gas collecting region.

