Subsurface valves are typically installed in strings of tubing deployed to subterranean wellbores to prevent the escape of fluid, from one production zone to another and/or to the surface. Possible applications of the embodiments of the present disclosure relate to all types of valves. For purposes of illustration this application discloses, as an example, safety valves used to shut in a well in the absence of continued hydraulic pressure from the surface. This example should not be used to limit the scope of the disclosure for non safety valve applications which may be readily apparent from the disclosure made herein to a person having ordinary skill in this art.
Without a safety valve, a sudden increase in downhole pressure can lead to catastrophic blowouts of production and other fluids into the atmosphere. For this reason, drilling and production regulations throughout the world require placement of safety valves within strings of production tubing before certain operations can be performed.
Various obstructions exist within strings of production tubing in subterranean wellbores. Valves, whipstocks, packers, plugs, sliding side doors, flow control devices, landing nipples, and dual completion components can obstruct the deployment of capillary tubing strings to subterranean production zones. Particularly, in circumstances where stimulation operations are to be performed on non-producing hydrocarbon wells, the obstructions stand in the way of operations that are capable of obtaining continued production out of a well long considered “depleted.” Most depleted wells are not lacking in hydrocarbon reserves, rather the natural pressure of the hydrocarbon-producing zone is insufficient to overcome the hydrostatic pressure or head of the production column. Often, secondary recovery and artificial lift operations will be performed to retrieve the remaining resources, but such operations are often too complex and costly to be performed on a well. Fortunately, many new systems enable continued hydrocarbon production without costly secondary recovery and artificial lift mechanisms. Many of these systems utilize the periodic injection of various chemical substances into the wellbore to stimulate the production zone thereby increasing the production of marketable quantities of oil and gas. However, obstructions in a producing well often stand in the way to deploying an injection conduit to the production zone so that the stimulation chemicals can be injected. While many of these obstructions are removable, they are typically components required to maintain production of the well and permanent removal is not feasible. Therefore, a mechanism to work around them would be highly desirable.
One of the most common of these obstructions found in production tubing strings are subsurface safety valves. Subsurface safety valves are typically installed in strings of tubing deployed to subterranean wellbores to prevent the escape of fluids from one zone to another. Frequently, subsurface safety valves are installed to prevent production fluids from blowing out of a lower production zone either to an upper zone or to the surface. Absent safety valves, sudden increases in downhole pressure can lead to disastrous blowouts of fluids into the atmosphere or other wellbore zones. Therefore, numerous drilling and production regulations throughout the world require safety valves within strings of production tubing before many operations are allowed to proceed.
Safety valves allow communication between zones under regular conditions and are typically designed to close when undesirable downhole conditions exist. One popular type of safety valve is commonly referred to as a flapper valve. Flapper valves typically include a closure member generally in the form of a circular or curved disc that engages a corresponding valve seat to isolate zones located above and below the flapper in the subsurface well. A flapper disc is preferably constructed such that the flow through the flapper valve seat is as unrestricted as possible. Flapper-type safety valves are typically located within the production tubing and isolate production zones from upper portions of the production tubing. Optimally, flapper valves function as high-clearance check valves, in that they allow substantially unrestricted flow therethrough when opened and completely seal off flow in at least one direction when closed. Particularly, production tubing safety valves prevent fluids from production zones from flowing up the production tubing when closed but still allow for the flow of fluids (and movement of tools) into the production zone from above.
Flapper valve disks are often energized with a biasing member (spring, hydraulic cylinder, etc.) such that in a condition with zero flow and with no actuating force applied, the valve remains closed. In this closed position, any build-up of pressure from the production zone below will thrust the flapper disc against the valve seat and act to strengthen any seal therebetween. During use, flapper valves are opened by various methods to allow the free flow and travel of production fluids and tools therethrough. Flapper valves may be kept open through hydraulic, electrical, or mechanical energy during the production process.
Non-limiting examples of subsurface safety valves can be found in U.S. Provisional Patent Application Ser. No. 60/593,216 filed Dec. 22, 2004 by Tom Hill, Jeffrey Bolding, and David Smith entitled “Method and Apparatus of Fluid Bypass of a Well Tool”; U.S. Provisional Patent Application Ser. No. 60/593,217 filed Dec. 22, 2004 by Tom Hill, Jeffrey Bolding, and David Smith entitled “Method and Apparatus to Hydraulically Bypass a Well Tool”; U.S. Provisional Patent Application Ser. No. 60/522,360 filed Sep. 20, 2004 by Jeffrey Bolding entitled “Downhole Safety Apparatus and Method”; U.S. Provisional Patent Application Ser. No. 60/522,500 filed Oct. 6, 2004 by David R. Smith and Jeffrey Bolding entitled “Downhole Safety Valve Apparatus and Method”; and U.S. Provisional Patent Application Ser. No. 60/522,499 filed Oct. 7, 2004 by David R. Smith and Jeffrey Bolding entitled “Downhole Safety Valve Interface Apparatus and Method”. Each of the above references is hereby incorporated by reference in its entirety.
One popular means to counteract the closing force of the biasing member and any production flow therethrough involves the use of capillary tubing to operate the safety valve flapper through hydraulic pressure. Traditionally, production tubing having a subsurface safety valve mounted thereto is disposed in a wellbore to a depth of investigation. In this circumstance, the capillary tubing used to open and shut the subsurface safety valve is deployed in the annulus formed between the outer surface of the production tubing and the inner wall of the borehole or casing. A fitting outside of the subsurface safety valve connects to the capillary tubing and allows pressure in the capillary to operate the flapper of the safety valve. Furthermore, because former systems were run with the production tubing, installations after the installation of production tubing in the wellbore are evasive. To accomplish this, the production tubing must be retrieved, the safety valve installed, the capillary tubing attached, and the production tubing, safety valve, and capillary tubing assembly run back into the hole. This expense and time consumed are such that it can only be performed on wells having a long-term production capability to justify the expense.
The present disclosure generally relates to hydrocarbon producing wells where production of the well can benefit from continuous injection of a fluid. More specifically, injection of a fluid from the surface through a small diameter, or capillary, tubing. Exemplary, non-limiting applications of fluid injection are: injection of surfactants and/or foaming agents to aid in water removal from a gas well; injection of de-emulsifiers for production viscosity control; injection of scale inhibitors; injection of inhibitors for asphaltine and/or diamondoid precipitates; injection of inhibitors for paraffin deposition; injection of salt precipitation inhibitors; injection of chemicals for corrosion control; injection of lift gas; injection of water; injection of hydraulic oil, such as through a stinger, to operate a wireline valve (as will be described in greater detail with respect to FIGS. 9A and 9B below) and injection of any production-enhancing fluid. Further production applications include the insertion of a tubing string hanging from a wireline retrievable surface controlled subsurface safety valve for velocity control.
Many wells throughout the world have surface controlled subsurface safety valves (“SCSSV”) installed in the production tubing, and such valves are well known by those of ordinary skill in the art of completion engineering and operation of oil and gas wells. SCSSVs fall into two generic types: tubing retrievable (“TR”) valves and wireline retrievable (“WR”) valves.
TR valves are attached to the production tubing and are deployed and removed from the well by deploying or removing the production tubing from the well. Removing the production tubing is typically cost prohibitive because a drilling rig must be mobilized, which can cost the operator of the well millions of dollars.
In sharp contrast, WR valves are deployed by wireline or slickline. Deploying WR valves via wireline or slickline is typically significantly less expensive to deploy and retrieve than TR valves. WR valves can also be referred to as “insert valves” because they can be adapted to be inserted inside either a TR valve or a hydraulic nipple in situ. Additionally, WR valves can be removed without removal of the production tubing. The actual method of deployment for WR valves is not critical to the claimed invention. Deployment methods utilizing slickline, wireline, coiled tubing, capillary tubing, or work string can be used in conjunction with the claimed invention. For the purposes of this patent, WR shall be used to describe any valve that is not a TR valve.
Because SCSSVs are a critical safety device used in virtually all modern wells, the manufacture and design of SCSSVs is controlled by the American Petroleum Institute (“API”). The current controlling specification published by API for SCSSVs is API-14a. While API-14a provides design and manufacture guidance for current SCSSVs, embodiments of the present disclosure can be adapted to incorporate new features or specifications required by future specifications that control the design and manufacture of SCSSVs.
API-14a currently requires certification testing, typically performed by a third party. In addition to the testing required by API-14a, valve manufacturers generally require a rigorous series of testing of new valve designs which can entail weeks or even months of in-house testing. The significant testing requirements imposed by API-14a and by manufacturers can result in newly designed SCSSVs taking months or even years to develop and perfect and can often cost manufacturers hundreds of thousands of dollars.
A new apparatus and method of use has been developed that solves the problems inherent with the prior art. The bypass passageway apparatus described herein has been adapted to work in concert with the invention described in U.S. Provisional Application Ser. No. 60/595,137, filed Jun. 8, 2005 by Jeffrey Bolding and Thomas Hill entitled “Wellhead Bypass Method and Apparatus”, a copy of which is hereby incorporated by reference as if set out fully herein. Although the bypass passageway apparatus described herein is compatible with the above invention, the bypass passageway apparatus of the present application can be used without the benefit of the Wellhead Bypass Method and Apparatus.
The bypass passageway apparatus enables a production-stimulating fluid to be injected into a wellbore using capillary tubing while maintaining the operation of a safety valve. As the demand for the bypass passageway apparatus is expected to be extremely high, there is a need for a means to convert existing certified designs to the bypass passageway apparatuses of the present application. For simplification, a WRSCSSV that has been converted to a bypass passageway apparatus shall be referred to as an “enhanced WRSCSSV”.
The present application discloses a conversion kit that enables a WRSCSSV to be converted to a bypass passageway apparatus. In addition, the present application discloses an enhanced WRSCSSV adapted to hang tubing. The present application also discloses a method for performing artificial lift using a bypass passageway apparatus. Finally, the present application discloses a method of injecting a production-enhancing fluid into a well while maintaining safety valve operation using a bypass passageway apparatus.