Wells – Processes – Placing or shifting well part
Reexamination Certificate
2002-05-10
2003-12-23
Dang, Hoang (Department: 3672)
Wells
Processes
Placing or shifting well part
C166S320000, C166S323000, C166S327000
Reexamination Certificate
active
06666273
ABSTRACT:
BACKGROUND OF THE INVENTION
1. Field of the Invention
The present invention relates to a valve assembly for use in a wellbore. More particularly, the invention relates to a valve assembly that allows fluid flow to pass through the valve in either direction. More particularly still, the invention relates to a dual purpose valve assembly for controlling the fluid flow during installation of a casing in a wellbore and subsequently for use as float equipment to facilitate the injection of zonal isolation fluids.
2. Description of the Related Art
Hydrocarbon wells are conventionally formed one section at a time. Typically, a first section of wellbore is drilled in the earth to a predetermined depth. Thereafter, that section is lined with a tubular string, or casing, to prevent cave-in. After the first section of the well is completed, another section of well is drilled and subsequently lined with its own string of tubulars, comprised of casing or liner. Each time a section of wellbore is completed and a section of tubulars is installed in the wellbore, the tubular is typically anchored into the wellbore through the use of a wellbore zonal isolation fluid, like cement. Zonal isolation includes the injection of cement into an annular area formed between the exterior of the tubular string and the borehole in the earth therearound. Zonal isolation protects the integrity of the wellbore and is especially useful to prevent migration of hydrocarbons towards the surface of the well via the annulus.
Zonal isolation methods of string are well known in the art. Typically, the cement fluid is pumped down in the tubular and then forced up the annular area toward the surface. By using a different fluid above a column of the cement, the annulus can be completely filed with cement while the wellbore is substantially free of cement. Any cured cement remaining in the wellbore is drillable and is easily destroyed by subsequent drilling to form the next section of wellbore.
Float shoes and float collars facilitate the cementing of tubular strings in a wellbore. In this specification, a float shoe is a valve-containing apparatus disposed at or near the lower end of the tubular string to be cemented into in a wellbore. A float collar is a valve-containing apparatus that is installed at some predetermined location, typically above a shoe within the tubular string. In certain cases, float collars are required rather than float shoes. However, in this specification, the term float shoe and float collar will be used interchangeably.
The main purpose of a float shoe is to facilitate the passage of cement from the tubular to the annulus of the well while preventing the cement from returning or “u-tubing” back into the tubular due to gravity and fluid density of the liquid zonal isolation fluids. In its most basic form, the float shoe includes a one-way valve permitting fluid to flow in one direction through the valve, but preventing fluid from flowing back into the tubular from the opposite direction. The float shoes usually include a cone-shaped nose to prevent binding of the tubular string during run-in.
Typically, wellbores are full of fluid to protect the drilled formation of the borehole and aid in carrying out cuttings created by a drill bit. When a new string of tubulars is inserted into the wellbore, the tubulars must necessarily be filled with fluid to avoid buoyancy and equalize pressures between the inside and the outside of the tubular. For these reasons, a float shoe should have the capability to temporarily permit fluid to flow inwards from the wellbore as the tubular string is run into the wellbore and fills the tubular string with fluid. In one simple example, a springloaded, normally closed, one-way valve in a float shoe is temporarily propped in an open position during run-in of the tubular by a drillable object, which is thereafter destroyed and no longer affects the operation of the valve.
Other, more sophisticated solutions have been the use of a differential fill valve. The differential fill valve allows filling of the tubular and circulation by utilizing the differential pressure between the inner and the outer annulus of the tubular. Typically, the prior art differential fill valve comprises a first and second flapper valve and a sleeve. The flapper valves are bias closed by a spring. The sleeve is secured in place by shear pins and is shiftable from a first to a second position. In operation, the differential fill valve is disposed on the end of the first string of tubular then inserted into the wellbore. During run-in the sleeve is in the first position, which prevents the second flapper valve from operating. As subsequent strings of tubulars are inserted into the wellbore the first flapper valve in the differential flow valve opens and closes based upon the differential pressure, thereby allowing wellbore fluid to enter the tubular string. The volume of wellbore fluid entering the tubular string is predetermined to achieve a differential height between the wellbore fluid inside the tubular annulus and the wellbore fluid outside the tubular. The amount of fluid entering the tubular through the flapper valve is controlled by a spring selected to bias the first flapper valve closed. The process of allowing a predetermined volume to enter the tubular is what is commonly called in the industry as differentially filling the tubular.
After the entire string of tubulars is disposed downhole, the differential fill capability of the valve is deactivated to change the valve into a one-way check valve. Typically, deactivation is accomplished by dropping a weighted ball from the surface down the wellbore either by free-fall or pumped in by a fluid mechanism allowing the ball to land into the sleeve. At a predetermined pressure the pins that secure the sleeve in the first position shear and the sleeve is shifted axially downward to a second position. In the second position, the sleeve closes the first flapper valve and subsequently allows the second flapper valve to operate. The deactivated differential fill valve functions as a standard float valve as described in the above paragraphs.
There are several problems associated with the prior art devices. One problem occurs while dropping the weighted ball to deactivate the differential fill feature in a deviated wellbore (deviations greater than 30 degrees from vertical). Typically, the ball is allowed to drop free-fall or pumped into a ball seat located in a sleeve. After the ball lands in the ball seat, drilling fluid is pressurized to act against the ball seat to shift the sleeve to a second position, thereby allowing a permanent check valve mechanism to engage. The reliability of actuating balls in a deviated wellbore greater than 30 degrees decreases as the deviation increases. Additionally, actuating balls in a horizontal, or near horizontal (70 to 90 degrees) well become ineffective in performing their required function, which leads to an inoperable downhole tool.
Another problem associated with the prior art devices arises when the tool is no longer needed to facilitate the injection of cement and must be removed from the wellbore. Rather than de-actuate the tool and bring it to the surface of the well, the tool is typically destroyed with a rotating milling or drilling device. Generally, the tool is “drilled up” or reduced to small pieces that are either washed out of the wellbore or simply left at the bottom of the wellbore. As in the case with the prior art devices that comprise of many metallic components numerous trips in and out of the wellbore are required to replace worn out mills or drill bits. This process is time consuming and results in lost productivity time.
Another problem with the prior art devices is the inability to operate in high downhole pressures and temperatures. Typically, as the depth of the wellbore increases both downhole pressure and temperature also increase. The prior art devices having a flapper valve design cannot operate effectively in pressures in excess of 3,000 PSI. Additionally, the prior art devices can
Dang Hoang
Moser, Patterson & Sheridan L.L.P.
Weatherford / Lamb, Inc.
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