Boring or penetrating the earth – Boring a submerged formation
Reexamination Certificate
2000-05-31
2003-12-30
Shackelford, Heather (Department: 3673)
Boring or penetrating the earth
Boring a submerged formation
C175S025000, C175S038000, C175S048000, C175S212000
Reexamination Certificate
active
06668943
ABSTRACT:
FIELD OF THE INVENTION
This invention relates generally to offshore well drilling operations. More particularly, the invention pertains to gas-lifted risers for use in drilling offshore wells. Specifically, the invention is a method and apparatus for controlling the riser base pressure and detecting well control problems, such as kicks or lost circulation, during drilling of an offshore well using a gas-lifted riser.
BACKGROUND OF THE INVENTION
In recent years the search for offshore deposits of crude oil and natural gas has been moving into progressively deeper waters. In deep waters, it is common practice to conduct drilling operations from floating vessels or platforms. The floating vessel or platform is positioned over the subsea wellsite and is equipped with a drilling rig and associated drilling equipment.
To conduct drilling operations from a floating vessel or platform, a large diameter pipe known as a “drilling riser” is typically employed. The drilling riser extends from above the surface of the body of water downwardly to a wellhead located on the floor of the body of water. The drilling riser serves to guide the drill string into the well and provides a return conduit for circulating drilling fluids.(also known as “drilling mud” or simply “mud”).
An important function performed by the circulating drilling fluids is well control. The column of drilling fluid contained within the wellbore and the drilling riser exerts hydrostatic pressure on the subsurface formation which overcomes formation pore pressure and prevents the influx of formation fluids into the wellbore, a condition known as a “kick.” However, if the column of drilling fluid exerts excessive hydrostatic pressure, the reverse problem can occur, i.e., the pressure of the drilling fluid can exceed the natural fracture pressure of one or more of the exposed (i.e., uncased) subsurface formations. Should this occur, the hydrostatic pressure of the drilling fluid could initiate and propagate a fracture in the formation, resulting in drilling fluid loss to the formation, a condition known as “lost circulation.” Excessive fluid loss to one formation can result in loss of well control in other formations being drilled, thereby greatly increasing the risk of a blowout. Thus, proper well control requires that the hydrostatic pressure of the drilling fluid adjacent an exposed formation be maintained above the formation's pore pressure, but below the formation's natural fracture pressure.
For a conventional offshore drilling system in which the drilling fluid contained in the wellbore and the drilling riser constitutes a continuous fluid column from the bottom of the well to the surface of the body of water, it is increasingly difficult, as water depth increases, to maintain the pressure of the drilling fluid in the wellbore between the formation pore pressure and the natural fracture pressure of the exposed formations. This problem is well known in the art. See, e.g., Lopes, C. A. and Bourgoyne, A. T., Jr.,
Feasibility Study of a Dual Density Mud System for Deepwater Drilling Operations
, OTC 8465, Offshore Technology Conference, May 5-8, 1997. Because of this problem, the allowable length of exposed borehole is severely limited and frequent installations of protective casing strings are required. This, in turn, results in longer times and higher costs to drill the well.
It has long been recognized that one solution to this problem is to maintain the drilling fluid pressure at the wellhead (i.e., at the elevation of the floor of the body of water) approximately equal to that of the surrounding seawater. This effectively eliminates the problems resulting from the fact that drilling fluid typically has a higher density than seawater. Several methods of accomplishing this have been proposed, including injection of a gas (“lift gas”) such as nitrogen into the lower end of the drilling riser. Lift gas injected into the drilling riser intermingles with the returning drilling fluid and reduces the equivalent density of the column of drilling fluid in the riser to that of seawater. The column of drilling fluid in the well below the lift gas injection point does not contain lift gas and, accordingly, is denser than the drilling fluid in the riser. Hence, this approach provides a “dual density” circulation system. U.S. Pat. No. 3,815,673 (Bruce et al.) discloses an example of such a “gas-lifted drilling riser” in which an inert gas is compressed, transmitted down a separate conduit, and injected at various points along the lower end of the drilling riser. Bruce et al. also disclose a control system responsive to the hydrostatic head of the drilling fluid which controls the rate of lift gas injection into the riser in order to maintain the hydrostatic pressure at the desired level.
U.S. Pat. No. 3,603,409 (Watkins) illustrates a variation of the gas-lifted drilling riser concept in which the drilling riser is replaced by a separate drilling fluid return conduit. The drill string enters the well through a rotating blowout preventer (BOP) located on top of the subsea wellhead, and alternate means for guiding the drill string into the well are provided. According to Watkins, lift gas is injected into the wellhead in an amount sufficient to cause the density of the drilling fluid in the separate return conduit to approximate the density of seawater.
Unfortunately, two major problems have prevented practical application of gas-lifted risers. The first is pressure control. Simulations and tests of the behavior of gas-lifted risers have shown that it is extremely difficult to maintain a constant value of the riser base pressure (p
rb
) due to unavoidable variations in the flow rate or density of the drilling fluid in the riser. An example of such unavoidable variation is the interruption of flow required to add a length (joint) of drill pipe to the drill string as the well is drilled deeper. Riser base pressure (p
rb
) is the integrated result of the varying density of the entire column of drilling fluid and lift gas in the riser and is particularly influenced by the rapidly expanding lift gas near the top of the riser. The effects on p
rb
of a momentary (i.e., two to three minutes) change in flow conditions at the base of a gas-lifted riser in 10,000 feet (3,048 meters) of water will persist for as long as about an hour and a half as the affected “packet” of drilling fluid and lift gas moves up the riser. The largest effect occurs as the mixture approaches the surface. Therefore, simply sensing p
rb
and adjusting the lift gas flow rate to respond to drilling fluid flow changes over intervals of several minutes leads to large instabilities in p
rb
.
The second major problem that has prevented practical application of gas-lifted risers is detection of well control problems such as kicks and lost circulation. It is well known that the most sensitive method of detecting kicks or lost circulation is to measure the rate of return flow of drilling fluid from the well and to compare it with the rate of flow of drilling fluid being pumped into the well via the drill pipe (see e.g., Maus, L. D., et al., Instrumentation Requirements for Kick Detection in Deep Water, Journal of Petroleum Technology, August 1979, pp. 1029-34). This may readily be accomplished provided the volume of fluid in the circulation system between the points of measurement of the input and return flow rates is constant or known. However, with a gas-lifted riser upstream of the return flow measurement point, there is the potential for unknown and varying volumes of fluid in the circulation system due to the presence of lift gas in the riser. This uncertainty significantly impedes the early detection of kicks or lost circulation.
In the late 1970s, two approaches to controlling gas-lifted drilling risers were proposed. U.S. Pat. No. 4,091,881 (Maus '881) envisioned diverting the return flow of drilling fluid from the upper portion of the drilling riser, through a throttling valve, and into a separate return conduit where the lift gas was injected. The rate
Ehrhardt Mark E.
Maus L. Donald
Van Acker Torney M.
Bell Keith A.
ExxonMobil Upstream Research Company
Jaramillo Nelson V.
Katz Gary P.
Kreck John
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