Measuring and testing – Borehole or drilling – During drilling
Reexamination Certificate
1999-11-19
2002-04-30
Williams, Hezron (Department: 2856)
Measuring and testing
Borehole or drilling
During drilling
C073S152540, C073S152510, C166S250010, C175S040000, C702S006000
Reexamination Certificate
active
06378363
ABSTRACT:
BACKGROUND OF THE INVENTION
1. Field of the Invention
The present invention provides an improved method for design and control of drilling operations.
2. Background of the Related Art
Wells are generally drilled to recover natural deposits of hydrocarbons and other desirable, naturally occurring materials trapped in geological formations in the earth's crust. A slender well is drilled into the ground and directed to the targeted geological location from a drilling rig at the surface. In conventional “rotary drilling” operations, the drilling rig rotates a drillstring comprised of tubular joints of drill pipe connected together to turn a bottom hole assembly (BHA) and a drill bit that is attached to the lower end of the drillstring. During drilling operations, a drilling fluid, commonly referred to as drilling mud, is pumped and circulated down the interior of the drillpipe, through the BHA and the bit, and back to the surface in the annulus. It is also well known in the art to utilize a downhole mud-driven motor, located just above the drill bit, that converts hydraulic energy stored in the pressurized drilling mud into mechanical power to rotate the drill bit.
To isolate geologic formations from the wellbore and to prevent collapse of the well, the well is generally cased with tubular pipe joints connected together with threaded connections to form a casing string. The casing string is generally installed in stages, a section of casing being installed in each stage. A section of casing generally comprises many connected joints of casing, all sections linked together to form the casing string.
Each section of casing is installed and cemented into place in the wellbore by circulating cement into the annular area defined by the outer surface of the section of casing and the inner bore wall of the wellbore. Casing sections are generally installed in successively decreasing diameters so that subsequent smaller diameter sections of casing can be installed and cemented in deeper portions of the well as drilling progresses. Installation of a section of casing requires the driller to remove the drillstring, including the BHA and the bit, from the well. The drillstring is removed from the well joint by joint in a time-consuming operation. Later, after the section of casing is cemented into place and the cement has sufficiently cured, the drillstring is again tripped into the well joint by joint before drilling operations can resume.
There is a strong cost-based incentive to maximize the length of each section of casing and to minimize the frequency of drilling rig downtime for tripping drillpipe out of and into the well. If the number of casing stages can be safely reduced using more accurate methods of assessing downhole conditions and estimating downhole pressures, then the well can be drilled faster and with considerably lower cost for the drilling rig and related support.
The pressure of porous and permeable geologic formation(s) is generally balanced by hydrostatic pressure applied by the column of drilling mud plus the pressure applied to or held on the well at the surface. Pressure may be applied in the drillstring by mud pumps to cause mud to circulate down the interior of the drillstring, through the bit and back up to the surface through the annulus. Drilling mud is designed to suspend and carry back to the surface small bits of rock called cuttings that are produced by the drilling process. Pressure may be held on the casing when the annulus is isolated from the atmosphere by closure of the blow-out preventers (BOPs) at the surface.
The driller generally controls hydrostatic pressures in the well by use of weighting agents added to the drilling mud to increase density. The driller generally controls the pressure on the well at the surface by activation or deactivation of the mud circulating pumps and by using the BOPs to isolate the annulus from the atmosphere. However, the driller cannot always control pressures occurring downhole at the formation because other factors affect the pressure applied to the formation at any given moment. These other factors include:
(a) pipe movement in the wellbore (rotation or reciprocation),
(b) temperatures and temperature gradients,
(c) pressure gradients and propagation rates of pressure fronts,
(d) viscosity and thixotropic properties of the drilling mud
(e) loading of cuttings from drilling, and
(f) fluid flows into and out of the wellbore.
Many types of geologic formations commonly encountered in drilling will fracture and fail if subjected to excessive pressure applied in the wellbore. Many types of fluid-bearing geologic formations are porous or permeable, and may either flow fluid into the wellbore or accept fluids from the wellbore. It is generally desirable to keep the pressure in the well adjacent to such formations above the pore pressure of porous formations and below the formation fracture pressure of exposed formations. This “window of safety” defined by the range of pressure between the pore pressure and the formation fracture pressure must be determined by the driller in order to design a safe and effective drilling plan and to make good decisions throughout the drilling process. Accurate determination of this window of safety directly effects the economic success of the drilling venture.
If the downhole pressure exceeds the formation fracture pressure, the region of the formation exposed to the downhole pressure will begin to physically break down and drilling mud will flow from the wellbore into the fractured formation at a rate determined by the extent of the fracture and the pressure differential. The resulting loss of overall height of the hydrostatic column of drilling mud can quickly result in inadequate well pressure at the formation. When this condition occurs, formation fluids, including gases, may enter the well from other formations in fluid communication with the well. This occurrence is commonly referred to as a kick. Once introduced into the wellbore, the gas migrates upwardly through the drilling mud towards the surface. The upwardly migrating gas expands as it encounters lower pressures, often forcing drilling mud to flow out of the well either at the surface or into formations in fluid communication with the well. This is a dangerous well control situation that must be avoided or responded to quickly. It is important that the driller avoids inadvertent fracturing of formations.
A well control situation can also develop if the pressure at the formation face falls below the pore pressure of fluids that may reside in porous formations. This well condition is commonly referred to as underbalanced. When the well is underbalanced, fluids from porous geologic formations that are in fluid communication with the well will flow into the well, displacing drilling mud upwardly towards the surface. As with the formation fracture, gas introduced through underbalanced conditions will also migrate to the surface and expand.
The “window of safety” or range of allowable downhole pressures may be defined by formation pore pressures (minimum) and the formation fracture pressure (maximum). Accurate determination of this window of safety has become increasingly important as technology has progressed and wells are drilled:
(a) in deep water locations where water temperature and depth affect changes in well design and dynamics,
(b) as higher formation pore pressures, or formations with lower fracture pressures are encountered,
(c) in extended reach wells drilled using directional drilling techniques,
(d) in wells with extremely slender boreholes with increased friction losses for required circulating mud pressures, and
(e) in extreme conditions of pressure and temperature, referred to as HPHT wells (high-pressure and high-temperature wells).
The driller can determine the pore pressure of fluid-bearing formations in a number of ways well known in the art. The driller can perform a leak-off test/formation integrity test (LOT/FIT) to test cement placed behind casing (LOT) and to test any exposed formation(s) to determine the p
Gzara Kais
Hache Jean-Michel
Rezmer-Cooper Iain
Ryberg John J.
Salazar Jennie (JL)
Schlumberger Technology Corporation
Wiggins David J.
Williams Hezron
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