Well control using pressure while drilling measurements

Details Well control using pressure while drilling measurements Well control using pressure while drilling measurements

2002-10-04

2004-11-09

Walker, Zakiya (Department: 3672)

Wells

Processes

With indicating, testing, measuring or locating

C166S250150, C175S048000

Reexamination Certificate

active

06814142

ABSTRACT:

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
Not applicable.
BACKGROUND OF THE INVENTION
The present invention relates generally to methods and apparatus for controlling borehole pressure in wells. More specifically, the present invention relates to methods and apparatus employing continuous real-time pressure while drilling measurements to bring borehole pressure back into control after borehole pressure is below pore pressure or greater than fracture pressure.
A drilling fluid is typically used when drilling a well. This fluid has multiple functions, one of which is to provide pressure in the open wellbore in order to prevent the influx of fluid from the formation. Thus, the pressure in the open wellbore is typically maintained at a higher pressure than the fluid pressure in the formation pore space (pore pressure). The influx of formation fluids into the wellbore is called a kick. Because the formation fluid entering the wellbore ordinarily has a lower density than the drilling fluid, a kick will potentially reduce the hydrostatic pressure within the well and allow an accelerating influx of formation fluid. If not properly controlled, this influx is known as a blowout and may result in the loss of the well, the drilling rig, and possibly the lives of those operating the rig. Therefore, when formation fluid influx is not desired (almost always the case), the formation pore pressure defines a lower limit for allowable wellbore pressure in the open wellbore, i.e. uncased borehole.
The open wellbore extends below the lowermost casing string, which is cemented to the formation at, and for some distance above, a casing shoe. In an open wellbore that extends into a porous formation, deposits from the drilling fluid will collect on wellbore wall and form a filter cake. The filter cake forms an important barrier between the formation fluids contained in the permeable formation at a certain pore pressure and the wellbore fluids that are circulating at a higher pressure. Thus, the filter cake provides a buffer that allows wellbore pressure to be maintained above pore pressure without significant losses of drilling fluid into the formation.
In order to maximize the rate of drilling, it is desirable to maintain the wellbore pressure at a level above, but relatively close to, the pore pressure. As wellbore pressure increases, drilling rate will decrease, and if the wellbore pressure is allowed to increase to the point it exceeds the formation fracture pressure (fracture pressure), a formation fracture can occur. Once the formation fractures, returns flowing in the annulus may exit the open wellbore thereby decreasing the fluid column in the well. If this fluid is not replaced, the wellbore pressure can drop and allow formation fluids to enter the wellbore, causing a kick and potentially a blowout. Therefore, the formation fracture pressure defines an upper limit for allowable wellbore pressure in an open wellbore. Typically, the formation immediately below the casing shoe has the lowest fracture pressure in the open wellbore, and therefore it is the fracture pressure at this depth that controls the maximum annulus pressure.
The fracture pressure is determined in part by the overburden acting at a particular depth of the formation. The overburden includes all of the rock and other material that overlays, and therefore must be supported by, a particular level of the formation. In an offshore well, the overburden includes not only the sediment of the earth but also the water above the mudline. The density of the earth, or sediment, provides an overburden gradient of approximately 1 psi per foot. The density of seawater provides an overburden gradient of approximately 0.45 psi/ft. The pore pressure at a given depth is determined in part by the hydrostatic pressure of the fluids above that depth. These fluids include fluids within the formation below the seafloor/mudline plus the seawater from the seafloor to the sea surface. A formation fluid gradient of 0.465 psi/ft is often considered normal. The typical seawater pressure gradient is about 0.45 psi/ft.
In surface and shallow water wells the differential in gradient between the seawater (or groundwater) and the earth often creates a pore pressure profile and fracture pressure profile that provide a sufficient range of pressure to allow the use of conventional drilling techniques.
FIG. 1
shows a schematic representation of pore pressure PP and fracture pressure FG. The pressure developed in the wellbore is essentially determined by the hydrostatic pressure of the wellbore fluid, along with pressure variations due to fluid circulation and/or pipe movement. For any given open hole interval, the region of allowable pressure lies between the pore pressure profile, and the fracture pressure profile for that portion of the well between the deepest casing shoe and the bottom of the well.
Clean drilling fluid is circulated into the well through the drill string and then returns to the surface through the annulus between the wellbore wall and the drill string. In offshore drilling operations, a riser is used to contain the annulus fluid between the sea floor and the drilling rig located on the surface. The pressure developed in the annulus is of particular concern because it is the fluid in the annulus that acts directly on the uncased borehole.
The fluid flowing through the annulus, typically known as returns, includes the drilling fluid, cuttings from the well, and any formation fluids that may enter the wellbore. The drilling fluid typically has a fairly constant density and thus the hydrostatic pressure in the wellbore vs. depth can typically be approximated by a single gradient starting at the top of the fluid column. In offshore drilling situations, the top of the fluid column is generally the top of the riser at the surface platform.
The pressure profile of a given drilling fluid varies depending upon whether the drilling fluid is being circulated (dynamic) or not being circulated (static). These two pressure profiles are represented by the static pressure SP and dynamic pressure DP profiles on FIG.
1
. In the dynamic case, there is a pressure loss as the returns flow up the annulus between the drill string and wellbore wall. This pressure loss adds to the pressure of the drilling fluid in the annulus. Thus, this additional pressure must be taken into consideration to ensure that drilling is maintained in an acceptable pressure range between the pore pressure gradient and fracture pressure gradient profile.
Because the dynamic pressure DP is higher than the static pressure SP, it is the dynamic pressure at the highest point in the uncased wellbore, i.e. the lowermost casing shoe, that is limited by the fracture pressure FG at depth D
1
. Correspondingly, the lower static pressure SP must be maintained above the pore pressure PP at the deepest point D
2
in the open wellbore. Therefore, the range of allowable pressures for a certain length of uncased wellbore L
1
, as shown in
FIG. 1
, is limited by the dynamic pressure DP reaching fracture pressure FG at the casing shoe depth D
1
and the static pressure SP reaching pore pressure PP at the bottom of the well D
2
.
Thus, in common drilling practice, the density of the drilling fluid will be chosen so that the dynamic pressure is as close as is reasonable to the fracture pressure at the casing shoe. This maximizes the depth that can then be drilled using that density fluid. Once the static pressure approaches pore pressure at the bottom of the well, another string of casing will be set and the same process repeated. Even when using conservative drilling techniques, the wellbore pressure may fall out of the acceptable range between pore pressure and fracture pressure and cause a kick. A kick may be recognized by drilling fluids flowing up through the annulus after pumping is stopped. A kick may also be recognized by a sudden increase of the fluid level in the drilling fluid storage tanks. After a kick has been detected, steps must be taken to control the kick.
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