Boring or penetrating the earth – Boring a submerged formation
Reexamination Certificate
2002-12-03
2004-11-30
Bagnell, David (Department: 3672)
Boring or penetrating the earth
Boring a submerged formation
C175S050000, C166S250100, C166S308100, C166S337000, C073S152220
Reexamination Certificate
active
06823950
ABSTRACT:
FIELD OF THE INVENTION
The present invention relates to a method for drilling and controlling a well drilled in an earth formation. More specifically, it relates to a method for controlling the creation of formation fractures and the propagation of such fractures into the earth formation.
BACKGROUND OF THE INVENTION
The production of hydrocarbons, i.e., oil and gas, from earth formations generally entails the drilling of one or more wells in the formation. A common component in drilling operations is the use of drilling fluid or mud. The drilling fluid is generally comprised of a water-based, synthetic-based or oil-based transport fluid and barite and other additives. The fluid is pumped down the drill pipe and is used to cool the drill bit and to remove drilling cuttings from the borehole. The cuttings are entrained in the fluid and returned to the surface by way of the annulus formed between the drill string and the borehole formation wall or casing. The cuttings are removed and the drilling fluid is treated to maintain density or other properties and then re-injected down the drill string. The drilling fluid serves the additional purpose of controlling the downhole formation pressure. The weight and density of the mud and the resulting hydrostatic pressure impart a positive pressure on the formation. This prevents formation fluids under pressure from leaving the formation, entering the borehole and causing a well event, such as a gas kick, which can result in a catastrophic blowout (worst case). The on-site supervisor (e.g. foreman) and mud engineer select the desired fluid density and add weighting agents (e.g. barite, hematite) as required to achieve the desired pressure control. However, the hydrostatic pressure can result in the mud permeating into the formation resulting in damage to the formation. It can also affect logging operations designed to characterize the formation. The addition of certain materials to the mud can be used to create a coating or mudcake or filter cake on the borehole wall preventing damage to the formation and fluid leak-off. Ideally, the drilling fluid density is selected such that the hydrostatic force is greater than the formation pore pressure but less than the formation fracture gradient. If the hydrostatic pressure is greater than the fracture gradient, then the drilling fluid would invade the formation, creating fractures therein. This also would result in a significant loss of drilling fluid to the formation.
The wells are generally drilled in stages or intervals. At the end of each interval, casing is set in the hole to support the hole and secure it. A cementing shoe is set in the casing and cement is pumped down the casing and returns up the annulus, displacing the drilling fluid in the annulus. The cement then isolates the outside of the casing from the formation in a successful cementing job. The drill string is used to drill through the cementing shoe and drilling operations begin for the next interval. Based on the formation pore pressure, the formation fracture gradient and the equivalent mud weight at various depths, one determines the depth of the intervals. Once an interval is complete, a smaller diameter casing string is run through the larger string and the process of cementing and drill thru is repeated.
The drilling fluid density is characterized in terms of its equivalent static density (equivalent static density), which is the density of the fluid when not circulated. The equivalent static density is affected by fluid compressibility as a result of the hydrostatic head, as well as downhole pressure and temperature. The drilling fluid is further characterized in terms of its equivalent circulating density (equivalent circulating density), the dynamic density of the fluid during circulation and/or rotation of the drillpipe. In addition to the factors that effect the equivalent static density, equivalent circulating density takes into account frictional losses in density due to circulation and pipe rotation.
While the objective is to maintain the fluid density between the formation pore pressure and formation fracture gradient, it is not always achieved. In order to understand how the formation reacts with the drilling fluid under both equivalent static density and equivalent circulating density conditions, a driller will perform a leak-off test (LOT), sometimes known as a casing shoe test (CST) or formation integrity test (FIT). The LOT is typically performed after an interval of casing has been run and cemented and prior to drilling a new interval. In many instances, regulations require an LOT upon setting of a new casing shoe. Alternatively, a LOT may be performed in an openhole environment, i.e. a section of hole drilled but not yet secured by a cemented casing string.
The procedure for carrying out a LOT commences with drilling out any cement left in the casing shoe and drilling a short length of new hole, on the order of 5-10 feet. Drilling and circulation is terminated and the annular blow out preventers (BOP) are closed on the drillpipe to isolate the drill string from (a) the cemented casing and (b) the newly drilled formation section. Drilling fluid is pumped down hole at low rates on the order of 0.25-1.0 barrels per min (bpm) and pressure measurements are made at the surface and/or using downhole pressure sensors.
The reaction of the formation to the increased pressures is depicted in FIG.
1
. The initial pressure profile is typically linear in nature and is attributable to the elastic deformation of the formation and the previously set casing as well as compression of the drilling fluid. As the pressure increases, the pressure response becomes non-linear. Presuming that the casing cement bond/seal and equipment pressure losses are not the cause for the deviation from linearity, it may be presumed that the point of non-linearity is the leak-off point or fracture opening point. This generally occurs when the tangential or hoop stress in the borehole exceeds the tensile strength of the formation. At this point, fractures are opened in the formation and the decrease in pressure can be attributed to the loss of fluid into the formation. Within this range, the fracture propagation is controlled, in that it requires additional pressure or energy to grow the formation fracture.
As pressure is increased further, the formation reaches a point where it breaks down. The fracture now continues to propagate without the need for any additional pressure or energy. The maximum pressure attained may be described as the unstable fracture growth pressure, whereas the pressure at which the fracture grows uncontrollably is described as the fracture propagation pressure. At this point, drilling fluid continues to be lost to the formation. When the pumping is stopped, the pressure will drop to a lower value known as the instantaneous shut-in pressure, at which point, fracture propagation will cease. The fractures will begin to close or deflate. This process can be accelerated by flowing drilling fluid back through the choke lines to decrease pressure. In
FIG. 1
, the pressure decline following instantaneous shut-in pressure is most probably due to increased frictional pressure or a decrease in fracture compliance during the fracture reduction/deflation. During this period drilling fluid flows back out of the formation into the borehole. The pressure continues to decrease steadily until it reaches a point where a rapid pressure drop is detected. This is characteristic of the mechanical closing of the fracture and is described as the fracture closure pressure, which is usually equated with the in-situ minimum horizontal formation stress. Though the fracture is described as “closed”, it may still exhibit significant permeability as a result being propped open by released formation materials or as a result of mismatches in the fracture faces.
If a second LOT is performed, again exhibiting the initial linear buildup, then the fracture opening pressure for the second test may occur at a pressure lower than the initial fracture opening p
Kotara, Jr. Ernest Benedict
Mayo George Herbert
Oort Eric van
von Eberstein, Jr. William Henry
Weaver Mark Allen
Bagnell David
Shell Oil Company
Stephenson Daniel P
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