A typical system for drilling an oil or gas wellbore has a tubular drill pipe, known as a “drill string” and a drill bit located at the lower end of the drill string. During drilling, the drill bit is rotated to remove formation rock, and drilling fluid called “mud” is circulated through the drill string to remove thermal energy from the drill bit and remove debris generated by the drilling.
Typically, care is exercised during drilling to prevent downhole pressure exerted by the drilling mud from exceeding a fracture initiation pressure of the formation. More specifically, if the downhole pressure that is exerted by the drilling mud exceeds the fracture initiation pressure, the formation exposed to this pressure begins to physically break down and allow mud to flow into the fractured formation. Such a condition may result in damage to the formation in addition to creating a hazardous drilling environment. Therefore, after the lower bullnose end of the most recent installed casing string segment, known as the “casing shoe” is installed, a formation integrity test (FIT) or a “leak off test” (LOT) may be performed.
Mud pulse telemetry modulates the circulating mud flow to communicate information to the surface. Communication using mud pulse telemetry, however, provides infrequent measurements to the surface, and the measurements are only available when the mud pumps produce an adequate flow rate of the drilling mud. The flow rate of the drilling mud is insufficient to convey the measurements during some operations, such as a FIT, a LOT, or formation fluid flow check (FC) and a formation stress test (FST).
A FIT determines if the formation below the most recently installed casing section will be broken by drilling the next section with higher bottom hole pressure. A FIT also tests the integrity of the cementing of the most recently installed casing section. A LOT determines the fracture initiation pressure for the next segment of the wellbore to be drilled.
During a FIT, the pumping of the drilling mud continues until either a predetermined bottomhole pressure is reached or the loss of drilling mud into the formation is detected. More specifically, a FIT test will stop when one of two conditions has been met, the maximum mud weight expected for the next wellbore section has been achieved, or the pressure as a function of volume pumped curve indicates initiation of a fracture by exhibiting a change in slope. The point in the pressure as a function of volume pumped curve that indicates initiation of a fracture by exhibiting a change in slope is known as a fraction initiation point (FIP). The pressures and flow rates associated with the FIT/LOT typically are measured using sensors located at the surface of the wellbore. The results of the FIT/LOT indicate the maximum pressure or mud weight that may be applied to the next segment of the wellbore during drilling operations.
A FIT is less accurate than a LOT in determining the maximum pressure that can be safely applied to the formation at the casing shoe. However, a FIT is typically performed instead of a LOT for several reasons. First, the formation may be damaged by a LOT inducing a full far field hydraulic fracture. Second, the surface pressure that is monitored by a FIT or a LOT is not representative of the downhole pressure. Third, the time required for a LOT is greater than the time required for a FIT. Deep water wellbores have a high cost of rig operations; therefore, the time consumed by a LOT may be an especially important factor for deep water wellbores.
The FIT determination of the maximum pressure that may be applied to the next segment of the wellbore, namely the FIP, will always be below the maximum mud weight that may be safely applied to the next segment of the wellbore. The maximum mud weight to use while drilling the formation below the casing shoe is not determinable by current industry practices. Current industry practice is to determine the FIP and/or pressure at which the pump is stopped for the FIT, namely the pump stop pressure (PSP).
FIG. 1 generally illustrates a graph 10 of bottom hole pressure as a function of volume of drilling mud pump and then elapsed time in a LOT (SPE/IADC 105193, “Improving Formation Strength Tests and Their Interpretation,” Eric Van Oort and Richard Cargo, 2007 SPE/IADC Drilling Conference). The FIP and the PSP are determined using a volume of drilling mud pumped as a function of time pumped plot, such as the plot depicted in the first test cycle of FIG. 1. When the curve deviates from a straight line representing fluid compressibility, the corresponding pressure is considered the FIP point.
A typical FIT ends at the PSP point or shortly thereafter. In contrast, an extended LOT has at least the first test cycle shown in FIG. 1. A FIT may conclude several minutes after pumping initiates, but an extended LOT may conclude several hours after pumping initiates. An extended LOT is primarily used when the fracture closure pressure (FCP) is of interest. FIG. 1 demonstrates that the FCP is determined by an extended LOT after the FIT would be concluded.
The FCP is less than the maximum mud weight that may be applied to the next segment of the wellbore as determined using the FIP or the uncontrolled fracture pressure (UFP) point. When the mud pressure reaches the FCP, the fracture will re-open. Because the mud pressure at which the fracture will re-open is below the maximum mud weight indicated by the FIP or the UFP, the LOT is disfavored and is performed disproportionately less relative to FIT tests.
Real-time downhole pressure measurements are lacking during a LOT, because mud pulse telemetry is unavailable during a LOT. Use of surface pressures compromises the accuracy of the determination of the formation integrity strength for multiple reasons.
First, the pressure at the casing show is estimated from the static surface mud weight measurement. If the properties of the drilling mud are not uniform or the drilling mud has suspended cuttings, this estimation is erroneous. The circulation time needed to achieve uniform drilling mud properties requires more time than the time which lapses during a FIT. Second, the compressibility, the frictional losses, and the actual temperature profile of the drilling mud affect the actual downhole pressure vs. time plot. Surface measurements cannot properly account for the compressibility, the frictional losses, and the actual temperature profile of the drilling mud. Third, the cementing unit pressure gauges used for measuring the surface pressures are less accurate than typical downhole gauges. For example, see SPE/IADC 59123, “Real-Time Formation Integrity tests Using Downhole Data,” Rezmer-Cooper et al., 2000 IADC/SPE Drilling Conference. Fourth, the use of a linear pressure vs. volume of drilling mud pumped plot does not accurately determine when the fluid compressibility effects end.
FIG. 2 generally illustrates a graph 20 of pressure as a function of time in a LOT when both surface pressure and annular pressure while drilling were measured as a function of time. The graph has a first curve 21 which is a plot of the surface pressure while drilling as a function of time. The graph has a first curve 21 which is a plot of the surface pressure while drilling as a function of time. In addition, the graph has a second curve 22 which is a plot of the annular pressure while drilling as a function of time. FIG. 2 demonstrates that the surface pressure is not merely a simple offset from the downhole pressure but varies as the pressure increases for the reasons previously set forth herein. Comparisons of downhole and surface pressure data recorded during LOT's indicate that the previously identified reasons for inaccuracy in determination of formation integrity strength typically result in errors of 0.5 ppg to 1.0 ppg and occasionally result in errors as high as 2.5 ppg. Therefore, the use of surface pressure creates a large uncertainty in formation integrity strength calculations and compromises the design of the wellbore.