Well Design Review
Well Design Review
There are occasions when operators want to hear K&M Technology Group’s assessment after the well design is already in progress and sometimes, even when finalized. This may happen because they realize the complexity of the well as the design advances or just because they need an expert’s second opinion. Under these circumstances, with the spud planned to be in a few months, it may not be too much time to get a different rig, get a different casing size, or import specialty tools.
In other occasions, the operator may have worked with K&M in performing a Mechanical Feasibility Analysis and may have even planned and drilled other wells with K&M’s support. Now, there is a new design that needs to be reviewed because it has different conditions as the previous wells: perhaps the new well is longer, has a higher inclination, or reaches a different reservoir TVD.
At this stage, K&M can perform a Well Design Review (WDR) to evaluate the existing design, identify risks and provide recommendations to deliver the well successfully within the hydraulic and mechanical limitations of the rig, tubular and anticipated geology. But even more important, K&M can help identify the best practices for drilling, tripping, or running casing/completions to mitigate any hazard identified with the current well design.
If K&M has not been involved in the design or execution of wells in the same field or pad, it is strongly recommended to perform an Offset Well Review (OWR) to calibrate the hydraulics, torque, and drag models to understand the local hazards and drilling conditions, and to evaluate the existing well construction practices.
A common recommendation from the Well Design Review is related to the specific hole cleaning parameters and drilling fluid properties.
Figure 1: ECD Gauge plots showing the ECD felt at TD when the drill string is POOH. The left plot uses the original proposed mud properties, the right plot uses the new, K&M proposed ones. In the latter case, it is possible to trip in elevators without causing swabbing related wellbore instability
An operator was planning a longer ERD well and requested K&M support. The analysis showed that using the originally planned mud properties, the swab ECD would create an unacceptable wellbore instability problem if it was lower than 9.5 ppg EMW. The existing design would have created problems tripping and running casing unless back reaming was applied in a long portion of the well, including the cased hole. K&M reviewed the hole cleaning requirements, the wellbore stability mud weight window and proposed different fluid properties.
Under these recommendations, pulling the string out of the hole was possible on elevators without changing casing or drill string sizes which would have been difficult at the existing design stage without compromising the hole cleaning requirements of the section.
In a deepwater drilling campaign, running the lower completion in a high angle production hole section and displacing the drilling fluid to completion fluid within a narrow mud weight window are challenging operations. In each of the wells, K&M reviewed the well design and recommended a drill string configuration that would allow drilling and tripping with minimum variations in the drilling ECD, surge, and swab to avoid having losses or induced wellbore instability. K&M also proposed a pumping schedule to ensure the ECD will not exceed the losses gradient and the differential pressure at the packer not exceeding its rated limit. In one of the wells, the mud weight window was too narrow that the pumping schedule has to include the pump rate and the MPD
Figure 2: ECD Snapshot in the lateral at an initial stage of the displacement with MPD backpressure sensitivity.
backpressure to ensure that the ECD at the lateral toe will not exceed the losses gradient, and the ECD at the tail will not be below the collapse gradient.
A critical aspect of the torque and drag analysis is the determination of the maximum overpull and the weakest point of the drill string. In high angle wells, the apparent overpull at the surface is larger than the actual overpull at the bit Or elsewhere in the well. This is because the
Figure 3: Tension snapshots of a Liner run at 18,500’ and 20,500’ (well TD). The gray lines show the pick-up tensional loads without overpull and the color lines show the loads at the maximum overpull for that depth. As can be seen, the actual overpull at the shoe is less than the apparent overpull at the surface. Also, the weakest element at the shallower depth is the drill pipe at ~6,900’, but at TD, the weakest element is the drill pipe at surface.
weakest point is not necessarily the drill pipe at the surface. In a deep high angle well, the WDR analysis of the liner run at 18,500 ft MD (already in the open hole) the maximum actual overpull at the liner shoe is 57k lbs and the apparent overpull observed at the surface is 145 klbs. In this case, the weakest point is the drill pipe at ~6,900 ft MD. At 20,500 ft MD (Well TD), both the maximum actual overpull and the apparent overpull increase to 63 klbs and 177 klbs. At TD, the weakest point is the drill pipe at the surface. Something similar can occur with the WOB or set down weight without rotation, where the actual WOB at the bottom is not necessarily equal to the apparent WOB at the surface. This has a tremendous implication for recovering from a stuck pipe situation or setting liners/packers.