Mr. Erik Milito - The House Committee on Natural Resources ...

ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 51
This substantially decreases the annular column hydrostatic pressure across potential flow zones within the
cemented annulus. This decreased hydrostatic pressure allows formation fluids to influx into the wellbore which starts
annular flows that can lead to LWC incidents.
Another way for lost circulation during cementing operations to lead to LWC incidents is when the actual TOC does
not reach the planned depth to cover potential flow zones and, instead, places drilling fluid across these formations. If
the drilling fluid hydrostatic pressure is below the formation’s pore pressure, annular flows may start immediately. If
the drilling fluid hydrostatic pressure is above the formation’s pore pressure, an annular flow may not start until drilling
fluid gellation (also called SGS development), solids settling, etc. decreases the hydrostatic pressure enough to
create an underbalanced pressure condition. See A.14, 4) for more information on this phenomenon.
Cement channeling may cause total or partial lost circulation during primary cementing by initially raising the cement
column to longer than planned heights (shallower depths) which results in pressures greater than fracture initiation/
propagation pressures. Relevant formations exposed to these pressures then “breakdown” or fracture and start taking
volumes of the cement slurry out of the annulus. When this occurs, the annular fluid level drops (called “fallback” or the
annular fluid flow rate out of the well decreases to less than the rate pumped into the well. In either case, the risk of an
LWC incident increases when these losses result in underbalanced pressure conditions across potential flow zones.
Applying adequate measures to prevent cement channeling and associated losses are described herein including
methods to optimize drilling fluid and cuttings removal/displacement by operational procedures and cementing job
designs such as measuring drilling fluid conditioning and hole cleaning performance with fluid calipers (see 5.2), pipe
movement, installing centralizers, and pumping relevant cement flushes and spacers at engineered rates.
An API cementing book [38] published in 1991 includes data (see Table A.10) indicating that up to 45 % of all wells
require an intermediate casing to prevent severe lost circulation while drilling to total depth (TD). With these extra pipe
strings in well designs, lost circulation events still occurred in 18 % to 26 % of all hole sections. Some areas reported
many more occurrences of lost circulation events ranging from 40 % to 80 % of wells. In recent years, these
percentages have likely increased as the number of shallow, easy-to-find reservoirs has steadily declined and well
operators have intensified their search for deeper reservoirs and drilled through depleted or partially depleted
formations. Conventional LCM including pills, squeezes, and pre-treatments, and drilling procedures such as ECD
management often reach their limit in effectiveness and become unsuccessful in the deeper hole conditions where
some formations are depleted, structurally weak, or naturally fractured and faulted.
In some cases, operators perform FIT or LOT measurements after the initial casing shoe test while drilling critical hole
intervals or after drilling the entire hole section. This practice helps confirm that lost circulation can be prevented by
the integrity of the open hole to contain pressures generated from deeper drilling and/or from operations to set casing/
liner pipes (higher ECD in running pipe and primary cementing). Successful cases over the last 50 years have proven
that this practice can successfully predict cementing placement without losses. In other cases when cement losses
are predicted by the hole section FIT or LOT, the operator may decide to apply alternative measures such as LCM
pills, tack and squeeze, etc. Some technical papers describe these practices including the lessons learned procedure
reported by Rederon et al [39] in SPE 149 (p. 5, rt. Column, step no.1) published in the late 1950’s.
Table A.10—1991 API Survey Data on Lost Circulation
United States North America Global
Producing fields in survey 204 218 339
Wells needing intermediate
casing and/or drilling liner
31 % 33 % 45 %
Lost Circulation Encountered
Surface casing 24 % 24 % 21 %
Intermediate casing 24 % 25 % 23 %
Production casing 24 % 24 % 24 %
Liners 18 % 26 % 19 %