American Oil and Gas Reporter - September 2019 - 43

a way to truly float the casing in the lateral. This means placing
a lighter fluid or gas on the inside of the casing to be run in the
lateral. To my knowledge, this has not yet been done because of
well control issues both while running casing and during the
return of the lightweight fluid. This is a solvable problem, but
not yet effectively accomplished.
I also would like to see the industry adopt a casing diameter
that would allow a range of grade and weight choices that
aren't currently reasonable. For example, a 53⁄4 or even 6-inch
diameter casing standardized with on-the-shelf support tools
would allow the engineer to choose between weight and grade
for different pressure containment applications. Either choice
would improve the inside diameter of the current 23 or 26pound, 51⁄2-inch casing. A wider range of applications and subsequent surface pressures could be addressed with either weight
or grade, or both. The minimum hole size could be a standard 8
½ inches. With a standardization of casing diameter and support
tools and services, lateral extension would no longer be restrained
by casing choice.
As noted, I would like to see greater use of the HAZID/HAZOP
process for extended-reach laterals, whether geopressured or
not. Money and lives would be saved by reducing failures, and
litigation would be lessened. Education of new people should
occur in small pieces. It is easier to make an impression and remember the core subject of a workshop than a multifaceted,
long-term school. The concept of on-the-job training is highly
effective in the U.S. military and would serve the oil and gas industry quite well.

Once the well reaches TD, it is turned over to the
completion engineers. How do all of the trends

ONE

and operational issues you've identified in drilling and
casing the lateral section impact the ability to complete
and produce it? "Bigger" remains the operative word in
hydraulic fracturing. Does the need to pump larger fluid
and proppant volumes or place more stages per foot of
lateral influence tubular design and engineering?
STONE: I believe good completion and subsequent production
begins at spud. History shows that producing formations can be
compromised and hindered during the drilling process. Successful
placement of undamaged casing determines the suitability of
the directional process in the lateral. In my experience, a dogleg
severity exceeding 3 degrees per 100 feet should be avoided in
long-lateral holes. Exceeding this threshold is common in the
curve and can be adequately managed. Casing running may experience tight hole or stuck pipe if dogleg severity exceeds this
3 degrees/100 feet threshold over multiple azimuths and vertical
depths in a long lateral.
As lateral length increases, fracture stimulation stage length
will shorten. Slurry viscosity, proppant content and other issues
related to reducing surface pressure will create a new norm.
Eventually, fracture stimulation requirements will require an
adjustment in tubular design, as mentioned. In fact, tubular
design will be impacted to the point that 51⁄2-inch, P-110 casing
will no longer work and the industry will have to adjust.
In conclusion, we will eventually drill long laterals that will
have efficiently fracture stimulated stages near the heel of the
well and less efficient fracture stimulation near the toe of the
well. Obviously, production efficiency near the toe and subsequent
economics will drive the quest to determine the lateral length
beyond which one is justified to drill another lateral well.

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American Oil and Gas Reporter - September 2019

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