American Oil and Gas Reporter - July 2020 - 47

SpecialReport: Proactive Chemistry
These wax molecules are almost always
in solution in the produced crude under
reservoir temperatures. The produced
oil cools as it moves from the perforations and up the hole, eventually reaching
the cloud point or wax appearance temperature. The wax appearance temperature is a function of the makeup of the
wax molecules in the crude and the
overall concentration or percentage of
wax molecules.
At this temperature, the wax molecules
begin to form crystals and platelets, and
come out of solution. Wax appearance
temperature often varies considerably
across different unconventional oil formations, but it is generally common to
see wax forming somewhere in the tubing
string before the oil reaches the surface.
Where exactly wax platelets begin to
form and attach to the tubing's internal
diameter and the surface of the rods is a
function of the wax concentration and
overall molecular makeup, formation temperature and production rate.
A well producing a high rate of fluid
often can carry fluid from the formation
to surface before a substantial amount of
formation temperature is lost, thereby
limiting the amount of wax that may form
in the tubing, wellhead or surface flowlines.
Conversely, a well producing a small volume of fluid will see that production lose
reservoir temperature much quicker and

likely experience wax coming out of solution thousands of feet down hole.
When an unconventional oil well is
shut in, the fluid trapped in the tubing
(assuming it is not a flowing well) will
begin to gravitationally separate. Brine
will fall to the bottom of the tubing string
and oil will remain on top. If a well with
a 70-to-30 oil-to-water ratio and 10,000
feet of tubing is shut in, it will have 7,000
feet of crude in the tubing sitting on top
of 3,000 feet of brine. Because the well is
not producing to surface, formation temperature is not moving up hole with the
produced fluid, and the oil and brine
quickly assimilate to the surrounding rock
temperature at their respective depths.
A well that previously experienced
downhole wax formation beginning at
3,000 feet and upward now may deposit
wax much lower. Additionally, a lengthy
shut-in also may result in a larger volume
of downhole wax.
Limited Options
Chemically, operators have few options
to address existing paraffin when returning
a shut-in well to production. Some of the
precipitated wax is likely to enter the
surface equipment and tankage as the well
begins producing fluid and can be treated
there using chemical or thermal means. If
the wax precipitated down hole is sufficiently severe-making it difficult to operate

the well-it may be necessary to thermally
treat down the annulus with either hot oil
or hot water to allow some of the wax to
melt and move with the produced fluids.
Previous work has demonstrated that
heat applied through fluids at surface are
limited in how far that heat extends down
hole. Based on this, thermal treatment
may not sufficiently remove wax that
formed deep in the tubing during shut-in.
If this seems to be the case, batching a
volume of a paraffin solvent/dispersant
down the tubing/casing annulus, where it
will be produced back up the tubing, can
help. Doing this while placing the well on
total produced fluid circulation has proven
very effective with wax removal using a
solvent/dispersant. The well should be circulated to allow for at least two passes of
the solvent/dispersant through the tubing
string. Determining the effectiveness of
wax removal after shut-in can be done
through monitoring amperage on prime
mover motors, flowline pressure and "grind
outs" of oil from surface vessels and tanks.
Unfortunately, the question is likely
not whether the industry will face another
time where unconventional wells need to
be shut in, but when. Operators should
establish a standard practice for protecting
their valuable assets from corrosion and
paraffin by proactively applying chemistry
prior to shutting those wells in. After all,
an ounce of prevention . . .
r

RICK
MCCURDY

Rick McCurdy is chief technology officer at maxSWD LLC, a chemical supplier helping
midstream water operators optimize flow assurance and injection in saltwater disposal
wells. In addition, he is the principal consultant for RMc3 Consulting LLC, providing
chemistry, conservation (water reuse) and corrosion consulting services. McCurdy previously
served as a subject matter expert in chemistry, corrosion, produced water treatment and
reuse, and alternative water sourcing for hydraulic fracturing at Chesapeake Energy
Corp. He was a primary developer of Chesapeake's initiative championing the beneficial
use of produced water, AquaRenew®, and its GreenFrac® environmentally-friendly additives
program. McCurdy has served as a technical expert during U.S. Environmental Protection
Agency workshops on hydraulic fracturing's potential impacts on water resources, and has
presented to the National Academy of Sciences, Engineering & Medicine; the Government
Accountability Office; and the U.S. Department of Energy regarding water use in the
energy sector. He holds an A.A.S. in petroleum technology.
JULY 2020 47

American Oil and Gas Reporter - July 2020

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