American Oil and Gas Reporter - June 2022 - 70

SpecialReport: Artificial Lift Technology
Before the study, PureWest relied on
plain 4140 bar stock plungers in each of
the eight wells. Historical data showed
that plunger run times ranged between
76 and 163 days per well, at which time
the plungers had to be replaced.
In practice, PureWest measures plungers
every three-six months (earlier if well production
declines) to determine if a plunger
needs to be replaced, which occurs when
the plungers have degraded so much that
they can no longer provide an effective
seal (Figure 1). The minimum acceptable
outer diameter is 1.88 inches. New bar
stock plungers have an outer diameter of
1.90 inches. Before the field study, PureWest
had to change plungers two-five times a
year on each of the eight wells.
Field Study Details
The field study deployed new B4C
treated 4140 steel plungers, all of which
had an initial outer diameter of 1.90 inches
(Figure 2). The plungers were evaluated
every three-six months and replaced if
the outer diameter was less than 1.88
inches. PureWest recorded the number of
run days achieved before plunger replacement
and the production levels of each
well across the 14-month period.
During eight months of production on
eight separate wells, only five B4C treated
4140 plungers required replacement because
they no longer met the minimum outer diameter
of 1.880 inches. The plungers in
these five wells still achieved an average
run time improvement of 244 days when
compared with the plain steel plungers
placed down hole before the study.
The three remaining wells with B4C
treated plungers were still running at the
study's conclusion. These wells recorded
an average run time improvement of 348
FIGURE 1
Worn-Out Plunger
TABLE 1
Run Time Comparison in Days Between Plain and Treated Plungers
Well Name Plain Steel Treated Steel Improvement Run-Time Multiple
Well 1
Well 2
Well 3
Well 4
Well 5*
Well 6
Well 7*
Well 8*
Average
76
97
155
155
151
112
163
139
131
*Active wells at conclusion of study
days compared with the plain steel
plungers (Table 1).
The B4C plungers had an average run
time of 414 days compared with 131 days
for plain steel plungers, representing a
mean improvement of 283 days-an increase
of 3.2 times. This increase in performance
eliminated 18 tool replacement cycles
across the eight wells studied.
Annual plunger replacements dropped
64% once the B4C treated ones were in
the field. The run time improvements and
less frequent replacements translated into
significantly lower overall operating expenses,
even after accounting for the additional
cost associated with the treatment.
Why Replacements Occur
Plunger seal efficiency is critical in
achieving optimal production. The
plunger's rise and fall during each production
cycle causes plunger wear over
time. The inevitable result of wear is
poor seal performance, leading to diminished
production. To sustain production,
worn plungers must be replaced.
Sandy, corrosive and highly deviated
wells are known to accelerate the mechanical
wear, abrasion or corrosion of
plunger lift system components. When a
plunger wears, production suffers. Plunger
failure also leads to higher operating expenses
and lost production from equipment
replacements and downtime.
Plunger replacement cycles vary from
well to well. The goal of any operator is
to achieve as much run time and production
as possible from each plunger so
operating expenses stay in line with production.
To accomplish this, operators
may optimize the well for the plunger
application or change equipment designs
and materials. Operators also may coat
or plate the plunger itself to extend its
run life. B4C treatment, which is neither
coating nor plating, is a promising option.
Historically, using plain 4140 steel
plungers on its wells in the Pinedale Anticline,
PureWest was performing 3.5 plunger
replacements per well per year on average.
B4C-treated 4140 plungers cut annual
plunger replacements to an average of
1.25 per well and increased average plunger
run life from 113 days to 414 days.
By extending plunger run life in all
eight wells, the B4C treatment helped
PureWest reduce equipment and labor
costs, and dramatically reduce overall
downtime and lost production associated
with maintenance and repair events.
Mechanisms For Longevity
The plungers treated with B4C lasted
FIGURE 2
New B4C-Treated Plunger
so long because the treatment alters the
base 4140 barstock's surface characteristics.
The treatment creates a slick, hard, intermetallic
boride layer that (unlike coatings
or platings) does not alter the dimensions
of the part. The treated surfaces' slickness,
hardness and corrosion resistance all contributed
to the plungers' longevity by protecting
them from abrasion and corrosion.
The slick surface exhibits a lower coefficient
of friction than the base metal
70 THE AMERICAN OIL & GAS REPORTER
255
444
438
327
502
349
503
491
414
179
347
283
172
351
237
340
352
283
3.4X
4.6X
2.8X
2.1X
3.3X
3.1X
3.1X
3.5X
3.2X
American Oil and Gas Reporter - June 2022

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