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Oilfield Technology
June
2016
can be flowed back to surface without damaging equipment, and
without handling issues associated with acid treatment waste fluid.
Fieldresults
Table 1 summarises 12 examples of successful treatments using
HDC to remove barite and scale and in some cases dramatically
increasing production or injection rates. Applications in oil and gas
Table 1. HDC barite dissolver case histories.
Location
Well type
Problem
Treatment
Deployment
Results
UK North Sea
28 000 extended reach
well with perforated
liner.
Barite from OBM caused severe skin damage.
Well under-produced from the outset.
High water cut, caused barium, strontium
sulfate and carbonate scales that impaired
production.
HDC I and HDC II designed
for barite and scale.
Bullheaded, 12 hour soak.
Pre-treatment production:
1550 bpd.
2424 boe/d.
After treatment:
2245 bpd
4997 boe/d
Stabilised production:
2340 bpd
3984 boe/d
Net increase in oil production was
51%. Removed 156 kg mud-grade
barite and 50 kg of barium scale.
UK North Sea
Three horizontal wells
with ESP and 900 ft of
screens.
Dolomite/barite mud solids blocked off
screens and ESP. Problem compounded by
HCI and U104-U105 treatments to remove
carbonate scale.
Koplus LO pumped ahead of
HDC Mark II.
Bullheaded.
First HDC soak: 8 - 12 hours.
Second HDC soak: 24 hours.
First well:
Pre treatment production:
11 000 boe/d
After treatment production:
22 000 boe/d.
Two more ESP wells treated,
contributing 60 000 boe/d.
UK North Sea
New
gravel-packed injector
well, moderate
temperature of 148˚F.
Operator attempted to inject through well
without removing SBM mud cake. Injection
significantly impeded.
HDC Xream and Mark II.
Coiled tubing placement,
24 hour soak.
Removed all filter cake even at low
bottomhole temperature.
UK North Sea
Oil producer completed
with well screens,
moderate temperature
of 148˚F.
Barite from OBM blocked screen and caused
skin damage.
HDC Mark II, 4000I.
Bullheaded, cleaned up
under its own pressure after
48 hours.
Production doubled from
pre-treatment levels, attaining
theoretical 90% rate.
UK North Sea
Horizontal oil producer
with 2000 ft reservoir
section, collapsed
shale left only 400 ft
able to produce.
SBM compressed around the well screen,
barite solids drop-out in formation. No results
from prior solvent/ nanowash treatment.
Koplus LO pre-flush,
HDC Mark II with calcium
carbonate dissolver.
Bullheaded, three treatments.
PI increased from 1.5 to 7.5.
Production before treatment:
400 boe/d.
Production after treatment:
4000 boe/d.
Louisiana
HPHT gas well,
12 000 psi THP 415˚F.
Well experienced severe mud losses during
drilling, stopped by massive LCM pills.
HCI and HF/HCI treatments could not remove
damage, liquefying formation.
HDC Mark II with Koplus LO
preflus.
Squeezed into well. Two-stage
soak.
Well produced 18 million ft
3
before
metal and gravel blocked choke
and tubing. Demonstrated that
gross damage to well could be
reversed.
Malaysia
High temperature gas
well, 325˚F deviated,
dual string completion,
perforated liner.
Originally designed to produce 25 million ft
3
but only produced 10 million ft
3
. OBM was
pumped to kill well. Perforations in both
zones buried in settled barite. Acid treatment
left well producing only 1 million ft
3
.
HDC Mark II, bullheaded
through short string.
Bullheaded through short
string. 26 hour soak. CTU used
for N
2
gas lift.
Production increased to
7 million ft
3
/d and 5 m
3
/d
condensate and 1228 kg of barite
dissolved.
Malaysia
High temperature gas
well, 325˚F deviated,
dual string completion,
perforated liner.
Originally designed to produce 50 million ft
3/
d
but only made 20 million ft
3
. Well impaired by
settled OBM solids. During a CT acid-washing
job, a jetting head was lost and production
rates remained poor.
HDC Mark II after Koplus LO
and Super Pickle pre-flush.
Bullheaded into lower zone.
The well recovered under its own
pressure and was placed on stream
at 45 million ft
3
.
Thailand
Monobore newly
drilled injector with
perforated liner.
Drilled with OBM, the well failed to inject after
perforation, blocked with barite.
HDC Mark II, in two stages.
Placed with coiled tubing unit,
first soak eight hours, second
soak 24 hours. Gas lifted
with CTU.
Well went operational injecting
8500 boe/d at 1500 psi.
Nigeria
Horizontal well
with 2467 ft section
completed with open
hole slotted liner.
Well had no production due to OBM solids and
damage from poor acid job. Two attempts
failed to unload well.
Super Pickle/Koplus LO pill
followed by HDC Mark II.
Coiled tubing placement.
Soaked for 24 hours. N
2
used
to lift well.
Well flowed at 2700 bpd at 650 psi
and stabilised at 2500 bpd.
Nigeria
Newly drilled producer
with well screens in
open hole. 160˚F BHT.
Well initially shut in for 152 days because of
local unrest, then produced poorly. Formation
impaired with mud solids. Fish left in well
during stimulation attempt, resulting in no
production.
Koplus LO and Super Pickle
pre-flush followed by HDC
Mark II.
Coiled tubing run to top of
fish, then treatment was
bullheaded.
Production increased from 0 bpd
to 3000 bpd.
Australia
HPHT geothermal well,
vertical.
Fish lodged in settled barite and through
milled bridge plug.
HDC Mark II, spotted three
times.
Bullheaded.
Fish, released from barite, fell to
bottom of well. No further fishing or
milling required.
fields around the world have included extended reach offshore
wells with severe oil based mud skin damage, horizontal wells
with clogged screens and electrical submersible pumps, injector
wells clogged with barite, and high temperature gas wells whose
production was impaired by mud filter cake and scale. In these
cases, HDC has been a practical solution for dealing with barite
problems.
