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Oilfield Technology
June
2016
Risksofacidtreatment
While acid treatment may be the right solution for many wells, there are
also are risks associated with acid stimulation. HCl or HF acids used for
well stimulation are hazardous chemicals that must be diluted with water
typically down to 15%or less, so large volumes may be needed. Several
additives are required to be blended into the acid treatment fluid, in large
part to prevent the acid fromdamaging the pumping equipment and well
tubulars. Also, acid jobs requiremobilisation of large volumes of acid,
frack tanks, pumping equipment and crews composed of up to 20 people.
It is difficult to time acid jobs because acid has a short ‘shelf life.’ Once
HCl has been blended with water and the required additives, themixture
only remains effective for two to three days as additives such as inhibitors
degrade with time.
When acid is pumped into a well, it will flow along the path of least
resistance, going places where it may not be needed. Many water based
acid jobs cause formation damage, including clay hydration, which
damages perforations and cuts off production. Acid can even soften
carbonate formations to the point of collapse, so the well can no longer
produce. Finally, a 3000 gal. acid treatment will need to be flowed back
from the well, generating as much as 15 000 gal. of waste fluid that must
be handled and disposed of safely. In wells where barite or related scales
are the problem, acid can actuallymakematters worse, turning a low
producing well into one that does not produce at all.
Advantagesof treatment
None of these problems apply to HDC treatments. The chemical requires
no special handling, and is as safe to use as synthetic oil basemud. It is
shipped in 55 gal. drums or small containers and is pumped ‘neat’ with no
additives, in small volumes, typically 10 - 20 bbls per treatment. Pumping
equipment needed for treatments may already be on the platformor at
the land well’s location. Triplex mud pumps with two 10 bbl displacement
tanks are generally sufficient to performa treatment. No blenders or large
crews of personnel are needed. Another benefit of the solution is that it
can be stored on location for up to two years, enabling flexible scheduling
of treatments.
In some instances the chemical can be pumped from the surface
(bullheaded) to treat the production interval affected by the barite or
scale. Inmore serious cases, when the specific location of well damage is
known, it is more effective to spot the chemical directly at the target zone
using coiled tubing and a jetting tool.
Whereas acid treatments require flow back of substantial amounts
of waste fluid, the solution is applied in such low volumes that most of it
dissipates into the formation. After treatment, HDC is an inert chemical
and the portion that flows back does not need to be removed from
produced fluid before refining.
The chemical is extremely effective at dissolving bariumsulfate,
especially in comparison toHCl treatments. In laboratory tests, an 18%HCL
treatment dissolves a negligible amount of barite, just 2 - 3 g/l of treating
fluid. In contrast, when the chemical was first introduced in the 1990s, it
dissolved 80 – 85 g of bariumsulfate and scales for every litre of treatment
chemical. Since then, HDC formulations have been improved. Laboratory
tests show that the latest version of Well Flow International’s HDC®-3
dissolves over 300 g/l, andwhen usedwith a Koplus® LX pre-treatment, it
can remove up to 380 g/l.
Laboratory tests show that the chelation reaction is particularly
effective at dissolving relatively small barite particles – 20 to 30microns in
diameter – which have the greatest potential to bridge and close off pore
throats in the formation. The chemical breaks these down to 1 - 2micron
particles that do not clog pore throats and remain in suspension as the
treatment is flowed back from the well.
While other available barite dissolvers require high bottomhole
temperatures to be effective, there is nominimumtemperature for
application of the chemical and it workswell at 190˚F, which is typical in
producingwells. The rate at which the chemical dissolves barite increases
with temperature up to 400˚F, and 450˚F is the practical limit for HDC use.
In some older fields where water is injected to helpmaintain
production, seawater or previously produced brines may be incompatible
with reservoir chemistry, resulting in barium, strontiumand calcium
scales in perforations, screens and tubulars that can impede or shut off
production.
HDC treatments, performed in two stages, clean barite and scale from
completion components and then penetrate the perforation tunnels and
reach up to onemetre into the formation. HDC remains chemically active
for up to 48 hours, compared to 6 - 12 hours for acid treatments, so that
when the second stage is applied it forces the first stage chemicals, which
are still partially active, into the formation behind the completion to
achieve further cleaning.
Planningawell intervention
To plan a well intervention using HDC, the chemical provider works
closely with the operator and the service company to review the history
of any candidate wells, to determine what treatments have already taken
place, and to decide whether the damaged zone needs to be isolated
before treatment. If there are asphaltenes present in the well, it must
be pre-flushed to expose the residual barite, filter cake or scale so it
can be effectively treated. Well Flow International uses TarClean™ and
Super Pickle® treatments, which do not damage elastomers or other
well components, to expose the barite contamination. The subsequent
treatment is designed tomatch well conditions and usually involves two
stages of soaking performed in sequence.
The first application is pumped into thewell, either bullheaded or
spotted by coiled tubing, at a rate of less than one bbl/min. To treat a
30mperforated interval, the coiled tubing unit would be used to spot the
chemical at the base of the zone, graduallymoving up to the top of the
interval, and then repeating this treatment pass to provide assurance that
the zone is filledwith the treatment chemical.
The first stage soaks for 6 - 8 hours while the chemical reacts with
contamination in the wellbore and in the adjacent formation. During
the first soak, the chelation reaction separates the bariumand sulfur to
break down the barite in the wellbore and extending out approximately
onemetre into the formation wheremost of the blockage to production
has occurred. Then, while the HDC from the first soak is still about 30%
active, a second soak is spotted using the samemethod. The second soak
pushes the first wave of chemical into the formation andmakes sure the
perforations and well screens are thoroughly treated. The second soak
will also remove any barite and solids that were not treated by the initial
dose of HDC.
After the second chemical placement, the chemical will finish reacting
with the barite and scale in 18 - 24 hours. At this point it becomes inert and
Figure 1.
HDC-3 dissolves over 300 g/l of bariumsulfate and scales, and
when usedwithaKoplus LX pre-treatment, it can remove up to 380 g/l.
