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AUGUST 2019 EXPLORATION | DRILLING | PRODUCTION
I s ‘prevention better than cure’ or ‘do you cross a bridge when
you come to it’? Is it better to operate a ‘monitor and repair’
approach to problem-solving or prioritise a ‘pre-emptive’
treatment regime?
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Richard Barr, Proserv, UK, details a step-by-step process for handling potential
pipeline restriction issues.
| 41
42 | Oilfield Technology August 2019
Questions such as these need to be answered for a range of
different flow assurance and production chemistry scenarios,
and the ultimate decisions taken should form an integral part
of delivering and sustaining production processes. Strategies
should be in place, incorporating a defined list capturing all
potential risks and how they should be managed, to reduce the
impact of hazards and threats.
A tolerable level of risk should also be established
within a matrix structure and clearly defined to ensure that
standardisation exists across the company, to allow for correct
and consistent prioritisation and – where required – the
allocation of funds.
Although there are many situations in which prevention is
undoubtedly the best strategy, not every remedy will work or
prove foolproof: for example, reservoir souring (an increase in
the amount of hydrogen sulfide) as a result of water injection.
Throughout the industry, seawater has been used to support
reservoir pressure and aid production. Biocides of different
types can be used, at different dose rates with different batch
durations and varying frequency of treatments, yet many
reservoirs will still sour over time, irrespective of the treatment
regime applied.
For the continued reliability of subsea pipelines, the
‘prevention is better than cure’ approach is the route to follow,
but, again, this can never be 100% guaranteed and unfortunately
restrictions do still occur. When this happens production can
be impacted and additional, unexpected costs incurred, with
revenue reduced. Indeed, there are cases where not just wells,
but also complete fields, have been shut-in or even lost, costing
the operator many millions of dollars.
When it comes to restrictions that simply cannot be resolved
through operational management, such as depressurisation
for hydrates and sand management techniques, then further
expense is required for remediation.
However, to ensure the best chance of success and to avoid
applying the wrong solution to the wrong problem, care must
be taken to ensure that the chosen corrective method is the
most suitable. Prior to any treatment being implemented, it
is vital to determine the composition of the restriction and its
location. This is where the incorporation of an iterative project
management lifecycle could help pay dividends to the operator
in ensuring that the best option is taken.
Key steps Review the procedures and policies to obtain a clear and
concise understanding of the environment, thus enabling
the development of a strategy to facilitate the removal of the
restriction. The key factors guiding a successful diagnosis
and the effective dissociation of a constriction in subsea
systems include:
The characteristics of production stream components,
including all hydrocarbon and non-hydrocarbon fluids,
gases and contaminants produced from the reservoir, or
introduced through production operations.
Well and flowline set-up, including piping configuration
and widths, equipment designs and capacities, and
production component construction materials.
Field layout, including water depths, tieback distance,
the topology of the flowline and the potential location of
the restriction.
Operating parameters, including rates of production,
production-stream composition, the processing pathway,
temperature and pressure regimes and the producer’s
operating strategies.
Consult with all applicable departmental and functional
personnel and review the different available remediation
options, be they chemical, mechanical, pressure etc.,
and understand the risk-cost-achievable benefit of each
technique available. Complete fit-for-purpose procedures for
the treatment method eventually selected and then conduct
the operation.
Assess the performance of the treatment against the desired
goal. Was the right application applied? How effective was
the treatment? What might have been done differently?
Build confidence in the day-to-day operations through
improved performance management, involving key
performance indicators and/or periodic audits to ensure
the correct production chemistry and operational processes
are followed. Train personnel to recognise and identify any
indicators which may lead to a possible future issue. Ensure
the completion of a root-cause-analysis benefit evaluation to
understand what led to the development of the restriction.
For almost all issues, some form of chemical is usually
required, be it for the removal of asphaltenes, wax or scale.
Therefore, it becomes essential that an understanding of what
is present, and in what quantity, is absolutely clear from the
outset.
Every reservoir crude oil and water chemistry varies, and
indeed the operating envelope will also be different, so that no
two deposits will be alike. They could be soft or hard waxes, they
Figure 1. 20 000 psi, DOT/PED subsea sampling cylinder pre-set for
single phase operations.
Figure 2. Proserv 50cc PED, titanium sampling cylinders.
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44 | Oilfield Technology August 2019
could have different hydrocarbon chain lengths or different scale
types and layering.
For wax, it is important to obtain data on the rheological
properties of the crude and the conditions under which the wax
will likely deposit. Dissolution of an existing deposit is usually
possible provided the fouling is not too severe. There are a wide
range of potential solvents available, with the most popular
including substituted aromatics and blends with gas oils.
TreatmentsField treatments may involve filling the affected area with the
chosen solvent and static soaking for a period, and then repeating.
Treating long production flowlines is sometimes only possible by
slowly pumping the slug, but this approach could take excessive
amounts of time and solvent. Hydrocarbon solvents used in the
past include toluene, terpenes, xylene and light gas oil.
For asphaltenes, chemicals like
pyridine, carbon disulfide, aromatics
and chlorinated hydrocarbons typically
offer the best solvency performance;
however, due to toxicity and other
handling concerns, aromatics are now
the preferred chemical for use in the
field. Basic aromatics can be relatively
inexpensive, but they can have flash
point concerns for an operator, so
alkyl substituents are sometimes
used instead. However, they possess
an inferior solvency performance,
creating something of a trade-off.
Additionally, most substituted
aromatics are listed as marine
pollutants, and there are signs of
movement towards bicyclic and other
polycyclic products. Many products
are used neat, or at times diluted with
crudes, and there have been reports of
deasphalted oils, with high aromatic
content, being used as a low cost
alternative to chemical solvents.
Aromatic solvents require
relevant checks to be carried out with
elastomers, and other materials that are contained within the
system to be treated, to ensure there are no potential adverse
reactions, which could result in issues such as swelling or
embrittlement, even aft er relatively short exposure.
For scale however, there is no universal chemical
solvent applicable, so it is only after sample analysis that
an ideal treatment can be prepared. As an example, it is
critical to know if the scale is acid soluble or not, but this
can prove tricky as carbonate scale can sometimes appear
acid insoluble if oil fouled. Given the vast range of options
available, Table 1 highlights the pros and cons of each.
Solvent effectiveness generally improves with increased
temperatures and agitation, so the performance of these
chemicals can vary greatly and this can influence final
selections and overall costs.
Identifying the exact nature of the deposit and
determining the size of the restriction, including where it is
located in the production system, are central to developing
a cost-effective remediation strategy. Once these are
established, the detailed process of targeting the right
chemical solution should be assisted. Subsea samples taken
upstream of the problem area, providing representative deposits
for laboratory analysis, will help considerably.
ConclusionHowever, with so many factors that can play a role in the
formation of restrictions, the development of a risk adverse,
cost-effective and achievable remediation strategy is no easy
matter. Any treatment method used for addressing restrictions
in subsea production systems should only be as the result of
robust, comprehensive analytical processes geared towards
diagnosing the factors that have affected production.
While prevention is undoubtedly a wise and valuable
consistent business model, if a flow issue strikes then a logical,
step-by-step assessment of the problem, such as an iterative
project management lifecycle, is the best way forwards.
Table 1. The pros and cons of using different chemicals to treat scale build-up in pipelines
Scale Chemical Pros Cons
Carbonate Hydrochloric
- Commonly used.
- Inexpensive.
- High dissolution.
- Vigorous reaction.
- Corrosive to steel (inhibitors can be
added but reduced performance at high
temperature).
- Secondary fouling downhole,
formation dependant.
Carbonate Sulfamic
- Can be shipped as dry powder.
- Non-volatile.
- Less corrosive.
- Reacts slower.
- More expensive.
Carbonate Formic & Acetic- Quick reaction.
- Not as corrosive as hydrochloric.
- Not as strong as hydrochloric.
- At high strengths, calcium salt has
limited solubility.
Sulfate Sequestrants- Different products work better on
different scales.
- Slow at low temperatures.
- Costly and can be deactivated if mixed
with brines containing calcium or
magnesium.
Sulfate Converters
- Treatment converts hard sulfate
scale to another form, which can be
treated with dilute acid.
- Multiple treatments may be required.
- Larger volumes.
- Cost factor.
Oxide Nitric- Works well on tight oxide films on
stainless steel and high nickel alloys.
- Not popular for use on common oilfield
scales.
Oxide Phosphoric- Basis of many household rust
removers.- Can precipitate calcium phosphate.
IronCitric acids/
ammonium salts
- Low common risks.
- Chance of reprecipitation is low.- Reacts slower.
Figure 3. Remotely operated underwater vehicle (ROV) subsea sampling system
being deployed for West Africa water chemistry.