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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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Ready for Ready for anythinganything

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.