American Oil and Gas Reporter - June 2014 - 74

SpecialReport: Offshore & Subsea Technology

Inhibitors Keep Subsea Wells Flowing
By Stephen Szymczak
and William Steiner
HOUSTON-Wells are stimulated in
order to boost production rates and extend
economic life, and flow assurance is part
and parcel of the post-production phase
of any stimulation effort. The production
typically brings with it a myriad of issues,
including inorganic and organic solids
that can deposit in the wellbore and at
various locations along the production
channels. Other common challenges include an increased risk of corrosion and
reservoir souring.
Flow assurance and production-related
issues are particularly challenging in offshore subsea developments, where wellbore access is severely limited and
workover costs are higher by orders of
magnitude. In subsea projects, flow assurance is a critical enabler of efficient
production operations and reserves recovery over a well's full life cycle. It is
no surprise that industry surveys consistently show deepwater operators identify
flow assurance as a top priority among
various technical challenges.
Solid inhibitors have been developed
that are delivered as part of a fracture
stimulation job to proactively mitigate
flow assurance challenges before a higher-cost, higher-risk intervention is required.
This controlled-release technology consists
of chemical inhibitors for scale, paraffin,
asphaltenes or corrosion, which are ad-

sorbed onto a proppant-like substrate that
is fed into the proppant during the hydraulic fracturing operation. As the proppant is pumped down hole and into the
formation, it carries the solid inhibitor
particles with it, where they remain behind
pipe and are dormant until needed.
The historical approach to placing inhibitors in the formation calls for a liquid
chemical to be added to the stimulation
fluid. These chemistries tend to start
flowing back as soon as the well is
brought on production and have relatively
short treatment lives. At common load
rates of 10-25 percent of active inhibitor
in a carrier fluid, the liquid-based treatment
may come back at a dosage of 1,000
parts per million or more, meaning the
inhibitor may be completely absent from
the well by the time it is needed.
'Vaccinating' A Well
Solid inhibitor particles, by contrast,
are not activated until they come into
contact with the fluid of interest (i.e., the
fluid they are designed to treat). In this
way, one might reasonably compare controlled-release solid flow assurance technology to "vaccinating" a well against
production interruptions. Instead of fighting an infection, the technology is waiting
to fend off flow assurance threats such
as scale, paraffin, bacteria and corrosion.
This is primarily important for scale treatment. Until the well produces water, the
scale inhibitor is inactive. Once water

FIGURE 1
Fines Generation at Different Closure Pressures and Inhibitor Dosages
(% by Weight Added)
10.0
9.0
12,000 psi

Percent Crushed Fines

8.0
7.0
6.0
5.0
10,000 psi

4.0
3.0

8,000 psi

2.0
1.0
5,000 psi

0.0
0.0

0.5

1.0

1.5
Percent by Weight Added

74 THE AMERICAN OIL & GAS REPORTER

2.0

2.5

3.0

production starts, it creates a chemical
reaction with the solids in the proppant
to activate the full measure of scale inhibition.
On production of hydrocarbons or water, the solid-state, slow-releasing inhibitor
is released into the fluid stream at a lower
dosage (in the range of 10 ppm), which
extends the effectiveness of the treatment
well beyond what is achieved with liquid
formulations. This solid chemical technology has seen widespread application
in onshore wells. In fact, more than
25,000 wells have been fractured using
this solid chemical technology over the
past nine years.
While this inhibitor has performed
exceptionally in land wells with relatively
low closure pressures (6,000 psi or below),
its effectiveness diminishes at higher
pressures. At a given percentage-byweight-added inhibitor dosage, the amount
of fines generated increases as closure
pressures climb, limiting conductivity
and resulting in a less effective inhibitor
treatment (Figure 1).
At closure pressures of 8,000 psi and
above (which are common in deepwater
wells), the conductivity of the solid substrate begins to drop, producing fines on
the order of 3 percent or greater by mass.
Because the active inhibitor chemistry is
added to the available surface area of the
substrate particles, any loss of surface
area resulting from crushing and fines
production translates to a limitation on
the total amount of chemical available
down hole.
Nanotechnology Material
This limitation at greater pressures
has led to the development a more robust
substrate to deliver inhibitor treatment
in deepwater applications. The technology
uses a patented, spherically shaped, highstrength, nanotechnology-based material
that is in the same size range as proppant
and withstands higher reservoir pressures
with less fines formation. As a result, it
provides a high internal and external surface area onto which the inhibitor chemistry is adsorbed.
Because much more substrate can be
added to the proppant pack (20 percent
by weight versus 2 percent with the original substrate), it provides primary stimulation or sand control and ongoing multiyear flow assurance with significantly

American Oil and Gas Reporter - June 2014

Table of Contents for the Digital Edition of American Oil and Gas Reporter - June 2014