American Oil and Gas Reporter - February 2016 - 63

rather than the years commonly required
in traditional chemical floods.
Self-Forming Nanostructures
The surface tension at a plain oil/water
interface typically is of the order of 25
dynes per centimeter (dyn/cm). Emulsions
formed by mixing oil, water and non-microemulsion-forming surfactants typically
are characterized by IFT values on the
order of 20-50 dyn/cm. In contrast, the
nanofluid additive can achieve IFTs below
1 dyn/cm.
The additive consists of multifaceted,
self-forming "nanodroplet" structures that
pack together. When dispersed in an injected fluid, the nanostructures dilute to
spherical, oil-swollen micelles that each
carry the three components of water, oil
and surfactant. Literally, millions of these
structures accumulate at interfaces, providing faster alterations of surface phenomena such as surface and interfacial
tension, contact angle, and interfacial viscosity at the oil/water interface.
When applied to oil reservoirs, the
additive is dispersed into the treating
fluid prior to injection into the wellbore.
There is sufficient lessening of the IFT
between the additive treating fluid and
the oil and/or water phases contacted by
the treating fluid in the wellbore and formation. The reduction of IFT overcomes
the capillary forces that "trap" oil or
water in the porous medium.
The combination of these modes of
action outperforms organic solvents and
surfactant systems. The additive's mode
of action may be threefold:
* The penetration of the oil or water
layer through the solvent additive mechanism;
* The microemulsification of the oil
and water components into the aqueous
phase; and
* The water-wetting of the underlying solid surfaces through the surfactant
action.
The technology has the added benefit
of altering the IFT between the rock and
the fluid with oil. As the additive-containing fluid enters the formation, the
rock fluid contact angle is altered to a
mixed-wet state. This results in a lower
required pressure to move the fluids from
the pores. It also can exhibit a lower
water saturation, creating a higher relative
permeability to oil or gas.
Versatile Applications
When utilized at an optimal concentration as a solvent/surfactant/aqueous
fluid, the additive produces a versatile
treatment system with many simultaneous
functions and applications, ranging from
drilling and stimulation to intervention

and EOR. It improves maximum penetration, contact efficiency, and dispersion
of various paraffins, asphaltenes, scales,
bacterial films, concentrated gel filter
cakes, formation fines, and drilling fluids.
For example, the technology was used
to increase production in a well that was
on a severe decline and had become uneconomic. The D sand reservoir appeared
to suffer from paraffin and formationfines plugging and condensate coning.
These problems also increased workover
frequency.
Prior to being treated with nanofluid,
production averaged less than 30 barrels
of oil and 10 Mcf of gas a month. After
treatment, monthly production immediately increased to more than 260 barrels
of oil and 800 Mcf of gas. The treatment
costs were amortized in less than one
week, and the operator realized a 14-to-1
return on investment in the first 90 days.
The well required no more workover
maintenance during the succeeding 12
months.
Mixing the additive with acid allows
uniform fines suspension in wellbore
breakdown treatments to aid in solids/damage recovery and improved oil flow. The
additive retards the reaction of inorganic
and organic (hydrochloric/acetic) acids
and provides efficient reaction kinetics
control to generate longer, narrower wormholes. The nanofluid also maximizes the
breakdown and dissolution of heavy or
complex hydrocarbons such as paraffins
and asphaltenes when pumped with acid,
carbon dioxide, water, and hydrocarbonbased carrier fluids.
It controls and maintains ideal reservoir
wettability, resulting in effective surface
cleaning without permanent alteration to
maximize subsequent treatment efficiency.
Moreover, the technology provides significant friction reduction in aqueous,
acidic, CO2 or nitrogen stimulation fluids
when pumped through treating tubulars,
and improves injectivity, especially in
polymer floods where sustained oil production is directly proportional to maintaining injection rates at a constant pressure.
Preferential Flow Paths
The biggest challenge in testing the
feasibility of any new chemical technology
in a tertiary recovery mode in wateredout waterfloods is mitigating the associated
geologic and economic risks, especially
in a low commodity price environment.
Consequently, the first step in field
testing the nanofluid was selecting candidates with known preferential flow
paths for the injected fluids. Injected
fluids tend to travel through high-perme-

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FEBRUARY 2016 63

American Oil and Gas Reporter - February 2016

Table of Contents for the Digital Edition of American Oil and Gas Reporter - February 2016