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Influencing CEOR Performance by
Optimizing Water Chemistry
Lisa Henthorne
Water Standard
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Influencing CEOR Performance by Optimizing Water Chemistry
Lisa Henthorne, Water Standard
Influencing CEOR Performance by Optimizing Water Chemistry
Lisa Henthorne, Water Standard
Abstract
A number of chemical enhanced oil recovery (CEOR) projects presently being implemented
around the world require specialized water chemistry to optimize performance in the reservoir.
The desire to use water quality, specifically the concentration of various inorganic salts, as a
mechanism to influence oil recovery has become an area of interest in recent years with the
advent of low salinity water injection. While low salinity water injection aims to change the
wettability characteristics in the reservoir and tends toward a low salinity water combined with a
consideration of divalent cation concentration to reduce chances of clay deflocculation, the range
of desired CEOR water chemistry can vary to a much greater degree.
Today, finding the technology and know-how to create the customized waters needed to
implement the CEOR projects on the horizon is a challenge for the oil and gas industry. Because
these unusual water compositions have never been required in any industrial or municipal
application, the technology to separate, then pick and choose ions from seawater, brackish water
or produced waters, has never been developed. Separation technologies such as membranes,
distillation and ion exchange were developed to remove ions to achieve lower concentrations of
ions. Examples include desalination, water softening, boiler feedwater and ultrapure water
production. But selective removal of ions is more difficult, particularly when the feedwater
source is highly saline such as seawater and many produced waters.
To achieve their water quality goals, some CEOR projects have considered desalinating the
source water then adding the desired salts along with the CEOR chemicals prior to injection. But
based on the planned project capacities, the cost of salts can be more than $20 million per year
for a relatively low salinity injection of 2,000 mg/L for KCl. Some projects have optimal
salinities (based on surfactant performance) of more than 20,000 mg/L with extremely low
hardness criteria. The cost of potentially adding salts to achieve these high salinity can cripple
the economics for these projects.
This paper describes the development and adaptation of specific membrane technologies and
tools to enable water treatment to the desired unique compositions for various CEOR projects
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Influencing CEOR Performance by Optimizing Water Chemistry
Lisa Henthorne, Water Standard
around the world. Pilot testing has been accomplished at three test sites to compare actual
membrane performance versus projected performance, to enable FEED design of the required
systems. The paper also discusses some of the unique instrumentation and controls required to
achieve the CEOR project performance goals, as well as the methods used to enable future
flexibility in the treatment system to allow for different injectant water chemistries in future
phases of the CEOR flood.
Background
Water-based Enhanced Oil Recovery (EOR) applications are increasing in number.
Waterflooding, originally adopted for pressure maintenance purposes, is now maturing into a
more profit-driven mechanism, which goes beyond secondary recovery to enhance oil
production. Through alteration of the injection water chemistry, and in some cases, adding
chemicals to improve conformance and miscibility between the oil and water, water-based EOR
techniques, such as Low Salinity Flooding (LSF) and CEOR are finding success. As these EOR
methods continue to develop and prove effective in increasing oil production, with some upfront
planning, operators developing greenfield waterflood facilities can easily include optionality for
EOR in the future. In addition, operators wanting to transition from existing conventional
waterflooding to EOR, now have options to cost-effectively facilitate the transition, onshore and
offshore. Moreover, some operators are thinking further outside the box, to use municipal or
industrial wastewater as a source for EOR injection water. Though the Oil & Gas Industry is
traditionally slow in adopting new technology, the relative low risk associated with the water
treating technologies that enable these EOR mechanisms, coupled with the current oil price, is
quickening the adoption rate.
Waterflooding in its simplest form is injected into the reservoir formation to displace residual oil
and maintain pressure. Its history reaches back to an original patent by William Richards in
1884, in which he recognized pressure on injected water would force oil to surrounding
producing wells (PDHengineer, 2012). Based on empirical results, onshore flooding developed
through the early 1900’s, and it was not until 1942 when Buckley and Leverett published the
seminal paper on “Mechanism of Fluid Displacement in Sands,” that the theoretical basis and
mechanisms of flooding were formulated. Through the mid-1900’s, waterflooding enjoyed a
prosperous growth period, and then expanded offshore using seawater. Today, waterflooding is
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Influencing CEOR Performance by Optimizing Water Chemistry
Lisa Henthorne, Water Standard
standard in offshore oil production, and water handling and injection are often the single biggest
operating cost for producers, with an estimated annual spend of $50 Billion (Sharma, M., 2011).
Fortuitously, the pre-existence of waterflooding infrastructure in aging fields throughout the
world, enables a cost-effective transition to water-based EOR implementation.
Water Treating for Waterfloods
Historically, water treatment has had a primary role in three key areas of waterflooding: source
water filtration and deaeration, sulphate reduced flooding, and produced water treatment. In
general, unit operations used in water treatment facilities vary depending on whether they are
located onshore or offshore, and it usually dictates the water composition. Onshore, water
resources are often limited and operators must use produced water reinjection.
Offshore,
seawater is the primary water resource, and space and weight are primary constraints. Yet,
seawater is recognized as having potentially value-eroding properties.
The most widely
recognized problem is scale formation from chemical incompatibility of the injected seawater
(high sulphate), and the original formation brine and reservoir rock containing barium and
strontium. In reservoirs that contain a substantial barium or strontium content, seawater injection
will cause the naturally occurring sulphate contained in the seawater to precipitate with the
barium and/or strontium, and this effect can eventually diminish the output of the production
wells.
In addition, sulphate-reducing bacteria in some reservoirs can feed on sulphate in
seawater, thereby producing hydrogen sulphide and “souring” the well or reservoir.
As a result, sulphate is often removed from the seawater in a facility process referred to as the
Sulphate Removal Package (SRP), using specialized Nanofiltration (NF) membranes that
maintain a high salinity. Dow FilmTec and Marathon Oil first introduced this membrane system
in 1991. Historically, Dow FilmTec has been the only manufacturer of SRP membranes, but
recently other manufacturers have successfully developed similar membranes, which are now
operational offshore. By the end of 2012, approximately 70 SRP systems were either online or
under construction for offshore production facilities around the world.
Historically, due to space and weight constraints, a major challenge in considering offshore EOR
is the retrofit cost to transition from an SRP system to a facility capable of meeting the EOR
water quality specifications.
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Influencing CEOR Performance by Optimizing Water Chemistry
Lisa Henthorne, Water Standard
Low Salinity Waterflooding
One of the fundamental elements in understanding water-based EOR is recognizing the
relationship between the oil,
the water, and the rock within the reservoir.
Typically, oil
reservoirs contain a degree of formation water of varying salinity. The “wettability” of reservoir
rock is defined as the portion of the rock surface coated with adsorbed hydrocarbons. For
increasing oil wetness, the oil prefers to stick to the rock and flow less easily relative to water.
One of the methods to increase oil recovery is to shift the reservoir toward more water wetness
by manipulating the ionic water composition at the interface point between the oil and rock.
Since the late 1990s, there have been numerous laboratory tests and field studies, where injection
of low salinity water has resulted in increased oil recovery. The University of Wyoming and BP
were early pioneers of the concept. BP has demonstrated the viability of LSF on sandstone core
samples and in the Alaskan North Slope fields. BP has since trademarked the process as
LoSalTM. Shell Oil Company has also progressed the concept. Supportive testing and analysis of
low salinity application to limestone reservoirs has been undertaken by the University of
Stavanger and Aramco.
In considering low salinity injection in sandstone, clay stability of the reservoir must be
considered. Injecting fresh water or water with too low a salinity can destabilize clays, based on
the clay composition in the reservoir. Research has been undertaken to describe the suitability of
injection water composition for various clay types (Ayirala et al, 2010, Ligthelm et al, 2009,
Scheurerman and Bergersen, 1990), indicating smectite and montmorillonite clays to be the most
sensitive. The relationship between total cations and percent divalent cations, on an equivalence
basis, provides guidance to the degree of clay sensitivity and suitability of various water
compositions for injection. Therefore, the concentration of divalent cations, such as magnesium
and calcium, play an important role in clay stability.
The mechanism of low salinity flooding is depicted simplistically in Figure 1; the process of
which can be described as follows:
1. Polar molecules in reservoir oil are attracted to the negatively charged clay surface. Divalent
cations (calcium, magnesium) act as bridges between the negatively charged molecules in the
oil and the negatively charged clay surface.
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Influencing CEOR Performance by Optimizing Water Chemistry
Lisa Henthorne, Water Standard
2. Low salinity water reduces the electrostatic forces holding the oil to the rock, resulting in the
release of oil from the rock surface.
3. When low salinity water is injected, the ion exchange equilibrium changes, and bound oil
becomes mobile and oil recovery increases.
LSF is anticipated to increase oil recovery in the range of 5-10% of Original Oil in Place (OOIP),
based on recent publications (Austad et al, 2010, Ayirala et al 2010, Seccombe et al, 2010,
Sorbie et al, 2010, Vledder et al, 2010, Ligthelm et al, 2009, Webb et al 2008, Lager et al, 2008).
In examining the preferred water chemistry in full-scale LSF projects under development, a wide
range of variability is seen, as a function of the reservoir and oil characteristics. Preferred
salinity levels range from 2,000 to 8,000 mg/L, hardness varies from 10 to 200 mg/L, while
sulphate ranges from 20 to 60 mg/L. The ability to create these selective blends will be
discussed in the subsequent sections.
Figure 1: Water-Oil-Rock Interfacial Characteristics
Chemical Enhanced Water Injection
CEOR is also emerging as a vital method to increase recoverable oil from aging reservoirs;
however, economics and the achievable, incremental, and recoverable oil will dictate its
widespread adoption. Water chemistry of the injection water plays an important role in the
effectiveness and cost of CEOR. CEOR programs can utilize alkali, surfactant, or polymer, or
some combination of same, such as Alkali-Polymer (AP), Surfactant-Polymer (SP), and AlkaliSurfactant-Polymer (ASP).
In polymer floods, using partially Hydrolyzed Polyacrylamides
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Influencing CEOR Performance by Optimizing Water Chemistry
Lisa Henthorne, Water Standard
(HPAM), it is well established the achievable viscosity for a given polymer concentration is a
function of the injection water salinity, with divalent cations having a more detrimental impact
than monovalent ions. Studies have shown (see Figure 2), that five to ten times less HPAM is
required when using desalinated or lower salinity water compared to seawater, resulting in an
equivalent cost savings related to polymer consumption. In surfactant flooding, the relationship
between the injection water chemistry and the effectiveness of the flood is a more complex
equation. Considerable research is ongoing to predict optimal salinities for surfactant flooding
and the added benefit of using salinity gradients through the life of the surfactant flood. Lastly,
alkali addition to either a surfactant and/or polymer flood requires the injection water be
softened, to prevent calcium and magnesium carbonate precipitation in the case when sodium
carbonate is the source of cost-effective alkali. Complicating matters further, the injection water
salinity must be kept to a level sufficient to prevent clay swelling in the reservoir (similar to low
salinity flooding), and sulphate levels must be low enough to prevent precipitation of the
sparingly soluble salts of barium or strontium, if present.
Typically, sandstone reservoirs are most frequently utilized for CEOR due to the higher
permeability of sandstone compared to limestone reservoirs.
The majority of the CEOR
technologies have been tested at pilot and commercial scale on sandstone lithology (Alvardo, V.
and Manrique, E. 2010). Increased oil recovery from CEOR floods is anticipated to range from
5-35% of OOIP, depending on the reservoir characteristics, and the type and duration of
flooding.
The preferred water chemistries in CEOR floods vary tremendously, from low salinity to very
high salinity, but generally, low hardness and low sulphate are preferred.
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Influencing CEOR Performance by Optimizing Water Chemistry
Lisa Henthorne, Water Standard
Figure 2: Polymer concentration required to achieve preferred viscosity at varying
salinity (Ayirala, S., Ernesto, U., Matzakos, A., Chin, R., Doe, P., van Den Hoek, P., 2010)
Normalized Polymer Concentration (dimensionless)
10
10 cP @ 10 sec-1
and 25°C
6 cP @ 2 sec-1
and 46°C
1
0.1
0.01
100
1000
10000
Injection Water Salinity (ppm)
100000
Challenges in Water Treating for LSF and CEOR
The ionic composition of injection water to optimize flood performance in LSF and CEOR
applications usually requires selective ion removal, that is, certain cations and anions must be
removed, while others are left behind. NF membranes are a proven technology for sulphate
removal for SRP treatment; therefore, are well accepted by the Oil & Gas Industry. Figure 3
provides a general description of the types of removal capabilities of different membrane
products.
It is to be noted that membrane filtration technologies, microfiltration, and
ultrafiltration, remove suspended solids, but not dissolved salts. Only the family of NF and
Reverse Osmosis (RO) can effect removal of dissolved salts; therefore, they are the membranes
needed for selective ion removal. However, the membrane filtration technologies are excellent
pretreatment unit operations to use upstream of NF or RO (Henthorne, 2010; Movahed, 2007).
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Influencing CEOR Performance by Optimizing Water Chemistry
Lisa Henthorne, Water Standard
Figure 3: Membrane treatment technologies as a function of rejection by molecular
weight, size, and types of contaminants
The challenges in developing the range of specific water chemistries identified as preferable for
LSF and CEOR include:

“Leaky” membranes that allow selective salt passage are not in demand in the municipal or
industrial membrane market, other than SRP membranes. Softening-type NF membranes
have not been developed for seawater treatment

Though the membrane industry is interested in the EOR market, it is not currently of
sufficient size to warrant R&D for new membrane technologies

Adaptation of proven municipal-type membranes into EOR applications that operate under
vastly different conditions and configurations, requires piloting and investment by users

Oil & Gas Industry projects are inclined to have exacting timelines that do not allow for
technology development and trials needed to achieve required Technology Readiness Levels
(TRL)
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Influencing CEOR Performance by Optimizing Water Chemistry
Lisa Henthorne, Water Standard

The EOR project water quality specifications have narrow bands of allowable fluctuations.
Inherently, membranes produce a varying permeate quality as a function of feedwater
temperature and composition, and membrane life

Oil & Gas Industry availability factors, design specifications and HSE requirements, differ
from the municipal water industry

The design drivers of facilities in Oil & Gas Industry applications, differ greatly from the
typical municipal or industrial water industry, requiring a paradigm shift in design values

Many of the preferred water chemistries requested for EOR projects have never before been
created using currently available technology

Membrane systems are designed to provide up to a specific salinity (or salt level) under all
operating conditions, while EOR systems may have both minimum and maximum
requirements

In EOR applications, access to different water chemistries can optimize oil recovery, as the
field transitions between different flood phases, which requires the water treating facilities to
provide a range of water quality
Solutions to Effect Customizing Water Chemistry
Ideally, one type of water treatment system could be developed to address the challenges
previously described. The ideal characteristics would include the ability to:

Produce a wide range of product water quality, from low to high salinity, from low to
medium hardness and sulphate

Fine-tune the product quality as a function of changing conditions, such as fluctuations in
feedwater temperature and composition, and the changing performance of the membranes
over their three to five year life

Change output quality during different phases of injection, and turndown/up output capacity,
as needed, as a function of blending of produced water or other needs

Automatically change the output water chemistry, on demand

Achieve a TRL for commercial application

Maintain a low weight and compact footprint, for ease in slotting into traditional SRP
allocated spacing on greenfield projects, and retrofitting brownfield systems
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Influencing CEOR Performance by Optimizing Water Chemistry
Lisa Henthorne, Water Standard
The H2Ocean SpectrumTM Technology aims to achieve these ideals. Pilot testing in support of
upcoming full-scale LSF and CEOR projects, demonstrated its capabilities and confirmed
membrane performance and tuning aspects of the system, and has achieved a minimum TRL 5.
Figure 4 describes the achievable water quality available from one H2Ocean SpectrumTM
Technology system, while Figure 5 demonstrates the capability of the membranes to achieve
expected hardness, sulphate and salinity rejection, based on pilot results. Due to its predominant
use of membrane technology for both filtration and selective salt removal, the system maintains a
compact footprint and weight, for ease of offshore adoption.
Figure 4. Cases of different achievable water quality from one H2Ocean SpectrumTM
Technology system
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Influencing CEOR Performance by Optimizing Water Chemistry
Lisa Henthorne, Water Standard
Figure 5. Salt rejection capability of a specific NF membrane product piloted in the
H2Ocean SpectrumTM Technology system
Conclusions
Water-based EOR methods are proving viable in pilots and full-scale applications around the
world. The ability to customize the water chemistry for injection in the EOR applications will
improve EOR performance and reduce costs. The Oil & Gas Industry needs new technologies to
meet the atypical needs of the water treating facilities for water-based EOR applications. For
offshore applications, space and footprint are also important drivers for adoption of the
technologies. The H2Ocean SpectrumTM Technology was developed to meet the overarching
needs associated with cost-effective implementation of EOR in the Oil & Gas Industry, and is
currently being adopted for full-scale EOR facilities.
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Influencing CEOR Performance by Optimizing Water Chemistry
Lisa Henthorne, Water Standard
References
Alvardo, V. and Manrique, E. 2010. “Enhanced Oil Recovery: An Updated Review,” Energies
3(9), 1529-1575, August 2010.
Austad, T., RezaeiDoust, A., and Puntervold, T. “Chemical Mechanism of Low Salinity Water
Flooding in Sandstone Reservoirs,” SPE Paper 129767 presented at the SPE Improved Oil
Recovery Symposium, April 2010.
Ayirala, S., Ernesto, U., Matzakos, A., Chin, R., Doe, P., van Den Hoek, P. 2010. “A Designer
Water Process for Offshore Low Salinity and Polymer Flooding Applications,” SPE Paper
129926 presented at SPE Improved Oil Recovery Symposium, April 2010.
Henthorne, L., “Trends in Pretreatment for Seawater Reverse Osmosis,” Water Conditioning and
Purification , November 2010.
Lager, A., Webb, K., Black, C., Singleton, M., and Sorbie, K. 2008. “Low Salinity Oil Recovery
– An Experimental Investigation,” Petrophysics Journal, Vol. 29, No. 1.
Ligthelm, D., Gronsveld, J., Hofman, J., Brussee, N., Marcelis, F., and van der Linde, H.A. 2010.
“Novel Waterflooding Strategy by Manipulation of Injection Brine Composition,” SPE Paper
119835 presented at SPE Improved Oil Recovery Symposium, April 2010.
Movahed, B., “Pretreatment for Membrane Processes,” American Membrane Technology
Association fact Sheet, 2007.
PDHengineer.com, “Waterflood History and Design Fundamentals,” Course No. 0-2004. Online
Publication
Scheuerman, R. and Bergersen, B. “Injection-Water Salinity, Formation, Pretreatment, and WellOperations Fluid-Selection Guidelines,” Journal of Petroleum Technology, July 1990.
Seccombe, J., Lager, A., Webb, K., Jerauld, G., and Fueg, E. 2010. “Improving Waterflood
Recovery: LoSal™ EOR Field Evaluation,” SPE Paper 113480 presented at SPE Improved
Oil Recovery Symposium, April 2010.
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