OTC-24105-MS

Engineering Design Challenges and Opportunities beyond Waterflooding in

Offshore Reservoirs
Vladimir Alvarado, University of Wyoming, Eduardo Manrique, TIORCO LLC

Copyright 2013, Offshore Technology Conference

This paper was prepared for presentation at the Offshore Technology Conference held in Houston, Texas, USA, 6–9 May 2013.

This paper was selected for presentation by an OTC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been
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Abstract
This paper presents an analysis on the potential of Enhanced-Oil Recovery (EOR) and its challenges in offshore
environments. EOR experience gained in onshore and shallow offshore should be translatable to offshore, but common sense
developed over years of exhaustive laboratory research, modeling based on our best understanding of recovery mechanisms
and extensive onshore field experience must be redeveloped to adapt to the stringent demands of the offshore. We show how
screening criteria and workflows recently developed can be adapted for evaluation of EOR potential in offshore
environments. A quick review of some of the new vibrant offshore basins is presented.

Offshore EOR decision-making and design require integrated operations that merge more tightly traditional IOR, for efficient
flooding, and EOR, to increase overall recovery factor. Screening criteria can be integrated through more adequate
consideration of soft issues. The starting point of the needed mindset is the understanding of soft issues that harden to
become barriers in the offshore. Large well spacing, limited space and its cost and unmanned operations are apparent
constraints. However, more subtle aspects drive the EOR designer’s mindset. The primary injectant in the offshore is
seawater and its main derived challenge its proper disposal or reutilization after breakthrough. Close-cycle operations impose
further understanding of the consequences of EOR downstream.

We show that opportunities abound, but disruptive technologies must be evaluated to overcome issues of reservoir
characterization, but we also need deeper understanding of geochemistry and rock-fluid interactions as enablers of close-loop
production. Production acceleration as a vehicle for upfront investment mitigation demands more-than-usual IOR through
conformance. A number of examples of successful strategies offshore show that some of the challenges can be overcome.

The results of this analysis should serve to rank opportunities in a number of basins. The current market provides
opportunities, but a more rigorous analysis of opportunities is required for their evaluation.

Introduction
Oil and gas production in offshore basins introduced new challenges to our industry. This translated into new paradigms such
as unmmaned subsea wells. Shallow offshore operations were developed through anchored platforms, but as water depth
increased, and cost and risk mitigation became even more important drivers for decision-making in these provinces, floating
production storage and offloading (FPSO) units popularized.
Regardless of reservoir/field location, oil and gas recovery, including enhanced-oil recovery (EOR), operate under the same
physical principles (Lake, 1996; Alvarado and Manrique, 2010a). This includes for instance miscibility conditions and
reduction in water-oil interfacial tension, as in miscible gas injection and chemical enhanced-oil recovery with surfactants,
respectively. However, without further considerations of well spacing, injectant delivery and downstream fluid processing as
well as health, safety end environment (HSE), EOR decision making would be fundamentally flawed. This is the reason why
EOR decision-making frameworks (Manrique et al., 2009; Alvarado and Manrique, 2010b) must be conditioned to
adequately evaluate EOR opportunities offshore. Figure 1 shows a cartoon illustrating dire differences between onshore and
offshore EOR operations. Some of these contrasting conditions impact the execution of offshore EOR pilot projects, in
contrast with the more frequently attempted projects onshore.
General considerations that are common to most offshore operations are:
2 OTC-24105-MS

1. Large interwell distance, typically 1 Km or so. This contrasts with the ability of onshore operations to conduct
infill drilling programs that favor EOR designs.
2. Limited platform work area. Although overdesign in offshore environment is generally financially less risky than
underdesigned systems, surface work area and power supply necessary for EOR operations are not usually
available. This includes, but is not limited to compression facilities, separation systems, mixing and softening
units, etc.
3. Seawater as water source. Except in cases where aquifer water is abundant and sufficient quality, seawater
provides a salinity level at 30,000 ppm or higher. This is also characterized by potential seasonal changes in
water chemistry.
4. Limited/stringent water disposal opportunities. The main challenges are to deal with low organic content in
water as well as chemical additives, if disposal takes place in the ocean. This tends to favor in situ (reservoir)
disposal, but injectivity as well as overall reservoir management must be carefully evaluated. Chemical EOR
involves the use of polymers and surfactants, which tends to worsen emulsion stability and scaling.
5. HSE considerations. It is particularly important to consider contingency plans. Assome authors have pointed out
recently (Goodyear et al., 2011), the fact that CO 2 is heavier than air implies that in case of emergency, sea
evacuation might not be appropriate in case of gas leaks.
Offshore

• Seawater or reservoir • Platform or FPSO • Limited chemical disposal

• Associated Gas • Large well spacing • Preferably in reservoir
• Transported from shore • Expensive operating space • Expensive operating space
• Limited processing space • Expensive retrofit • Limited residence time

Injectant Injection System & Separation System &

Source & Processing Facilities Disposal

• Surface or aquifer water • Flexible, tailor-designed • Numerous disposal options

• Associated Gas, pipelines • Infill drilling common • Separation as needed
• Local facilities • Power supply as needed • Cheaper operating space
• Abundant processing space • Viable retrofit • Flexible residence time

Onshore
Figure 1. Contrast between onshore and offshore enhanced-oil recovery operations

Decision making, though intended as a rational activity, namely driven by objectivity, in practice is steered significantly by
perception. One of the main misunderstandings in decision-making is our ability to manage uncertainty, based on the belief
that it can be reduced to ‘aceptable’ levels (Bickel and Bratvold, 2007). This, in turn, leads to fewer decisions to investigate
viability of a recovery process (pilot projects) as well as full deployment of technology. It is known that the fewer the
decisions to move forward, the greater the chance to destroy value (Begg et al., 2003). The large well spacing that
characterizes offshore operations produces less dense reservoir maps based on well data and consequently more uncertain
images of the reservoirs. This adds an additional complexity that relates to longer residence time of fluids in the reservoir.
Several negative consequences of this fact include longer time to see reservoir responses to fluid/energy injection, i.e.
increased production and/or pressure response. This also increases the need for conformance (Alvarado and Manrique,
2010a).
The literature review in this paper shows that new filtration and water-treatment technologies have enabled conditioning
injection water. The paradigm of this is low salinity waterflooding (BP, 2012; Morrow and Buckley, 2011). This also is
potentially benefitial to chemical flooding operations and in particular polymer flooding. However, a missing piece that
requires further R & D emphasis is rock reactivity or more simply attention to geochemical aspects. While a design based on
properly mixing injection and connate brines appears robust, as the reservoir is brought to be out of equilibrium with brine,
the potential of water chemistry to be modified by dissolution/precipitation is prompted (Gregersen et al., 2012). This article
isolates challenges associated with offshore operations through a thourough review of published information and contrasts
this with onshore experiences. An update on offshore EOR is provided, followed by a discussion on screening of offshore
EOR opportunities.

Updates on Offshore EOR

EOR in offshore fields have been assessed over the last decade (Awan et al., 2008; Bondor et al., 2005; Surguchev et al.,
OTC-24105-MS 3

2005). Manrique et al. (2010) and Alvarado and Manrique (2010a) presented a summary review of EOR in onshore and
offshore fields.
Based on this review update, pressure maintenance by gas flooding, waterflooding and Water-Alternating-Gas (WAG)
injection still represent the main recovery strategies applied in offshore fields. CO2-EOR (and storage) continues to attract the
most attention around the world as a strategy to increase oil recovery and extend the productive life of offshore fields.
However, Chemical EOR (CEOR) methods are starting to draw a growing interest around the world, as suggested by an
increased number of pilots scheduled for the next few years. Thermal methods and more specifically High Pressure Air
Injection (HPAI) is the recovery process considered more recently for possible application offshore. However, Thermal EOR
seems to be losing ground, based on the literature review of the last few years.
This section provides a summary review of recent EOR efforts in offshore fields. This review is divided by recovery process:
Gas, Chemical and Thermal EOR methods.

Gas Methods
EOR gas flooding continues to be the preferred recovery process used in offshore fields and this trend is not expected to
change in the near future, especially in carbonate formations. Bourdarot and Ghedan (2012) developed a detailed EOR
screening for offshore reservoirs. Results of this comprehensive evaluation concluded that only gas injection (continuous or
in a WAG mode) represents the most suitable strategy from the operation, e.g. natural gas, and facilities point of view.
However, gas availability, either natural gas or CO2, was highlighted as an issue that can reduce technical and economic
feasibility of these EOR methods. In this particular case N 2 injection may represent the most reasonable strategy, if one
considers the Cantarell Field, offshore Mexico, as a possible business case analog (Sánchez et al., 2005). Abu El Ela (2012)
also reported a comprehensive screening study of Egyptian onshore and offshore fields. Based on reservoir temperature
(140°F to 280°F) and formation water salinity (42,000 to 370,000 ppm), miscible and immiscible gas (or WAG) represented
the most suitable EOR methods, including CO2 injection. However, CO2 availability and its transportation represent a major
challenge despite the existence of several industrial sources where CO2 can be captured. As of today, natural gas re-injection
is the most viable EOR option for offshore fields (e.g. North Sea). Some of the field cases recently documented in the
literature includes:
 A down dip WAG injection pilot was reported in offshore West Africa to reduce gas flaring and increase oil
recovery. The pilot project started in June 2009 and on the basis of the pilot results, a second injector was added as
part of the project expansion (Choudhary et al., 2012).
 Brodie et al. (2012) reported gas/WAG injection experiences in offshore fields (i.e. Magnus, Ula and Harding
Fields) using hydrocarbon gases. Miscible WAG has been a successful EOR process in Magnus and field expansion
will extend production life until 2028. By 2010, 60 to 70% of the field was under miscible WAG and it is expected
to continue its expansion. Ula field started tertiary miscible WAG in 1998 with good results arresting production
decline in the field. In Ula field FAWAG (Foam Assisted WAG) was also tested. FAWAG pilot was declared as
partially successful and despite gas injectivity reduction, the operator still considers it a viable option to delay gas
breakthrough. Harding Field is under immiscible gas re-injection using stable gravity drainage, contributing with
high recovery factors. Additionally, the authors consider that with the experienced gained over the last few decades
in gas and WAG injection, along with the potential availability of CO2 from industrial sources, the productive life of
offshore reservoirs can be extended under CO2-EOR.
 Feasibility studies of WAG with hydrocarbon gases and CO 2 have been reported for mature fields of Baram Delta
Operation, offshore Malaysia. CO2 sources are not available, but there are different scenarios under consideration
(Valdez et al., 2011).
 Water and gas injection are also expected to grow offshore Abu Dhabi and potentially in other regions in the Middle
East (MacPherson and Denly, 2012).
CO2 injection as an EOR and storage strategy continues to gain lot of attention, especially for offshore fields. Sweatman et al.
(2011) suggest that offshore CO2 EOR/CCS projects are more viable than onshore fields located in populated areas and
where fields are at reasonable distance from shore, which is not always the case. There is no doubt of the potential of CO2 to
increase oil recoveries. However, CO2 costs, required injection volumes, i.e. tankers vs. pipeline, production acceleration in
high well spacing, i.e. project economics, and fields approaching their economic limit are some of the key unresolved
challenges of CO2 EOR/storage offshore.
U.S. Gulf of Mexico (GOM) is not the exception for CO2 EOR/storage offshore. ARI (2005) suggested that through a sharing
risk between public and private sectors and reasonable CO2 costs, 3.6 billion barrel can be produced offshore Louisiana over
a 40-year period, delaying platform abandonment/decommissioning. Years later, Koperna and Ferguson (2011) reported that
CO2-EOR in the GOM could increase oil production in 5.8 billion plus the benefits of CO2 storage. However, approximately
13% can be recovered assuming an oil price of $US 70/bbl and a CO 2 cost of $US 2.2/ MMscf ($US 45/ton). Therefore,
authors suggested that higher crude oil prices and lower CO2 costs are required to materialize CO2-EOR potential before
fields are abandoned and facilities are dismantled. Incentives such as reduced royalties and credits for CO 2 storage have been
also proposed as strategies to materialize CO2 EOR potential in the GOM. Tippee (2012) recently reported that the technical
incremental oil recovery potential of CO2-EOR offshore U.S. was estimated in 6 billion barrels. However, only 0.9 billion
4 OTC-24105-MS

barrels are estimated to be economic assuming an oil price of $US 85/bbl, $US 40/ton of CO 2 and 20% rate of return after
taxes. The incremental oil potential offshore U.S. represents only 1.34% of the total in the U.S. (including Alaska and Lower
48 onshore) assuming same economics. The use of CO2 viscosifiers, polymer gels and foams are considered as potential
game changers to materialize CO2 EOR potential in the U.S., especially onshore.
Despite all complexities associated to CO2 capture and transportation for CO2-EOR and storage offshore, there are multiple
efforts ongoing from the laboratory to the process design to move CO2-EOR from onshore to offshore. Examples include:
 Laboratory study to evaluate the CO2 potential for chalk formations in Danish North Sea (Olsen, 2011).
 Feasibility study of WAG-HC or WAG-CO2 for mature fields of the Baram Delta Operation, offshore Malaysia.
CO2 sources are still not available, but different approaches are under consideration (Valdez et al., 2011).
 Assessing the challenges of moving CO2 flood experiences onshore to offshore environments including safety, well
architecture and completion, CO2 gas lift, subsurface and possible pilot strategies (Goodyear et al. 2011).
 Strategy to optimize CO2 injection in an offshore Brazilian field. In addition to conventional screening, fluid and
simulation studies and, key non-technical reservoir aspects were also evaluated including equipment materials, HSE
and gas processing capacity. The best approach for the field under evaluation was the use of WAG-CO2 and
scenarios evaluated meet gas processing capabilities available. Potential limitations of CO2 injection in mature
offshore fields were also addressed (Rosa and Branco, 2012).
 Process design aspects to consider CO2 EOR offshore (Salim et al., 2012).
 Abu Dhabi strategy to capture CO2 from industrial sources (i.e. Emirates Steel Industries PJSC) is under
consideration through a joint effort Abu Dhabi National (ADNOC) and renewable energy companies. The main goal
of this study is to support potential CO2-EOR projects (Daya, 2012).
However, two of the most relevant field projects reported in the literature are the WAG-CO2 pilot in Lula Field, offshore
Brazil, and the CO2 Huff-n-Puff pilot in Rang Dong Field, offshore Vietnam, briefly described below:
 Lula Field is a carbonate light oil reservoir (28-30°API) located in ultra-deep waters (1,800 – 2,400 m) in the area of
Santos Basin Pre Salt Cluster. The associated gas in the reservoir contains roughly 25% CO 2 and the decided
strategy is to avoid venting CO2. The operator decided to test CO2-EOR strategies to store the CO2 streams and
increase recovery. WAG-CO2 pilot started in April 2011 injecting hydrocarbon gas with high CO 2 content. In
September 2011, CO2 was separated from the produced gas, exporting natural gas to shore. At this time, the CO2
content in the injected gas was higher than 80%. Preliminary results suggest that CO 2 injection is a good strategy
and a detailed project monitoring will continue to validate technical and economic feasibility for a possible field
expansion (Pizarro and Branco, 2012a & 2012b).
 Rang Dong field reported a CO2 Huff-n-Puff test in May 2011. The field is located 135 Km offshore Vietnam. CO2
was obtained from a fertilizer and chemical company (99.97% purity) north in the country. The CO2 was trucked
1,800 Km and transferred to storage tanks installed in the vessel used for the project. Project was successful at
increasing oil rates and reducing water cuts. Changes in oil composition were also observed. Based on the results of
this CO2 cyclic injection, an inter-well test was proposed as the next step of the project before a possible field scale
application (Ha et al., 2012).
Regarding the use of N2 or flue gases in EOR gas flooding, no new offshore projects has been documented during the past
few years. GOM in Mexico is still having the world largest N2 injection projects in the Campeche Bay Area (i.e. Akal-
Cantarell). Ku Field started in 2009 pressure maintenance by N 2 injection (160 MMscf/d). Injection rate was increased to 250
MMscf/d by the end of 2011 to maintain reservoir pressure and delay the advance of Water Oil Contact in this highly
fractured carbonate reservoir. Ku is one of the offshore oil fields located in the Ku-Maloob-Zaap (KMZ) Asset where more
immiscible N2 floods are expected to start in years to come due to existing installed capacity in the area. Due to vast oil
reserves in offshore highly fractured carbonate formations, Mexico continue its efforts evaluating the contribution of fluid
flow from natural fractures using geomechanical approach (Cruz et al., 2009) and, gas conning and channeling management
in naturally fractured reservoirs (Rodriguez-de la Garza et al., 2012). Double Displacement (DDP) and Second Contact Water
Displacement (SCWD) Processes have been also under study for possible application in HT/HP naturally fractured
reservoirs. From this study, DDP with natural gas showed better recoveries than N2. The use of surfactant as wettability
modification was also proposed, but with limited benefits (Gachuz-Muro et al, 2011). However, the possible effects of N 2
injection on oil viscosity increase due to vaporization that also occurs during immiscible conditions and its impact on limiting
oil to flow from the rock matrix to natural fracture network has not been addressed in the literature. Although gas conning
and channeling can be dominated by the permeability contrast between fracture and rock matrix, the increase of oil viscosity
generally observed by N2 injection can also limit oil flow capacity out of the carbonate matrix, limiting oil production rates
due to possible blocking effects of viscous oil at the fracture: matrix interface.
Finally, the use of Flue Gases has been considered in screening studies for Offshore Newfoundland light oil reservoirs
(Hibernia, Terra Nova and White Rose Fields) in Canada (Thomas et al., 2010). Fields under evaluation are located more
than 300 Km from shore in very harsh offshore environment. Therefore, authors suggest that the only option for flue gas
injection will depend on volumes generated on site (i.e. from gas turbines). Removal of flue gas contaminants, flue gas
compression and power supply requirement combined with weight capacity limit represents one of the key challenges for the
applicability of this recovery process. Preliminary screening discarded technical and economic feasibility of flue gas injection
OTC-24105-MS 5

in White Rose Field.

Chemical Methods
Chemical EOR (CEOR) in offshore fields has drawn growing interest during the last few years. Recent advances in chemical
additives, increased number of onshore pilots and experience gained in Bohai Bay (China) and Dalia (Angola) polymer
floods is somehow framing the possibility to scale-up CEOR projects in offshore environments. From this review it can be
noticed that the increasing activity in low salinity water injection is opening new options to implement and optimize CEOR
projects. Therefore, this is another variable that needs to be considered when performing EOR screening specifically for
offshore fields. Additionally, possible long term availability of CO 2 (probably in few regions), CO2 costs and legal
framework, among other challenges described in the previous section, may contribute reducing implementation cycle of
CEOR pilots and before offshore reservoirs reach its economic limits. This section of the paper presents an overview of
conformance technologies, low salinity waterflooding and CEOR activities reported recently. The evaluation of microbial
and nanotechnology EOR applications will be also briefly addressed.

Conformance technologies with polymer gels continue to support water shut-off strategies and waterflooding optimization in
offshore fields. Turner and Zahner (2009) reported a successful water shut-off treatment in a naturally fractured shale
formation (Monterrey Fm.) offshore California. Su et al., (2012) reported a successful gel treatment pilot to modify water
injection profile in a heavy oil field offshore China. This multi-well pilot was run between 2009 and 2011 and the results
suggest that conformance treatment can be used to reduce water channeling/production in waterfloods under adverse
mobility. In-depth conformance (BrightWater®) technology has been also used to optimize offshore waterfloods
(Roussennac and Toschi, 2010). However, there are recent offshore applications in Asia and Africa not documented in the
literature in addition to ongoing evaluations for possible field applications in the near future. In general, conventional
polymer gels or thermally activated polymer (BrightWater®) treatments are technologies tested in offshore fields. It is highly
probable that both strategies will be part of future CEOR offshore to delay possible breakthrough of chemical additives
injected, e.g. polymers and/or surfactants. This assumption is based on ongoing onshore field cases (i.e. El Tordillo Field in
Argentina and confidential field in the U.S.). In the U.S case polymer gels have been used to modify water injection profile
before or during the injection of Colloidal Dispersion Gels (CDG’s) and Alkali-Surfactant-Polymer (ASP) optimizing sweep
efficiency, oil recoveries and reducing the probability of producing injected chemicals, which will be critical for offshore
operations from the environmental perspective and treatment of produced fluids.
Low salinity adjusting brine composition or designed water to improve oil recoveries under waterflooding is definitively
showing a growing interest for onshore and offshore applications. Several laboratory studies using sandstone and carbonate
core material have reported increases in oil recoveries by low salinity waterflooding. However, operating mechanisms are
inconclusive or not well understood (Morrow and Buckley, 2011; RezaeiDoust et al., 2010; Winoto et al., 2012; Zahid et al.,
2010). On the other hand, LoSal® process is scheduled to start in Clair Ridge (offshore UK) and Mad Dog Phase 2 project in
the GOM (Beckman, 2012a; BP, 2012; Robbana et al., 2012). Clair Ridge is expected to increase oil recoveries in excess of
42 MMbbls compared to conventional sea water injection. Reddick et al., (2012) reported a detailed methodology to evaluate
and manage LoSal® recovery process in onshore and offshore fields.
Independently of the discrepancies identified in the literature regarding the possible mechanisms of low salinity water
injection, this area may lead to important water treatment strategies that can benefit to some extent CEOR implementation
offshore (Walsh and Henthorne, 2012). Ayirala et al. (2010) suggested that the desalinization approach will enable Low
salinity waterflooding and potentially polymer floods reducing its costs and complexity in offshore environments. Recently,
Henthorne and Wodehouse (2012) presented an overview of membrane technology that can support Low Salinity
waterflooding and CEOR projects offshore and onshore. In their work it was suggested that the low number of reverse
osmosis and nanofiltration products available with selective salt rejection capabilities is expected to increase due to increased
interest in offshore CEOR. Although laboratory and field evidences of low salinity waterflooding improving incremental oil,
its economics needs to be demonstrated at offshore scale where reservoir volumetrics and well spacing (i.e. water mixing and
production response) may demand high CAPEX. Additionally, the lack of reliable predictive tools may represent another
challenge for low salinity waterflooding designs as a stand-alone oil recovery process. However, the availability of low
salinity injection water will increase the probability of success of offshore CEOR, especially in high temperature reservoirs.
Regarding CEOR offshore, Bohai Bay (Luo et al., 2011; Zhao et al., 2010; Zhou et al., 2008; Xiaodong et al., 2011) and
Dalia (Morel et al., 2008; Morel et al., 2012) polymer floods represents the most relevant projects during the last decade.
Both field experiences are paving the way of polymer flood offshore and possible more complex CEOR such as SP or ASP.
By 2010 Bohai Bay polymer flood offshore China reported a total of 27 injectors distributed in 5 platforms and an
incremental oil of 6 million barrels (Luo et al., 2011; Xiaodong et al., 2011). Dalia polymer flood offshore Angola started in
January 2009 and detailed evaluation, field implementation including surface facilities has been described by Morel et al.
(2008 & 2012). Lessons learned from these projects will definitively contribute to optimizing CEOR offshore. Gao (2011)
presented a review of polymer floods in onshore and offshore heavy oil reservoirs reporting polymer shear degradation in
surface facilities as one of the main challenges to keep polymer viscosity at reservoir conditions. During the last few years
several studies assessing the potential of CEOR including subsurface and surface for offshore operations have been reported
in the literature:
6 OTC-24105-MS

 Screening study for offshore carbonate reservoirs concluded that surfactant-polymer (SP) was considered as a very
challenging possibility due to high reservoir salinities and temperatures combined with a limited experience in
onshore carbonate reservoirs (Bourdarot and Ghedan, 2011).
 Evaluation of polymer and SP floods in an offshore Egyptian viscous oil reservoir (17 - 24 cp) located in the Gulf of
Suez. The main limitations highlighted to implement polymer flooding were water quality, limited number of
injectors and surface facilities (Shehata et al., 2012).
 Comprehensive polymer rheology (HPAM and AMPS) and coreflood study reporting that high molecular weight
polymers (i.e. HPAM) can lead to poor injectivity or cause fracturing under typical injection shear rates in offshore
matrix formations. This study also concluded that permeability reduction increases with the increase of polymer
molecular weight (Stavland et al., 2010).
 Polymer flood evaluation for Mariner Field in the UK sector of the North Sea. Mariner field is a shallow heavy oil
(12-14 °API) with two main reservoirs, Maureen (67 cp) and Heimdal (508 cp). Development strategy of Maureen
reservoir will consider the use of horizontal wells at the top of the formation to partially mitigate low productivity,
increase contacted pore volume and delay as much as possible water encroachment (from bottom aquifer) under
adverse mobility ratio. Challenges under evaluation for the development of this field include water handling
capacity, water/oil emulsions, flow assurance and well completions in an unconsolidated formation, among others
(Berg at el., 2011). The possibility of polymer flooding in Mariner and Heidrun (Offshore Norway) was also
referred by Beckman (2012b).
 Field development challenges of Mariner and Bressay heavy oil fields offshore UK was described by Berg (2011).
Paper also assesses subsurface related issues on Bressay Field. These fields have 11-14°API oil with viscosities
ranging from 65 cp to 540 cp at reservoir conditions.
 Technical feasibility, risk assessment and EOR potential of ASP injection in St. Joseph Field, offshore Sabah,
Malaysia (Chai et al., 2011; Du et al., 2011; Lo and Jamaludin, 2011). PDE (2012) recently reported an important
investment to evaluate ASP in North Sabah Field, offshore Malaysia.
 Surface and subsurface requirements to implement CEOR in offshore fields (Raney et al., 2012). Some of the areas
highlighted during this study include: new chemicals and equipment amenable to offshore will likely be needed for
efficient water/oil separation, subsurface and surface challenges needs to be addressed simultaneously. Additionally,
to accelerate transferring CEOR experience from onshore to offshore application multidisciplinary R&D involving
operators and service providers will be required.
 Detailed description of challenges and best practices for crude oil demulsification in CEOR projects. Short retention
times and limited space are key areas of attention for offshore fields which needs to be considered when designing
CEOR (Nguyen and Sadeghi, 2012).
 Challenges of water treating for CEOR highlighting the importance of oil/water emulsion tendencies, among other
key variables for offshore projects (Walsh and Henthorne, 2012).
 The use of dedicated vessels for low salinity and/or CEOR was evaluated. Authors suggest that dedicating an
independent unit may reduce cost and implementation of EOR projects offshore (Wodehouse and Henthorne, 2011).
Some EOR methods proposed for offshore fields, different than conventional polymer and surfactant (A/SP) floods,
documented in the literature includes:
 Laboratory study evaluating the use of Ferro magnetic nanoparticles (Ferro fluids) for surfactant flooding (Kothari et
al., 2010).
 Study proposing the use of nanotechnologies to support EOR offshore fields where large volumes of chemical
additives are required (Ayatollahi and Zerafat, 2012). However, authors do not propose specific technologies that
can replace/assist EOR processes in the short to mid-term.
 JIP started to evaluate the potential of feeding reservoir microorganisms as an EOR strategy to increase oil recovery
in the Danish North Sea (Offshore, 2011).

Thermal Methods
Thermal EOR methods practically do not seem to have attracted a lot of interest for offshore applications. Despite the
completion of a screening study to evaluate High Pressure Air Injection (HPAI) in Newfoundland light oil reservoirs offshore
Canada (Thomas et al., 2010), review of thermal methods for carbonate formations for possible application in heavy oil
reservoir such as Ferdows Field, offshore Iran (Ghoodjani et al., 2012) and technical feasibility study of using downhole
electrical heating in Zatchi Marine Field (15-27°API), offshore Congo (Szemat et al., 2010), there is not much interest in
thermal EOR methods for offshore applications during the last few years. The only field application identified during this
review was the cyclic steam injection in Bohai Bay Field, offshore China. This particular project started in 2009 and steam
was co-injected with flue gas reporting an increase in oil productivity of 2 to 3 times (up to 100 m3/day) by the
implementation of this stimulation method (Yongtao et al., 2011).

Based on this EOR update review for offshore fields, thermal EOR methods do not seem to have an important impact in
offshore oil production during the next decades compared to gas and chemical EOR methods.
OTC-24105-MS 7

Closing Remarks: EOR Screening in Offshore Reservoirs

The reviewed publications and reflexions in this article clearly indicate that some of the lessons from onshore practices,
particularly in regards to EOR screening are somewhat translatable to offshore EOR analysis. Care must be exercised,
though, given the apparent constrainst that field operations in these environments impose. The investment in analyses that
neglect soft issues (Manrique et al., 2009), such as the supply side or downstream disposal of fluids, particularly when
legislation forbids the use of certain additives, can lead to frustration and misallocation of resources. Most offshore designs
are tightly constrained to meet stringent financial ceiling of projects. This implies that often retrofitting facilities might not
been financially justifiable, so assumptions on subsurface operations might be misguided. A more holistic entry analysis that
necessarily includes data screening must, in turn, include soft issues early enough. Numerous EOR screening methodologies
have been proposed over several decades including lookup tables (Taber et al., 1997a & 1997b), fuzzy logic (Alvarado et al.,
2008), neural networks and data mining (Alvarado et al., 2002) techniques. Whatever the approach, they are all affected by
the biased introduced by practice, namely the dominant R&D, pilot and full field project, mostly onshore. With the exception
of WAG is perhaps the only EOR process that reflects enough offshore tradition (experience) to balance some of the bias
driven by onshore experience. A recent workflow for EOR decision-making (Manrique et al., 2009) introduces the notion that
soft issues must be evaluated prior to any significant decision making, namely before performance predictions take place (this
includes analytical simulations). The reason for this is that no matter how simple or sophisticated models are, significant
human resources are allocated and decisions delayed, creating a potential situation for sinking value (Begg et al., 2003).
Some of these considerations specific to offshore are listed as follows:
 Declining production in offshore fields (i.e. Europe and offshore Asia/Pacific) will need additional investments in
infrastructure and EOR technologies to be able to sustain current levels of production. Tax incentives for mature fields
might be required to promote the implementation of EOR projects. For example, UK government introduced a tax
relief for mature North Sea fields with the intention to encourage investments in mature assets and delay
decommissioning (Beckman, 2012c; O&GJ, 2012)
 Gas injection (continuous or WAG) will continue to dominate EOR in offshore environments, especially using
hydrocarbon gases. Gas re-injection followed by reservoir depressurization will be most common development plan,
unless feasible EOR strategies are technically and economically justified before abandonment/decommissioning. The
evaluation of CO2 will continue to grow due to its potential to increase oil recovery and extend reservoir production
life. However, low CO2 costs, tax incentives and regulatory framework needs to be in place in order to become a
feasible option for some offshore areas in the world. Finally, Nitrogen injection will continue to be important offshore
Mexico due to installed capacity and number of fields with access to N 2 sources. N2 injection will continue to be a
viable option in large offshore fields with high natural gas demand for power generation/export (competing gas
market) or without access to CO2. N2 injection will be preferred under miscible conditions to justify CAPEX (i.e. Air
separation units) and OPEX (i.e. N2 rejection, if needed) associated to this recovery process.
 Challenges of Chemical EOR (CEOR) in offshore environments:
o Platform space and weight limitations (use of dedicated vessels/FPSO could be an option). SP will have an
advantage over ASP due to smaller mass of chemicals required and the reduced the probability of severe scale
formation due to the interaction of alkali with reservoir rock and waters. Additional considerations can include:
 SP generally uses surfactant concentrations from 0.5 to 1.0 wt% and ASP from 0.1 to 0.5 wt%. However,
alkaline concentrations in ASP formulations are between 1 to 2 wt%.
 Some commercial surfactants can be delivered at very high concentration of active material (up to 85%
without solvents), which will reduce space and storage requirements for CEOR.
 Use of liquid vs. dry polymers needs to be considered (i.e. space and time required for dry polymer hydration).
o Remote locations making difficult to transport chemicals using pipelines from shore. High CAPEX and high
shear degradation of conventional HPAM polymers are key limiting factors (use of dedicated vessels/FPSO
could be an option).
o High well spacing (Pore Volumes) may delay oil response (infill drilling is a limited option). Well spacing will
also require stable chemical additives, especially in high temperature and salinity conditions.
o High injection rates can contribute with production acceleration. However, high polymer degradation and high
volumes of chemicals should be expected.
o Limited retention times and space for produced fluids treatment (e.g. demulsification). Limited options for
water disposal might be also applicable.
o Sea water and/or high brine formation salinities combined with high reservoir temperatures can limit the
applicability of CEOR. However, there are several ongoing (unpublished) SP pilots at low temperatures (80-
100°F) operating in the U.S. with salinities between 40,000 to 100,000 ppm and water hardness (Ca 2+ + Mg2+)
from 3,000 to 6,000 ppm that can generate further knowhow for possible future offshore applications.
o Weather conditions may also represent an important challenge for project implementation.
8 OTC-24105-MS

o All the above explain the reduced number of CEOR pilots implemented in offshore fields. Bohai Bay and Dalia
polymer floods represent two projects leading the way to optimize polymer flooding at larger scale and more
complex chemical methods.
o New chemicals (i.e. polymers resistant to shear degradation and environmentally acceptable chemicals) and
injection/produced water treatment strategies will be required to materialize CEOR potential in offshore fields.
 Thermal EOR methods do not seem to be a viable option for offshore fields. HPAI might be applicable in cases
where is justified. Corrosion and high temperatures can represent most important challenges of this recovery
process.
A potential avenue to follow in terms of screening projects offshore is to incorporate downstream soft-issue considerations
(production fluid processing) and geochemistry. In this sense, if for instance rock reactivity (geological/geochemical
characteristics) is significant in time scales of potential floods, this information should be incorporated in the screening of
designed water and chemical floods. This could advance a more selective screening strategy for offshore projects.

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