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Recent
Publications Using Oil Chem Technologies Products
Laboratory Aspect of Chemical EOR Processes Evaluation
for Malaysian Oilfields
SPE 100943
(2007)
This paper deals with the application of various surfactants
for use under extremely harsh conditions of salinity
and temperature. Surfactants including ORS-164HF, SS-7064,
ORS-41HF, ORS-57HF, ORS-49HF were screened for thermal
stability, phase behavior, ability to reduce IFT and
maintain low IFT upon dilution with connate brine, compatibility
with polymer and alkali. It was found that softening
of the water was necessary in order to use Alkaline
Surfactant (AS) or Alkaline Surfactant Polymer (ASP)
processes to recover residual oil. Processes employing
alkali alone or surfactant and/or polymer alone without
alkali recovered little incremental oil. AS flooding
recovered an average of 14.6% OOIP and ASP flooding
recovered an average of 28.6% OOIP. Temperatures were
about119oC and salinities were about 39,000 ppm TDS.
Meeting the Challenges in Alkaline Surfactant Pilot
Project Implementation at Angsi Field, Offshore Malaysia
SPE 109033
(2006)
This paper describes the design of an offshore Alkaline-Surfactant
(AS) pilot project employing Sodium Hydroxide and 6-72LV
surfactant and softened seawater. Reverse osmosis will
be used to soften the seawater. The paper deals with
the various aspects of planning to implement a single
well tracer test (SWTT) including safety, product registration,
facilities, softening equipment, water supply and quality,
The results from the SWTT will be used to plan and implement
a future large scale offshore project.
Alkaline-Surfactant-Polymer Flood of the Tanner
Field
SPE 100004
(2006)
This paper describes the results obtained with an Alkaline-surfactant-Polymer
Flood (ASP) in the Tanner Field, Campbell County, Wyoming.
Softened water containing 1.0 wt% NaOH, 0.1 wt% ORS-41
and 1000 ppm Alcoflood 1275A was employed following
waterflooding. The ASP flood was initiated in April
2000 at a 43% oil cut. A single injection well and two
production wells were employed. 642,700 bbls (0.251
PV) of ASP solution was injected followed by 644,685
bbl (0.252) of a tapered polymer slug. This was followed
by a water flood beginning in January 2005. A total
of 236,000 bbl (0.092 PV) of water were injected through
December 2005. Response to the ASP was detected after
six months of injection. ASP is projected to recover
17% or 340,000 bbls of oil. As of December 2005 1,013,928
bbls of oil was produced by primary, secondary and ASP
flooding. Oil cut at this time was 14%. The cost of
producing incremental oil from ASP including chemicals,
plant, and design was $5.82/bbl
Single Well Alkaline-Surfactant Injectivity Improvement
Test in Big Sinking Field
SPE 89384
(2004)
This paper describes a single well test in the Big
Sinking Field in Eastern Kentucky to determine the feasibility
of using Alkaline-Surfactant to improve injectivity.
Sodium carbonate at concentrations of 0.5 to 2.0 wt%
along with ORS-62HF at 0.1 wt% was used in fresh water.
Water injectivity was increased 320% in the laboratory
and 220% in the field using 0.5 wt% NaOH and 0.1wt%
ORS-62HF. The results show that a properly designed
alkaline-surfactant solution has the ability to significantly
increase the effective permeability to water. Using
the oil price of $25/bbl at the time of the test, the
payout time was approximately 8 months. A field wide
proje
Laboratory Study of "Super"
Surfactants as Candidates in Surfactant Flooding
13th European Symposium on Improved Oil Recovery
Budapest, Hungary, April 2005
This paper presented by Professor I, Lakatos of the
University of Miskolc in collaboration with the Hungarian
Oil and Gas , E&P Division and Oil Chem Technologies
describes the use of certain Oil Chem Technologies super
surfactants in laboratory core tests at concentrations
of
< 5g/l. This detailed study comprised the determination
of surface and interfacial tensions, CMC, bulk and interfacial
rheological properties, transmission and back-scattering
photon correlation analysis of micelle properties and
oil solubilization, phase behavior, wettability effects
and flooding tests. The surfactants were found to reduce
the interfacial tension by four orders of magnitude.
Laboratory tests using ASP and Alkaline-Surfactant followed
by Polymer (AS + P) were developed and resulted in an
increase of 20% in displacement efficiency. A single
low tension water flooding technology was evaluated
that provided a positive effect on mobility control
(sweep efficiency) and oil recovery. In the future,
the new methods may form one of the alternatives in
the IOR/ EOR strategy at the Algyo field in Hungary.
Selected U.S. Department of Energy's EOR Technology
Applications
SPE 84904,
October 2003
This paper presented at the SPE International Improved
Oil recovery Conference describes several field projects
using various EOR technologies including Steamflooding,
Biotechnology, Alkaline-Surfactant-Polymer Formulations
(ASP), Carbon Dioxide Viscosifiers, and Microhole Technology.
The ASP discussion involves the selection use of Oil
Chem Technologies ORS-62 with Sodium Carbonate in the
Warden Unit of the Sho-Vel-Tum field in Oklahoma. Total
chemical cost per incremental barrel of oil was $6.41.
It was estimated that this could be lowered to $4/ barrel
if the pilot unit was used to supply four injection
wells instead of the one test well. This project added
10,444 bbl of incremental oil in 1.3 years. The project
received "Best New Technology in the Mid Continent
Region" award from Hart's Oil and Gas World. DOE
states that the benefits of this project "included
information and data that helped demonstrate the applicability
of surfactant-enhanced alkaline flooding as a cost-effective
EOR method, transfer of surfactant-enhanced alkaline
flooding technology to the petroleum industry, and information
regarding procedures for designing and applying the
technology that will assist operators to sustain production
from mature oil fields rather than abandoning marginal
wells."
Determining the Most Profitable ASP Flood Strategy
for Enhanced Oil Recovery
Canadian International Petroleum Conference June 2003
This paper by Zhang and Huang of SRC and Dong of University
of Regina discusses the selection of the optimum ASP
formulation for a 23.8 API crude oil at 50 C with 4310
PPM water containing 30 mg/L divalent ions. ORS-62HF
was found to give extremely low IFT using 0.08 wt% surfactant
and 1.0% NaOH. Using 0.5 PV of solution on sandpacks
resulted in recovery of 54% ROIP. The effect on residual
oil recovery of different concentrations of surfactant
and NaOH as well as different ratios of the two and
injection of various pore volumes is discussed. Higher
residual oil saturation in non-waterflooded cores help
the ASP form an oil bank indicating that if possible
ASP should be applied early in reservoir life to obtain
higher oil recoveries. Corefloods using live oil and
dead oil indicated that the final oil recoveries do
not differ significantly, no matter what type of oil
is used in ASP coreflooding. Copies of this presentation
are available upon request.
ASP System Design for an Offshore Application in
La Salina Field, Lake Maracaibo
SPE 84775,
June 2003
This paper by Hernandez, Chacon, Anselmi and Baldonedo
of PDVSA and Qi, Dowling and Pitts of Surtek, Inc. was
first presented in March of 2001 at the SPE Latin American
and Caribbean Petroleum Engineering Conference held
in Buenos Aires. The paper describes the selection of
the proper surfactant formulation for an ASP project
to be initiated in Lake Maracaibo on 25 API gravity
oil. Linear and radial core tests as well as phase studies
were conducted. Interfacial tension reduction up to
25,000 fold was observed with some ASP formulations.
The logistics and difficulties in preparing the offshore
site for the ASP injection are discussed. Some of the
critical factors to be considered are equipment footprint
minimization, storage space for injection chemicals,
preparation and transport of ASP solution through injection
lines as well as concentrations and physical characteristics
of the polymer, surfactant and alkali. After testing
23 commercial surfactants, ORS-47HF was chosen for the
pilot field test scheduled to begin in the fall of 2003.
Copies of this paper are available upon request.
New Surfactant for Chemical Flood in High-Salinity
Reservoir
SPE 80237,
February 2003
Evaluation of the chemical flood potential in the Chihuido
de la Sierra Negra field, Argentina, has been carried
out using several different recovery scenarios. This
field has been submitted to extensive waterflooding
for several years, and surface facilities have been
designed to recycle produced brine as injection brine.
The use of produced brine, as chemical solution make-up
water is therefore very advantageous from both an operational
and economical point of view. However, the formation
brine contains around 110,000 PPM Total Dissolved Solids
with around 2,800 PPM divalent cations. This makes the
selection of the proper surfactant extremely difficult.
Processes such as Alkali Surfactant Polymer Flooding
have been considered, however, the requirement of large
amounts of fresh water as well as softening units in
the field adversely affects the economics of this process.
This paper discusses the development of a new anionic
surfactant that provides solubility in high salinities
and low interfacial tension at low concentration. The
Chihuido de la Sierra Negra field history is briefly
described, and the laboratory screening and evaluation
of the surfactants, including the interfacial tension
properties, the adsorption, the core evaluation, and
the performance of the flood will also be discussed.
Ultra-low Concentration Surfactants for Sandstone
and Limestone Floods
SPE 75186,
April 2002
A new type of surfactant has been developed that can
be used at very low concentrations to produce ultra-low
interfacial tensions (IFT) for sandstone and limestone
formations. These surfactants can be used for Alkaline
Surfactant Polymer (ASP) floods, surfactant floods and
as an adjuvant for water floods. These new types of
surfactants differ from traditional surfactants used
in ASP and surfactant floods by offering the following
advantages:
· Low concentration levels - They are effective
at low concentration levels normally used for ASP but
do not require alkali to produce low interfacial tensions
in sandstone formations. For limestone formations, sodium
carbonate is normally preferred to reduce adsorption
however it is not needed to produce ultra-low IFTs.
· Salt tolerance - They are very salt tolerant.
Case studies using this new type surfactant in brines
with ~110,000 PPM total dissolved solids (TDS) and ~2500
PPM divalent cations show excellent interfacial tension
lowering, even at 0.05% surfactant levels. The injection
water does not need to be treated or softened, which
can result in a tremendous cost saving for IOR applications.
· Emulsion, corrosion, and scale reduction -
Problems such as emulsion formation, scale, corrosion,
etc. are minimized because only low concentrations of
surfactant are needed and alkali is not required to
produce ultra-low interfacial tensions.
First Ultra-Low Interfacial Tension Flood Field Test
Is Successful
SPE 71491,
October 2001
This paper describes the results of laboratory and
field tests comparing Alkaline Surfactant Polymer Flooding
to Alkaline Surfactant Foam Flooding. ASP liquids without
polymer were found to form stable foams when mixed with
natural gas and gave ultra-low IFTs. Natural Gas at
ratios of 1:1 to 5:1 to injection fluid containing 0.3%
(active) ORS-41ä and 1.3% NaOH was evaluated for
incremental oil recovery over water flooding and ASP
flooding. Incremental increases of 10.1 to 14.4 over
ASP and 26.7 to 30.6 over water flooding was found in
laboratory tests with the best results occurring at
a gas/liquid ratio of 3:1 by volume. Injection pressures
in field test gave 100% increase, while ASP gave 32.1
and 35.6 % increase and water flooding gave an increase
of 4.3%. Final recovery of field tests is predicted
to be about 70% OOIP.
Summary of ASP Pilots in Daqing Oil Field -
SPE 57288,
1999
This paper compares laboratory and field data using
several ASPF Techniques using various surfactants, polymers
and bio-surfactant with NaOH and Na2CO3. Surfactant
was found to be compatible with bio-surfactant. Some
damage to the formation was detected with both NaOH
and Na2CO3 but it was not significant. Chromatographic
separation also occurred but was not significant. Numerical
simulation and pilot results showed that more than 20%
OOIP oil recovery was obtained over water flooding.
Surfactant B in this paper is Oil Chem Technologies'
ORS-41®.
Design and Operation of the Sho-Vel-Tum Alkali-Surfactant-Polymer
Project
Hart's Petroleum Engineering International, Dec. 1998.
Planning and Implement of an Alkali-Surfactant-Polymer
(ASP) Field Project
DOE/PC/910087-0328 (OSTI ID: 3994)
These articles describe the successful application
of ASPF to a southern Oklahoma field. The upper sand
of the formation was about 12 feet of porous sandstone.
Average current oil saturation is 32.6% PV and average
permeability is about 300 md. Oil Chem Technologies,
Inc. ORS-62TM was used as the surfactant, along with
Na2CO3 as the alkali and Allied Colloids 1275A polymer.
ORS-62TM was chosen for its potency in reducing IFT
(down to 10-5 mN/m in some cases) and its ease of handling
in cold weather. Oil production increased rapidly until
170 days into the flood, when it leveled out at about
22 bbl/d - a five-fold increase. This production rate
continues to the present. ASP response occurred slightly
earlier than was predicted by simulation.
An Alkaline/Surfactant/Polymer Field Test in a Reservoir
with a Long-Term 100% Water Cut
SPE 49018,
1998
This paper describes an extended field test using Oil
Chem Technologies's ORS-41®. The results of the
flood exceeded predictions. Incremental recovery was
16-17% of OOIP over 100% water cut by water flooding
or more than 25% over 98% water cut by water flooding.
A large oil bank was formed. A large amount of emulsion
was formed in the produced fluid with viscosities as
high as 140 mPa·S, but this was resolved with
a newly developed demulsifier which broke the emulsions
easily. Chromatographic separation was not a serious
problem and the test was deemed a technical and economic
success.
Pilot Test of Alkaline Surfactant Polymer Flooding
in Daqing Oil Field
SPE 36748,
1996 / SPE Reservoir Engineering, Nov. 1997
This paper describes two ASP flood fields in Daqing,
China. The surfactant B used in XF Pilot area is Oil
Chem Technologies's ORS-41®.
The field trial was run in 8.4m thick sandstone at a
depth of 830m. The temperature was 48oC and the oil
viscosity 6 - 8 mPa·s. Connate water salinity
was 6,800 mg/L. Average porosity was 26.0%. Sodium hydroxide
was used as the alkali. Oil recovery increased from
12 bbl/d to 62 bbl/d and water cut decreased from 96.9%
to 82.4%. No problems were encountered with emulsions
during recovery of the oil
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