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.


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.