Alkaline/Surfactant/Polymer Flood: From the Laboratory to the Field

2011 ◽  
Vol 14 (06) ◽  
pp. 702-712 ◽  
Author(s):  
W. M. Stoll ◽  
H.. al Shureqi ◽  
J.. Finol ◽  
S. A. Al-Harthy ◽  
S.. Oyemade ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Test Tube ◽  
Full Field ◽  
Asp Flooding ◽  
Chemical Eor ◽  
Single Well ◽  
Hydrocarbon Gas ◽  
Reservoir Simulation Model ◽  
Petroleum Development ◽  
Alkaline Surfactant Polymer

Summary After two decades of relative calm, chemical enhanced-oil-recovery (EOR) technologies are currently revitalized globally. Techniques such as alkaline/surfactant/polymer (ASP) flooding, originally developed by Shell, have the potential to recover significant fractions of remaining oil at a CO2 footprint that is low compared with, for example, thermal EOR, and they do not depend on a valuable miscible agent such as hydrocarbon gas. On the other hand, chemical EOR technologies typically require large quantities of chemical products such as surfactants and polymers, which must be transported to, and handled safely in, the field. Despite rising industry interest in chemical EOR, until today only polymer flooding has been applied on a significant scale, whereas applications of surfactant/polymer or alkaline ASP flooding were limited to multiwell pilots or to small field scale. Next to the oil-price fluctuations of the past two decades, technical reasons that discouraged the application of chemical EOR are excessive formation of carbonate or silica scale and formation of strong emulsions in the production facilities. Having identified significant target-oil volumes for ASP flooding, Petroleum Development Oman (PDO), supported by Shell Technology Oman, carried out a sequence of single-well pilots in three fields, sandstone and carbonate, to assess the flooding potential of tailor-made chemical formulations under real subsurface conditions, and to quantify the benefits of full-field ASP developments. This paper discusses the extensive design process that was followed. Starting from a description of the optimization of chemical phase behavior in test-tube and coreflood experiments, we elaborate how the key chemical and flow properties of an ASP flood are captured to calibrate a comprehensive reservoir-simulation model. Using this model, we evaluate PDO's single-well pilots and demonstrate how these results are used to design a pattern- flood pilot.

Advancement Towards the Full-Field Implementation of Marmul Alkaline-Surfactant-Polymer in the Sultanate of Oman

2021 ◽  
Author(s):  
Dawood Al Mahrouqi ◽  
Hanaa Sulaimani ◽  
Rouhi Farajzadeh ◽  
Yi Svec ◽  
Samya Farsi ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Phase 1 ◽  
Recovery Efficiency ◽  
Sultanate Of Oman ◽  
Water Separation ◽  
Full Field ◽  
Oil Water Separation ◽  
Oil Water ◽  
New Formulation ◽  
Alkaline Surfactant Polymer

Abstract In 2015-2016, the Alkaline-Surfactant-Polymer (ASP) flood Pilot in Marmul was successfully completed with ∼30% incremental oil recovery and no significant operational issues. In parallel to the ASP pilot, several laboratory studies were executed to identify an alternative and cost-efficient ASP formulation with simpler logistics. The studies resulted in a new formulation based on mono-ethanolamine (MEA) as alkali and a blend of commercially available and cheaper surfactants. To expediate the phased full field development, Phase-1 project was started in 2019 with the following main objectives are confirm high oil recovery efficiency of the new ASP formulation and ensure the scalability and further commercial maturation of ASP technology; de-risk the injectivity of new formulation; and de-risk oil-water separation in the presence of produced ASP chemicals. The Phase 1 project was executed in the same well pattern as the Pilot, but at a different reservoir unit that is more heterogeneous and has a smaller pore volume (PV) than those of the Pilot. This set-up allowed comparing the performance of ASP formulations and taking advantage of the existing surface facilities, thus reducing the project cost. The project was successfully finished in December 2020, and the following major conclusions were made: (1) with the estimated incremental recovery of around 15-18% and one of the producers exhibiting water cut reversal of more than 30%, the new ASP formulation is efficient and will be used in the follow-up phased commercial ASP projects; (2) the injectivity was sustained throughout the entire operations within the target rate and below the fracture pressure; (3) produced oil quality met the export requirements and a significant amount of oil-water separation data was collected. With confirmed high oil recovery efficiency for the cheaper and more convenient ASP formulation, the success of ASP flooding in the Phase-1 project paves the way for the subsequent commercial-scale ASP projects in the Sultanate of Oman.

scholarly journals Nonionic Surfactant to Enhance the Performances of Alkaline–Surfactant–Polymer Flooding with a Low Salinity Constraint

2020 ◽  
Vol 10 (11) ◽  
pp. 3752 ◽  
Author(s):  
Shabrina Sri Riswati ◽  
Wisup Bae ◽  
Changhyup Park ◽  
Asep K. Permadi ◽  
Adi Novriansyah
Keyword(s):  
Nonionic Surfactant ◽  
Oil Recovery ◽  
Anionic Surfactant ◽  
Pore Volume ◽  
Salinity Gradient ◽  
Reference Case ◽  
Low Salinity ◽  
Asp Flooding ◽  
Optimum Salinity ◽  
Alkaline Surfactant Polymer

This paper presents a nonionic surfactant in the anionic surfactant pair (ternary mixture) that influences the hydrophobicity of the alkaline–surfactant–polymer (ASP) slug within low-salinity formation water, an environment that constrains optimal designs of the salinity gradient and phase types. The hydrophobicity effectively reduced the optimum salinity, but achieving as much by mixing various surfactants has been challenging. We conducted a phase behavior test and a coreflooding test, and the results prove the effectiveness of the nonionic surfactant in enlarging the chemical applicability by making ASP flooding more hydrophobic. The proposed ASP mixture consisted of 0.2 wt% sodium carbonate, 0.25 wt% anionic surfactant pair, and 0.2 wt% nonionic surfactant, and 0.15 wt% hydrolyzed polyacrylamide. The nonionic surfactant decreased the optimum salinity to 1.1 wt% NaCl compared to the 1.7 wt% NaCl of the reference case with heavy alcohol present instead of the nonionic surfactant. The coreflooding test confirmed the field applicability of the nonionic surfactant by recovering more oil, with the proposed scheme producing up to 74% of residual oil after extensive waterflooding compared to 51% of cumulative oil recovery with the reference case. The nonionic surfactant led to a Winsor type III microemulsion with a 0.85 pore volume while the reference case had a 0.50 pore volume. The nonionic surfactant made ASP flooding more hydrophobic, maintained a separate phase of the surfactant between the oil and aqueous phases to achieve ultra-low interfacial tension, and recovered the oil effectively.

scholarly journals Variations of Micropores in Oil Reservoir Before and After Strong Alkaline Alkaline-surfactant-polymer Flooding

2016 ◽  
Vol 9 (1) ◽  
pp. 257-267
Author(s):  
Yongqiang Bai ◽  
Yang Chunmei ◽  
Liu Mei ◽  
Jiang Zhenxue
Keyword(s):  
Quantitative Analysis ◽  
Crude Oil ◽  
Oil Recovery ◽  
Chemical Flooding ◽  
Sem Images ◽  
Force Microscopy ◽  
Micropore Structure ◽  
Asp Flooding ◽  
Before And After ◽  
Alkaline Surfactant Polymer

Enhanced oil recovery (EOR) provides a significant contribution for increasing output of crude oil. Alkaline-surfactant-polymer (ASP), as an effective chemical method of EOR, has played an important role in advancing crude oil output of the Daqing oilfield, China. Chemical flooding utilized in the process of ASP EOR has produced concerned damage to the reservoir, especially from the strong alkali of ASP, and variations of micropore structure of sandstones in the oil reservoirs restrain output of crude oil in the late stages of oilfield development. Laboratory flooding experiments were conducted to study sandstones’ micropore structure behavior at varying ASP flooding stages. Qualitative and quantitative analysis by cast thin section, scanning electric microscopy (SEM), atomic force microscopy (AFM) and electron probe X-Ray microanalysis (EPMA) explain the mechanisms of sandstones’ micropore structure change. According to the quantitative analysis, as the ASP dose agent increases, the pore width and pore depth exhibit a tendency of decrease-increase-decrease, and the specific ASP flooding stage is found in which flooding stage is most affective from the perspective of micropore structures. With the analysis of SEM images and variations of mineral compositions of samples, the migration of intergranular particles, the corrosions of clay, feldspar and quartz, and formation of new intergranular substances contribute to the alterations of sandstone pore structure. Results of this study provide significant guidance for further application to ASP flooding.

Instow: A Full-Field, Multipatterned Alkaline-Surfactant-Polymer Flood—Analyses and Comparison of Phases 1 and 2

2021 ◽  
pp. 1-15
Author(s):  
M. J. Pitts ◽  
E. Dean ◽  
K. Wyatt ◽  
E. Skeans ◽  
D. Deo ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Phase 1 ◽  
Water Injection ◽  
Phase 2 ◽  
Full Field ◽  
Two Phases ◽  
Original Oil In Place ◽  
Total Oil ◽  
Operation Cost ◽  
Alkaline Surfactant Polymer

Summary An alkaline-surfactant-polymer (ASP) project in the Instow field, Upper Shaunavon Formation in Saskatchewan, Canada, was planned in three phases. The first two multiwell pattern phases are nearing completion. Beginning in 2007, an ASP solution was injected into Phase 1. Phase 1 polymer drive injection began in 2011 after injection of 37% pore volume (PV) ASP solution. Coincident with the polymer drive injection into Phase 1, Phase 2 ASP solution injection began. Phase 2 polymer drive began in 2016 after injection of 55% PV ASP solution. Polymer solution injection for the polymer drives of both phases continues in both phases with Phase 1 and Phase 2 injected volumes being 55 and 42% PV as of August 2019, respectively. Phase 1 and Phase 2 oil cut response to ASP injection showed an increase of approximately four times from 3.2% to a peak of 13.0% for Phase 1 and Phase 2 oil cut increased from 1.8% to a peak of 14.8%, approximately eightfold. Oil rates increased from approximately 3200 m3/m (20 127 bbl/m) at the end of water injection to a peak of 8300 m3/m (52 220 bbl/m) in Phase 1 and from 1230 m3/m (7 736 bbl/m) to 6332 m3/m (39 827 bbl/m) in Phase 2. Phase 1 pattern analysis indicates that the PV of ASP solution injected varied from 13% to 54% PV of ASP. Oil recoveries after the start of ASP solution injection in the different patterns ranged from 2.3% original oil in place (OOIP) up to 21.3% OOIP with lower oil recoveries generally correlating with lower volumes of ASP solution injected. Wells in common to the two phases of the project show increased oil cut and oil rate responses to chemical injection from both Phases 1 and 2. Total oil recovery as of August 2019 is 60% OOIP for Phase 1 and 62% OOIP for Phase 2. Phase 1 economic analysis indicated chemical and operation cost was approximately CAD 26/bbl, resulting in the decision to move forward with Phase 2.

Alkaline/Surfactant/Polymer Chemical Flooding Without the Need for Soft Water

SPE Journal ◽  
2009 ◽  
Vol 15 (01) ◽  
pp. 184-196 ◽  
Author(s):  
Adam K. Flaaten ◽  
Quoc P Nguyen ◽  
Jieyuan Zhang ◽  
Hourshad Mohammadi ◽  
Gary A. Pope
Keyword(s):  
Sodium Carbonate ◽  
Oil Recovery ◽  
High Performance ◽  
High Salinity ◽  
Divalent Cations ◽  
Low Cost ◽  
Soft Water ◽  
Chemical Flooding ◽  
Asp Flooding ◽  
Alkaline Surfactant Polymer

Summary Alkaline/surfactant/polymer (ASP) flooding using conventional alkali requires soft water. However, soft water is not always available, and softening hard brines may be very costly or infeasible in many cases depending on the location, the brine composition, and other factors. For instance, conventional ASP uses sodium carbonate to reduce the adsorption of the surfactant and generate soap in-situ by reacting with acidic crude oils; however, calcium carbonate precipitates unless the brine is soft. A form of borax known as metaborate has been found to sequester divalent cations such as Ca++ and prevent precipitation. This approach has been combined with the screening and selection of surfactant formulations that will perform well with brines having high salinity and hardness. We demonstrate this approach by combining high-performance, low-cost surfactants with cosurfactants that tolerate high salinity and hardness and with metaborate that can tolerate hardness as well. Chemical formulations containing surfactants and alkali in hard brine were screened for performance and tolerance using microemulsion phase-behavior experiments and crude at reservoir temperature. A formulation was found that, with an optimum salinity of 120,000 ppm total dissolved solids (TDS), 6,600 ppm divalent cations, performed well in corefloods with high oil recovery and almost zero final chemical flood residual oil saturation. Additionally, chemical formulations containing sodium metaborate and hard brine gave nearly 100% oil recovery with no indication of precipitate formation. Metaborate chemistry was incorporated into a mechanistic, compositional chemical flooding simulator, and the simulator was then used to model the corefloods. Overall, novel ASP with metaborate performed comparably to conventional ASP using sodium carbonate in soft water, demonstrating advancements in ASP adaptation to hard, saline reservoirs without the need for soft brine, which increases the number of oil reservoirs that are candidates for enhanced oil recovery using ASP flooding.

Scaling Laws and Forecasting Techniques of Silicate in ASP Flooding

2013 ◽  
Vol 850-851 ◽  
pp. 221-224
Author(s):  
Xin Sui ◽  
Hai Ming Wu ◽  
Bao Hui Wang ◽  
Dong Jing ◽  
Hong Jun Wu ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Scaling Laws ◽  
Ph Value ◽  
Oil Production ◽  
Asp Flooding ◽  
Aluminum Ions ◽  
Calcium Magnesium ◽  
Set Up ◽  
Lower Temperature ◽  
Alkaline Surfactant Polymer

Served as alkaline-surfactant-polymer flooding for the enhanced oil recovery, alkaline-surfactant-polymer has widely been employed for Chinese oil production. In the practical opinion, the silicate scaling, which was formed by alkali, would harm layer gradually and affect oilfield production seriously. For the reason, in this paper, the phase diagrams of silicate scale were obtained in three different systems, including single silicon system, calcium/ magnesium/ silicon coexistence system, and calcium/ magnesium/ silicon/ aluminum coexistence system. The results showed that, other ions would affect the morphology and process of silicate scaling. In the experimental research range, silicate scaling is more easily to form with the lower temperature or pH value. The mixing scale was formed by absorption of silicate scale on the surface of carbonate scale. The aluminosilicate was formed by aluminum ions and silicon. The silicon scale forecasting model and equation of three different systems in ASP flooding with alkali was set up according to lab date. These data can provide theoretical basis for preventing scaling in oil production

An Experimental Study on Efficient Demulsification for Produced Emulsion in Alkaline/Surfactant/Polymer Flooding

2021 ◽  
pp. 1-34
Author(s):  
Yang Song ◽  
Yunfei Xu ◽  
Zhihua Wang
Keyword(s):  
Electric Field ◽  
Oil Recovery ◽  
Pulse Electric Field ◽  
Water Separation ◽  
Efficient Treatment ◽  
Peak Current ◽  
Charge Neutralization ◽  
Asp Flooding ◽  
Dehydration Effect ◽  
Alkaline Surfactant Polymer

Abstract Tertiary oil recovery technologies, exampled as alkaline/surfactant/polymer (ASP) flooding, can enhance oil recovery (EOR) as an important oil displacement technology noteworthy in the present oilfields. However, it is the fact that the produced emulsion droplets have strong electronegativity, which will lead to the destabilization of electric field and affect the dehydration effect in the process of electric dehydration. This paper innovatively proposed an efficient demulsification scheme, which uses platinum chloride (PAC) as a chemical regulator to control electric field destabilization through the charge neutralization mechanism, and then introduces demulsifier to promote oil-water separation. Furthermore, the dehydration temperature, power supply mode and electric field parameters are optimized so as to achieve superior dehydration effect of ASP flooding produced liquid. The results indicate that PAC as a chemical regulator by exerting charge neutralization and electrostatic adsorption mechanism could reduce the electronegativity of the emulsified system, decrease the peak current of dehydration, shorten the duration of peak current of dehydration, improve the response performance of the electric field, and increase dehydration rate in ASP flooding dehydration process. When the demulsifier dosage is 100 to 120 mg/L, using the composite separation process with the dehydration temperature of 45 to 50 °C for the thermochemical separation stage and 60 °C in the electrochemical dehydration stage and AC-DC composite electric field or pulse electric field can achieve better dehydration effect. The investigations in this study will provide support and basis for the efficient treatment of ASP flooding produced emulsion.

Full Field Scale Hydrocarbon Gas Enhanced Oil Recovery Project in Offshore Vietnam -Response Analysis and Optimization Practice in Early Stage

2018 ◽  
Author(s):  
Yohei Kawahara ◽  
Yukiya Sako ◽  
Zhenjie Chai ◽  
Chuyen Nguyen Chu ◽  
Takahiro Murakami ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Early Stage ◽  
Response Analysis ◽  
Field Scale ◽  
Full Field ◽  
Hydrocarbon Gas

Full Field EOR Implementation of A Low Cost Surfactant Continuous Injection at Arahan-Banjarsari, South Sumatra

2020 ◽  
Author(s):  
T. Ariadji
Keyword(s):  
Oil Recovery ◽  
Micellar Solution ◽  
Low Cost ◽  
Spontaneous Imbibition ◽  
Successful Implementation ◽  
Full Field ◽  
Chemical Eor ◽  
Reservoir Conditions ◽  
Water Cut ◽  
Continuous Injection

The objective of this paper is to describe a series of laboratory work results in conjunction with successful implementation of the surfactant (micellar) continuous injection in the Muara Enim sand of the Arahan-Banjarsari Field, South Sumatra. A series of lab tests were conducted using field cores and fluids taken from the Arahan-Banjarsari (AR-BS) field. The tests included phase behavior, mixture viscosity measurement, spontaneous imbibition, and static isotherm adsorption tests. Several surfactant formulas had been tested to find the most consistent and most suitable to the reservoir conditions. The surfactant injection was started in March 2009 into three AR wells. The injection was divided into 4 stages with initial concentration of 0.45% and the final concentration of 0.1%. Total volume of micellar solution injected in 110 days was 52,365 bbls. An increase in oil production was observed not only in two AR wells but also in 8 wells in the neighboring BS field (500 meters distance) after 140 days since injection of micellar solution started with injection rates of 200-250 bpd. Two BS wells were reopened and produced 28% and 54% water cut (the water cut before the two wells were shut in was 19% and 76%). This micellar solution injection managed to decrease the decline rate of 70% to 26% per year, increase production rate from AR and BS fields from 90 bopd to a peak of 220 bopd in 5 months since injection started, and reserves enhancement of 183 M bbls (10% OOIP) during 3.5 years of continuous injection. The low cost, full scale chemical EOR leads to changes in the common understanding about micellar flooding and shows a high impact on oil recovery of 183 Mbls (AB-5c sand with OOIP of 1.8 MMSTB).

Evaluating Efficiency of Surfactant-Polymer Flooding with Single Well Chemical Tracer Tests at Kholmogorskoye Field

2021 ◽  
Author(s):  
Mikhail Bondar ◽  
Andrey Osipov ◽  
Andrey Groman ◽  
Igor Koltsov ◽  
Georgy Shcherbakov ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Promising Result ◽  
Tracer Tests ◽  
Polymer Flooding ◽  
Water Flooding ◽  
Residual Oil ◽  
Core Flooding ◽  
Oil Saturation ◽  
Chemical Eor ◽  
Single Well

Abstract EOR technologies in general and surfactant-polymer flooding (SP) in particular is considered as a tertiary method for redevelopment of mature oil fields in Western Siberia, with potential to increase oil recovery to 60-70% OOIP. The selection of effective surfactant blend and a polymer for SP flooding a complex and multi-stage process. The selected SP compositions were tested at Kholmogorskoye oilfield in September-December 2020. Two single well tests with partitioning chemical tracers (SWCTT) and the injectivity test were performed. The surfactant and the polymer for chemical EOR were selecting during laboratory studies. Thermal stability, phase behavior, interfacial tension and rheology of SP formulation were investigated, then a prospective chemical design was developed. Filtration experiments were carried out for optimization of slugs and concentrations. Then SWCTT was used to evaluated residual oil saturation after water flooding and after implementation of chemical EOR in the near wellbore areas. The difference between the obtained values is a measure of the efficiency of surfactant-polymer flooding. Pandemic restriction shifted SWCTT to the period when temperature dropped below zero and suitable for winter conditions equipment was required. Two SWCTT were conducted with same surfactant, but different design of slugs in order to prove technical and economic models of SP-flooding. Long-term polymer injectivity was accessed at the third well. Oil saturation of sandstone reservoir after the injection of a surfactant-polymer solution was reduced about 10% points which is around one third of the residual oil after water flooding. Results were compared with other available data such as well logging, lab core flooding experiments, and hydrodynamic simulation. Modeling of SWCTT is ongoing, current interpretation confirms the increase the oil recovery factor after SP-flooding up to 20-25%, which is a promising result. Temperature model of the bottom hole zone was created and verified. The model predicts that temperature of those zones essentially below that average in the reservoir, which is important for interpretation of tracer test and surfactant efficiency. The tested surfactant showed an acceptable efficiency at under-optimum conditions, which is favorable for application of the SP formulation for neighboring field and layers with different reservoir temperatures, but similar water composition. In general, the results of the conducted field tests correlate with the results of the core experiments for the selected surfactant

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