Alkaline-Surfactant-Polymer Flood of the Tanner Field

Pitts, Malcolm; Dowling, Phillip; Wyatt, Kon; Surkalo, H.; Adams, Kenneth M.

doi:10.2523/100004-ms

Cited by 18 publications

(3 citation statements)

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“…An incremental oil recovery of 20%, 24.0%, and 26.8% were reported for the Daqing oil field, 2,4 the Karamay oil field, 5 and the Tanner field. 6 ASP flooding provides a distinctly higher recovery factor than polymer flooding on a reservoir scale (5%−10%). Every oil field typically requires its own combination of chemicals in order to maximize oil recovery.…”

Section: Introductionmentioning

confidence: 98%

“…As global oil prices increased from the early 2000s, research into polymer and ASP flooding resulted in many successful field applications. An incremental oil recovery of 20%, 24.0%, and 26.8% were reported for the Daqing oil field, , the Karamay oil field, and the Tanner field . ASP flooding provides a distinctly higher recovery factor than polymer flooding on a reservoir scale (5%–10%).…”

Section: Introductionmentioning

confidence: 99%

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Mechanistic Modeling of the Alkaline/Surfactant/Polymer Flooding Process under Sub-optimum Salinity Conditions for Enhanced Oil Recovery

Hosseini-Nasab

Padalkar

Battistutta

et al. 2016

Ind. Eng. Chem. Res.

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Alkaline−surfactant−polymer (ASP) flooding is potentially the most efficient chemical EOR method. It yields extremely high incremental recovery factors in excess of 95% of the residual oil for water flooding on the laboratory scale. However, current opinion is that such extremely high recoveries can be achieved under optimum salinity conditions, i.e., for the Winsor Type III microemulsion phase characterized by ultralow interfacial tension (IFT). This represents a serious limitation since several factors, including alkali-rock interaction, the initial state of the reservoir water, and the salinity of injected water, may shift the ASP flooding design to either sub-optimum or over-optimum conditions. A recent experimental study of ASP floods, based on a single internal olefin sulfonate (IOS) in natural sandstone cores with varying salinity from sub-optimum to optimum conditions, indicated that high recovery factors can also be obtained under sub-optimum salinity conditions. In this paper, a mechanistic model was developed to explore the causes behind the observed phenomena. The numerical simulations were carried out using the UTCHEM research simulator (at The University of Texas at Austin), together with the geochemical module EQBATCH. UTCHEM combines multiphase multicomponent simulation with robust phase behavior modeling. An excellent match of the numerical simulations with the experiments was obtained for oil cut, cumulative oil recovery, pH profile, surfactant, and carbonate concentration in the effluents. The simulations gave additional insight into the propagation of alkali consumption, salinity, surfactant profiles within the core. The study showed that the initial condition of the core is important in designing an ASP flooding. Because of uncertainties in the various chemical reactions taking place in the formation, an accurate geochemical model is essential for operating an ASP flooding in a particular salinity region. The simulation results demonstrate also that, for crude oil with a very low total acid number (TAN), the ultralow IFT and low surfactant adsorption can be achieved over a wide range of salinities that are less than optimal. The results provide a basis to perform better modeling of the suboptimum salinity series of experiments and optimizing the design of ASP flooding methods for the field scale with morecomplicated geochemical conditions.

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Section: Introductionmentioning

confidence: 98%

Section: Introductionmentioning

confidence: 99%

Mechanistic Modeling of the Alkaline/Surfactant/Polymer Flooding Process under Sub-optimum Salinity Conditions for Enhanced Oil Recovery

Hosseini-Nasab

Padalkar

Battistutta

et al. 2016

Ind. Eng. Chem. Res.

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“…This is imperative because a predominantly weak associative effect would not necessarily guarantee the needed rheological impact in terms of recovery efficiency even if polymer injectivity is not affected. (Pu and Xu, 2009) Gudong HPAM 68.0 3022 (Zhijian et al, 1998) Bohai Bay HPAM 65.0 6070 (Mogollon and Lokhandwala, 2013) Xing Long Tai HPAM 56.6 3112 (Zhang et al, 1999) Bohai oil field HAPAM 65.0 32423 (Han et al, 2006) Henan oil field HPAM 75.0 5060 (Chen et al, 1998) Shengli HPAM 70.0 10000 (Gao, 2014) USA Cambridge Minnelusa PAM 55.6 Not specified (Vargo et al, 2000) Tambaredjo HPAM 36.0 Not Specified (Mogollon and Lokhandwala, 2013) Tanner PAM 80.0 66800 (P) a (Pitts et al, 2006) West Khiel HPAM 57.0 46,480 (P) a (Meyers et al, 1992) Canada Pelican HPAM 23.0 6800 (Mogollon and Lokhandwala, 2013) David pool PAM 31.0 6660 (I) b (Pitts et al, 2004 (Algi and Okay, 2014;Fang et al, 2016) 2-vinylnaphtahlene (Zeng et al, 2002) Methacrylic Acid (Fernyhough et al, 2009;Bang et al, 2017) N-vinylpyrrolidinone (Taghizadeh and Foroutan, 2004;Willersinn and Schmidt, 2017) 4-vinylbenzenesulfonate (Kang et al, 2015) 2-Acrylamido-2-methyl-1-propanesulfonic acid (Çavuş, 2010;Kundakci et al, 2011) Methyl methacrylate (Cilurzo et al, 2014;Khromiak et al, 2018) Poly(propylene glycol) methacrylate (Shemper et al, 2002) Sodium vinylsulfonate (Mori et al, 2010;Mori et al, 2012) Carboxymethyl cellulose (Han et al, 2010;Han et al, 2013) N-phenylacrylamide (Zhou and Lai, 2004) N-tert-Octylacrylamide (Zhu et al, 2012) N-dodecylacrylamide…”

Section: Conclusion and Recommendationsmentioning

confidence: 99%

Hydrophobically associating polymers for enhanced oil recovery – Part A: A review on the effects of some key reservoir conditions

Afolabi

Oluyemi

Officer

et al. 2019

Journal of Petroleum Science and Engineering

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Research advancement in polymer flooding for Enhanced Oil Recovery (EOR) has been growing over the last decade. This growth can be tied to increased funding towards the development of superior polymers such as hydrophobically associating polymers when oil prices were high and increasing concern that "easy oil" has been exploited with the focus now on "difficult to extract" oil. The use of hydrophobically associating polymers for EOR was discussed along with its limitations. In this context, the improved rheological properties of associating polymers cannot only be linked to the molecular structures arising from different synthesis methods. Equally, external parameters similar to conditions of oil reservoirs affect the rheological properties of these polymers. As such, this review placed critical emphasis on the molecular architecture of the polymer and the synthesis route and this was linked to the observed rheological properties. In addition, the influence of some key oilfield parameters such as temperature, salinity, pH, and reservoir heterogeneity on the rheological behaviour of hydrophobically associating polymers were reviewed. In this respect, the various findings garnered in understanding the correlation between polymer rheological properties and oilfield parameters were critically reviewed. For associating polymers, an understanding of the molecular architecture (and hence the synthesis method) is crucial for its successful design. However, this must be theoretically linked to the preferred EOR application requirements (based on oilfield parameters).

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A comprehensive review of alkaline–surfactant–polymer (ASP) flooding

Sheng

2014

Asia-Pacific J Chem Eng

219

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Alkaline-surfactant-polymer (ASP) flooding is a combination process in which alkali, surfactant, and polymer are injected in the same slug. Because of the synergy of these three components, ASP is the current worldwide focus of research and field trial in chemical enhanced oil recovery (EOR).This paper is to provide a comprehensive review of the ASP process. The reviewed topics include the following: ASP MECHANISMSBefore presenting the synergy of ASP process, the mechanisms of each individual component are discussed first. Mechanisms of polymer floodingThe process of polymer flooding is same as waterflooding except that polymer is added in the water so that the solution viscosity is increased. Sometimes, it is called thickened waterflooding. It is well known that when the Screening criteria for broader EOR processes were discussed by several researchers, e.g. Lake et al., [21] Taber et al., [22,23] Al-Bahar et al., [24] Dickson et al., [20] and Al-Adasani and Bai (2010). [25] Some of the Asia-Pacific Journal of Chemical Engineering A COMPREHENSIVE REVIEW OF ASP FLOODING 473 S o ÀS or 1ÀS or ÀS wc : Here S o , S or, and S wc are oil saturation, residual oil saturation, and connate water saturation, respectively. The proposed mobility control requirement provides a criterion for mobility control design for an ASP project. PROBLEMS ASSOCIATED WITH ASP FLOODINGCommon operational problems in an ASP project are low injectivity, polymer degradation, difficulty to separate J. J. SHENG Asia-Pacific Journal of Chemical Engineering 482 produced water from oil, pump failures, bacterial growth, corrosion, problems related logistics, and handling, especially in an offshore environment. [84] This section discusses issues resulting from ASP applications, including produced emulsion, chromatographic separation, precipitation and scaling, and others.

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Alkaline-Surfactant-Polymer Flood of the Tanner Field

Cited by 18 publications

References 0 publications

Mechanistic Modeling of the Alkaline/Surfactant/Polymer Flooding Process under Sub-optimum Salinity Conditions for Enhanced Oil Recovery

Mechanistic Modeling of the Alkaline/Surfactant/Polymer Flooding Process under Sub-optimum Salinity Conditions for Enhanced Oil Recovery

Hydrophobically associating polymers for enhanced oil recovery – Part A: A review on the effects of some key reservoir conditions

A comprehensive review of alkaline–surfactant–polymer (ASP) flooding

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