Surfactant Polymer SP vs. Alkali-Surfactant Polymer ASP: Do We Need the a in ASP?

Delamaide, Eric; Rousseau, David; Wartenberg, Nicolas

doi:10.2118/204611-ms

Day 3 Tue, November 30, 2021 2021

DOI: 10.2118/204611-ms

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Surfactant Polymer SP vs. Alkali-Surfactant Polymer ASP: Do We Need the a in ASP?

Eric Delamaide¹,

David Rousseau

Nicolas Wartenberg

Abstract: The first surfactant-based pilots can be traced back to the 1960s and since then almost a hundred field tests have taken place. Interestingly, almost half of these pilots have used an alkali (ASP) and the other half has not (SP). This reflects the current status of the industry which is divided along the same lines and over the same question: do surfactant-based processes require alkali or not? This paper proposes to address this question by providing explanations and discussing case studies. Th… Show more

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Cited by 3 publications

References 85 publications

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Experimental Design and Evaluation of Surfactant Polymer for a Heavy Oil Field in South of Sultanate of Oman

Al-Jabri¹,

Farajzadeh²,

Alkindi³

et al. 2021

SPE Europec Featured at 82nd EAGE Conference and Exhibition

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Heavy oil reservoirs remain challenging for surfactant-based EOR. In particular, selecting fine-tuned and cost effective chemical formulations requires extensive laboratory work and a solid methodology. This paper reports a laboratory feasibility study, aiming at designing a surfactant-polymer pilot for a heavy oil field with an oil viscosity of ~500cP in the South of Sultanate of Oman, where polymer flooding has already been successfully trialed. A major driver was to design a simple chemical EOR method, to minimize the risk of operational issues (e.g. scaling) and ensure smooth logistics on the field. To that end, a dedicated alkaline-free and solvent-free surfactant polymer (SP) formulation has been designed, with its sole three components, polymer, surfactant and co-surfactant, being readily available industrial chemicals. This part of the work has been reported in a previous paper. A comprehensive set of oil recovery coreflood tests has then been carried out with two objectives: validate the intrinsic performances of the SP formulation in terms of residual oil mobilization and establish an optimal injection strategy to maximize oil recovery with minimal surfactant dosage. The 10 coreflood tests performed involved: Bentheimer sandstone, for baseline assessments on large plugs with minimized experimental uncertainties; homogeneous artificial sand and clays granular packs built to have representative mineralogical composition, for tuning of the injection parameters; native reservoir rock plugs, unstacked in order to avoid any bias, to validate the injection strategy in fully representative conditions. All surfactant injections were performed after long polymer injections, to mimic the operational conditions in the field. Under injection of "infinite" slugs of the SP formulation, all tests have led to tertiary recoveries of more than 88% of the remaining oil after waterflood with final oil saturations of less than 5%. When short slugs of SP formulation were injected, tertiary recoveries were larger than 70% ROIP with final oil saturations less than 10%. The final optimized test on a reservoir rock plug, which was selected after an extensive review of the petrophysical and mineralogical properties of the available reservoir cores, led to a tertiary recovery of 90% ROIP with a final oil saturation of 2%, after injection of 0.35 PV of SP formulation at 6 g/L total surfactant concentration, with surfactant losses of 0.14 mg-surfactant/g(rock). Further optimization will allow accelerating oil bank arrival and reducing the large PV of chase polymer needed to mobilize the liberated oil. An additional part of the work consisted in generating the parameters needed for reservoir scale simulation. This required dedicated laboratory assays and history matching simulations of which the results are presented and discussed. These outcomes validate, at lab scale, the feasibility of a surfactant polymer process for the heavy oil field investigated. As there has been no published field test of SP injection in heavy oil, this work may also open the way to a new range of field applications.

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Experimental Design and Evaluation of Surfactant Polymer for a Heavy Oil Field in South of Sultanate of Oman

Al-Jabri¹,

Farajzadeh²,

Alkindi³

et al. 2021

SPE Europec Featured at 82nd EAGE Conference and Exhibition

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Which is the Most Attractive IOR Method to Produce the Venezuelan Highly Viscous Oil Resources in the Energy Transition Era? A Comprehensive Review of Research and Field Applications

Rodriguez

Delamaide²,

Rousseau

et al. 2022

Day 1 Mon, October 31, 2022

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Venezuela has been a potential producer of highly viscous crude oils for more than a century, thanks to its large resources located at the Lake Maracaibo and Eastern Venezuela basins in the Orinoco Oil Belt. Despite these huge resources, Venezuelan oil production is going through one of the greatest crises in its history, presenting a dramatic production decline, for which the application of Improved Oil Recovery (IOR) methods with low environmental impact (low carbon emissions, low water consumption, etc.) is crucial to increase oil production. The main methods applied in Venezuelan highly viscous oil reservoirs (heavy, extra-heavy and bituminous oil reservoirs) have been cold production with sand by vertical and horizontal wells with artificial lift pumps, waterflooding, thermal IOR/EOR methods (steam drive-based methods), chemical EOR (CEOR) methods, namely polymer and surfactant-polymer (SP) flooding, hybrid methods (e.g. thermal combined with solvents or CEOR methods), among others. Research works in CEOR methods for Venezuelan highly viscous oil reservoirs have shown that high oil recoveries may be possible for oils with viscosities up to 13,400 mPa.s. On the other hand, for the case of bituminous oil reservoirs (e.g. viscosities up to 50,000 mPa.s) thermal IOR methods and combinations with chemicals, nanoparticles, or solvents may increase oil production significantly. The methods reviewed in this article are: waterflooding, chemical flooding (e.g. polymer, surfactant, alkali and a combination of them), steam drive methods (e.g. CSS, In-situ Combustion and SAGD), solvent flooding, microorganisms and hybrid methods. Based on research and field tests, CEOR methods may lead to increased oil recovery of extra-heavy oils with low carbon emissions compared to thermal EOR methods, thus making SP flooding and low salinity polymer flooding among the most attractive technologies. Depending on the type of chemicals evaluated, recovery mechanisms such as mobility control, IFT reduction, ion exchanges and/or wettability alteration might be most efficient. It also appears that hybrid methods have achieved the highest recovery at the laboratory scale (e.g. In Situ Combustion with nanoparticles). For the medium-heavy oil reservoirs of the Maracaibo Lake Basin, waterflooding combined with infill well optimization and microorganism flooding are encouraging IOR methods with low environmental impact. The greatest challenges in the application of these technologies are related to technical and economic considerations that will be decisive for the implementation of the IOR processes at the pilot scale and/or massification at the field scale aiming to increase Venezuelan oil production in this era of the energy transition.

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Towards Sustainable Oil Production: CO2 Footprint Assessment of EOR Surfactant-Based Processes

Marie,

Mathieu,

Mikel

et al. 2023

Day 2 Thu, June 29, 2023

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To meet energy demand while reducing CO2 emissions in a carbon constrained future, one of the key milestones of the roadmap proposed by the International Energy Agency is to stop new oil and gas field developments and extend instead existing fields’ lifetime. Waterflood and EOR recovery methods aiming at optimizing mature fields’ oil production thus appears as technologies of choice. Nonetheless, oil production by waterflood is energy and therefore carbon intensive, especially for oil fields exhibiting high water-cuts, due to produced water handling. Recent communications suggest that chemical EOR processes such as polymer flood reduce the CO2 emitted per barrel of produced oil compared to water flooding, as they reduce water cut and/or accelerate oil production. Few papers however assess the CO2 footprint of surfactant-based processes. In this work, we aim to compare the carbon emissions of different chemical EOR scenarios including polymer, surfactant-polymer and alkaline-surfactant-polymer, with a reference waterflood scenario. We present an exergy-based methodology to estimate energy gains obtained from water-cut decrease while taking into account process efficiency, including oil production, water treatment required for chemical use and chemical production. The corresponding CO2 emission reduction is then estimated from these energy gains. This methodology was applied to two case studies available in the literature, the Mangala field polymer flood pilot and the Taber alkaline-surfactant-polymer flood. Necessary injection and production data were collected to extrapolate production water rate and WOR using Decline Curve Analysis. Results show that implementing polymer or alkaline-surfactant-polymer flooding after waterflooding allows wells to reach higher oil production rates, up to twice as much. In addition, water-oil ratio is more than ten times reduced i.e. less produced water has to be handled while producing more oil. Thus, we show that for both of these fields oil production is less carbon intensive. Furthermore, we considered a hypothetical surfactant-polymer flood to compare to the Taber alkaline-surfactant-polymer flood. Water treatment as well as chemical production energy costs are reduced for the surfactant-polymer due to the absence of added alkali, which induces additional CO2 emission reduction. This study highlights that chemical EOR, in particular polymer and/or surfactant-based processes stands as a potential solution to reduce the carbon footprint of oil recovery while maintaining the production required to sustain the world's energy consumption.

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Surfactant Polymer SP vs. Alkali-Surfactant Polymer ASP: Do We Need the a in ASP?

Cited by 3 publications

References 85 publications

Experimental Design and Evaluation of Surfactant Polymer for a Heavy Oil Field in South of Sultanate of Oman

Experimental Design and Evaluation of Surfactant Polymer for a Heavy Oil Field in South of Sultanate of Oman

Which is the Most Attractive IOR Method to Produce the Venezuelan Highly Viscous Oil Resources in the Energy Transition Era? A Comprehensive Review of Research and Field Applications

Towards Sustainable Oil Production: CO2 Footprint Assessment of EOR Surfactant-Based Processes

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