Coreflood Tests Research Articles

Design and Tuning of Nanofluids Applied to Chemical Enhanced Oil Recovery Based on the Surfactant-Nanoparticle-Brine Interaction: From Laboratory Experiments to Oil Field Application.

The primary objective of this study is to develop a novel experimental nanofluid based on surfactant–nanoparticle–brine tuning, subsequently evaluate its performance in the laboratory under reservoir conditions, then upscale the design for a field trial of the nanotechnology-enhanced surfactant injection process. Two different mixtures of commercial anionic surfactants (SA and SB) were characterized by their critical micelle concentration (CMC), density, and Fourier transform infrared (FTIR) spectra. Two types of commercial nanoparticles (CNA and CNB) were utilized, and they were characterized by SBET, FTIR spectra, hydrodynamic mean sizes (dp50), isoelectric points (pHIEP), and functional groups. The evaluation of both surfactant–nanoparticle systems demonstrated that the best performance was obtained with a total dissolved solid (TDS) of 0.75% with the SA surfactant and the CNA nanoparticles. A nanofluid formulation with 100 mg·L−1 of CNA provided suitable interfacial tension (IFT) values between 0.18 and 0.15 mN·m−1 for a surfactant dosage range of 750–1000 mg·L−1. Results obtained from adsorption tests indicated that the surfactant adsorption on the rock would be reduced by at least 40% under static and dynamic conditions due to nanoparticle addition. Moreover, during core flooding tests, it was observed that the recovery factor was increased by 22% for the nanofluid usage in contrast with a 17% increase with only the use of the surfactant. These results are related to the estimated capillary number of 3 × 10−5, 3 × 10−4, and 5 × 10−4 for the brine, the surfactant, and the nanofluid, respectively, as well as to the reduction in the surfactant adsorption on the rock which enhances the efficiency of the process. The field trial application was performed with the same nanofluid formulation in the two different injection patterns of a Colombian oil field and represented the first application worldwide of nanoparticles/nanofluids in enhanced oil recovery (EOR) processes. The cumulative incremental oil production was nearly 30,035 Bbls for both injection patterns by May 19, 2020. The decline rate was estimated through an exponential model to be −0.104 month−1 before the intervention, to −0.016 month−1 after the nanofluid injection. The pilot was designed based on a production increment of 3.5%, which was successfully surpassed with this field test with an increment of 27.3%. This application is the first, worldwide, to demonstrate surfactant flooding assisted by nanotechnology in a chemical enhanced oil recovery (CEOR) process in a low interfacial tension region.

Activating solution gas drive as an extra oil production mechanism after carbonated water injection

Abstract Enhanced oil recovery (EOR) methods are mostly based on different phenomena taking place at the interfaces between fluid-fluid, and rock-fluid phases. Over the last decade, carbonated water injection (CWI) has been considered as one of the multi-objective EOR techniques to store CO2 in the hydrocarbon bearing formations as well as improving oil recovery efficiency. During CWI process, as the reservoir pressure declines, the dissolved CO2 in the oil phase evolves and gas nucleation phenomenon would occur. As a result, it can lead to oil saturation restoration and subsequently, oil displacement due to the hysteresis effect. At this condition, CO2 would act as in-situ dissolved gas into the oil phase, and play the role of an artificial solution gas drive (SGD). In this study, the effect of SGD as an extra oil recovery mechanism after secondary and tertiary CWI (SCWI-TCWI) modes, has been experimentally investigated in carbonate rocks using coreflood tests. The depressurization tests resulted in more than 25% and 18% of original oil in place (OOIP) because of the SGD after SCWI and TCWI tests, respectively. From the ultimate enhanced oil recovery point of view, the efficiency of SGD was observed to be more than one-third of that of CWI itself. Furthermore, the pressure drop data revealed that the system pressure depends more on the oil production pattern than water production.

Coreflood on a chip: Core-scale micromodels for subsurface applications

Fluid injection experiments in rocks, commonly referred to as corefloods, are widely used to study and understand fluid flow in the subsurface. However, visual inspection of flow in cores requires computed tomography machines which may not be widely accessible. We introduce a novel micromodel that is as long as a typical core (40 cm), has adjustable pore structure, and includes 2.5D pore throats that can be used to conduct fluid displacements analogous to those in cores. Flow can be visualized inexpensively in the micromodel with an optical microscope. We performed standard coreflood tests in our micromodel including a tracer test and a steady state permeability test. We also conducted multiphase displacements by injecting aqueous solutions at varying glycerol concentrations to displace oil from the micromodel and observed the effect of the viscosity ratio on macro-scale recovery efficiency. When the injected aqueous solution was less viscous than the resident oil, it fingered through the oil. Fingering was not observed in the cases where the injected glycerol solution was more viscous than the oil. Moreover, as the viscosity of the injected glycerol solution increased, oil was recovered more rapidly. Additionally, we performed surfactant and glycerol floods in short (2.4 cm) and long (40 cm) micromodels that show long chips capture scale dependent physics, such as oil banking, that small chips do not capture. The novel micromodel shows promise as a screening tool for chemical EOR because it captures phase banks that are desirable in corefloods.

Investigation of the effect of engineered water/nanofluid hybrid injection on enhanced oil recovery mechanisms in carbonate reservoirs

Changing the salinity and ionic composition of the injected water and designing “engineered water” (EW) is an enhanced oil recovery approach which affects the wettability of carbonate reservoirs and improves the oil recovery in many cases. Application of nanoparticles also affects oil production by various mechanisms such as altering the wettability, changing the viscosity of the oil and the injected fluid, and changing the interfacial tension. The benefits of combining these two approaches and developing a hybrid method are investigated in this paper.Experiments and measurements of different characteristics such as contact angle, zeta potential, particle size, ATR (attenuated total reflectance) analysis, ESEM (environmental scanning electron microscope) imaging, ion/nanoparticle deposition, and microemulsion formation were completed to analyze the influence of the hybrid method on rock/oil/brine interactions. Core flooding tests were also conducted to study the performance of the method to improve oil recovery.The most effective EW was selected by adjusting the concentrations of magnesium, calcium, and sulfate ions of Persian Gulf water. Nanoparticles such as SiO2, CaCO3, TiO2, and gamma Al2O3 were also studied to achieve the longest stability. Finally, the effect of combining the optimum states of engineered brine and nanoparticles on different mechanisms was investigated.Our results showed that spiking the injection brine with sulfate ions and using a hybrid method with silica nanoparticles at a concentration of 0.1 wt% provided the best effect on the enhanced oil recovery. This combination altered the wettability more than standalone methods. Also, there was a decrease in adsorption of nanoparticles on the rock surface, which controls the retention mechanism. Therefore, the presence of more nanoparticles in the fluid flow leads to the formation of microemulsions and increases in the viscosity of the injected fluid, which affects the sweep efficiency in porous media.

Synergistic effects of Janus graphene oxide and surfactants on the heavy oil/water interfacial tension and their application to enhance heavy oil recovery

The interfacial activities of graphene oxide (GO) and two kinds of Janus graphene oxide (JGO150 and JGO400), i.e., GO with one side being modified by two different amount of dodecylamine, were evaluated in various oil/water systems. Based on the results of IFT measurement, JGO showed the greater interfacial activity than original GO, especially for JGO400 which greatly reduced the heavy oil/water IFT to 0.12 mN/m. Molecular dynamic simulations were employed to illustrate the interfacial interaction between GO/JGO and oil molecules. Furthermore, the interaction between three kinds of nano-sheet materials and three types of surfactants, including dodecyltrimethylammonium bromide (DTAB), sodium dodecyl sulfate (SDS), and Triton X-100 (TX-100), were systematically investigated in the heavy oil/water system. The JGO400/DTAB system exhibited excellent synergistic effects to dramatically decrease the heavy oil/water IFT to 8 × 10−3 mN/m, which was responsible for its remarkable ability to improve heavy oil recovery (19.5%) in core flooding tests.

Investigation on the effects of AlOOH nanoparticles on sodium dodecylbenzenesulfonate stabilized o/w emulsion stability for EOR

Emulisons stabilized by surfactants have been used in enhanced oil recovery (EOR) for effective profile control and displacement, whereas the lack of long-term stability especially under harsh reservoir conditions limited their wide application. In this study, Pickering emulsions stabilized by sodium dodecylbenzenesulfonate (SDBS) and anisotropic slice-like AlOOH nanoparticles were systematically studied. The adsorption of SDBS on AlOOH nanoparticles was confirmed by the measurements of zeta potential and Fourier Transform Infrared (FTIR) spectra. The three-phase contact angle tests were conducted to explore the reason for the double phase inversion of the AlOOH/SDBS stabilized emulsions from o/w to w/o and back to o/w again. The optical microscopy images verified the adsorption mechanism of SDBS on AlOOH nanoparticles at the oil/water interface. It was found that the three-dimensional network structure formed by the micro-flocculated modified AlOOH nanoparticles could prevent coalescence and phase separation, resulting in the enhanced stability of the emulsion. The AlOOH/SDBS stabilized emulsion showed the super tolerances in a wide range of shear rates, temperature and electrolyte concentrations. The core flooding tests and microscopic visualization flooding experiments demonstrated that the AlOOH/SDBS stabilized emulsions significantly improved the tertiary oil recovery (33 % of IOIP) via the enhanced displacement and sweep efficiencies. The present study provides a typical Pickering emulsion with great stability under harsh reservoir conditions for EOR.

The effect of type waves on vibroseismic implementation of changes properties of rock, oil viscosity, oil compound composition, and enhanced oil recovery

Based on the results of laboratory studies, the frequency of 35 Hz in longitudinal waves and 20 Hz in circular waves is the optimum frequency that can increase the maximum oil recovery. Coreflooding test results before the vibration effect can increase oil production by 51.96% and reduce the residual oil saturation by 59.03%. The surprising results when the vibration effect was applied to the coreflooding test method with P wave types continuously succeeded in increasing oil production by 60.54%, intermittent P waves by 63.53% and circular waves by 64.76%, while also reducing Sor by 48.49% in continuous P waves, intermittent P waves at 44.81% and C waves at 43.3%. The P wave type vibrational method has an increase in oil gain by 16%, intermittently by 22%, Sor reduction by 18% and 24%, in circular wave oil gain increases by 25%, and Sor decreases by 27% from before the vibration effect given. Besides vibration can change the physical properties of rocks, among others; permeability has increased by 7% using P waves continuously, intermittently by 31% and C waves by 4%; porosity of 5.88% with P waves continuously, intermittently of 6.46% and circular waves of 4.63%; grain size before vibration of 45.16 μm after vibration using continuous P waves of 42.01 μm, intermittently of 47.98 μm, and circular of 50.46 μm; changes in oil composition to contain more alkanes, and lack of aromatic compounds; oil viscosity increased by 3% with continuous P waves, intermittent of 5%, and circular 61%. The new point from this paper is analyzing the vibroseismic effect by using SEM images in terms of the watershed segmentation of the Rabbani algorithm compared to lab results, which have an error rate of under 2%, and a review of oil composition by the GC-MS method.

Study on the optimization of the performance of preformed particle gel (PPG) on the isolation of high permeable zone

Unwanted water production is a critical problem in fractured reservoirs. Corrosion of facilities and reduction of oil relative permeability are some of the consequences of high water production. Preformed particle gel (PPG) injection is one of the conformance control methods, which initiated in 2007, has been used to control water production and increase sweep efficiency. There are several parameters which affect the performance of PPG such as stability at reservoir condition, salinity of makeup solution and PPG particle size and concentration. Although the study of the application of PPG in fracture plugging attracted a lot of attention in recent years, there are limited studies to investigate the effect of PPG physical properties on its application in water production control. In this study, the application of a super absorbent polymer on fracture plugging has been investigated. The results of swelling tests indicated that this type of PPG had significant high resistance even at high temperatures and wide range of salinities. In addition, the results of rheology tests showed that the PPG solution was stable even at high salinity and high shear rate condition. In order to study the mechanism of improvement of sweep efficiency through PPG injection, visual investigation using glass etched micromodel was performed. The results showed that the main mechanism for PPG treatment is water diversion into the low permeability zone as the consequence of fracture plugging. Also, core flooding tests were performed to check the performance of PPG in a heterogeneous carbonate porous media. According to the results, PPG was able to reduce the permeability, and this permeability reduction is related to swelling ratio which is controlled by makeup solution salinity. The results of this study revealed the potential of super absorbent polymers as preformed particle gel in unwanted water production through fracture plugging.

A viscoelastic self-regulating agent for enhance oil recovery

A novel hydrophobic monomer, allyl dodecylphenol polyoxyethylene ether (DP), was synthesized by reacting dodecylphenol polyoxyethylene ether (DPEO) and allyl chloride. Then DP was reacted with acrylamide (AM) and acrylic acid (AA) to form the viscoelastic self-regulating agent (DPPAM). The structure, thermalstability and microstructure of DPPAM was characterized by FT-IR, 1H-NMR, elemental analysis, thermal gravimetric analysis (TGA) and scanning electron microscope (SEM). Moreover, effect of DP dosage, DPPAM and salt concentrations as well as of the temperature and shear rate on the solution viscosity was investigated. Results indicated that 0.4 mol% DP can significantly improve the viscosity of the DPPAM solution to 100.01 mPa·s, and the CAC of DPPAM was 2.3 g/L. Notably, DPPAM showed superior properties in regard to temperature-tolerance, shear-tolerance and salt-tolerance than PPAM. Core flooding test declared that DPPAM enhanced oil recovery by 17.56 %, which was much better than 5.66 % of PPAM. All these features indicated that DPPAM has a better application potential in EOR than PPAM.

Rheological behavior of a wormlike micelle and an amphiphilic polymer combination for enhanced oil recovery

Amphiphilic polymers have been widely studied and applied in oil fields as effective enhanced oil recovery (EOR) agents. However, the viscosity of their aqueous solution is low at low concentration. In order to improve their poor viscosity-thickening ability at low concentrations, a combined system was used by mixing a zwitterionic surfactant (erucyl dimethyl amidopropyl betaine, EDAB) and an amphiphilic polymer (APC16) at the mass ratio of 2:1. The rheological properties and aggregate microstructure of the EDAB–APC16 combination system were investigated by rheometry, scanning electron microscopy, transmission electron microscopy, and fluorescence spectroscopy, and the EOR efficiency was measured using core flood tests. The results showed that EDAB can significantly increase the viscosity of the APC16 solution, even though the polymer concentration is lower than its critical aggregation concentration. In the EDAB–APC16 combination system, the wormlike micelles of EDAB can synergistically interact with APC16 through hydrophobic association and electrostatic attraction to achieve a thickening effect. Furthermore, the effects of temperature, pH, and the inorganic salts on the viscoelasticity of the EDAB–APC16 system were investigated. An optimized EDAB–APC16 system at 1500 mg/l [pH = 7.5 and c (NaCl) = 5000 mg/l] was selected to be the oil displacing agent, which achieved an EOR of 18.4% after the initial water flood. The polymer–surfactant composite system under development exhibited great potential as an effective chemical EOR agent.

Experimental Investigation and Performance Evaluation of Modified Viscoelastic Surfactant (VES) as a New Thickening Fracturing Fluid.

In hydraulic fracturing, fracturing fluids are used to create fractures in a hydrocarbon reservoir throughout transported proppant into the fractures. The application of many fields proves that conventional fracturing fluid has the disadvantages of residue(s), which causes serious clogging of the reservoir’s formations and, thus, leads to reduce the permeability in these hydrocarbon reservoirs. The development of clean (and cost-effective) fracturing fluid is a main driver of the hydraulic fracturing process. Presently, viscoelastic surfactant (VES)-fluid is one of the most widely used fracturing fluids in the hydraulic fracturing development of unconventional reservoirs, due to its non-residue(s) characteristics. However, conventional single-chain VES-fluid has a low temperature and shear resistance. In this study, two modified VES-fluid are developed as new thickening fracturing fluids, which consist of more single-chain coupled by hydrotropes (i.e., ionic organic salts) through non-covalent interaction. This new development is achieved by the formulation of mixing long chain cationic surfactant cetyltrimethylammonium bromide (CTAB) with organic acids, which are citric acid (CA) and maleic acid (MA) at a molar ratio of (3:1) and (2:1), respectively. As an innovative approach CTAB and CA are combined to obtain a solution (i.e., CTAB-based VES-fluid) with optimal properties for fracturing and this behaviour of the CTAB-based VES-fluid is experimentally corroborated. A rheometer was used to evaluate the visco-elasticity and shear rate & temperature resistance, while sand-carrying suspension capability was investigated by measuring the settling velocity of the transported proppant in the fluid. Moreover, the gel breaking capability was investigated by determining the viscosity of broken VES-fluid after mixing with ethanol, and the degree of core damage (i.e., permeability performance) caused by VES-fluid was evaluated while using core-flooding test. The experimental results show that, at pH-value (), 30 (mM) VES-fluid (i.e., CTAB-CA) possesses the highest visco-elasticity as the apparent viscosity at zero shear-rate reached nearly to 10 (mPa·s). Moreover, the apparent viscosity of the 30 (mM) CTAB-CA VES-fluid remains 60 (mPa·s) at (90 C) and 170 (s) after shearing for 2-h, indicating that CTAB-CA fluid has excellent temperature and shear resistance. Furthermore, excellent sand suspension and gel breaking ability of 30 (mM) CTAB-CA VES-fluid at 90 (C) was shown; as the sand suspension velocity is 1.67 (mm/s) and complete gel breaking was achieved within 2 h after mixing with the ethanol at the ratio of 10:1. The core flooding experiments indicate that the core damage rate caused by the CTAB-CA VES-fluid is (), which indicate that it does not cause much damage. Based on the experimental results, it is expected that CTAB-CA VES-fluid under high-temperature will make the proposed new VES-fluid an attractive thickening fracturing fluid.

A novel design of silica-based completion nanofluids for heavy oil reservoirs

The main objective of this manuscript is the design of completion nanofluids (NanoCF) using silica nanoparticles based on the impact on the capillary number for being applied in heavy crude oil reservoirs. Six types of silica nanoparticles with different chemical nature were characterized by dynamic light scattering (DLS), point of zero charge (pHpzc), Fourier transform infrared spectroscopy (FTIR), transmission electron microscopy (TEM), surface area (SBET), X-ray diffraction (XRD) and total surface acidity through temperature-programmed desorption of NH3 (TPD-NH3). Adsorption isotherms were constructed for understanding the non-ionic surfactant interaction with nanoparticles and rock surfaces, showing that a high adsorption affinity of the surfactant onto the rock surface, leaving less than 24% of free surfactant molecules able to migrate to the water/oil interface. Nevertheless, nanoparticle addition onto completion fluids (CF) could reduce the adsorbed surfactant onto the rock surface by 75%, which means more molecules of surfactant at the interface due to the nature of the obtained nanoparticles (NPS). The nanoparticles were selected based on the capillary number, showing that the best material reduced the interfacial tension between heavy crude oil and CF more than 76% and have the capacity to modify an initial oil-wet state to a water-wet rock surface. Finally, a coreflooding test was carried out at reservoir conditions (158 °F and 6.89 MPa) for evaluating the best completion nanofluid design based on the static tests, showing an increase of the oil effective permeability of 37% and incremental oil recovery of 3% in comparison to the completion fluid without nanoparticles. For the first time, novel completion nanofluids could allow stimulating the well from the beginning of the productive life.

Investigation of fines migration for a high-pressure, high-temperature carbonate gas reservoir offshore Malaysia

A high CO2 carbonate gas field offshore Sarawak, Malaysia, is scheduled for development. Fines migration has been identified as a potential risk for a sustained and stable production for this field, triggering this investigation. The reservoir investigated (subdivided in S3, S2, S1 formation) has an average 8% clays, of which over 50% are migratory illites and 15% migratory kaolinite. This paper discusses the laboratory findings and factors contributing to fines migration for this reservoir. We conducted core flood tests to determine critical flow rates for the onset of fines migration of high CO2 hydrocarbon gas and CO2-saturated brine within the production gas zone. In addition, we measured total suspended solids during each incremental rate stage and performed scanning electron microscopy–energy-dispersive X-ray (SEM–EDX) analysis on the effluents collected. We also performed mineralogical analysis of formation rocks to determine clay types, amount, and morphology. Core floods performed with CO2-saturated brine on S3 and S2 cores showed damage at a critical flow rate of 10 ml/min with permeability recovery of 65–75%. This shows that CO2-saturated brine tends to mobilize the fines such as illite and kaolinite. Core floods performed with high CO2 hydrocarbon gas showed permeability recovery of 93–96% at rates up to 10 ml/min. SEM analysis on effluents collected showed presence of silicate and carbonate particles with size of 5–50 μm. A combined salt dropout and fines mobilization core flood showed a higher degree of formation damage due to fines mobilization with 74% permeability recovery compared to baseline permeability compared to core floods with high CO2 hydrocarbon gas. However, the formation damage due to fines mobilization for this experiment was reversible. Overall, the results indicate that a high potential for fines migration in this type of carbonate system exists for CO2-saturated brine flow with significant less potential for dry CO2 flow.

Performance of Chromic Acetate-HPAM Gel for Flue Gas Mobility Control in Low-Permeability Reservoir

Chromium acetate-HPAM gel is developed to solve the gas channeling problem in low-permeability flue gas flooding reservoirs. Polyacrylamide with low molecular weight of 2 million is optimized as the main agent to construct an organic chromium gel system. The acid resistance performance and blocking capacity of the gel system are evaluated afterwards. It is revealed by the tests that acid components in flue gas have a severe impact on the gelation time, strength as well as long-term stability of the cross-linked gels. Rheological tests show that the gel system embodies with high elastic modulus in flue gas environment at 42°C, which ensures its favorable performance in core flooding tests. After gel application in cores, the permeability reduction can reach up to 99% and 97% separately while water flooding and flue gas flooding. The chromium acetate-HPAM gel exhibits perfect mobility control ability and possesses immense potential as regulating blocking system in low-permeability flue gas flooding reservoirs.

Development of silicon quantum dots based nano-fluid for enhanced oil recovery in tight Bakken cores

A novel silicon quantum dots (SiQDs) based nano-fluid was first developed for effectively recovering Bakken Oil. The Bakken Formation is one of the largest contiguous deposits of unconventional oil in the USA and Canada. However, the oil recovery rate is only 5%−10% due to the existence of abundant tiny pores and ultra-low permeability. In this work, a novel nano-fluid was developed using ultra-small sized silicon quantum dots (SiQDs) coated with a zwitterionic surfactant. The nano-fluid exhibited good stability in synthetic high salinity brine containing divalent cations at high temperature and excellent capabilities in reducing interfacial tension and altering wettability, making it a good enhanced oil recovery (EOR) agent for tight Bakken Formation. Experimental results showed that the developed nano-fluid recovered 25.72 %OOIP (original oil-in-place) from Bakken core samples by spontaneous imbibition, which was 7.49 %OOIP higher than using surfactant alone. Similar results were obtained in the core flooding tests, where 41.98 %OOIP was finally recovered by the nano-fluid, compared to 30.28% in surfactant case. Herein, the mechanisms of disjoining pressure and synergistic effects between surfactant and nanoparticles have also been put forward. In short, the developed quantum dots based nano-fluid has played an instructive and a reference role in the application of oil field and would be a potential oil displacing agent for EOR.

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

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.

Rapid and continuous polymer dissolution by rotating packed bed for enhanced oil recovery

Polymer flooding has been widely used for enhancing the on-shore oil recovery. However, this method is greatly restricted for offshore application because of the large space occupation and low polymer dissolution rate in traditional batch stirred tank reactor (STR). A rapid and continuous polymer dissolution approach via Higee intensification is firstly proposed. Study of this approach is investigated by partially hydrolyzed polyacrylamide (HPAM) dissolution testing in rotating packed bed (RPB). The effects of different operation parameters, including rotational speed, packing thickness, liquid flow rate and temperature of the dissolution performance are experimentally studied. The basic physical property, rheological property and stability testing results show that the quality of the as-obtained polymer solution is basically equivalent or slightly superior to that obtained by traditional STR method. The core flooding test of the polymer solution obtained by Higee technique exhibits nearly one percent higher improved oil recovery than that of the STR approach. Moreover, a 3-month pilot test (30 m3/h scale) of this Higee rapid polymer dissolution approach achieved 83.93 % space occupation reduction and 32.84 % power consumpation saving compared with the existing STR process. This method exhibits well prospect in polymer flooding for EOR, especially for offshore applications.

Role of the calcite-water interface in wettability alteration during low salinity waterflooding

Wettability alteration has been widely accepted as the key process for enhanced oil recovery during controlled salinity waterflooding. However, the decisive mechanism causing wettability alteration, particularly for crude-oil-brine-carbonate-rock systems, is not fully understood. Zeta potential is a key electrochemical parameter for the mineral-brine interface and is sensitive to physicochemical changes at the interface. In this study, we conducted core-flooding tests integrated with zeta potential measurements to characterize changes in wettability, oil recovery and zeta potential on two carbonate rock samples, Carbonate-I and Carbonate-II, comprised of close to pure calcite. Following the same coreflooding protocol with the same crude oil and flooding brine compositions, the two samples showed different behaviour. Incremental oil recovery during controlled (low) salinity waterflooding was observed in the oil-brine-Carbonate-II system (8% incremental oil recovery) but there was no response for the Carbonate-I system. The zeta potential of the Carbonate-I and Carbonate-II samples also showed different behaviour in high salinity formation brine, with Carbonate-I returning a positive zeta potential, consistent with previous published measurements, but Carbonate-II returning an anomalously negative value. We suggest that the different zeta potential and EOR behaviour is most likely caused by the different proportions of crystal faces and edges in each sample that are exposed to brine. The low permeability Carbonate-II sample contains nanoscale pores and the edges of the calcite crystals are the dominant surface in contact with brine. Our results suggest that textural variations in natural carbonates control calcite-brine interfacial properties and the behaviour during controlled salinity waterflooding.

Insights into the Effects of Pore Size Distribution on the Flowing Behavior of Carbonate Rocks: Linking a Nano-Based Enhanced Oil Recovery Method to Rock Typing.

As a fixed reservoir rock property, pore throat size distribution (PSD) is known to affect the distribution of reservoir fluid saturation strongly. This study aims to investigate the relations between the PSD and the oil–water relative permeabilities of reservoir rock with a focus on the efficiency of surfactant–nanofluid flooding as an enhanced oil recovery (EOR) technique. For this purpose, mercury injection capillary pressure (MICP) tests were conducted on two core plugs with similar rock types (in respect to their flow zone index (FZI) values), which were selected among more than 20 core plugs, to examine the effectiveness of a surfactant–nanoparticle EOR method for reducing the amount of oil left behind after secondary core flooding experiments. Thus, interfacial tension (IFT) and contact angle measurements were carried out to determine the optimum concentrations of an anionic surfactant and silica nanoparticles (NPs) for core flooding experiments. Results of relative permeability tests showed that the PSDs could significantly affect the endpoints of the relative permeability curves, and a large amount of unswept oil could be recovered by flooding a mixture of the alpha olefin sulfonate (AOS) surfactant + silica NPs as an EOR solution. Results of core flooding tests indicated that the injection of AOS + NPs solution in tertiary mode could increase the post-water flooding oil recovery by up to 2.5% and 8.6% for the carbonate core plugs with homogeneous and heterogeneous PSDs, respectively.

Development of Nanofluids for the Inhibition of Formation Damage Caused by Fines Migration: Effect of the interaction of Quaternary Amine (CTAB) and MgO Nanoparticles.

Fines migration is a common problem in the oil and gas industry that causes a decrease in productivity. In this sense, the main objective of this study is to develop nanocomposites based on the interaction of quaternary amine (hexadecyltrimethylammonium bromide—CTAB) and MgO to enhance the capacity of retention of fine particles in the porous medium. MgO nanoparticles were synthesized by the sol–gel method using Mg(NO3)2·6H2O as a precursor. Nanoparticles were characterized by dynamic light scattering (DLS), the point of zero charge (pHpzc), thermogravimetric analysis, and Fourier transform infrared spectroscopy (FT-IR). Different nanoparticle sizes of 11.4, 42.8, and 86.2 nm were obtained, which were used for preparing two system nanofluids. These systems were evaluated in the inhibition of fines migration: in the system I MgO nanoparticles were dispersed in a CTAB-containing aqueous solution, and system II consists of a nanocomposite of CTAB adsorbed onto MgO nanoparticles. The fines retention tests were performed using Ottawa sand 20/40 packed beds and fine particles suspensions at concentrations of 0.2% in a mass fraction in deionized water. Individual and combined effects of nanoparticles and CTAB were evaluated in different treatment dosages. The analysis of the interactions between the CTAB and the MgO nanoparticles was carried out through batch-mode adsorption and desorption tests. The best treatment in the system I was selected according to the fines retention capacity and optimized through a simplex-centroid mixture design for mass fractions from 0.0% to 2.0% of both CTAB and MgO nanoparticles. This statistical analysis shows that the optimal concentration of these components is reached for a mass fraction of 0.73% of MgO nanoparticles and 0.74% in mass fraction of CTAB, where the retention capacity of the porous medium increases from 0.02 to 0.39 mg·L−1. Based on the experimental results, the nanofluids combining both components showed higher retention of fines than the systems treated only with CTAB or with MgO nanoparticles, with efficiencies up to 400% higher in the system I and higher up to 600% in the system II. To evaluate the best performance treatment under reservoir conditions, there were developed core flooding tests at fixed overburden pressure of 34.5 MPa, pore pressure at 6.9 MPa and system temperature at 93 °C. Obtaining critical rate increases in 142.8%, and 144.4% for water and oil flow in the presence of the nanofluid. In this sense, this work offers a new alternative for the injection of nanocomposites as a treatment for the problem of fines migration to optimize the productivity of oil and gas wells.