Chemical Flooding Research Articles

Lignin Nanoparticles as Highly Efficient, Recyclable Emulsifiers for Enhanced Oil Recovery

Emulsification is one of the important processes in chemical flooding to mobilize the residual oil in wells following secondary recovery. Oil displacement efficiency is enhanced and volumetric sweep efficiency is increased by engineering the interactions of the supporting chemicals used with the geological formations present in the wells. Polymers and surfactants are often applied to enhanced oil recovery (EOR) as emulsification displacement. However, polymers are limited by poor temperature and salt tolerance, while surfactants have a high cost. In this contribution, we report on the use of lignin nanoparticles (LNPs) as Pickering emulsifiers obtained from enzymatic hydrolysis of lignin powders to apply in EOR. The interfacial activity of LNPs prepared this way is greatly improved, which substantially promotes its emulsification ability. We show that kerosene emulsified with different concentrations of LNPs can form stable Pickering emulsions, and the emulsions can be stored for up to 6 months. In addition, due to the pH responsive character of lignin, rapid oil–water separation can be achieved by alkali demulsification. This enables the reuse of lignin suspension under pH control, which provides a new platform for the application of green and low-cost flooding, employing LNPs in EOR.

Coreflood-on-a-Chip Investigation of Oil Bank Formation in Low Interfacial Tension Chemical Floods at Favorable and Unfavorable Viscosity Ratios

Summary An efficient tertiary chemical flood involves the chemicals displacing the oil in a stable manner, so the initially disconnected trapped oil ganglia coalesce into a bank as the flood progresses. However, the location of surfactants and polymers in the core during a chemical flood is difficult or impossible to determine at very fine time and space resolutions. In this work, we bridge this gap by visualizing saturation profiles in a coreflood-on-a-chip, a micromodel that is the same length as a core, and monitoring fluorescent aqueous injectant as displacements occur. We visualize, for the first time, surfactants in and around oil banks at the pore and Darcy scales during low-tension displacements. We present 12 chemical floods in the coreflood-on-a-chip, imaged at the centimeter scale, including six surfactant and six alkali-surfactant-polymer (ASP) floods at low, intermediate, and high initial water saturations. Additionally, we present a micron-scale visualization of an ASP flood under UV light to observe the distribution of surfactant around an oil bank at the pore scale. We found that oil banks formed even during very unfavorable displacements, when surfactant solution (1 cp) displaced oil (80 cp) in a micromodel at intermediate and residual oil saturations. Although our results show saturation profiles are mostly well described by fractional flow theory, the distribution of injected aqueous phase is not. Significant aqueous injectant, including surfactant, flows within and ahead of oil banks.

Alkaline-Surfactant-polymer (ASP) for chemical flooding in carbonate reservoirs

Alkaline-Surfactant-polymer (ASP) for chemical flooding in carbonate reservoirs

Viscoelastic Oil Displacement System of Modified Silica Nanoparticles/Zwitterionic Surfactant for High Salinity Reservoir

AbstractPolymer flooding and polymer/surfactant flooding have achieved good efficiency in the application of conventional reservoir, but the existed chemical flooding technology cannot cannot address the issues of the requirements of chemical flooding in high salinity reservoir. Under the condition of high salinity reservoir, due to the increase of calcium and magnesium ions, the increasing viscosity effect of oil displacement system is lost. In order to study the feasibility of applying nanomaterials in the field of enhanced oil recovery under the conditions of high salinity reservoir, develop a low-concentration and high-efficiency oil displacement system. EAPC solution has advantages in reducing interfacial tension, but its viscosity is not good. Therefore, hydrophobically modified silica nanoparticles (SiO2 NPs) were added to the carboxylic acid–type erucic acid amide propyl betaine (EAPC) solution. The interaction between EAPC and hydrophobic carbon chains led to the exposure of carboxyl groups, thus making the system more stable. The interfacial activity and zeta potential were studied, and the interaction mechanism between modified SiO2 NPs and EAPC was obtained. The results show that when the EAPC concentration is 0.3%, the apparent viscosity of the modified silica nanoparticles (SiO2 NPs) composite system can reach 40 mPa·s, and the oil-water interfacial tension can be reduced to 10-2 mN/m. The micro-visualization model and the simulated oil displacement experiment proved that the modified SiO2 NPs (0.3%)/EAPC (0.3%) composite system has a variety of oil displacement mechanisms. Under the simulated reservoir conditions (total salinity of 25000 mg/L, calcium and magnesium ion concentration of 500 mg/L, 70 °C), it is proved that the modified SiO2 NPs composite system had good viscoelasticity and improved oil washing efficiency. The oil displacement system has guiding significance for effectively enhancing the recovery of high salinity reservoir.

Effect Evaluation and Action Mechanism Analysis of "Profile Control + Plugging Removal" after Chemical Flooding.

The existing plugging removal operation in JZ9-3 oilfield has the disadvantages of small amount of plugging remover, fast injection speed, and short construction time. Under the condition of injection well suction profile reversal, plugging remover is difficult to enter the low permeability part and play the role of deep plugging removal. In order to improve the plugging removal effect, this paper used the physical simulation method to carry out the experimental study and mechanism analysis on the effect of water flooding, chemical flooding, and plugging removal measures of the multi-layer system combination model. The results showed that the recovery of general plugging removal after chemical flooding increases by only 0.70%, while the recovery of ‘profile control + plugging removal’ increases by ‘9.34% + 2.59%’, and the amount of produced liquid decreases by more than 40%. It can be seen that the combined operation of profile control and plugging removal has dual effects of plugging and dredging and synergistic effect, which not only expands the swept volume, but also reduces the inefficient and ineffective cycles. On this basis, the optimization design and effect prediction of the target well W4-2 plugging removal scheme were carried out by using the numerical simulation method. Recommended scheme: inorganic gel profile control agent volume 13,243.6 m3, produced by the main agent (Na2O·nSiO2), isolation fluid (Water), and auxiliary agent (CaCl2) through multiple rounds of alternating injection into the reservoir. The plug removal agent (K2S2O8) injection volume is 100 m3, the concentration is 0.8%. The post-implementation ‘Output/Input’ ratio is expected to be 3.7.

Evaluation of Silicon Carbide Nanoparticles as an Additive to Minimize Surfactant Loss during Chemical Flooding

AbstractSurfactant flooding is a prolific enhanced oil recovery technique. It alters the rock fluid interfacial interactions between reservoir fluids and rocks. However, a pair of impeding factors often limit the economic viability of the process and need to be optimized. The first is the surfactant loss on the adsorbent surface due to adsorption making it a potential environmental problem. The second is the Critical Micelle Concentration (CMC) which governs the amount of surfactant pumped. This study aimed to minimize the surfactant loss and the CMC, thereby optimizing the flooding efficiency and reducing the environmental concerns for nanoparticle applications. To achieve this, Silicon Carbide nanoparticles (SCN) were employed as additives to the surfactant solution. It was observed that the use of SCN reduces the surfactant adsorption by as much as 44 % and the critical micelle concentration by 14 %. The studies also observed that the concentration of SCN required to get these results is dramatically (more than 25 times) lower than previously reported literature on other nanoparticles. To adsorption isotherm studies provide an insight into the type of adsorption taking place. The adsorption isotherm follows the Langmuir model.

Study on micro remaining oil distribution of polymer flooding in Class-II B oil layer of Daqing Oilfield

During the implementation of chemical flooding, problems of slow decline of water cut and poor development effect appear in Class-II B oil layer of Daqing Oilfield. In this paper, photoetched glass models and micro CT-scanner technology are used for polymer flooding experiment with different molecular weight. Experiment are carried out by parallel displacement method to simulate the effect of interlayer heterogeneity on the residual oil distribution. The results of photoetched glass model displacement experiment show that under the condition of parallel displacement, the enhanced oil recovery of low permeability model is the largest when the molecular weight of polymer solution is 1900 × 104 Da, and the overall displacement efficiency is the best. However, the compatibility between polymer solution with molecular weight of 2500 × 104 Da and low permeability model is poor. The variations in cluster residual oil saturation is lower in low permeability model, whereas other types of residual oils are higher. Micro CT-scanner results show that there is almost no membrane and blind end residual oils after polymer flooding, which validates the low utilization ratio of membrane and blind end residual oils saturation in photoetched glass model.

Analyzing the microbial factors affecting microbial enhanced oil recovery through numerical simulation study

ABSTRACT Primary and secondary recovery methods are usually not sufficient to maximize the oil recovery. In many cases, more than 40% of the Oil Initially in Place is left in the reservoir after implementing these recovery methods. To resolve the issue at hand, petroleum engineers have at their disposition a plethora of tertiary recovery methods such as chemical flooding, thermal recovery, and microbial enhanced oil recovery (MEOR). In this study, we propose the use of MEOR: a technique that uses naturally occurring microbes in the reservoir or injected microbes to enhance the oil recovery. The MEOR process is governed by several mechanisms such as viscosity reduction, relative permeability alteration, capillary pressure alteration, and other reaction-induced system changes such as pressurization. This study investigates the impact of these mechanisms on the hydrocarbon production by conducting a numerical simulation using our in-house MEOR numerical simulator. In the base case study, the case with MEOR shows the 20% of oil production improvement than the case without MEOR. We conduct a sensitivity analysis to evaluate the impact of microbial factors affecting MEOR to the system responses and production behavior, where the maximum growth rate of microbes is found to be the most influential factor with the scaled sensitivity coefficient of 1.384 × 105. The findings provide the relative impacts of factors affecting the performance of MEOR, which subsequently suggest the factors to be investigated with emphasis for oil production improvement in the MEOR applications.

Research and Application of Chemical Flooding Control Technology in Sand-producing Reservoir

Research and Application of Chemical Flooding Control Technology in Sand-producing Reservoir

Testing of a hydrodynamic chemical flooding simulator by comparing the results of polymer flooding simulation with similar results of existing simulators

The use of numerical modeling tools, including reservoir simulators, helps oil companies in making decisions and ensuring successful field development. This work is devoted to the testing of a reservoir simulator based on a new formulation in partial derivatives of a compositional model of chemical flooding by comparing the results of polymer flooding simulation with similar results of Eclipse 100.

Creation of a Hydrodynamic Digital Model of a Laboratory Core Experiment of Surfactant Polymer Impact on Oil Recovery, in Order to Determine Parameters for Further Full-Scale Simulation

The work aimed to solve the problem of determining, validating, and transferring model parameters of flooding using chemical enhanced oil recovery (EOR) from a core experiment to a full-scale hydrodynamic model. For this purpose, a digital hydrodynamic model describing the process of oil displacement by the surfactant and polymer solution on the core is created and the digital model is matched to achieve convergence with the historical data. This approach allows the uncertainties associated with the limited number of experiments to be removed to fully describe the parameters of the chemical surfactant polymer flooding model and form a database that could subsequently be replicated at various field sites, having the composition of reservoir fluids and distribution of rock composition in the core material as the basis. Besides, the digital model allows for verification of physical and chemical properties of surfactants and polymers, values of the adsorption of chemical agents on rocks, and the behavior of relative permeability in the hydrodynamic model of EOR before making predictions on the full-scale model and to improve the quality of forecast cases.

Distribution Characteristics of Micro Remaining Oil of Class III Reservoirs after Fracture Flooding in Daqing Oilfield

The class III reservoir in the Daqing Oilfield has poor sand body development, poor reservoir physical properties, and poor effects of measures. Its water drive recovery degree is low and the remaining reserves are large. It is the key target oil layer of the Daqing Oilfield. Due to the sedimentary characteristics and reservoir physical properties of class III reservoirs, conventional EOR technology (chemical flooding) and conventional stimulation and injection measures (fracturing) have poor potential tapping effects on class III reservoirs. According to the special reservoir conditions and development characteristics of the class III reservoir in the Daqing Oilfield, fracture-flooding technology is innovatively proposed, which greatly improves the recovery of remaining oil in class III reservoirs. The rapid injection of hydraulic surface activators into the formation and displacement of the remaining oil in class III reservoirs through rock core flooding experiments were simulated in this paper. The nuclear magnetic resonance (NMR), confocal scanning laser, and computed tomography (CT)-scanning technologies were applied to study the remaining oil distribution after fracture flooding. The results show that: (1) After fracture flooding, the peak value of the T2 spectrum curve of NMR shifts to the left and the degree of middle and small pore space production increases obviously. (2) Confocal scanning laser study shows that the remaining oil in thin membranous and clustered forms on pore surfaces is highly utilized. (3) CT scan study shows that the remaining oil in membranous and clustered forms is effectively utilized after fracture flooding. In summary, fracture-flooding technology can improve the washing efficiency and sweep volume of class III reservoirs, thus enhancing the recovery efficiency of class III reservoirs.

An integrated framework based on deep learning algorithm for optimizing thermochemical production in heavy oil reservoirs

The development of heavy oil reservoirs with active edge and bottom water is one of the most challenging problems in petroleum engineering. In response to the limited thermal recovery of these reservoirs, a multi-phase and multi-component numerical simulation model for thermal and chemical recovery is proposed. An edge-water assisted chemical flooding (EAC flooding) is proposed, which can improve oil displacement efficiency and sweep efficiency by rational utilization of edge-water energy when compounding multi-component chemical system. Then, a deep reinforcement learning algorithm is proposed to predict dynamic production parameters and determine the optimal working system to maximize the oil recovery according to the above mathematical model. The deep reinforcement learning (DRL) model can predict the dynamic production curves according to given states with optimal strategy. At the same time, the proposed model can determine the best conversion timing from cyclic steam stimulation to EAC flooding. Finally, the DRL model can automatically obtain the optimal working system, effectively improving the oil recovery while considering the economic benefits. Thus, the DRL model can solve traditional numerical simulation's time-consuming and labor-intensive challenges and accurately give the optimal working system for developing heavy oil reservoirs with edge water in the field.

The ternary combination of polymer gel, microsphere and surfactant for conformance control and oil displacement to improve oil recovery in strong heterogeneous reservoir

The reservoir heterogeneity of Suizhong 36-1 oilfield is very obvious, the average permeability reaches 2000mD. Long-term water injection development leads to serious water channeling in high permeability layers, resulting in ineffective circulation of injected water and reduction of oil recovery. It is urgent to form an effective EOR method. In this paper, the oil displacement effect of different combination slugs including polymer gel, polymer microsphere and surfactant is evaluated by means of conformance control and chemical flooding. Three-layer heterogeneous 3-D plate model is used for oil displacement experiment. The experimental results show that the combination slug sequentially composed of polymer gel, polymer microspheres and surfactant have the best oil displacement effect with the oil recovery increment by 21.2% after the first water flooding. In addition, using the best slug combination for two rounds flooding, the recovery factor increased by 28.2% compared with the first water flooding. This paper provides some new insights for enhanced oil recovery in strong heterogeneity reservoir.

Low retention surfactant-polymer process for a HTHS carbonate reservoir

Development of surfactant formulations for high temperature (100 °C), high salinity (>50,000 ppm) and especially high hardness (>2000 ppm) reservoirs is challenging. Alkali-surfactant-polymer processes have been developed in the past, but requires soft injection brine. The objective of this work is to develop a surfactant-polymer (SP) process for a high temperature, high salinity (HTHS) reservoir that can be injected with available hard brines (such as sea water) to achieve ultra-low IFT, low residual oil saturation, and low surfactant retention in carbonate rocks. Phase behavior experiments were performed to identify a combination of anionic and zwitterionic surfactants. Four tertiary chemical corefloods were conducted in Indiana Limestone cores to test oil recovery and surfactant retention. A copolymer containing acrylamido-tertiary-butyl sulfonate, SAV10xv was identified to be stable at this HTHS condition. Sodium polyacrylate (NaPA) was identified as a sacrificial chemical to reduce surfactant adsorption. The chemical floods were successful in reducing the residual oil saturation to 8–11%. A preflush of NaPA reduced the surfactant retention from 0.133 mg/g to 0.017–0.038 mg/g of rock. Including the NaPA in the chemical slug was not as effective. The use of this surfactant formulation with a preflush of sodium polyacrylate can enhance the oil recovery in high temperature, high salinity carbonate reservoirs with very low surfactant retention.

Experimental investigation on remaining oil distribution and recovery performances after different flooding methods

Nowadays most of the oilfield in China have entered the middle-late development stages with the problem of high water cut and low permeability. Many studies have been conducted on the mechanism of chemical flooding to enhance oil recovery. However, there has been less previous evidence for accurate identification and distribution of remaining oil. Therefore, we proposed a new nuclear magnetic resonance (NMR) interpretation method as well as a new residual oil fluorescence analysis method. In this study, we conducted core displacement experiments with different methods. The nuclear magnetic resonance (NMR) tests and fluorescence analysis of frozen slides were performed in each stage after flooding to study the effect of different displacement methods on the recovery degree and the remaining oil distribution. The results showed that alkali can only slightly improve the recovery of macropores and free-state oil due to its poor sweep volume and oil washing efficiency. Surfactants can increase oil recovery in mesopores and the type of bound-state remaining oil by reducing interfacial tension (IFT). Although the injection of polymer can enlarge the sweep volume, the effect of displacement efficiency is poor in narrow space. Therefore, it can only improve the recovery factor in smallpores and mesopores as well as the type of free-state remaining oil. The synergistic effect of ASP system not only can form ultra-low interfacial tension to enhance the recovery of bound-state and half-bound state, but also can help surfactants and alkali enter smallpores according to the injection of polymer. Thus, the oil recovery is significantly improved. Moreover, our study provided a micro-level understanding as the occurrence state and distribution of remaining oil. The result also lays the foundation for further enhance oil recovery in oilfield.

Molecular Dynamics Studies on Effective Surface-Active Additives: Toward Hard Water-Resistant Chemical Flooding for Enhanced Oil Recovery.

Divalent ions, which are omnipresent in brine, may be detrimental to surfactant functionalities during chemical flooding in the enhanced oil recovery (EOR) process. Surfactant blending is one potential solution to overcome such an adverse effect. Herein, we report a molecular dynamics (MD) study to investigate the molecular arrangement and possible applications of surfactant blending in hard water-resistant chemical flooding for oil recovery. We chose commonly used anionic surfactants, sodium dodecyl sulfate (SDS), as primary surfactants. The non-ionic (propanol) and cationic [cetrimonium bromide (CTAB)] surfactants with a wide range of concentrations are introduced to the primary system. We demonstrate that CTAB can disaggregate the cation bridging when their concentration is above a certain threshold. This threshold value is related to the surfactant and cosurfactant surface charge in the interface region. The cation bridging density is maintained at a low level when the sum of surfactants and cosurfactant interface charges is neutral or positive. On the other hand, propanol barely disaggregates the cation bridging. When propanol concentration is above a certain value, it even facilitates the cation bridging formation. Both propanol and CTAB can further decrease the oil-brine interfacial tension (IFT) while having different efficacies (IFT decrement rate is different as their interface concentration increases). More rapid IFT decrement is observed when cation bridging is disaggregated (i.e., in systems with high CTAB concentrations). Increasing propanol concentration barely affects hydrogen bond (H-bond) formation between SDS and H2O because of a low propanol distribution around SDS. On the other hand, the first increasing and then decreasing trend in H-bond density between SDS and H2O is observed as CTAB concentration increases. Our work should provide important insights into designing chemical formulas in chemical flooding applications.

Micromechanism of partially hydrolyzed polyacrylamide molecule agglomeration morphology and its impact on the stability of crude oil−water interfacial film

Based on the background of oilfield chemical flooding produced liquid treatment projects, to achieve new insight into the micromechanism of the impact of polymer molecules applied to enhanced oil recovery (EOR) technology on the crude oil−water interface behavior, different “crude oil/HPAM/produced water” interface simulation systems were constructed by regulating the polymerization degree and hydrolysis degree of partially hydrolyzed polyacrylamide (HPAM) and combining the composition and physical properties of oil and water phases. The simulated results showed that all simulation systems have a stable layer order and clear crude oil−water interface after dynamic relaxation equilibrium. HPAM molecules were agglomerated in different forms at the crude oil−water interface depending on the inorganic cations in the water phase and their own degree of polymerization and hydrolysis, and the order of inorganic cations aggravating the agglomeration was Ca2+>Na+>K+>Mg2+. The stability of the interfacial film was positively correlated with the gyration radius of the HPAM molecules. Unlike the continuous increase in the gyration radius of HPAM molecules with increasing polymerization degree, the effect of increasing hydrolysis degree on the stability of the crude oil−water interfacial film is concentrated in the range of 15–35%, the gyration radius of HPAM molecules no longer increases when the hydrolysis degree continues to increase, and the interfacial film stability no longer significantly changes.

Date-Leaf Carbon Particles for Green Enhanced Oil Recovery.

Green enhanced oil recovery (GEOR) is an environmentally friendly enhanced oil recovery (EOR) process involving the injection of green fluids to improve macroscopic and microscopic sweep efficiencies while boosting tertiary oil production. Carbon nanomaterials such as graphene, carbon nanotube (CNT), and carbon dots have gained interest for their superior ability to increase oil recovery. These particles have been successfully tested in EOR, although they are expensive and do not extend to GEOR. In addition, the application of carbon particles in the GEOR method is not well understood yet, requiring thorough documentation. The goals of this work are to develop carbon nanoparticles from biomass and explore their role in GEOR. The carbon nanoparticles were prepared from date leaves, which are inexpensive biomass, through pyrolysis and ball-milling methods. The synthesized carbon nanomaterials were characterized using the standard process. Three formulations of functionalized and non-functionalized date-leaf carbon nanoparticle (DLCNP) solutions were chosen for core floods based on phase behavior and interfacial tension (IFT) properties to examine their potential for smart water and green chemical flooding. The carboxylated DLCNP was mixed with distilled water in the first formulation to be tested for smart water flood in the sandstone core. After water flooding, this formulation recovered 9% incremental oil of the oil initially in place. In contrast, non-functionalized DLCNP formulated with (the biodegradable) surfactant alkyl polyglycoside and NaCl produced 18% more tertiary oil than the CNT. This work thus provides new green chemical agents and formulations for EOR applications so that oil can be produced more economically and sustainably.

Experimental evaluation of designed and synthesized Alkaline-Surfactant-polymer (ASP) for chemical flooding in carbonate reservoirs

More than half of the oil and gas resources of the world are hosted in carbonate reservoirs. Also, a total of 60% of their residual oil is left unswept during conventional primary and secondary oil recovery operations. The complexity of carbonate reservoirs due to relative weak water imbibition, undesired capillary forces, low permeability (less than 50mD), oil wetness and geochemical interactions in the presence of formation water high salinity causes precipitation of the injection chemicals resulting in clogging of pore throats and residual oil entrapment. Therefore, taking advantage of purposefully designed chemicals known as alkaline-surfactant-polymer (ASP) for enhanced oil recovery (EOR) applications rather than common commercial ASP materials for these challenging petroleum reservoirs is expected. In this research, the synthesized ASP combination was considered to improve the oil production mechanisms of the desired carbonate porous medium. Ultra-low interfacial tension about 1.6 × 10–3 has been achieved by Alkaline-Surfactant-Nano (ASN) synergistic formulation. Meanwhile, wettability alteration was evaluated by contact angle measurement. The contact angle was reduced from Θ = 155.2° (oil-wet) to Θ= 23.7° (water-wet) by the ASN combination. As well, the remarkable HTHS tolerable and shear resistance synthesized Co-polymer Nanocomposite was applied, and 10 times diluted seawater (losal) was chosen as chemicals compatible aqueous solvent for core flooding experiments. Thus, formulated ASP fluids were synergized by alumina nanoparticles at optimized concentrations of chemicals. Hence, this synthesized ASP is able to improve the residual oil production mechanism and lower the capillary pressure (Pc). 16 chemical flooding scenarios were run on Karanj oil field carbonate outcrop cores; the results of the four successful scenarios with the highest original oil in place (OOIP) recovery percentages are discussed. Experiments results are revealed that the cumulative oil recovery could arrive at 91% under the harsh condition of the reservoir. According to the findings of current research, this ASP formulation is highly recommended for chemical flooding of tight carbonate reservoirs.