Movement behavior of residual oil droplets and CO2: insights from molecular dynamics simulations

After primary and secondary recovery of tight reservoirs, it becomes increasingly challenging to recover the remaining oil. Therefore, improving the recovery of the remaining oil is of great importance. Herein, molecular dynamics simulation (MD) of residual oil droplet movement behavior under CO2 displacement was conducted in a silica nanopores model. In this research, the movement behavior of CO2 in contact with residual oil droplets under different temperatures was analyzed, and the distribution of molecules number of CO2 and residual oil droplets was investigated. Then, the changes in pressure, kinetic energy, potential energy, van der Waals' force, Coulomb energy, long-range Coulomb potential, bond energy, and angular energy with time in the system after the contact between CO2 and residual oil droplets were studied. At last, the g(r) distribution of CO2–CO2, CO2-oil molecules, and oil molecules-oil molecules at different temperatures was deliberated. According to the results, the diffusion of CO2 can destroy residual oil droplets formed by the n-nonane and simultaneously peel off the n-nonane molecules that attach to SiO2 and graphene nanosheets (GN). The cutoff radius r of the CO2–CO2 is approximately 0.255 nm and that of the C–CO2 is 0.285 nm. The atomic force between CO2 and CO2 is relatively stronger. There is little effect caused by changing temperature on the radius where the maximum peak occurs in the radial distribution function (RDF)-g(r) of CO2–CO2 and C–CO2. The maximum peak of g(r) distribution of the CO2–CO2 in the system declines first and then rises with increasing temperature, while that of g(r) distribution of C–CO2 changes in the opposite way. At different temperatures, after the peak of g(r), its curve decreases with the increase in radius. The coordination number around C9H20 decreases, and the distribution of C9H20 becomes loose.

Response to the Variation of Clay Minerals During ASP Flooding in the Saertu Oilfield in the Songliao Basin

In this paper, the variation of clay minerals and their influence on reservoir physical properties and residual oil before and after ASP flooding are analyzed. The results show that the total amount of clay minerals in reservoirs decreases after ASP flooding in the ultra-high-water-cut-stage reservoirs of the Naner Zone in the Saertu Oilfield, Songliao Basin. Therein, the illite content reduces, while the content of illite smectite mixed-layer and chlorite increases. The content of kaolinite varies greatly. The content of kaolinite decreases in some samples, while it increases in other samples. The clay minerals block the pore throat after ASP flooding. As a result, the pore structure coefficient and the seepage tortuosity increase, the primary intergranular pore throat shrinks, and the pore–throat coordination number decreases. Nevertheless, the dissolution of clay minerals reduces the pore–throat ratio and increases porosity and permeability. The variation of clay minerals after ASP flooding not only intensifies the reservoir heterogeneity but also affects the formation and distribution of residual oil. The residual oil of the oil–clay mixed adsorption state is a newly formed residual oil type related to clay, which accounts for 44.2% of the total residual oil reserves, so it is the main occurrence form of the oil in reservoirs after ASP flooding. Therefore, the exploitation of this type of residual oil has great significance to enhance the oil recovery in ultra-high-water-cut-stage reservoirs.

Produced Water Quality: The Effects of Different Separation Methods for Water and Chemical Floods

Gravity settling represents the main oil-water separation mechanism. Many separation plants rely only on gravity settling with the aid of demulsifiers (direct or reverse breakers) and other chemicals such as water clarifiers if they are required. Yet, other complementary separation methods exist including filtration, flotation, and centrifugation. In terms of results and more specifically with respect to the separated produced-water, the main threshold on its quality is the dispersed oil content. Even with zero discharge and reinjection into hydrocarbon formations, the presence of residual oil in the aqueous phase represents a concern. High oil content results into formation damage and losses in injectivity which necessitates formation stimulations and hence additional operational expenses. In this work, we investigated the effects of different separation techniques on separated water quality. In addition, we studied the impact of enhanced oil recovery (EOR) chemicals on the different separation techniques in terms of efficiency and water quality. Based on the results, we identified potential improvements to the existing separation process. We used synthetic well-characterized emulsions. The emulsions were prepared at the forecast water: oil ratio using dead crude oil and synthetic representative brines with or without the EOR chemicals. To clearly delineate and distinguish the effectiveness of different separation methods, we exacerbated the conditions by preparing very tight emulsions compared with what is observed on site. With that, we investigated three separation techniques: gravity settling, centrifugation, and filtration. First, we used Jar Tests to study gravity settling, then a benchtop centrifuge at two speeds to evaluate centrifugation potential. Finally, for filtration, we tested two options: membrane and deep-bed filtrations. Concerning the water quality, we performed solvent extraction followed by UV analyses to measure the residual oil content as well as light transmission measurements in order to compare the efficiency of different separation methods. The results of analyses suggest that gravity settling was not efficient in removing oil droplets from water. No separation occurred after 20 minutes in every tested condition. However, note that investigated conditions were severe, tighter emulsions are more difficult to separate compared to those currently observed in the actual separation plant. On the other hand, centrifugation significantly improved light transmission through the separated water. Accordingly, we can conclude that the water quality was largely improved by centrifugation even in the presence of EOR chemicals. In terms of filtration, very good water quality was obtained after membrane filtration. However, significant fouling was observed. In the presence of EOR chemicals, filtration lost its effectiveness due to the low interfacial tension with surfactants and water quality became poor. With deep-bed filtration, produced water quality remained good and fouling was no longer observed. However, the benefits from media filtration were annihilated by the presence of EOR chemicals. Based on these results and at least for our case study, we conclude that centrifugation and deep-bed filtration techniques can significantly improve quality of the separated and eventually reinjected water. In terms of the effects of EOR chemicals, the performance of centrifugation is reduced while filtrations are largely impaired by the presence of EOR chemicals. Thereby, integration of any of the two methods in the separation plant will lead to more efficient produced-water reinjection, eliminating formation damage and frequent stimulations. Yet, it is important to note that economics should be further assessed.

Heavy Oil Recovery by Alkaline-Cosolvent-Polymer Flood: A Multi-Scale Research Using CT Imaging

For reservoirs containing oil with a high total acid number, alkali-cosolvent-polymer (ACP) flood can potentially increase the oil recovery by its saponification effects. The enhanced oil recovery performance of ACP flood has been studied at core and reservoir scale in detail, however, the effect of ACP flood on residual oil saturation in the swept area still lacks enough research. Medical computed tomography (Medical-CT) scan and micro computed tomography (Micro-CT) scan are used in combination to visualize micro-scale flow and reveal the mechanisms of residual oil reduction during ACP flood. The heterogeneous cores containing two layers of different permeability are used for coreflood experiment to clarify the enhanced oil recovery (EOR) performance of ACP food in heterogeneous reservoirs. The oil saturation is monitored by Medical-CT. Then, two core samples are drilled in each core after flooding and the decrease of residual oil saturation caused by ACP flood is further quantified by Micro-CT imageing. Results show that ACP flood is 14.5% oil recovery higher than alkaline-cosolvent (AC) flood (68.9%) in high permeability layers, 17.9% higher than AC flood (26.3%) in low permeability layers. Compared with AC flood, ACP flood shows a more uniform displacement front, which implies that the injected polymer effectively weakened the viscosity fingering. Moreover, a method that can calculate the ratio of oil-water distribution in each pore is developed to establish the relationship between the residual oil saturation of each pore and its pore size, and reached the conclusion that they follow the power law correlation.

Development of the Surfactant-Based Chemical EOR Formula for Low Permeability Reservoirs

Based on the results of the foam flooding for our low permeability reservoirs, we have explored the possibility of using low interfacial tension (IFT) surfactants to improve oil recovery. The objective of this work is to develop a robust low-tension surfactant formula through lab experiments to investigate several key factors for surfactant-based chemical flooding. Microemulsion phase behavior and aqueous solubility experiments at reservoir temperature were performed to develop the surfactant formula. After reviewing surfactant processes in literature and evaluating over 200 formulas using commercially available surfactants, we found that we may have long ignored the challenges of achieving aqueous stability and optimal microemulsion phase behavior for surfactant formulations in low salinity environments. A surfactant formula with a low IFT does not always result in a good microemulsion phase behavior. Therefore, a novel synergistic blend with two surfactants in the formulation was developed with a cost-effective nonionic surfactant. The formula exhibits an increased aqueous solubility, a lower optimum salinity, and an ultra-low IFT in the range of 10-4 mN/m. There were challenges of using a spinning drop tensiometer to measure the IFT of the black crude oil and the injection water at reservoir conditions. We managed the process and studied the IFTs of formulas with good Winsor type III phase behavior results. Several microemulsion phase behavior test methods were investigated, and a practical and rapid test method is proposed to be used in the field under operational conditions. Reservoir core flooding experiments including SP (surfactant-polymer) and LTG (low-tension-gas) were conducted to evaluate the oil recovery. SP flooding with a selected polymer for mobility control and a co-solvent recovered 76% of the waterflood residual oil. Furthermore, 98% residual crude oil recovery was achieved by LTG flooding through using an additional foaming agent and nitrogen. These results demonstrate a favorable mobilization and displacement of the residual oil for low permeability reservoirs. In summary, microemulsion phase behavior and aqueous solubility tests were used to develop coreflood formulations for low salinity, low temperature conditions. The formulation achieved significant oil recovery for both SP flooding and LTG flooding. Key factors for the low-tension surfactant-based chemical flooding are good microemulsion phase behavior, a reasonably aqueous stability, and a decent low IFT.

Core-to-Field-Scale Simulations of Polymer Viscoelastic Effect on Oil Recovery Using the Extended Viscoelastic Model

Being one of the most commonly used chemical EOR methods, polymer flooding can substantially improve both macroscopic and microscopic recovery efficiencies by sweeping bypassed oil and mobilizing residual oil, respectively. However, a proper estimation of incremental oil to polymer flooding requires an accurate prediction of the complex rheological response of polymers. In this paper, a novel viscoelastic model that comprehensively analyzes the polymer rheology in porous media is used in a reservoir simulator to predict the recovery efficiency to polymer flooding at both core- and field-scales. The extended viscoelastic model can capture polymer Newtonian and non-Newtonian behavior, as well as mechanical degradation that may take place at ultimate shear rates. The rheological model was implemented in an open- source reservoir simulator. In addition, the effect of polymer viscoelasticity on displacement efficiency was also captured through trapping number. The calculation of trapping number and corresponding residual-phase saturation was verified against a commercial simulator. Core-scale tertiary polymer flooding predictions revealed the positive effect of injection rate and polymer concentration on oil displacement efficiency. It was found that high polymer concentration (>2000 ppm) is needed to displace residual oil at reservoir rate as opposed to near injector well rate. On the other hand, field-scale predictions of polymer flooding were performed in a quarter 5-spot well pattern, using rock and fluid properties representing the Middle East carbonate reservoirs. The field-simulation studies showed that tertiary polymer flooding might improve both volumetric sweep efficiency and displacement efficiency. For this case study, incremental oil recovery by polymer flooding is estimated at around 11 %OOIP, which includes about 4 %OOIP residual oil mobilized by viscoelastic polymers. Furthermore, the effect of different parameters on the polymer flooding efficiency was investigated through sensitivity analysis. This study provides more insight into the robustness of the extended viscoelastic model as well as its effect on polymer injectivity and related oil recovery at both core- and field-scales. The proposed polymer viscoelastic model can be easily implemented into any commercial reservoir simulator for representative field-scale predictions of polymer flooding.

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

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

Historical Overview and Future Perspective of Chemical EOR Project for Major Malaysian Offshore Oilfield: Case Study

A major Malaysian offshore oilfield, which is currently operating under waterflooding for a quite long time and declining in oil production, plan to convert as chemical enhanced oil recovery (CEOR) injection. The CEOR journey started since the first oil production in year 2000 and proximate waterflooding, with research and development in determining suitable method, encouraging field trial results and a series of field development plans to maximize potential recovery above waterflooding and prolong the production field life. A comprehensive EOR study including screening, laboratory tests, pilot evaluation, and full field reservoir simulation modelling are conducted to reduce the project risks prior to the full field investment and execution. Among several EOR techniques, Alkaline-Surfactant (AS) flooding is chosen to be implemented in this field. Several CEOR key parameters have been studied and optimized in the laboratory such as chemical concentration, chemical adsorption, interfacial tension (IFT), slug size, residual oil saturation (Sor) reduction, thermal stability, flow assurance, emulsion, dilution, and a chemical injection scheme. Uncertainty analysis on CEOR process was done due to the large well spacing in the offshore environment as compared to other CEOR projects, which are onshore with shorter well spacing. The key risks and parameters such as residual oil saturation (Sorw), adsorption and interfacial tension (IFT) cut-off in the dynamic chemical simulator have been investigated via a probabilistic approach on top of deterministic method. The laboratory results from fluid-fluid and rock-fluid analyses ascertained a potential of ultra-low interfacial tension of 0.001 dyne/cm with adsorption of 0.30 mg/gr-of-rock, which translated to a 50-75% reduction in Sor after waterflooding. The results of four single well chemical tracer tests (SWCTT) on two wells validated the effectiveness of the Alkaline Surfactant by a reduction of 50-80% in Sor. The most suitable chemical formulation was found 1.0 wt. % Alkali and 0.075 wt. % Surfactant. The field trial results were thenceforth upscaled to a dynamic chemical simulation; from single well to full field modeling, resulting an optimal chemical injection of three years or almost 0.2 effective injection pore volume, coupled with six months of low salinity treated water as pre-flush and post-flush injection. The latest field development study results yield a technical potential recoverable volume of 14, 16, and 26 MMstb (above waterflooding) for low, most likely, and high cases, respectively, which translated to an additional EOR recovery factor up to 5.6 % for most-likely case by end of technical field life. Prior to the final investment decision stage, Petronas’ position was to proceed with the project based on the techno-commerciality and associated risks as per milestone review 5, albeit it came to an agreement to have differing interpretations towards the technical basis of the project in the final steering committee. Subsequently, due to the eventual plunging global crude oil price, the project was then reprioritized and adjourned correspondingly within Petronas’ upstream portfolio management. Further phased development including a producing pilot has been debated with the main objective to address key technical and business uncertainties and risks associated with applying CEOR process.

Recent Advances in Capillary Desaturation Curves for Sandstone and Carbonate Reservoirs

Different enhanced oil recovery (EOR) methods are usually applied to target remaining oil saturation in a reservoir after both conventional primary and secondary recovery stages. The remaining oil in the reservoir is classified into capillary trapped residual oil and unswept /bypassed oil. Mobilizing the residual oil in the reservoir is usually achieved through either decreasing the capillary forces and/or increasing the viscous or gravitational forces. The recovery of the microscopically trapped residual oil is mainly studied using capillary desaturation curve (CDC). Hence, a fundamental understanding of the CDC is needed for optimizing the design and application of different EOR methods in both sandstone and carbonate reservoirs. For sandstone reservoirs, especially water-water rocks, determining the residual oil saturation and generating CDC has been widely studied and documented in literature. On the other hand, very few studies have been conducted on carbonate rocks and less data is available. Therefore, this paper provides a comprehensive review of several important research studies published on CDC over the past few decades for both sandstone and carbonate reservoirs. We critically analyzed and discussed theses CDC studies based on capillary number, Bond number, and trapping number ranges. The effect of different factors on CDC were further investigated including interfacial tension, heterogeneity, permeability, and wettability. This comparative review shows that capillary desaturation curves in carbonates are shallower as opposed to these in sandstones. This is due to different factors such as the presence of high fracture density, presence of micropores, large pore size distribution, mixed-to-oil wetting nature, high permeability, and heterogeneity. In general, the critical capillary number reported in literature for sandstone rocks is in the range of 10−5 to 10−2. However, for carbonate rocks, that number ranges between 10−8 and 10−5. In addition, the wettability has been shown to have a major effect on the shape of CDC in both sandstone and carbonate rocks; different CDCs have been reported for water-wet, mixed-wet, and oil-wet rocks. The CDC shape is broader and the capillary number values are higher in oil-wet rocks compared to mixed-wet and water-wet rocks. This study provides a comprehensive and comparative analysis of CDC in both sandstone and carbonate rocks, which serves as a guide in understanding different CDCs and hence, better screening of different EOR methods for different types of reservoirs.