Search

Complex surfactant formulations have been applied to induce ultra-low interfacial tension (IFT) (e.g., 10−3 mN/m) between the displacing water phase and the displaced oil phase in chemical enhanced oil recovery (CEOR), where the residual oil after waterflooding can be largely recovered as an oil bank. This paper is concerned with a simpler, lower-cost CEOR, in which a sole additive of surface active solvent (SAS) makes low-tension displacement fronts in polymer flooding (e.g., 10−2 mN/m) without involving ultra-low IFT microemulsion phase behavior. The envisioned application of SAS in this research is to displace a continuous oil phase with low-IFT displacement fronts with mobility control by polymer. Previous research found that 2-ethylhexanol-7PO-15EO (2-EH-7PO-15EO, or "7-15") as SAS was able to reduce the IFT between polymer solution and the reservoir oil from 15.8 mN/m to 0.025 mN/m. In this research, the effect of SAS partition coefficient on the low-tension polymer (LTP) flooding was studied as an additional factor for SAS optimization. In particular, the comparison between two SAS species, 2-EH-4PO-15EO (4-15) and 2-EH-7PO-25EO (7-25), was important, because they had similar IFT values, but markedly different partition coefficients. The IFT was 0.20 mN/m with 4-15 and 0.18 mN/m with 7-25; and the partition coefficients were 1.61 with 4-15 and 0.68 with 7-25 at the experimental temperature, 61°C. These two SAS species were compared in the secondary-mode LTP flooding with a slug of 0.5 wt% SAS for 0.5 pore-volumes injected (PVI). Although these two SAS species gave comparable IFT values, their oil-displacement characteristics were quite different. The oil recovery factor at 1.0 PVI was 65% with 4-15 and 67% with 7-25. At 5.0 PVI, it was 74% with 4-15 and 84% with 7-25. The SAS recovery at the effluent was 67% for the 4-15 SAS and 86% for the 7-25 SAS. With a similar IFT reduction, the SAS with a smaller partition coefficient (i.e., 7-25) resulted in less SAS retention and more oil production for a given amount of injection. In comparison to the previous research with 7-15, the oil recovery factor with 7-25 was smaller at 5.0 PVI, but similar at early times up to 1.5 PVI. When the SAS concentration was reduced to 0.1 wt% SAS for 0.5 PVI, the oil recovery factors with 7-25 and 7-15 were close to each other at both early and final stages. In these smaller slug sizes, the SAS recovery was detected only for the 7-25 case, which means 7-25 went through the sandpack whereas 7-15 did not. That is, the optimization of SAS likely requires taking a balance between lowering the partition coefficient and lowering the IFT.

Chemical additives have often been added to injection water for enhanced oil recovery (EOR) from geologic formations in the oil industry. The oil clusters in porous mediums commonly remain in the microsized capillary elements such as pores and throats due to high capillary pressures or negative capillary pressures, which is a function of pore topology, interfacial tensions, and wettability. Recent studies show that tailoring the ion composition in the injection brine can be an effective way to alter the wettability of carbonate reservoirs, reverse the capillary pressures to positive values, and improve oil displacement efficiency. There are limited studies on the impact of dynamic wettability alteration on multiphase fluid flow in heterogeneous carbonate rocks. The dynamics of pore-by-pore displacement by smart waterflooding is still unclear. The objective of this research is to examine the process of wettability alteration in a natural carbonate rock by smart waterflooding and understand its impact on the microscale oil displacement. A carbonate rock sample was flooded with various amount of smart water within the first hour and after twelve hours, and the flooding cycles were visualized using synchrotron-based microtomography. The pore-scale observations demonstrate that the oil phase initially remains in the corner of the oil-wet pores after contacting with the smart water solution. After twelve hours, the oil droplets were remobilized to the center of the pores due to wettability alteration and favorable interfacial energies. This transition in the fluid occupancy enables the oil phase to form high-connectivity flow channels and subsequently resulting in oil mobilization and extraction from the porous medium.

One of the key aspects in the development of heavy and extra heavy oil resources is the creation and application of effective development technologies. The heterogenic carbonate reservoir represented the permian-carboniferous deposit of the Usinskoe oil field in the capacity of a place for testing the technology for the extraction of super-viscous oil using carbon dioxide (CO2).The paper presents the results of PVT study and flooding experiments on cores and slim tubes (slim-tube method) performed under various thermobaric conditions corresponding to different zones of the permian-carboniferous deposit. The purpose of the research is to evaluate the effectiveness of the application of CO2 injection technology together with the heat carrier to increase oil recovery from a deep-seated heavy oil reservoir.As a result of the studies, it was found that the most effective condition of displacement of super-viscous heavy oil by carbon dioxide in the conditions of the permian-carboniferous deposit of the Usinskoe oil field is the immiscible displacement condition.The displacement of super-viscous heavy oil by carbon dioxide from a low-permeability porous matrix at low temperatures is ineffective without preliminary heating of the reservoir.It has been shown by the experiments that preliminary heating provides an increase in the efficiency of the displacement of super-viscous heavy oil by carbon dioxide – the oil recovery factor increases and the gas-oil ratio decreases.The results of flooding experiments show that there is an optimal ratio of the heat carrier and CO2 injection volume, which makes it possible to increase the efficiency of the thermal process and the reservoir development indicators.

In the past decades, oil companies have shown growing interest in increasing oil recovery efficiency. Commonly, after primary and secondary recovery phases, a large amount of oil remains trapped inside the reservoir. Thus, the number of studies focused on enhanced oil recovery is growing, aiming to increase the recovery factor. The focus of this work is to study the fundamentals of oil displacement in porous media using a confocal laser scanning microscope, which enables 3D visualization of dynamic phenomena with a good spacial and time resolution. The analysis was on oil displacement that results from the use of a suspension of gellan gum microcapsules in water injected after water injection. These microcapsules moving along with the water, blocked some of the preferential paths and forced the water to displace trapped oil ganglia. The result achieved was a collection of 3D images from artificial porous media, in which it was possible to distinguish the distribution of phases (microcapsules, oil, and aqueous phases) inside the porous media, before and after the microcapsules injection. These images showed that indeed the gellan gum microcapsules blocked preferential water paths and that, after the blockage, some oil ganglia were displaced from their original positions. This work applied modern techniques of microscopy to investigate the concept behind enhanced oil recovery using microcapsules.

This paper studied a new fracturing fluid based on a supramolecular complex between associative polymer and viscoelastic surfactant (VES). The combination of VES and associative polymer synergistically enhances the viscosity several times more than that of the individual components alone. The fluid system was optimized by experimental design. The microstructure of wormlike micelle and complex formation was verified by electron microscopy. The proppant transport test in a large-scale fracture simulator showed good proppant suspension ability. After fracturing, the nano- surfactant molecule in the liquid have a high surface energy, which can play a good oil displacement effect in the crack. The fluid has 50% lower formation damage than that of conventional guar. The fluid was prepared with less additives and formed gel instantly, which can be mixed on the fly in the field. The gel can be completely broken with almost no residue. By flooding and [1]nuclear magnetic resonance experiments results, compared to the conventional fracturing fluid and water, oil displacement efficiency can be increased by 12% to 20%, more micro-pores in the oil and gas drive for higher pressure stimulation effect for tight oil reservoir. Field application of the new fracturing fluid in 10 tight gas wells showed the enhancement of gas production over 100%. The fluid has 20% lower friction pressure than that of guar fluid. Hence, the new supramolecular fluid is an effective fracturing fluid. Supramolecular fracturing fluid provides a new fracturing system with less formation damage to fracturing operation. This paper will be beneficial to all engineers and technologists who are currently working at tight gas stimulation applications.

In view of tight oil reservoirs with no natural productivity (tight sandstone and carbonate reservoirs with matrix permeability under overburden pressure of no more than 0.2mD (pore permeability less than 2mD)), a nanometer high efficient oil washing agent has been developed by combining nano-drop, high efficient oil washing surfactant and wettability reversal means, which can turn the disadvantage of the small pores and throats into advantage and realize fracturing effect enhancement by making use of the spontaneous imbibition. For the tight oil reservoir, large scale and high pumping rate multi-stage fracturing in horizontal wells and fracture diversion technique are recommended to smash the reservoirto create a fracture network of natural fractures and artificial fractures for oil and gas flow. The aim is to increase reservoir stimulation volume and the artificial fracture area. Meanwhile, nanometer high efficient oil washing agent is added in the fracturing fluid. By changing rock wettability, the oil-wet interface is turned water-wet, and the capillary force is changed from imbibition resistance to imbibition drive, boosting spontaneous imbibition. Therefore, the biobased solvent and surfactant can work in synergy to separate the oil film from pore and throat surface, realizing displacement of oil by water. Experimental data shows the application the nanometer oil displacement agent can enhance the oil displacement efficiency of core by12%. After fracturing, the well should be shut down for some time. The shut-down time should take the reservoir pressure and temperature, pore structure and connectivity and the imbibition capacity of the fracturing fluid etc into account, and can be worked out by spontaneous imbibition experiment and NMR etc to guide field operation. This technology has been used 10 well times in tight oil reservoirs in western China, including 3 well times of key exploration well stimulation, and 7 well times of old well repeated fracturing, all the treatments have achieved good effect. Among them, one well worth special note, this well had no production before fracturing, but obtained a high production of 42t a day after fracturing. During the shutdown of well, the fracturing fluid in the artificial fracture network can contact fully with micro-pores in the matrix and displace the oil in them through imbibition to the fracture system, then the oil can flow along the fracture network to the well bottom. The high efficient imbibition fracturing technology for tight oil reservoir is a revolution in fracturing. With fracturing fluid system and well shutdown different from traditional fracturing, this technology can enhance fracturing effect and more importantly oil recovery. This paper has great guidance and reference significance for engineers and researchers engaged in tight oil development.

Amphiphilic polymers applied in oil production are usually polymer mixtures with wide distribution in molecular weight. To determine the performance of oil displacement of polymer with specific molecular weight, it is essential to employ precipitation method to separate polymer mixtures into two molecular categories, including high molecular weight category (HM component) and low molecular weight category (LM component). The separated categories are characterized by FTIR. The rheology properties of the separated categories are evaluated by static and dynamic rheology methods. The aggregation behavior and thickening mechanism of both molecular categories is analyzed by SEM intuitively. Emulsification performances are investigated by analyzing the kinetic stability and rheological rules. Finally, displacement efficiency of the two categories is achieved by core flooding. Experimental results of CT scanning for the displaced cores and microscopic model reveal the distribution of residual oil and the mechanism of oil displacement, respectively. The observed structural analysis indicates similar molecular structures for separated categories. However, the grafting density of the LM is higher than that of the HM. The viscosity of the LM drops more as compared to that of HM. In contrast, viscoelastic properties of LM are better than that of the HM in solutions. Emulsion particle size of HM increases at a certain degree while that of LM decreases. The stability of LM emulsion is stronger as compared to that of HM. LM is more conducive to the stability of the emulsion system owning to more hydrophobic group and better emulsion viscoelastic properties than the HM emulsion. Oil recovery efficiency of the LM reaches 54%, 5% higher than that of the HM, which indicates that the LM is more conducive to enhance oil recovery. Core flooding results suggest that the oil displacement mechanism of the HM is via mobility control, and eventually enhance the sweep efficiency; LM improves the ability of emulsifying crude oil, and thus enhance oil recovery; and synergistic effect after compounding of different molecular weight polymers showed the highest EOR effect. Current study is of great significance for the synthesis of amphiphilic polymer and oil field applications. A polymer system with proper molecular weight distribution and grafting density can effectively improve oil recovery for a polymer flooding.

Simultaneous three-phase flow of gas, oil and water is a common phenomenon in enhanced oil recovery techniques such as Water-Alternating-Gas (WAG) injection. Reliable reservoir simulations are required to predict the performance of these injections before field application. However, most commercial simulators are based on Darcy-type formulation requiring the concept of relative permeability. Generally, three-phase relative permeabilities are calculated from empirical correlations, which are based on two-phase relative permeability. However, heavy oil displacement by gas or water can lead to viscous fingering due to the unfavourable mobility ratio between heavy oil and the displacing fluid. In addition, the injection soluble gases such as CO2 can result in compositional effects. Estimation of three-phase relative permeability under such conditions are extremely complex and using conventional techniques for the estimation can lead to erroneous results. We used the result of three coreflood experiments carried out on a core to generate two-phase and three-phase relative permeability data using an improved history matching methodology that takes into account the instability and the compositional effects in the estimation processes. The results show that a simultaneous CO2 and Water injection (CO2-SWAG) can be adequately matched using a secondary gas/liquid and a tertiary oil/water relative permeabilities. This is because contrary to WAG in conventional oil recovery, where gas and water open up separate saturations paths, in this case, the water follows the gas saturation path due it's lower resistance as a result of the CO2 dissolving in the oil and reducing the oil viscosity. It is also important to include Pc even in high permeable porous media as we observed that the inclusion of capillary pressure dampened the propagation of the viscous fingers and hence helped the front to become stabilised leading to a better sweep efficiency.

Prediction of reservoir performance during water displacement process is a routine procedure for homogeneous reservoirs but complicated in heterogeneous reservoirs. The Stiles method has consequently been used over time in the industry for such reservoirs. This method, however, is evidently time consuming and tedious as the varying permeability values are reordered and lumped. This paper applies the Welge procedure to a stratified reservoir without reordering or lumping of permeability with the aim to ensure improved productivity by more proper planning, more efficient use of resources and determination of the economic viability of the project. This paper also seeks to formulate a procedure that can judiciously handle even larger sets of permeability values to produce more accurate result A fractional flow equation was derived for any number of layers to generate a single fractional flow curve (FFC). Injection inflow into a layer was determined using the layer capacities and this facilitated calculation of times to breakthrough and times to attain a particular saturation after breakthrough. A formula was then derived to determine the oil produced at any instant. A software was designed for the entire procedure to ensure faster and more accurate predictions. Results showed that heterogeneities had no effect on the microscopic displacement and thus the fractional flow curve remained unchanged whether the reservoir was heterogeneous or not. Heterogeneities affected only the total flow in the distinct layers and thus times to attain specified average water saturations. The results of oil recovery obtained were compared to those obtained using the Stiles method to demonstrate that this method is faster without loss of accuracy.

Enhanced oil recovery (EOR) process selection is an important part of field development strategy. One of the most important categories of EOR methods utilize certain chemical components that enhance the fluid properties. Polymer-enhanced waterfloods are one of the examples. During conventional waterfloods, the flow characteristics and displacement efficiency usually depends on a certain rock type in study. In a chemical EOR flood, there are a large number of parameters needed to be defined and optimized that impact process efficiency. The attempt to execute corefloods for various combinations of these parameters for each rock type would lead to a large number of tests not executable in a time frame compatible with timely decision making. And the destructive nature of the experimental chemical EOR floods prohibits repeated testing on the same core sample. The natural difference between the samples selected for the study can prevail over the process efficiency difference related to the certain design parameter in the study. Digital core analysis can help to optimize design of EOR floods and reduce the associated uncertainty. In this work we apply digital core analysis to investigate the dynamics of oil displacement, using water and water-based polymer solutions in porous media. The described technology application includes scanning of core samples using X-ray microtomography, creating digital models for the samples in study, and running pore-scale hydrodynamic modeling using the density functional hydrodynamics (DFH) method, which combines density functional theory with compositional multiphase hydrodynamics. The results include visual snapshots of phase distributions at pore scale for various times during the waterflooding and polymer solution flooding at various concentrations. Polymer-enhanced waterflooding increased the displacement coefficient by almost 2% and 20% for low- and high-concentrated polymer solutions, respectively. This effect was further explained by analyzing the dynamics of oil displacement on a pore scale. The results show an exemplary sensitivity study that investigates the dependency of the displacement coefficient on the polymer solution type and concentration. Additional sensitity studies with varying design parameters (slug size, injection sequence, polymer type, etc.) can be also performed.

There have been numerous laboratory tests conducted in recent years, studying the potential for heavy oil recovery through chemical addition (polymers and surfactants). In these tests, recovery is often understood in terms of pre-water breakthrough and post-water breakthrough improved oil recovery. Pre-breakthrough tests focus on viscous fingering and sweep efficiency from water vs. polymer additives. Post breakthrough tests study the potential for oil recovery after a waterflood has already been run: in these systems surfactants and polymers are added and there is conclusive evidence that chemical additives can be very effective at improving heavy oil recovery at the scale of these core flood systems.The observation made in laboratory core floods is that chemical recovery of oil is achieved under very high pressure gradients. The mechanism proposed in these tests is that chemicals plug water pathways and lead to improved sweep within the core. In reservoir applications of this technology, these same conditions may not be met and it is unclear whether these chemicals will still be as effective in non-linear systems. This study shows tests run in a 2D Hele-Shaw cell, which displaces oil with no pore scale trapping and with many open flow pathways like what is expected in the field. The objective of running tests in this system is to understand the mechanisms of heavy oil recovery and to observe whether chemical additives can still be successful for producing heavy oil in non-linear core systems with no capillary trapping.

The utilization of nanoparticles (NPs) as an agent for improved oil recovery (IOR) and enhanced oil recovery (EOR) has attracted a lot of attention over the past decade. NPs are known to have high mechanical and thermal stability and they can be tailored to meet the specifications of a given reservoir system. As a result, as opposed to polymers, NPs are suitable options for EOR processes as they are capable of withstanding high temperatures, pressures, shear and salinity in harsh environments often prevalent in subsurface oil reservoir systems. Researchers have made promising observations and results at laboratory scale, proving that nanoparticles possess the capacity and potential to reduce residual oil in the rock matrix thus increasing ultimate recovery. NPs have been observed to lower interfacial tension (IFT), reduce the viscosity of oil and alter wettability. This study presents an in-depth review of the oil displacement mechanisms that favour nanoparticle enhanced residual oil recovery. It goes on to review the causes and effects of NP retention in porous media. Processes carried out at laboratory scale and properly designed for reservoir fluids may fail when implemented at reservoir scale as a result of geological factors. Hence the review concludes by making recommendations for successful NP EOR projects.

Understanding the flow behavior of viscoelastic fluids in porous media is critical for optimizing enhanced oil recovery (EOR). Polymers such as hydroxypolyacrylamide (HPAM) are used to improve sweep efficiency in reservoirs and these polymers often exhibit elasticity. Surprisingly, recent experimental and field observations indicate that these viscoelastic polymers improve oil recovery up to an additional 20%, contrary to the conventional wisdom that polymers should have no impact on residual oil saturation. Here, we attaempt to understand effects of viscoelasticity on residual saturation in water-wet and mixed-wet porous media. Static and dynamic computational fluid dynamics (CFD) simulations of oil droplets in the presence of viscoelastic polymer are conducted in geometries representative of pore throats. Results show that additional forces on the oil droplet are present for fluids that exhibit elasticity over those that do not (e.g. water) and those forces become larger as the oil droplet approaches a constriction. It is also shown using dynamic simulations that the amount of deformation of the oil droplet is greatly affected by the elasticity of the displacing fluid. These results are promising and provide a theoretical foundation for the laboratory and field observations of reduced residual oil.

"Simultaneous water and gas" (SWAG) injection is the effective method of enhanced oil recovery. However, until recently the effect of SWAG in the development of heavy oil fields has been studied insufficiently. In the present study laboratory researches have confirmed that SWAG injection when 25% gas content in the mixture significantly increases the displacement efficiency of heavy oil with the viscosity 217 mPa*s of Russkoye deposit, compared with water flooding. It has allowed extending the effective application of SWAG as a non-thermal method of enhanced oil recovery more than twice. According to the results of laboratory experiments to pre-extracted and not extracted core material, it was found that the degree of hydrophobic pore surface, which depends on the adsorption of polar components of oil, significantly affect the oil displacement efficiency when SWAG implementing. It was established that SWAG at the optimum gas content is effective for both hydrophilic and hydrophobic environments. The values of the heavy oil displacement efficiency for the hydrophilic core material of Russkoye field are about 1.8 times higher than for hydrophobic. The technology for SWAG injection from the use of mono-block multistage pump-ejecting systems has been developed. The technology can significantly improve the systems efficiency and the process of water-gas mixtures delivering into injection wells. The obtained results allow creating non-thermal energy-efficient methods for developing and improving oil recovery of heavy oil fields.

Commercial polymer floods have generally used partially hydrolyzed Polyacrylamide (HPAM) as the polymer of choice, since HPAM generates high viscosities in relatively fresh brines at a reasonable cost. In high salinity or hardness brines, the anionic charges on the HPAM polymer chain interact with the dissolved cations, shrinking the hydrodynamic size of the polymer molecules. The smaller hydrodynamic radius generates lower viscosities and requires higher polymer concentrations. In order to reduce the polymer loading in saline brines, a series of hydrophobically modified biopolymers have been synthesized. The non-ionic nature of hydroxyethyl cellulose (HEC) provides an ideal polymer back bone since it does not interact with the dissolve cations. Hydrophobic groups (aliphatic hydrocarbon chains) are attached to the backbone of the polymer to impart associating properties between polymer molecules. The inter-molecular interaction between the hydrophobic moieties led to a significant viscosity increase in comparison to polymers without hydrophobic groups. Several screening steps were used throughout the product development to arrive at practical polymer formulations: 1) Filtration; 2) Sandpack tests; 3) Corefloods in the presence of oil. By varying molecular weight of the base HEC polymer and the amount of hydrophobic content, practical polymer products were developed for polymer flood applications. Coreflood tests showed that the hydrophobically modified HEC generated significant resistance factor in saline brines, outperforming the HPAM polymers.

Aiming at the low viscosity of polymer solution, which is compounded with fresh water but diluted with produced water, and at the problems concerning oil displacement efficiency, an onsite test on polymer solution with viscosity stabilizer (PSVS) is carried out. As a result, it has great and guiding significance to the application and popularization of viscosity stabilizer by studying the performance of polymer solution with viscosity stabilizer and its influence on oil displacement efficiency. In this paper, aiming at two different kinds of polymer solutions among which one is compounded with fresh water but diluted with fresh produced water and the other with aerated produced water, two laboratory evaluative tests concerning viscosity stabilization, anti-shear stability, fluidity, and absorbability of polymer solution as well as its oil displacement efficiency are done. The results of onsite application of PSVS are traced and analyzed. The viscosity stabilization of the polymer solution adding with viscosity stabilizer becomes much better than that of the normal polymer solution. The resistance and the residual resistance factors, the static oil sand adsorption rate and the dynamic core adsorption rate of the solution are all increased markedly. The working viscosity and oil displacement efficiency are improved markedly as well. In comparison with the polymer solution diluted with fresh produced water, the polymer solution diluted with aerated produced water is much better in terms of viscosity stabilization. Comparing with the normal polymer solution with viscosity stabilizer before sheared, the polymer solution which is sheared before adding with viscosity stabilizer performs obviously better in terms of viscosity stability. In contrast to the adjacent block injected with normal polymer solution, the block under onsite flooding test with injection of PSVS features that the average injection pressure increases slightly but keeps steady, the recovery speed of the average monthly water cut of production wells slows down, the thickness of the absorptive layers increases, and the periodic recovery rate improves as well.

The Colloidal Dispersion Gel (CDG) technology, sharing multiple similarities with polymer flooding, is developed(1) for in-depth profile modification. However, due to the differences in chemical type and concentration, molecular structure and mechanisms, the displacement processes between CDG and polymer are different. The injection capacity of the two processes are about the same, but polymer flooding features large injection increase amplitude, quick pressure increase in initial period and quick decrease for subsequent flooding pressure; while CDG injection features a slower and gradual increase and decrease. The oil recovery effect for polymer flooding is mainly realized during the process of polymer injection, featuring quick water cut decrease and fairly quick increase as well quick water cut increase for subsequent water flooding; the oil displacement effect of CDG is equivalent of that for polymer flooding during chemical injection, but performs much better than polymer during subsequent water flooding. During the initial stage of the CDG injection, the water cut shows multiple stages of decline and then shows a slow increase during the water drive. In addition, water cuts in producers were stabilized for a long period of time. The production cycle for polymer flooding in a pattern with 250 meters distance between injection and production wells is usually about 6 years, while the CDG process lasted over 10 years. Under similar geological conditions, the chemical injection amount for CDG profile modification is 20% less than that of the polymer flooding but the increased oil recovery is about4% over the polymer flooding at the economic limit.

Application of gas as oil displacement agent is constrained not only due to the paucity of gas resources, but due to high cost of site buildup, adverse effect of gas breakthrough on producing well behavior, and as consequence, relatively poor efficiency of the process.

The differences between naturally fractured reservoir and vuggy fractured reservoir are apparent in the aspect of oil displacement by water. In fractured reservoir, the oil displacement by water is the governing recovery mechanism known as capillary imbibition, which allows the recovery of matrix oil that cannot be reached by the externally applied pressure gradients of waterflooding. The main difficulty is the problem of choosing the well pattern. While oil displacements in the vuggy fractured reservoir are dependent on the single well huff-and-puff because of its higher permeability and the nonexistence of the coning, thus its displacement is to inject water by production well, and the mechanism is to complement formation energy and replace rather light oil with water by gravity segregation. In this paper, the displacement models of naturally fractured reservoir, which are based on streamline numerical simulation method, are developed and discussed on the well pattern, well type, recovery rate, injection rate, injection cycle, etc. The result shows that design of well pattern plays a dominating role in the waterflooding, followed by the optimization of injection rate. While for the vuggy fractured reservoir, injection cyclic deserves prior consideration. The other factors such as critical recovery rate, critical injection rate, injection opportunity, aquifer, etc. are also taken into account in the study, which make the development scenario of vuggy fractured reservoirs more reasonable and economic. In the end, an example of comparison between Fuyu oilfield(naturally fractured reservoir) and Tarim oilfield (vuggy fractured reservoir) is presented to illustrate the differences of the displacement, and scenarios suited for the reservoir are put into implementation. The study provides an important technical support for similar reservoirs development, especially when confronted with the problem of oil displacement at the secondary recovery stage.

Most of oil fields are developed on waterflooding. In some regions there are many fields with strong water drive. In both cases oil production is accompanied by water production. From economical point of view income is proportional to oil production but operating expenses are proportional to liquid production. So, excessive water production can decrease profitability of a project. In some economical software there is a dependency of watercut upon oil displacement. But in reality foregoing dependencies are drastically different from field to field. This paper is devoted to finding regularities and confirmation them by means of analytical and numerical calculations. Several influencing parameters are considered – such as relative permeabilities, fluid viscosities, fluid densities, heterogeneity and permeability profile, permeability anisotropy, layer slope, fractures, aqufer size and activity, well distance and patterns, position of perforation intervals, pressure drawdown, maximum allowed watercut. Those factors could be divided into two global groups – geological and technological. Ultimate fraction of mobile oil displaced (volume sweep efficiency) depends on many factors. That is why field ultimate recovery factor is always less then laboratory displacement factor. But even laboratory waterflooding experiments show wide range of watercut vs. sweep dependencies for core samples from the same field. For the same maximum watercut (e.g. 98%) we can get from 0.6 to 0.9 sweep. The quantity of water produced per unit of produced oil depends both on geology and technology. It's impossible to change geological environment but we can chose a proper method to develop any field. Field examples and practical recommendations are presented in the paper.

Excessively large amplitude excitations resulting from earthquakes, explosions, or mechanically vibrated systems are found to generate macroscopic and microscopic mechanisms that have beneficial effects on the production of wellbores. A downhole harmonic vibration oil-displacement system (DHVOS) that generates a sudden large amplitude excitation to the liquid in the wellbore was developed by researchers at CNPC (China National Petroleum Company). Compared with other downhole artificial vibration systems, the DHVOS system is a heavy-duty unit that can provide long period operations and large amplitude excitations. This system has been implemented in CNPC's oil fields such as Liaohe, Huabei, Shengli and Zhongyuan. The DHVOS system provides a harmonic vibration frequency of 88 shocks per minute with each shock having 5-ton strength. More than 100 oil-producing wells have been stimulated with the downhole vibration system since 1997. The field results demonstrated that periodic application of large amplitude excitation to oil reservoirs led to increased oil production rates and decreased produced fluid water content. The observed oil production-rate increments ranged from 27.5% to over 400% with an average increment of 47.6% compared to the pre-vibration production rates. The reduction in water oil ratio (WOR) varied 10% to 75% with an average of 48.4% in WOR reduction.

Aimed for the need of oil displacement in high salinity formations where the normal nonionic and anionic surfactants are inefficient because of salting out or cloud point phenomena[1], A novel structure surfactant(LF) with nonionic and anionic hydrophilic group is put forward and synthesized. The said surfactant is soluble in 30% NaCl brine, and shows good surface activity in brine with 100,000mg/L salinity concluding 5,000mg/L CaCl2. By analysizing the volume fraction-salt concentration phase graph, the salt tolerance property of LF, petroleum sulfonate and their combined system is comparatively studied , LF is excellent, the proportional increment of LF in combined system will improves salt tolerance property of the combined system. In any different brine , water/n-decane Interfacial tension is high if only LF or petroleum sulfonate is used, but Interfacial tension will reach super low if the combined system is appropriately used as long as water salinity is enough high(higher than 20,000mg/L). By adjusting the proportion of LF and petroleum sulfonate in combined system, water/oil Interfacial tension can always reach super low regardless of water salinity, so the system can be particularly used as oil displacement agent in high salinity formations. The paper presents three oil displacement and one chemical tuff and puff formulations consisted of LF and KPS, which were suitable for high salinity formations in Zhongyuan oil field. The temperatures of four test zone are 86.9°C, 65.0°C, 82.5°C and 82.5°C, the salinities are 88,540 mg/L, 55,028 mg/L, 14,9127mg/L and 195,000 mg/L, the room recovery improvement all exceed 19%. Now the four field tests get along favorably, verifying good result and indicating bright application prospect.

In this paper, the visco-elastic characteristics of polyacrylamide solution have been studied experimentally. The mechanisms of the effect of polymer solution with visco-elastic characteristic on each type of residual oil after water flooding are analyzed and the mechanisms of polymer solution with visco-elastic characteristic increasing microscopic oil displacement efficiency are studied. By the analysis of microscopic experiments of percolating flow, corresponding relationships between the characteristic parameter describing the visco-elastic behavior of polymer solution and displacement efficiency of residual oil in "dead ends" are given. It is shown that the larger the visco-elastic behavior of polymer solution, the higher the displacement efficiency of residual oil in "dead ends". A phenomenon that is not seen during water flooding is observed during polyacrylamide solution flooding in the microscopic experiment of percolating flow, that is, residual oil can be pulled into "oil threads" by the polyacrylamide solution. So a new type of oil flow channel, i.e. "oil thread" channel, can be formed and residual oil flows downstream through the "oil thread" channel. The probability of forming a steady "oil thread" flow channel in polymer flooding is also analyzed theoretically and proved. The research indicates that the mechanism of polymer solution microscopically increasing oil recovery is due to the visco-elastic characteristic of the polymer solution, the sweeping force acting on the residual oil for the visco-elastic polymer solution is larger than that of water. The residual oil is not pushed out by the polymer solution but pulled out by the polymer solution. It is also found that every type of residual oil after water flooding can be decreased by visco-elastic polymer solution, and the larger the visco-elastic property, the stronger the capability of the polymer solution to "sweep out" the residual oil. In brief, the results indicate that polymer flooding can not only macroscopically increase the sweep efficiency but also microscopically increase the oil displacement efficiency and a new type of flow channel, "oil thread", can also be formed.Besides new understanding on the mechanism of the flow of fluid through porous media and the displacement of residual oil, the above results should be beneficial to designing new EOR methods to further increase the recovery of oil fields.

Aimed for the need of oil displacement in high salinity formations where the normal nonionic and anionic surfactants are inefficient because of salting out or cloud point phenomena[1], A novel structure surfactant(LF) with nonionic and anionic hydrophilic group is put forward and synthesized. The said surfactant is soluble in 30% NaCl brine, and shows good surface activity in brine with 100,000mg/L salinity concluding 5,000mg/L CaCl2. By analysizing the volume fraction-salt concentration phase graph, the salt tolerance property of LF, petroleum sulfonate and their combined system is comparatively studied, LF is excellent, the proportional increment of LF in combined system will improves salt tolerance property of the combined system. In any different brine, water/n-decane Interfacial tension is high if only LF or petroleum sulfonate is used, but Interfacial tension will reach super low if the combined system is appropriately used as long as water salinity is enough high(higher than 20,000mg/L). By adjusting the proportion of LF and petroleum sulfonate in combined system, water/oil Interfacial tension can always reach super low regardless of water salinity, so the system can be particularly used as oil displacement agent in high salinity formations. The paper presents three oil displacement and one chemical tuff and puff formulations consisted of LF and KPS, which were suitable for high salinity formations in Zhongyuan oil field. The temperatures of four test zone are 86.9°C, 65.0°C, 82.5°C and 82.5°C, the salinities are 88,540 mg/L, 55,028 mg/L, 14,9127mg/L and 195,000 mg/L, the room recovery improvement all exceed 19%. Now the four field tests get along favorably, verifying good result and indicating bright application prospect.

In this paper experimental results obtained for the oil displacement by water within a two-dimensional vuggy fractured porous cell are presented. The experiments were carried out with an acrylic cell, where fractures were represented by channels of 1.6 mm wide, 1.2 mm deep and 19 cm long, whereas the vugs were represented by cylinders of 1 cm diameter and 1.2 mm deep. The experimental procedure is as follows: the cell, saturated 100% with oil was placed horizontally and at time t=0 water was injected at a constant rate. Photographs were taken to follow the water front in the cell; then, the area corresponding to oil and water was measured. In this way the water saturation in the cell was determined. This water saturation is equal to the oil recovery, considering oil and water as incompressible fluids. Based on the experimental results, a theoretical model was developed. This model considers that the porous space is constituted by two regions: one that can conduct fluids, called flow region and a stagnant region that interchange matter with the flow region through a diffusion-like process. Analytical solutions for water saturation and normalized oil recovery are presented. The model fitted in a reasonable way the experimental data of normalized oil recovery, indicating that the theoretical model can be a useful tool to explain oil recovery processes in vuggy fractured reservoirs.

Abstract The heavy oil reservoirs in Henan oilfield are mainly thin-bedded viscous and unconsolidated with viscous oil. Many of which are suitable for cold production. Lab experiments show that high permeability channels can be created in the reservoir when a large amount of sand is produced, and that the oil displacement efficiency is significantly improved in presence of dissolved gas. Field pilot shows that the fluid is produced in a foamy oil form with sand-cut of 2-20% (in volume) and oil production of 16-30t/d, which is over 10 and 5 times as much as that of conventional recovery and cyclic steam stimulation in the same reservoir respectively. P. 119

Steam displacement of oil in a slimtube under non-condensing isothermal conditions affords the opportunity to investigate two thermal mechanisms in relative isolation: steam oil displacement and steam distillation of oil in the dynamic situation. The added ability to investigate the composition of the produced oil under high resolution, allows estimation of a production allocation by mechanism. This work gives insights into strategies to accelerate the growth of the steamchest and enhanced compositional effects for improved steamflood performance. The effects of temperature on oil and steam were determined in a sixty foot slimtube using Minas oil, a 33°API waxy oil from Indonesia, under isothermal conditions in the temperature range 300–600°F (149–315°C). Significant compositional changes in the hydrocarbon distribution of the produced oil allowed estimates that 16% of the oil is produced by vaporization alone in a light oil steamflood at 400°F (204°C). Higher temperatures increase the percentage for better vaporization and displacement recoveries. Steam can vaporize hydrocarbon components to at least C24 at 400°F (204°C) and much higher carbon numbers at higher temperatures. After steam breakthrough, vaporization becomes a major recovery mechanism in a steamflood. The vaporized hydrocarbons are normally seen as condensate in the field. The steam vaporization process, like the carbon dioxide vaporization, removes the lightest hydrocarbons first and in boiling point order. The long slimtube acts like a gas chromatograph column and allows the separation of the hydrocarbons to be observed once vaporization begins. This is not normally seen in the field because the condensate commingles with the oil as it travels through the reservoir to the producing well. Therefore, a light oil having many light hydrocarbon components would produce a lot of condensate and a heavy oil could produce considerably less. The implications of compositional changes will be discussed.

Abstract The analytical description of oil displacement by water in porous media is a complex problem of interest in secondary oil recovery by waterflooding. Due to its complexity, most of the studies in this area are restricted to one-dimensional cases. In this paper, the radial two-dimensional case is treated. For the experimental work, a transparent porous cell built with two ground circular glass plates was used. This cell has the advantage of allowing direct visualization of the movement of fluids. Based on the experimental results, a theoretical model was developed to explain the radial displacement of oil by water in a porous medium. The theory considers that:water tends to follow preferential paths where the motion is essentially longitudinal and of the convective type;at the same time, there is a lateral motion of dispersive type which tends to widen the preferential paths. Introduction Oil displacement by water within porous media is a very complex process that has been studied by reservoir engineers for more than fifty years. The complexity of the process is due to the simultaneous action of several factors, primarily viscous forces, capillary forces and pore volume geometry. For describing this process, some simple theoretical models have been proposed. Frequently, these models do not represent in a reasonable way the reservoir behavior. Recently, immiscible displacement of oil by water within a porous medium has had a renewed interest at some research centers. For the study of this flow problem, besides conventional techniques, some non-conventional such as X- and gamma-ray tomography and nuclear magnetic resonance have been used. Because of its transparency, that allows direct visualization of fluid movement, the use of two-dimensional transparent cells has been of particular interest. The purpose of this paper is to describe a new two-dimensional transparent porous cell, which has proved to be a versatile research tool. Based upon experimental results obtained with this cell, a theoretical model that explains in a reasonable way the mechanics of oil displacement by water through porous media is proposed. Experimental Work Experimental work was carried out with a two-dimensional porous cell. This cell is constructed with two glass plates. One of the faces of each plate is roughened by using an appropriate abrasive. Upon placing one roughened surface against the other, we obtain a two-dimensional porous medium whose matrix has a random distribution of pores. Fig. 1 shows the components of a circular cell, with an inlet port at the center of the cell. The operation of the cell is as follows: when the porous space is occupied by air, the cell is translucent, but when it is saturated with oil it becomes transparent, because the refraction indices of the glass and of the oil used in the experiments are similar. However, when water is injected to displace oil, the invaded area becomes translucent because water has a refraction index smaller than that of glass. In this way, the water front can be followed in detail. The experiments of this paper were carried out with circular, square and hexagonal cells. The circular cell has 20 cm (7.9 in) in diameter. The glass plates, 0.6 cm (0.24 in) thick, were treated with an abrasive that yielded 0.01 cm (0.0049 in) pores. The inlet port consists of a stainless steel tube of 0.05cm (0.020 in) of interior diameter. To carry out the displacements runs, the cell was saturated completely with heavy oil of 100 cp (0.1 Pa.s) viscosity; then it was placed on the arrangement shown on Fig. 2. Afterwards, water was injected at the center of the cell, at a constant rate of 0.23 cm3/min (0.014 in3/min). Fingering effects appeared immediately. P. 115

Abstract The dependence of the capillary pressure on the flow rate, for two-phase flow in porous media, has been theoretically and experimentally investigated. A theoretical dynamic expression for the capillary pressure has been derived which involves a dynamic term which is proportional to the time derivative of the saturation. A series of waterfloods have been performed at different flow rates. While flowing the cores, capillary pressure and saturations have been locally measured. Capillary pressure has been found to depend on the flow rate as theoretically predicted: it increases with the flow rate and its derivative with respect to saturation mostly decreases when the flow rate is increased. The dynamic term is interpreted as the contribution of the viscous forces to the pressure drops. A strong impact of this dynamic expression on two-phase flow modelling and calculation of relative permeabilities has been found. Introduction The standard framework used to model two-phase flow in porous media relies on the notion of relative permeabilities and capillary pressure. Relative permeabilities reflect the viscous effects, while capillary pressure incorporates the capillary effects. These flow parameters are assumed to depend only on saturation. Relative permeabilities have been introduced to generalize the Darcy law. These flow parameters express the fact that one phase reduces the flow paths accessible to the other phase. The apparent permeability to this second phase is thus lowered due to the presence of the first phase. Therefore, relative permeabilities are known to be less than unity and dependent on saturation. The notion of capillary pressure originates from the generalization of the Laplace law. When an oil/water meniscus separates two phases, oil and water, and is positionned in a capillary tube of radius R, the difference in pressures, Pc, across the meniscus, i.e. the capillary pressure, will be proportional to the meniscus curvature C: Pc = C. This curvature is known to be equal to 2cos /R, where is the contact angle between the meniscus and the solid surface. The coefficient of proportionality is the interfacial tension. Assuming that a non-wetting phase displaces a wetting phase and that a porous medium can be seen as a set of capillary tubes, for a given capillary pressure level, the menisci will be located at the entry of capillary tubes with a radius equal to 2y cos / Pc. The set of accessible tubes is related thus to a given saturation. This is why the capillary pressure Pc is assumed to be a function of saturation. This function is then used to interpret two-phase flow in porous media though the Laplace law is valid only under static conditions. P. 491^

Abstract The effect of fracture length, orientation and conductivity on waterflooding performance in repeated fractured well patterns is considered. It's found that for fixed well spacing density there is an optimum fracture length which provides maximum of oil recovery at a fixed time of production, be cause of oil recovery at breakthrough changes for the worse with the increase of fracture length. For the developed oil field, aggravation may be connected with unfavorable orientation of fractures in well pattern. If orientation of fractures is in accordance with well pattern, with fixed well spacing density the aggravation due to increasing fracture length can be connected with the finite fracture conductivity. The cleanup of fracture and zone invaded by the viscous fracturing fluid, when putting the well into production, is investigated. The increase in fracture length is shown to leads to slowing-down fracture cleanup and invaded zone washout and as a result to extreme relationship between well productivity factor and fracture length. productivity factor and fracture length. Fully implicit numerical simulator based on the method of lines, was developed for solving multi-phase flow problems. The main advantage of this method is in the efficient simulation of transient processes with great difference in time or space scales. Introduction To understand the effect of sandfilled fracture length, fracture orientation and its conductivity on the flow of two immiscible fluids is important to enhance waterflooding performance in well patterns with long hydrofractures. From the solution of Prats for steady flow in finite conductivity sandfilled fracture with an elliptical outer boundary it follows that:well productivity doesn't increase when fracture length is greater than some limit length;the effective wellbore radius of an infinite conductivity fracture is given by one quarter of fracture length. The analytical solution for unit mobility displacements between wells with infinite conductivity fractures established that the effective wellbore radius method was unable to predict the change in the areal sweep versus fracture length. The flow rate predicted by this method, is in agreement with an exact solution up to dimensionless fracture length of 0.3. The transient response of fractured well in a single layer system. for single-phase flow was also presented in literature. As noted by Lacy, a very long fracture, oriented along the line connecting producing and injecting wells, leads to significant shortfall in areal sweep efficiency at breakthrough. The invasion of treatment fluid through fracture surfaces in porous media during fracturing stimulation, as well as finite proppant conductivity may influence well productivity. The point is that, viscous fracturing fluid used for treatment damages proppant-pack and invaded zone permeability. In spite of the fact that treatment fluids are degraded - though rarely completely - either by the temperature of the reservoir or by breakers, it would be interesting to analyze hydrodynamics of invaded zone washout and fracture cleanup. The consequences of fracture and porous media permeability damage caused by the fracturing fluid should be taken into account when designing fracture treatments. P. 481

Abstract Waterflood simulations in two-dimensional cross-sections are used to investigate the effects of fine-scale relative permeabilities and permeability heterogeneity on displacement permeabilities and permeability heterogeneity on displacement performance. Heterogeneity is found to be most significant performance. Heterogeneity is found to be most significant when deviations from the mean are highly correlated in the direction of flow, i.e., a layered reservoir. As spatial correlation decreases, the production behavior approaches that of a homogeneous medium. The critical features of the fine-scale relative permeabilities are the end-point relative permeability to water at residual oil saturation and the approach of the oil relative permeability curve to residual oil saturation. Relative permeability variations are found to be less important, but not necessarily negligible, when permeability heterogeneity is large and highly correlated in the displacement direction. Under most circumstances, the minimum relative permeability data required to avoid gross errors in simulation predictions are the end-point effective permeabilities to predictions are the end-point effective permeabilities to each phase and the fractional flow curve approaching residual oil saturation. Waterflood simulations using exact relative permeability data are compared with simulations where permeability data are compared with simulations where complete relative permeability information is not available. Cases are considered where relative permeabilities are estimated by straight lines between known end points and relative permeabilities derived from end point measurements and fractional flow data for high water cuts. An approximate method is proposed to derive relative permeability information from limited production history data. permeability information from limited production history data. The importance of production behavior at low fractional flow of oil also suggests the use of centrifuge measurements to help define the oil relative permeability curve approaching residual oil saturation. Introduction Reservoir simulation is currently limited by the number of grid blocks that can be used for practical simulation calculations. Grid block dimensions of hundreds of feet areally and tens of feet vertically are often required to describe an entire reservoir or even a portion of a reservoir. Individual grid blocks are assigned uniform properties for porosity, permeability, relative permeability and other properties. permeability, relative permeability and other properties. Frequently, however, rock properties are not uniform within a grid block. Properties assigned to grid blocks that differ from values Properties assigned to grid blocks that differ from values measured on smaller core samples are referred to as effective properties. Effective properties are usually necessary when phase distributions or rock properties or both are nonuniform within a grid block. Several investigators have proposed methods to determine effective rock properties that incorporate effects of sub-grid scale properties that incorporate effects of sub-grid scale heterogenity on single-phase flow. However, there are no general, theoretical methods available to evaluate effective multiphase flow properties for grid blocks containing permeability heterogeneity. permeability heterogeneity. P. 25

Summary Oil displacement experiments are reported which were performed in stratified rectilinear systems consisting of two lower permeability sandstone slabs, enclosing a central high permeability layer made of unconsolidated glass ballotini. The adjacent layers were in good flow communication, except for a very small region close to the outlet. This arrangement allows the crossflow mechanisms that occur when the viscosity of the displacing brine is increased by adding a water soluble polymer. These mechanisms cannot be assessed by performing experiments in one-dimensional cores or packs. Results of oil displacement experiments are presented for different mobility driving fluids, in which glycerol is used to viscosify the aqueous phase. carbon-I 4 and chlorine are used as radioactive tracers in the experiments. The effluent fluids from each layer were collected and analysed to produce data on the cumulative oil recovery, watercuts, flow rates in each layer, viscosities and concentrations of radioactive tracers. The results of these oil displacement experiments were modelled using computer simulation, and a very good match to the experiments was obtained. This simulation work confirms the flow mechanisms involved when water soluble polymers are used to increase the oil production from stratified reservoirs. Introduction In stratified reservoirs with high permeability contrasts between layers, early water breakthrough can occur during a waterflood, causing low vertical sweep efficiencies. The use of water soluble polymers to increase the water viscosity has been shown to be an effective way of improving the sweep efficiency and hence increasing the oil recovery. Earlier theoretical work has shown that the mechanism of increasing the recovery of oil in this way involves the crossflow of fluids between the various layers, as well as increasing the velocities in the lower permeability layers adjacent to the high viscosity polymer solution). A large number of papers have been published which investigate oil displacement using polymer solution in one-dimensional cores. Some experiments have also been performed in two-dimensional systems, but most of these used multiple radial or linear cores in parallel, with no contact between the cores except at the inlet. In the early literature, waterflooding experiments in communicating layered systems were reported, generally from the viewpoint of investigating scaling laws, or recovery mechanisms. More recently, polymer displacement experiments have been performed in stratified systems, with crossflow between layers. Whilst these have provided valuable information on the displacement processes, they have not provided sufficient data to allow a theoretical analysis of the flow mechanisms. In our laboratory, we are performing experiments which provide detailed information on the oil recovery, watercuts, flow rates and tracer concentrations produced from individual layers. The results of these experiments are being analysed using numerical simulation, in order to reproduce the flow mechanisms quantitatively. Earlier work performed at Winfrith used a heterogeneous core made from a sandstone cylinder with the centre removed and replaced with a pack of glass ballotini. This work has recently been extended using a rectilinear core assembly, and the results of these later studies are discussed in this paper. P. 823^

Abstract Multi-component micellar fluids containing broad equivalent weight surfactants, such as vacuum gas oil (VGO) and polybutene sulfonates, are being considered for commercial applications of micellar flooding. These surfactants are attractive for such applications because they are considerably less expensive than the more pure sulfonates. A phase behavior study of micellar fluids containing VGO sulfonate as a function of salinity, hardness, brine dilution, temperature, cosurfactant type, and surfactant-cosurfactant ratio was used to define the region within which stable micellar fluids can be formulated. The phase behavior study demonstrates that for micellar formulations within the stable region that contain 10 wt. % surfactant, the addition of an equal volume of oil (decane) normally produces Type I microemulsions (Winsor's notation). More dilute micellar fluids (1 wt. % surfactant) show Type III behavior. Effluent analyses from corefloods show that VGO sulfonate remains almost exclusively in the water phase (although a small amount of Type III microemulsion was observed in some of the effluent). This suggests that the recovery mechanism for the VGO sulfonates is donlinated by the Type I lobe of a Type III phase envirorunent. Phase behavior tests of polybutene sulfonates show that in the presence of calcium the sulfonate partitions into the oil phase forming microemulsions partitions into the oil phase forming microemulsions in a Type II lobe of a Type III phase environment. During displacement tests in the presence of calcium, polybutene sulfonates partition into the oil phase generating such microemulsions in situ. phase generating such microemulsions in situ. The use of a Type II to Type I phase transition in moving partitioned sulfonates was investigated. Type II microemulsions generated external to the core were injected to displace the in-place oil. These were followed by a fluid designed to produce a phase transition from Type II to Type I. The phase transition from Type II to Type I. The Type II microemulsion miscibly displaced the inplace oil. The phase transition microemulsion flood displaced oil more efficiently at higher salinity and hardness levels than has been obtained using conventional micellar fluid formulations of VGO and polybutene sulfonates. polybutene sulfonates Introduction Phase Behavior of Surfactant-Brine-Oil Systems Phase Behavior of Surfactant-Brine-Oil Systems The phase behavior of surfactants in hydrocarbon-brine systems has been the subject of interest in the literature for more than a quarter of a century. As seen in Figure 1, a surfactant brine-oil system can equilibrate as single, two-or multiple-phase, depending on the overall system composition. At higher surfactant concentration, all phase environments are single-phase. At lower surfactant concentrations in a Winsor Type I system two equilibrium phases are present. (To simplify this presentation the original phase behavior notation introduced by Winsor is used throughout.) The equilibrium tie lines in the two-phase region indicate one of the phases is essentially oil and the other phase is a microemulsion containing surfactant, brine, and oil. Because the compositions of the two equilibrium phases which result from all mixtures on a tie line are the same, the tie lines are also lines of constant interfacial tension. Type I microemulsions displace oil by a capillary number controlled process and a slug of Type I fluid is miscibly displaced by the polymer mobility (brine) with which it is soluble. Pope and Nelson predicted and observed the following characteristics of oil displacement by Type I microemulsions:Only one type of phase relationship can exist in the transition zone, essentially pure oil inequilibrium with brine-rich microemulsion.The volume fractions of oil-rich phase will decrease rapidly in the transition zone. P. 547

Abstract The aim of-this laboratory work was a detailed study of oil recovery ability of aqueous surfactant solutions. The first part included determination of relevant physical chemical properties of additive solutions, physical chemical properties of additive solutions, i.e. interfacial and rheological properties, phase diagram exploration as well as an evaluation of the specific adsorption-retention properties of surfactant polymer solutions in porous media used for oil polymer solutions in porous media used for oil recovery tests. In the second part, the results of the series of oil displacements were analysed - to give a precise description of the main features of displacements by aqueous surfactant solutions, - to assess their oil recovery efficiency, shown to depend on surfactant concentration in slug injected, consecutive or simultaneous injection mode of polymer and surfactant and additive retention properties in the porous media chosen, - to compare the oil recovery performances of surfactant solutions and microemulsions taken from the same Winsor III type diagram. Finally, application of a Buckley-Leverett type approach was considered to aid in the interpretation of the successive displacement steps observed during flooding by surfactant solutions at low or moderate concentrations. Introduction Oil recovery processes by means of surfactant micellar solutions or microemulsions include the injection of slugs of varied compositions. For instance, the concentrations of additives (sulfonates and alcohols) used in pilot tests were respectively 2.7, 5.5, 8 and 13.4 weight % on Benton, Big Muddy, North Burbank and Wilmington Fields. Also injected surfactant formulations can contain crude or refined oil (as in the case of recent pilots of Wilmington or Bell Creek Field). Despite a lot of published work dealing with micellar processes, one of the published work dealing with micellar processes, one of the still pending questions concerns the definition of pertinent criteria for selection of the optimal pertinent criteria for selection of the optimal composition and type of micellar solution for a given field. The aim of this laboratory work was a precise assessment of the features, performances and limitations of aqueous surfactant solutions which were studied in the concentration range from 0.2 to 10 weight % of additives. Such solutions can yield, even at low concentrations, to partial oil miscibility, depending on the specific characteristics of the corresponding phase diagram involving all the components present within the swept pore space. The initial compositions of sulfonate solutions, then, are represented along the water-additive side of phase diagrams; they can thus be considered as limit cases of so-called water-rich microemulsions. The following study was divided in two parts - extensive determination of the physical chemical properties of micellar solutions, involved in oil properties of micellar solutions, involved in oil displacement mechanisms inside porous media, - analysis and interpretation of oil displacements by means of aqueous surfactant solutions. DETERMINATION OF PHYSICAL-CHEMICAL PROPERTIES OF SYSTEMS Interfacial properties and phase diagram : Aqueous surfactant solutions, used in subsequent oil recovery experiments, were prepared with two distinct petroleum sulfonates, Petrostep 420 (60 % active material-cosurfactant hexanol) and TRS 10-80 (average M.W. 420 - 73 % a.m.-co-surfactant t-C5 alcohol), dissolved in a brine of constant salinity: 15 g/l sodium chloride. 5 % Petrostep solutions (exact composition given in Table III) in contact with Petrol D (an odorless oil-cut marketed by Esso-Chimie), give two phase systems with interfacial tensions of about 2.10-3 mN/m.

SPE Members Abstract Displacement tests on reservoir core samples provide a direct method for assessing the provide a direct method for assessing the microscopic displacement efficiency of specific recovery processes in particular reservoirs. They also provide an effective source of data for the comparison of alternative processes. This paper demonstrates the validity of scaling criteria developed to provide unambiguous relative permeability data from favourable mobility ratio water-oil displacement tests on strongly oil wet and water wet reservoir systems. Microvisualisation techniques were used in conjunction with core displacement tests. These techniques allow a better mechanistic understanding of displacement processes and the location and distribution of residual oil to be established. Displacement experiments were performed on oil wet and water wet reservoir systems and the resulting pressure and production histories compared with water displacement of solidifiable oil analogues. After solidification of 'residual oil', water was also replaced by a solidifiable analogue. Good agreement between water-oil displacement characteristics and water-oil analogue displacement characteristics demonstrate maintenance of wettability. Static contact angle tests were also used to ensure wettability alteration was not induced during the fluid replacement technique. Direct microscopic observation of the fluid distributions at initial and residual saturation using UV fluorescence illumination techniques are presented. The location of initial water presented. The location of initial water saturation is shown to be generally associated with water filled clays and microporous minerals. 'Classical' pendular rings and surface water do not account for the bulk of Swi. Residual oil in the water wet systems was largely located as discreet blobs as expected. In the oil wet reservoir system examined, residual oil was associated with clay (mainly kaolinite) filled pores. In this case the clays were apparently oil wet. Previously determined scaling criteria and analysis procedures are described and validated. Introduction The efficiency with which a particular recovery process extracts oil from a reservoir is process extracts oil from a reservoir is classically described in terms of 'microscopic', 'areal' and 'vertical' sweep efficiencies. Areal and vertical sweep efficiencies are largely dependent on reservoir properties (eg vertical permeability distribution, shale body permeability distribution, shale body distribution and faults) and the production scheme applied (eg well spacing and pattern). Microscopic sweep efficiency is usually determined from the results of laboratory core displacement tests. Great care is required in designing these tests to ensure the information obtained is representative of the microscopic displacement occuring in the reservoir. Results obtained are greatly influenced by sample preparation and the experimental methods preparation and the experimental methods applied. It is first necessary to establish representative wettability and initial fluid distributions in the core samples. Scaling criteria are then used to select appropriate experimental flow rates. The flow rate chosen will depend largely on the respective wetting tendancies of the displacing and displaced phases. For strongly water or oil wetting phases. For strongly water or oil wetting systems in which the displaced phase or the displacing phase strongly wets the rock surface, criteria have been established based on experimental and theoretical studies. P. 339

Abstract Flow and displacement theories for non-Newtonian polymer solutions in porous media have not been advanced to porous media have not been advanced to nearly the extent as those for the Newtonian fluids. At present, the field and experimental data available pertaining to the flow mechanism of pertaining to the flow mechanism of polymer solutions through porous media, polymer solutions through porous media, albeit reliable, are not comprehensive nor complete. Both experimental and theoretical research in development of a more satisfactory theory to describe the flow behavior of polymer solutions in porous media are urgently needed. Laboratory experiments were performed to study the role of mobility performed to study the role of mobility ratio for a process in which oil is displaced from a porous medium by a polymer solution. A reduced friction polymer solution. A reduced friction factor-Reynolds number correlation is developed to predict the flow of various polymer solutions through consolidated porous media and a theory is advanced to explain more truly the flow behavior of a polymer solution as it passes through the cores. The cone and plate viscometer data obtained for a total of 88 solutions of twelve different polymers more frequently used by the petroleum industry appeared to fit the power law equation quite well. The effects on solution viscosity of temperature, sodium chloride concentration, polymer molecular weight and polymer concentration are also discussed. Introduction Among the methods of secondary recovery which have been developed is one which involves the injection of high-viscosity water into the reservoir to improve the mobility ratio and thereby increase the displacement efficiency. The mobility ratio, when two immisicible fluids displace each other, is defined as the ratio of the mobility of the displacing fluid to that of the displaced fluid: displacing M = (1)displaced The mobility ratio is a very important factor in secondary recovery predictions, governing the recovery efficiency of the oil by the displacing fluid. A mobility ratio of greater than one will result in an uneven and an inefficient displacement and a poor oil recovery.

Abstract Ten to possibly thousand fold ratios of horizontal permeability to vertical permeability are required in two "clean" sand reservoirs to match actual water-free product ion of oil and. gas of wells having bottom water. Layer models with average permeabilities of cores at similar stratigraphic position in the reservoir rather than values selected from the permeability frequency distribution and with highly restricted cross flow yield the best match between actual and calculated dilution of wet gas by injected gas in two cycling projects. These same reservoir modeling concepts yield reasonable agreement with actual performance of the Seeligson enriched gas drive test without assumption of serious viscous fingering with gravity segregation. Introduction The effects of heterogeneity off reservoir rocks on fluid displacement efficiency remain as a very important unsolved problem in this period of rapidly growing application of fluid injection for increased recovery of oil. Hypotheses of reservoirs ranging from non-connecting layers characterized by permeability frequency distribution, irrespective of spatial origin of cores, to reservoirs so heterogeneous they are nearly homogeneous have been offered as bases for evaluation of actual oil recovery projects. Since we are forever barred from knowing the actual variation arid continuity of rock properties, it is imperative that we test our simplified models against performance of actual reservoirs to select those assumptions most appropriate as guides to judgment. This paper presents two types of field observations having a bearing on these models:Determination that 10 to possibly1000 fold ratio of horizontal permeability to vertical permeability is required to match water coning performance of a number of wells in "clean" sand reservoirs in contrast with very low ratios usually observed in small core plugs. Possibly cross flow between layers in laboratory fluid flow models or calculated mathematically for multilayer systems with equal horizontal and vertical permeabilities may not be representative of actual reservoirs in which gross anisotropy appears to be much greater than that of small cores.Agreement between actual dilution of gas streams by injected gas in two cycling projects and that calculated with assumption of parallel flow in separate layers is reasonable if permeabilities assigned to individual layers are average permeabilities of cores from different wells at the same relative vertical position in the reservoir section rather than values from the permeability frequency distribution. Most performance features of the current Seeligson enriched gas drive project are adequately matched by this parallel layer type analysis.

Abstract Displacement studies were performed on a Berea sandstone core in which a residual brine saturation was initially present. The oil saturation was determined as a function of time and distance by measuring the electrical resistance of segments of the core. Relative permeability was measured by a modified Penn State method for the same porous medium used in the displacement studies and static capillary pressures were determined for adjacent samples. The shape of the stabilized zone and recovery at water breakthrough were calculated using both measured and computed relative permeability data and these agreed with the experimental. The fraction of brine flowing at a given oil saturation was determined from saturation distribution data at various times and distances during the displacement runs by calculations based on the continuity equation. As the stabilized zone is formed, the shape of the fw vs So curve approaches a straight line for a certain range of saturations. Introduction A wide variety of experimental work on fluid displacement in porous media has appeared in the petroleum engineering literature during the last two decades. Along with this has appeared the theoretical treatment which forms the basis of our present concepts in this field. One of the first papers of background interest for this particular study was that of Leverett in which was developed the fractional-flow formula. A short time later Buckley and Leverett presented a form of the continuity equation as well as a method of using it and a simplified version of the fractional-flow formula (gravity and capillary-pressure terms neglected) to calculate the distance which any saturation has traveled in a given time interval. Terwilliger et al observed that after their water gas interfaced advanced a certain distance from the inlet of the system, all gas saturations over a certain interval beginning at the extreme flood front advanced at the same velocity. On the basis of the continuity equation they concluded that the change of fractional flow (gas) with saturation must be constant and this zone wherein all saturations moved at the same rate was named the "stabilized zone." They presented a method of calculating the saturation distribution in the stabilized and non-stabilized zones and obtained reasonable agreement between calculated and experimental values.

Abstract Many crude oils contain components which lead to the formation of solid films at the interface between the crude oil and water. Film forming ability varies widely among crude oils. It is completely absent in some, although most crudes will exhibit film formation at oil-water interfaces. The effect of these solid films on the displacement of oil by water has been demonstrated in laboratory flow studies using n-hexadecane and water as the immiscible fluids, and stearic acid as the film forming additive. These tests were conducted on highly reproducible glass bead packs. The presence of solid films can measurably increase the amount of oil recovered before water breakthrough. This increase may vary from as high as 52 per cent additional oil when connate water is absent to 14 per cent additional oil when connate water is present. The water production from breakthrough to a producing water-oil ratio of 100 is reduced by the presence of solid films. Decreases may be as high as 64 per cent when connate water is present. Solid film formation has little effect on the total oil recovered by flooding to WOR = 100 when connate water is present. However, in the absence of connate water, the oil recovery is less by about 12 per cent when flooding to the same water-oil ratio. The fact that solid film formation exerts such a pronounced and definite effect on laboratory systems indicates that further film effects in reservoirs where they are absent or enhance their effect in others. Introduction The existing information regarding the solid films which often occur at oil-water interfaces has been previously summarized and methods have been described whereby these films may be investigated in the laboratory. This technique of investigation has been successfully applied to the study of one crude oil-water system. Thus far, however, there has been no direct experimental evidence on the effect which these films display in the displacement of oil by water. The goal of the experiments described here was to demonstrate, under controlled laboratory conditions, the effect of film formation on displacement systems differing only by the presence or absence of films. The system chosen for these tests was n-hexadecane-water. Stearic acid dissolved in the n-hexadecane could be demonstrated to form films, at the n-hexadecane-water interface, which appeared very similar to those observed with natural crude oil-water systems. Moreover, the amount of stearic acid [about 14 parts per thousand] necessary to achieve this film formation was so slight as to have little effect on the n-hexadecane-water interfacial tension. The effects on other properties of the n-hexadecane were almost completely negligible. In order to achieve reproducible packing among the tests and to minimize any other side effects, glass beads were used as the porous medium. Materials The glass beads used were U.S. 60 screen No. 11 grade. Their range of diameter was 0.0095 - 0.0059 in. Their density was 2.45 gr/cc. The normal hexadecane was designated ASTM grade and has an apparent purity of greater than 99 per cent. Eastman reagent grade stearic acid was used. The water for flooding was laboratory deionized water. Previous tests had established this water as free of surface active impurities.