The oil field is located 40 km offshore Sarawak, Malaysia in the southwestern part of the Baram Delta at a water depth of 250 feet. It is an anticline bounded by two (2) sealing faults and composed of multiple hydrocarbon bearing sand reservoirs separated by sealing shale layers. Oil has been produced since 1972 from more than 10 different reservoir units. Enhanced oil recovery (EOR) redevelopment project in the field will begin in 2018. The project will increase the crestal gas injection and initiate water injection at various locations in the water leg for two (2) major oil rim reservoirs. In a third relatively smaller reservoir water and immiscible gas will be injected in an immiscible Water-Alternating-Gas (iWAG) scheme. Required gas for the entire project will be supplied from five gas reservoirs, as well as by recycling the produced gas from the oil reservoirs. A Well, Reservoir and Facilities Management, or WRFM, plan was put together to prepare the reservoirs for the EOR project and to further optimise the development decisions. This paper outlines the objectives of the WRFM plan for the EOR redevelopment project. Key uncertainties that have an impact on the development plans are highlighted. A summary of surveillance activities required to manage the key uncertainties are given. At the end, focusing on the XE/XF reservoir group, reservoir surveillance required to monitor and manage a mature off-shore oil rim reservoir is discussed. XE/XF reservoir has a large gas cap and surrounded by an aquifer. The oil rim is dynamic in nature, which moved into the gas cap after the start of production due to the imbalance between the strong aquifer and gas cap expansion. For pressure maintenance purposes, as well as to prevent the rise of the oil rim, gas injection into the cap was started in 2001. Most recent saturation logs show that the current oil-water and gas-oil contacts in the field can no longer be regarded as even surfaces. The surveillance plan focuses on monitoring the saturation and pressure changes in the reservoir to locate the current gas-oil and oil-water contacts, and to understand the strength of the surrounding aquifer. The learnings will impact the number and locations of production and injection wells that are planned to be drilled as a part of the EOR project. In addition, the results will be used to update the existing dynamic reservoir model, which will be utilised for long term reservoir management.

This paper presents full field offshoresurfactant-polymer (SP) floodingapplied in JZ 9–3 Oilfield, Bohai Bay, China. Followed by 3-year polymer flooding which produced 4% incremental oil, the field turned to surfactant-polymer flooding. In the first stage, SP flooding was implemented in 4 injection wells. Then full field SP flooding was conducted in 8 injectors and 23 correspondent producers were involved. The injection scheme is designed as a slug of 0.23 pore volume (PV) of polymer solution at 0.120% polyacrylamide and second slug of 0.3 PV mixture of 0.20–0.24% of HDS surfactant and 0.12–0.15% of 3640C polymer and third slug of 0.035 PV of 0.12% 3640C polymer solution. By monitoring injection characteristics, oil increasing and water content decreasing, and development index, the results show significant effect in incremental oil recovery compared to polymer flooding since 2010 when the SP flooding started.By 1 st , Dec, 2014, the SP flooding has been improving oil production for 42 million tons with composite water cut 73.5% which declined by about 6.5%. There are 11 wells in 23 producers has obviously responded. The daily oil production of the center correspondent producer was doubled and water content decreased from 81% to 42%. The SP flooding effects lasted for about 2 years and could be extended further. This paper presents the feasibility of SP flooding in offshore environment.

The conventional blocking agents are hard to solve the problem of steam channeling during steam injection. In order to increase sweep volume and improve oil recovery, the in-depth blocking agents for conformance control are proposed and developed according to temperature gradient in the stratum when injecting steam. The in-depth blocking agents consist of gel system, organic/inorganic cross-linking system and inorganic curing system with different applicable temperature 60~110°C, 120~160°C and 170~300°C. The gel system with temperature resistance is composed of non-ion polyacrylamide and organic cross-linker. The organic/inorganic cross-linking system is composed of organic resin, silicide and stabilizer. The inorganic curing system is composed of superfine cement and stabilizing Na-bentonite. In this paper, the temperature distribution of heterogeneous reservoirs during the process of steam huff and puff is simulated by CMG. According to the above temperature distribution, these blocking agents are separately used for remote zone, transition zone and near wellbore zone of steam injection well. Sandpack flood tests indicate that the in-depth blocking agents have excellent blocking performance. Furthermore, the in-depth blocking agents have been applied to two injection wells in Bin'nan oilfield. After oilfield pilot test, steam injection pressure and daily oil production increased, and the input-output ratio increased to 1:3. The success of oilfield test confirms that the in-depth blocking agents are efficient to control steam channeling.

In recent years, low salinity waterflooding (LSWF) has been a promising technique to recover oil in sandstone reservoirs. In view of research results for the last decade, it is acknowledged that substantial oil recovery beyond conventional waterflooding from sandstone is wettability alteration. However, the major contributor to wettability alteration is still uncertain. Therefore, this paper investigates this major mechanism and shows how it is involved in the process of IOR. Rock and oil surface chemistry were tested to explain the influence of zeta potential on the disjoining pressure. Coreflood experiments with permeability less than 1mD were carried out and the impact of different wettabilities ranging from strong water-wet to slight water-wet on LSWF recovery was investigated with combination of thermodynamic theory. Relative permeability curves were obtained by history matching the corefloods experiments for both slight water-wet and strong water-wet cores with consideration of salinity effect. Thermodynamics of wettability by low salinity waterflooding was analyzed to characterize the surface forces between the surfaces of oil/water and water/rock. Zeta potential results showed that decreasing divalent cations and salinity makes the electrical charges at both oil/brine and brine/rock interfaces become strongly negative, which results in elevation of the repulsive forces between oil and rock, and as a result the rock turns more water-wet, which was confirmed by thermodynamics characterization. Corefloods experiments showed that a high potential in slight water-wet reservoirs can be achieved by low salinity waterflooding due to the double layer expansion. The relative permeability curves obtained by history matching showed that LSW improves oil recovery by accelerating oil production (relative perm changes) and reducing residual oil saturation in slight water-wet rock but not in strong water-wet rock. Thermodynamics of wettability analysis indicated that the mechanism of low salinity waterflooding might be interpreted by disjoining pressure calculation. In conclusion, double layer expansion caused by highly negative zeta potential as a result of lower salinity and divalent cation plays a major role in recovering additional oil. The low salinity waterflooding EOR-Effect might be interpreted by disjoining pressure calculation. These findings can help in composition design of low salinity water to maintain higher potential to recover oil in oil field.

Foam has been successfully used for profile control in mature reservoirs for the advantages of easy preparation, selectively plugging capacity, effective profile control and displacement efficiency capacity. However, the stability of foam is a serious problem for scale applications in oilfields. Due to viscoelasticity, strong shearing stability, high temperature and salinity resistance of micron dispersed particle gel (DPG), it was prepared to stabilize foam. The micron DPG particles were prepared using bulk gel by high shearing method in our lab ( C.L. Dai, et al., 2012 ). A new three phase foam system was successfully prepared by adding micron DPG particles through a modification of Ross-Mile method. The foaming capacity, stability and morphology were systemically investigated. The plugging capacity and enhanced oil recovery capacity of new three phase foam have been also investigated by sand-pack flowing tests. The effects of surfactant concentration, DPG particle concentration, salinity, oil concentration and gas-liquid ratio on the foaming capacity of three phase foam are systematically investigated. Increasing in surfactant concentration, DPG particles concentration and gas-liquid ratio can improve the foam volume and decay half-life of three phase foam, whereas increasing in salinity and oil concentration decrease the foam volume and decay half-life. By increasing in solution viscosity, adsorption at gas-liquid interface and non-adsorption in solution, the DPG particles can effectively stabilize new three phase foam. Morphology results show that the formed new three phase foam is compact and uniform. Sand-pack experimental results show that the new three phase foam has a better plugging capacity and enhanced oil recovery capacity than traditional aqueous phase foam. The new three phase foam may have a great potential for profile control in mature reservoirs.

The oil/water interfacial tension (IFT) is a key index of the properties of chemical enhanced oil recovery (EOR) displacement systems with surfactant. The studies showed that different oil and water often required different surfactant formulations to reduce IFT. The crude oil compositions in different oilfields differ with each other. Therefore, it requires different surfactant formulations to fit oil properties. It is necessary to reveal what kinds of components in crude oil have crucial influence on IFT reducing ability of surfactants, so as to optimize surfactant formulations for certain crude oil being performed efficiently. Daqing Oilfield crude oil was cut into five oil fractions with different boiling range by true boiling point distillation method. Group compositions (saturates, aromatics, resins, wax and asphaltene) of high boiling fraction and vacuum residuum were further separated by column chromatography and solvent extraction method. Five oil fractions and seven group compositions of crude oil were obtained. The effects of these fractions and chemical compositions on the performances of surfactants in reducing IFT were investigated. The IFT for the crude oil fractions and group components separated were tested using sodium alkylbenzene sulfonate (ABS) surfactants with different structures. The results indicated that oil fractions and group components have different impact on surfactants in reducing IFT. Low IFT value could be obtained for 200–350 °C and 350–400 °C oil fractions by ABS with carbon chain length of C 16 -C 18 or C 16 alkyl methyl benzene sulfonate. The unfavorable interfacial activity for oil fractions were low and high boiling point fractions. The effect degree order of IFT reducing ability for group components by ABS surfactants was: resins > aromatics > saturates > wax. High boiling point fractions and heavy components of resins and aromatics significantly influence on the performance of ABS surfactants in reducing IFT. Based on these results, an industrial product HABS was developed which could reach ultralow IFT between crude oil and surfactant solutions. Understanding the effect of crude oil components on the performances of surfactants in reducing oil/water IFT will help us to screen and optimize surfactant oil displacement formulations targeted according to the different properties of crude oils.

In oilfild operations, it is important to decrease water production and increase the efficiency of oil sweep. A gel treatment is using preformed particle gels (PPGs) to reduce water flow through high-permeability formation in mature reservoirs. The success of PPGs treatment primarily depends on whether or not PPGs can reduce the high permeability zones to the anticipate level. This work sought to find methods that minimized the damage caused by PPGs on unswept, low-permeable zones/areas, thus improving PPG treatment efficiency. These results can help to identify of the best PPG types, particle sizes, and brine concentrations for specific reservoir condition. Both a static filtration test model and load pressure model were used to evaluate the damage caused by various PPGs on sandstone core samples with various degrees of permeability. Two types of particle gels, a strong Daqing gel (DQ) and a weak Liquiblock TM 40k gel (40K), were used for various experiments, each with a different strength. The particle sizes ranged from 30 to 120 meshes. Sodium chloride (NaCl) was used to prepare all brines. Various brine concentrations at room temperature were selected to prepare the swollen PPGs. The effect of particle size, core permeability, and brine concentration on core damage was investigated. Results of these experiments yielded information useful for promoting the best PPG treatment for conformance control in mature reservoirs. These results can be used to optimize PPG's design and, thus, prevent damage to the unswept, low-permeable zones/areas.

We have successfully performed bacterial reduction of an iron-containing outcrop sand sample under static conditions using Shewanella genus bacteria. Adsorption of an anionic (alkyl benzyl sulfonate) surfactant was around 7-times lower on treated outcrop samples. Most of this reduction (~3X) occurs over the first 3-4 days of incubation, contemporaneously with iron dissolution and limited biofilm formation. Continued incubation after this point attends the formation of significant biofilm, as well as a continued decrease in surfactant adsorption. Non-iron-reducing bacteria also formed biofilm on outcrop samples, yielding a significant (though smaller) decrease in surfactant adsorption. Microscopy demonstrates preferential attachment of biofilm to iron minerals in a heterogenous outrop sample. Repeated rinsing results in a removal of biofilm formed by iron-reducing or bacteria and a corresponding increase in surfactant adsorption to about 1/3 to 1/2 of original levels. This proof of concept for a bacterial core restoration method using iron-reducing bacteria is considered successful, with the caveat that care must be taken to minimize and/or remove biofilm in order to avoid biofilm-related artifacts. Implications of these results for the determination of reservoir rock-fluid properties in biologically-active reservoirs are also discussed.

Minimum Miscible Pressure (MMP) is a critical parameter in the design of gas injection EOR projects. Several experimental and analytical methods have been proposed in the literature for determining MMP. For example, slim-tube experiments, method of characteristic (MOC) and numerical-simulation/cell-to-cell methods. The majority of these methods have limitations of complexity, long duration and/or high costs. Hence there is a need for alternative approaches. This paper presents a simple method for estimating near-miscibility pressures that is based on a gas-oil interfacial tension calculation procedure. The method assumes near miscibility conditions at low interfacial tensions and relies only on using a cubic equation-of-state (EOS) and the Parchor model. This method enables rapid calculation of MMPs for multiple component gas-oil systems. The method was validated against Zick fluid system and tested in a number of gas-oil systems. We also present a detailed analysis of the quality and compatibility of Whitson characterization with the IFT based method, where we consider a broad range of 12 gas-oil systems, for which PVT (composition, CCE and CV) and gas injection data are available (swelling test, slim tube test). We explore the impact of using swelling test data and slim tube data to tune the EOS on the calculated MMP using IFT based method. The results show that MMP estimation using our IFT based method is fast, easy to implement and reasonably accurate.

A novel technology has been developed for in-depth profile control based on thermo-gelling polymers (refers as THR). This technology differs from the ones currently used through different aspects. Thermo-gels polymers spontaneously gel when they reach a threshold temperature. Below this temperature, the product behaves as low-viscosity fluid, with good injectivity in reservoir rock. The system is single-component, and does not require any additive, contrary to classical gel systems which need to mix a polymer with a cross-linker (and often additives) to control gelation time. It is thus of easy control and does not face the drawbacks of two- or multi-component gel systems. Moreover this family of products is bio-sourced, thus environmentally friendly (some are CEFAS approved). Different THRs have been developed whose gel temperature varies between 25 and 85°C. The present work details laboratory evaluation of different THRs, including rheological properties, gel kinetics, gel strength, long-term stability and coreflood experiments. Main results are as follows: i ) gel temperature can be optimized by varying brine salinity and THR type and/or concentration; ii ) gel kinetics is very rapid once the gel temperature is reached, iii ) THRs remain stable over period of time superior to one year in reservoir conditions; iv ) coreflooding experiments in sandstone rocks show moderate adsorption (around 50 μg/g), good injectivity below gel temperature and strong pressure build-up once gel temperature is reached. Gel strength can be as high as 35 bar/m.

In spite of CO 2 mobility reduction during CO 2 and surfactant solution co-injection, CO 2 -foam flooding in heavy oil reservoirs has relatively poor sweep efficiency due to the high viscosity the oil. Therefore, reducing the oil viscosity is necessary to improve CO 2 -foam sweep efficiency. For this reason, steam is injected initially during steam-CO 2 -foam flooding to reduce oil viscosity. Displacement process is followed using CO 2 and surfactant solution co-injection. In our previous experimental study, in order to highlight the potential of steam-CO 2 -foam flooding, three different oil recovery experiments were conducted using medium heavy crude oil (19 °API), including CO 2 -foam flooding after water flooding, CO 2 -foam flooding and steam-CO 2 -foam flooding. The results showed that steam-CO 2 -foam flooding increases oil recovery dramatically by simultaneous mechanisms such as oil viscosity reduction by steam, CO 2 dissolution in oil and emulsification by steam and surfactant. Furthermore, the effect of high surfactant concentration slug injection on steam-CO 2 -foam flooding performance was investigated. The results showed that slug causes the formation of viscous micro emulsions in front of CO 2 -foam flood and improves CO 2 -foam sweep efficiency. In this paper, the effects of oil gravity and pore volume injected (PVI) of steam to PVI of foam on the oil recovery during steam-CO 2 -foam flooding have been studied. The experiments are conducted using heavy oil (12 °API) and sand pack models under reservoir conditions of 1550 psi and 131°F. In order to investigate the effect of PVI of steam/PVI of foam ratio on the oil recovery, three different oil recovery scenarios have been conducted using heavy crude oil, including CO 2 -foam flooding only, steam-CO 2 -foam flooding including 0.14 PVI of steam/PVI of foam ratio and steam-CO 2 -foam flooding including 0.34 PVI of steam/PVI of foam ratio. The results show that in spite of decreasing oil recovery by decreasing API gravity of the oil during steam-CO 2 -foam flooding, increasing PVI of steam improves oil recovery. The steam-CO 2 -foam flooding process has the following benefits. (1) Combination of steam injection and CO 2 -foam flooding as a novel enhanced oil recovery (EOR) method to achieve favorable oil recovery. (2) The applicability of this EOR method in heavy and medium heavy oil reservoirs.

Reitbrook oil field, located in the North of Germany, has produced oil since 1937 and has an impressive production history of more than 77 years. Reitbrook field life can be divided into three main periods: Oil Production (1937-1963), Gas Blowdown (1963-1973) and Underground Gas Storage (UGS) (1973-2014). The oil production did not stop during the Gas Storage period. On the contrary, the gas injection and withdrawal periods linked to the UGS activity allowed to enhance the oil production of this mature asset. After a brief presentation of the field, the specific mechanisms enhancing the oil production during the UGS period will be detailed and compared to the traditional gas injection technique. Reitbrook is a shallow (top reservoir at 640 m/bsl) oil field with an initial reservoir pressure of 81 bars and a specific oil gravity of 22°API. Some uncertainty remains on the STOOIP which is in the 31-41 10 6 Sm 3 range. Before being converted into an UGS in 1973, the field had a cumulative oil production of 2.35 10 6 Sm 3 , corresponding to a recovery factor around 6.5%. During the UGS period, circa 0.5 10 6 Sm 3 of additional oil has been produced, increasing the recovery factor from 6.5% to 7.8%. The increase in oil production during the UGS period is linked to various physical mechanisms, both at the pore scale and at the reservoir scale. The conversion of an oil field into an UGS makes a specific EOR process which can be contemplated to extend the life of a mature oil field. Through Reitbrook case study, the oil production mechanisms linked to the UGS activity will be presented, showing that this combination could be considered as an effective EOR technique. The conversion of a mature oilfield into an UGS while enhancing its oil production is also interesting from an economic perspective since it cumulates the value of the increase in oil recovery and the value of the gas storage activity while sharing the cost of gas compression / treatment and the benefits from the wells already in place. In addition, the implementation of such projects also allows to extend the economic life of installations and to postpone the decommissioning costs.

The present work numerically investigates the effect of reservoir temperature and pH on microbial growth and its transport within the reservoir which undergoes the reversible sorption kinetics. Further, the present work also studies the influence of reservoir temperature and pH on changes in interfacial tension between oil and water, capillary pressure and its impact on microscopic oil displacement efficiency. The microbe used is strain of Bacillus sp and the nutrient supplied to microbe is molasses. For this purpose, a novel mathematical model is developed which describes the coupled multiphase fluid flow and multispecies reactive transport in porous media which occurs during the MEOR process. Moreover, in the present work, the first order Monod kinetics equation is expressed as a function of temperature and pH which dictates the microbial growth rate. The developed mathematical model is sloved numerically by finite volume discretization technique and the results are found to be numerically stable and validated with the experimental results. The numerical data used for validation and for numerical simulation studies are presented. The results suggest that the oil displacement efficiency increases as the reservoir temperature and pH approaches the optimum temperature and pH required for microbes to reach its maximum growth. The present numerical model may be applied as an effective screening tool before the application of MEOR process and also serves as a reservoir simulator tool to predict the performance of MEOR process.

The three phase relative permeability is one of the most crucial parameters in reservoir engineering. Generally, experimental oil samples used in three phase flow are pure hydrocarbon samples instead of crude oil. Experiments are mostly carried out at low pressure with no chance of miscibility between the gas and oil phases. Because three phase lab data obtained by the steady-state method is expensive and time consuming, it is more common to use unsteady-state method to acquire two phase data. Many methods have been developed to calculate three phase relative permeability from two phase curves. However, there are no well recognized methods to perform the calculation, especially for carbon dioxide flooding due to the strong interaction among CO 2 , brine and oil phases. Diffusion coefficient and solubility of CO 2 in crude oil and brine were measured. Furthermore, all parameters including viscosities, densities, volume factors and interfacial tensions of three phases in CO 2 flooding were obtained. On the basis of these parameters, JBN method was revised to include the effects of CO 2 on brine and oil. Relative permeabilities of oil and water phases were measured at conditions of oil and water two phases. Oil and gas relative permeabilities at different reservoir pressures were obtained at oil and gas phases, which show the effects of interfacial tension on relative permeabilities. Furthermore, Corey method and Stone Ⅱ method were improved and applied to calculate three phase relative permeability. Mathematic models of three phase relative permeability were proposed. The results show that oil phase isoperms is concave to 100% oil saturation. Water phase isoperms and gas phase isoperms are straight lines. Additionally, the scope of oil phase isoperms indicates that three phase flow zone is very narrow in CO 2 flooding for low permeability reservoirs. The displacement effect is related to the saturation path, which contributes to oil recovery. All the production parameters can be illustrated through the ternary diagram combining three phase isoperms and saturation path change.

Alkaline-Surfactant-Polymer (ASP) flooding is potentially the most efficient chemical EOR methods. It yields extremely high incremental recovery factors in excess of 95% of residual oil for water flooding. The current opinion is that such extremely high recoveries can only be achieved at optimum salinity conditions, i.e. for the Winsor type III micro-emulsion phase characterized by an ultra-low interfacial tension (IFT). This represents a serious limitation since several factors including alkali-rock interaction, initial state of reservoir water and salinity of injected water may shift the ASP flood design to either under or over optimum conditions. A recent experimental study of ASP floods, based on a single internal olefin sulfonate (IOS), in natural sandstone cores varying salinity from under-optimum to optimum conditions indicated that indeed high recovery factors can be obtained also at under-optimum salinity conditions (see parent paper in this conference by Battistutta et al (2015). In this paper a mechanistic model is developed to explore the causes behind the observed phenomena. The numerical simulations were done using the UTCHEM research simulator (University of Texas at Austin) together with the geochemical module EQBATCH. UTCHEM combines multiphase multicomponent simulator with a robust phase behaviour modelling. An excellent match of the numerical simulations with the experiments was obtained for oil cut, cumulative oil recovery, pH profile, surfactant, and carbonate concentration at effluents. The simulations gave additional insight into the propagation of alkali consumption, salinity, surfactant and polymer profiles within the core. The study showed that the initial condition of the core is important in designing an ASP flood. Due to the uncertainties in the various chemical reactions taking place in the formation, an accurate geochemical model is essential for operating the ASP flood at a particular salinity region. Moreover, simulation results demonstrate for the crude oil with considerably low acid number, the ultralow IFT and low surfactant adsorption can be achieved over a wide range of salinities less than optimal salinity. The results provide a basis to perform better modelling of the under-optimum series of experiments and optimizing the design of ASP floods methods for the fields scale with more complicated geochemical condition.

CO 2 foam for enhanced oil recovery applications has been traditionally used in order to address mobility control problems occur during CO 2 flooding. However, the supercritical CO 2 foam generated by surfactant has a few shortcomings such as loss of surfactant to the formation due to adsorption, and lack of a stable front in the presence of crude oil. These problems arise due to the fact that surfactants dynamically leave and enter the foam interface. We discuss the addition of polyelectrolytes and polyelectrolyte complex nanoparticles to the surfactant solution in order to stabilize the interface using electrostatic forces with a view to generate stronger and longer lasting foams. An optimized ratio and pH of the polyelectrolytes was used to generate the nanoparticles. Thereafter we studied the interaction of the polyelectrolyte-surfactant CO 2 foam and the polyelectrolyte complex nanoparticle-surfactant CO 2 foam with crude oil in a high pressure, high temperature static view cell. The nanoparticle-surfactant CO 2 foam system was found to be more durable in the presence of crude oil. Understanding the rheology of the foam becomes crucial to determine the effect of shear on the viscosity of the foam. A high pressure high temperature rheometer setup was used to shear the CO 2 foam for the three different systems and the viscosity was measured with time. It was found that the viscosity of the CO 2 foams generated by these new systems of polyelectrolytes were slightly improved than the surfactant generated CO 2 foams. Core flood experiments were conducted in the absence and the presence of crude oil to understand the foam mobility and the oil recovered. The core flood experiments in the presence of crude oil show promising results for the CO 2 foams generated by nanoparticle-surfactant and polyelectrolyte-surfactant systems. This paper also reviews the extent of damage if any, that could be caused due to the injection of nanoparticles.

This work describes two types of laboratory chemical enhanced oil recovery (EOR) flooding experiment. Results are presented for micromodels and core floods (Bentheimer sandstone). Saturation behaviour is followed directly by optical microscopy in the micromodels and these images enable interpretation of the saturation development in the sandstone core as determined using spatially resolved nuclear magnetic resonance (NMR). The oil is a simple alkane (decane) but the surfactant combination is designed for EOR. The work is supported by surfactant phase behaviour, oil-water interfacial tension (spinning drop), and effluent analysis (surfactant concentration). The data and analysis presented here confirms much of that previously inferred general behaviour, using modern direct observation techniques (NMR and microfluidics). These micromodel data directly illustrate local behaviour of middle phases within the porous network, the mobilisation of ganglia, and the formation of middle phase from ganglia. The correlation of micromodel data with spatially resolved core data is striking, and allows identification of behaviours within the core. An aqueous formulation of anionic surfactants and butan-2-ol is injected into decane-saturated porous media. The formulations were selected to give rise to equilibrium L1 and L3 phase behaviours at different NaCl concentrations. The aqueous formulation contains 1% of each of a C12,13 alcohol-propoxy-sulfate and a C20-24 internal olefin sulfonate (supplied by Shell Chemicals) and 8% butan-2-ol. This formulation with 2% and 4% NaCl give rise to L1 and L3 phase behaviour and oil-water (measured) interfacial tensions of 0.10 and 0.006 mN/m, respectively, which at the flow rates used give corresponding capillary numbers of 3.5×10 -5 and 6.0×10 -4 , compared to a surfactant-free flood value of ~ 1×10 -7 . Both surfactant formulations provide improved oil displacement from the core. Adding surfactant in “L1-based” formulations reduces interfacial tension. However, “L3-based” formulations give ultra-low interfacial tensions and hence better recovery, exhibiting complex behaviour consistent with (1) the formation of, and then (2) the displacement of, microemulsion phases.

Two phase polymer flooding experiments were carried out using a novel Lab-on-a-Chip experimental set up. The microfluidics device uses porous Glass-Silicon-Glass (GSG) micro-models which were constructed based on reservoir rock thin section. The model attempts to resemble the thin sections internal porous structure geometry but also the rock wettability. The results were monitored and analyzed in real time using an image analysis algorithm. Polymer flooding is widely used to obtain incremental oil recoveries through providing favorable mobility ratio. However, its ability to mobilize and displace oil at microscale through its viscoelastic properties is still debated. EOR flooding experiments performed in micromodels that resemble porous media provides continuous visual access that combined with quantitative image analysis can provide improved understanding on displacement mechanisms. In particular, the more difficult questions concerning the complex viscoelastic behavior of polymers and its role in mobilizing trapped oil. In addition, when verified, micromodel based flooding can provide a complement to experimentation on limited core samples. The experimental results did not show a significant increase in oil recovery due to viscoelasticity in the micromodels used at the preset experimental conditions. GSG micromodels were successfully implemented under reservoir temperature for flooding experiments. Additionally it was found that using an extended Cox-Merz Plot (relation between Rheological parameters) to describe the rheology will improve the interpretation of the phenomena taking place; as well as considering the elongational rheology of aqueous polymer solutions. The results presented in this work show that flooding experiments in micromodels have a great potential to improve chemical EOR screening processes. The visualization technology depeloped during this work will contribute significantly and can be the enabler of intensified application of microfluidics technologies in EOR.

Increasing flooding solution viscosity with polymers provides a favourable mobility ratio, compared to brine flooding, and hence improved volumetric sweep efficiency. Flooding with a polymer solution exhibiting elastic properties has been reported to increase displacement efficiency, resulting in a sustained doubling of the recovery enhancement compared to that with conventional viscous polymer flooding (SPE-144294 ( Wang, et al., 2011 )). Flooding with viscoelastic polymer solutions is claimed to increase recovery more than expected from changes in capillary number alone (SPE-127453 ( Wang, et al., 2010 )). This increase in displacement efficiency by viscoelastic polymers is reported to occur due to changes in the steady state flow profile and enhancements in oil stripping and thread formation. However, within the industry there are doubts that a genuine effect is observed, or that improvements in displacement efficiency occur with field-applicable flow regimes (SPE-169681 ( Vermolen, et al., 2014 )). In this work, we show a different mechanism by which viscoelastic polymer solutions provide improvements in displacement efficiency, and demonstrate that these effects may be obtained at field-relevant flow rates. Our observations implicate an effect previously unrecognised in this context. Furthermore, this underlying mechanism explains both the enhanced capillary desaturation curves and the observation of apparent flow thickening (SPE-129200 ( Seright, et al., 2011 ), SPE-113620 ( Delshad, et al., 2008 )) for these viscoelastic solutions in porous media. The work contrasts experiments on flow and recovery using viscous and viscoelastic polymer solutions. The circumstances under which viscoelasticity is beneficial are demonstrated. The findings are applicable to the design of formulations for enhanced oil recovery by polymer flooding. A combination of core flooding, micromodel flow, and rheometric studies are presented. The results include single-phase and multi-phase floods in sandstone cores. Polymer solutions are viscoelastic (partially hydrolysed polyacrylamide, HPAM) or viscous (xanthan). The effect of molecular weight, flow rate, and concentration of the HPAMs are described. The data lead us to suggest an alternative mechanism that may be used to explain the observations of improved displacement efficiency and why the improvement is not seen for all viscoelastic polymer floods.

In situ formation of microemulsions is studied by co-injection of its individual phases: surfactant solution and decane oil. The experiments were conducted in micro-channels etched on a glass micromodel which facilitates the direct observation of the microemulsion formation. The micromodel was horizontally placed under an inverted fluorescence microscope. The aqueous phase was injected via one micro-channel and the oil phase was injected via another. The two microchannels merged at a T-junction where the microemulsion phase started forming upon mixing of its two individual phases. The oil phase was doped with an oil-soluble fluorescent dye, called Nile Red, which shifts its fluorescent peak based on the polarity of the environment. Under fluorescent light, the microemulsion and oil phase fluoresced bright red and amber brown, respectively. Microemulsions found their application in chemical enhanced oil recovery ( cEOR ) due to their ability to eliminate the capillary forces by generating ultra-low interfacial tension ( IFT ) between the aqueous phase and the oil-in-place. The flow regime shifts from immiscible to a quasi-miscible one, allowing the brine to access the more isolated parts of the rock. Inevitably the microemulsion becomes part of the flowing system and it has to be recovered. Therefore understanding of the microemulsion rheology as well as its IFT is important. The common knowledge on microemulsion formation is limited to the phase behavior analysis performed in static test tubes. Such tests answer some questions on microemulsion properties once they are formed, but they do not provide any insight to how a microemulsion forms and flows. This study presents a methodology to visualize the microemulsion together with its aqueous and oil phase components at the time scale necessary to study mixing. These visualizations can provide insights into questions regarding in situ microemulsion formation, and consequently, the rheological behavior of multiphase systems with ultra-low IFT . Our experiments indicated that at flowing conditions the fluids may mix spontaneously, and the mixing profile depends on the salinity of the environment as well as the injection rates.