Oil Bank Research Articles

Oil booms, bank productivity and natural resource curse in finance

Using a rich monthly microdata, this study is the first one to investigate the effect of commodity booms on bank productivity in the context of resource-endowed economies. Consistent with the axiom of a natural resource curse in finance, we find significant decline in banks’ total factor productivity (TFP) during episodes of oil booms.

Effect of dynamic spreading and the disperse phase of crystalline starch nanoparticles in enhancing oil recovery at reservoir condition of a typical sarawak oil field

Nanofluid flooding has been proven to be very effective in enhanced oil recovery (EOR). The performance depends on the material and formulation process. Previous studies have focused only on the use of inorganic, metal and metal oxides nanoparticles. The use of nanofluids from natural sources has not been investigated to a reasonable extent for possible application in EOR. In this study, ascorbic acid was used for the first time to synthesize crystalline starch nanoparticles (CSNP). The physical properties of the CSNP including their size distribution and crystalline structures were investigated. The interfacial properties of the crystalline starch nanofluid (CSNF) at the interface of oil and water (O/W) were investigated at different concentrations and temperatures. The effect of the interaction between electrolyte and ultrasonic was determined. The wettability alteration efficiency of CSNF on oil-wet sandstone surface was investigated using the sessile drop method. A core flooding experiment was conducted at reservoir conditions to justify the effect of wettability alteration and dispersion of CSNF on additional oil recovery. The performance of the CSNF was compared with the conventional EOR chemical. The methods were effective in producing spherical and polygonal nanoparticles with a mean diameter of 100 nm and increased in crystallinity of 7%. The interfacial tension (IFT) decreased with increase in concentration of CSNF, electrolyte and temperature. The results show that CSNF can change the wettability of sandstone at low concentration, high salinity and elevated temperature. The pressure drops data show stability of CSNF at 120 °C. The formation of oil bank was enough to increase oil recovery by 23%. CSNF was effective in mobilizing residual oil at reservoir condition. It can, therefore, be concluded from this experiment work that the method applied herein is easier, cost-effective and can reduce energy consumption making the method economically advantageous compared to conventional methods.

Oil mobilization and solubilization in porous media by in situ emulsification

HypothesisFor a wide range of subsurface engineering processes, such as geological carbon sequestration and enhanced oil recovery, it is critical to understand multiphase flow at a fundamental level. To this end, geomaterial microfluidic devices provide visual data that can be quantified to explain the physics of multiphase flow at the length scale of individual pores in realistic rock structures. For surfactant enhanced oil recovery, it is the underlying geometrical states of the capillary trapped oil that dictates the recovery process and the degree to which oil is recovered through either mobilization or solubilization during in situ emulsification. ExperimentsA novel geomaterial microfluidic device is fabricated and its integrity is checked using light microscopy and X-ray micro-computed tomography (μ-CT) imaging. Subsequently, alkaline surfactant (AS) flooding of an oil saturated device is studied for enhanced recovery. The recovery process is analyzed by collecting 2D radiographic projections of the device during water flooding and in situ emulsification. 3D μ-CT images are also collected to quantify the geometrical states of the fluids after each flooding sequence. FindingsOur study reveals the processes of oil cluster mobilization and solubilization in porous media. After water flooding there are numerous oil clusters that are relatively large, extending over multiple pores, forming various loop-like structures. These clusters are mobile under AS flooding accounting for 75% of the recovered oil. The less mobile smaller clusters, isolated to single pores, forming no loop-like structures are immobile. These clusters are solubilized during AS flooding accounting for 25% of the recovered oil. The mobilized clusters coalesce forming an oil bank prior to total solubilization. The remaining oil clusters after AS flooding are highly non-wetting, as indicated by contact angle measurements and would only be recoverable after further solubilization.

Foam-Assisted Chemical Flooding for Enhanced Oil Recovery: Effects of Slug Salinity and Drive Foam Strength

The novel enhanced oil recovery (EOR) technique combining the reduction of oil/water (o/w) interfacial tensions (IFT) to ultralow values and generation of a foam drive for mobility control is known as foam-assisted chemical flooding (FACF). We present a well-controlled laboratory study on the feasibility of FACF at reservoir conditions. Two specially selected chemical surfactants were screened on their stability in sea water at 90 °C. The ability of both surfactants to generate stable foam in bulk was studied in the presence and absence of crude oil. It led to the composition of the foam drive formulation for drive mobility control. Phase behavior scan studies, for the two crude oil/surfactant/brine systems, yielded the design of the chemical slug capable of mobilizing residual oil by drastically lowering the o/w IFT. Core-flood experiments were performed in Bentheimer sandstones previously brought to a residual oil to waterflood of 0.33 ± 0.02. A surfactant slug at under-optimum (o/w IFT of 10-2 mN/m) or optimum (o/w IFT of 10-3 mN/m) salinity was injected for mobilizing residual oil. It resulted in the formation of an unstable oil bank because of dominant gravitational forces at both salinities. Next, a foam drive was generated either in situ, by co-injecting nitrogen gas and surfactant solution, or pregenerated ex situ and then injected to displace the oil bank. We found that (i) the presence of the crude oil used in this work has a detrimental effect on foam stability in bulk and foam strength in Bentheimer sandstones, (ii) optimum salinity FACF was able to increase the ultimate oil recovery with 5% of the oil in place (OIP) after water flooding compared with under-optimum FACF, and (iii) injection of pregenerated drive foam increased its ultimate oil recovery by 13% of the OIP after water flooding compared to in situ drive foam generation at optimum salinity.

Economic sanctions: costs and benefits for the oil and gas and banking industries in modern terms

Economic sanctions: costs and benefits for the oil and gas and banking industries in modern terms

Experimental investigation on block and transport characteristics of foam in porous media for enhanced oil recovery processes

Foam microscopic block characteristics were investigated in a 2D-visualization flow test and big 3D core foam flooding experiment. The foam macroscopic block characteristics and transport mechanism in porous media are investigated by measuring the production performance and pressure distribution in a positive rhythm heterogeneous reservoir model. Blockage of the throat by bubbles happens with single large bubble blocking or small bubble bridging and composite plugging with multiple bubbles. The distribution of the high-pressure gradient zone at a different time reflects the transport characteristic of the foam front and the oil bank formed during foam flooding. The selective blocking feature can effectively increase flow resistance and pressure, and promote the flow direction from the high permeability layer to the middle and low permeability layer, resulting in the expansion of swept volume. When 0.8 PV foam with the quality of 66.7% is injected into the big 3D core in the tertiary model, an incremental oil recovery of 21.19% OOIP is observed. The inlet pressure rises sharply from 40 kPa at waterflooding to 156.60kPa after foaming flooding, increasing approximately by 4 times. Foam can not only improve the displacement efficiency in the high permeability layers but also improve the displacement and expanding efficiency in the mid and low permeability layers. After the foam flooding, the incremental oil recovery rate in the high, media and low permeability layer is about 18.33%, 20.03%, and 23.23% OOIP respectively, indicating the influence of heterogeneity and effectiveness of foaming flooding. The primary way to enhance oil recovery in heterogeneous reservoirs is to increase oil displacement efficiency based on expanding the sweeping volume. In addition, the results of 3D foam EOR experiment provide an experimental basis for numerical simulation and play an important role in understanding and the application of the foam-EOR method in the heterogeneous reservoirs.

Pore scale and macroscopic visual displacement of oil-in-water emulsions for enhanced oil recovery

In-situ formation of emulsions has been observed in a large amount of chemical flooding pilots, and their effect on oil recovery is of great interest to petroleum engineers and researchers. In this study, microfluidic and transparent sand pack models were used to investigate mechanisms of emulsion propagation and plugging in both pore and macro scales. A microfluidic chip consisting of high- and low-permeability areas was fabricated to represent a heterogeneous area. Another chip was created with the same throat width but enlarged pore sizes (1.5 times larger) and reduced throat lengths. Two microscopic displacement experiments were conducted to compare the effect of pore structure on residual oil displacement after surfactant/polymer (SP) flooding by injecting the same emulsion slug. Meanwhile, the macroscopic flow path of the displacing fluid in the emulsion flooding was investigated using a relatively homogeneous transparent 2D sand pack. The emulsion plugging was proved to be a complicated process, and it could be strongly affected by pore throat structures. Fluid division and high oil recovery could only be achieved during the emulsion flooding in the condition with properly matched sizes of emulsion droplets and pore throats. For a relatively homogeneous 2D sand pack model, oil bank formation and enlarged sweep volume were observed in the emulsion flooding even though it was conducted after SP flooding. As suggested by results of this study, the in-situ formation of emulsion might significantly contribute to the oil recovery in reservoirs with tortuous pore structures, while making little difference in those with large pore throat channels that emulsion couldn’t be trapped in.

Investigation of alkaline-surfactant-polymer flooding in a quarter five-spot sandpack for viscous oil recovery

The alkaline-surfactant-polymer (ASP) flood has been shown in the past to reduce residual oil saturation significantly after waterflood. ASP floods for light oils are designed to be stable where the mobility ratio of the oil bank to the ASP slug is kept close to one. For viscous oils, such stable recovery processes may be unreasonably slow due higher oil viscosity. The goal of this paper is to study unstable ASP flooding (i.e., oil to ASP slug mobility ratio < 1) in secondary and tertiary modes. A viscous oil of viscosity 100 cp was displaced by an ASP slug in a quarter 5-spot sandpack. The ASP formulation was developed by studying the phase behavior of the oil with several alkaline-surfactant formulations. The effectiveness of the ASP formulation was validated in a 1D sandpack by conducting a water flood followed by a stable tertiary ASP flood. A reservoir sand was used to create a sandpack inside a square steel cell similar to a quarter five-spot pattern. Several ASP floods were then conducted in this cell to study both the displacement efficiency and the sweep efficiency of ASP floods. The tertiary ASP flood recovered most of the oil (∼98% of OOIP) when the ASP slug viscosity exceeded the oil viscosity, but pressure gradients were high at ∼ 1 ft/d injection. When the ASP slug viscosity was lowered to about 1/3 of the oil viscosity, the oil recovery dropped slightly to 90% OOIP, but the pressure gradient decreased significantly. As the extent of waterflood preceding the ASP flood became shorter, the oil was recovered faster for the same pore volumes injected. The ultimate recovery was independent of the extent of waterflood. The laboratory 5-spot floods were modeled by the simulator UTCHEM. The calibrated simulator can be used at the field scale to determine optimum viscosity ratio and ASP flood timing for viscous oil reservoirs.

Insights into the fractional flow of low salinity water flooding in the light of solute dispersion and effective salinity interactions

The objective of Low Salinity Water Flooding (LSWF) is to improve oil recovery. While a significant number of laboratory tests have been carried out to investigate the impact of LSWF, field scale modelling is often reported in the form of sector models with relatively coarse cells. This paper assesses the impact of simulating flow at very fine scales and informs on the properties that should be captured at the coarse scale to avoid numerical errors. We have found that the weighting function that is used to control changes to fluid mobility combines with numerical and physical diffusion to induce a retardation/acceleration effect. This is a physical effect rather than part of a chemical reaction.In this study, numerous simulations of LSWF have been carried out at the reservoir scale to investigate flow behaviour for various salt concentration (salinity) weighting functions and dispersion coefficients. We have examined the effective salinity range over which the weighting function is applied as well as considering various shapes. Dispersion was varied to represent physical and numerical effects. These have been compared to analytical solutions from fractional flow theory.We also observed that the fractional flow of the oil bank will be same for both the secondary and tertiary flooding. We point out the relative importance of various parts of the relative permeability curves. An important finding of this work is that by spreading the salinity front through dispersion and setting a low value at which salinity impacts mobility, we saw the injected low salinity front advance more slowly while the high salinity front of formation water moves more quickly. This is an effective retardation effect. We related this to an effect equivalent to adsorption in the fractional flow theory and could measure it in a similar way. We were also able to develop a prediction of the effect using the analytical solution to the advection-diffusion equation.The outcome is that we can estimate a corrective term for the flow behaviour in situations where the dispersion is quite strong, particularly in numerical simulations. We consider that this enable corrections to be made for numerical dispersion effects in field scale models.

Numerical simulation of the impact of geological heterogeneity on performance and safety of THAI heavy oil production process

The Toe-to-Heel Air Injection (THAI) in-situ combustion process is an efficient way to extract heavy oil and bitumen. However, such reservoirs are often geologically heterogeneous. This work studied the impact of a range of different geological heterogeneities, often found in bitumen deposits, on the performance and safety of THAI. These heterogeneities included random heterogeneity, layered reservoirs, shaly reservoirs, and semi-permeable cap-rocks. A further aim was to also develop potential remedial measures, such as selective well placement. It was found that the degree of symmetry assumed for the reservoir model had a substantial impact on the predicted level of oil production. This is of particular relevance to otherwise apparently symmetrical well placement designs such as staggered line drive. While the presence of impermeable zones resulted in the decrease in the overall oxygen utilisation for shaly reservoirs, compared to simply low permeability reservoirs, there was no evidence of oxygen breakthrough due to preferential channelling into the production well. In layered reservoirs, the development of a rich oil bank during THAI operation depended upon the distribution of permeability around the horizontal producer (HP), and did not occur when there was high permeability just above the HP. It has been shown that the proper representation of the cap-rock in reservoir models for the simulation of THAI is essential in order to accurately mimic the full pattern of heat distribution into the oil zone of the reservoir, and, thence, fuel lay-down. While THAI can operate stably with a permeable cap-rock, vertical permeabilities above ∼1–3 mD led to significant loss of combustion gases from the reservoir.

Fuelled Power: Oil, Financiers and Central Bank Policy in Nigeria

ABSTRACTWhile the literature on business power and global finance has illuminated the ways in which financial institutions limit the policy autonomy of states in developing countries, we know much less about the circumstances under which the power of financiers is undermined. In this article, I advance explanations of these circumstances by arguing that state access to natural resource revenues reduces the power of financial institutions and enhances the capacity of the state to pursue central bank policies which violate the interests of major financiers. I employ a case study of central bank policy in Nigeria to probe this argument and find evidence that supports the claim that whenever the Nigerian government's access to resource revenues increased, the state's capacity to diverge from financiers’ preferred central bank policies and to advance its own preferences increased as well. The analysis provides the basis for broader propositions about the policy space of developing countries vis-à-vis financial institutions and the variability of structural power.

Experimental investigation of emulsified oil dispersion on bulk foam stability

Recently aqueous foams have shown promising results to overcome viscous fingering and gravity segregation problems during gas injection process. However, one of the main challenges is the stability of the foams in the presence of oil bank at the front of injected foam. Oil can penetrate into the foam structure in the form of continuous phase or emulsions which might deteriorate lamellae and plateau borders that can result in bubble coalescence and foam rupture. The combination of the surfactant solution, responsible for stabilizing foams, with oil increases the potential for the formation of oil emulsions. In this condition emulsions stability and phase behaviour have the main influence on the bulk foam stability. The objective of this research is to conduct a comprehensive study on the effect of emulsified oil, at different concentrations and salinities on the stability of bulk foams used during oil displacement processes. This was achieved using a foam column test, in which foam is generated and its decay monitored with time. The half-life for each sample was noted and a comparison was made for different cases. Furthermore, changes in the foam bubble sizes and distribution were observed and analysed using an image processing software. A gradual reduction in the half-life of foam was observed with increasing concentration of emulsified oil. The degree to which a foam structure is destabilized by the emulsified oil droplets is dependent on the type and concentration of surfactant employed in generating the foam. At 2 wt% concentration of emulsion, the half-life recorded for foam generated by AOS surfactant, was 107 min, while for the foam generated by SDBS was only 39 min. Further analysis of the results showed a reduction in the number of dispersed oil droplets with increasing the salinity. In addition, the effect of increased salinity of the emulsion on foam stability was again found to be a function of the type of the surfactant is present in the foam system.

A systematic numerical modeling study of various polymer injection conditions on immiscible and miscible viscous fingering and oil recovery in a five-spot setup

Polymer flooding is employed to prevent immiscible viscous fingering between oil and water. If the polymer injection concentration is decreased rapidly, there is a high chance that fast growing miscible viscous fingers will pierce through the polymer bank and enter the oil bank. This is very detrimental to oil production. We performed numerical modeling of polymer flooding in one-quarter of a five-spot system. Due to the nonuniform flow field in a five-spot setup, the fingering patterns are very different and miscible fingers are more detrimental in this case than in a rectangular domain. In this paper we quantify the impact of injection concentration and duration of polymer flooding on the growth rate of miscible and immiscible viscous fingers. Besides decrease and increase of immiscible and miscible viscous finger growth at the front and rear of polymer banks respectively, we have shown that the residual oil saturation decreases for higher injection concentrations. However for high injection concentrations, polymer should be injected for a long duration so that the width of the polymer bank is large and miscible fingers cannot cause short-circuiting. Since injection at constant concentration for a long duration is not optimal, simulations for different multi-step injection were performed. Our results demonstrate that arbitrary decreases in polymer injection concentration are not effective for enhancing oil recovery. The ideal polymer injection scheme suggested by our simulations should involve an initial constant rate, followed by a gradual decrease. This is mainly to overcome the retardation due to adsorption of the polymer.

Mechanisms and influencing factors of the oil bank in fire flooding

Abstract Based on the systematic summary of current research on oil bank, the definition of oil bank in the process of fire flooding and its quantitative indices were proposed; and a new one-dimensional positive dry-fire flooding model considering temperature gradient was established based on the steady flow theory of gas and liquid phases. Single factor analysis and orthogonal experiments were adopted to verify the reliability and reveal the formation mechanisms and the controlling factors of the oil bank. Then the optimal conditions for the oil bank to form were discussed. The study results show the formation of the oil bank is controlled by 3 factors: (1) Oil bank would come into being within a certain temperature interval and above a critical value of temperature gradient (absolute value), with temperature too high or too low and temperature gradient absolute value lower than the critical value, the oil bank couldn't form. (2) For fire flooding process in heavy oil reservoirs, the viscosity of oil influences the width of oil bank and the speed at which oil bank forms; the lower the oil viscosity is, the wider the oil bank is and the faster the oil bank forms. (3) Oil saturation could affect the developing temperature and speed of oil bank. The favorable temperature at which oil bank develops gets lower and the accumulating speed of oil gets faster when the oil saturation is higher. By orthogonal experiments with the model, the optimal combinations of reservoir conditions for forming oil bank during fire flooding in heavy oil reservoirs can be worked out.

Update on PDVSA US Litigation Trust v. Lukoil Pan Americas, et al.

This is an update to the article we published on March 15, 2018 on the lawsuit filed by the PDVSA US Litigation Trust (the “Trust”) in federal court in Miami, Florida on behalf of Venezuela’s state-owned oil company, Petroleos de Venezuela, S.A. (“PDVSA”) against a group of 44 oil trading companies, banks and individuals, alleging that they participated in a 14-year scheme to rig bids, underpay on purchases and overcharge on sales, allegedly resulting in billions of dollars of losses to PDVSA. Our prior article flagged a number of interesting legal and factual questions raised by the suit, such as how the Trust was created, whether it has standing to assert PDVSA’s claims, whether some or all of the claims would be barred by applicable statutes of limitation and adequately assert an injury in the United States, and whether the Trust would be able to obtain the cooperation from PDVSA necessary to respond to discovery requests, among others. The case also may have implications for financial creditors of PDVSA, and even creditors of the Republic of Venezuela, who may be able to lay claim to the economic value of the Trust’s lawsuit or to any recovery, on the theory that the Trust is pursuing the claims for PDVSA’s sole benefit. The filings in the suit thus far provide insight into some, though certainly not all, of the questions raised by this suit and also introduce new issues of their own. Defendants are pursuing a vigorous challenge to the standing of the Trust to assert PDVSA’s claims under both Venezuelan and New York law, which the Court has agreed to hear as a preliminary issue. The agreement by which the Trust was formed has been filed with the Court and it reveals the role of the Venezuelan government in entering into the Trust agreement on PDVSA’s behalf and the economic interests of the Trust’s lawyers and other professionals versus those of the beneficiary of ultimate recoveries, PDVSA. The defendants’ opposition to the Trust’s motion for a preliminary injunction seeking a seizure of evidence and freeze of assets also has revealed defenses to the federal and state claims asserted in the complaint and confirmed that some of the issues we identified are already arising in the litigation.

PDVSA US Litigation Trust: What Creditors Should Know About the Trust, Its Claims and Its Implications for Venezuela's Restructuring

Last week, lawyers unsealed a complaint filed in federal court in Miami, Florida on behalf of Venezuela’s state-owned oil company, Petroleos de Venezuela, S.A. (“PDVSA”), against a group of 44 oil trading companies, banks and individuals. The suit alleges that the defendants participated in a 14-year scheme to rig bids, underpay on purchases and overcharge on sales, allegedly resulting in billions of dollars of losses to PDVSA. The lawsuit was brought by an entity called the PDVSA US Litigation Trust, which was formed for the purpose of pursuing potential claims by PDVSA, and to which PDVSA has reportedly assigned its litigation rights related to the alleged bribery scheme but retained the right to receive the net recovery the Trust obtains. The decision by PDVSA to pursue these claims in the United States at this time via a litigation trust raises a number of interesting legal and strategic issues not just for the defendants named in the suit, but also for PDVSA’s bondholders and other creditors. With respect to the litigation, there are questions as to whether the Trust has sufficient standing to be a claim, whether some or all of the claims will be barred by applicable statutes of limitation, and whether the Trust will be able to obtain the cooperation from PDVSA necessary to respond discovery requests. The case may also generate a reaction by financial creditors of PDVSA, who until now faced the prospect of pursuing claims to billions of dollars in defaulted PDVSA bonds without any known PDVSA assets in the United States, other than PDVSA’s indirect interest in CITGO Petroleum Corporation. Those creditors might now be able to lay claim to the economic value of the Trust’s lawsuit or to any recovery, on the theory that the Trust is pursuing the claims for PDVSA’s sole benefit and PDVSA has the right to receive any recovery assuming no impediment posed by any then-pending U.S. sanctions. The potential ability to attach the Trust’s recoveries may convince creditors to pursue actions against PDVSA in order to position themselves as the first beneficiaries of those recoveries, or may otherwise provide the proverbial “carrot” to offer creditors willing to restructure their claims as part of an eventual global restructuring of the debt of PDVSA, and possibly even the Republic.

Numerical Modeling of Unstable Waterfloods and Tertiary Polymer Floods Into Highly Viscous Oils

Summary The saturation distribution after unstable waterflooding into highly viscous oil may have a decisive effect on the efficiency of tertiary polymer flooding, in particular because of hysteresis effects associated with oil banking. In this work, we model waterflood and tertiary polymer-flood experiments performed on Bentheimer sandstone slabs with heavy oils of approximately 2,000 and 7,000 cp, and compare the numerical results with experimental production, pressure, and X-ray data. The unstable waterfloods are initially simulated in two dimensions with our parallel in-house research reservoir simulator (IHRRS) using a high-resolution discretization. In agreement with existing literature, we find that Darcy-type simulations dependent on steady-state relative permeabilities—inferred here from a 3D quasistatic pore-network model (PNM)—cannot predict the measured waterflood data. Even qualitatively, the viscous-fingering patterns are not reproduced. An adaptive dynamic PNM is then applied on a 2D pore network constructed from the statistics of the 3D network. If the fingering patterns simulated with this 2D PNM are qualitatively in good agreement with the experimental data, a quantitative match still cannot be obtained because of the limitations of 2D modeling. Although 3D dynamic PNMs at the slab scale would currently lead to prohibitively high computational cost, they have the potential to address the deficiencies of continuum models at highly unfavorable viscosity ratio. For the tertiary polymer floods characterized by a much more favorable mobility ratio, Darcy-type modeling is applied, and history matching is conducted from the end of the waterfloods. We find that unless hysteresis caused by oil banking is accounted for in the relative permeability model, it is not possible to reconcile the experimental data sets. This hysteresis phenomenon, associated with oil invasion into previously established water channels, explains the rapid propagation of the oil bank. For the considered experiments, a simultaneous history match of good quality is obtained with the production and pressure data, and the simulated 2D saturation maps are in reasonable agreement with X-ray data. This paper addresses the challenges in modeling highly unstable waterflooding, using both a conventional Darcy-type simulator and adaptive dynamic PNM, by comparing the simulated results with experimental data including saturation maps. It also highlights the important role of relative permeability hysteresis in the tertiary recovery of viscous oils by polymer injection.

SmartWater synergy with chemical EOR: Effects on polymer injectivity, retention and acceleration

The synergy between various enhanced oil recovery (EOR) processes has always been raised as a potential optimization route for achieving a more economic and effective EOR application. In previous work, beside the established positive impact of SmartWater on polymer rheology, we have demonstrated polymer positive impact on SmartWater effects through measurements of surface potential and contact angles. The results were also supported by forced oil-displacement experiments. In this work, we further investigate this SmartWater/Polymer synergy focusing on the possible impact of SmartWater on polymer floods specifically polymer injectivity, retention and acceleration. For this purpose, a set of thoroughly designed single-phase displacement experiments were performed at reservoir conditions. Many of the observed effects of SmartWater on polymer injectivity and transport can be attributed to polymer coil expansion in the lower-salinity SmartWater. The results mainly demonstrate that SmartWater has: (1) a slight negative impact on both polymer and chase water injectivity, (2) a positive impact on polymer retention, and (3) a negligible impact on polymer, hence oil bank, acceleration. Given the minor negative impact on injectivity, we conclude that SmartWater/Polymer flooding exhibits an overall favorable synergy that reduces chemical consumption, improves sweep, and enhance recovery.

Low salinity polymer flooding: Lower polymer retention and improved injectivity

Delayed arrival of the oil bank and reduced injectivity are risks which are commonly associated with low salinity polymer (LSP) flooding. In this study, experimental work was carried out to address these risks; the polymer retention and the cationic exchange in the presence of polymer were the main subjects of investigation. Single phase coreflood experiments were performed, where low and high salinity polymer (HSP) solutions, i.e., conventional polymer flood using formation brine, were injected in reservoir core plugs. The performance of the two polymer solutions were analyzed for polymer retention, injectivity and polymer acceleration. Compared to the HSP coreflood, the LSP coreflood showed considerably lower polymer retention and better long-term injectivity. There was no delay in polymer breakthrough, and the polymer acceleration was comparable to HSP floods. Analysis of produced effluent of the LSP coreflood detected divalent ion concentrations higher than the injected solution, and the solution which was already in equilibrium with the rock. This suggested that the divalent ions were released from the rock into the solution because of cation exchange in the presence of the LSP solution. Such increase in divalent ion concentration increased the polymer solution salinity and resulted in a viscosity loss. The results of the experimental study indicated that LSP flooding can be an attractive alternative to conventional polymer flooding, although viscosity loss due to cation exchange is a subject for further de-risking work. A numerical model which couples the cation exchange in presence of polymer with flow dynamics in core scale has also been developed. The flow field was used to advect the polymer which influenced the equilibrium condition between the rock surface and the solution. We present preliminary results obtained using the model which can be used to gain insights and study sensitivities around different geochemistry coupled flow processes.

Microscopic scale interactions of water ions at crude oil/water interface and their impact on oil mobilization in advanced water flooding

In this study, we performed interfacial shear rheology, surface potential and oil droplets coalescence time measurements to investigate microscopic scale interactions of various individual water ions at both air-water and crude oil-water interfaces. The measured interfacial rheology data indicated completely different interfacial behavior at crude oil-water interface when compared to air-water interface due to the presence of crude oil functional groups. Viscous dominated response was observed at crude oil-water interface for all brine compositions. Lower interfacial viscous modulus was observed for certain key ions such as calcium, and magnesium. The interfacial viscous modulus was found to be substantially much higher for sulfates, besides exhibiting some elasticity. The surface potential was gradually decreased by replacing seawater with calcium only brine. The better surface activity with seawater can be attributed to adsorption of more key water ions at the surface.These interesting results observed with calcium and magnesium ions at crude oil-water interface are expected to favorably impact oil mobilization in advanced water flooding processes. Such favorable interactions can quickly destabilize the interfacial film between oil and water (due to less viscous interfaces) to promote the coalescence between released oil droplets and enable faster oil mobilization. This coalescence process is also sequential and it would continue until the formation of small oil bank. The coalescence times measured between oil droplets confirmed the adverse impact of sulfate ions, to hinder the coalescence and delay oil mobilization, in consistent with interfacial shear rheology results. The new fundamental knowledge gained in this study would provide an important guidance on how to synergize water ion interactions at fluid-fluid interfaces with those at rock-fluids interfaces and optimize advanced water flooding processes in carbonate reservoirs.