Significant Incremental Oil Recovery Research Articles

Introducing data-driven virtual viscosity measurements

Polymer-based chemical flooding is a mature enhanced oil recovery technology that has proven to result in significant incremental oil recovery that is both cost and GHG emission-competitive compared to the oil recovered by conventional waterflooding. For such chemical flooding projects, controlling the viscosity of injected polymer solution is critical because the polymer cost is one of the most significant cost elements in the project economics. The polymer viscosity is routinely measured in the laboratory using fluid samples taken manually at different sampling points (i.e., polymer preparation facilities, injecting lines, and well heads). However, in the case of large-scale projects, such viscosity monitoring becomes time-consuming and requires dedicated field staff. Moreover, the quality of laboratory-measured viscosity is questionable due to the potential viscosity degradation caused by the oxygen ingress or polymer shearing during sampling, storage, and measurement. The inline viscometers were introduced to improve the reliability of viscosity measurements and have a better quality of viscosity monitoring. Such viscometers are relatively simple devices readily available on the market from several vendors. However, the device comes at additional costs and requires modifications at the tie-in point (bypass line, drainage, and (sometimes) communication and power lines). On top of it, operational costs include regular maintenance that the inline viscometer requires to ensure good data quality.This study introduces a data-driven Virtual Viscosity Meter (VVM) as a tool to augment the inline and laboratory viscosity measurements. Standard injector wells in a field are equipped with gauges that report injection rate, well/tubing head pressure, and temperature of the injected fluid. With such well data and viscosity measurements, calculating the viscosity becomes a machine learning regression problem. Training the machine learning regression methods on the actual inline and laboratory-measured polymer viscosity has demonstrated that VVM is a promising, high-accuracy solution with a low computational cost. The possibility of further implementing this approach to calculate the viscosity of an injected fluid was investigated using the data from several projects. Finally, the application of the VVM tool for viscosity monitoring and the limitations of VVM were discussed.

Numerical Trend Analysis for Factors Affecting EOR Performance and CO2 Storage in Tight Oil Reservoirs

Improved oil recovery from tight oil reservoirs to fulfill the fossil fuel requirements and the CO2 storage to meet the net carbon zero objectives are the two motivations of this work. CO2 is a major anthropogenic greenhouse gas and its emission to our plants’ atmosphere is hazardous, particularly causing global warming. Therefore, its injection in the sub-surface oil-bearing formations not only improves the oil recovery but also reduces the carbon footprint from the planet. In this study, a mechanistic numerical simulation model is built using typical U.S. tight oil reservoir rock and fluid properties. The reservoir model is equipped with a hydraulically fractured single horizontal well that is subjected to multiple sensitivities using the huff-n-puff technique. Detailed CO2 trapping and diffusivity mechanisms at the nanopore scale are discussed that numerically define the CO2 solubility in formation oil and it’s trapping phenomenon into the nanopore spaces. The results show that CO2 injection works predominantly to achieve significant incremental oil recovery. Also, the reservoir with lighter in-situ fluid composition and higher reservoir pressure further enhances the oil recovery due to improved diffusivity and the solubility of CO2 into the reservoir fluid. It is also found that the increased number of huff-n-puff cycles and the incremental CO2 injection volume in each cycle not only enhance the oil recovery performance but likewise help to trap a larger volume of CO2 into a reservoir. A few diagnostic contour plots are also presented in this study to demonstrate the simultaneous effect of multiple hydraulic fracture parameters and the CO2 injection volume for the directional EOR and CO2 trapping performance. The findings of this study can help for a better understanding of designing EOR operations in tight oil reservoirs to achieve both goals concurrently.

Effects of thief zones on displacement efficiency: Microfluidic pore-scale and conformance control analysis

Thief zones are regions with high permeability, usually formed in mature or depleted reservoirs after water flooding, which can further reduce the overall recovery during subsequent EOR stages. While existing conformance control solutions alleviate the impact of thief zones, selecting an optimal solution based on current laboratory methods is challenging, since current methods fail to isolate the impact of thief zones, lack tight control of initial conditions, and use long evaluation times as well as large sample volumes. In this study, a microfluidic analogue is designed and fabricated with multiple permeability regions, representing thief zones in a reservoir, to evaluate the performance of polymer flood in a porous medium. The analogue contains four connected and distinct heterogenous zones of different permeability, in which the fluid dynamics and relevant conformance control are resolved during secondary and tertiary polymer floodings, once thief zones are apparent. The secondary water flooding did not exhibit an efficient displacement, with fingering and by-passing effects predominantly observed in higher permeability zones and minor oil displacement in the lowest permeability zone. Despite the fingers created by water flooding, polymer flooding showed much higher displacement efficiency throughout all four zones, resulting in significant incremental oil recovery. The secondary polymer flooding also produced more oil than the secondary water flood due to improvement in the mobility control. Lastly, pore-scale mechanisms such as viscous cross-flow between zones was observed during the polymer flood.

Capillary Pressure Effects on Estimating the Enhanced-Oil-Recovery Potential During Low-Salinity and Smart Waterflooding

SummaryMany experimental studies have investigated smart water and low-salinity waterflooding and observed significant incremental oil recovery after changes in the injected-brine composition. The common approach to model such enhanced-oil-recovery (EOR) mechanisms is by shifting the input relative permeability curves, particularly including a reduction of the residual oil saturation. Cores that originally display oil-wetness can retain much oil at the outlet of the flooded core because of the capillary pressure being zero at a high oil saturation. This end effect is difficult to overcome in highly permeable cores at typical laboratory rates. Injecting a brine that changes the wetting state to less-oil-wet conditions (represented by zero capillary pressure at a lower oil saturation) will lead to a release of oil previously trapped at the outlet. Although this is chemically induced incremental oil, it represents a reduction of remaining oil saturation, not necessarily of residual oil saturation.This paper illustrates the mentioned issues of interpreting the difference in remaining and residual oil saturation during chemical EOR and hence the evaluation of potential smart water effects. We present a mathematical model representing coreflooding that accounts for wettability changes caused by changes in the injected composition. For purpose of illustration, this is performed in terms of adsorption of a wettability-alteration (WA) component coupled to the shifting of relative permeability curves and capillary pressure curves. The model is parameterized in accordance with experimental data by matching brine-dependent saturation functions to experiments where wettability alteration takes place dynamically because of the changing of one chemical component. It is seen that several effects can give an apparent smart water effect without having any real reduction of the residual oil saturation, including changes in the mobility ratio, where the oil already flowing is pushed more efficiently, and the magnitude of capillary end effects can be reduced because of increased water-wetness or because of a reduction in water relative permeability giving a greater viscous drag on the oil.

Microfluidic Investigation of Low-Salinity Effects During Oil Recovery: A No-Clay and Time-Dependent Mechanism

SummaryWe present a study of the low–salinity effect during oil recovery using microfluidics experiments in an attempt to narrow the gap between pore–scale observations and porous–media–flow mechanisms, and to explain one type of low–salinity effect with delayed oil recovery and without the presence of clay. A microfluidic toolbox is used, including single–pore–scale microchannels, a pore–network–scale (approximately 102 pores) micromodel, and a reservoir–on–a–chip model (approximately 104 pores with heterogeneity), all with 2D connectivity. Experiments at the single–pore scale reveal a time–dependent oil dewetting and swelling behavior when a crude–oil droplet is in contact with low–salinity water. An interplay between water chemical potential and oil–phase polar compounds explains this pore–scale observation well. Experiments at the pore–network scale illustrate that the dewetting and swelling of residual oil in the swept region increase the water–flow resistance, modifying the flow field and thus redirecting the flooding liquid into unswept regions. This pore–network–scale effect is re–expressed into a macroscale model as a sweep–efficiency improvement derived from the change of relative permeabilities, which requires time to develop. Finally, experiments on our “reservoir–on–a–chip” model show significant incremental oil recovery during tertiary low–salinity waterflooding and confirm that late–time sweep–efficiency improvement contributes to most of the incremental oil recovery. On the basis of this microfluidic framework, we emphasize the following three findings: Low–salinity tertiary waterflooding can improve oil recovery by an improvement of sweep efficiency, which is a consequence of residual–oil dewetting and swelling.The low–salinity effect can occur without the existence of clay.The wettability alteration and oil swelling are time–dependent processes and should be expressed as a function of oil/water contact time rather than dimensionless time [pore volume (PV)], which explains some observations from previous coreflood experiments.

Exploring Low-IFT Foam EOR in Fractured Carbonates: Success and Particular Challenges of Sub-10-md Limestone

SummaryThe high formation heterogeneity in naturally fractured limestone reservoirs requires mobility control agents to improve sweep efficiency and boost oil recovery. However, typical mobility control agents, such as polymers and gels, are impractical in tight sub-10-md formations due to potential plugging issues. The objective of this study is to demonstrate the feasibility of a low-interfacial-tension (low-IFT) foam process in fractured low-permeability limestone reservoirs and to investigate relevant geochemical interactions.The low-IFT foam process was investigated through coreflood experiments in homogeneous and fractured oil-wet cores with sub-10-md matrix permeability. The performance of a low-IFT foaming formulation and a well-known standard foamer [alpha olefin sulfonate (AOS) C14-16] were compared in terms of the efficiency of oil recovery. The effluent ionic concentrations were measured to understand how the geochemical properties of limestone influenced the low-IFT foam process. Aqueous stability and phase behavior tests with crushed core materials and brines containing various divalent ion concentrations were conducted to interpret the observations in the coreflood experiments.Low-IFT foam process can achieve significant incremental oil recovery in fractured oil-wet limestone reservoirs with sub-10-md matrix permeability. Low-IFT foam flooding in a fractured oil-wet limestone core with 5-md matrix permeability achieved 64% incremental oil recovery compared to waterflooding. In this process, because of the significantly lower capillary entry pressure for surfactant solution compared to gas, the foam primarily diverted surfactant solution from the fracture into the matrix. This selective diversion effect resulted in surfactant or weak foam flooding in the tight matrix and hence improved the invading fluid flow in the matrix. Meanwhile, the low-IFT property of the foaming formulation mobilized the remaining oil in the matrix. This oil mobilization effect of the low-IFT formulation achieved lower remaining oil saturation in the swept zones compared with the formulation lacking low-IFT property with oil. The limestone geochemical instability caused additional challenges for the low-IFT foam process in limestone reservoirs compared to dolomite reservoirs. The reactions of calcite with injected fluids—such as mineral dissolution and the exchange of calcium and magnesium—were found to increase the Ca2+ concentration in the produced fluids. Because the low-IFT foam process is sensitive to brine salinity, the additional Ca2+ may cause potential surfactant precipitation and unfavorable over-optimum conditions. It, therefore, may cause injectivity and phase-trapping issues especially in the homogeneous limestone.Results in this work demonstrated that despite the challenges associated with limestone dissolution, the low-IFT foam process can remarkably extend chemical enhanced oil recovery (EOR) in fractured oil-wet tight reservoirs with matrix permeability as low as 5 md.

A study of the performance of the LSWA CO2 EOR technique on improvement of oil recovery in sandstones

Abstract Low salinity water is an emerging enhanced oil recovery (EOR) method that causes wettability alteration towards a favorable state to reduce residual oil saturation, while water alternating gas (WAG) is a proven EOR process that enhances oil recovery by controlling mobility of both water and gas. Therefore, combining the two EOR processes as low salinity water-alternating CO2 EOR injection (LSWA CO2) can further improve oil recovery by promoting the synergy of the mechanisms underlying these two methods. Core flooding experiments, contact angle, interfacial tension (IFT), and CO2 solubility measurement in oil and brine were conducted to investigate the viability and performance of LSWA CO2 in sandstone reservoirs. A favorable wettability alteration, along with IFT reduction and mobility control, are the mechanisms that contribute to residual oil mobilization efficiencies during the LSWA CO2 EOR process. In addition, LSWA CO2 core flooding experiments result in a significant incremental oil recovery. Three smart waters were tested in our research, to examine the impact of changing cationic composition on oil recovery. The solutions are designed brines as NaCl (SW1), MgCl2 (SW2), and KCl (SW3). Of the three solutions, SW1 yields the highest incremental oil recovery and highest IFT reduction. In addition, it results in a favorable wettability alteration towards a more water-wet state. In all cases, introducing CO2 to the brine/oil system shows a great advantage in terms of enhancing wettability modification, promoting IFT reduction, and controlling the displacement front of the injected fluid through mobility control.

Efficiency of enhanced oil recovery using polymer-augmented low salinity flooding

Oil recovery from heavy oil resources has always been a challenging task. This work is aimed at investigating the recovery efficiency of polymer-augmented low salinity waterflooding in heavy oil reservoirs. The main recovery mechanism behind low salinity waterflooding is wettability alteration to more water-wet state. On the other hand, polymer flooding is performed to control fluids mobility and hence improve displacement efficiency. Combining both recovery methods is expected to add to recovery efficiency obtained by individual methods, and the aim of this work is to explore this experimentally. In this study, several laboratory experiments were conducted using Berea and Bentheimer sandstone cores starting with base runs of continuous secondary seawater and tertiary twice and 10 times diluted seawaterflooding (low salinity). Significant incremental oil recovery was obtained when flooded with low salinity water, and 10 times diluted seawater was determined to be used as low salinity water. Contact angle and Zeta potential measurements indicate wettability alteration due to clay detachment as the main recovery mechanism. Synergy of water secondary flooding and polymer tertiary flooding at different water salinity levels proved the efficiency of hybrid low salinity polymer flooding process in Berea sandstone. Low water salinity during secondary injection mode played a major role on ultimate recovery with less contribution to tertiary polymer slug injection. High salinity waterflooding provided lower secondary recovery leaving more residual oil for polymer slug to act on at that cycle. Smaller polymer slug of 0.1 pore volume was found to be sufficient in tertiary flooding with low salinity water but with slightly slower recovery rate. Bentheimer sandstones known for its low clay content were subjected to polymer-augmented waterflooding at high and low salinity levels. Close secondary and tertiary recoveries were obtained for the two salinity levels with slower recovery rate for low salinity run. Minute clay content and water-wet characteristic as determined by contact angle measurements may explain the lack of water salinity effect on recovery. The lack of salinity role and the two shock fronts with connate water bank in between known to exist during low salinity flooding may explain the slower recovery rate encountered. Comparison of both sandstones indicates that less ultimate recovery from Berea rocks, and this can be attributed to their initial intermediate wet state in contrast to the water-wet Bentheimer sandstone rocks.

Influence of Wettability on Residual Gas Trapping and Enhanced Oil Recovery in Three-Phase Flow: A Pore-Scale Analysis by Use of Microcomputed Tomography

Summary We imaged an intermediate-wet sandstone in three dimensions at high resolution (1–3.4 µm3) with X-ray microcomputed tomography (micro-CT) at various saturation states. Initially the core was at connate-water saturation and contained a large amount of oil (94%), which was produced by a waterflood [recovery factor Rf = 52% of original oil in place (OOIP)] or a direct gas flood (Rf = 66% of OOIP). Subsequent waterflooding and/or gasflooding (water-alternating-gas process) resulted in significant incremental-oil recovery (Rf = 71% of OOIP), whereas a substantial amount of gas could be stored (approximately 50%)—significantly more than in an analog water-wet plug. The oil- and gas-cluster-size distributions were measured and followed a power-law correlation N ∝ V−τ , where N is the frequency with which clusters of volume V are counted, and with decays exponents τ between 0.7 and 1.7. Furthermore, the cluster volume V plotted against cluster surface area A also correlated with a power-law correlation A ∝ Vp, and p was always ≈ 0.75. The measured τ- and p-values are significantly smaller than predicted by percolation theory, which predicts p ≈ 1 and τ = 2.189; this raises increasing doubts regarding the applicability of simple percolation models. In addition, we measured curvatures and capillary pressures of the oil and gas bubbles in situ, and analyzed the detailed pore-scale fluid configurations. The complex variations in fluid curvatures, capillary pressures, and the fluid/fluid or fluid/fluid/fluid pore-scale configurations (exact spatial locations also in relation to each other and the rock surface) are the origin of the well-known complexity of three-phase flow through rock.

Surfactant oil recovery in fractured carbonates: Experiments and modeling of different matrix dimensions

Abstract Oil recovery from fractured carbonate reservoirs by water flooding is often inefficient due to the commonly oil-wet nature of these rocks and the lack of sufficient spontaneous capillary imbibition driving force to push oil out from the matrix to the fracture network. Chemical processes such as surfactant/alkali-induced wettability alteration and interfacial tension (IFT) reduction have shown great potential to reduce the residual oil saturation in matrix blocks, leading to significant incremental oil recovery (IOR). However, the time required to achieve a significant amount of oil recovery is the most crucial deciding factor in field projects. The magnitude of recovery and response time of any chemical process depends on the degree of wettability alteration and IFT reduction, the nature and density of fracture network, and the matrix block size. Oil recovery experiments were performed for the same matrix rock and chemical formulation, but for different sized cores to gain a better understanding of the time dependence of the recovery process. The measured oil recoveries were history-matched. The simulation models were then used to predict the recovery response times for larger cores. The controlled and systematic laboratory measurements for several core sizes helped in developing dimensionless scaling groups to aid in understanding the time dependence and the upscaling of laboratory results to field-scale applications. This finding is significant as it illustrates the extent of wettability alteration and IFT reduction needed in fractured reservoirs. Laboratory measurements and simulation work substantiate the validity and the range of applicability of upscaled procedures and indicate the importance of viscous and buoyancy forces in larger field cases. The results of this work will be useful for the design of future field projects.

1D Simulations for Microbial Enhanced Oil Recovery with Metabolite Partitioning

We have developed a mathematical model describing the process of microbial enhanced oil recovery (MEOR). The one-dimensional isothermal model comprises displacement of oil by water containing bacteria and substrate for their feeding. The bacterial products are both bacteria and metabolites. In the context of MEOR modeling, a novel approach is partitioning of metabolites between the oil and the water phases. The partitioning is determined by a distribution coefficient. The transfer part of the metabolite to oil phase is equivalent to its ”disappearance,” so that the total effect from of metabolite in the water phase is reduced. The metabolite produced is surfactant reducing oil–water interfacial tension, which results in oil mobilization. The reduction of interfacial tension is implemented through relative permeability curve modifications primarily by lowering residual oil saturation. The characteristics for the water phase saturation profiles and the oil recovery curves are elucidated. However, the effect from the surfactant is not necessarily restricted to influence only interfacial tension, but it can also be an approach for changing, e.g., wettability. The distribution coefficient determines the time lag, until residual oil mobilization is initialized. It has also been found that the final recovery depends on the distance from the inlet before the surfactant effect takes place. The surfactant effect position is sensitive to changes in maximum growth rate, and injection concentrations of bacteria and substrate, thus determining the final recovery. Different methods for incorporating surfactant-induced reduction of interfacial tension into models are investigated. We have suggested one method, where several parameters can be estimated in order to obtain a better fit with experimental data. For all the methods, the incremental recovery is very similar, only coming from small differences in water phase saturation profiles. Overall, a significant incremental oil recovery can be achieved, when the sensitive parameters in the context of MEOR are carefully dealt with.

3-D Model Studies of Alkaline Flooding Using Horizontal Wells

In this study, the effect of sodium hydroxide (NaOH) solution for the improved oil recovery of Garzan (26° API) crude oil was investigated using two different laboratory models. The effect of injection rate on oil recovery was investigated using a one-dimensional unconsolidated limestone reservoir model. The effect of horizontal and vertical well configurations on oil recovery was also studied using a 3-D physical model and various well configurations. As previously studied, the interfacial tension measurement of Garzan crude oil and NaOH solution interface was measured to find the optimum concentration of the alkaline solution that gave the minimum interfacial tension at the crude oil/alkaline solution interface at different salinity of the alkaline solutions. The results of the 1-D model tests showed that the NaOH solutions with increasing salinity has given the most significant incremental oil recovery, about 3 to 9% for Garzan crude oil. The results of the displacement tests showed that the injection flow rate of alkaline solution has an important effect on Garzan crude oil in spite of oil recovery achieved. The optimum injection flow rate for Garzan crude oil has been found as 183 cc/hr. A total of 6 runs were conducted to investigate the effect of horizontal-vertical well configuration on oil recovery by alkaline flooding. Alkaline flooding experiments were performed in three different well configurations: (1) a vertical injector and horizontal producer, (2) horizontal injector and horizontal producer, and (3) a vertical injector and vertical producer. The highest oil recovery was obtained through vertical injector-horizontal producer configuration.

Improved oil recovery using alkaline solutions in limestone medium

In this study, the effect of sodium hydroxide (NaOH) and sodium silicate (NaSiO 4) solutions for the improved oil recovery of Garzan (26 API°) and Raman (17.2 API°) crude oils with variable salinity of the alkaline solutions, and the effect of injection flow rate at the salinity values of the alkaline solutions that yielded maximum oil recovery for both crude oils has been investigated using a one-dimensional unconsolidated limestone reservoir model. As the previous study, the interfacial tension measurements of the given crude oils and alkaline solutions interface have been measured to find the optimum concentrations of the alkaline that give the minimum interfacial tension at the crude oil/alkaline solution interface, at different salinity of the alkaline solutions. Using these optimum alkaline concentrations, 22 displacement runs have been performed; 13 runs with the variable salinity of the alkaline solutions, six runs with the variable injection flow rate, and the remaining three runs were the base floods, performed without oil to see the interaction of alkaline solutions with the porous matrix. The results of the displacement tests showed that the NaOH solutions with increasing salinity, has given the most significant incremental oil recovery, about 3–9% for Garzan crude oil, while the NaOH and NaSiO 4 solutions with different salinity did not produced any significant incremental oil recovery for Raman crude oil, when compared with the base waterfloods performed for each crude oil types. Six displacement runs have been performed; three runs for Garzan crude oil and three runs for Raman crude oil at injection flow rates of 400, 300, 200 and 100 cm 3/h for each crude oil with the salinity of the alkaline solution that yielded maximum oil recovery. The results of the displacement tests showed that injection flow rate of alkaline solution has an important effect on Garzan crude oil and has less effect on Raman crude oil in the scope of oil recovery achieved. The optimum injection flow rates for both Garzan and Raman crude oils have been found, which was 200 cm 3/h for Garzan crude oil and 300 cm 3/h for Raman crude oil for our model.

Optimization of Vertical Miscible Flood Performance Through Cyclic Pressure Pulsing

Abstract The concept of improving the performance of vertical hydrocarbon miscible floods is addressed. Improvement is attempted through cyclic pressure pulsing. The idea is to force recovery from dendritic structures or other unswept areas through pressure pulsing of the solvent and gas phases. A series of vertical miscible floods was performed on a-core from the Rainbow Keg River area. Methane (solvent) displaced n-pentane (oil) under a variety of rate and pressure scenarios. All runs were performed at rates significantly higher than the critical rate for the specific system. Through the experiments it was established that at the core level, the rate of displacement has a considerably larger effect on oil recovery than the pressure pulse. However, even if the solvent has broken through, reduction of frontal advance rates can provide significant incremental oil recovery. Introduction Vertical hydrocarbon miscible floods are frequently used in the Rainbow Lake reefs of northern Alberta. Oil is displaced downward by a less viscous solvent. Viscous fingering, which is in part triggered by local heterogeneities is blamed for reduced sweep efficiencies and oil recoveries which are less than what was expected in the design stage. In most cases, the solvent is chased by another gas. When both solvent and chase gas break through, the gas to oil ratio (GOR) increases dramatically with a comparable decrease in oil production. The standard approach in controlling excessive gas or solvent production is workovers in which the current perforations are cement squeezed and new perforations are made lower in the reef. This procedure is costly and is not always successful. Husky proposed another procedure in optimizing the displacement strategy which can improve the vertically directed miscible floods, by applying a cyclic flow interruption consisting of periodical shut-in(1). Field observations lead to the formulation of the concept(2,3). Conceptually, periodic shut-in and pressure pulses cause reduction and even reversal in the advancement rate of the solvent/oil flood front. These changes would allow not only the cones and fingers of solvent to heal back, but also the healing process would increase the length of the mixing zone. Longer mixing zones reduce the tendency for fingers to form. Also, these changes would change the pathways of dispersion and diffusion, potentially accessing bypassed oil. The problem with the cyclic flow interruptions is that production is discontinued. The question was raised whether a similar effect could be observed through a continuous process. It was proposed that cyclic pressure pulsing under restricted flow could provide increased mass transfer between solvent and oil and also allow for the solvent to access previously inaccessible oil through lateral spread. It was decided to test the proposed ideas in the experimental system previously used to test the applicability of the shut-in concept(2.3). FIGURE 1: Schematic of the experimental apparatus. (Available in full paper) Experimental The demonstration experiments were conducted in core from Rainbow Keg River "B" pool. The properties of the different pieces used in this study are shown in Table 1. Methane was used as the solvent and n-pentane as the oil.