Chen, Szu-Ying (University of California at Santa Barbara) | Kaufman, Yair (University of California at Santa Barbara) | Kristiansen, Kai (University of California at Santa Barbara) | Howard, A. Dobbs (University of California at Santa Barbara) | Nicholas, A. Cadirov (University of California at Santa Barbara) | Seo, Dongjin (University of California at Santa Barbara) | Alex, M. Schrader (University of California at Santa Barbara) | Roberto, C. Andresen Eguiluz (University of California at Santa Barbara) | Mohammed, B. Alotaibi (Saudi Aramco) | Subhash, C. Ayirala (Saudi Aramco) | James, R. Boles (UCSB) | Ali, A. Yousef (Saudi Aramco) | Jacob, N. Israelachvili (UCSB)
Waterflooding via injection of chemistry-optimized low-salinity – also, low ionic strength/concentration – waters, such as SmartWater, is becoming increasingly attractive for improved oil recovery, especially in carbonate reservoirs. In this manuscript, we describe the results from a series of experiments and theoretical modeling to determine the mechanisms that govern the
We measured various interrelated crude-oil(
The results presented in this manuscript are of practical significance to provide a better understanding of SmartWater flooding mechanisms in carbonates at multiple length scales, including subnano-, nano-, micro-, and macroscopic scales. The new fundamental understandings presented in this study will also guide the optimization of SmartWater flooding processes in other reservoir systems.
Smart water and low salinity waterflooding has been established as an effective recovery method in carbonate reservoirs by demonstrating a significant incremental oil recoveries in secondary and tertiary modes compared to seawater injection. Therefore, understanding of multiphase flow phenomena in reservoir rocks is critical to optimize injected water formulations for substantial increase in oil recovery. Characterization of fluid-fluid and fluid-rock interactions have been extensively conducted at micro- and macroscopic scale, attempting to reveal the underlying mechanisms responsible for wettability alteration. Indeed, routine methods for assessing macro-wettability of fluids on rock surfaces (contact angle) include the sessile drop and captive bubble techniques. However, these two techniques can provide different contact angle depending on rock surface heterogeneities, roughness and drop size. Thus, contact angle measured at macroscale can only be used to characterize the average wettability and a direct visualization at nanoscale is needed to identify oil and brine distribution in the carbonate matrix and wettability state at the pore scale. The application of ion-beam milling techniques allows investigation of the porosity at the nanometer scale using scanning electron microscopy (SEM). Imaging of carbonate porosity by SEM of surfaces prepared by broad ion beam (BIB) and under cryogenic conditions allow to investigate preserved fluids inside the rock porosity and, combined with energy dispersive spectroscopy (EDS) identify crude oil and brine distributions and quantify carbonate-oil interfaces and wettability state. The experiments have been conducted on carbonate rock samples aged in crude oil and saturated with brines at high and reduced ionic strength. This study established an experimental protocol using Cryogenic high resolution broad ion beam (Cryo-BIB SEM) equipped with energy dispersive spectroscopy (EDS). The results show that ion-BIB milling provides a smooth surface area with large cross-section of few mm2. High resolution imaging analysis allowed identification of the different phases, chemical mapping and distribution of oil, brine within the porous matrix. Segmentation of rock-oil-brine interface allowed an estimation of the in-situ contact angle and showed the effect of injected salinity brine on the 2D contact angle and more accurate description of the carbonate wettability at nanoscale.
Fredriksen, S. B. (University of Bergen) | Alcorn, Z. P. (University of Bergen) | Frøland, A. (University of Bergen) | Viken, A. (University of Bergen) | Rognmo, A. U. (University of Bergen) | Seland, J. G. (University of Bergen) | Ersland, G. (University of Bergen) | Fernø, M. A. (University of Bergen) | Graue, A. (University of Bergen)
An integrated enhanced oil recovery (IEOR) approach is presented for fractured oil-wet carbonate reservoirs using surfactant pre-floods to alter wettability, establish conditions for capillary continuity and improve tertiary CO2 foam injections. Surfactant pre-floods, prior to CO2 foam injection, alter the wettability of fracture surface towards weakly water-wet conditions to reduce the capillary threshold pressure for foam generation in matrix and create capillary contact between matrix blocks. The capillary connectivity transmits differential pressure across fractures and increases both mobility control and viscous displacement during CO2 foam injection. Outcrop core plugs were aged to reflect conditions of an ongoing CO2 foam field pilot in West Texas. A range of surfactants were screened for their ability to change wetting state from oil-wet to water-wet. A cationic surfactant was the most effective in shifting the moderately oil-wet cores towards weakly water-wet conditions (from an Amott-Harvey index of - 0.56 ± 0.01 to 0.09 ± 0.02), and was used for pre-floods during IEOR. When applying a surfactant pre-flood in a fractured core system, 32 ± 4% points OOIP was additionally recovered by CO2 foam injection after secondary waterflooding. We argue the enhanced oil recovery is attributed to the surfactant successfully reducing the capillary entry pressure of the oil-wet matrix providing capillary continuity and enhancing volumetric sweep during tertiary CO2 foam injection.
CO2 enhanced oil recovery is usually affected by poor sweep efficiency due to unfavorable mobility contrast between the injected CO2 and oil. To alleviate this problem, CO2 is added to the injected brine and transported in the reservoir by flood water. Therefore, Carbonated Water Injection (CWI), takes advantage of both CO2 and water flooding processes. Furthermore, geochemical reactions between the injected carbonated brine and rock can alter petrophysical properties of the reservoir and affect final oil recovery. While there are several CWI coreflood experiments reported in the literature, simulation studies for this process are scarce.
Accurate modeling of CWI performance requires a simulator with the ability to capture true physics of the CWI process. In this study, a compositional reservoir simulator developed at The University of Texas at Austin, UTCOMP, coupled with a state-of-the-art geochemical package developed by United States Geological Survey, IPhreeqc, is used to model CWI process. We considered the impact of CO2 mass transfer between brine and hydrocarbon phases based on thermodynamic constrains at the reservoir condition. In order to validate our simulation approach, the results of our CWI simulations were compared with a recently published coreflood experiment. Moreover, we investigated the fluid-rock interactions in CWI.
The results of the simulations, indicated that prior to water breakthrough the main drive mechanism is displacement. But as more carbonated water is injected, CO2 diffuses more into the trapped oil left behind, which results in oil swelling and subsequent oil viscosity reduction. Moreover, reaction of carbonate minerals such as calcite with carbonated brine results in dissolution of the main rock matrix which consequently creates wormholes similar to carbonates acidizing.
In this study we propose a novel approach for accurate modeling of carbonated waterflooding process. The results of this study highlight the importance of geochemical reactions in modeling CWI process. Our approach has been validated based on history matching at the backdrop of a recently published coreflood experiment.
Alcorn, Z. P. (Department of Physics and Technology, University of Bergen) | Fredriksen, S. B. (Department of Physics and Technology, University of Bergen) | Sharma, M. (The National IOR Centre of Norway, University of Stavanger) | Rognmo, A. U. (Department of Physics and Technology, University of Bergen) | Føyen, T. L. (Department of Physics and Technology, University of Bergen) | Fernø, M. A. (Department of Physics and Technology, University of Bergen) | Graue, A. (Department of Physics and Technology, University of Bergen)
A CO2 foam enhanced oil recovery (EOR) field pilot research program has been initiated to advance the technology of CO2 foam for mobility control in a heterogeneous carbonate reservoir. Increased oil recovery with associated anthropogenic CO2 storage is a promising technology for mitigating global warming as part of carbon capture, utilization, and storage (CCUS). Previous field tests with CO2 foam report various results due to injectivity problems and the difficulty of attributing fluid displacement specifically to CO2 foam. Thus, a more integrated multiscale methodology is required for project design to further understand the connection between laboratory and field scale displacement mechanisms. Foam is frequently generated in a reservoir through the injection of alternating slugs of surfactant solution and gas (SAG). To reduce costs and increase the success of
Laboratory investigations include dynamic aging, foam stability scans, CO2 foam EOR corefloods with associated CO2 storage, and unsteady state CO2/water endpoint relative permeability measurements. Wettability tests of restored reservoir core material yield Amott-Harvey index values of −0.04 and −0.79, indicating weakly oil wet to oil wet conditions. Foam scans demonstrate highest foam quality at gas fraction (fg) of 0.70. CO2 foam EOR corefloods after completed waterfloods, at optimal foam quality, result in a total recovery factor of 80% OOIP with an incremental recovery of 35% OOIP by CO2 foam.
A negligible difference is observed in incremental CO2 foam recoveries and apparent viscosities when using 1 wt% and 0.5wt% surfactant solution. High differential pressures during CO2 foam suggest generation of stable foam with mobility reduction factors by CO2 foam up to 340, over CO2 at reservoir conditions. CO2 storage potential was assessed during displacement to investigate the carbon footprint of CO2 foam injection.
Relative permeability endpoints and foam stability scan parameters are input into a validated field scale numerical simulation model to recommend design parameters for SAG injection. The numerical model investigates foam's impacts on oil recovery, gas mobility reduction, producing gas oil ratio (GOR), and CO2 utilization. Simulation studies show the effectiveness of foam to reduce gas mobility, improve CO2 utilization, and decrease GOR.
Kazempour, Mahdi (Nalco-Champion, an Ecolab Company) | Kiani, Mojtaba (Nalco-Champion, an Ecolab Company) | Nguyen, Duy (Nalco-Champion, an Ecolab Company) | Salehi, Mehdi (Nalco-Champion, an Ecolab Company) | Lantz, Mike (Nalco-Champion, an Ecolab Company)
In recent years, the United States (US) has experienced a resurrection in hydrocarbon recovery owing to the extraction of oil and gas from unconventional resources. Due to the ultra-low permeability nature of these reservoirs and their oil-wet characteristics, oil production declines are steep and oil recoveries remain very low (< 12% of OOIP). This challenge endures even with the assistance of hydraulic fracturing advancements and well spacing optimizations. The billions of barrels of remaining oil is a good target for chemical enhanced oil recovery (EOR) technologies.
In this study, after comprehensive laboratory testing, a series of customized chemical formulations was developed to improve oil recovery under the challenging conditions of the Middle Bakken and Niobrara formations (temperature >110 °C, salinity>220,000 ppm, and hardness>15,000 ppm). To examine the performance of the selected formulation in the field-scale, a single well enhancement trial was carried out. A detailed review of the lab and field data (pre-and post-treatment) is discussed in this study. Oil rate decline analysis and numerical simulations were used to obtain more insight about the true effectiveness of the chemical treatments. The results of this field trial reveal that injecting a proper wettability altering agent can improve oil recovery from shale oil reservoirs by up to 25% of the estimated ultimate recovery (EUR). The results of numerical simulations also show that the additional oil recovered in this field trial cannot be achieved by either well shut-in or straight water injection.
The lessons learned from this study provide practical information to optimize similar field trial designs leading to more profitable projects. The concepts and information here can be also translated to other unconventional basins and gas condensate or wet/dry gas reservoirs.
The wettability of tight reservoir rock plays a critical role in affecting relative permeability and in turn oil recovery. However, the link between wettability and its effects on oil recovery remains poorly understood, and the potential to boost oil recovery by varying the wettability has not been fully explored. This work was an attempt to conduct a systematic experimental study to improve our understanding of wettability of tight oil reservoirs and the mechanisms of its alteration on oil recovery improvement. Contact angles of individual rock-forming minerals and reservoir rock samples were first measured in brines with different salinities. Then the minerals were aged separately with a medium crude oil with sufficient polar components to investigate their tendency for wettability alteration. As well, oil and water distributions inside tight core samples were scanned by a synchrotron-based computed tomography scanner. Contact angle measurements for all minerals and reservoir rocks showed initial water-wetting behavior. After aging with crude oil for over two months, polar components from the oil adsorbed onto the solid surfaces to alter their wettability to less water wet. Consequently, this wettability alteration contributed to oil and water redistribution and saturation change in reservoir cores.
The experimental findings suggested that the wettability in tight reservoirs is a strong function of rock mineralogy, formation fluid properties, and saturation history. Preliminary numerical simulation revealed how rock wettability alteration could contribute to improved oil recovery through waterflooding.
Føyen, T. L. (Dept. of Physics and Technology, University of Bergen) | Fernø, M. A. (Dept. of Physics and Technology, University of Bergen) | Brattekås, B. (The National IOR Centre of Norway, Dept. of Energy Resources, University of Stavanger)
Spontaneous imbibition is a capillary dominated displacement process where a non-wetting fluid is displaced from a porous medium by the inflow of a more-wetting fluid. Spontaneous imbibition strongly impacts waterflood oil recovery in fractured reservoirs and is therefore widely studied, often using core scale experiments for predictions. Decades of core scale experiments have concluded that spontaneous imbibition occurs by a uniformly shaped saturation front and that the rate of imbibition scales with square root of time. We use emerging imaging techniques to study local flow patterns and present new experimental results where spontaneous imbibition deviates from this behavior.
The imbibition rate during early stages of spontaneous imbibition (the
In this paper we investigate the contribution of capillary and viscous cross-flow to oil recovery during secondary polymer flooding. Cross-flow can be an important mechanism in oil displacement processes in vertically communicating stratified reservoirs. Using polymers will change the balance of these contributions. Previous numerical investigations have shown that the amount of viscous cross-flow is controlled by the layer permeability contrast and a dimensionless number that characterises the combined effects of water, polymer and oil viscosities. The highest viscous cross-flow values were observed during favourable mobility ratio floods in reservoirs with a layer permeability ratio close to 3.
The purpose of the laboratory study was to validate previous numerical studies of cross-flow performed using commercial reservoir simulators. A series of experiments were performed in glass beadpack using analogue fluids comprising water, glycerol solution (to represent the polymer) and paraffin oil. All porous medium and fluid properties (including relative permeabilities and capillary pressure curves) needed for the numerical simulations were determined independently of the displacement experiments. Two beadpacks were constructed of two layers of different permeabilities parallel to the principal flow direction. In one of the packs a barrier was placed between the two layers to prevent cross-flow. Comparing the recoveries from these enabled us to quantify the contribution of cross-flow to oil recovery. The mobility ratios examined in the experiments ranged from very unfavourable to very favourable. The layer permeability ratio was approximately 2.5.
Good agreement was obtained between experiments and simulations, without the need for history matching, demonstrating that the simulation correctly captures the physics of crossflow. The incremental oil recoveries attributable to cross-flow and mobility control both fell within the error margins of the experimentally calculated values. The experiments showed that capillary cross-flow dominated over viscous cross-flow on laboratory length scales. Having validated the simulator, we then used it to show that wettability (with and without capillary pressure) can modify the impact of cross-flow on oil recovery.
Accurate and continuous capillary pressure (
This paper develops a coupled equation-of-state (EoS)