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.
Sheng, Kai (The University of Texas At Austin) | Argüelles-Vivas, Francisco J. (The University of Texas At Austin) | Baek, Kwang Hoon (The University of Texas At Austin) | Okuno, Ryosuke (The University of Texas At Austin)
Water is the dominant component in steam injection processes, such as steam-assisted gravity drainage (SAGD). The central hypothesis in this research is that in-situ oil transport can be enhanced by generating oil-in-water emulsion, where the water-continuous phase acts as an effective oil carrier. As part of the research project, this paper presents an experimental study of how oil-in-water emulsion can improve oil transport in porous media at elevated temperatures from 373 K to 443 K.
Dimethyl amine (DEA) was selected as the organic alkali to form oil-in-water emulsions with Athabasca bitumen and NaCl brine at 1000 ppm salinity and 0.5 wt% alkali concentration. This composition had been confirmed to be optimal in terms of oil solubility in the water-external emulsion phase at a wide range of temperatures. Then, flow experiments with a glass-beads pack were conducted to measure effective viscosities for emulsion samples at shear rates from 5 to 80 sec−1.
Results show that the effective emulsion viscosity is not sensitive to temperature. At an estimated shear rate of 11 sec−1, for example, the emulsion viscosity was 35 cp at 373 K and 31 cp 403 K. The efficiency of in-situ bitumen transport was evaluated by calculating bitumen molar flow rate under gravity drainage with the new experimental data. Results show that oil-in-water emulsion can enhance in-situ bitumen transport by 1.5 to 7 times at temperatures below 403 K, in comparison with the gravity drainage of oil-water two phases in conventional SAGD. This is mainly because the mobility of the bitumen-containing phase is enhanced by the reduced viscosity and increased effective permeability. A marked difference between alkaline solvents and conventional hydrocarbon solvents is that only a small amount of alkaline solvent enables to enhance in-situ transport of bitumen.
The objective of this research was to develop a surfactant formulation for EOR in an oil-wet, high-salinity, fractured dolomite reservoir at ~100°C. A key requirement was achievement of interfacial tension (IFT) sufficiently low to spontaneously displace oil from the matrix by buoyancy. The formulation developed to do so was a blend of lauryl betaine and C15-18 internal olefin sulfonate, supplemented by a smaller amount of i-C13 ethoxylated carboxylate, all thermally stable and commercially available surfactants although the carboxylate not in quantities required for largescale EOR processes. Proportions of the three surfactants for injection in hard sea water were selected using equilibrium phase behavior results and estimates of IFT obtained by a novel technique based on the manner in which oil exits a small, vertically-oriented, rectangular oil-wet capillary cell as it is displaced upward in the cell by surfactant solution. The ability to recover oil from an oil-wet dolomite core was confirmed by an Amott imbibition cell experiment in which 50% recovery was observed for a core initially fully saturated with oil. The formulation's ability to generate strong foam in porous media was presented earlier in SPE-181732-MS. Research at Rice for three additional projects having carbonate reservoirs but different crude oils, brines, and temperatures of at least 60°C demonstrated formulation versatility by showing good oil recovery by core floods with modestly adjusted proportions of the same three surfactants (SPE-184569-MS, 2017; SPE-190259-MS 2018, US Patent 9,856,412). In the first two of these cited studies, the foamed formulation was injected to recover crude oils from a novel model fracture-matrix system.
Maubert, M. (The University of Texas at Austin) | Jith Liyanage, P. (The University of Texas at Austin) | Pope, G. (The University of Texas at Austin) | Upamali, N. (The University of Texas at Austin) | Chang, L. (The University of Texas at Austin) | Ren, G. (Total E&P R&T) | Mateen, K. (Total E&P R&T) | Ma, K. (Total E&P R&T) | Bourdarot, G. (Total E&P) | Morel, D. (Total E&P)
Alkaline-surfactant-polymer (ASP) coreflood experiments using Indiana limestone were conducted to test the effectiveness of sodium hydroxide in reducing surfactant retention on limestones. Low concentrations of sodium hydroxide of only about 0.3 wt% increase the pH to about 12.6. The high pH reduces the adsorption of anionic surfactants by changing the surface charge of the limestone from positive to negative as well as having other favorable geochemical effects. Sodium carbonate could not be used in these experiments to increase the pH because the Indiana Limestone rock contained gypsum, which causes calcium carbonate to precipitate when it dissolves. Another advantage of sodium hydroxide is that much lower concentrations are needed compared to sodium carbonate because of its lower molecular weight. No adverse reactions between the sodium hydroxide and limestone were observed and the propagation of the pH in the corefloods was observed to be extremely favorable. The tertiary oil recovery was high and the surfactant retention using sodium hydroxide was low compared to experiments without alkali and compared to typical retention values reported in the literature for carbonates.
Immiscible Water Alternating Gas (IWAG) is an EOR process whereby water and immiscible gas are alternately injected into a reservoir to provide better sweep efficiency and reduce gas channelling from injectors to producer wells, aiming to stabilize the displacement front and increase contact with the unswept areas of the reservoir. In this work, we present a summary of best practices for laboratory evaluation of IWAG. This work was motivated by observations related to the way laboratory measurements are normally done, which could result in erroneous interpretation if the results were to be used directly for the design of a field application.
The set of best practices were collected from own work expanding over two decades of laboratory work, discussion with experts from laboratory services and research centres, and a comprehensive literature review. They were tested in a laboratory workflow and compared to conventional workflows used by most laboratories. The recommended approach covers steps from sample preparation, experimental setup, measurement protocols, guideline for process design, and data QA/QC for later use in reservoir simulation.
Among the best practices, particular attention is given to the type of fluids and samples used for the measurements based on the strong effect of rock-fluid interactions on the IWAG performance. The layout of the experimental setup, and how the injection and displacement process is done and the flow effects quantified. Other best practices relate to the selection of the WAG slug ratio, and required initial conditions of the core where the laboratory testing is done. The number of cycles in the WAG injection affects the recovery. On the initial condition of the sample, the knowledge of the sample wettability at the start of the WAG is critical since the optimum ratio is influenced by the wetting state of the rock. A WAG ratio of 1:1, which is the most popular in field applications, is not necessarily the most appropriate.
Regarding flow properties, relative permeability should be evaluated under three-phase conditions and making sure hysteresis effects are well captured data in general not readily available. Special attention should be given to the selection of correlations for calculating three-phase relative permeability widely reported in the literature; in most cases they are not accurate for WAG injection since they do not consider special treatment of water-gas cycle.
We present a side by side comparison of the impact on the laboratory results will be given on using recommended best practices to more routine laboratory implementations. These best practices, with focus on immiscible WAG, provide a new unique workflow for the execution of laboratory programs supporting a better understanding of the involved phenomena and providing accurate data for immiscible WAG process design.
Previously proposed models of wettability change have not been tied to the chemistry that controls wettability but instead were driven by simplistic criteria such as salinity level or concentration of an adsorbed species. Such models do not adequately predict the impact of brine compositional change and therefore cannot be used to optimize brine composition. In this work, after testing proposed models in the literature on sandstones and carbonates, we propose a mechanistic surface-complexation-based model that quantitatively describes observations for ionically treated waterfloods. To the best of our knowledge this is the first surface-complexation-based model that fully describes ionic compositional dependence observed in ionically treated waterfloods in both sandstones and carbonates.
We model wettability change by directly linking wettability to brine chemistry using detailed colloidal science. Brine has charged ions that interact with polar acidic/basic components at the oil-water interface and rock surface and therefore oil/brine and rock/brine interfaces are charged and exert both Van der Waals and electrostatic forces on each other. If the net result of the forces is repulsive, the thin water film between the two interfaces is stable (i.e., the rock is water-wet) otherwise, the thin water film is unstable and the rock becomes oil-wet. Based on
We implemented the improved wettability change model in a comprehensive coupled reservoir simulator, UTCOMP-IPhreeqc, in which oil/brine and rock/brine zeta potentials are modeled using the IPhreeqc surface complexation module. We take into the account total acid number (TAN) and total base number (TBN) for the oil/brine interface and we use rock surface reactions for brine/rock surface potential modeling. Surface potentials obtained from the geochemical model are used to calculate the dimensionless group controlling wettability change, which is dynamically modeled in the transport simulator. The model is validated in sandstones and carbonates by simulating an inter-well test, and several corefloods and imbibition tests reported in the literature. For sandstones, we model
The goal of this work is to develop surfactant systems that can improve oil flow from shale wells after fracturing or re-fracturing. Surfactants can reduce oil-water interfacial tension and wettability of the shale, which in turn can improve water imbibition, increase oil relative permeability and reduce water blockage at the matrix-fracture interface. Temperature in typical shale reservoirs are high and the surfactants need to be aqueous stable to be effective in these treatments. Mixing two surfactants often gives higher aqueous stability than those of the single surfactants. A large number of surfactants (anionic, non-ionic and cationic) and their blends were studied for aqueous stability, contact angle and spontaneous imbibition. Seven single surfactants and nine surfactant blends were found to be stable in both high and low salinity brines at 125 °C. All aqueous stable blends changed wettability of oil-wet shale to preferentially water-wet in both high and low salinity brines. Seven single surfactants and five surfactant blends were tested for imbibition. Surfactant solutions improved water imbibition to the extent of 20% PV. Surfactant blends improved imbibition more than the single surfactants. Imbibition in cores reached a plateau in about 3 days. Surfactant blends have the potential to be used in low salinity fracturing or refracturing fluids to stimulate shale wells.
For waterflooding in argillaceous reservoirs, the injection water needs to be carefully designed to avoid formation damage by clay swelling and migration. Common methods of achieving this are compatibility tests of injection water with formation water and rocks and injectivity tests. However, such tests are often not practical nor even possible due to the limited availability and prohibitive cost of obtaining actual reservoir cores. The objective of this work was to develop a cost-effective method to evaluate injectivity that does not require the use of reservoir core. In this study, a novel coreless injectivity method was developed and validated. The method utilizes field-produced drill cuttings to make synthetic core plugs, which are universally available during well drilling and commonly considered as waste. A specially designed cleaning process was performed for the drill cuttings. They were then wet compressed with a high-pressure hydraulic press and dried in a constant-humidity oven to make core plugs with standard dimensions. Drill cutting plugs prepared in this way can then be used for injectivity tests as an alternative to actual reservoir core plugs. The routine core analysis revealed that, although sedimentary structures were lost, the drill cutting plugs preserved the mineralogy and maintained comparable porosity and permeability to the reservoir plugs. To validate the representativeness of the formation damage tendencies of the drill cutting plugs, water injectivity tests were carried out on both preserved reservoir cores and compressed drill cutting cores, using simulated injection water with successively lower salinities. The results showed that injectivity loss as indicated by increasing pressure drop was consistent with both types of cores. The "coreless injectivity evaluation" technique can be applied for argillaceous reservoirs with formation damage concerns. It is a cost-effective and viable technique for evaluating water injectivity when reservoir cores are unavailable.
Over the past two decades, low salinity waterflooding has emerged as a successful tertiary recovery method. Several mechanisms have been suggested to contribute to the effect of the low salinity waterflooding. Fines migration in clay containing sandstones is amongst the main reasons attributed to the success of this technique. The effect resulting from the migration of fines helps homogenize the flow pattern of the waterfront, thus achieving better displacement efficiency. Little or no attention has been given to the effect of water blockage on multilayered reservoirs. The present work aims to study the effect of low salinity waterflooding on multilayered clay-rich sandstone reservoirs.
Parallel coreflood experiments were used to investigate the effect of low salinity waterflooding on multilayered reservoirs. Clay-rich Bandera sandstone cores were used for the experiment. Cores from two different blocks were used to obtain a contrast in the absolute permeability. All cores were saturated with the same high salinity formation water and then displaced with oil to reach initial water saturation. The cores were then aged at the reservoir temperature for 21 days. Three parallel coreflood experiments were used to compare the high salinity waterflooding to the low salinity waterflooding in both secondary and tertiary modes. Core effluent and CT scan were used to evaluate the recovery from all experiments.
The high salinity waterflooding shows heterogeneous water invasion, and more oil was recovered from the higher permeability core. Alternatively, the low salinity waterflooding in secondary mode showed a more homogeneous recovery regime, as the water blockage kept the waterfront advancement even between cores. Finally, the application of low salinity waterflooding in tertiary mode slightly improved the recovery from both cores equally.
This work is the first to emphasize the benefits of low salinity waterflooding in multilayered clay-rich sandstones. The conclusions from this work suggest a diversion effect to occur allowing for higher displacement efficiencies in multilayered clay-rich reservoirs.
Theriot, Timothy P. (Chevron Energy Technology Company) | Linnemeyer, Harold (Chevron Energy Technology Company) | Alexis, Dennis (Chevron Energy Technology Company) | Malik, Taimur (Chevron Energy Technology Company) | Perdue, Charles (Chevron Energy Technology Company)
High molecular weight HPAM’s tend to be highly shear sensitive. Various components of polymer mixing and distribution systems pose risk to the integrity of HPAMs due to high shear experienced at valves, chokes and other flow control devices. At a minimum, this risk can severely impact chemical EOR operating cost due to polymer degradation and consequential viscosity loss of the injectate. Low-shear, low-cost polymer injection distribution systems have the potential to reduce polymer usage, maintain injection stream viscosity, and enable integration into brownfield facilities. Lower viscosity losses translate into optimized operating and capital cost for CEOR pilot and full field projects. The objective of this work was to determine the equipment (piping), process, and polymer parameters that affect viscosity loss due to shear degradation.
In this work, polymers were evaluated from two different vendors. The effects of molecular weight, chemical concentration, and brine salinity on polymer sensitivity to viscosity loss due to shear degradation were investigated. Polymer solutions were either blended on site or purchased pre-blended in synthetic brine solutions. Pumped by a positive displacement, low-shear pump, the solutions flowed through a mass meter and were delivered to a distribution system component at various flow rates. For flow control devices, pressure differentials were adjusted at fixed flow rates. Polymer solution samples were collected upstream and downstream of the tested component. Samples were taken in no-shear sample collectors. Pressure upstream and downstream of the test component and flow rate were recorded during the flow test. Viscosity was measured with a Brookfield viscometer at ambient temperature. When higher concentration solutions were tested, viscosity was measured of diluted samples at target concentration to determine amount of shear degradation as evidenced by viscosity loss.
Results indicate that viscosity degradation of polymer solutions does occur in flow control devices and is directly correlated to pressure differential across the pipe device. Internal geometry has little impact on the amount of degradation. Velocity has little impact on the amount of degradation. Polymer molecular weight and structure both affect the amount of degradation due to shear as does solution concentration. Generally, viscosified brine solutions will lose viscosity when flowed through devices with greater than 50 psi differential pressure in the range of 15-50% of initial viscosity. Using more concentrated polymer streams and diluting to target concentration after flow control will reduce the amount of viscosity loss.
Based on the laboratory results, design and operating condition, recommendations can be made for polymer injection distribution systems to minimize shear degradation of the flowing viscosified brine stream.