Quintero, Harvey (ChemTerra Innovation) | Abedini, Ali (Interface Fluidics Limited) | Mattucci, Mike (ChemTerra Innovation) | O’Neil, Bill (ChemTerra Innovation) | Wust, Raphael (AGAT Laboratories) | Hawkes, Robert (Trican Well Service LTD) | De Hass, Thomas (Interface Fluidics Limited) | Toor, Am (Interface Fluidics Limited)
For optimizing and enhancing hydrocarbon recovery from unconventional plays, the technological race is currently focused on development and production of state-of-the-art surfactants that reduce interfacial tension to mitigate obstructive capillary forces and thus increase the relative permeability to hydrocarbon (
A heterogeneous dual-porosity dual-permeability microfluidic chip was designed and developed with pore geometries representing shale formations. This micro-chip simulated Wolfcamp shale with two distinct regions: (i) a high-permeability fracture zone (20 µm pore size) interconnected to (ii) a low-permeability nano-network zone (100 nm size). The fluorescent microscopy technique was applied to visualize and quantify the performance of different flowback enhancers during injection and flowback processes.
This study highlights results from the nanofluidic analysis performed on Wolfcamp Formation rock specimens using a microreservoir-on-a-chip, which showed the benefits of the multi-functionalized surfactant (MFS) in terms of enhancing oil/condensate production. Test results obtained at a simulated reservoir temperature of 113°F (45°C) and a testing pressure of 2,176 psi (15 MPa) showed a significant improvement in relative permeability to hydrocarbon (
Measurements using a high-resolution spinning drop tensiometer showed a 40-fold reduction in interfacial tension when the stimulation fluid containing MFS was tested against Wolfcamp crude at 113°F (45°C). Also, MFS outperformed other premium surfactants in Amott spontaneous imbibition analysis when tested with Wolfcamp core samples.
This work used a nanofluidic model that appropriately reflected the inherent nanoconfinement of shale/tight formation to resolve the flowback process in hydraulic fracturing, and it is the first of its kind to visualize the mechanism behind this process at nanoscale. This platform also demonstrated a cost-effective alternative to coreflood testing for evaluating the effect of chemical additives on the flowback process. Conventional lab and field data were correlated with the nanofluidic analysis.
Two-phase oil/water relative permeability measurements were conducted at ambient and high temperatures in two different rock-fluid systems; one using a clean Poly-Alpha-Olefin (PAO) oil and the other with Athabasca bitumen. The tests were performed in a clean sand-pack with the confining pressure of 800 psi, using deionized water as the aqueous phase. Both the JBN method and the history match approach were utilized to obtain the relative permeability from the results of isothermal oil displacement tests. The contact angle and IFT measurements were carried out to assess any possible wettability alteration and change in fluid/fluid interaction at higher temperatures.
Results, Observations, Conclusions: The results of the clean system using the viscous PAO oil confirmed that the two-phase oil/water relative permeability in this ultra-clean system is practically insensitive to the temperature. The slight variation in oil endpoint relative permeability, especially at ambient condition, was attributed to variations in the packing of sand. It was found that the history matching derived two-phase relative permeability from the highest temperature test provides reasonably good history matches of the other displacements that were conducted at lower temperatures. In addition, it is shown that the JBN approach based relative permeability curves show larger variations, primarily due to insufficient volume of water injection at lower temperatures, which makes the practical residual oil saturation much higher than the true residual. In contrast with the ultra-clean system, the results obtained with bitumen showed much larger variations in relative permeability with temperature.
Most of the reported studies involving history matching approach treat the low-temperature measurements as the base case and show that changes in relative permeability are needed to history-match the tests at higher temperatures. We have shown that the displacement done at the highest temperature provides a more reliable estimate of the relative permeability and, in some cases, this relative permeability can successfully history match tests done at lower temperatures. In view of the impracticality of injecting sufficient water to reach close to real residual oil saturation at low temperatures, it would be better to obtain relative permeability data at high temperatures for characterizing the two-phase flow behavior of viscous oil systems.
Initial rate and decline are the two main parameters defining the economics of unconventional shale oil development. To improve economics, companies drill longer horizontal wells with more than twenty equidistant stages, different completion strategies and various additives such as surfactants and nano surfactants. This procedure evolves to factory mode in which tasks are optimized in timing and performance without attention to the matrix aspects of improving the recovery. Here, we report the design of a mutual solvent injection pilot in the Vaca Muerta unconventional reservoir during the completion of four unconventional shale oil wells. Reducing
Vaca Muerta has been long regarded as a water wet shale because of the limited water backflow post-fracking job. Alternating water injection was implementing assuming that the well productivity is driven by spontaneous imbibition, but this strategy has been unsuccessful as capillary pressure hysteresis drives this mechanism. We started studying Vaca Muerta from the rock microstructure using energy-dispersive spectrometry and focused gallium Ion Beam ablation FIB SEM images. The microstructure varied widely from millimeters in the same plug which could be expected because in shale rocks millimeters represent more years of deposition than in a conventional reservoir. We identified intercalations of massive water wet zones and strongly oil wet zones in the Vaca Muerta kitchen zone. The oil wet intercalations have high porosity and adsorption isotherm indicating 100 to 1000 times more permeability than the water wet zone. The water wet intercalations are highly saturated with water, and on the contrary, the oil wet intercalations are highly saturated with oil. The pilot designed consisted of four wells in which we will test different injection concentrations but keeping the total mass constant. In this manner, we will estimate the volume contacted by the solvent.
The laboratory protocol indicates a large percentage of macro and meso-pores. We implemented the dimethyl-ether injection which changes the interfacial tension, viscosity and wettability and we obtained the modified relative permeabilities which were the injection of dimethyl ether at 30% concentration along with the hydraulic fracture stimulation stages doubled the initial oil production rate.
The pilot consisted of five wells in which we will test different injection concentrations but keeping the total mass constant. In this manner, using the numerical simulation, we will estimate the volume contacted by the solvent.
Intercalations of high porosity high permeabilities zones in which the injection of a mutual solvent that reduces viscosity and could change wettability in oil wet/water-wet Vaca Muerta improving matrix connectivity.
Stephenson, Tim (Flotek Industries) | Oswald, Darin (Flotek Industries) | Dwyer, Pat (Flotek Industries) | Brown, Derek (Flotek Industries) | Ndefo, Emeka (Flotek Industries) | Kiran, Sumit (Crescent Point Energy) | Smith, Jeff (Crescent Point Energy) | Gaffney, Breandan (Crescent Point Energy)
Application of chemistries for waterflooding has traditionally required a significant upfront investment in core flood testing. Investments of this sort equate to money and time spent on a reservoir screening tool which does not guarantee an accurate translation into pilots. The aim of this paper is to explore core flood results in conjunction with pilot results for conventional and unconventional reservoirs where microemulsions are deployed in order to enhance oil recovery.
Microemulsions act as a delivery platform for solvent (terpene) and surfactant mixtures throughout a given rock volume. Their ability to alleviate damage and change the energetics of surfaces is believed to enhance mobilization of oil. They’re optimized for a given reservoir in the laboratory based on fluid-fluid and fluid-rock interactions. This includes adsorption (persistency), asphaltene wash-off, demulsification, drop size, and interfacial tension testing. We in turn label changes in injectivity of water as well as increases in oil production as indicators of success in core floods and pilots.
The above strategy has led to microemulsion optimization in Taylorton Bakken (which is more conventional) and Lower Shaunavon (which is more unconventional) in SE and SW Saskatchewan, Canada. These are characterized by changes in permeability, temperature, mineralogy (quartz vs calcite), oil (paraffinic vs asphaltenic) and water (high vs low salinity). This study demonstrates a beneficial core flood and pilot response in conventional reservoirs using microemulsions. What’s however interesting and noteworthy is that the core flood response is negligible in unconventionals (<5% incremental oil recovery) due in part to asphaltenes plating out on the core’s exterior surface during restoration of wettability, whereas the pilot response is quite positive.
The major highlight of this work is the need to address the discrepancy in core flood testing and pilot results in unconventional reservoirs. This is required before core flood testing can be used as a reliable screening tool for unconventional reservoirs. We’ve furthermore demonstrated the beneficial impact of microemulsions in both conventional and unconventional reservoirs as well as the need for optimization based on fluid-fluid and fluid-rock interactions.
We present a CT coreflood study of foam flow with two representative oils: hexadecane C16 (benign to foam) and a mixture of 80 wt% C16 and 20 wt% oleic acid (OA) (very harmful to foam). The purpose is to understand the transient dynamics of foam, both generated in-situ and pre-generated, as a function of oil saturation and type. Foam dynamics with oil (generation and propagation) are quantified through sectional pressure-drop measurements. Dual-energy CT imaging monitors phase saturation distributions during the corefloods. With C16, injection with and without pre-generation of foam exhibits similar transient behavior: strong foam moves quickly from upstream to downstream and creates an oil bank. In contrast, with 20 wt% OA, pre-generation of foam gives very different results from co-injection, suggesting that harmful oils affect foam generation and propagation differently. Without pre-generation, initial strong-foam generation is very difficult even at residual oil saturation about 0.1; the generation finally starts from the outlet (a likely result of the capillary-end effect). This strong-foam state propagates backwards against flow and very slowly. The cause of backward propagation is unclear yet. However, pre-generated foam shows two stages of propagation, both from the inlet to outlet. First, weak foam displaces most of the oil, followed by a propagation of stronger foam at lower oil saturation. Implicit-texture foam models for enhanced oil recovery cannot distinguish the different results between the two types of foam injection with very harmful oils. This is because these models do not distinguish between pre-generation and co-injection of gas and surfactant solution.
The simulation of the In Situ Combustion (ISC) process is a very challenging process due to the complexity and nonlinear nature of the problem. In this work, we propose an efficient technique to simulate experimental procedures for the ISC process including heterogeneity. The effects of permeability on mass flow and heat transfer were studied through a series of numerical frameworks. Different approaches to model the reactions occurring during combustion were attempted and simulation results were validated using experimental results. We focus on two different key areas: the integration of chemical reaction kinetics obtained through kinetic cell experiments, and the analysis of efficient simulations of combustion tube experiments that account for the flow element. After establishing a robust framework that accurately matches lab-scale results, combustion tube simulation results using a commercial simulator were analyzed to corroborate conclusions. Through observing the propagation of the combustion front and the oil bank in heterogeneous zones, assessments around the effects of permeability on the ISC process were performed. This work provides valuable information that would be instrumental in understanding experimental behavior of in-situ combustion and upgrading results to field scale after matching numerical results with experimental data collected in our future work.
A mechanistic approach for calculation of oil-gas capillary pressure curves and relative permeabilities in unconventional reservoirs is presented. The approach accounts for reservoir fluid composition, contact angle wettability and pore size distribution of each specific reservoir and generates a unique set of relative permeability curves based on those inputs. This allows calculation of curves in reservoirs where historical production data is limited.
Phase behavior calculations are computed by coupling the Peng-Robinson equation of state and the Young-Laplace capillary pressure model. This coupling allows for inclusion of the effect of confinement of reservoir fluids on volumetric and transport properties.
The reservoir is modeled as a bundle of tubes with diameters representative of the pore size distribution found in the reservoir. A multi-step depletion is modeled followed by gas injection and a secondary depletion. Separate capillary pressure results are obtained for each part of the process. After the capillary pressure curves are generated, an integration is performed on the capillary results to generate a set of relative permeability curves following the Nakornthap and Evans method (1986).
The multi-step process is used to allow recalculation of the relative permeability curves as the reservoir fluid composition changes due to the initial depletion and then secondary gas injection.The approach yields a unique set of relative permeability results for each set of input parameters.The mechanistic approach is demonstrated on two different oil compositions, a black oil sample and a volatile oil. For each of the oil compositions, two different injection gasses are evaluated (methane and carbon dioxide). The intermediate calculations are summarized and the final permeability results are included in the paper. The results show that for both oil samples evaluated, the gas injection results in an increase in oil relative permeability. Carbon dioxide is more effective at increasing the oil relative permeability than methane for both oil samples. This suggests that carbon dioxide could be an effective option for enhanced oil recovery operations in unconventional reservoirs.
A unique element of the approach presented is that the calculation of relative permeability curves for the initial reservoir depletion is immediately followed by the calculation of new relative permeability curves as the reservoir composition changes due to gas injection. This allows prediction of relative permeability results in an unconventional reservoir for both the initial reservoir depletion and also for hypothetical enhanced oil recovery operations. Since the model can be run quickly and repeatedly, sensitivity analyses can be performed on the permeability curves as a function of initial reservoir conditions and injection gas compositions and amounts.
Nguyen, Nhat (The University of Texas at Austin) | Ren, Guangwei (TOTAL E&P R&T, USA) | Mateen, Khalid (TOTAL E&P R&T, USA) | Ma, Kun (TOTAL E&P R&T, USA) | Luo, Haishan (TOTAL E&P R&T, USA) | Neillo, Valerie (TOTAL SA) | Nguyen, Quoc (The University of Texas at Austin)
Low-Tension Gas (LTG) has emerged as a novel enhanced oil recovery injection strategy, employing foam in place of polymer to displace the oil bank created with the help of ultra-low-IFT (ULIFT). In our prior work, the process was successfully employed, both in sandstones and carbonates, to achieve attractive oil recoveries with relatively low surfactant retention. However, earlier experiments were carried out at high flow rates in relatively high permeability cores. To improve the robustness of this novel injection scheme, it is necessary to examine it under wider practical environments. Therefore, in this work, experiments are conducted in carbonate and sandstone cores, at lower injection rates and rock permeabilities, to determine whether the foam could provide the necessary mobility control with this novel EOR technique. Initially, a lower flow rate (1 ft/D) experiment is conducted in relatively high permeability (388 md) sandstone core to compare it with the earlier results under a higher injection rate (4 ft/D). Subsequently, even further reduced injection rate (0.5 ft/D) is employed in a sandstone core with one order of magnitude lower permeability (36 md). Two other corefloods with Estaillades limestone (166 md) and Richmont (7 md) are carried out to extend the comparison to carbonate rocks. Surfactant retentions are determined. It is found that four-times-lower injection rate (1ft/D) just slightly delayed oil production, and achieved comparably high oil recovery (87%), indicating a good mobility control. Proportionally reduced pressure drop during slug injection implies similar total fluid mobility. Accordingly, salinity propagation examined from effluents shows slight delays. Even with ten-times-lower permeability sandstone (36 md) at a lower total injection rate (0.5 ft/D), comparable oil recovery (84%) and salinity propagation are found, despite of much lower foam strength. With an intermediate-permeability Estaillades limestone (166 md), compared to high permeability sandstone, oil production is delayed, but comparable eventual oil recovery (88%) is obtained. The delay could be due to higher surfactant retention (0.301 mg/g). The delayed effluent salinity propagation is noticeable, which may be caused by increased total fluid mobility. Finally, extremely low permeability Richmont (7 md) indeed adversely impacts the oil recovery (~58%) and the salinity propagation. This could be attributed to higher surfactant retention and/or decreased foam stability due to oil-wet rock surface. The works here test the robustness of the LTG process in more practical reservoir conditions and have widened its applicability. Demonstration of its feasibility in low-permeability reservoirs, where use of polymer is not currently feasible, will greatly promote the testing and deployment of this technology in the future.
Li, Shidong (Institute of Chemical and Engineering Sciences, Agency for Science, Technology and Research A*STAR) | Dan, Daniel (Institute of Materials Research and Engineering, Agency for Science, Technology and Research A*STAR) | Lau, Hon Chung (Department of Civil and Environmental Engineering, National University of Singapore, Singapore, Singapore. Institute of Chemical and Engineering Sciences, Agency for Science, Technology and Research A*STAR) | Hadia, Nanji J (Institute of Chemical and Engineering Sciences, Agency for Science, Technology and Research A*STAR) | Torsæter, Ole (PoreLab, Norwegian Center of Excellence. Department of Geoscience and Petroleum, Norwegian University of Science and Technology NTNU) | Stubbs, Ludger P. (Institute of Chemical and Engineering Sciences, Agency for Science, Technology and Research A*STAR)
Altering the wetting state of a rock surface to more water-wet has been proposed as an enhanced oil recovery (EOR) mechanism for nanoparticles. However, how nanoparticles achieve this is not well understood. The objective of this study is to fill this knowledge gap by using advanced 2D and 3D visualization techniques.
In this study, advanced visualization techniques were used to study how hydrophilic silica nanoparticles change the wettability of a glass surface. First, we used interferograms of an oil drop resting on a nanoparticle-treated glass surface to analyze the effect of nanoparticles on wettability. Second, we used Atomic Force Microscopy (AFM) to characterize the structure of nanoparticles covering a glass surface. Third, we used a 2D microfluidic apparatus to visualize wettability alteration caused by the nanoparticle injection. Fourth, we used a fluoresence imaging method with confocal microscopy to find out the reason for this change.
Interferograms of a nanoparticle-treated glass surface showed bright and dark fringes, indicating the presence of a thin water film covering the glass surface caused by nanoparticle adsorption. Furthermore, the higher the nanoparticle concentration, the thicker was the nanoparticle adsorption layer. A low pH environment can reduce nanoparticle adsorption on the glass surface. AFM results showed that the topography of the glass surface changed from smooth to rough after nanoparticle treatment. Microfluidic experiments showed that nanoparticle injection changed the wettability of the grain surface to more water wet. By using a confocal microscopy, we observed a thin water film covering the surface of glass grains suggesting that nanoparticle adsorption is the main mechanism of wettability alteration by nanoparticles.
This paper presents findings of new techniques to study wettability alteration by nanoparticles, including thin-film interferometry, surface characterization by AFM, and fluoresence imaging with confocal microscopy. Observations showed that nanoparticles adsorption on a glass surface results in a thin water film that prevents the oil from contacting the surface. This is the main mechanism of wettability alteration by nanoparticles. This is the first time use of these advanced visualization techniques to study wettability alteration by nanoparticles is reported.
A sizeable portion of the Athabasca oil sand reservoir is classified as Inclined Heterolithic Stratification lithosomes (IHSs). However, due to the significant heterogeneity of IHSs and the minimal experimental studies on them, their hydro-geomechanical properties are relatively unknown. The main objectives of this study are investigating the geomechanical constitutive behavior of IHSs and linking their geological and mechanical characteristics to their hydraulic behavior to estimate the permeability evolution of IHSs during a Steam Assisted Gravity Drainage (SAGD) operation. To that end, a detailed methodology for reconstitution of analog IHS specimens was developed, and a microscopic comparative study was conducted between analog and in situ IHS samples. The SAGD-induced stress paths were experimentally simulated by running isotropic cyclic consolidation and drained triaxial shearing tests on analog IHSs. Both series of experiments were performed in conjunction with permeability tests at different strain levels, flow rates, and stress states. Additionally, an analog sample with bioturbation was tested to examine the hydro-geomechanical effects of bioturbation. Finally, the hydro-mechanical characteristics of analog IHS were compared with its constituent layers (sand and mud).
The microscopic study showed that the layers’ integration and grain size distribution are similar in analog and in-situ IHS specimens. The results also revealed that geomechanical properties of IHSs, such as shear strength, bulk compressibility, Young's modulus, and dilation angle, are stress state dependent. In other words, elevating confining pressure could significantly increase the strength and elastic modulus of a sample, while decreasing the compressibility and dilation angle. In contrast, the friction angle and Poisson's ratio are not very sensitive to changes in the isotropic confining stress. An important finding of this study is that the effect of an IHS sample's volume change on permeability is contingent on the stress state and stress path. Volume change during isotropic unloading-reloading resulted in permeability increases and sample dilation during compression shearing resulted in permeability decreases, especially at high effective confining stresses. Moreover, the tests revealed that the existence of bioturbation dramatically improves permeability of IHSs in comparison to equivalent non-bioturbated specimens but has negligible effects on its mechanical properties, which remain similar to non-bioturbated specimens. The results also showed that bioturbation has minimal impact on permeability changes during shearing. Lastly, experimental correlations were developed for each of the parameters mentioned above.
For the first time, specialized experimental protocols have been developed that guide the infrastructure and processes required to reconstitute analog IHS specimens and conduct geomechanical testing on them. This study also delivered fundamental constitutive data to better understand the geomechanical behavior of IHS reservoir and its permeability evolution during the in-situ recovery processes. Such data can be used to accurately capture the reservoir behavior and increase the efficiency of SAGD operations in IHS reservoirs.