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Roostaei, Morteza (RGL Reservoir Management Inc.) | Hosseini, Seyed Abolhassan (University of Alberta and RGL Reservoir Management Inc.) | Soroush, Mohammad (University of Alberta and RGL Reservoir Management Inc.) | Velayati, Arian (University of Alberta) | Alkouh, Ahmad (College of Technical Studies) | Mahmoudi, Mahdi (RGL Reservoir Management Inc.) | Ghalambor, Ali (Oil Center Research International) | Fattahpour, Vahidoddin (RGL Reservoir Management Inc.)
Summary Sieve analysis, sedimentation, and laser diffraction (LD) have been the methods of choice in determining particle-size distribution (PSD) for sand control design. However, these methods do not provide any information regarding the particle shape. In this study, we introduce the application of dynamic image analysis (DIA) to characterize particle sizes and shape descriptors of sandbearing formations. Different methods were compared in the estimation of PSD and fines content, which are the primary factors important in sand-control design. Through minimizing the sampling and measurement errors, the deviation between different PSD measurement techniques was attributed solely to the shape of the particles and the amount of fine fraction. For fines-content measurement, the values obtained through Feret min parameter values (the minimum size of a particle along all directions) calculated by DIA and sieving measurement are comparable within a 5% confidence band. The deviation between the results of different methods becomes more significant by increasing fines content. The fines and clay content show higher values when measured by any wet analysis. LD also tends to overestimate the fines fraction and underestimate silt/sand fraction compared with other dry techniques. By comparing the deviation of the DIA and sieving at standard mesh sizes, an algorithm has been developed that chooses the equivalent sphere sizes of DIA with minimum deviation from sieving. This study performs several measurements on formation sands to illustrate the real advantage of the new methods over traditional measurement techniques. Furthermore, particle-shape descriptors were used to explain the deviation between the results of different PSD measurement methods. Introduction One of the main factors in classifying the components of soil is the investigation of the size distribution of the particles. PSD is generally being used for soil classification and some hydraulic properties including soil's permeability, porosity, consolidation, and shearand volume-change behavior (Campbell and Shiozawa 1992). Furthermore, depositional history of transported soil and development of in-situ soils are also being evaluated by PSD. Thus, PSD provides valuable information in engineering and other fields such as environmental geoscience, sedimentology, and pedology. Studies confirmed that there are major problems associated with sedimentation methods including their time-consuming procedure, need for a fairly large number of samples (20 g), and dependency of the results on laboratory equipment, specific technique, or operation (Percival and Lindsay 1996).
In deep oil-sands deposits using the steam-assisted-gravity-drainage (SAGD) recovery process, real-time optimization (RTO) involves controlling optimum subcool to ensure steam conformance. Contemporary workflows use linear model predictive control (MPC) with oversimplified models that are inadequate to represent highly complex, spatially distributed, and nonlinear reservoir dynamics. In this research, two novel workflows using nonlinear MPC (NMPC) are proposed. The first workflow reduces an NMPC problem to linear MPC by estimating an equivalent linear model of a nonlinear black-box model in a mean-square-error sense. Another approach is to use nonlinear dynamic models explicitly for accurate prediction of the plant states and/or outputs. The resulting nonconvex, nonlinear cost optimization problem is solved using an interior-point algorithm at each control interval. Proposed workflows are tested using the history-matched, field-scale model of a SAGD reservoir located in northern Alberta, Canada. Qualitative and quantitative analysis of the results reveals that nonlinear black-box models based on system identification theory can successfully capture the nonlinearity of the SAGD process. Also, both workflows can control the subcool above the desired set-point while ensuring stable well operations. More than a 24% increment is achieved in net present value (NPV) using proposed NMPC workflows compared with the field operations with no closed-loop control. Overall, NMPC can successfully be used for improved RTO, energy efficiency, and greenhouse gas emissions while considering available surface facilities and well configurations.
Yang, Xinxiang (University of Alberta) | Kuru, Ergun (University of Alberta) | Gingras, Murray (University of Alberta) | Iremonger, Simon (Sanjel Energy Services) | Taylor, Jared (Sanjel Energy Services) | Lin, Zichao (University of Alberta) | Chase, Preston (Sanjel Energy Services)
Stress-induced fractures in wellbore cement can form high-risk pathways for methane or carbon dioxide leakage, yet little to no quantitative information on the impact of these fractures has been reported. To investigate this, scanning electron microscopy (SEM) and microcomputed tomography (micro-CT) techniques were used to quantify the 2D and 3D geometrical parameters of cement fractures in mature thermal thixotropic cement samples that were subjected to pre- and post-peak compressive stress. A novel simulation method was also proposed to quantify the impact of the stress-induced realistic 3D fractures on the cement permeability.
Results show that, for prepeak samples, 90% of the 2D fractures have length and width smaller than 100 and 5 µm, respectively. Although higher compressive stress reshaped the 3D fractures and increased the fracture length and width, no well-propagated fractures were observed. For post-peak samples, distinctly visible (>0.1 mm) well-propagated fractures were generated but failed to penetrate the entire sample; therefore, the effect of stress-induced fractures (up to 1.0% strain) on cement sample’s permeability is limited. CT-based 3D visualization and simulation both show that inclusion of a correctly engineered fiber additive can blunt the fracture propagation in cement samples.
We conclude that the fractures in cement matrix created by the monotonic compressive stress (up to the limit of uniaxial compressive strength) are not likely to form continuous leakage pathways. This is because the 2D fractures in cement matrix as shown by SEM images are in limited dimensions, whereas the 3D fractures in cement matrix observed from CT-based 3D models have poor connectivity, generally indicating that leakage pathways of significant permeability would not form as a result of compressing the cement samples up to their uniaxial compressive strength limit. Inclusion of a fiber additive is expected to enhance cement integrity by limiting the fracture propagation.
The fluid rheological properties and circulation rates are the two main operational variables significantly affecting the hole-cleaning performance. Adari et al. (2000) investigated the effect of fluid rheological properties and flow rates on cuttings-bed erosion through a broad set of experiments. Rabenjafimanantsoa et al. (2005) and Bizhani et al. (2016) reported the delay in the onset of particle movement in bed-erosion tests conducted using polymer fluids. Walker and Li (2000), on the other hand, concluded that polymer-based fluids had higher cuttings-carrying capacity. On the basis of the field practices from North Sea operations, Saasen and Løklingholm (2002) discussed the hole-cleaning performance of polymer-based drilling fluids in detail and they concluded that the gel forming as a result of the interaction of the cuttings bed and the polymer-based drilling fluid is an important factor undermining the hole-cleaning performance of polymer-based fluids.
Ayirala, Subhash (Saudi Aramco) | Li, Zuoli (University of Alberta) | Mariath, Rubia (University of Alberta) | AlSofi, Abdulkareem (Saudi Aramco) | Xu, Zhenghe (University of Alberta) | Yousef, Ali (Saudi Aramco)
The conventional experimental techniques used for performance evaluation of enhanced oil recovery (EOR) chemicals, such as polymers and surfactants, have been mostly limited to bulk viscosity, phase behavior/interfacial tension (IFT), and thermal stability measurements. Furthermore, fundamental studies exploring the different microscale interactions instigated by the EOR chemicals at the crude oil/water interface are scanty. The objective of this experimental study is to fill this existing knowledge gap and deliver an important understanding on underlying interfacial sciences and their potential implications for oil recovery in chemical EOR.
Different microscale interactions of EOR chemicals, at crude oil/water interface, were studied by using a suite of experimental techniques, including an interfacial shear rheometer, Langmuir trough, and coalescence time measurement apparatus at both ambient (23°C) and elevated (70°C) temperatures. The reservoir crude oil and high-salinity injection water (57,000 ppm total dissolved solids) were used. Two chemicals, an amphoteric surfactant (at 1,000 ppm) and a sulfonated polyacrylamide polymer (at 500 and 700 ppm) were chosen because they are tolerant to high-salinity and high-temperature conditions.
Interfacial viscous and elastic moduli (viscoelasticity), interface pressures, interface compression energies, and coalescence time between crude oil droplets are the major experimental data measured. Interfacial shear rheology results showed that surfactant favorably reduced the viscoelasticity of crude oil/water interface by decreasing the elastic and viscous modulus and increasing the phase angle to soften the interfacial film. Polymers in brine either alone or together with surfactant increased the viscous and elastic modulus and decreased the phase angle at the oil/water interface, thereby contributing to interfacial film rigidity. Interfacial pressures with polymers remained almost in the same order of magnitude as the high-salinity brine. In contrast, a significant reduction in interfacial pressures with surfactant was observed. The interface compression energies indicated the same trend and were reduced by approximately two orders of magnitude when surfactant was added to the brine. The surfactant was also able to retain similar interface behavior under compression even in the presence of polymers. The coalescence times between crude oil droplets were increased by polymers, while they were substantially decreased by the surfactant. These consistent findings from different experimental techniques demonstrated the adverse interactions of polymers at the crude oil/water interface to result in more rigid films, while confirming the high efficiency of the surfactant to soften the interfacial film, promote the oil droplets coalescence, and mobilize substantial amounts of residual oil in chemical EOR.
This experimental study, for the first time, characterized the microscale interactions of surfactant-polymer chemicals at the crude oil/water interface. The applicability of several interfacial experimental techniques has been demonstrated to successfully understand underlying interfacial sciences and oil mobilization mechanisms in chemical EOR. These techniques and methods can provide potential means to efficiently screen and optimize EOR chemical formulations for better oil recovery in both sandstone and carbonate reservoirs.
Complex flow mechanisms, such as Knudsen diffusion, are encountered in the shale matrix because of the presence of nanopores. Numerous apparent-permeability models have been proposed to capture the ensuing non-Darcy flow behavior. However, these models are not readily available in most commercial reservoir simulators, and ignoring these mechanisms can potentially underestimate the overall matrix conductivity. This work implements an explicit coupling strategy for integrating a pressure-dependent apparent-permeability model in reservoir simulation. The numerical models are subsequently used to study the effects of apparent-permeability modeling and natural-fracture distribution on gas production and water loss during flowback. The effects of multiphase-flow functions on fluid retention are also assessed.
A set of 3D reservoir models are constructed using field data obtained from the Horn River shale-gas reservoir. First, stochastic 3D discrete-fracture-network (DFN) models are scaled up into equivalent continuum dual-porosity/dual-permeability models. An apparent-permeability (Kapp) model accounting for contributions of slip flow, Knudsen diffusion, and surface pore roughness is applied at each gridblock. A novel coupling scheme is formulated to facilitate the updating of Kapp after a certain specified time interval, capturing the pressure dependency of the Kapp. The sensitivity of the updating frequency is analyzed.
The results reveal that incorporating these additional flow mechanisms by means of the apparent-permeability formulation could potentially increase the overall gas-production prediction by up to 11%, depending on the average pore radius, reservoir pressure, and several other matrix or fluid properties. The implications of Kapp modeling in water-loss mechanisms are further examined through a set of sensitivity analyses, where the effects of multiphase-flow functions and DFN distributions are systematically investigated. The following interesting findings are observed:
This work offers a novel, yet practical, scheme for representing the pressure-dependent matrix apparent permeability in the flow simulation of shale reservoirs. The proposed method captures the non-Darcy flow behavior caused by the complex transport mechanisms occurring in nanosized pores. Most importantly, this coupling procedure can be implemented in existing commercial reservoir-simulation packages. The results have revealed a few interesting insights regarding the potential implications in fracturing design and estimation of stimulated reservoir volume.
Huang, Hai (Xi’an Shiyou University and Shaanxi Key Laboratory of Advanced Stimulation Technology for Oil & Gas Reservoirs) | Babadagli, Tayfun (University of Alberta and Xi’an Shiyou University) | Chen, Xin (University of Alberta) | Li, Huazhou (University of Alberta and Xi’an Shiyou University) | Zhang, Yanming (Oil & Gas Technology Research Institude of Changqing Oilfield Company)
Water blocking can be a serious problem, causing a low gas production rate after hydraulic fracturing, a result of the strong capillarity in the tight sandstone reservoir aggravating the spontaneous imbibition. Fortunately, chemicals added to the fracturing fluids can alter the surface properties and thus prevent or reduce the water-blocking issue. We designed a spontaneous imbibition experiment to explore the possibility of using novel chemicals to both mitigate the spontaneous imbibition of water into the tight gas cores and measure the surface tensions (STs) between the air and chemical solutions. A diverse group of chemical species has been experimentally examined in this study, including two anionic surfactants (O242 and O342), a cationic surfactant (C12TAB), an alkaline solution of sodium metaborate (NaBO2), an ionic liquid (BMMIM BF4), two nanofluids with aluminum oxide and silicon oxide (Al2O3 and SiO2, respectively), and a series of deep eutectic solvents (DES3-7, 9, 11, and 14). Experimental results indicate that the anionic surfactants (O242 and O342) contribute to low STs but cannot ease the water-blocking issue because they yield a more water-wet surface. The high pH solution (NaBO2), ionic liquid (BMMIM BF-4), and sodium chloride brine (NaCl) significantly decrease the volume of water imbibed to the tight sandstone core through wettability alteration, and C12TAB leads to both ST reduction and an air-wet rock surface, helping to prevent water blocking. The different types of DESs and nanofluids exhibit distinctly different effects on expelling gas from the tight sandstone cores through water imbibition. This preliminary research will be useful in both selecting and using proper chemicals in fracturing fluids to mitigate water-blocking problems in tight gas sandstones.
Injecting water with chemicals to generate emulsions in the reservoir is a promising method in the enhancement of heavy-oil recovery because the formation of oil-in-water (O/W) emulsions significantly reduces oil viscosity. Nanoparticles (NPs) (Pickering emulsions) can be used for this purpose as a cost-effective alternative to expensive surfactants; however, such Pickering emulsions need to be stable for successful applications. The objective of this study is to screen the effective emulsifier for O/W emulsions from a broad range of solid NPs and identify suitable Pickering emulsifying agents (e.g., adjusting pH or salt concentration) that can render emulsions stable at relevant conditions, and to investigate how a range of physical parameters, such as particle concentration, water/oil ratio (WOR), and temperature affect emulsion stability.
Five NPs—including cellulose nanocrystals (CNCs), silica, alumina, magnetite, and zirconia—were tested on their capabilities of stabilizing O/W emulsions through glass vial screening tests under various pH and salinity conditions. The screening results showed that the CNC could become an effective emulsifier by either adjusting pH or salinity. In addition, zeta potential measurements were conducted to explain the observations. The stabilization mechanisms of CNCs were studied through an epifluorescent transmitted microscope showing that the formation of a dense particle layer around the oil droplets, as well as a network in the continuous phase, were the two main mechanisms accounting for the high stability of the emulsions stabilized by CNCs. The effects of particle concentrations on the emulsion stability were studied quantitatively by analyzing the droplet-size distributions calculated by the open-source ImageJ software, with the results showing a sharp decrease in droplet size, followed by a smooth change as the particle concentration increased. For the WOR effect, phase inversion from O/W to water-in-oil (W/O) emulsions was observed when the oil content was more than 0.6. The thermal stability of emulsions was studied both macroscopically by glass bottle tests and microscopically through a microscope, both of which show that the CNC-stabilized emulsions remained thermally stable up to 100°C. The rheological properties of both aqueous dispersions of CNCs and the corresponding O/W emulsions were also measured under various salinity conditions. The results showed that the salinity had a great impact on the viscosity of the CNC suspension and the typical shear-thinning behavior of Pickering emulsions.
This study provides an option to enhance emulsion stability without surfactants, which will reduce the costs and facilitate field applications of emulsion flooding in heavy-oil recovery.
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 hydrogeomechanical 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 hydrogeomechanical effects of bioturbation. Finally, the hydromechanical characteristics of analog IHS were compared with its constituent layers (sand and mud).
The microscopic study showed that the layers’ integration and grain size distributions 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 the 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 nonbioturbated specimens but has negligible effects on its mechanical properties, which remain similar to nonbioturbated specimens. The results also showed that bioturbation had minimal impact on permeability changes during shearing. Lastly, experimental correlations were developed for each of the preceding parameters mentioned.
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.
Phase change plays an essential role in wettability during steam injection, and oil becomes the wetting phase in the steam zone. This study investigates this unfavorable phenomenon using visual data obtained from micromodel experiments and how the wettability can be reversed using chemicals. All measurements were conducted at temperatures up to 200°C on glass-bead micromodels. The models were initially saturated with brine solution and then displaced by two types of mineral oils (450 and 111,600 cp at 25°C). Steam was then constantly injected into the micromodels to evaluate the effect of phase change and wettability status on residual saturation development. Next, chemical additives, screened from the previous contact-angle and thermal-stability measurements, were added to the steam to observe their ability in modifying phase distribution and wettability state. The results showed that phase distribution and residual oil saturation are critically sensitive to the steam phase. At any circumstances, wettability alteration with chemicals was possible. The shape and characteristics of the trapped oil with and without chemicals were identified through micromodel images, and suggestions were made as to the conditions (pressure, temperature, and time to apply during the injection application) at which these chemicals show optimal performance.