Search

This paper presents a numerical investigation of hydraulic fracturing in oil sands during cold water injection by considering the aspects of both geomechanics and reservoir fluid flow. According to previous studies, the low shear strengths of unconsolidated or weakly consolidated sandstone reservoirs significantly influence the hydraulic fracturing process. Therefore, classical hydraulic fracture models cannot simulate the fracturing process in weak sandstone reservoirs. In the current numerical models, the direction of a tensile fracture is predetermined based on in situ stress conditions. Additionally, the potential transformation of a shear fracture into a tensile fracture and the potential reorientation of a tensile fracture owing to shear banding at the fracture tip have not yet been addressed in the literature. In this study, a smeared fracture technique is employed to simulate tensile and shear fractures in oil sands. The model used combines many important fracture features, which include the matrix flow, poroelasticity and plasticity modeling, saturation-dependent permeability, gradual degradation of the oil sands as a result of dilative shear deformation, and the tensile fracturing and shear failure that occur with the simultaneous enhancement of permeability. Furthermore, sensitivity analyses are also performed with respect to the reservoir and geomechanical parameters, including the apparent tensile strength and cohesion of the oil sands, magnitude of the minimum and maximum principal stress, absolute permeability and elastic modulus of the oil sands and ramp-up time. All these analyses are performed to clarify the influences of these parameters on the fracturing response of the oil sands.

To solve the problems such as high denstiy, foam instability, low compressive strength, high porosity and poor durability associated with conventional foam cements, a novel colloidal gas aphron (CGA) based foam cement system was investigated and tested for properties. CGA is used in a base slurry as the foam component and the recipe was optimized with hollow sphere and micro-silica in terms of particle size distribution (PSD). Porosity, permeability, strength, brittleness, elasticity, free water content, foam stability and density tests on the CGA based foam cement system were carried out to evaluate the performance of the system. According to the experiment results, at the foam proportion of 10%, the cement density was reduced to 1 040 kg/m3, and stable microfoam net structure not significantly affected by high temperature and high pressure was formed in the cement system. The optimal CGA based foam cement has a free water content of 0%, porosity of 24%, permeability of 0.7×10−3 μm2, low elasticity modulus, high Poisson's ratio, and reasonable compressive strength, and is more elastic and flexible with capability to tolerate regional stresses. Key words: colloidal gas aphron, foam cement, light weight cement, compressive strength, well cementing

Fouling is a critical issue faced by the chemical and oil industries in various operation processes, which has negative impact on the operational efficiency and generates significant economic losses, technical and environmental challenges. Investigating the interaction mechanisms between foulants (e.g., fine solids, asphaltenes) and different substrates is of both fundamental and practical importance in understanding the fouling mechanisms in chemical/petroleum engineering processes and developing antifouling strategies. In this work, atomic force microscope (AFM) colloidal probe technique was employed to directly quantify the interactions between silica or asphaltenes and selected substrates (i.e., carbon steel L80 and L80 with electroless nickel-phosphorus (EN) coating) in aqueous solutions. The effects of salinity, pH and presence of divalent ions (e.g., Ca2+) on the surface interactions were investigated. The obtained force profiles showed that the interactions between silica or asphaltenes and L80 surface were more attractive than that between silica or asphaltenes and EN coating, in NaCl solutions. Bulk fouling tests in silica and asphaltenes-coated silica suspensions revealed that significant fouling of silica and asphaltenes were found on L80 substrates, while EN coating exhibited excellent antifouling performance. Our results provide useful insights into the fundamental understanding of the fouling mechanism of fine solids and asphaltenes, and the development of novel effective antifouling coatings in chemical and oil industries.

A smeared fracture type hydraulic fracture simulator is developed through numerical coupling between an in-house reservoir simulator and a geomechanical commercial software (FLAC2D). The new package falls within the category of partially decoupled model and is versatile, flexible and efficient. This approach can be used to couple any other advanced commercial fluid flow or geomechanical simulators for an accurate description of the initiation and propagation of hydraulic fractures. The paper contains a discussion of the partial coupling technique to link fluid flow and geomechanical calculations in modeling fracture initiation and propagation. The models use a common gridblock for the fracture and reservoir and use the deformation calculations to update the porosity and permeability. The method captures the interactive effects of the fracture on reservoir fluid flow and formation geomechanics through stress dependent permeability and porosity. The developed smeared fracture model can capture both tensile and shear fractures in the formation. Major features of this model include modeling poroelasticity and plasticity, matrix flow, shear and tensile fracturing with concomitant permeability enhancement, saturation-dependent permeability, stress-dependent stiffness and gradual degradation of oil sands due to dilatant shear deformation . The model has been applied to numerically simulate field size hydraulic fracturing in oil sands during cold-water injection to show the predictive capability of the simulator.

Steam Assisted Gravity Drainage (SAGD) is the primary thermal recovery technology currently employed to extract heavy oil and high-viscosity bitumen from Alberta oil sands. In the near-wellbore region, the initial stresses are nearly zero, and as the SAGD chamber grows, the stresses tend to build up due to the thermal expansion of the formation. Also, melting of the bitumen and subsequent loss of the bonding between the grains leads to the collapse of the gap between the formation and sand control liner over time. The result will be effective stress buildup and gradual compaction of the oil sands around the liner. Slotted liners have been extensively used as a sand control device in SAGD wells. Slotted liners must allow free flow through the slots with minimal plugging and acceptable amounts of sand production. In our study, large-scale unconsolidated sand was packed over a multi-slot coupon of the slotted liner. The sand-pack was subjected to several stress conditions corresponding to the evolving stress conditions during the life cycle of a SAGD producer well. The testing program employed several multi-slot coupons to examine the flow performance under typical encountered stresses in SAGD wells. Cumulative produced sand was measured at the end of testing as an indicator of the sand control performance. The permeability evolution of the sand in the near-coupon zone was calculated by measurements of pressure differentials and considered as a measure of screen flow performance. Fines/clay concentration along the sand-pack was also quantified after the test to investigate the fines migration, a phenomenon which is considered to be the main reason for reduced wellbore productivity. Experimental results show that the liner performance is significantly affected by the normal stress buildup on the liner. Experimental observations indicate sand-pack compaction due to the increase of effective stress around the liner leads to a lower porosity and permeability. The situation near the liner is further complicated by the fines accumulation that results in pore plugging and further permeability reduction. When it comes to sanding, however, higher stresses help stabilize the sand bridges behind the slots, leading to less sand production. As for the design criteria, the lower and upper bounds of the slot size are governed by plugging and sand production, respectively. Considering the stress effect on plugging and sanding, testing data indicate that both the lower and upper bounds should be revised to larger slot aperture sizes.

Previous studies showed that the fouling materials strongly affect the plugging of sand control devices during the oil production, thereby reducing oil productivity index drastically. In this study, we investigate how the compressive and tensile strengths of fouling materials affect the cleaning performance of shock waves generated by an electrohydraulic stimulation (EHS) tool. First, we synthetically plug wire-wrapped screens using different class G cement slurries widely used in oil fields. Silica, calcite, clay, and organic carbon powder as additives are mixed with the cement at different concentrations. Next, we evaluate the compressive and tensile strengths of the cured cement samples by performing uniaxial compressive strength (UCS) and Brazilian tests. Finally, the cleaning performance of the EHS tool is evaluated for plugged wire-wrapped screens. The UCS and Brazilian tests results show that the presence of additives changes the mechanical properties of cement samples. The compressive and tensile strengths of cement samples prepared with silica are found to be higher than those prepared with calcite and clay. Besides, the results of the pulsing stimulation treatment performed by the EHS tool show that the cleaning performance of the EHS tool for the wire-wrapped screens plugged with cement and carbon powder is the highest among all samples as cement samples with carbon powder represent the weakest mechanical properties (UCS and tensile strengths) among all samples. This study provides valuable insights into understanding the effect of shock waves on cleaning the plugged wire-wrapped screens. The results also enable production engineers to better plan for the treatment of damaged wells.

A central issue in hydraulic fracturing treatment in petroleum wells is the transport of proppant particles by the injection fluid. In this paper, we present an innovative proppant transport model in a fixed rectangular- and elliptic-shaped slots. The proposed model is an improvement to the current modeling of proppant transport by applying a non-oscillatory numerical scheme which has high accuracy everywhere in solution domain, even close to the steep gradients. In addition, inertia, fracture wall, and concentration effects on proppant settling along with slurry evolution as a function of proppant concentration has been considered. This paper introduces the mathematical equations that govern the proppant transport phenomenon and discusses special front capturing numerical techniques, boundary conditions, coupling between proppant and slurry mass conservation equations and time stepping restrictions required for the solution stability. We incorporated published correlations obtained from proppant transport laboratory experiments in our numerical model to better capture the physics of the problem. 5th- order WENO scheme was used to avoid oscillation and diffusion at the proppant front since traditional finite difference discretization was found to be insufficient in solving the hyperbolic transport partial differential equations. Results show that the technique used in this study can capture the proppant distribution with minimum oscillation and diffusion. A series of sensitivity analysis was conducted to explore the legitimacy of these assumptions and to provide guidelines that allow more accurate predictions of the proppant and fluid transfer. Numerical results are presented to show how proppant distribution is impacted by the injection fluid viscosity, density difference between proppant particles and injection fluid, proppant size, and fluid flow injection rate. Results of the sensitivity analysis illustrate the significance of choosing appropriate viscosity of the injection fluid as small changes in the viscosity may cause noticeable effects on the concentration distribution. In addition, we found that variation of proppant size and density within a reasonable range have a modest effect on proppant concentration distribution. Furthermore, we also investigated the amount of gravity driven vertical motion of proppant which is driven by density differences (convection) and compare it to a second gravity driven motion which is proppant settlement. Both of these two well recognized mechanisms can occur inside a fracture during proppant placement, however, the importance of each mechanism as a function of proppant injection design parameters is not fully understood.

The effects of Ca2+ on the CO2 corrosion behavior and film characteristics of N80 carbon steel and electroless Ni–P coating at high temperature and high pressure were investigated by immersion tests, in-situ electrochemical measurements, surface characterization techniques and water chemistry analysis. The results demonstrate that the corrosion of N80 steel is significantly influenced by Ca2+ concentration, however Ni–P coating exhibits exceptional corrosion resistance regardless of Ca2+ concentration. The microstructure and compactness of FeCO3 corrosion film is altered with the increased incorporation of Ca2+, thereby affecting the electrolyte penetration and the corrosion rate consequently. The added Ca2+ also impacts the water chemistry of the aqueous phase, postponing the FeCO3 precipitation. Meanwhile, the superb corrosion resistance of Ni–P coating is owing to the protection of the formed NiO/Ni(OH)2 film and the absence of scale formation.

Fouling phenomena are commonly observed in oil production processes, which have caused many challenging issues. Many previous studies focused on fouling in aqueous environment. However, the characterization of foulants and underlying interaction mechanism in organic media still remain limited, which is of fundamental and practical importance. In this work, the foulants on slotted liner samples were characterized, which have served in an oil wellbore based on steam-assisted gravity drainage (SAGD) operation for about six months. The foulants were demonstrated to be fine mineral solids (e.g., silica) and organic materials (e.g., asphaltenes). Atomic force microscope (AFM) colloidal probe technique was employed to quantify the interaction forces of silica particles or asphaltenes with carbon steel (L80) substrates with or without electroless nickel-phosphorus (EN) coating in organic media. The results demonstrated that the corrosion on L80 surface could significantly enhance the adhesion with silica particles and asphaltenes, aggravating the fouling phenomena; while the EN coating could effectively eliminate the corrosion and show good antifouling property. Quartz crystal microbalance with dissipation monitoring (QCM-D) technique was applied to investigate the dynamic adsorption behaviors of asphaltenes on iron (a major component of L80) and EN coating surfaces. The QCM-D results showed that much less asphaltenes were adsorbed on EN coating than that on iron, which agrees well with the force measurements. This work provides useful insights on the fouling processes and fundamental surface interaction mechanisms of fine solids, asphaltenes and substrates in oil, with implications on developing effective antifouling strategies (e.g., functional coatings) in oil production.

The electroless Ni-Mo-P/Ni-P composite coating was applied on N80 carbon steel, and the effects of Mo addition and heat treatment on the corrosion resistance enhancement in CO2/H2S/Cl− brine were studied by electrochemical measurements and surface analysis techniques. The Mo addition in the as-deposited Ni-P coating causes the microstructural transformation from amorphous to crystalline due to the reduced P content, thereby suffering severe corrosion. The impaired corrosion performance of as-deposited Mo-incorporated coating is also originated from the absence of the oxide film on the coating surface. Nonetheless, the heat-treated Ni-Mo-P/Ni-P coating exhibits desirable corrosion resistance, which is reflected by the outstanding corrosion inhibition efficiency (η = 96.1%). Heat treatment facilitates the formation of Ni4Mo phase and more importantly, the growth of an oxide film consisting of nickel and molybdenum oxides (H2S-immuned MoO3) with better passivation properties, which accounts for the remarkable corrosion resistance improvement.

Repassivation time (tre) is a significant parameter when evaluating the repassivation property of material. Herein, we propose a new method to obtain tre by first theoretically unifying the repassivation current–time (i(t)) function for common film growth models, subsequently simplifying the unified i(t) function based on single particle impingement data, then deriving the completed repassivation current expression corresponding to tre using mathematical approximation methods, and finally verifying this method via comparing the obtained tre of three materials. The newly proposed method is reliable, universal and simple to compare repassivation properties of different materials without curve fitting and considering film growth mechanism.

The erosion-enhanced corrosion behavior of electroless Ni–P coating was investigated by single particle impingement coupled with in-situ electrochemical measurements. The transient anodic dissolution of Ni–P coating induced by the single particle impingement is enhanced with the rising impact velocity, followed by a rapid repassivation that obeys a bi-exponential decaying law. The coating demonstrates a good erosion-corrosion resistance due to its strong capability of repassivation that is scarcely affected by the changing hydrodynamics under the test conditions. The erosion-enhanced corrosion rate of Ni–P coating in flowing slurry is well predicted based on the repassivation kinetic parameters determined from single particle impingement.

The corrosion behavior of J55 carbon steel pipe was investigated in a water production well environment in the Athabasca oil sands reservoir. The corrosion morphologies and the chemical compositions of corrosion products were examined by surface analysis techniques. The protection performance of the formed corrosion scales was evaluated using electrochemical measurements. The results show that severe erosion corrosion occurs on the inner wall of the pipe and causes a significant thinning, which is the dominant reason for the pipe failure. Likewise, the failure of the thread zone is originated from the severe corrosion of inner wall as well. Localized corrosion of carbon steel occurs in the welding zone because of the galvanic effect between stainless steel and carbon steel. Furthermore, the distributions of corrosion products on the inner wall are notably affected by the flow. Dense and thick Ca-containing corrosion scales act as a physical barrier layer and prevent the steel from further corrosion, whereas localized corrosion occurs in the regions with loose and thin corrosion scales.