Fredriksen, Sunniva B. (University of Bergen) | Alcorn, Zachary P. (University of Bergen) | Frøland, Anders (University of Bergen) | Viken, Anita (University of Bergen) | Rognmo, Arthur U. (University of Bergen) | Seland, John G. (University of Bergen) | Ersland, Geir (University of Bergen) | Fernø, Martin A. (University of Bergen) | Graue, Arne (University of Bergen)
An integrated enhanced-oil-recovery (EOR) (IEOR) approach is used in fractured oil-wet carbonate core plugs where surfactant prefloods reduce interfacial tension (IFT), alter wettability, and establish conditions for capillary continuity to improve tertiary carbon dioxide (CO2) foam injections. Surfactant prefloods can alter the wettability of oil-wet fractures toward neutral/weakly-water-wet conditions that in turn reduce the capillary threshold pressure for foam generation in matrix and create capillary contact between matrix blocks. The capillary connectivity can transmit differential pressure across fractures and increase both mobility control and viscous displacement during CO2-foam injections. Outcrop core plugs were aged to reflect conditions of an ongoing CO2-foam injection field pilot in west Texas. Surfactants were screened for their ability to change the wetting state from oil-wet using the Darcy-scale Amott-Harvey index. A cationic surfactant was the most effective in shifting wettability from an Amott-Harvey index of –0.56 to 0.09. Second waterfloods after surfactant treatments and before tertiary CO2-foam injections recovered an additional 4 to 11% of original oil in place (OIP) (OOIP), verifying the favorable effects of a surfactant preflood to mobilize oil. Tertiary CO2-foam injections revealed the significance of a critical oil-saturation value below which CO2 and surfactant solution were able to enter the oil-wet matrix and generate foam for EOR. The results reveal that a surfactant preflood can reverse the wettability of oil-wet fracture surfaces, lower IFT, and lower capillary threshold pressure to reduce oil saturation to less than a critical value to generate stable CO2 foam.
CO2 Water-Alternating-Gas injection (CO2 WAG), which involves complex phase and flow behaviour, is still a challenging task to simulate and predict accurately. In this paper, we focus specifically on the regime of viscous fingering flow in CO2 WAG in heterogeneous systems because of its importance. We investigated two key physical processes that occur during near-Miscible WAG (nMWAG) processes, namely oil stripping (Mechanism 1, M1) and low-interfacial-tension (IFT) film flow effects (Mechanism 2, M2). The low IFT effects in M2 manifest themselves in an increased mobility of oil phase due to film flow process (discussed below). The importance of properly simulating the interaction of viscous, compositional (M1), and low-interfacial-tension effects (M2) is clearly demonstrated in this study. Our specific aim is to improve the modelling of CO2 displacement in the transition from immiscible to miscible flows in CO2 WAG processes.
We simulated both immiscible and near-miscible CO2 WAG and also continuous CO2 displacements with unfavourable mobility ratios for 1D and 2D systems. 2D heterogeneous permeability fields were generated with certain Dykstra-Parsons coefficients and dimensionless correlation ranges. IFT (σgo) was calculated by the simulator as part of the compositional simulation using the McLeod-Sugden equation. The consequent IFT effects on relative permeability was imposed using two commonly used models, i.e.
We tested various combinations of oil-stripping effects (M1) and IFT effects (M2) to evaluate the potential impact of each mechanism on the flow behaviour such as the local displacement efficiency, the tracking of tracer flow and the ultimate oil recovery. Oil bypassed by viscous fingering/local heterogeneity, can be efficiently recovered by WAG in the cases where both M1 and M2 are taken into account (as opposed to either mechanism being considered alone). Through tracer analysis, we found that a major recovery mechanism in near-miscible displacement was
Alcorn, Zachary P. (University of Bergen) | Fredriksen, Sunniva B. (University of Bergen) | Sharma, Mohan (University of Stavanger) | Rognmo, Arthur U. (University of Bergen) | Føyen, Tore L. (University of Bergen and SINTEF Industry) | Fernø, Martin A. (University of Bergen) | Graue, Arne (University of Bergen)
A carbon-dioxide (CO2) -foam enhanced-oil-recovery (EOR) field pilot research program has been started 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 because of injectivity problems and the difficulty of attributing fluid displacement specifically to CO2 foam. Thus, a comprehensive integrated multiscale methodology is required for project design to better link laboratory- and field-scale displacement mechanisms. This study presents an integrated upscaling approach for designing a miscible CO2-foam field trial, including pilot-well-selection criteria and laboratory corefloods combined with reservoir-scale simulation to offer recommendations for the injection of alternating slugs of surfactant solution and CO2, or surfactant-alternating-gas (SAG) injection, while assessing CO2-storage potential.
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. Tertiary CO2-foam EOR corefloods at oil-wet conditions result in a total recovery factor of 80% of original oil in place (OOIP), with an incremental recovery of 30% of OOIP by CO2 foam after waterflooding. Stable CO2 foam, using aqueous surfactants with a gas fraction of 0.70, provided mobility-reduction factors (MRFs) up to 340 compared with pure-CO2 injection at reservoir conditions. Oil recovery, gas-mobility reduction, producing-gas/oil ratio (GOR), and CO2 utilization at field pilot scale were investigated with a validated numerical model. Simulation studies show the effectiveness of foam to reduce gas mobility, improve CO2 utilization, and decrease GOR.
Andersen, Pål Østebø (University of Stavanger) | Lohne, Arild (International Research Institute of Stavanger) | Stavland, Arne (International Research Institute of Stavanger) | Hiorth, Aksel (University of Stavanger) | Brattekås, Bergit (University of Bergen)
Capillary spontaneous imbibition (SI) of solvent (water bound in gel) from formed polymer gel into an adjacent, oil-saturated porous medium was recently observed in laboratory experiments. Loss of water from the gel by SI might influence the blocking capacity of the gel residing in a fracture, by decreasing its volume, and might contribute to gel failure, often observed in water-wet oil fields.
This work presents an original modeling approach to simulate and interpret spontaneous imbibition of water from Cr(III)-acetatehydrolyzed-polyacrylamide (HPAM) gel into adjacent oil-saturated rock matrix. Simulations were compared to experiments on the core scale, using two different boundary conditions: all faces open (AFO) and two-ends-open free spontaneous imbibition (TEOFSI). Capillary forces enable water (used as gel solvent) to enter the rock matrix. The gel particle network itself is, however, inhibited from entering because of its structure, and remains on the surface of the rock matrix. We developed a theory that describes the gel as a compressible porous medium and describes the flow of water through gel. The polymer structure of the gel is proposed to constitute a gel matrix of constant solid volume. Gel porosity, defined by the volume fraction of solvent, is modeled as a function of pore pressure and gel compressibility. Gel permeability is modeled as function of gel porosity using a Kozeny-Carman approach. The flow equations for the gel and core domains were solved simultaneously by implementing the proposed description into the core-scale simulator IORCoreSim. The gel surrounding the core was discretized and included as a part of the total grid.
The simulated flow of water through and from the gel occurred in a transient manner, driven by the coupled gradients in gel fluid pressure and gel porosity. Gel porosity initially decreased in a layer close to the core surface because of reduced aqueous pressure, and continued to decrease in layers away from the core surface. The propagation rate was controlled by two main gel parameters: First, gel compressibility controlled the pressure gradient within the gel network, and the amount of water transported from the outer part of the gel toward the core surface to balance the pore pressure; and, second, gel permeability limited how fast water could flow within the gel at a given pressure gradient, thus increasing the time scale of the overall imbibition process.
Crosslinked polymers extrude through fractures during placement of many conformance-improvement treatments, as well as during hydraulic fracturing. Dehydration of polymer gel during extrusion through fractures has often been observed and was extensively investigated during recent decades. Injection of highly viscous gel increases the pressure in a fracture, which promotes gel dehydration by fluid leakoff into the adjacent matrix. The present comprehension of gel behavior dictates that the rate of fluid leakoff will be controlled by the gel and fracture properties and, to a lesser extent, be affected by the properties of an adjacent porous medium. However, several experimental results, presented in this work, indicate that fluid leakoff deviates from expected behavior when oil is present in the fracture-adjacent matrix. We investigated fluid leakoff from chromium (Cr)(III)-acetate hydrolyzed polyacrylamide (HPAM) gels during extrusion through oil-saturated, fractured core plugs. The matrix properties were varied to evaluate the effect of pore size, permeability, and heterogeneity on gel dehydration and leakoff rate. A deviating leakoff behavior during gel propagation through fractured, oil-saturated core plugs was observed, associated with the formation of a capillary driven displacement front in the matrix. Magnetic resonance imaging (MRI) was used to monitor water leakoff in a fractured, oil-saturated, carbonate core plug and verified the position and existence of a stable displacement front. The use of MRI also identified the presence of wormholes in the gel, during and after gel placement, which supports gel behavior similar to the previously proposed Seright filter-cake model. An explanation is offered for when the matrix affects gel dehydration and is supported by imaging. Our results show that the properties of a reservoir rock might affect gel dehydration, which, in turn, strongly affects the depth of gel penetration into a fracture network and the gel strength during chase floods.
Spontaneous imbibition is a capillary-dominated displacement process in which a nonwetting fluid is displaced from a porous medium by the inflow of a more-wetting fluid. Decades of core-scale experiments have concluded that spontaneous imbibition occurs by a uniformly shaped saturation front with a rate that scales with the square root of time. The imbibition rate during early stages of spontaneous imbibition (the onset period) has been reported to deviate from the square-root-of-time behavior, although its effect on the imbibition process is not well-understood. Controlled-imbibition tests, presented in this paper, demonstrate that restricted wetting-phase flow during the onset period gives irregular saturation fronts and deviation from the square-root-of-time behavior. The deviation was caused by local variation in porosity and permeability or by a nonuniform wettability distribution, and was directly visualized or imaged by positron-emission tomography (PET). Without knowledge of local flow patterns, the development of irregular saturation fronts cannot be observed; hence, the effect cannot be accounted for, and the development of spontaneous imbibition might be erroneously interpreted as a core-scale wettability effect. Restricted wetting-phase flow at the inlet affects Darcy-scale wettability measurements, scaling, and modeling; our observations underline the need for a homogeneous wettability preference through the porous medium when performing laboratory spontaneous-imbibition measurements.
Sedimentary methane hydrates contain a vast amount of untapped natural gas that can be produced through pressure depletion. Several field pilots have proved the concept with days to weeks of operation, but the longer-term response remains uncertain. This paper investigates the parameters affecting the rate of gas recovery from methane-hydrate-bearing sediments. The recovery of methane gas from hydrate dissociation through pressure depletion was studied at different initial hydrate saturations and different constant production pressures in cylindrical sandstone cores. Core-scale dissociation patterns were mapped with magnetic resonance imaging (MRI), and pore-scale dissociation events were visualized in a high-pressure micromodel. Key findings from the gas-production-rate analysis are that the maximum rate of recovery is only to a small extent affected by the magnitude of the pressure reduction below the dissociation pressure, and that the hydrate saturation directly affects the rate of recovery, where intermediate hydrate saturations (0.30 to 0.50) give the highest initial recovery rate. These results are of interest to anyone who evaluates the production performance of sedimentary hydrate accumulations and demonstrate how important accurate saturation estimates are to prediction of both the initial rate of gas recovery and the ultimate-recovery efficiency.
This paper investigates CO2-foam stabilized with nanoparticles (NP) as an enhanced oil recovery (EOR) agent in carbonate reservoirs with high temperature and salt content. Under these conditions surfactants, widely used to stabilize foams, becomes unstable and will not generate strong foam. Our objective is to use NP as a stabilizing agent for surfactant based foam through an integrated process where the surfactants generate foam and the NP stabilizes the foam. Aqueous NP solutions (1500 ppm) were injected through porous media at high temperature (120 °C) to evaluate solution stability for a range of brine salinities, pH and resident times. Stable solutions were subsequently co-injected with supercritical CO2 to create foam and increase the apparent viscosity of CO2.
High temperature and salinity are challenging for most surfactants; however it is a common reservoir condition in many carbonate fields. The nanoparticles had a high degree of stability with little precipitation or gelation in the presence of salt content as high as 23 wt.% NaCl as long as the pH was sufficiently low. The stability of the nanoparticles decreased with increased temperature, leading to gelation and injectivity problems in limestone core samples when the injection water had native pH. The problem was less pronounced in sandstone core samples. Nanoparticle stability increased with decreasing pH, and it was possible to achieve steady-state conditions at 120 °C for longer periods of time. CO2 was shown to be a viable stabilizing agent by decreasing the pH of the injection brine and had the added benefit of creating stable foam for enhanced oil recovery. This is particularly important in limestones and carbonates where the pH of the injection water tends to increase as it interacts with the rock. The nanoparticles can be used alone or in combination with surfactants to increase the stability the surfactant generated foam. Surfactant based foam is generally more effective at generating foam, but is less stable at harsh conditions than nanoparticles.
The wave equation in the frequency domain can be transformed into to an equivalent integral equation of the Lippmann-Schwinger type, based on a decomposition of the wave operator into an arbitrary reference medium and a corresponding perturbation. The Lippmann-Schwinger equation can in principle be solved exactly via the inversion of a large operator (or matrix) or iteratively via the traditional Born series. However, operator inversion can be costly and the traditional Born series is only guaranteed to converge for small perturbations. We here use renormalization group (RG) theory to derive a novel scattering series solution of the Lippmann-Schwinger equation which is guaranteed to converge for arbitrary (large) perturbations. Our RG approach is based on the use of an auxillary set of time-dependent scattering potentials, which gradually evolves toward the real physical scattering potential. We show that the corresponding auxillary Green functions satisfies a general RG equation, and we derive an ordinary differential equation for the time-evolution of the auxillary time-dependent Green functions by using a Lie-group approach to the RG flow equation. We focus on convergence issues, but the computational cost can be significantly smaller than than the cost of calculating the Green function via exact matrix inversion, depending on the time-dependency assumed for the the auxillary scattering potential. The results of a series of numerical experiments based on the SEG/EAGE salt model confirm that the renormalized scattering series converges when the traditional Born series diverges. These ideas and results will hopefully find future use within nonlinear inverse as well as direct scattering.
Presentation Date: Wednesday, October 17, 2018
Start Time: 1:50:00 PM
Location: 211A (Anaheim Convention Center)
Presentation Type: Oral
Dynamic ray tracing is an efficient and reliable method for computation of geometrical spreading along a given reference ray. The method yields first-order derivatives of perturbations in position/slowness and therefore enables first-order extrapolation of these quantities to points in the close (paraxial) neighborhood of the reference ray. Knowledge of such first-order perturbation derivatives readily gives coefficients for second-order extrapolation of traveltime into the paraxial region. We extend conventional dynamic ray tracing to include continuation of higher-order perturbation derivatives along the reference ray. The motivation is to provide a robust and more accurate extrapolation of geometrical spreading and other amplitude-related quantities, for applications in the kernel operations of modeling, mapping, and imaging. Important by-products of the method are coefficients for higher-order expansion of traveltime. Volumetric properties of the medium are represented using quintic (fifth-order) B-spline functions. The first numerical results for anisotropic media, based on a heterogeneous 3D model with constant elliptical anisotropy, are very promising with respect to the foreseen applications.
Presentation Date: Tuesday, October 16, 2018
Start Time: 1:50:00 PM
Location: 205A (Anaheim Convention Center)
Presentation Type: Oral