Vik, Bartek (Uni Research, CIPR) | Kedir, Abduljelil (Uni Research, CIPR) | Kippe, Vegard (Statoil ASA) | Sandengen, Kristian (Statoil ASA) | Skauge, Tormod (Uni Research, CIPR) | Solbakken, Jonas (Uni Research, CIPR) | Zhu, Dingwei (Uni Research, CIPR)
Polymer injection for viscous oil displacement has proven effective and gained interest in the recent years. The two general types of EOR polymers available for field applications, synthetic and biological, display different rheological properties during flow in porous media. In this paper, the impact of rheology on viscous oil displacement efficiency and front stability is investigated in laboratory flow experiments monitored by X-ray.
Displacement experiments of crude oil (~500cP) were performed on large Bentheimer rock slab samples (30×30cm) by secondary injection of viscous solutions with different rheological properties.
Specifically, stabilization of the aqueous front by Newtonian (glycerol and shear degraded HPAM) relative to shear thinning (Xanthan) and shear thickening (HPAM) fluids was investigated.
An X-ray scanner monitored the displacement processes, providing 2D information about fluid saturations and distributions. The experiments followed near identical procedures and conditions in terms of rock properties, fluxes, pressure gradients, oil viscosity and wettability.
Secondary mode injections of HPAM, shear-degraded HPAM, xanthan and glycerol solutions showed significant differences in displacement stability and recovery efficiency. It should be noted that concentrations of the chemicals were adjusted to yield comparable viscosity at a typical average flood velocity and shear rate.
The viscoelastic HPAM injection provided the most stable and efficient displacement of the viscous crude oil. However, when the viscoelastic shear-thickening properties were reduced by pre-shearing the polymer, the displacement was more unstable and comparable to the behavior of the Newtonian glycerol solution.
Contrary to the synthetic HPAM, xanthan exhibits shear thinning behavior in porous media. Displacement by xanthan solution showed pronounced viscous fingering with a correspondingly early water breakthrough.
These findings show that at adverse mobility ratio, rheological properties in terms of flux dependent viscosity lead to significant differences in stabilization of displacement fronts. Different effective viscosities should arise from the flux contrasts in an unstable front.
The observed favorable "viscoelastic effect", i.e. highest efficiency for the viscoelastic HPAM solution, is not linked to reduction in the local Sor. We rather propose that it stems from increased effective fluid viscosity, i.e. shear thickening, in the high flux paths.
This study demonstrates that rheological properties, i.e. shear thinning, shear thickening and Newtonian behavior largely impact front stability at adverse mobility ratio in laboratory scale experiments. Shear thickening fluids were shown to stabilize fronts more effectively than the other fluids. X-ray visualization provides an understanding of oil recovery at these conditions revealing information not obtained by pressure or production data.
In this paper we investigate the contribution of capillary and viscous cross-flow to oil recovery during secondary polymer flooding. Cross-flow can be an important mechanism in oil displacement processes in vertically communicating stratified reservoirs. Using polymers will change the balance of these contributions. Previous numerical investigations have shown that the amount of viscous cross-flow is controlled by the layer permeability contrast and a dimensionless number that characterises the combined effects of water, polymer and oil viscosities. The highest viscous cross-flow values were observed during favourable mobility ratio floods in reservoirs with a layer permeability ratio close to 3.
The purpose of the laboratory study was to validate previous numerical studies of cross-flow performed using commercial reservoir simulators. A series of experiments were performed in glass beadpack using analogue fluids comprising water, glycerol solution (to represent the polymer) and paraffin oil. All porous medium and fluid properties (including relative permeabilities and capillary pressure curves) needed for the numerical simulations were determined independently of the displacement experiments. Two beadpacks were constructed of two layers of different permeabilities parallel to the principal flow direction. In one of the packs a barrier was placed between the two layers to prevent cross-flow. Comparing the recoveries from these enabled us to quantify the contribution of cross-flow to oil recovery. The mobility ratios examined in the experiments ranged from very unfavourable to very favourable. The layer permeability ratio was approximately 2.5.
Good agreement was obtained between experiments and simulations, without the need for history matching, demonstrating that the simulation correctly captures the physics of crossflow. The incremental oil recoveries attributable to cross-flow and mobility control both fell within the error margins of the experimentally calculated values. The experiments showed that capillary cross-flow dominated over viscous cross-flow on laboratory length scales. Having validated the simulator, we then used it to show that wettability (with and without capillary pressure) can modify the impact of cross-flow on oil recovery.
Skauge, T. (CIPR Uni Research) | Skauge, A. (CIPR Uni Research) | Salmo, I. C. (CIPR Uni Research) | Ormehaug, P. A. (CIPR Uni Research) | Al-Azri, N. (PDO) | Wassing, L. M. (Shell Global Solutions International BV) | Glasbergen, G. (Shell Global Solutions International BV) | Van Wunnik, J. N. (Shell Global Solutions International BV) | Masalmeh, S. K. (Shell Global Solutions International BV)
Polymer injectivity is a critical parameter for implementation of polymer flood projects. An improved understanding of polymer injectivity is important in order to facilitate an increase in polymer EOR implementation. Typically, injectivity studies are performed using linear core floods. Here we demonstrate that polymer flow in radial and linear models may be significantly different and discuss the concept in theoretical and experimental terms.
Linear core floods using partially hydrolyzed polyacrylamides (HPAM) were performed at various rates to determine in-situ viscosity and polymer injectivity. Radial polymer floods were performed on Bentheimer discs (30 cm diameter, 2-3 cm thickness) with pressure taps distributed between a central injector and the perimeter production well. The in-situ rheological data are also compared to bulk rheology. The experimental set up allowed a detailed analysis of pressure changes from well injection to production line in the radial models and using internal pressure taps in linear cores.
Linear core floods show degradation of polymer at high flow rates and a severe degree of shear thickening leading to presumably high injection pressures. This is in agreement with current literature. However, the radial injectivity experiments show a significant reduction in differential pressure compared to the linear core floods. Onset of shear thickening occurs at significantly higher flow velocities than for linear core floods. These data confirm that polymer flow is significantly different in linear and radial flow. This is partly explained by the fact that linear floods are being performed at steady state conditions, while radial injections go through transient (unsteady state) and semi-transient pressure regimes.
History matching of polymer injectivity was performed for radial injection experiments. Differences in polymer injectivity are discussed in the framework of theoretical and experimental considerations. The results may have impact on evaluation of polymer flood projects as polymer injectivity is a key risk factor for implementation.
Alkali-Surfactant-Polymer (ASP) is one of the most attractive chemical EOR methods. In properly designed ASP formulations, the alkali-surfactant provides ultralow interfacial tension (IFT) between drive aqueous fluid and the displaced oil whereas polymer ensures a good mobility control. Nevertheless, the efficiency of ASP can be much less than expected under various reservoir conditions including low permeability, high temperature, high formation brine salinity, presence of divalent cations (Ca+2, Mg+2) in the formation brine. This is due to polymer degradation or precipitation, low injectivity, scaling in well and surface equipment. This paper reports an experimental study of new a chemical EOR which has the potentially to overcome above drawbacks. The chemical formulation consists of the combination of no-polymeric viscosity enhancement compound and a blend of two surfactants. The performance of this chemical formulation was evaluated by a series of core-flood tests on Bentheimer sandstone cores, under stable gravity conditions, with the aid of X-ray Computed Tomography. A significant reduction of the residual oil saturation was observed by constructing the capillary desaturation curves (CDC) suggesting that proposed formulation is potentially a rather good chemical EOR agent.
New fracturing techniques, such as hybrid fracturing (Sharma et al. 2004), reverse-hybrid fracturing (Liu et al. 2007), and channel (HiWAY) fracturing (Gillard et al. 2010), have been deployed over the past few years to effectively place proppant in fractures. The goal of these methods is to increase the conductivity in the proppant pack, providing highly conductive paths for hydrocarbons to flow from the reservoir to the wellbore. This paper presents an experimental study on proppant placement by use of a new method of fracturing, referred to as alternate-slug fracturing. The method involves alternate injection of low-viscosity and high-viscosity fluids, with proppant carried by the low-viscosity fluid. Alternate-slug fracturing ensures a deeper placement of proppant through two primary mechanisms: (i) proppant transport in viscous fingers, formed by the low-viscosity fluid, and (ii) an increase in drag force in the polymer slug, leading to better entrainment and displacement of any proppant banks that may have formed. Both these effects lead to longer propped-fracture length and better vertical placement of proppant in the fracture. In addition, the method offers lower polymer costs, lower pumping horsepower, smaller fracture widths, better control of fluid leakoff, less risk of tip screenouts, and less gel damage compared with conventional gel fracture treatments. Experiments are conducted in simulated fractures (slot cells) with fluids of different viscosity, with proppant being carried by the low-viscosity fluid. It is shown that viscous fingers of low-viscosity fluid and viscous sweeps by the high-viscosity fluid lead to deeper placement of proppant. Experiments are also conducted to demonstrate slickwater fracturing, hybrid fracturing and reverse-hybrid fracturing. Comparison shows that alternate-slug fracturing leads to deepest and most-uniform placement of proppant inside the fracture. Experiments are also conducted to study the mixing of fluids over a wide range of viscosity ratios. Data are presented to show that the finger velocities and mixing-zone velocities increase with viscosity ratio up to viscosity ratios of approximately 350. However, at higher viscosity ratios, the velocities plateau, signifying no further effect of viscosity contrast on the growth of fingers and mixing zone. The data are an integral part of design calculations for alternate-slug fracturing treatments.
New fracturing techniques such as hybrid fracturing (Sharma et. al., 2004), reverse hybrid fracturing (Liu et. al., 2007) and channel (HiWAY) fracturing (Gillard et al. 2010) have been deployed over the past few years to effectively place proppants in fractures. The goal of these methods is to generate a network of open channels within the proppant pack, providing highly conductive paths for hydrocarbons to flow from the reservoir to the wellbore. This paper presents an experimental study on proppant placement using a new method of fracturing, referred to as Alternate-Slug fracturing, which involves alternate injection of low viscosity and high viscosity fluids into the fracture. Alternate-slug fracturing ensures deeper placement of proppants through two primary mechanisms: (a) proppant transport in viscous fingers formed by the low viscosity fluid and (b) an increase in drag force in the polymer slug leading to better entrainment and displacement of any proppant banks that may have formed. Both these effects lead to longer propped fracture length and better vertical placement of proppants in the fracture. In addition the method offers lower polymer costs, lower pumping horsepower, smaller fracture widths, better control of fluid leakoff and less gel damage compared to conventional gel fracs.
Experiments are conducted in simulated fractures (slot cells) to study the mixing of fluids over a wide range of viscosity ratios. Data is presented to show that the finger velocities and mixing zone velocities increase with viscosity ratio up to viscosity ratios of about 350 and the trend is consistent with Koval's theory. However, at higher viscosity ratios the mixing zone velocity values plateau signifying no further effect of viscosity contrast on the growth of fingers and mixing zone. Fluid elasticity is observed to slow down the growth of fingers and leads to growth of multiple thin fingers as compared to a single thick dominant finger in less elastic fluids.
Experiments are conducted with fluids of different viscosity and elasticity, with proppants being carried by the low viscosity fluid. It is shown that the injection rate, slug size and viscosity ratio can be used to control the geometry of the fingers created and, therefore, the proppant distribution in the fracture. The non-uniform placement of proppant in the viscous fingers leads to the creation of high permeability paths in the proppant pack.
Ionizing electron particles were used as an efficient means of delivering energy to heavy hydrocarbon molecules. Although heavy oil reserves are known as rich sources of energy, their contribution to the energy market has been impacted by the fact that the conventional thermal or catalytic upgrading and visbreaking methods always demand a considerable energy and money investment. Therefore, application of potential alternatives with lower operating costs and higher process throughput appears to be extremely crucial in such a competitive market. In this research, high-energy electron processing technology was offered as a remedy to reduce the viscosity of heavy petroleum samples. Irradiated fluids exhibited lower viscosities than thermally cracked samples. Moreover, reaction temperature was observed to have a substantial influence on radiolysis process. At relatively low temperatures, radiation-induced upgrading stays inactive without any contribution to the viscosity reduction process. However, as the temperature exceeds a specific threshold, radiation-induced chain reactions become activated, decreasing the viscosity of irradiated samples. At the end, we have investigated the effect of different additives upon radiolysis of hydrocarbon molecules. Interestingly, radiolytic reactions were completely suppressed by some of these additives.
Padekar, Bharat S. (IITB-Monash Research Academy) | Singh Raman, R.K. (Department of Mechanical & Aerospace Engineering & Department of Chemical Engineering Monash University) | Raja, V.S. (Department of Metallurgical Engineering and Materials Science Indian Institute of Technology Bombay) | Paul, Lyon (Magnesium Elektron Ltd)
Using two methods, we obtained measurements of elastic moduli for Berea sandstone at exploration seismic frequencies under dry, full, and partial saturation conditions. We refer to one method as indirect, since lower (0.008 – 0.8 Hz) than seismic frequencies are used, but by controlling fluid (glycerol) viscosity with temperature, the results can be scaled up to higher frequencies (0.1 – 1000 Hz). The second method involves measuring brine saturated core samples directly at seismic frequencies (5–50 Hz). The results between the two methods compare well, which validates the indirect methodology and gives more confidence overall to both results. These measurements are of value due to recent interest in the oil industry in low frequency velocity dispersion as a gas indicator. Such measurements, of which relatively few are done at seismic frequencies, can help constrain theoretical models.