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.
Knowledge of dispersion and attenuation in sedimentary rocks is important for understanding variations in seismic properties of reservoirs. These variations are often related to the presence of fluids in the pore space of rocks. In most sedimentary rocks saturated with fluid characterized by low mobility, which can stem either from low intrinsic permeability or from high fluid viscosity, relative motion between pore fluid and a rock skeleton makes a significant impact on acoustic wave attenuation and dispersion of the elastic moduli of rocks at seismic frequencies. But our current understanding of seismic velocity dispersion and attenuation in saturated rocks is limited due to a lack of laboratory data obtained at seismic frequencies.
We present the results of the laboratory measurements of elastic and anelastic parameters of dry and glycerol saturated Berea sandstone (71 mD permeability, 19 % porosity) conducted at seismic frequencies. The experiments were performed with a low-frequency laboratory apparatus designed to measure the complex Young’s moduli and extensional attenuation of rocks at seismic frequencies. The apparatus operates at confining pressures from 0 to 70 MPa and strain amplitudes from 10-8 to 10-6. The elastic moduli and extensional attenuation of dry and glycerol-saturated sandstone were measured at a differential pressure of 10 MPa at two temperatures of 23 and 31 0C. Peaks of attenuation in the glycerol-saturated sample were found at frequencies of ~0.6 Hz (230C) and ~1.5 Hz (310C). Our analysis shows that the quantitative relationship between the extensional attenuation and the Young’s modulus measured for the glycerol-saturated sandstone is consistent with the causality principle presented by the Kramers-Kronig relations.
It has been demonstrated (Batzle et al., 2006), that mobility of pore fluids in rocks, which is defined as the ratio of rock permeability to fluid viscosity, ensures fluid pressure deviations amongst the pores when a seismic wave passes. As a result the seismic properties can be significantly influenced by the ability of fluid to move within the pores. For the rocks with low-mobility fluid the pore pressure can be out of equilibrium even at seismic frequencies. However, most laboratory measurements are limited to ultrasonic techniques which operate in the megahertz range. Literature on seismic-frequency laboratory measurements of the acoustic properties of reservoir rocks saturated with fluid having low mobility is relatively sparse. Batzle et al. (2006) studied attenuation and dispersion for water-, brine- and glycerol- saturated sedimentary rocks in the frequency range of 5 Hz to 800 kHz and demonstrated that the Gassmann theory might not be always applicable to the rocks saturated with low-mobility fluids even within the seismic band. Adam and Otheim (2013) measured dry and saturated with liquid CO2 and water low-permeability basalts in the seismic (2-300 Hz) and ultrasonic (~0.8 MHz) frequency ranges at differential pressures of 3.4 to 17.2 MPa and found that the bulk moduli of saturated rocks at frequencies greater than 20 Hz are not consistent with the Gassmann theory. The measurements conducted by Mikhaltsevitch et al. (2014) on dry and water saturated low-permeability (0.7 mD and 1.1 mD) sandstones at differential pressures of 9 and 23 MPa revealed considerable extensional attenuation and dispersion of the bulk moduli in the seismic frequency range. These results demonstrate that for low-permeability rocks the low-frequency limit of acoustic wave dispersion can be below below the seismic frequency range and the Gassmann theory cannot be applied at seismic frequencies.
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.
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.
Most thermal heavy oil recovery methods entails changes of pore fluid, pressure and temperature which in turn induce complex changes in the elastic properties of reservoirs that are in general unconsolidated or weakly consolidated porous rocks. In this paper, laboratory measurements of velocities and attenuations under different conditions of temperature and stress were performed on samples of a weakly consolidated reconstituted sandstone saturated with various fluids (air, water and glycerol). The sample investigated is representative of weakly cemented sandstone reservoirs with high porosity and permeability. The experimental results demonstrate the strong impact of the nature of the pore fluid on the compressional and shear wave velocities and attenuations. The influence of temperature and stress are discussed, together with the wave dispersion mechanisms.
Seismic techniques such as 2D or 3D seismic reflection surveying, sonic well-logging, vertical seismic profiling (VSP), among others, are used in petroleum industry both for reservoir characterization and for production monitoring. The seismic parameters of interest are the intrinsic velocities and attenuations. Many studies have been conducted on changes in wave velocities associated with oil production [1, 2, 3, 4]. The experimental determination of attenuation is more difficult than the measurement of velocities [5, 6], resulting in a very limited amount of available data in this area. Moreover, there is a need of laboratory measurements of the wave velocities and attenuations under various conditions of temperature, pore pressure and fluid saturation so as to determine the changes in rock properties resulting from oil production. The purpose of this paper is to present some data on the dependency of both P-wave and S-wave velocities and attenuations on the pore fluid, the stress and temperature in poorly cemented porous sandstone. To do so, ultrasonic measurements have been carried out. The important effects of the pore fluid viscosity in glycerol-saturated samples and some dispersion mechanisms are discussed.
2. MATERIAL DESCRIPTIONS
Cylindrical reconstituted samples are prepared from Fontainebleau sand, composed of mono-crystalline quartz sub-spherical grains . This sand is moderately well sorted with a mean grain size of 250 micrometers (coarse grain). In order to reconstitute the sample, sand is poured into a stainless steel mould and a silicate solution is then circulated through the specimen, precipitating silica at the contacts between grains. After several circulations and oven-drying, the samples exhibit a weak cementation. Samples have a porosity from 37 % to 40 % (deduced from the results of Tomography scanner, Micro Tomography scanner, Purcell tests and from weight measurements) and a high permeability of about 3 to 4.10-12 m² (3 to 4 D). The Micro Tomography scanner image of the reconstituted sample (Fig. 1) exhibits a poorly consolidated nature. Several clusters of particles are observed, as results of artificial cementation processes. The grains (in white color) are highly angular. In brief, this reconstituted sandstone can be considered as a representative model of sandstone reservoirs with weakly cemented, porous and highly permeable nature. Two types of fluids were used to saturate the samples: water and glycerol.
A set of analog vapor-extraction (VAPEX) laboratory experiments was performed to test the ability of existing analytic and numerical models to predict oil-drainage rates from this process. The selected analog fluids and porous media enabled all input parameters to the analytic model to be determined independently of the analog VAPEX experiments without history matching. The results show that the underprediction of oil rate by the standard analytic model is not because of increased levels of mixing between the solvent and oil over that expected from molecular diffusion and convective dispersion, but rather because of a deficiency in the analytic model formulation.
This paper investigates the role of convective dispersion on oil recovery by VAPEX using an analogue fluid system of ethanol and glycerol in well-characterized glass bead packs. Laboratory studies of VAPEX in porous media result in significantly high production rates than predicted either by analytic models derived from Hele-Shaw experiments or numerical simulations.
Previous workers have obtained an improved match between experiment and simulation by artificially increasing the diffusion coefficient of the injected vapour into the oil. Justifications for this increase include convective dispersion, an increased surface area due to the formation of oil films on sand grains, imbibition of oil into those films and a greater dependence on drainage height. Convective dispersion seems to be the most plausible mechanism.
A first contact miscible liquid-liquid system was used in these experiments so that all mechanisms contributing to increased-mixing apart from convective dispersion were eliminated. Improved confidence and prediction of VAPEX oil drainage rates will increase the likelihood of field scale application of VAPEX. This has been limited, due to difficulties in predicting the outcome on the laboratory scale and upscaling the results.
Longitudinal and transverse dispersion coefficients were measured experimentally as a function of flow-rate and viscosity ratio, with and without gravity. Vapex drainage experiments were performed over a range of injection rates. More than 80% of oil in place recovered after one pore volume of solvent injection. The oil drainage rates were compared with those predicted by the Butler-Mokrys analytical model using either molecular diffusion or convective dispersion. Using measured convective dispersion improved prediction of oil drainage rate by over 50%. Nonetheless experimental oil drainage rates were still slightly higher than predicted.
These results indicate that convective dispersion needs to be included in mixing calculations in order to better predict oil drainage rates during VAPEX.