|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Juárez, José Luis (CEPSA) | Bertin, Henri (Université de Bordeaux) | Omari, Abdelaziz (INP) | Romero, Carolina (TOTAL) | Bourdarot, Gilles (TOTAL) | Jouenne, Stephane (TOTAL) | Morel, Danielle (TOTAL) | Neillo, Valerie (TOTAL)
Among the many parameters needed to optimize a polymer flood is the choice of polymer viscosity, mobility ratio and polymer slug size that should be injected to maximize oil recovery. In this paper, a new polymer flooding experimental study is addressed to answer two questions. Firstly, considering a given crude oil, what optimal polymer solution viscosity should be injected? And secondly how much polymer solution should be injected during the polymer flood to maximise recovery?
Experiments were carried out using 1D homogeneous Bentheimer cores of similar properties. The cores were oil flooded using crude oil (µo = 120cP at T=60°C) and aged to obtain intermediate wet conditions. The polymer was a partially hydrolysed polyacrylamide (HPAM) dissolved in a moderate salinity brine. The polymer solutions were prepared at different concentrations (from 1500ppm to 3000ppm) to cover a large range of viscosity ratio (
Corefloods results show as expected, that the polymer is more efficient in terms of oil recovery when viscosity ratio is low. In line with polymer flooding theory, we observed at intermediate wettability conditions, that a maximum oil recovery is reached at M =1 (Rµ = 5) and that oil recovery did not increase when reducing the ratio to M = 0.5 (Rµ= 2). However, when considering aspects such as polymer mass required, injectivity concerns and flow stability, we observe two favorable conditions, corresponding Rµ= 5 and Rµ = 10, for a mobility ratios of 1 and 7, respectively.
Different polymer slug sizes were injected in the cores at the above conditions (Rµ = 5 and Rµ = 10) followed by water flooding (chase water). Both injections (polymer and water injection) were carried out at same flow rate to minimize miscible viscous fingering at the rear of the polymer slug. Results show that an optimal polymer slug size exists for which one can obtain the same microscopic oil recovery than that of continuous polymer injections at Rµ=5 and Rµ=10, an important finding that can impact the economic viability of the process.
In conclusion, our experimental study shows that at 1D scale, optimal values of viscosity ratio, polymer slug size and polymer mass injected lead to the same maximum oil recovery obtained by continuous polymer injection. A necessary starting point before upscaling a polymer flood and studying the impact of heterogeneities.
Juárez-Morejón, Jose L. (University of Bordeaux) | Bertin, Henri (University of Bordeaux) | Omari, Aziz (University of Bordeaux) | Hamon, Gerald (Total) | Cottin, Christophe (Total) | Morel, Danielle (Total) | Romero, Carolina (Total) | Bourdarot, Gilles (Total)
Summary An experimental study of polymer flooding is presented here, focusing on the influence of initial core wettability and flood maturity (volume of water injected before polymer injection) on final oil recovery. Experiments were performed using homogeneous Bentheimer Sandstone samples of similar properties. The cores were oilflooded using mineral oil for water-wet conditions and crude oil (after an aging period) for intermediate-wet conditions; the viscosity ratio between oil and polymer was kept constant in all experiments. Polymer, which is a partially hydrolyzed polyacrylamide (HPAM), was used at a concentration of 2,500 ppm in a moderate-salinity brine. The polymer solution was injected in the core at different waterflood-maturity times [breakthrough (BT) and 0, 1, 1.75, 2.5, 4, and 6.5 pore volumes (PV)]. Coreflood results show that the maturity of polymer injection plays an important role in final oil recovery, regardless of wettability. The waterflood-maturity time 0 PV (polymer injection without initial waterflooding) leads to the best sweep efficiency, whereas final oil production decreases when the polymer-flood maturity is high (late polymer injection after waterflooding). A difference of 15% in recovery is observed between early polymer flooding (0 PV) and late maturity (6.5 PV). Concerning the effect of wettability, the recovery factor obtained with water-wet cores is always lower (from 10 to 20%, depending on maturity) than the values obtained with intermediatewet cores, raising the importance of correctly restoring core wettability to obtain representative values of polymer incremental recovery. The influence of wettability can be explained by the oil-phase distribution at the pore scale. Considering that the waterflooding period leads to different values of the oil saturation at which polymer flooding starts, we measured the core dispersivity using a tracer method at different states.
It is estimated that 60% of the world's remaining oil is held in carbonate reservoirs. Due to its moderate permeability, the transition zone can extend over a hundred meters and therefore contain a significant amount of STOIIP. The water-oil displacements behavior is not always well understood, especially when it occurs in the transition zone where capillary effects are dominant and both phases are mobile. The oil trapping and the rock wettability in this zone appear to be two key features to deal with. They must be studied as a function of parameters such as initial oil saturation, oil characteristics, rock properties etc. There is very little experimental data available in the literature that describes these features.
This study focuses on relative permeability and residual oil saturations during drainage and imbibition in carbonate reservoirs.
Steady-state core floods were performed with crude reservoir oil on outcrop limestone cores, some with moldic porosity, over a very large range of initial oil saturations. Cores were aged with crude oil before the imbibition process to allow wettability change at the initial oil saturations. Two main types of limestone have been studied: with unimodal or bimodal pore size distributions.
The two types of limestone cores exhibit very different responses to wettability alteration for the same oil/brine system while almost identical mineralogy. We attributed these differences to the vuggy structure of the Estaillade limestones, which might promote oil-wettability.
-The inspection of the water relative permeability curves show that water wettability decreases as Soi increases, i.e. as the elevation above the contact increases, for the two types of limestones. Therefore it is not correct to derive imbibition scanning Kr curves from the bounding Kr curve at high Soi, while assuming that wettability is constant.
- Hysteresis is observed for both the oil and water relative permeability curves as a function of saturation
- Non monotonic evolution of Sorw as a function of Soi has been observed for the limestone with bimodal pore size distribution. This behavior is ascribed to the combined effect of increasing fraction of micro porosity being filled by oil initially as well as wettability variation as Soi increases. On the other hand, Sorw increases monotonically as Soi increases, for the limestone with unimodal pore size distribution.
- The comparison between the experimental relative permeability curves and the ones derived from simple hysteresis models show that neglecting the variation of wettability along the transition zone leads to erroneous values in oil saturations thus on oil recovery.
In order to reduce the uncertainties in predicting oil recovery of carbonates reservoirs, core laboratory flooding experiments are conducted using representative rock samples and reservoir fluids at the same conditions as in the reservoir (pressure, temperature, wettability).
Numerical models are then developed to best fit the experimental data and to mimic as closely as possible the different scenarios. This is especially important when investigating the transition zone where it has been shown by several authors [1-4] that assumptions made to quantify the recovery factor can lead to erroneous values.
The oil-water transition zone (see Figure 1) is defined as the part of the reservoir between the free-water level (FWL) and the dry-oil limit (DOL)  where the water saturation reaches a near-constant irreducible value. In this zone, capillary effects are dominant and both water and oil are considered to be mobile. Its thickness can be more important (over a hundred meters) for low permeability reservoirs or/and similar water-oil density values. It could then contain a considerable amount of STOIIP.
To determine modifications of oil/water two-phase-flow properties after injection of water-soluble polymers, unsteady-state flow experiments were performed on both water- and oil-wet (silane-treated) sandstones. The same imbibition cycle (water displacing oil) under the same conditions was performed on the same core, first without any polymer and then after polyacrylamide had been adsorbed within the core. The capillary pressure was measured directly along the core by use of water- and oil-wet semipermeable membranes, while relative permeabilities were determined from the measurement of the saturation profile (by gamma ray absorption), outlet fluid production, and pressure drop.
The action of adsorbed polymer on relative permeabilities was found to be the same with both water- and oil-wet cores (i.e. a selective reduction of the relative permeability to water with respect to the relative permeability to oil). The trend was somewhat different for the capillary pressure. For the case of water-wet sandstones, the capillary pressure remained positive but increased dramatically after polymer adsorption. Because the polymer has little effect on the interfacial tension (IFT), this effect was attributed to the reduction of pore-throat size caused by macromolecule adsorption and to a possible improvement of the wettability of the core to water. For the case of oil-wet sandstone, the capillary pressure curve moved from negative to positive values, indicating that, in addition to pore-size restriction, the wettability of the core changed after polymer adsorption. This wettability change also induced a dramatic drop in residual oil saturation (ROS).
Excessive production of water as a result of heterogeneities or fractures often causes channeling or water coning and is a problem of central importance for field operators. Several techniques have been developed to overcome this problem. Among them, direct injection of polymer or gels in the production well was shown to enable the reduction of the water cut. If the drawdown on the treated well can be increased, then, in addition to the reduction in water production, the treatment can induce an increase in oil production.1 Several researchers have studied the mechanisms involved in the action of polymer or gels (Schneider and Owens,2 Zaitoun and Kohler,3 Zaitoun et al.,4 Liang et al.5). They all found that polymer or gels are able to reduce selectively the relative permeability to water with respect to the relative permeability to oil. Provided that the polymer is hydrophilic, this property does not depend on the polymer type (polyacrylamide, xanthan or scleroglucan) or on the nature of the rock (sandstone, limestone, or unconsolidated sand). Most existing experiments have been performed either under steady- or unsteady-state conditions at a high flow rate (Welge method).
Several physical processes have been proposed to explain the selective action of the polymer. The following are some principal ones.
1. Shrinking of the gel in the presence of oil. Dawe and Zhang6 observed water eviction from a gel during the displacement of an oil droplet in a micromodel. The influence of the wettability was also investigated. The gel was shown to have a lower blocking efficiency in oil-wet micromodels.
2. Partitioning of fluids. This hypothesis, put forward by Liang et al.,5 suggests that a segregation of oil and water occurs in the core and explains the disproportionate permeability.
3. Wall effect. The presence of the polymer adsorbed on pore walls may induce a lubrication effect that favors the flow of oil through the center of the pore channels and attenuate pore-wall roughness. This hypothesis was suggested by Zaitoun and Kohler.3 These authors proposed a simple two-phase-flow capillary model within a cylindrical geometry to describe the effect of an adsorbed polymer layer at the pore wall. To complete this pore-level study, we are developing a numerical model where the pore consists in a periodic two-dimensional (2D) divergent/convergent channel.7 The first results8 confirm qualitatively the experimental observations.
4. Wettability effect. The adsorption of the hydrophilic polymer on pore walls may enhance the water wettability of the rock and thus contribute to the relative permeability modification.
Most of reported studies were focused on relative permeability modifications, but little information (Barrufet and Ali9) is available about the effect of polymer on the capillary pressure. Our experimental procedure aimed at the measurement of this parameter as well. We performed unsteady-state core-flow experiments at low flow rates. To our point of view, these experiments are more realistic than steady-state ones. During these experiments, we measured directly the capillary pressure along the core using semipermeable membranes at pressure taps, and we determined the relative permeabilities over the whole saturation range.
We used synthetic brines containing 50 g/L&minus1 KI and 0.4 g/L&minus1 NaN3. The potassium ion prevents clay migration while the iodide ion improves the accuracy of saturation measurements by gamma ray attenuation technique.10 Sodium azide was used as a bactericide. As the oil phase, we used Marcol 52, a mineral oil having a viscosity of 10.5 mPa·s at 20°C. IFT's between brine and oil and between polymer solution and oil were measured with the ring technique; values were 33´10&minus3 and 28´10&minus3 N/m&minus1, respectively.
We used a high-molecular-weight nonionic polyacrylamide (PAM) available in powder form. The polymer behaves like a flexible coil in solution with an average diameter of 0.32 mm. Its molecular weight is 9´106 dalton.4 The solution, whose concentration is 2500 ppm, was prepared by slow addition of polymer powder to the brine in a vortex created by magnetic stirring. After complete dissolution of the powder, the solution was filtered on line with a set of 8-, 3- and 1.2-mm Millipore membranes to remove any solid or microgel. The viscosity of the polymer solution was measured over a wide range of shear rates with a Contraves LS 30 viscometer. The curve of viscosity vs. shear rate is plotted in Fig. 1.