Recently, cationic polyacrylamides (CPAM) have been successfully applied in water shutoff treatments of oil and gas wells. These polymers adsorb strongly on reservoir rocks, building up an adsorbed layer of significant thickness. Moreover, under high rates, the coiled macromolecules stretch and can bridge large pore throats. This so-called bridging adsorption mechanism has been described previously for high-molecular-weight non-ionic polyacrylamides (PAM). CPAM rheology and retention behavior has been studied in unconsolidated SiC packs and in Berea sandstones in a permeability range 0.1–1 D with CPAM solutions having a cationicity between 0 and 50%. Due to the attraction between the positive charges carried by the polymer chain and the negative surface charges of the rock, both CPAM adsorption and bridging adsorption are higher than for PAM having the same molecular weight. A maximum adsorption is found around 10–15% cationicity. This maximum, observed both in SiC and in Berea, is due to the competition between adsorption energy and pore wall accessibility. Although the permeability to water drops considerably after CPAM bridging adsorption, the permeability to oil is remarkably preserved, which makes CPAM attractive for water shutoff applications. Introduction Operators of mature oil and gas fields are often faced with a high water production coming from a water source (aquifer) or resulting from water injection. Excessive water production generally causes economic and operational problems. It decreases oil production, results in large amounts of water that need to be disposed and gives extra costs related to oil/water separation, handling and lifting. Other problems include the increased tendency for the formation of emulsions, scale and corrosion. So a high water production decreases the economical lifetime of a well and there is a need to reduce it. Classically the following distinction is made regarding the treatments to be used to tackle the water problem.1 If water and hydrocarbon zones are clearly separated, a permanent barrier, which is placed in the water producing zone, should be applied (Treatment A). Cements, resins or strong gels can form these full-blocking systems. If hydrocarbon and water zones are not clearly distinguishable or there is a high level of crossflow between layers, the use of total shutoff is risky. In this case disproportionate permeability reducers (DPR's), usually polymer solutions or weak polymer gels should be applied. The aim is to reduce water flow selectively while not influencing oil flow (Treatment B).1,2 The working of DPR's is based on the fact that adsorption of hydrophilic polymers can strongly decrease the relative permeability to water while having little effect on the relative permeability to oil. Due to the increasing need for bullhead treatments (treatments without zonal isolation), oilfield operators have focused on self-selective systems (Treatment B). These systems can be bullheaded downhole, reducing selectively the permeability to water with respect to the permeability to oil or gas. Due to this property polymers or weak gels were thought to be magic products that could be used in all situations. The relatively low success rate of DPR bullhead treatments (literature reports around 40%) shows reality is less favorable. Hereunder we will discuss three reasons for this by using an example of a DPR treatment on a two-layer well with 1/10 permeability contrast (Figure 1). Here the high-permeability layer is swept first, either by an active aquifer or by water injection. The low-permeability layer is still producing at high oil cut, although water production from the high-permeability layer is overtaking its oil production.

The saturation profiles are routinely measured during Special Core Analysis (SCAL experiments). Several ways exist to use this information in the inversion procedure of the relative permeability data. To date, the local saturation profiles are either included in a global objective function that is minimized during the inversion process, or smoothed and used as input data in the simulation, which leads to non smoothed simulated pressure drop. None of these methods permit to reproduce the local saturation fluctuations that are measured during coreflooding experiments. Our approach has the advantage to take benefit from these fluctuations to characterize the petrophysical properties for a given rock-type. In this paper, the methodology is first recalled and illustrated on a synthetic case. It is based on upscaling techniques applied in reservoir simulation. Both the stabilized and transient saturation profiles are analyzed to evaluate the local properties. The quality of the history matching is significantly improved. In addition, both kr and Pc-curves are obtained from only one experiment and the variability of these parameters with the heterogeneity is also investigated. This estimated interval of confidence for kr and Pc can be very useful to perform uncertainty studies at the reservoir scale. The Pc-curve interval of confidence determined with this method on a carbonate sample, is in good agreement with the variability observed with several centrifuge experiments performed on sister plugs. Finally an alternative approach derived of the heterogeneous method is proposed, which allows a very quick acquisition of all the information relative to kr and Pc during a multi-rate flow experiments. Introduction Petrophysical parameters assessment Both relative permeability (kr) and capillary pressure (Pc) curves are key factors for assessment and prediction of the hydrocarbon recovery of a field. Representative curves are routinely obtained through SCAL (Special Core Analysis Laboratory) studies, in operating conditions as close as possible of reservoir conditions. These conditions mainly concern the thermodynamic conditions (pressure, temperature), the reservoir stress (overburden pressure), the nature of the fluids (synthetic reservoir brine, live oil), the initial saturation state (low Swi value) and the in-situ wettability (preserved samples or restored wettability through an aging process at Swi). Relative permeabilities are usually determined from flow experiments performed on core samples using either the UnSteady-State (USS) or the Steady-State (SS) method, where either one or two fluids respectively are injected. The centrifuge technique can also be used but not at full reservoir conditions (Ruth, 1997; Chardaire et al., 1992). Whatever the method used, the experimental results must be interpreted using capillary pressure curves. Virnovsky et al. (1998) proposed an analytical method to correct the SS data for capillary pressure. However, numerical simulations are needed for both USS and SS because a complete analytical solution does not exist. The kr curves can either be optimized in order to history match the experimental data knowing the Pc curve (from another experiment) or both kr and Pc curves can be optimized simultaneously (Chardaire et al., 1992; Helset et al., 1998). More recently, it has been shown that both kr and Pc curves can be determined at reservoir conditions using the semi-dynamic approach (Lombard et al., 2002). The main advantage of this method is to establish several equilibrium states between the viscous and the capillary forces within the sample by injecting one fluid while the other circulates at the outlet face. These equilibrium states enable the determination ofboth the kr of the injected phase and the Pc curve. The kr of the displaced phase can also be obtained by history matching of transient evolution of the pressure drop.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe saturation profiles are routinely measured during Special Core Analysis (SCAL experiments). Several ways exist to use this information in the inversion procedure of the relative permeability data. To date, the local saturation profiles are either included in a global objective function that is minimized during the inversion process, or smoothed and used as input data in the simulation, which leads to non smoothed simulated pressure drop. None of these methods permit to reproduce the local saturation fluctuations that are measured during coreflooding experiments. Our approach has the advantage to take benefit from these fluctuations to characterize the petrophysical properties for a given rock-type. In this paper, the methodology is first recalled and illustrated on a synthetic case. It is based on upscaling techniques applied in reservoir simulation. Both the stabilized and transient saturation profiles are analyzed to evaluate the local properties. The quality of the history matching is significantly improved. In addition, both kr and Pc-curves are obtained from only one experiment and the variability of these parameters with the heterogeneity is also investigated. This estimated interval of confidence for kr and Pc can be very useful to perform uncertainty studies at the reservoir scale. The Pc-curve interval of confidence determined with this method on a carbonate sample, is in good agreement with the variability observed with several centrifuge experiments performed on sister plugs. Finally an alternative approach derived of the heterogeneous method is proposed, which allows a very quick acquisition of all the information relative to kr and Pc during a multi-rate flow experiments.