Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Abstract This paper presents for the first time; Coupling of the EnKF methodology and tracer data; A new developed tracer simulator which accounts for partitioning gas tracers, and; Coupling of the EnKF methodology with partitioning gas tracer data. The ensemble Kalman Filter (EnKF) has recently gained popularity as a method for history matching. The EnKF includes online update of parameters and the dynamical states. An ensemble of model representations is used to represent the model uncertainty. Tracers are widely used to increase the understanding of fluid flow. Tracers can be used to label injection fluids, hence, well connections and fluid patterns can be established when the tracer appears in production wells. Tracer data contains valuable information but are typically underexploited; most of the tracer-tests are only evaluated in a qualitative manner, without any kind of comparison to simulation results. This paper brings together tracer and modelling competence by including tracer data as measurements in the EnKF methodology. Gas tracers in reservoirs are partitioning tracers and must be modelled as such. As far as we know, no other simulators includes adequate options for modelling these tracers, both with respect to convection terms and diffusion/dispersion terms in the conservation equation. In this paper we present a new tracer simulator, which avoids the above mentioned shortcomings. This new tracer simulator includes separate time step control and a second order spatial numerical scheme to reduce numerical smearing of the tracer data. This new simulator has been coupled with the EnKF methodology. The value of tracer data, and partitioned tracer data, in the EnKF approach is demonstrated on North Sea based examples. The permeability and fault transmissibility multipliers of the reservoirs are estimated by EnKF. These examples show that tracer data can be used successfully in an automatic updating scheme, not only by the traditionally manual updating. Introduction Large oil volumes are left behind after primary and secondary production methods. This oil is found as micro-distributions (remaining oil) in the water or gas swept volumes and as larger un-swept oil banks for instance in the shadow of large impermeabilities. In order to utilize tertiary recovery (EOR) methods and modern drilling technology (e.g., horizontal/flexible and multi-branched wells), it is important to quantify these remaining and untouched oil volumes and determine their location in the reservoir. Contemporary modelling and visualization tools have improved the ability to understand complex reservoirs and thus helped improve decisions regarding optimum reservoir development. Nevertheless, any reservoir simulation model represents one of many realizations of the real reservoirs, and to reduce the inherent uncertainty of the models it is important to include additional data, such as tracer data.
- North America > United States > Texas (0.46)
- Europe > Norway > North Sea (0.34)
- North America > United States > Texas > Fort Worth Basin > Ranger Field (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Statfjord Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Lunde Formation (0.99)
- (10 more...)
Abstract Injection of CO2 is a well known enhanced oil recovery (EOR) technique. Formation of stable foam inside the reservoir can improve macroscopic sweep efficiency. On the other hand, retention of surfactants decreases the cost-efficiency of the EOR process. This paper presents flow-through retention experiments with CO2-foaming agents onto outcrop Liege chalk plugs. Two branched ethoxylated (EO) sulphonates with different ethoxylation degree, S1 (EO=7) and S2 (EO=12) were used. The aim was to investigate the effect of ethoxylation degree on surfactant retention. Furthermore, the effects of temperature and residual oil on surfactant retention were studied. The effect of waterflooding followed by CO2 flooding on surfactant retention at reservoir conditions was also evaluated. Partitioning of the foaming agents between water and oil phases was studied. Results show that increasing the ethoxylation degree of the surfactant decreases the retention onto chalk cores saturated with formation water at 55°C. S2 (EO=12), which was found to give the lowest retention at 55°C, was found to have a higher retention at 70°C. The presence of residual oil saturation after waterflooding (Sorw) decreased the retention of S1 (EO=7) and increased the retention of S2 (EO=12) when compared to the absence of residual oil. The retention of S2 (EO=12) after waterflooding followed by CO2 flooding at 340 bar and 55°C was in the same range as retention on 100% water saturated core, but significantly lower than retention in residual oil saturated cores. The experiments have shown that not only surfactant structure and temperature are important for the retention of surfactants, but also the presence of oil. Introduction CO2-flooding is a well known Enhanced Oil Recovery (EOR) technology to improve microscopic sweep efficiency. However, there are major limitations with this method due to the large difference in mobility between displacing and displaced fluids. High mobility of CO2 leads to gas fingering with subsequent poor macroscopic sweep efficiency, which is again augmented by reservoir heterogeneities and gravity segregation (Grigg et al. 2004; Bai et al. 2005). A solution for this problem can be to use mobility controlling foams. Studies have demonstrated that surfactant stabilized foam could drastically reduce the gas mobility in the porous media, consequently improving volumetric sweep efficiency and oil recovery (Schramm and Wassmuth 1994; Green and Willhite 1998; Grigg and Mikhalin 2007). Though this EOR method is promising, there is a setback. Surfactant molecules tend to retain to the solid media reducing their effectiveness (Grigg and Milkhan 2007) decreasing the cost efficiency for CO2-foam processes. The economics of CO2 foam flooding depend significantly on the quantity of surfactant required to generate and propagate the foam. It is therefore important to study retention of surfactants onto reservoir rock. Surfactants may retain in reservoir rock by several mechanisms. In oil-free reservoir medium retention mechanisms like precipitation, chemical degradation and adsorption onto the solids have been identified (Meyers and Slater 1980; Zhang and Somasundaran 2006). If oil is present in the porous medium, additional mechanisms like partitioning of surfactant into the oil, deactivation of surfactants by binding to crude oil asphaltenes and co-adsorption of surfactant and oil can contribute to surfactant retention (Green and Willhite 1998; Mannhardt and Novosad 1994). Surfactant loss through partitioning into the crude oil can be responsible for surfactant losses by as much as 30% (Grigg and Mikhalin 2007). It is often difficult to distinguish between the different retention mechanisms or isolate the specific cause for retention.
- Geology > Mineral (0.95)
- Geology > Rock Type > Sedimentary Rock (0.95)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Reduction of residual oil saturation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Analysis of the Wettability Alteration Process During Seawater Imbibition Into Preferentially Oil-Wet Chalk Cores
Yu, Liping (U. of Stavanger) | Evje, Steinar (International Research Institute of Stavanger) | Kleppe, Hans (University of Stavanger) | Karstad, Terje (University of Stavanger) | Fjelde, Ingebret (IRIS) | Skjaeveland, Svein M. (U. of Stavanger)
Abstract Improved oil recovery from fractured oil-wet carbonate reservoirs is a great challenge. The water-flooding efficiency will be low because of higher permeability in fractures than in matrix, and negative capillary pressure retains oil inside the matrix blocks. Studies of oil-wet chalk have shown that sulphate ions in the seawater may alter the wettability towards increased water-wetness. One-dimensional spontaneous imbibition tests of seawater into preferentially oil-wet chalk cores are performed. To get a better understanding, a numerical model has been developed which includes effects of wettability alteration. The experiments are carried out on cylindrical, sealed core plugs with only top open or with both ends open. Only countercurrent imbibition takes place for cores with top end open. For cores with both ends open, both countercurrent and cocurrent imbibition take place, and oil recovery rate is obviously accelerated. Taking formation water as the base case, higher oil recovery is observed with seawater imbibition. To simulate the wettability alteration process caused by seawater, a model is developed which includes molecular diffusion, adsorption of wettability alteration (WA) agent, gravity and capillary pressure. The WA agent diffuses into the formation water initially present in the core, adsorb onto the rock surface and induce wettability alteration. Consequently, the capillary pressure curve is shifted to higher values. In particular, the capillary pressure at the initial water saturation changes from negative to positive values and seawater is imbibed into the core. The shapes of relative permeability curves also depend on the wettability. The simulation results can fairly well match the experimental data. With the experimental and modeling work we explore the interplay between capillarity and gravity, and especially the importance to consider wettability alteration process is again confirmed. Introduction Spontaneous imbibition is a process where a wetting phase displaces the non-wetting phase in a porous media by capillary action. It is important for fractured reservoirs to produce oil from the rock matrix. Many carbonate reservoirs are naturally fractured but often preferentially oil-wet (Roehl and Choquette, 1985; Chillingar and Yen, 1983). Water can enter the oil-wet matrix block to displace oil only if it overcomes the entry pressure or capillary barrier. The goal can be achieved by several mechanisms, altering the wetting state of the rock surface, lowering interfacial tension, or making use of viscous or gravitational forces. With the first approach the capillary pressure can be changed from negative to positive value which then leads to spontaneous imbibition. Many literatures have reported the wettability alteration towards water-wetness caused by surfactants (Spinler and Baldwin, 2000; Seethepalli et al., 2004; Standnes and Austad, 2000b). Usually the surfactant will also reduce the interfacial tension quite a lot, but at the same time it decreases the capillary pressure, and then spontaneous imbibition process will be negatively influenced. On the other side, the commercial feasibility of surfactant should be further studied. Strand et al. (2003) studied the spontaneous imbibition of aqueous surfactant solutions into oil-wet carbonate cores. They observed that sulphate in the imbibing fluid had a positive effect to improve spontaneous imbibition behavior. Recent laboratory studies indicated that seawater could improve oil recovery from moderately water-wet chalk reservoir such as the Ekofisk field (Austad et al., 2005; Høgnesen ans Standnes, 2006; Zhang and Austad, 2005; Zhang and Austad, 2006). It was observed that high temperature and the presence of sulphate ions in the injected seawater were the key factors for wettability modifications towards more water-wet conditions. The water-wetness of the chalk material increased with increasing temperature and concentration of sulphate in the seawater.
- North America > United States > Texas > Harris County > Houston (0.28)
- North America > United States > Oklahoma (0.28)
- Europe > Norway > North Sea > Central North Sea (0.24)
- Geology > Mineral > Sulfate (0.98)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.34)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)