Core permeability

Static leak-off experiments with borate-crosslinked and zirconate-cross-Unked hydroxypropylguar fluids showed practically the same leak-off coefficients [1883]. An investigation of the stress-sensitive properties showed that zirconate filter-cakes have viscoelastic properties, but borate filter-cakes are merely elastic. Noncrosslinked fluids show no filter-cake-type behavior for a large range of core permeabilities, but rather a viscous flow dependent on porous medium characteristics. 

Core floods were performed to determine if treatment polymers would prevent permeability damage caused by fines migration within consolidated rock and whether the adsorbed polymers would themselves reduce core permeability. The tests were performed using Hassler sleeve chambers. With the exception of the polymer... 

Figure 1. Composition and Concentration Effects of Potassium Based Clear Well Fluids on Core Permeabilities.

Another series of experiments used sandstone cores previously injected with starved bacteria to investigate the ability of the bacteria to grow within rock cores when given a suitable nutrient Berea sandstone cores of 200 and 400 millidarcy (md) permeabilities were used as they were considered to be more representative of reservoir conditions than the glass bead cores. The sandstone cores were injected with 300 to 450 pore volumes of 10 /ml starved bacteria until the cores contained an even distribution of bacteria (Fig. 3A B) and the core permeabilities were between 13% and 18%. SCM nutrient was injected through the cores (Fig. 3C) until the core permeability fell to 0.1%, this required 360 pore volumes of SCM. 

Figure 13 shows that the core permeability drops over many injected pore volumes and ultimately levels off. The effluent profile (dashed lines) shows that the oil droplets appear after some time, and their concentration rises slowly and levels off at the inlet value of 0.5%. The time at which the permeability reduction stops is about the same time at which the oil droplets approach their inlet concentration. 

Permeability reductions were also observed by McAuliffe (9), and his results are shown in Figure 14. He used a Boise sandstone core with an initial permeability of 1600 mD and injected a 0.5% OAV emulsion having average oil-droplet sizes of 1 and 12 xm. The small-diameter emulsion reduced the permeability from 1600 to 900 mD after 10 pore volumes of the injected emulsion the 12-fxm emulsion was much more effective in reducing the core permeability. After 10 pore volumes had been injected, the permeability was reduced to 30 mD, almost a 50-fold reduction. 

Luo et al (2002). The tested core permeability was 0.7 to 1.8 and the porosity was 0.2. In addition, the displaced oil was 9.5 mPa s at 70°C. Table 5.5 compares the performance of KYPAM with HPAM 1285 at a concentration of 1000 mg/L. A 0.4 PV injection volume was used. We can see that the flow behavior of KYPAM was better than HPAM 1285. KYPAM has been widely used in polymer flooding, ASP, and profile control projects in Daqing, Shengli, Huabei, and Xingjiang fields. Several field test cases are presented next. 

Conduct core flood tests with the polymer solution at different injection rates. Measure the pressure drop, Ap, corresponding to each injection rate (velocity u). The core permeability and porosity are measured before the core flood tests. 

In very recent work, the above variation was examined for three other surfactants, using pairs of core samples (Type I and Type II) that had been taken from the same well but differed from each other in permeability by factors of about 20. For each of the three surfactants, the mobility is shown on a log—log plot as a function of core permeability. The first of the four lines on each of the three plots are for surfactant-free brine—C02 mixture, and the others are for three different low concentrations. Figure 8 is for Chevron Chaser CD-1045, Figure 9 is for Henkel NES-25, and Figure 10 is for Chevron CD-1050. 

The investigations (26—29) illustrated the difference between reactive and nonreactive foams. During the tests, core permeabilities ranged from 0.5 to 5.0 md. Fluid loss of the nonreactive foam was approximately half of the reactive foam, although the stability of each did not show a significant difference. This result suggests two possible scenarios. The first is that the foamed acid is destabilized in its reaction with limestone, and this destablization causes greater fluid loss of the gas phase. The second is that the permeability is increased as the add dissolves the limestone. 

Figure 11. Effect of particle size on core permeability ratio. (Reproduced with permission from reference 71. Copyright 1988.)...

In two cores, permeability was reduced after the first series of polymer flow experiments by oilflooding to interstitial water saturation and waterflooding to residual oil saturation. Permeability to brine was determined at residual oil saturation prior to polymer flow experiments. Polymer flow experiments were done following the sequence described above. Small amounts of oil were produced during some experiments. This usually occurred during the highest flow rate of a run. Displaced oil was estimated from the volume of oil collected in a graduated cylinder. In one... 

The sequence in an injectivity/retention test typically involves four steps. First, the initial core permeability is measured with brine. Then multiple pore volumes of polymer are injected at a constant rate while the pressure drop is monitored and the effluent is fractionated for analysis. Next, brine is injected to flush unretained polymer from the core sample. Finally, the postinjectivity brine permeability is measured. 

Core permeability is determined before (Kf) and after (K) acid injection by using Darcy s law for linear flow. Permeability ratio, Kj., is also calculated as a function of the cumulative core effluent using the following equation ... 

Figure 8, from reference [14], shows the permeability ratio as a function of the acid injection rate. For brine saturated cores, the final core permeability exponentially increases with the acid injection rate. The same trend is noted in the case of oil saturated cores. 

At first, core was measured with a vernier caliper to get its diameter and length, then it was vacuumpumping and saturated by formation water. After that, the core was put into the core holder to plus confining pressure 2.0 MPa. When the process was turned on, core was injected displacement of formation water forward, core was flowed the displaeement fluid more than 10 times the pore volume until the flow was stable. The core permeability K was calculated, then 2 PV the gel... 

Several models have been proposed in the literature to predict wave transmission through a rubble mound structure which, however, do not explicitly account for the effect of the core permeability. The parameter which mostly affects the transmission coefficient Kt has been found to be a function of the relative freeboard i c/Hs and... 

In this chapter, some of the basic ideas on polymer adsorption at a solid-liquid interface are briefly discussed. The different types of polymer retention mechanism within a porous medium as referred to above are then reviewed, together with discussion of how these may be measured in the laboratory both static and dynamic adsorption are discussed in this context. Retention of HPAM and xanthan are then considered and the levels observed and their sensitivities to polymer, solution and porous medium properties are discussed. The effect of polymer retention in reducing core permeability is also considered. Finally, some work on the effect of polymer adsorption on two-phase relative permeability, which is of some relevance in the polymer treatment of producer wells in order to control water production, is reviewed. 

Figure 5.11. The effect of the initial core permeability on RRF for the flow of HPAM (M) in 3% NaCl through a Berea core (after Smith, 1970).

Before discussing the issues concerning the polymer experimental procedures, it is necessary to establish the conditions under which the more traditional field core data have been gathered (i.e. core permeabilities, relative permeabilities, etc.). Central to such consideration is the matter of core wettability and how the core has been conditioned or restored for the relative permeability experiments and, therefore, for the polymer flooding experiments. This very important matter will not be considered here, but it will be assumed that the wettability and conditioning of the reservoir core have been satisfactorily achieved. This is important for polymer properties, since the adsorption is thought to be greater in water-wet cores than in oil-wet systems. In the discussion below, it will be assumed in all cases that experiments in porous media use correctly conditioned field cores at residual oil (unless otherwise stated). The oil will be the (dead) field oil, and conditions of reservoir temperature, but not necessarily pressure, will be established in the core. 

Measurement of transport parameters The main measurement of interest under this heading is of the excluded/inaccessible pore volume (IPV) of polymer relative to tracer as parameterised by the core permeability. If this quantity is known, then it should be included in the simulation studies since it may have some effect on the relative breakthrough times of polymer and tracer. However, it has been found that the IPV effect is usually dominated by the frontal retardation of the polymer as a result of adsorption/retention, and it is not generally of major importance in the assessment of the outcome of the polymer flood. Other measurements, such as of polymer dispersion coefficient and viscous fingering parameters, are primarily of importance for interpreting detailed core flood experiments since they do not scale in a simple way to the field and cannot therefore be used directly in the polymer field-scale simulations. 

Rock core permeability (darcies) . lOOOE-02 Rock core porosity (decimal nbr) . 2000E+00... 

Roclc core permeability (darcies) Roclc core porosity (decimal nbr) Mud calce permeability (darcies) Mud cake porosity (decimal nbr) Mud solid fraction (decimal nbr) Viscosity of invading fluid (cp) Viscosity, displaced fluid (cp) Pressure at well boundary (psi) Pressure, effective radius (psi) Radius of the well bore (feet) Reservoir, effective radius (ft) Rspurt > Rwell radius 0 t=0 (ft) Maximum allowed number of hours... 

Rock core permeability (darcies) . lOOE-02 Rock core porosity (decimal nbr) . lOOE+00 Viscosity, invading liquid (op) . lOOE+01 Viscosity of displaced gas (op) . 200E-01 Compr. . invading liquid (1/psi) . 300E-05... 

---