Caustic Slug Injection in the Singleton Field
- L.W. Emery (Atlantic Richfield Co.) | N. Mungan (Petroleum Recovery Research Institute) | R.W. Nicholson (U. of Tulsa)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- December 1970
- Document Type
- Journal Paper
- 1,569 - 1,576
- 1970. Society of Petroleum Engineers
- 5.7.2 Recovery Factors, 5.3.2 Multiphase Flow, 5.6.5 Tracers, 5.2.1 Phase Behavior and PVT Measurements, 2.4.3 Sand/Solids Control, 4.1.2 Separation and Treating, 5.2 Reservoir Fluid Dynamics, 1.8 Formation Damage, 5.4.1 Waterflooding, 1.6.9 Coring, Fishing, 5.3.4 Reduction of Residual Oil Saturation, 5.1 Reservoir Characterisation, 1.2.3 Rock properties
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The watered-out portion of this field in Nebraska appeared to be a good candidate for injection with NaOH. The results of the pilot program have been disappointing, however, probably because of poor sweep efficiency and because of deterioration of the caustic slug.
Waterflooding is still the most widely used of all secondary oil recovery processes. Unfortunately, oil recovery by waterflooding is far from complete because of two inherent limitations: (1) no matter how much water may be passed through a reservoir, some quantity of residual oil remains in the pores that have been swept by the injected water; and (2) economic considerations require that waterflooding be terminated when the produced WOR exceeds some critical limit, even through portions of the reservoir may not yet have been swept. Mungan showed that, at breakthrough, oil recovery from oil-wet cores is always less than from water-wet cores and that, after breakthrough, large quantities of oil are produced, accompanied by a high WOR. Leach et al. and Mungan showed that in some cases the oil recovery can be made more efficient by changing the pH of the injected water.
We shall discuss here a laboratory study of oil recovery efficiency in synthetic cores using Singleton crude and water of pH ranging from 3.5 to 12.5, and the field trial based on the laboratory findings.
Most of the displacement studies were performed in flow tubes packed with unconsolidated Ottawa sand. Each tube had a cylindrical section 2.062 in. ID and 30 in. long, and was made of monel metal. The inlet flange had a straight face, two entry ports, and the usual fluid distribution grooves. The outlet flange, however, was bored in the shape of a funnel, which was packed with silica flour consisting of a mixture of 325- and 400-mesh powder. This effectively eliminated capillary end effects. The tubes were packed with a sand having a broad particle-size distribution. Experience has shown that if the sand is well sorted in particle size, the resulting unconsolidated pack gives waterflood residual oil saturations that are unreasonably low, ranging from 10 to 15 percent pore volume (PV). A commercially available sand mixture, American Graded Sand Co. AGSCO No. 16 sand, was used to pack the tubes and gave waterflood residuals of about 30 percent PV. The particle-size distribution of this sand is given in Table 1. Much care was devoted to cleaning the sand, and a technique involving no vibration was developed to eliminate segregation of grains of different sizes during packing. Random cores from several packs indicated the porosity and permeability to be uniform. Displacement experiments permeability to be uniform. Displacement experiments were also performed in two 10-ft-long, 4-in.-diameter Berea cores. Formation sensitivity studies were made with small cores from the Singleton field. These cores had been handled and stored in a conventional manner, with no precautions taken to keep them fresh or in their native equilibrium state. The refined oil used - Klearol* - was purified using procedures described elsewhere.
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