Near-Wellbore Placement of Small (Sand Consolidation) Treatments
- D.R. Davies (Koninklijke/Shell E and P Laboratory) | A.M.P.M. Hagelaars (Koninklijke/Shell F and P Laboratory) | D.L. Roberts (Koninklijke/Shell E and P Laboratory)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- November 1984
- Document Type
- Journal Paper
- 1,905 - 1,916
- 1984. Society of Petroleum Engineers
- 2.4.3 Sand/Solids Control, 3.2.4 Acidising, 2.2.2 Perforating, 3.2.5 Produced Sand / Solids Management and Control, 4.1.2 Separation and Treating, 1.14 Casing and Cementing, 5.2 Reservoir Fluid Dynamics, 4.3.4 Scale, 4.1.5 Processing Equipment
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The degree of success of small-volume, miscible near-wellbore treatments, such as chemical sand- consolidation systems, depends critically on the efficient placement of the chemicals. 1 In the case of sand consolidation, (1) failure to treat all the perforations, (2) contamination, or (3) dilution of the chemicals (which leads to a low-strength consolidation) will result in a continuation of sand production. 2 The final distribution of the injected fluids in the formation is a function of many complex processes occurring during placement: mixing in the injection tubing, stability of displacement, gravity-induced movement of the fluids, etc.
In recent years significant effort has been directed to the study of fluid displacement (miscible and immiscible) in porous media. Stability criteria for the displacement of one fluid by another have been established, and the problem of viscous fingering-an unstable displacement resulting from a less viscous fluid displacing a more viscous fluid-has received much attention. Thus the stability of the displacement process is controlled by fluid mobility ratio, fluid density differences, formation porosity and permeability, and the fluid injection rate. The theory and laboratory evidence is well-documented for the linear low-rate flow associated with reservoir engineering studies. However, less attention has been given to the same displacement phenomena that occur in the near-wellbore region during small-volume chemical treatments (sand consolidation, acidization, selective plugging, etc.). Attention has been drawn to the need for more consideration of placement profiles in these operations. Experimental and theoretical studies have shown that gravity segregation between fluids of different densities in the well is an important factor affecting injection profiles. The experiments deserted in this paper examined the effect of fluid viscosity contrast and injection rates on the placement profile of the injected fluid in the near-wellbore region of the formation. These investigations were performed in both full- and reduced-scale models an although they were carried out mainly with sand- consolidation chemicals the results may be applied to other miscible, near-wellbore treatments.
The work consisted of four distinct studies: (1) experiments at low injection rates to study the stability of the displacement and simulate the phenomena occurring in the near-wellbore region during injection, (2) a study of the rate of movement of fluids in the formation under the influence of gravity, which may occur in practice when fluid injection is complete and the well is shut in, (3) experiments at high injection rates (equivalent to those employed in field operations) through single perforations, and (4) multiple perforation experiments at field injection rates to examine the effect of fluid viscosity ratio on the extent of pore fluid trapping between perforations.
The information generated from these studies emphasized the placement advantages to be gained by improved mobility control (high viscosity contrast) and, more specifically, was used to estimate the effectiveness of sand-consolidation treatments in field operations.
Experimental Models and Procedures
Small-Scale Transparent Sector Model. A transparent model was used to observe the displacement of one fluid phase by another. The model (Fig. 1) consists of a sector (30 degrees) of a transparent cylinder, packed with crushed pyrex glass and saturated with a xylene/kerosene mixture. Axial pressures up to 0.6 MPa [87 psi] were exerted on the glass pack by hydraulically pressurized membranes mounted in the top and bottom covers. The xylene/kerosene composition was chosen so that its refractive index matched that of the crushed glass, thus making the pack completely transparent. The sector model had three inlets (simulated perforations) and three outlets opposite each other. A perforated plate covered by a wire mesh (74-um [74-micron]) screen was placed 0.10 m [0. 3 ft] in front of the outlets. This vertical screen prevented the formation of streamlines between the inlet and outlet during injection; thus, radial flow was achieved in the model.
Experiments were carried out by injecting a nonreactive colored solution of known properties into the model and draining an equivalent volume of reservoir fluid. The position of the colored fluid then was monitored as a function of time.
Physical Wellbore Model (PWM). The full-size PWM (Fig. 2) consists of a pressure vessel (diameter of 2 m [6.6 ft] and a height of 1.2 m [4 ft]) packed with sand. The sand can be stressed independently in axial and radial directions. Axial pressures up to 1.6 MPa [232 psi] can be exerted on the sandpack by two hydraulically pressurized membranes mounted in the top and the bottom covers. Radial stress is induced with the aid of 18 inflatable pressure cells placed circumferentially in the vessel.
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