Recent studies by Mamora and Moreno showed the feasibility to achieve reservoir sand consolidation by using hot alkaline solutions. This new reservoir sand consolidation technique was validated through an experimental work using Venezuelan sand samples from different unconsolidated heavy oil reservoirs (S-1, S-2 and S-3) and commercial Silboca sands (S-4). The samples, packed into Teflon tubes, were placed in a horizontal stainless steel cell at a pressure of 500 psig. Then, hot sodium carbonate solution between 120 and 250 °C was injected at 5-cc/min-flow rate during 2 to 5 hours. Effluent solution was sampled every 20 minutes. Permeability measurements were performed before and after each run to check variations. After each test, sand packs were dried at 100 °C and examined through electron microscope to observe the morphology of secondary phases.
Sand consolidation was verified for S-1 and S-2 sands and secondary phases were identified as sodium aluminum silicates for tests with temperature above 240 °C. No consolidation was observed with S-3 and Silboca sands, probably due to the large grain sizes and a 98 % quartz content, respectively. It is believed that the aluminum contained in clays and/or feldspar is required to obtain sand consolidation. Permeability reduction is low enough to encourage further experiments. Temperature, pore volume, composition and grain size are critical parameters for consolidation. Soaking time and injection rate showed less influence on the process. Potential benefits from field application of this technique can be expected by minimizing sanding problem and cost reductions associated to the production operations.
Sanding problems in producers due to pressure falls, friction and dissolution of minerals during steam injection are well known. The production of sand in weak formations with poor consolidation is a problem that causes serious damage in production lines, valves, pumps, etc. Even worse, this phenomenon can cause reductions in productivity or well collapse. On the other hand, sand removing in highly viscous oils at the surface is expensive and time consuming. Normally under these circumstances, it is required the implementation of a sand control method that could go from slotted liners, screens or gravel packs to complex chemical methods that are usually expensive. The chemical processes have limited use in thermal projects due to the high temperatures. In addition, long curing time for resins plus short time stability makes them a non well-received option.
A novel sand consolidation method using high temperature alkaline solutions was first field-tested in the Wilmington oil field, Ca. and was reported by Davies et al.1 and Hara et al.2 This method was lab-tested in the Texas A &M University by Mamora et al.3, Nielsen4 and Moreno et al.5, 6. The interest in the implementation of this method encouraged by previous results was the base of the current research.
The main objective is to determine if the new technique of consolidation by injecting Na2CO3 alkaline solution at high temperature (200–250 °C) is applicable to reservoirs with sand problems in Venezuela.
