Abstract
Many fields in South East Asia are suffering from sand production problems due to sensitive sandstone formation. Sand production increases with time and increasing water production. The production of sand induces loss of production, due to sand accumulation in the wellbore, and heavy operational costs such as frequent sand cleaning jobs, pump replacements, replacement of surface and downhole equipment, etc. An original sand control technology consisting of polymers injection and already deployed in gas wells, has been successfully tested in an offshore oil well.
The technology utilizes polymers having a natural tendency to coat the surface of the pores by a thin gel-like film of around 1 µm. Contrary to the use of resins which aim at creating a solid around the wellbore, the polymer system maintains the center of the pores fully open for fluid flow, thus preserving oil or gas permeability while often reducing water permeability (a property known as RPM for Relative Permeability Modification). The advantage of such system is that the product can be injected in the bullhead mode and often, a reduction of water production is observed along the drop in sand production. In gas wells, the treatment lasts around 4 years and can be renewed periodically.
A lab work was undertaken to screen out a polymer product well suited to actual reservoir conditions. We conducted bulk tests to evaluate product interaction on reservoir sand samples, and corefloods to evaluate in-situ performances. Treatment volume and concentration were determined after lab test.
One of "Oil Well" candidate is located in Arjuna Field, offshore Indonesia. Downhole conditions are: Temperature = 178°F, salinity = 18000 ppmTDS, permeability = 140-300mD, two perforated intervals with total thickness of 67ft (ft-MD) with 38 ft Average Netpay Thickness, production rate = 800 bfpd. The well is under gas lift and needed to be cleaned out every 3 months because of sand accumulation.
Polymer treatment was performed in two stages (bottom, then upper interval). A total volume of 150 m3 of polymer solution was pumped. Immediately after treatment, sand cut dropped from 1% to almost 0%. This enabled increasing the drawdown from 32/64’’ choke to 40/64’’, keeping the production sand free and sustained with time.
This field test confirms the feasibility of the original sand control polymer technology both in gas wells and in oil wells, which opens high possibilities in the future.
Water shutoff and conformance improvement: an introduction
