Chemical tests limit sand build-up in Norwegian Sea wells
Statoil has achieved encouraging results from field tests carried out with an environmentally-friendly, oil-soluble chemical for sand consolidation. Tests are now being prepared for other Norwegian fields.
Sand production is a common problem in both oil and gas wells, especially when the reservoir is poorly consolidated. If the stress acting on the rock around the well becomes larger than the rock strength, shear failure of the borehole or perforation wall will occur. Shear failure results in the breaking of bonds between neighboring sand grains. The retaining forces are then reduced, and individual sand grains can be mobilized.
The fluid flow then erodes this zone, carrying sand grains into the wellbore. If the fluid velocity is high enough, the sand will be transported all the way to the surface. Often the start of sand production coincides with water breakthrough.
Various methods have been developed to stop sand entering the well. The most common is the installation of a screen or slotted liner, perhaps combined with a gravel pack, in the production interval. Management techniques have also been developed, such as the maximum sand free rate (MSFR), or acceptable sand rate (ASR), whereby the well is choked back and the flow rate reduced. However, this often involves flowing the well far below its potential, and perhaps at an uneconomic rate.
Other solutions have been developed which rely on chemicals to increase the strength of the rock in the near-bore area, normally phenol or epoxy-type polymers, or furain aldehydes. However, these types of chemical are toxic and environmentally damaging. A further drawback is that they combat sand production by generating very hard rock with poor permeability which adversely affects the fluid flow.
Statoil’s concept is based on field evidence indicating that a residual strength corresponding to the capillary force in water-wet sand is sufficient to stop or limit sand production substantially, says Hans Kristian Kotlar, a specialist at the Statoil Research Centre in Trondheim. If correct, this suggests that only a small increase in the residual strength of the sand will significantly enhance the MSFR.
The development team therefore looked for a solution which would bring about a small increase in the residual strength of the sand, a search which took them to chemicals quite different from those traditionally used for sand consolidation. Another consideration was that the chemical treatment system should be oil-soluble-unlike water-soluble systems, it should not alter the relative permeability of the oil-bearing zones.
After evaluating three different chemical systems, one was chosen to be developed for laboratory qualification and field use. This is an organosilane which was found to give very good visco-elastic binding to the sand grains, says Kotlar.
After testing on sand from the field and live cores, the chemical was field-tested in a subsea well on one of Statoil’s fields in the Norwegian Sea. The first well to be treated was a horizontal well with a single 35-m perforated interval. This interval has high permeability with a liquid production potential of 6-7,000 cu m/day. To keep erosion at an acceptable rate, the well had been choked back to around 2,500 cu m/d liquid rate.
Following the treatment, production was increased as high as 6,500 cu m/d for a period before being reduced to 4,500 cu m/d. After two months sand production began again, but at a lower rate than before the treatment (see figure).
Due to the success of the treatment in the first well, two more wells in the field were subsequently treated. This was an ad hoc decision which did not allow proper planning of the operation, Kotlar says. Consequently, compared with the first well, the volume of treatment chemical used in the second and third wells was completely undersized, which in turn meant that the penetration of the chemical into the formation was not as deep as in the first well. Moreover, wells 2 and 3 have multiple perforations, with total lengths of 185 m and 570 m respectively, and such long perforation intervals pose placement problems.
Nevertheless, the treatment initially resulted in practically sand-free production at increased liquid rates. In both wells, sand production started again after a time. But as with the first well, the objective of an increased MSFR was also achieved in wells 2 and 3. The results of the testing program were clearly encouraging but also raised questions about the placement issue.
When a well is to be treated, the chemical is injected into the hydrocarbon phase by the simple process of bullheading. It can be relied on to find its way to the area where sand is being produced, as this is characterized by high permeability. However, in long horizontal wells, the chemical tends to go where there is least resistance, and a viscosifying agent may be needed to ensure that it travels to the toe.
Other Statoil-operated licenses and other operators have agreed to allow testing of the chemical treatment on their fields. Preparatory testing of cores has taken place and it is hoped to perform field tests later this year, Kotlar says.
The development of this chemical treatment is being carried out under the aegis of Statoil’s Tail Production entity, part of the Technology and Products business area.•
