A horizontal well shows sustained (8 months) revenue benefit after treatment. Persistence of treatment through shutdown interruptions is also noted. (All figures courtesy of Champion Technologies)

Novel organosilane chemicals are the basis of new technology developed by StatoilHydro and Champion Technologies. The key components are oil-soluble and hydrophobic in nature, yet are water-sensitive. The components’ low bioaccumulation tendencies and high biodegradation factor also satisfy strict environmental criteria for North Sea use. The treatment process consists of only a few deployment steps and is relatively simple to implement.

When the consolidation chemical is placed properly in a producing sandstone formation in which the bonding between individual sand grains has been disrupted, the active chemical components react with connate water near the well bore to bind sand grains together in a polymerized organosilane network, without significantly impairing the permeability of the formation rock matrix. The effect is to restore some of the residual strength of damaged rock (or improve the strength of poorly consolidated rock) near the well bore — enabling it to withstand more forceful fluid flows without eroding — and to increase the reservoir’s maximum sand-free production rate.

The relatively mild chemical technique has halted sand production for varying lengths of time in the 12 wells where it has been applied to date. Oil production rates in treated wells have increased from 15% to 174%. Evidence indicates the method can reduce water production of wells with high water cuts.
Sand-production challenges

Sand production problems typically begin when stresses introduced into a producing formation by production operations become powerful enough to mobilize individual grains of sand near the well bore. A layer of plasticized sand is generated near the well bore. As produced fluids flow toward the well bore, they can erode the plasticized solids and transport sand particles to equipment on the surface. The rate of erosion and amount of sand produced are influenced by the degree of residual strength of near-wellbore plasticized materials and the rate of produced-fluid flow.

In some cases, sand production can be controlled or curtailed by reducing the rate of production. But this solution frequently prevents the project from achieving its financial objectives.

Many effective mechanical methods have been developed to stop sand production from unconsolidated reservoirs, most of which involve precisely placing a screen or slotted liner downhole in the well bore, sometimes in combination with a gravel pack. The risk of sand production also can be minimized by completing wells with cemented liners and oriented perforations. However, most mechanical remedies require the mobilization of costly equipment spreads, which can raise high economic hurdles for mature wells.

Traditional chemical sand-consolidation methods attempt to increase the maximum sand-free production rate by firmly bonding sand grains together to restore the strength of the rock matrix to a large degree. However, this approach can cause big reductions in permeability.

To beneficially increase the maximum sand-free production rate of some weakly consolidated sandstone reservoirs, it is only necessary to increase the residual strength of the formation by a small amount. This low strength requirement inspired investigation of completely different chemistries from traditional chemical solutions to sand production.

Treatment method

The new organosilane sand-consolidation treatment consists of a three-step application in which a hydrocarbon pre-flush, the main chemical pill in hydrocarbon phase, and a hydrocarbon placement volume are bullheaded into the well. In most applications to date, the same fluid — diesel — has been used as a pre-flush fluid, placement fluid, and carrier for the organosilane chemical.

The hydrocarbon pre-flush is performed to dewater the production tubing and to reduce water saturation near the well bore, i.e., to prepare the reservoir matrix. This is necessary because these organosilanes are oil-soluble and react with water. The pre-flush ensures the organosilanes will not be able to react before the chemical reaches the porous environment. The objective is to place the chemical so it will interact with the irreducible water around the sand grains (the bulk volume having been flushed by diesel) and hydrolyze. In doing so, the chemical becomes hydrophilic and partitions into the water layer around the sand grains.

If properly placed, the organosilane molecules will react with hydroxyl groups on surfaces of silica sand and with each other to form a polymerized organosilane network that strengthens the damaged formation near-wellbore. Stabilizing and restoring the residual strength of the sand matrix enables the reservoir to achieve higher rates of production without allowing the erosion and transport of sand grains into the well bore.

Selecting a suitable candidate well is one of the most important parts of the application design process. Wells have been chosen for treatment in four offshore fields producing from middle and lower Jurassic sands with permeability ranging from 50 millidarcies (mD) to more than 10 Darcy.

Organosilane applications

Preceding all field treatments, laboratory tests assessed the potential for reductions in permeability post-treatment. Values ranged from 15% to 40%, but figures as high as these were not noted among wells actually treated. Treatments to date have shown careful job design and treatment placement are key to the success of the technology.

Some wells with more challenging completions (i.e., wells with long horizontal intervals) produced sand-free for only a matter of a few weeks, while others, with shorter production intervals, produced for several months before sand production returned. One well produced sand-free for 10 months before re-treatment was necessary.

But even in cases where sand-free production time was relatively short, treatment costs were repaid quickly. In several instances, treatment costs were returned many times over by higher production rates, lower maintenance costs, and avoided remediation costs.

In one well with a high water cut, oil production increased by 48.7%, or 58 cu m/day, following chemical sand consolidation with the organosilane method. Payback of treatment cost, including the cost of interrupted production revenue, was achieved in about 11 days, and the well was operated sand-free five months after treatment.

In another notable application, an offshore horizontal well producing from a 35-m, highly permeable perforated interval had a calculated liquid production potential between 6,000 cu m/day and 7,000 cu m/day. But when produced at such high rates, the well eroded sand from the matrix and transported it all the way to the surface. To keep sand erosion at a manageable level, the well was choked back to a liquid production rate of 2,500 cu m/day.

During the test period following the chemical sand-consolidation treatment, the well produced sand-free at a rate of 6,500 cu m/day. To avoid provoking sand production, the well was choked back to a production rate of 4,500 cu m/day, still an 80% increase. Despite this measure, sand production gradually returned after three months, indicating a gradual deterioration of the treatment over time.

The new organosilane chemical sand-consolidation method has proven its potential value to resolve a wide range of problematic well conditions where sand-control completions have not been installed or have failed, when unexpected sand production occurs that was not anticipated in the design phase, or where the predicted value of future production does not justify remediation with a more costly recompletion.