Two years of laboratory and field results suggest that sand control to address fines migration challenges can be overcome with proper formation analysis and engineered treatment design, including appropriate clay stabilizers and fines-fixing agents.

Fines migration
Most unconsolidated sandstone formations require solids production control such as well screens, often combined with gravel packs or frac pack treatments. However, these

Figure 1. Flowing 2% KCl through a synthetic core reduced the core permeability due to fines migration into pore throats. (All graphics courtesy of BJ Services)
formations may also include siliceous fines, which are typically very loosely bound to reservoir sand grains. When mobilized, these fines may plug the pore throats of the formation, gravel packs or well screen. In addition, they can act as nucleation sites for organic precipitation and stabilize emulsions. Plugging and emulsion issues inevitably lead to lower-than-expected production performance and both short- and long-term production decline. With the desire to maintain maximum production, drawdown pressures are typically increased, which would increase the potential for downhole failures from produced fines. These produced mobilized fines can also cause downhole and surface plugging and erosion in both wellbore piping and surface equipment.

A number of downhole phenomena can cause fines to be mobilized. Chemical effects weaken bonds between the fines and the rock matrix. Mechanical effects impose drag forces on the particles, exacerbated by changes in downhole stresses during production. More typically, fines migrate due to a combination of effects: Oil viscosity and gas turbulence produce drag, combined with chemical effects and so-called “flow shock” that occurs with a sudden increase in flow rate, such as when a new well is brought on production with inappropriately designed choke sizes. Fines migration also becomes prevalent at the onset of water production and declining pore pressure.

A typical means of minimizing fines mobilization during completion or well stimulation is the use of clay stabilization agents in the completion/stimulation fluid recipe. Common products
Figure 2. Adding a fines stabilizer enabled even high flow rates without permeability degradation.
used include low-molecular-weight polyamines to protect the formation against damage due to clay swelling, sloughing and migration of fines. Although these additives work well on clays, they are usually ineffective on non-clay fines such as quartz, amorphous silica, feldspar and mica.

A more successful fines stabilization option is a hydrolysable organosilane complex (HOC), which forms a non-oil-wetting polysiloxane coating to link siliceous particles (clay and non-clay grains and fines), thereby immobilizing small particles. Importantly, the short-chain polysiloxanes do not adversely affect permeability.

Lab testing
To verify the efficiency of the HOC, regain permeability laboratory tests were conducted using synthetic core plugs that represented potential fines migration-prone sandstones. The synthetic core plugs comprised 60% 20/40 Brady gravel + 20% 100 mesh + 20% 325 mesh. The synthetic cores were packed from unconsolidated bulk synthetic sand wetted with 2% potassium chloride to form a paste. The paste was transferred to 1-in.-diameter lead sleeves and tightly packed. The packed sand was encapsulated in the sleeve with 60-mesh wire screens mounted on both ends. Before conducting the test, the core plugs were loaded in rubber sleeves at 1,000 psi confining pressure and heated to a temperature of 100°F (38ºC). Tests performed to determine the success of the HOC as a fines immobilizer included comparison of regain permeability with 2% KCl versus 2% KCl containing a 1% solution of an HOC fines stabilizer. The laboratory procedure is given below:
1. Establish flow through synthetic core in production direction with 2% KCl at a given velocity to steady-state permeability.
2. Inject HOC in 2% KCl treatment fluid.
3. Change flow velocities to establish new steady-state permeability.
4. Return flow velocity to its original value until steady state was achieved.
5. Compare initial and final permeabilities to determine if fines migration occurred under the high-flow rate.

The results are illustrated in Figures 1 and 2. Figure 1 illustrates the permeability test results when only 2% KCl was flowed through the core. Core permeability dropped markedly with
Figure 3. A well in the Eugene Island area of the Gulf of Mexico was a good candidate for a fines-stabilization agent.
increasing flow rate. Over the test period, permeability dropped to 47% of the original, indicating fines migration and pore throat bridging. Figure 2 depicts the permeability response of the synthetic core when pre-treated with 1% HOC in 2% KCl. The pre-treatment with 1% HOC indicated an effective stabilization of fines within the core, resulting in consistently stable pressures and permeabilities. No produced fines were detected in the effluent filtrate.

Treatment design
A conventional frac pack operation without the use of a fines-stabilizing agent typically consists of a mini-frac and step-rate injection test to determine fracture/formation characteristics, which helps to optimize frac pack treatment design. Frac pack treatments usually use crosslinked fluids to transport proppant into a created fracture. Fluid without proppant (pad) is used to create the fracture, and then proppant is added in stages of increasing concentration.

When incorporating a fines-stabilizing agent into a frac pack treatment, the mini-frac and step-rate treatments are pumped as in the conventional treatment. A concentration of 5 to 10 gpt (gallons of fines stabilizer per 1,000 gal of base fluid) is added to the pad portion and the low-concentration stage/stages (typically 0.5 to 2 ppa) of the frac pack slurry treatment. The remaining stages of the proppant-laden slurry are the same as in conventional frac pack treatments.

Case history
In February 2006, a well located in the Eugene Island area of the Gulf of Mexico was side-tracked and frac-packed in a sand with perforations from 16,065 to 16,145 ft (4,900 to 4,924 m) as shown in Figure 3.

The well’s original completion used a gravel pack without a fines stabilizing agent, and the well appeared to begin to plug off immediately. Production lasted for only 6 months until failure occurred due to fines migration problems.

For the sidetracked well, due to the history of failures and the nature of the formation, an HOC fines stabilizing agent was added to the fracture treatment to enhance the long-term flow assurance. The frac pack treatment was redesigned using information from the mini-frac test. The frac pack was pumped at 12 bbl/minute, with the pad and 1-ppa proppant stage containing 5 gpt of the HOC material.

Although the fines stabilization agent bonds fines to the formation, there was no significant pressure increase compared with the mini-frac treatment (as expected from the lab test profile). After the 1-ppa stage, the proppant ramp continued to a maximum of
10 ppa.

Initial production was 4.4 MMcf/d of gas, 298 b/d of oil and 40 b/d of water. After 1 year, production was 3.6 MMcfg/d, 169 bo/d and 43 bw/d with no signs of fines migration issues.
Due to the success of this well, four other wells have been treated using the fines stabilizing agent after log evaluations indicated that they might be at risk of having fines migration issues.

To date, these four wells have not shown any problems associated with fines migration.