Improving Fracturing Fluid Performance and Controlling Formation Fines Migration with the Same Agent: Is it Achievable?
Authors: Huang Tianping , Clark David E. 
Published: May 2016

Traditionally, hydraulic fracturing (frac-packing) and controlling formation fines migration treatments are separate operations that incur high costs for operators, especially for offshore asset developments. Hydraulic fracturing or frac-packing treatment can reduce fines generated in the near-wellbore region, but not the fines migrating from deep hydrocarbon-producing formations. Separate treatment for fines migration control is usually required for maintaining wellbore productivity.

Recent studies have found that some inorganic nanoparticles can significantly improve the performance of surfactant micellar fluids in hydraulic fracturing and frac-packing applications, including fluid thermal stability and fluid loss control properties. A theoretical model illustrates that the nanoparticles are first associated with the energetically unfavorable endcaps of surfactant micelles and then become the junctions of the wormlike micelles. Hydrophobic components as internal breakers are placed within wormlike surfactant micelles during surface mixing. After fluid pumping is completed, the internal breakers act to collapse the wormlike surfactant micelle structures. This causes the viscous frac-fluid significantly lose its viscosity and the nanoparticles are released. The released nanoparticles precipitate and attach to nearby proppants to act as formation fine fixators to capture fines when they flow through this region. Our lab tests detail this dual functional performance improvement of surfactant micellar fluid and the controlled migration of formation fines.

Introduction

Formation fines are tiny particles that easily migrate with any fluids flowing in the sandstone formations. As a well produces, hydrocarbons (oil and/or gas) and/or formation water carrying those fines in the porous media move to the small near-wellbore region from distant regions of the reservoir in all directions. As well production continues a large quantity of the formation fines may concentrate in the near-wellbore region. These tiny particles in high concentrations can interact to form larger particles that plug pores in the near-wellbore region or plug sand control screens or proppant packs, which result in rapid production decline. When formation fines pass through a sand control screen, local erosion of the screen can be another concern, and production pumps are also susceptible to damage by the formation fines.

When production decline is induced by formation fines plugging near-wellbore region, the well is usually treated with acid to remove the plugged fines to recover its productivity. As the well continues production, acid washing treatments are frequently required. Figure 1 illustrates how an offshore well required an acid washing treatment nearly every two months because of low productivity induced by formation fines plugging. Each time when the well was treated with acid washing, the production rate was increased for a short time and quickly declined because of formation fines migration. Frequently offshore treatments significantly increase asset development cost. However, reducing treatment frequency and maintaining productivity are ways to reduce cost.