Description of the material

A model is presented for predicting the performance of water injection wells with frac-packed completions. The model estimates the plugging of the frac-pack because of solids in the injected water and its effect on the frac-pack completion. It takes into account the thermal stresses caused by cold water injection and pore pressure changes.

Application

Frac-packs are increasingly being used for sand control in injection wells in poorly consolidated reservoirs. These completions allow for large injection rates and longer injector life. Many of the large off-shore developments in the Gulf of Mexico and around the world rely on these completions for water flooding and pressure maintenance. The performance of these injectors is crucial to the economics of the project since well intervention later in the life of the field is expensive and undesirable.

Results, Observations, and Conclusions

Injector performance is shown to depend on the solids content in the injected water, proppant size in the frac-pack, initial width and length of the frac-pack, injection rate, injection water temperature and the minimum horizontal stress. In cases with wide and conductive frac-packs, the plugging of the frac-pack will be gradual and the injectivity would remain high. In cases where significant plugging may occur, a rapid rise in the bottom-hole pressure will result in sharp decline of initial injectivity. However the frac-packs will widen up after the bottom hole pressure reaches a critical pressure because of a high permeability channel through the frac-pack which will alleviate the injectivity decline.

Significant New Contributions

A model for water injection into frac-packed wells is presented for the first time. It accounts for plugging of the frac-pack and the formation around, thermal stresses caused by cold water injection and frac-pack widening and/or lengthening.

Background and Problem Description

All injected fluids contain suspended particles, which can potentially plug the formation around a well. This reduces the permeability in the near-wellbore region and causes a rise in the injection pressure to maintain a constant injection rate. When the injection pressure exceeds fracture pressure, fractures are initiated. Subsequently, the face of the fracture gets plugged with continued injection, and the pressure at the fracture tip exceeds the fracture propagation pressure and the fracture extends in length (Suárez-Rivera, R. et al. 2002, and Saripalli, K.P., et al. 1999). The particle plugging and fracture propagation are coupled. In addition, if the injected fluid is colder than the reservoir, thermal stresses are induced, which lower the fracture propagation pressure significantly and may cause thermally induced fractures.

There are no models and little field data (McCarty, R.A. et al. 2006) published on the injection performance of frac-packed wells. Frac-packing is widely used in production wells but recently many water injectors have used frac-pack completion technology as well. Some of the advantages of frac-packing in water injectors are:

1. It provides a resilient and robust long term completion with minimum intervention required, especially in sub-sea wells.
2. It provides sand control if the formation is poorly consolidated.
3. It minimizes plugging of the injection well by providing a larger permeability and flow area in comparision to perforated completions or gravel pack completions.
4. Larger injection rates are possible.

McCarty et al. (2006) have documented the utilization of frac-pack completion technology for water injectors in sand control environments. They observed no sand control failures in frac-packed injectors for more than five years.