Field X is located off-shore beneath ~100m of water. Initially, long horizontal production wells and sub-vertical water injection wells were used for the field development. When one of the oil production wells located at the edge of the field watered out, it was decided to convert it for water injection. Since reservoir permeability is low (tens of mD), generation of injection induced hydraulic fractures is expected.

The following questions needed to be addressed in order to mitigate risks and guarantee operational success of the water injection program:

How will injectivity of the long horizontal injector develop over time?

How long would injection induced fractures grow over time?

In which direction are the fractures going to grow with respect to the horizontal wellbore (i.e., could they reach an adjacent producer)?

What will be the outflow fraction of the injected water from the horizontal wellbore versus the induced fracture?

To answer these questions, a simplified horizontal well flow model was coupled with a fracture model. This fracture model required geomechanical input in form of present day in-situ stresses (both orientation as well as magnitudes) and pore pressures as well as rock mechanical properties in form of Young's moduli and Poisson's ratio. Resulting from the geomechanical analysis, we found that the present day stress state is that of a normal to strike slip faulting environment (i.e., Sv ~ SHmax > Shmin) whereby well head pressures in excess of 80 bar with Shmin gradient of 0.6 psi/ft would induce fracturing in the reservoir with a well confined direction.

The geomechanical-fluid flow model calculated the various pressure drops from the wellbore sand face into the reservoir, location of the different fronts (thermal, water), and propagation of the induced fracture along with plugging of the inside fracture faces.

A good history match of the ongoing water injection into the horizontal well was achieved. The forward simulations showed that fractures are being generated dependent on the injection rates, water quality, injection temperature and the minimum principal horizontal stress (Shmin). When injection rates are too high, a substantial amount of water – in excess of 50% – is expected to be injected into the induced fracture despite very good water quality and the horizontals appreciable length (i.e., more than 2000 m).

The geomechanical model suggests that induced fractures are more likely to initiate in a region of lower stress along the wellbore caused by localized facies variation and propagate from there initially in a direction closely parallel to the wellbore (i.e., (sub-) longitudinal with the wellbore axis by ±20°).

To optimize field management and to avoid the generation of extensive induced transverse fractures, water injection is recommended at a maximum injection rate of 7,500 bbl/d, a minimum injection temperature above 55°C, and a water quality of less than 3ppmv (6 micron particle diameter). The optimization is confirmed with the observation that the closest producer shows signs of pressure support with an increase in oil production, but no evidence of premature water breakthrough.