Cuttings re-injection (CRI) has been demonstrated to be a cost effective method to dispose of drilling wastes while having a relatively low environmental impact. The effective and continuous implementation of CRI is crucially dependent on, among other parameters, effective fracture propagation and subsequent cuttings placement into the target injection formation.
This paper presents the cuttings re-injection (CRI) history of three North Sea wells and introduces the concept of Optimum Slurry Placement (OSP) to ensure injection longevity. The CRI history included more than 300 cycles of injection, with a total accumulated volume of ~150,000 bbls of slurry during fours year of injection. The slurry volume and solid concentration varied for different cycles, as did the fluid properties and pump schedules. The injection was performed in the same sand with a permeability of ~one Darcy located at a depth of 5000ft. Analysis of the CRI data for each well, including induced fracture cycle modelling, showed that fundamental differences in slurry displacement within the reservoir led to varying surface pressure requirements.
Optimum Slurry Placement (OSP) involves effectively displacing cuttings far from the near wellbore area. This avoids the generation of near wellbore packing or disposal domains and reduces the potential for near wellbore stress alteration. Such stress alterations will increase the pressure required to initiate and propagate the fracture induced during each cycle of CRI.
A comprehensive geomechanical and fracture model was used to perform both the initial CRI placement prediction, and subsequent evaluation using injection history data. The study found that in two of the wells, where appropriate displacement volumes were used, a minimal surface pressure increase was observed. This contrasts with surface pressure increases of 60% in the well where near wellbore packing was observed after extended period of slurry injection with low pre-flush or displacement volumes. Increased pressure requirements compromise the well integrity and limit the capacity for continued CRI.
By modeling the injection process, understanding of the fractures created during CRI process is obtained and the final fracture geometries can be optimised. The injection history of three CRI wells was evaluated to review and improve the execution of OSP process for future CRI cycles. Successful implementation of the designed OSP process was achieved in one of the wells under study. A total additional injected volume of 11000bbls was carried out in this well and no alteration of hydraulic requirements were observed. Pressure monitoring and analysis during CRI proved that near wellbore packing was not induced. This prevented significant increases in fracture initiation and propagation pressures, safeguarding the wells injection capacity. It is suggested that continuous CRI can be successfully applied by implementing the OSP process, preventing near wellbore stress alterations and simultaneously assuring CRI placement longevity more generally in cuttings re-injection wells elsewhere.