At Scaled Solutions, we have been working with operators, service companies and chemical suppliers for many years to improve the effectiveness of bullhead scale inhibitor squeeze treatments. Most production wells are heterogeneous, with different rock permeabilities, pressure contrasts and areas producing predominantly oil or water. In this environment, chemical placement can be a critical factor in determining the success of a treatment.
Mineral scale formation is a water-based phenomenon, and scale inhibitors are typically water-soluble chemicals that exhibit poor solubility in oil. For a scale inhibitor to be effective, it must be delivered to the water-producing zones in the near-wellbore. Any inhibitor that is placed in the oil zones will not return to the wellbore, and so will be effectively wasted.
If too much of the planned treatment fails to get placed in the main water producing zones, when the well is put back on to production the inhibitor concentration in the wellbore will fall below its minimum effective concentration faster than planned, requiring additional unplanned treatments with all the costs and lost/deferred production that that entails. In some cases, where the well contains several production zones, some zones may receive too much inhibitor while others may receive little or no protection. This may result in parts of the near-wellbore or production system scaling up, even when the topsides SI residuals analysis indicates that ample scale inhibitor is present.
Having a better idea of the placement challenges in your wells and being able to devise strategies to improve the placement can help increase treatment lifetimes, reduce the number of unplanned interventions and thus help maintain optimal hydrocarbon production.
The complex nature of most oil and gas wells can make it difficult to intuitively assess the placement challenges present in the field. Typically, placement of bullhead squeeze treatments can be affected by a large number of parameters including permeability differences, pressure contrasts, fluid mobility effects, fluid viscosities, wellbore geometry, frictional pressure losses, the presence of fractures, injection rates and the nature of the treatment chemicals. As part of a long-running multi-sponsor Joint Industry Project (JIP), Scaled Solutions developed the Place iT™ near-wellbore chemical placement simulator, which considers all of these parameters when simulating the chemical placement and subsequent chemical returns for a well. The Place iT™ model has been used to help improve the design of a number of successful scale inhibitor squeeze treatments in challenging wells throughout the world.
The following parameters are considered when planning and optimising squeeze design:
Scale inhibitor adsorption isotherms can be derived either from laboratory core flood data or from field return data. The derived isotherm can then be used to simulate field treatments to compare the actual field return with the predicted return. If these differ markedly, then further placement and treatment modelling can be conducted to gain a better understanding of the factors influencing the low field return lifetime, and to help optimise the initial field treatment to give better treatment lifetimes in the future.
Scaled Solutions have integrated their fluid dynamic modelling and Pilot Rig apparatus to investigate the effect of fluid shear on scale formation and precipitation. This has produced a deep understanding of the bulk and surface effects that flow has on scale location formation and deposition. Rig and modelling together have proved to be a powerful tool combination which provide both understanding and performance evaluation under more field related conditions. Low scaling brines may be evaluated together with inhibitor chemical application without the need to alter brine chemistry.