Drilling through depleted zones in offshore deepwater prospects is becoming more common with ongoing production and field maturation, especially when deeper-lying, virgin-pressured reservoirs are explored and produced in later stages of field development. Some of the challenges associated with these depleted zones include severe mud loss and associated borehole problems, as well as troublesome cementing and poor zonal isolation. Artificially strengthening the wellbore is now becoming of crucial importance in order to successfully drill and cement deepwater wells in mature fields and any other wells with narrow drilling margins.

In this paper, we introduce an innovative thermal wellbore strengthening (TWBS) technique to elevate the tangential stress (also known as the hoop stress) near the wellbore, and consequently increase the fracture gradient. A "thermal fluid," consisting of a carrier mud with heat-releasing ("exothermic") coated particles, has been designed to target depleted zones and release heat at exactly the right time to increase near-wellbore thermal stress, which directly elevates the near-wellbore tangential stress and in turn elevates the effective fracture gradient. Ultimately, this lowers the risk of lost circulation and improves the chance of successfully cementing and achieving zonal isolation. For instance, a TWBS treatment can be executed as an integral part of the cement job by using it in an extended spacer train for mud displacement, pumped directly prior to cement placement.

The coated exothermic particles were designed such that they could release their "payload" via an extended time-release mechanism, to ensure that the heat release reaches the appropriate target location in the wellbore at the right time. The chemical systems, which are based on dissolving various hygroscopic salts in water, were tested and developed to heat up the wellbore and increase temperature up to 100°C. This will potentially elevate the fracture gradient by several hundred psi, depending on formation properties. Details regarding the formulation and testing of the non-coated, coated particles, and the carrier fluid are discussed; as well as considerations for TWBS field application.

In addition, a new computational heat transfer model was developed to calculate the temperature distribution within the rock formation and within the drillstring/work string and wellbore annulus, for a formation contacted by a fluid with particles that react in exothermic fashion. The new model calculates the transient temperature distribution, increase in near-wellbore stress, and fracture gradient for a given amount of heat generation by the fluid and temperature increase in the rock. It can assist with well design aspects of the proposed thermal wellbore strengthening technique, and is particularly helpful in estimating the downhole temperature variations and assessing its implications prior to job execution. Details of the model and results of several typical simulations are given herein.

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