Dr. Sandeep Kulkarni, Principal Technical Professional at Halliburton Energy Service

Modeling Real-Time Wellbore Pressures under Transient Fluid and Operational conditions The last decade has seen significant shift towards digital oilfield in the upstream industry. The shift has involved building hardware and software for ‘real-time’ estimation of wellbore characteristics such as wellbore pressure under time-dependent (transient) fluid and operational conditions. Specific to the drilling activity, the earlier ‘off-line’ measurement/modeling typically estimated wellbore pressures for steady-state drilling fluid properties and operational conditions, and assumed thumb-rule based margins for un-evaluated transient scenarios. In contrast, the recent advancements for ‘real-time’ measurement/modeling of wellbore pressures has provided following benefits.

• Safer drilling of the narrow margin and complex wells • Optimize the drilling processes (such as rate of penetration) to save cost

The seminar presents a brief overview of the fluids’ technology in the upstream drilling industry and elaborates certain aspects of the ongoing research for ‘real-time’ measurement/modeling in this area. When a well is being drilled, a drilling fluid (typically a thixotropic and shear-thinning formulation consisting of particulates, emulsion and polymers suspended in a base oil) is  ‘circulated’ downhole through the drillpipe, it exits through the drill-bits, and then it flows up through the annulus carrying the drill-cuttings to the surface. Additionally, the drilling fluid may be left ‘un-circulated’ in the wellbore during pulling in/out of the drillpipe or during maintenance. It is important that, during both the ‘circulated’ and ‘uncirculated’ scenarios, the wellbore pressure gradient (generated by hydrostatic head and frictional pressure losses of the drilling fluid) stays between pore pressure (pressure exerted by the fluids present in the pores of the formation) and fracture pressure (pressure limit beyond which wellbore cracks develop) gradients as shown in Fig. 1. In this seminar, modeling for ‘real time’ wellbore pressures under certain ‘un-circulated’ and ‘circulated’ scenarios is presented accounting for transient fluid/operational conditions. Validation and advantage of this modeling work is also demonstrated.

I. Wellbore sag model (transience in a ‘un-circulated’ scenario): The model predicts information about the changing fluid composition along the wellbore depth as affected by sedimentation and sliding (sag) of the high-density particulates in the drilling fluid. The wellbore sag model uses finite element approach where several constitutive relations are embedded in the mass balance equation solved at each element of the grid. Specifically, for a wellbore section of a given inclination, the model provides quantitative density/rheology estimates of the barite-depleted zone at the top of the section and the barite-accumulated zone at the bottom as shown in Fig.2. As the sag-affected fluid is circulated out after the ‘un-circulated’ period, the model also predicts the varied mud weight of the fluid collected at the surface and the corresponding transient wellbore pressures. The modeling results enabled fast decision making at the well site to optimize fluid formulations and operating conditions for sag-related wellbore pressure management.

II. Drilling fluids thixotropy & pipe rotation model (transience in a ‘circulated’ scenario): Drilling fluids exhibit time-dependent rheological response particularly at static or low-shear conditions. The fluids develop gel microstructure attributed to interaction between polymers, colloidal particles, and emulsion droplets in the fluid. As fluid circulation is initiated, the pumps assist in accelerating the flow rate to a desired level. In this process, wellbore pressure spikes occur because of the developed gel microstructure in the fluid; the microstructure breaks down gradually with shearing as evident from Fig.3. Understanding the mechanism of gel formation and breakdown under various shear, temperature, and pressure conditions improved accuracy of the wellbore pressure modeling for the thixotropic fluid characteristics. The modeling results enabled determination of pump acceleration values that ensure that wellbore pressure gradients at any instant does not go beyond the fracture gradient. In addition, the impact of pipe rotation on the wellbore pressure response was analytically modeled accounting for the shear thinning and Taylor instabilities effects; modeling this transient scenario again ensured safe drilling window and optimization of the operational conditions.