Ensuring Sustained Production by Managing Annular-Pressure Buildup

Abstract

Abstract Increased tubinghead temperature with increased rate may induce pressure increase in the annuli for the trapped fluid. Managing annular-pressure buildup or APB for sustaining well deliverability is particularly crucial in subsea wells, which cannot be intervened easily. Ordinarily, a multistring casing design accommodates anomalous pressure rise from the standpoint of well integrity. However, management of day-to-day operations presents challenges when APB occurs. This study presents mechanistic models for understanding and mitigating APB during production. Specifically, by preserving mass, momentum, and energy in the wellbore we developed two approaches involving semisteady-state and transient formulations for estimating APB. The intrinsic idea is to mimic the physical process with minimal input parameters to estimate pressure buildup in the annuli. Our model formulation handles the mechanisms of fluid expansion and fluid influx/efflux quite rigorously. This approach appears quite sufficient because we account for most of the cases of APB encountered. Introduction Historically, production and reservoir engineers seldom probed the root causes of APB, perhaps because tubular design with implicit APB control has been in the domain of drilling engineers. But the advent of continuous monitoring of pressure and temperature at the well bottom, tubinghead, and annuli presents the opportunity for real-time production and reservoir management within the safe operating limits of the system. Pressures measured at the tubinghead and bottomhole with the corresponding flow rate are the most sought after entities in production-engineering calculations; rate validation in integrated asset modeling is a case in point. In contrast, temperature measurements have not found routine usage, but are gaining increased attention in connection with transient-pressure testing (Sui et al. 2008, Duru and Horne 2008, Izgec et al. 2007, Hasan et al. 2005, Kabir et al. 1996), downhole flow profiling (Wang et al. 2008, Nath et al. 2007, Johnson et al. 2006, Ouyang and Belanger 2006), and flow-rate estimation (Izgec et al. 2008, Kabir et al. 2008). This paper shows that both pressure and temperature responses at the tubinghead and annuli are strongly related to flow rates and that these measured entities can be used to alert the operator of possible APB. Naturally, clarity in understanding interrelationship of wellhead temperature with flow rate and pressure is imperative for sustaining long-term wellhead deliverability without compromising well integrity. Fluid production in a typical production string influences pressures in production and surface casings. Generally speaking, only the shallowest casings are cemented to the top, whereas the others, cemented at the bottom, contain mostly drilling fluid. Producing fluids in the tubing string transmit heat to the liquid-filled annuli, thereby triggering pressure increase. APB is not just associated with fluid production; fluid circulation during drilling may also induce the same, as reported by Pattillo et al. (2006). Accessible wellheads in typical land and offshore dry-tree wells allow the operator to monitor and bleed off all annuli as needed. However, subsea wells present serious logistical difficulties for managing APB. Predictably the stakes are high in high-pressure, high-temperature (HPHT) wells and those that are completed in a deepwater environment, where intervention costs are prohibitive. High flow rates simply exacerbate the APB issue because of the associated high energy that the fluids bring to surface.