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Sathuvalli, Udaya B. (Blade Energy Partners) | Pilko, R. M. (Blade Energy Partners) | Gonzalez, R. A. (Blade Energy Partners) | Pai, R. M. (Blade Energy Partners) | Sachdeva, P.. (Blade Energy Partners) | Suryanarayana, P. V. (Blade Energy Partners)
Summary Subsea wells use annular-pressure-buildup (APB) mitigation devices to ensure well integrity. We define mitigation techniques that control APB by reducing lateral heat loss from the production tubing to the wellbore as Type I techniques. Mitigation techniques that control the stiffness (psi/°F) of an annulus by modifying its contents and boundaries are defined as Type II techniques. Although the physics of APB mitigation is well-understood, the reliability of a mitigation strategy or its interaction with other parts of the wellbore is not always quantifiable. This is partly because of the lack of a unified approach to analyze mitigation strategies, and partly because of the lack of downhole data after well completion. Simply stated, the engineer is hard-pressed to find computational-predictive methods to assess alternative scenarios and strategies within the framework of the design basis during the life of the well. In this light, our paper presents a quantitative approach to design the currently used APB mitigation strategies: rupture disks, syntactic foams, nitrified spacers, and vacuum-insulated tubing (VIT). In each case, the design is linked to the notion of “allowable APB” in an annulus, which in turn is tied to the design of the casing strings, and thus to wellbore integrity. We also review APB mitigation techniques that have been used less frequently or are awaiting proof of concept/field trial.
Khaksar, Abbas (Baker RDS Pty Ltd) | Rahman, Khalil (Baker RDS) | White, Adrian (Geo Mechanics) | Ghani, Juanih (Talisman Malaysia Limited) | Asadi, Mohammad S. (Baker Hughes) | Stewart, Keith (Talisman (Asia) Ltd.)
Abstract Hydrocarbon bearing reservoirs in the Southern Fields, Malay Basin, Malaysia contain in excess of 40 sandstone reservoirs interbedded with mudstones and coal seams. Years of production from shallower and mechanically weaker reservoirs resulted in pressure depletion whilst deeper and generally stronger reservoirs are still at early development stages and have normal pressures. High angle and horizontal development wells, to be completed without sand control, are planned for the deep reservoirs. Reservoir pressure depletion results in a lower fracture gradient and a decrease in the drilling mud weight window. An improperly weighted mud may induce wellbore instability in weaker but normally pressured formations or mud losses while drilling heavily depleted shallow formations. Systematic geomechanical evaluations are required to assess the drillability of shallow depleted reservoirs and the feasibility of horizontal wells without sand control for deeper normally pressured reservoirs. In a series of studies, a full-scale geomechanical model was developed, validated and updated using core, logs and drilling data from wells in the area. In particular, a total mud loss event in depleted formations in a recent well and rock mechanical data were used to establish the pore pressure-stress coupling (path) factor, an important parameter required for well control and managed pressure drilling operations. Subsequent drilling campaigns have all been successful via good drilling practices and using the recommended mud programs based on previous drilling experience and consistent with wellbore stability assessments. Some cementing issues were reported due to a much lower fracture gradient in the upper depleted sandstones sections but these issues have not prevented safe completion of the wells. Sand production prediction studies were also carried out for a number of planned wells. Based on sanding assessments, well completion recommendations included cased and perforated completion, barefoot completion and openhole with predrilled liner completion depending on the well trajectory, rock fabrics, rock strengths and production conditions for individual cases. Production experiences to date have been consistent with the model prediction and completion recommendations (i.e. sandfree production from several wells with predrilled liner completion).
Abstract Depleted Fracture Gradients have been a challenge for the oil and gas industry during drilling and cementing operations for over 30 years. Yet, year after year, problems related to lost circulation, borehole instability (low mud weight due a low fracture gradient), and losses during cementing operations leading to NPT and remedial work continue to rank as some of the top NPT events that companies face. This paper will demonstrate how the geomechanical modeling, well execution and remedial strengthening operations should be implemented to provide for a successful outcome. The use of a Fracture Gradient (FG) framework will be discussed, and the use of a negotiated fracture gradient will highlight how the fracture gradient can be changed during operations. This paper will also show actual examples from Deepwater operations that have successfully executed a detailed borehole strengthening program. Through our offset studies and operational experience, we will provide a format for navigating complex depleted drilling issues and show an example on recovering from low fracture gradients. This paper will demonstrate (1) how our framework facilitated multi-disciplinary collaborative discussion among our subsurface and well engineering communities; (2) how the impacts of drilling fluids and operational procedures can change this lost circulation threshold; and (3) how our negotiated FG approach has successfully delivered wells drilled in narrow margins.
Abstract The Oriente Basin of Ecuador is one of the most productive of the South American Sub-Andean Basins and it contains a sedimentary fill between Paleozoic to Recent age. Major commercial interest is confined to the Cretaceous depositional cycle and all the significant production comes from fluvio- deltaic and marine sandstones of the Hollin and Napo Formations. To reach prospective targets, the oil companies have to drill tertiary continental and transitional sedimentary formations, i.e Chalcana, Orteguaza, Tiyuyacu, Tena. The challenges to overcome could be summarized in formations reactive to the drilling fluids, tertiary overpressure clay stones, volcanic inter bedding layers, hard conglomerate intervals, limestone rocks, sand production in the reservoirs, cretaceous overpressure shales and magma type intrusions. The objective of this paper is to illustrate the geomechanic behavior of the wells drilled in Oriente Basin at a regional scale based on the geological framework model of several fields that have been drilled or stimulated by using 1D or 3D mechanical earth models- MEM, (Plumb, R.A, 2000). A compilation of data from drilling and sanding prediction analysis, open hole logs, rock mechanical data by integrating rock strength characterization at the laboratory, borehole images, and formation pressure measurements are analyzed to assist in well planning and field development and to understand the problems already encountered in the existing vertical, deviated and horizontal wells. A complete characterization of formation stresses is included using traditional techniques of estimation derived from microfracs, mini-fracs, leak-off tests, hydraulic fracture data, poroelastic strain calibration, or derived from advanced sonic stress estimation using the induced anisotropy in the presence of variation of the three shear modulus crossing dipole dispersions obtained from near-wellbore stress concentrations.