Casing failure probability is high in Ann Mag Field, South Texas due to the high pressure high temperature operational environment. The formation sands are over-pressured where the pore pressure ranges from 0.85 to 0.93 psi/ft. Casing damage has been experienced in over 11 wells from 18 that have been drilled in the area, near 61% of total wells were damaged during their production life. Casing failure may be caused by formation shear failure, formation compressive failure, casing tension failure, casing collapse or fault activation. Casing buckling is not considered in the study because cement bond logging shows that the cement sheath is good. Triaxial tests were carried out to measure formation mechanical properties that were used for reservoir compaction, fault activation and formation failure analysis. The Mohr-Coulomb failure criterion was applied to study the formation failure and the minimum pore pressure required to activate the fault. The finite element methods were used to analyze the casing tension failure caused by reservoir compaction. According to the formation shear failure analysis, the minimum allowable pore pressure around the casing is around 2,000 psi. In the study of fault activation, for shale formation, at the internal friction coefficient of 0.51, the probability that the normal fault can be activated is very high. The maximum drawdown and depletion were calculated based on potential casing failure types. In the plot of workability operational limits, shale formation has narrower safe zone than the sand formation. Recommendations for drilling and production were made to increase the well service life and improve the gas recovery. This paper presents the casing failure mechanism and characterization under HPHT conditions in south Texas that can be prevented in the future wells and provides workability operational limits for different formations.

Casing has a higher likelihood of failure in compacting reservoir than in a typical reservoir. Casing fails because reservoir compaction induces compression and shear stresses onto it. The compaction occurs as reservoir pressure depletes during production. High compacted reservoirs typically are composed of unconsolidated, overpressured rocks such as chalk, diatomite, and sandstone. Pore pressure depletion increases effective stress, which is the rock matrix stress pushing upward against overburden pressure. Effective stress may exceed rock compressive strength, inducing compaction. Wells in compacting reservoirs are likely to fail and to have high deformation rates.This paper introduces the concept of structural reliability to quantify the probability of casing failure in compacting reservoirs. Probabilistic models for casing capacities are developed using current design methods and a reservoir compaction load observed using finite-element model simulations. The proposed probabilistic models are used to define two limit-states functions used in predicting the probability of casing failure for two possible modes of failure: axial yielding and buckling failures. A limit-state function describes the casing condition as the casing experiences a reservoir compaction load. The limit state function is the input in component and system analyses for estimating the probabilities of failure as reservoir pressure is depleting. Sensitivity and importance analyses are also performed to determine the role and significant of parameters and random variables affecting the casing reliability.Applying the knowledge produced from this research to casing design can improve design reliabilities and forecast the probability of casing failure in compacting reservoirs. IntroductionCasing failure and deformation are becoming problems in mature oilfields. The number of these oilfields has been increasing since 1980, where failures are a major problem to cause wells to stop producing or preventing necessary well services. The number of failure reported from Shengli oilfield, Ekofisk chalk field, and Belridge diatomite field combined to over 10,000 casing failures (Yodavich et al. 1998, Fredich et al. 1998.A major cause of casing failure in these mature fields is reservoir compaction. Reservoir compaction causes casing to experience large additional stresses that casing may not be designed for. Assessing and predicting casing conditions in mature fields where reservoirs tend to compact are important in order to prevent casing failures. Many papers have shown casing failure mechanisms and reservoir compaction mechanisms using methods such as geomechanical simulation, analytical formulation, and probabilistic modeling.Geomechanical simulations are widely used to determine high stress zones in the formation around the field. Earlier geomechanical models depend on 2D modeling to find crucial depths and compaction rates related to the amount of production (Chia et al. 1989, Fredich et al. 1998, Hansen et al.1995, Wooley et al. 1988. Today technol...

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Summary In subsea environments, using large-bore/high-rate well designs is often a key contributor to the economic recovery of hydrocarbon resources. Their use is a necessity for accommodating the huge production capacity of the reservoirs they penetrate, with the major benefit of minimizing the number of wells necessary to develop a subsea field. The enthusiasm for using such well designs, however, must also be tempered by a clear understanding of the considerable well control risk they introduce—that risk being an increased level of difficulty in bringing such a well under control if a blowout were to occur. It is common that multiple relief wells, with their inherent complexities and time investment, would be simultaneously required to bring a big-bore blowout under control. The discussion of this fact is, though, not a common topic in industry literature. Instead, capping stacks have been more the focus. Much recent attention has been trained on ensuring that capping stacks are a viable method for quickly responding to a high-rate subsea blowout. This makes sense in light of the simpler, and publicly more palatable, concept of rapidly installing a capping stack on a blown-out subsea well. Still, a capping stack is only as reliable as the wellhead it must connect to. It is because subsea wellheads have such a high chance of being damaged during a blowout that relief wells will always be relied on as the ultimate backstop for ensuring that a subsea blowout can be brought under control. This reliance on relief wells, as they are traditionally envisioned, has limitations though when addressing a high-rate subsea blowout. Any subsea relief well will have inherent limitations resulting from the architecture of choke and kill lines (flow restrictions) and that of the crossover piping at the blowout preventer (BOP; erosion concerns). In the world of high-rate subsea blowouts, these limitations can sometimes translate into multiple relief wells being required to inject fluid at the rates necessary to affect a dynamic kill. However, the simultaneous use of multiple subsea relief wells to dynamically kill a single blowout has only been tried once in the industry's history. As a result, some countries require that stopping a blowout must be possible by drilling only one relief well. In this paper, we describe methods that can be implemented to transcend traditional relief well limitations via using a relief well injection spool (RWIS), with the ultimate goal of dynamically killing a subsea big-bore blowout using a single relief well. The technique varies with water depth. In both shallow-water (826 ft) and deepwater (8,260 ft) environments, the techniques are presented and analyzed that will allow using a single subsea relief well to perform a dynamic kill using 15 lbm/gal drilling fluid injected at 238 bbl/min. This particularly severe scenario, based on a big-bore gas well development in Western Australia, is chosen so that our results will have applicability to most subsea well control events that might arise in the future.

A blowout contingency plan was made for a gas field in a remote area with water depth exceeding 1600 m. The worst-case discharge analysis for a representative well in the field concluded that the reservoir is capable of producing at a highly prolific rate, which posed a challenge when developing a source control contingency plan that complies with governing regulators’ and operators’ internal requirements. Simulations using a transient multiphase flow simulator showed that the kill requirements could exceed the capability of a single conventional relief well; however, planning to intersect and coordinate a dynamic kill using multiple relief wells involved unacceptable operations risks. Furthermore, considering rig availability, limited pumping resources, and long mobilization times for this region, planning to use multiple relief wells is not a feasable option. A recently developed subsea flow spool system can eliminate the need for multiple relief wells in the case of potentially hard-to-kill blowouts, especially where a dynamic kill using multiple relief wells would involve unacceptable operations risks. Dynamic kill simulation shows that the subsea flow spool, coupled with a supporting mobile offshore drilling unit (MODU), flexible flow lines, a supplementary flow spool, and a casing string placed inside the riser will be able to achieve a successful kill if needed. Furthermore, detailed engineering analysis of triaxial loads, fatigue, and erosion were done for critical hardware components to ensure all potential failure points were addressed. In conclusion, the subsea flow spool is a key component of demonstrating a single-relief well contingency for potentially hard-to-kill blowouts