Summary Pore-pressure (PP) and fracture-gradient (FG) predictions were prepared for Prelude development wells in the Browse basin in offshore northwest Australia. The PP forecasts were based on resistivity- and sonic-based models calibrated with pressure measurements and drilling events, such as kicks from existing wells. FGs were based on leakoff tests and loss events from offset wells and were not necessarily equal to either the minimum compressive principal stress (often considered a lower bound to FG) or the formation-breakdown pressure (often considered an upper bound to FG that includes effects of formation tensile strength and near-wellbore hoop stress). The minimum compressive horizontal stress was calculated from lithology-dependent effective-stress ratios. Maximum horizontal stress was inferred from observed breakouts. PP and stresses were combined with formation properties from well logs and laboratory rock-mechanics tests to provide input for elastoplastic (shales) and poroelastic (sands) borehole-stability (BHS) models. These techniques are applicable to exploration, appraisal, or early-development wells that have potential for encountering geopressured formations in high-angle well sections requiring good predrill estimates to adequately plan the casing and drilling programs and determine BHS. The predrill studies can be extended to provide integrated real-time PP and BHS while drilling, and the models can be recalibrated after each well to provide updated predictions for subsequent wells. There are only minor deviations in the predicted PP and FG among the different well locations considered. Common features include potential loss zones in the shallow overburden, pressure ramp within the Jamieson, pressure regression below the Aptian, and near-hydrostatic pressure within the Upper Swan and below. The BHS models indicate that minimum-required mud weight in deviated sections could be up to 20% higher than that required to balance formation PP. In one well that would cross a suspected fault, the risk of fault reopening or reactivation is low.

Drilling experience in the Niger Delta has shown that inappropriate selection of kick tolerance could constitute a serious setback to the implementation of cost effective and innovative solutions in well designs. While a conservative selection of kick tolerance could make a well design uneconomical, attracting severe cost penalties by fostering use of expensive / extreme pressure-ratings BOPs and extra casing strings sometimes, undue tightening of the tolerance on the other hand could make a well undrillable from safety point of view. This consideration poses serious dilemma to the well engineer who must balance the demands of conflicting alternatives in his management of design risks. To resolve this, the approach of stochastic analysis procedures to the prediction of appropriate design kick tolerance in any given geological setting and operational environment is being presented in this paper. Since this approach depends largely on the use of historical kick records, certain concerns regarding the reliability and acceptability of the use of historical data for the purpose of kick tolerance modeling and selection were equally addressed. Finally, a well example shows how this method has been used to integrate kick tolerance considerations in the management of design risks associated with the deployment of new technology application, expandable sand screen, in a high rate horizontal oil producer. Introduction In well planning process, kick tolerance is one of the key parameters in setting depth determination and burst designs of non-production casing strings. Also, various practices and techniques are generally used in the selection of appropriate design value for this parameter, the commonest being the use of gas flow deterministic models combined with computer simulations (also commonly based on Monte Carlo simulation engine) to investigate the likelihood of the selection1,2. While the popularity of this method is rooted in arguments against presumed limitations inherent in the use of historical drilling data for the modeling kick tolerance distribution, it is mind boggling that input variables with similar historical origin (i.e. permeability, porosity, crew reaction time, etc) which could even be less reliable are often used in these simulations. This development suggests that the problem really is not with the use of historical well control data for kick tolerance modeling, but rather with what approach has been employed to transform these data into usable forms. Needless to say, a general consensus throughout the drilling industry is the desirability of an acceptable and reliable method of kick tolerance determination from historical kick data. The fact that historical records usually encompass a wide range of events, environment, and data quality poses a great challenge to the development of historic probability distribution with any great confidence. However, stochastic analysis procedures combined with various data mining techniques provide a veritable means of transforming historical well control data into usable probabilistic models for the reliable prediction of kick tolerance within a given geological settings. The outstanding feature of this approach is that any probabilistic model developed using historical records must be validated by sound engineering judgment based upon historical experience of drilling and operational practices particular to the environment. This represents a classic case of the combination of both qualitative and quantitative risk assessment approaches to the management of design risks.

Drilling operations are conducted within a pressure window bounded on the lower side by the pressure of the formation fluids exposed in the open hole and on the upper side by the fracture resistance of the formation matrix. The narrowing of this operating margin, as experienced in deepwater environments, increases the technical challenges associated with drilling operations. Typical challenges include a sharp reduction in the maximum allowable open hole drilled depth, well control and exposure to difficult kicks, well breathing or ballooning, the risk of wellbore losses and a requirement to install multiple casing strings to get to TD. This paper examines the phenomenon of narrow margins in deepwater, the conditions that drive it, and presents a holistic assessment of the available geological, geophysical, engineering and technology solutions for mitigating narrow margin drilling (NMD) conditions. The solution concepts are indexed into a newly developed model called the NMD Solutions Matrix which introduces an NMD intensity scale that provides a measure of the degree of difficulty that can be expected in a well as a result of narrow margin conditions. The applicability of the model is demonstrated in a history match of three industry case examples in two deepwater regions in the world where NMD conditions were encountered and mitigated. The NMD solutions matrix was also applied to a DW project in the planning phase which yielded insights that more clearly articulated the exposure in the project. The analyses indicate that the model, as a planning tool, has the potential to sharpen the awareness of possible challenges and enable upfront mitigation measures to reduce their impact during execution. Its application thus offers strong potential to positively impact drilling effectiveness in deepwater and yield or save considerable value in these high cost operations

This paper describes the strategies and practices used to deliver best in class ROP performance in three different applications (through salt, soft clastic and medium-hard clastic formations) on the Deepwater Gulf of Mexico. A novel advanced bit design was tested with mechanical (WOB and RPM) and hydraulic (flow rate) parameters beyond the current operational envelope. Several operational and equipment limits were also tested and moved beyond the previous levels. The drilling parameters and results from the three applications are also included. Over the last couple of years, the drilling cost for deep-water drilling has been reduced through continuous performance improvement resulting in a "Beyond the Best" mentality. Every time a new best in class ROP performance is achieved, questions about "What else can be done", are asked. A project was taken up to challenge the current drilling operational envelope resulting in ROPs faster than ever in the Deepwater Gulf of Mexico. Integrated well planning combining operator and service provider knowhow and modeling capability were used to identify current operational limits and the required changes to go beyond them. BHA configuration and downhole tools were design and adjusted accordingly. Rig equipment were also reviewed and modified. The novel advanced bit design, with 3D cutting elements combining the shearing action of conventional PDC cutters with the crushing action of tungsten carbide insert, was selected by the project due to its capability of delivering less torque when higher mechanical parameters (WOB and RPM) are used. Field data demonstrates that using WOB up to 70,000 lbs while drilling with a 14-3/4" bit through medium-hard rock resulted in 9 % increase in ROP (103.2 ft/hr), when compared with the previous fastest ROP achieved while drilling similar formations in the field. Also, using 220 rpm while drilling trough salt with a 16-1/2" bit delivered 12% increase in ROP (307.3 ft/hr), when compared with the previous best performance. Furthermore, using 220 rpm in combination with 1460 gpm flow rate (22% above the normal flow rate), while drilling with a similar 16-1/2" bit through interbedded soft rock formations delivered 91% increase in ROP (368.7 ft/hr), when compared with the previous fastest ROP achieved while drilling similar formations in the field. The cuttings load limit in the annulus was tested beyond its current limit (3%) without observing hole pack off or stuck pipe issues. No vibration was observed while operating at the surface torque limit. A cost saving of over $2M was realized from this performance improvement effort. The identified opportunities for improvement and lessons learned included in the paper have led to best practices for future wells resulting in a valuable benchmark benefiting practicing engineer involved in similar projects. Furthermore, operational parameters used in the project confirm the robustness and benefits of the novel advanced bit design used in the project delivering higher ROP with a smooth torque response.

Pore pressure (PP) and fracture gradient (FG) predictions were prepared for Prelude development wells in the Browse Basin, offshore northwest Australia. The PP forecasts were based on resistivity- and sonic-based models calibrated with pressure measurements and drilling events such as kicks from existing wells. Fracture gradients were based on leakoff tests and loss events from offset wells and were not necessarily equal to the minimum compressive horizontal stress, which was calculated from lithology-dependent effective stress ratios. Maximum horizontal stress was inferred from observed breakouts. Pore pressure and stresses were combined with formation properties from well logs and laboratory rock mechanics tests to provide input for elasto-plastic (shales) and poro-elastic (sands) borehole stability models. These techniques are applicable to exploration, appraisal, or early development wells that have potential for encountering geopressured formations in high-angle well sections requiring good pre-drill estimates to adequately plan the casing and drilling programs and determine borehole stability. The pre-drill studies can be extended to provide integrated real-time pore pressure and borehole stability while drilling, and the models can be recalibrated following each well to provide updated predictions for subsequent wells. There are only minor deviations in the predicted PP and FG among the different well locations considered. Common features include potential loss zones in the shallow overburden, pressure ramp within the Jamieson, pressure regression below the Aptian, and near-hydrostatic pressure within the Upper Swan and below. The borehole stability models indicate that minimum required mud weight in deviated sections could be up to 20% higher than required to balance formation pore pressure. In one well that would cross a suspected fault, the risk of fault reopening or reactivation is low. This study indicates that use of integrated borehole stability and PP/FG models can result in higher minimum required mud weights and narrower drilling windows than would be suggested from the PP/FG models by themselves and can therefore contribute to enhanced safety, optimized well designs, and reduction of non-productive drilling time. Lost circulation at mud weights well below the minimum in-situ stress can be explained by reactivation or initiation of shear fractures. Introduction Prelude is a gas and gas-condensate field that was discovered in 2007 in the Browse Basin, offshore northwest Australia; it will be developed utilizing the world's first floating liquefied natural gas (FLNG) facility. The Prelude development will require several wells drilled at high angle from approximately the same surface locations to near-horizontal sections within the target reservoir as chosen from among eight potential well paths (Figure 1). The potential for moderately geopressured formations requires good pre-drill estimates of pore pressure (PP) and fracture gradient (FG) to adequately plan the casing and drilling programs and (combined with the high-angle well sections) determine borehole stability. Expected (P50), minimum (nominally P15), and maximum (nominally P85) cases are considered for both PP and FG to account for uncertainty in the predictions.