The increasing complexities of wellbore geometry imply an increasing potential of damage resulting from downhole bit wear. Although the locations of critical bit wear can be difficult to predict, the quantification of the actual bit teeth/cutter wear is important to achieve reduced cost per foot and predictable bit failure.There is no acceptable universal mathematical model that describes bit wear accurately because of the complex nature of downhole conditions. Usually, either analytical models or real-time data analytics are used separately to estimate and predict bit wear. Combining both methods and using them simultaneously is an efficient way to address this limitation. This paper presents a new simple analytical bit wear model coupled with data analytics using real-time gamma ray data to suppress the uncertainties of the interacting formation properties and other intervening variables. The fractional bit wear of polycrystalline diamond compact (PDC) bit cutters is obtained from the geometric correlation between height loss and the cutter volume loss. The volume loss of cutters is assumed to be proportional to weight on bit (WOB), cutter sliding distance, rock strength, and rock quartz content.The paper presents a field example to predict and estimate the bit wear using actual data. Gamma ray and rate of penetration (ROP) data of the initial drilling section are used to train the model to quantify the influence of formation strength interaction with the analytical model. Then estimation of ROP using the new bit wear model was carried out using actual field drilling parameters. The calculated ROP profile closely matched with the actual data within reasonable accuracy of less than 5%. Specific procedures are proposed for effective prediction of ROP and bit life.

Summary Modern-day oil exploration pushes operators into harsher and more-difficult drilling environments in the search for hydrocarbon reserves. Eastern Canada is one of those environments where deep water and the need to penetrate through thick salt sheets greatly increases difficulties faced by drillers. This paper describes a case history of deepwater subsalt drilling and examines the requirements for success. This paper also details the challenges using seismic data, of prewell planning for dealing with high pore-pressures and variable fracture gradients. Experience shows that prewell engineering differs considerably from conditions actually encountered that require rapid adjustments based on actual well data. In the case reported here, a fluid influx occurred at a depth where planning indicated a significantly lower pore-pressure. This influx directly led to losing a bottomhole assembly (BHA), sidetracking, and a re-evaluation of the well data and pore-pressure regimes possible at that depth. This paper also highlights the need for flexible well designs able to respond to unanticipated drilling hazards and wellbore problems. In the case history reported here, the 11¾-in. casing was set 511 m higher than originally planned because of pore-pressure increases. This decision had a significant effect later in the well construction program, requiring the use of expandable casing not originally in the well program. This paper illustrates on-the-fly modification of drilling designs to rapidly deploy unplanned equipment, the use of unconventional borehole sizes, and the use of newer technology such as rotary-steerable assemblies for side-track kickoff. The paper will also discuss the optimized use of hole openers and expandable casing and the potential effects of expandable casing on subsequent hole-opener use. These dynamic modifications and immediate implementation of lessons learned allowed successful drilling to a record depth for eastern Canada. Introduction The Weymouth A-45 well is located approximately 160 miles south by southeast from Halifax, Nova Scotia, Canada, in the deepwater area of the Scotian Shelf. Prewell seismic analysis identified the presence of a subsalt anomaly, the 1507-m-thick Argo salt sequence. This sequence presented a potential major drilling challenge and also a significant problem in prewell pore-pressure and fracture gradient planning. The well incorporated a complex well design using concentric hole openers and an unconventional casing designed to successfully complete the well. The well design was planned in response to the challenges posed by the 1685-m deepwater environment and the thick salt deposit, as well as their combined effect on overburden and fracture pressure. The impact of these factors combined with limited drilling-pressure margins (based on expected pore-pressure increases) required a more complex borehole and casing design. Despite the potential hazards and complex well design, the drilling program allowed for flexibility in the decision processes and in well design changes not only to deal with problems encountered, but also, to extend drilling successes. Flexibility was particularly important when drilling through the salt body with a point-the-bit rotary-steerable system. Although the rotary-steerable system was not planned for use below the salt, the success of the system in the shallower parts of the well led to its subsequent use below the salt and highlighted the flexibility of rotary-steerable technology. Planning and Design Three seismic lines and six offset wells were provided to perform an initial analysis of the Weymouth Prospect in August 2002. These data were processed using the Sperry Drilling Services formation-pressure estimation model to generate overburden, pore-pressure, and fracture-pressure predictions. The six offset wells (H-100 Shubenacadie, H-98 Evangeline, H-38 Glenelg, J-48 Glenelg, N-49 Glenelg, and M-41 Tantallon) showed two different pore-pressure regimes unrelated to water depth. H-100 and M-41 were both deepwater wells.

TX 75083-3836, U.S.A., fax 1.972.952.9435. AbstractModern day oil exploration pushes operators into harsher and more difficult drilling environments in the search for hydrocarbon reserves. Eastern Canada is one of those environments where deepwater and the need to penetrate through thick salt sheets greatly increase the difficulty faced by drillers. This paper describes a case history of deepwater, sub-salt drilling and examines the requirements for success. This paper also details the challenges, using seismic data, of pre-well planning for dealing with high pore pressures and variable fracture gradients. Experience shows that pre-well engineering differs considerably from conditions actually encountered, conditions that require rapid adjustments based on actual well data. In the case reported here, a fluid influx occurred at a depth where planning had indicated a significantly lower pore pressure. This influx directly led to losing a BHA, sidetracking, and a re-evaluation of the well data and pore pressure regimes possible at that depth. This paper also highlights the need for flexible well designs able to respond to unanticipated drilling hazards and wellbore problems. In the case history reported here, the 11¾in. casing was set 511m higher than originally planned due to pore pressure increases. This decision had a significant effect later in the well construction program, requiring the use of expandable casing, not originally in the well program.This paper illustrates on-the-fly modification of drilling designs to rapidly deploy unplanned equipment, the use of unconventional borehole sizes, and the use of newer technology such as rotary steerable assemblies for side-track kick-off. The paper will also discuss the optimised use of hole openers and expandable casing and the potential effects of expandable casing on subsequent hole opener use. These dynamic modifications and immediate implementation of lessons learned allowed successful drilling to a record depth for Eastern Canada.

As the oil and gas industry expands into evermore challenging environments with more complicated processes and designs, minimizing well cost and ensuring the best use of resources has resulted in an increase in the engineering planning and field-execution requirements. Drilling optimization has changed from simply improving the rate of penetration (ROP) to analyzing all aspects of the drilling process by establishing an integrated workflow that enables different engineering departments to plan and execute the well. In this case history, the operator’s challenges included vibration in horizontal sections, hydraulics, and wellbore integrity concerns resulting from narrow mud weights available to minimize reservoir damage and to control pore pressure. Drilling optimization also includes measuring and improving operational efficiency and consistency. Many activities are required in a drilling operation, and the inefficiency of these activities increases well costs. This inefficiency can be described as invisible lost time (ILT), which has been shown to contribute to up to 15% of total well cost. It exposes open holes to longer elapsed times which causes hole problems, especially in reactive formations. This case study takes a holistic look at the drilling performance and efficiency improvements that can be made by planning, modeling, and introducing a collaborative drilling engineering team with a real-time field execution team to analyze drilling challenges and address those challenges for future developments.

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