The application of hybrid bits saves the operator drilling time by out-drilling conventional roller-cone and fixed-cutter bits in difficult, dense, tough and interbedded intervals. These intervals comprise interbedded sandstone, limestone, and siltstone down to depth of 12,500 to 13,500 ft. Operators who drilled these overbalanced wells typically used conventional roller-cone and fixed-cutter bits, depending on the area of the play. The roller-cone bits consistently drilled the entire interval, yet achieved slow penetration rates due to the lack of available weight. Fixed-cutter bits have been tested to achieve higher penetration rates. They drill faster than roller-cone bits with the available weight on bit but with higher drilling torque, close to the rig limitation. Fixed-cutter bits also experience dynamic dysfunctions that prematurely damage the bits, making it difficult to complete the entire interval. Extensive research, testing, and development have produced a hybrid bit that combines roller-cone and fixed-cutter elements to address these major challenges. The fixed-cutter elements make the bit more aggressive and provide higher penetration rates at low weight on bit. The roller-cone cutting elements drill through the harder part of the interbedded formation with much lower torque oscillations, making it easier to achieve the directional requirements, and reduce dynamic dysfunctions, improving the reliability of the bottomhole assembly and a better dull condition of the drill bit. This paper will present analysis of drilling data from the field to provide a detailed description of the operational challenges in this application by comparing the performance of roller-cone, fixed-cutter, and hybrid bits. After describing the planning and operational execution of drilling an 8.5-in. hole section with a hybrid bit in this challenging application, the paper concludes with a discussion of the technical and economical benefits and potential of this new technology.

Current and future offshore exploration activity is penetrating to deeper reservoirs, driving the need for increased drillstem testing (DST) for high pressure and high temperature wells. Typically, liners are tied back to the surface to achieve reliable wellbore integrity and flow. In the past, these tiebacks require expensive cementing operations which also limit future wellbore re-entry options.An innovative non-cemented floating liner tieback with reliable floating seals can improve the entire DST process by eliminating the cost and risk of cementing operations. In addition, the operator is able to retrieve the casing tieback and have the option to use the same well for appraisal or development phases.The paper discusses the floating tieback system and details a case history on a high pressure well in which the operator completed the DST operation safely and met all well objectives. Discussion of system reliability includes casing design and modeling by both operator and suppliers, plan changes based upon pressure data obtained during the drilling phase, detailed operational procedure in a deepwater environment, successful tieback retrieval and future operations.

Saudi Aramco's "M" Field is located offshore and will be developed using over 300 wells with a combination of land and offshore drilling facilities. Well number M-A is a land-based, power water injector well, drilled to an offshore bottomhole location. The resulting well design dictated directionally drilling an extended-reach well with an 8–1/2-in. horizontal-hole section over 13,900 ft (4237 m) in length. It was apparent from the outset that directionally drilling the 8–1/2-in. section was going to be extremely challenging. Once drilled, running and cementing the 7-in. liner would present a host of additional difficulties. To ensure a successful outcome, Saudi Aramco assembled a dedicated team of Operator and Service personnel to review all aspects of this openhole section and resulting liner running operations. The latest in directional drilling technology was used to ensure the exacting directional control needed to deliver the wellbore. In addition, running the over 14,400-ft- (4389-m)-long liner required the use of new and innovative liner hanger technology to overcome any challenges encountered during liner deployment. This paper will outline the planning, methods, and equipment applied to deliver the resulting 8–1/2-in. hole section, and successfully deploy Saudi Arabia's longest-ever cemented 7-in. liner. Introduction Field Description "M" field is an offshore field located in shallow water depths of 3–16 ft (1 to 5 m). The field has been produced since its discovery, and the current plan is to increase production dramatically by drilling more than 300 onshore and offshore wells. However, the location of the field in shallow water makes developing the wells even more challenging. Saudi Aramco's offshore drilling fleet consists of jack-up rigs that cannot operate in shallow water. The preliminary planning showed that 37 platforms are needed to be installed to meet the production target, and major dragging works have to be done for channels to facilitate the movement of marine vessels and rigs.