This paper describes the tests and concept behind a new hydraulic hammer. The objectives of these tests were to evaluate penetration rate performance of this hammer when used in conventional drilling conditions. To date the usage of hydraulic hammers has been hindered due to limited compatibility with drilling fluids solids content. Therefore, this hammer was conceived to operate with all kinds of drilling fluid, including Lost Circulation Materials. Additionally, this hammer would be used with conventional tri-cone bits. This is significant because inter-bedded formations can be drilled without repeated changes to the bottom-hole assembly and drilling can continue in the event of hammer failure. The technology consists of a rotating valve system that alternately directs fluid to a piston that drives down a steel mass to strike the rear of the bit and then to a port that bypasses the piston. This action allows the mass to return to its original position ready for the next downward stroke. The valve operates at a known frequency that is directly proportional to flow rate. Due to these unique characteristics, the Hard Rock Drilling JIP decided to test the hammer, the results of which are discussed here. Introduction Compared to conventional techniques, percussion tools are capable of increasing penetration rates in hard rock. For example, while drilling granite, penetration rates of 30m/h have been achieved1. However, the usage of hydraulic hammers has been limited by solids content in drilling fluids and the requirement for specialized drilling bits2. Targeting this particular application, the development of a new hydraulic hammer was initiated by Andergauge in 1996. Key operational objectives were 1) Penetration rate increase (Figs 1 and 2) 2) compatibility with all kinds of drilling fluid, including lost circulation material 2) compatibility with conventional tri-cone bits. The technology consists of a rotating valve that alternately directs drilling fluid to a piston that drives down a steel mass to strike the rear of the bit (Figure 3). Drilling fluid then flows through a port by-passing the piston enabling the mass to return to its original position ready for the next downward stroke. The valve operates at a known frequency that is directly proportional to flow rate (Figure 4). The rotating valve continuously generates pressure pulses, driving the steel mass eight times a second, which delivers 80,000 - 100,000 lb impact force at the bit. The impact improves penetration rates, but is of a sufficiently low magnitude to avoid damaging bit journal bearings. The rotating valve concept is proven in another established drilling tool. It has been used to withstand harsh down-hole drilling conditions in over than 250 runs, some of which have exceeded 200 circulating hours. Three tests had already been conducted using the same type of bit, BHA configuration to drill identical formations with and without the hammer. The first occurred in Stavanger, Norway. In this test, the rate of penetration using the hydraulic hammer was recorded as 50% to 100% higher than without. The second test was performed in Indonesia and the rate of penetration with the hydraulic hammer was 84% higher than without. However, both tests presented durability problems. A third test, considered an endurance trial, was conducted in Oklahoma, USA. The longevity of the run determined the test to be a success, independent of the 22% rate of penetration increase achieved. This run was considered a breakthrough as the hammer proved that it was capable of:tri-cone bit compatibility;drilling fluid compatibility;life expectancy in excess of 60 hours; andincreasing rate of penetration. Consequently, the Hard Rock Drilling JIP decided to evaluate the performance and life expectancy of the hammer through a series of tests in Stavanger, Norway.

Increasingly, operators seek to underream. Whether driven by cementing tolerances, ECD improvements, pore pressure fracture gradients, production increases, swelling shales/salts or setting sand screens, underreaming is sought after at all stages of field development. To date, the industry has a common perception that concentricity can only be delivered through concentric cutting mechanisms. This paper proves otherwise. The performance, risks and suitability of an eccentric underreaming device are compared with concentric underreamers. Usage in over 100 well sections is tabulated and reviewed to verify the device drills concentric hole in differing formations and applications. Pilot bit and underreamer cutter characteristics are matched for directional control, durability and hole quality. Specific attention is paid to N Sea & GOM run history covering usage with push and point-the-bit rotary steerables. In exploratory, deepwater or complex well paths, the device is placed above a 3-D rotary steerable and full logging suite. Here the problem of leaving pilot gauge rathole is also addressed. In enhanced RPM, motor directional applications it is placed as nearbit. Computational fluid dynamics, nozzle and PDC cutter layouts are also discussed with regard to optimizing cuttings evacuation, hole cleaning, BHA stability and ROP. In conclusion, 20 different well construction activities are presented and used as a benchmark for the evaluation of the risks and suitability of the device as compared with concentric underreamers. Some drilling engineers may be surprised by part of this papers' title - an eccentric device drills concentric hole and offers a viable alternative to underreamers - as there is a common perception that concentric hole can only be attained through concentric cutting mechanisms. Before proving this perception inaccurate, it is worth defining certain terms. For the purposes of this paper, the following terms mean ‘the opening of a well-bore after passing through a restriction’.UnderreamingHole enlargementReaming while drillingSimultaneous underreamingDrilling with a bicentre/eccentric bitHole-opening However, ‘Hole-openers’ as downhole tools are beyond the scope of this study due to their nature. They have fixed pre-determined diameters and are best suited for top-hole applications as they can not pass through restrictions or routinely underream several thousand feet or more' (Ref 1 & 18). The perception surrounding concentricity arises from differences between Eccentric Underreamers (E-UR) and Concentric Underreamers (C-UR). In the case of E-UR, which are integral underreamers or evolutions from bicentre bits, the perception is based on the following:Eccentric bits have an unbalanced and eccentric cutting action.An unbalanced cutting action is unlikely to result in good drilling dynamics.Therefore, an eccentric cutting action is unlikely to provide concentric hole.

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Applications such as close tolerance casing design and expandable liners, often necessary for deepwater and subsalt well construction, require underreaming to ensure adequate reservoir diameters. However, underreaming generates uncertainty sometimes, particularly in hard formations. Instead of direct real-time verification, reliance is placed on indirect indicators such as increased standpipe pressure or drilling torque. The uncertainty as to whether the desired wellbore-diameter is actually delivered exists until a calliper is run. Subsequently, a correction run may still be needed, hence additional cost. This paper explains a design process to solve these problems. An explanation of a novel technology illustrates how it verifies and detects variations in underreaming diameter in real-time. A telemetry system alerts the user if there is a significant difference between planned and actual diameters and prompts a check of operational parameters such as WOB, drilling fluid pump rates or RPM, if needed, repeat underreaming in the uncertain interval. A comparative evaluation was made of the drilling dynamics of underreamers and the root cause analysis of NPT. For example, bit only RoPs are higher than underreaming RoPs and in a combination BHA the bit tends to out-drill the underreamer. Not only does the underreaming have limited cutter contact with the wellbore and limited hydraulics, BHA modelling shows these limitations are worsened by wall-side forces and bending moments which are concentrated at the underreamer. The design process sought to improve traditional technology by considering RoP, improved underreaming BHA stability and generate a more balanced cutting action. CFD (Computational fluid dynamics) show how a novel configuration of nozzle distances and orientations improves cuttings evacuation and reduces particle residence times. In conclusion, a drilling engineering risk table presents 20 underreaming applications and is used as a benchmark for a comparative evaluation of underreaming risk types. Introduction Oil and gas companies are exploring and developing reserves in more challenging basins such as those in water-depths exceeding 6,000 ft (1830m) or below massive salt sections. These wells have highly complex directional trajectories with casing designs including 6 or more well sections. Known as 'designer' or 'close tolerance casing' wells, such wells have narrow casing diameters with tight tolerances and have created a need to enlarge the wellbore to avoid very small diameter reservoir sections and lower production rates (Figure 1 PPFG). In other applications such as cemented solid expandable liners, underreamers are required to provide the tolerance for tubular expansion to occur or for increased cement sheath. The tolerances between the enlarged well-bore and the expanded tubular are very close. Therefore, the bottom-hole assemblies that are needed to drill or complete these wells routinely include devices to underream the well-bore. In this way, underreamed hole size has become an integral part of well construction and there is now an increased dependence on underreaming to meet planned wellbore diameters across the industry (Ref 2).

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