This paper will address the improvements in well placement and drilling efficiency seen during a start-up project where wired drillpipe was introduced as an enabling technology during the project. By using multiple strands of new technology, in a controlled, managed fashion, Eon Ruhrgas delivered rate of penetration (ROP) increases of 200% and, at the same time, increased net-to-gross by nearly 100%. The delivery of these new technologies will be reviewed along with the culture of learning and constant improvement fostered by the Eon Ruhrgas. The collaborative atmosphere led to an open environment where all the potential issues, risks, and hazards had been discussed and contingencies made to ensure that delivery would not be compromised. A case study on the drilling of the first three wells on the Babbage field, where significant new technology advances were introduced on the second and third development wells, will outline, in detail, the improvements in performance observed. In summary, the introduction of wired telemetry drillpipe and the use of a downhole-powered rotary steerable system (RSS) ensured optimum trajectory control, ensuring "sweet" spots were identified and delivered, while maintaining an optimum ROP. By using the increased data-carrying capability of the wired drillpipe, it was possible to provide high quality image data, allowing a better understanding of the downhole environment and ensuring that the stratigraphic control was optimized. The optimization was enhanced by 24-hour operations geological support, continuous dip-picking, and geosteering modelling support onshore but live-linked to the wellsite. By using this knowledge in conjunction with a mud motor power section attached to an RSS, it was possible to deliver a step change in drilling performance through the reservoir.

The Rita gas field was the first dual lateral well aimed at carboniferous reservoirs drilled in the UK Southern North Sea. This method enabled both the East and West fault segments of the field to be produced from the same upper well bore, thus reducing drilling costs and improving field economics. An invert emulsion drilling fluid was chosen for this field application due to the risk of shale instability over the long horizontal sections of each wellbore. The West segment was drilled and suspended with a whipstock placed above the sand screen completion. The positioning of this whipstock would not allow for re-entry, making remediation of the West lateral impractical. A remediation treatment for this leg was required as the planned suspension fluid was an invert emulsion system that would be in contact with the completion screens and reservoir for more than a month whilst the East leg was drilled and completed. The chosen suspension fluid in the East leg removed the requirement for remediation with enhanced well productivity. This paper describes the design and testing of the reservoir drilling and suspension/completion fluids that were used on this multi-lateral project to minimise drilling time and maximise productivity. Introduction The well described in this paper was a complicated design and consisted of a dual lateral to produce gas from two unconnected reservoirs. The Rita well (44/22–12) was spudded in early July 2008. The first (West) leg of the well had a TD of over 17,000 ft with a 6" horizontal section of over 2,700 ft. After the lower completion was run in the first leg a whipstock was set to enable drilling of the second (East) leg. The East leg had a TD of 15,600 ft and a 6" horizontal section of over 2000 ft. The plan was to suspend the first leg for a period of time that might exceed 2 months to allow for the drilling of the second leg and the running and installing the novel completion. This industry has experienced lower than expected production rates from wells which have been suspended for long periods with oil-based, solids-laden fluids before a clean up has been initiated. This raised the question of what type of fluid to leave below the whipstock, as re-entry to this leg for clean-up or well remediation was not economically feasible if production was lower than expected. Due to the diametrically opposed shape of the well, with long horizontal sections the drilling team was strongly in favour of using an oil-based reservoir drill in fluid (OBRDIF). This fluid would give a stable wellbore and provide a low friction co-efficient for drilling and running the completion assemblies. Using OBRDIF would reduce the risk of hole instability and minimise non-productive time. However if OBRDIF was used in the drilling phase, it would mean that a solids-laden invert emulsion would be left in the hole when the first leg was suspended with the sand screens below the whipstock. This presented several risks. The fluid would require fine screening to prevent blocking of the completion equipment with drill solids. Also, there was a risk that the solid particles in the suspension fluid would agglomerate as the fluid remained static for an extended period. If agglomeration did occur, these solids would probably not pass through the mesh of the completion screens and could potentially reduce their conductance. The size and concentration of the solids in the suspension fluid were recognised as areas of concern that should be addressed to ensure maximum productivity of this well.

This paper describes the application of dual lateral, level 4 junction - technology to successfully develop a marginal field in the Carboniferous area of the Southern North Sea (SNS) on the United Kingdom Continental Shelf (UKCS). This is the first known use of this technology in this area of the SNS where significant drilling risks have previously led to relatively simple well designs to mitigate the risk of failure. The Rita Field straddles blocks 44/21b and 44/22c and lies 110km due east of the United Kingdom coastline and 35km west of the UK-Dutch offshore boundary. The field is composed of adjacent, tilted, Carboniferous fault block structures containing Westphalian reservoir sandstones sealed by Silverpit shale and halites at the regional Base Permian Unconformity. The NW-trending fault blocks are separated by a NE - striking normal fault. The eastern fault block was successfully tested by 44/22c-9 in 1996 whilst the western fault block was targeted by 44/21b-11 in 1998 but failed to find gas. Well results, however, indicated the likely presence of up-dip reservoir quality Westphalian sandstones, although the development risk was higher. The selected development scenario was a dual lateral well from a single subsea wellhead, accessing both Rita main fault blocks. Although this concept yielded the most attractive economic development scenario, it nevertheless set the multidiscipline team with many significant well design challenges, including the following: Directional planning to target a gap within the high pressure Plattendolomite rafting in the Zechstein evaporite sequence whilst accommodating the reservoir strict targeting objectives of each leg. Utilising the five separate liner hanger systems that would be required in this single dual lateral well. Conducting extensive directional drilling within the Silverpit evaporite sequence with low weight OBM drilling fluid. Horizontal drilling up to 3000 ft of Carboniferous reservoir in 6 in hole whilst managing directional, hole stability and formation damage objectives. Placing the junction within a very confining area of the Zechstein basal sequence and achieving full cement isolation. Deploying the long 4 in. sandscreen lower completions. Mitigating the risk of formation damage in the first isolated reservoir leg whilst the second leg was being drilled and completed. Developing and deploying the first HPHT gauge through a 13-5/8 in vertical subsea tree in the UKCS. Further, as the western fault block was seen as an exploration target, the well design had to accommodate the geological uncertainly due to the poor quality of the seismic data, of the NE - striking normal fault and the planned reservoir entry point being out of position. Successfully dealing with these engineering challenges resulted in several industry firsts which will be fully described within the text of the paper. On completion, production rates were better than expected with very good selective delivery from both legs of the well prior to co-mingling.