Most production wells currently drilled in the North Sea are in complex geological settings. In order to place the wells safely and effectively, drilling a successful production well requires an advanced technology and integrated proactive reservoir navigation approach, in addition to multiple data driven answer products from downhole tools. Extra deep azimuthal resistivity logging while drilling (LWD) tools can detect boundaries up to 30 m away from the wellbore given optimal resistivity conditions. Combined with multicomponent inversion modelling (MCWD), the data acquired are used to map multiple boundaries, individual sand bodies, reservoir thicknesses, and lateral reservoir changes. Borehole images aid in geosteering and are used to steer up or down based on structural boundaries identified on the image. Using wired pipe technology that provides telemetry rates good enough for memory-resolution data, the full resolution electrical image is available while drilling. Despite complex reservoir geometry in both external boundaries and internal sedimentary structure, it was possible to succesfully geosteer by using an integrated geosteering approach. Through MCWD inversion, it was possible to track a thin, highly resistive layer at the roof for much of the reservoir, which allowed for proactive geosteering, optimizing wellbore placement and mapping of reservoir volumes.
This paper will discuss the implementation of the Wired Drill Pipe telemetry on two wells of the Babbage development project in the Central North Sea and will present the quantified efficiency gains achieved across various drilling operations. Wired Drill Pipe (WDP) telemetry enables bi-directional, high speed data transmission to and from downhole tools at speeds up to 57,600 bps (Olberg et al. 2008). This enables real-time "recorded" quality MWD and LWD data to be transmitted instantaneously to surface, as well as near-instantaneous commands ("downlinks") to be sent to MWD, LWD and RSS tools while drilling. The contribution of WDP telemetry to well placement and Geosteering on the Babbage development project has been published previously (Hatch, et al. 2011). This paper however, will present the efficiency gains and corresponding time savings that WDP telemetry enabled through the instantaneous transmission of data up and down the drillstring. A detailed analysis of the two WDP wells drilled with WDP telemetry will show the quantified time savings when compared to three wells drilled with conventional mud pulse telemetry. The analysis will compare the time spent on several activities including the transmission of downhole data to surface and vice-versa, the frequency of unplanned bit or BHA trips and on-bottom drilling time. The analysis will account for the differences in BHA designs, well paths and controlled drilling practices. Compared to the Babbage wells, drilled with mud pulse telemetry, a reduction of multiple days per well can be inferred through the increased efficiency of these operations and activities.
This paper presents and discusses the results of a case study where Wired Drillpipe (WDP) technology was implemented on the Martin Linge offshore field development project in the Norwegian sector of the North Sea. Martin Linge’s resources consist of a shallow oil reservoir and several, deeper, structurally complex, high pressure gas and condensate reservoirs. The oil reservoirs are being developed with long horizontal wells and several deviated wells are drilled to unlock the gas and condensate reserves. The field was initially discovered in 1975 but proved too complex to develop at the time. Over the years several exploration and appraisal wells were drilled within a narrow pressure window, with multiple BHA runs per section. The complex drilling environment posed many challenges including severe losses, influxes, unstable formations and excessive downhole shock and vibrations resulting in poor MWD/LWD signal. WDP telemetry enables bi-directional, high speed data transmission to and from downhole tools at speeds up to 57,600 bps (Olberg et al. 2008). Conventional telemetry methods only provide very limited bandwidth (8-12 bps) for real-time data transmission and can suffer from signal reliability under adverse conditions, for example: no mud pulse data transmission to surface when pumps off or at flowrates below tool settings, decoding issues during high levels of downhole shock and vibrations and unfavorable mud conditions, such as gelled cold mud, gas, high viscosity pills, mud additives etc. WDP technology was implemented on the Martin Linge field development from the start of the development. The technology introduction cost off-set against the quantifiable benefits for the project was initially calculated close to break-even. Furthermore, the high upside potential associated with the use of this technology should allow improved well placement and have a positive effect on the quality of the drains drilled. This paper will summarize how the high speed telemetry provided by WDP enables wells to be drilled without the typical limitations imposed by conventional telemetry methods. The analysis will focus on two areas of efficiency and performance improvement. Firstly, the quantified data transmission time savings due to the real time high speed transfer of critical data between downhole and surface will be discussed in detail. Secondly, the network performance, drilling performance, application of new technology and technology investment cost will be discussed.
The Cambro-Ordovician formation in onshore Algeria consists of hard and abrasive sandstones that have proven challenging to drill. Up until now, no bit has completed the section in one run, and these formations have been considered beyond the limit of what is drillable by PDC cutters. Previous sections have used impregnated diamond and roller cone bits that achieved low penetration rates and required multiple bit runs. The impregnated runs require the additional cost of turbo drills or high-speed motors to deliver the rotation speeds necessary to achieve acceptable rates of penetration, while a bearing seal failure of a roller cone bit increases the risk of losing bit pieces in hole. The operator conducted an optimization process based on rock mechanics including an analysis of prior performances to conclude that the formation could be drilled more economically applying the recent advances in PDC bit technology. Collaboration between the bit manufacturer and the operator facilitated the implementation and development of the latest bit technology, including enhanced bit stability, improved cutter layout and more resistant cutters. After an initial, partially successful run, new bit improvements were implemented. The two subsequent runs completed their sections, enabling the operator to drill with one bit through what was previously a multiple-bit section. Rates of penetration were improved significantly over previous impregnated and roller cone runs. Requirements for down hole drive tools and bit trips were eliminated as was the risk of bit junk being left in hole. This paper outlines the process that led to improved understanding of the formation drill ability, the research and development behind this new bit technology, the continuous optimization of the specific bit, its field performance, and the resulting cost saving for the operator.
The recent industry downturn has forced operators and contractors to re-think and look at different ways to reduce costs while improving the complete well delivery process. Compounding challenges are longer reservoir sections with more complex well trajectories and tighter geological constraints. These complex drilling challenges have been successfully completed in the past, thru use of high-speed Wired Drill Pipe (WDP) telemetry (Schils et al. 2016; Teelken et al. 2016), where the WDP telemetry enabled bi-directional high-speed data transmission to and from downhole tools at speeds up to 57,600 bps (Olberg et al.2008). Whilst the use of WDP telemetry within the ‘drilling phase’ of the well delivery process has become more accepted and implemented globally, providing improved performance and wellbore placement, the use of WDP during the ‘completions phase’ has never been attempted. That is, till today. This paper focuses on the use of WDP during the ‘completion phase’, discussing the first ever application of the battery operated Remotely Operated Completion System (ROCS) on WDP, used offshore North Sea, for umbilical-less Tubing Hanger installation. The ROCS consists of redundant controls architecture and pumps to operate the electrical and hydraulic functions and read gauges. Thru use of the highspeed WDP telemetry, the ROCS is controlled in real-time from topside to operate the Tubing Hanger Running Tool (THRT), Tubing Hanger (TH), downhole functions and downhole gauges, eliminating the need for the traditional umbilical deployed within the Marine Riser. The WDP operated ROCS allows for a simplified system mobilization and operation, reducing total number of rig days and costs significantly. The main advantages that will be discussed and shown include: Eliminating the Electro-Hydraulic umbilical and handling equipment (costly associated equipment) Reduces personnel in red zone (umbilical-less: no clamping) Reduces/Eliminates rig interfaces, (such as Workover Control System (WOCS) container reducing the deck space demand, increasing rig flexibility) Ready to Run (ROCS including THOJ/THRT (Tubing Hanger Orientation Joint/Tubing Hanger Running Tool) tested and mobilized already connected to the TH Significantly reduces risk of Waiting on Weather Real-time readings local to tool, (accurate volumes and pressures, no umbilical influence) The system has been used for horizontal and vertical completions and can operate different running tools, offering field proven benefits for the industry.
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