Mud Pulse Telemetry (MPT) is the most common down hole-to-surface communication technology utilized by MWD/LWD systems. Compared to alternative technologies, MPT systems are characterized by a proven record of high reliability in a wide range of operating environments. Reliable data delivery is feasible in a variety of scenarios ranging from shallow vertical to complex, deep water wells in all types of drilling fluid media.Recent years have seen the introduction of many new LWD technologies which are providing unparalleled amounts of wireline quality evaluation data in realtime. Access to high quality, complete, evaluation data sets whilst drilling is enabling geologists and engineers to make decisions with higher confidence based on more and higher quality datasets, consequently enabling wells to become more complex and fulfill multiple objectives. The ever increasing volume of information generated by these new technologies has begun to exceed the bandwidth transmission capacity that traditional MPT technology can deliver. To fully capitalize on the LWD technological advances being implemented, an increase in data transmission speeds is required. This paper discusses a new telemetry system that delivers data rates in excess of 6 bits per second (bps). The system has been deployed in a number of complex 3D extended reach offshore wells in Norway. During operations, the system reliably delivered high data rates of up to 20 bps, resulting in improved drilling efficiency, and reduced operational risk due to enhanced realtime decision quality based on the improved quality of FE and downhole diagnostics data.

The demand for increased oil and gas recovery requires the drilling of complex extended reach wells with optimized reservoir exposure for production and minimized overall production costs. In order to achieve these objectives, the use of high-end drilling and logging technology to optimize well placement is of the essence. However, the optimal utilization of this technology is often limited by the real-time transmission bandwidth of essential data from and to the downhole tools. The introduction of wired drillpipe technology has facilitated a step change in two-way data communication resulting in a high-speed data transmission giving much greater volume, resolution and quality of formation evaluation data and drilling dynamics data. Furthermore, the direct control of rotary steerable tools has now been enhanced to allow instantaneous programming changes and better utilization of dynamics data to enhance the decision making process required to address drilling dysfunction challenges, hole quality, gross ROP and BHA reliability. The high bandwidth technology was used while drilling two laterals on the Troll field's reservoir in the Norwegian North Sea in 2007. The memory quality data was transferred through wired drillpipe to the surface while geosteering through relatively unconsolidated sandstones with localized zones of hard calcite cementation. The bottom hole assembly employed, comprised multiple formation evaluation and dynamics sensors to fully understand the downhole drilling conditions. The data was transferred to the expert advisory centre onshore for advanced processing and interpretation to enable the critical decision making process. The adoption of a Total Systems Approach to select the ideal combination of application-specific drill bit, drilling system, and appropriate procedures and practices was presented and described by Stavland, et al (2006). Realizing the full benefit of the approach has been hampered by bandwidth restriction and time lag associated with conventional mud pulse telemetry. This paper will discuss how wired drillpipe technology has been utilized to enhance the Total System Approach concept during the first tests and how it will affect operations going forward. Introduction Telemetry Drill String Technology Overview First used in 2003 and commercially launched in 2006, the broadband network used in this application offers an ultra high-speed alternative to current mud pulse and electro-magnetic telemetry methods. The network utilizes individually modified drilling tubulars to provide bi-directional, real-time, drill string telemetry at speeds upwards of 57,000 bits per second. This greatly enhanced band-width in comparison to existing technology makes it possible to obtain large volumes of data from downhole tools (and other measurement nodes along the drill string) instantaneously, greatly expanding the quantity and quality of information available while drilling. The network utilizes a high-strength coaxial cable and low-loss inductive coils embedded within double-shouldered connections in each tubular joint to convey information. Currently available telemetry tubulars include various sizes of range 2 and range 3 drillpipe, heavy-weight drillpipe, drill collars, and a wide array of bottom hole assembly components (API Spec. 5D).

One recent management trend is the establishment of onshore operations centers by oilfield operators that are currently developing offshore assets. Unfortunately, the formation of such a center has typically been a niche activity within many companies and, as a result, some may fail to consider the lessons learned from earlier operation center failures. It is also vital that those attempting to develop such a center make sure the center's purpose functions within the industry's overall framework. While these centers have often delivered, with varying degrees of success, on their anticipated benefits such as faster decision-cycle time, better, more informed decisions and reduced POB, robust business and organizational models are necessary to ensure these efforts' long-term viability. As part of a long-established business partnership, Norsk Hydro and Baker Hughes INTEQ have recently implemented changes to the industry's longest continuously running remote drilling operations center. Supporting some of the Norwegian Continental Shelf's most technologically challenging drilling operations, the center is contributing to improved financial performance, reduced POB, enhanced service quality and supporting work process changes within both organisations. The revised model has been implemented as the 'normal' service delivery channel for five drilling operations supported by the BEACON center on a 24/7 basis and routinely operate advanced technologies such as formation pressure testing while drilling, deep reading resisitivity and azimuthal imaging services. This paper will outline the technical and commercial models that have been developed, provide insight to the challenges encountered and achieved successes. Introduction Transferring real-time rig-site data to office-based experts is not a new concept within the E+P industry. In 1985, Mobil established a satellite communications network to feed real-time drilling and MWD data to the Mobil Drilling Data Center1 and, a short while later, Amoco opened a similar drilling center2. These early command centers delivered rig-site data to a central group of experts (additional to the core operations/asset teams) tasked with supporting critical operations. Little attention was placed on process management or human processes and, coupled with an inability to demonstrate the value of maintaining dedicated experts and infrastructure in a changing business environment the Amoco center eventually disbanded in 19893. The late 1990's Norwegian oil industry was characterized byRapid technology development of advanced down-hole drilling technologies such as Rotary Closed Loop Drilling SystemsIncrease in production by innovative application of new drilling, completion and production technologies. The exploitation of the thin oil leg of the Troll field by Norsk Hydro exemplifies thisInvestment by oil companies in fiber optic telecommunications infrastructureRapid advances in computing technology and large scale uptake of web based software applications Norsk Hydro and Baker Hughes began work in 1997 on defining work practices and organizational models that would address the challenges listed above by relocating some personnel from offshore to an onshore operations service center manned 24/7. The concept was named BEACON (Baker Expert Advisory Center/Operations Network) and, after pilot testing with Hydro and BP in 2000/1, commercial operations commenced at the end of 2001[3].

Innovative solutions for development of new technology and business models are needed to meet the economic challenges of declining production from the mature North Sea oil province. Bed space limitations imposed by platform redesign and modification at Oseberg East as part of the operator's improved oil recovery (IOR) strategy dictate a manning solution which significantly reduces persons on board (POB) if tail production is to be economically viable. Previous POB reduction models have typically focused on reducing the drilling contractor and production-phase manning levels on the platform. This study extends operational efficiency by employing an Integrated Services Model that encompasses multiple service providers in addition to the drilling contractor. Considering the entire crew in the context of "manning by tasks instead of manning by services" results in a substantial reduction of headcount whilst maintaining quality of execution. The solution developed covers directional drilling, downhole fluids, cementing, logging while drilling and completion operations, as well as drilling contractor and operator tasks. Emphasis has been put on transfering all work tasks that do not require physical presence at the rigsite to the onshore organization, for which use of modern communication technology is key. The business model promotes operational efficiency between service companies and drilling contractor through the development of non-traditional working processes that transgress individual company boundaries. Employees from third parties will be cross-trained such that their presence onboard is utilized in mission critical operations even where responsibility for the operation does not rest with their home organization. Maximising the effectiveness of onboard headcount is considered a first step in developing long-term, cost-effective solutions that will help ensure the longevity of mature assets. This paper describes solutions developed during the detailed planning phase of the Oseberg East tail production project, challenges to implementation, and expected benefits of the new service delivery model. Introduction The original drilling phase of the Oseberg East (Figure 1) development was performed with a drilling support vessel that provided additional accommodation, drilling/completion fluids storage, mud pumps, power generation and cementing. Norsk Hydro's IOR strategy highlighted the opportunity to improve the Oseberg East recovery rate from 28% to 35% by drilling seven new wells from the platform. Figure 1 - Oseberg East platform A pre-condition for the Oseberg late-life project is the requirement to maintain current production whilst simultaneously constructing new wells without using a dedicated support vessel. This is a challenge given the size of the platform as the original design made no provision for maintain bulk volumes of drilling fluids or cement onboard, power supply, or lodging of personnel.

No abstract