TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractWell testing is important for reservoir formation and fluid characterisation. Well testing is, however, omitted in many instances due to the high cost, risks and environmental restrictions associated with a well test. The Downhole Production Testing (DPT) method 1 will have a significant impact on safety, environment and cost aspects compared to conventional production testing or drill stem testing (DST).The Downhole Production Test method allows all the produced reservoir test fluid to be re-injected into another zone within the well bore while flow rate, pressure and temperature data are monitored and controlled from surface. In situ fluid samples are taken during the flow period. After penetration of a zone of interest, an injection zone is selected at a depth which allows a sufficient injection rate. The drilling fluid acts as the primary pressure barrier during the test. The production and injection zones are isolated from the drilling fluid by a packer arrangement.No fluid flows to surface during the test, so the entire surface processing equipment normally associated with well testing is no longer required. This significantly reduces the onshore and offshore logistics operation. Even more important is that hydrocarbons will not flow to surface under high pressure during the test. This significantly improves the risk and safety aspects of conducting a well test. High-risk operations in deep water related to discharge during emergency disconnect or hydrate formation during testing are also eliminated.A "zero emission" goal is achieved by no burning and no hydrocarbon flows to surface. This paper describes the method and the environmental implications of this new testing method. Included also is a detailed discussion of the safety and risk elements involved in different operating scenarios. Furthermore, this paper discusses some of the preliminary design parameters and possible implementation of the concept. It describes potential cost benefits for various applications and demonstrates that this new technology reduces cost and improves the environment, safety and risk while allowing test objectives to be met.

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).

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractSince the advent of steerable motors in the mid 80's, the drilling of complex horizontal 3D wells has become a standard in development drilling. To further extend the envelope and optimally position the wellbore to improve drilling efficiency and optimize production more sophisticated systems were required. Now two decades on, the industry has developed intelligent Rotary Steerable Systems (RSS) and sophisticated Logging While Drilling technologies that have both lowered well cost through NPT reduction and given the operator the opportunity to position the well path optimally in the reservoir, based on real time logging data. This environment has placed an increased reliance on Logging-While-Drilling (LWD) measurements. In this paper we will review wells drilled and logged on a North Sea field and how the application of a number of advanced LWD technologies have maximized answers through acquiring full formation evaluation in a single pass. We will discuss the importance of having an integrated LWD system engineered for diverse drilling applications and also designed as a compact, modular system with sensors close to bit with increased flexibility and a wide range of measurements. The realtime aspects of LWD are important in delivering valuable answers. Examples will be illustrated, which demonstrate the value of these technologies in accurate estimating reserves, well positioning, non-productive time (NPT) reduction and drilling hazard mitigation. With such a complex, integrated system, a thorough approach to pre-job planning, realtime follow-up and post-well analysis is a key factor in achieving full formation evaluation data acquisition in parallel with improved drilling performance.

Field development in mature areas of the Norwegian Continental Shelf (NCS) is changing from giant fields to minor localized hydrocarbon traps often made up of isolated and rotated fault blocks. The existing infrastructure needs to be utilized to make the additional reserves economic. Being a marginal part of a mature area, the existing subsurface and reservoir information is very limited. The cost involved in field developments on the NCS is substantial and additional appraisal wells are often too costly, delaying the field development and increasing total cost. The solution to gain the information needed and to place the well optimally within the reservoir, is to have enough flexibility in the well design to evaluate and change the planned well trajectory based on the information acquired during drilling. The well trajectories in these cases are horizontal producers with normally one main bore in each fault block. This case describes the application of precise 3D Rotary Steerable System and LWD measurements which enable accurate identification of the Oil-Water-Contact, Gas-Oil-Contact and top reservoir, for a horizontal well through multiple branches drilled from one main bore in a single continuous operation. The valuable information, obtained through controlled sidestep exploration drilling, provides additional knowledge to optimize the producing main bore. Horizontal wellbore placement is supported by real-time reservoir characterization through real-time formation pressure measurement to validate any fluid movements and fluid compartmentalization of the reservoir. Being able to perform this in a single run accentuates the unique effectiveness and flexibility available in the well construction process. In this marginal field development in the North Sea realtime data acquisition and accurate well placement play a significant part in the success of the field development and illustrates to what extent precise 3D RSS and answers from LWD data help in effectively optimizing well placement and reservoir characterization. Introduction The Tampen area on the Norwegian Continental Shelf (NCS) has been under production since mid 1970's and the early giant discoveries are ageing. During the early development phase of the Tampen area of the NCS an excellent infra structure with platforms and pipelines were engineered and constructed. The marginal field developments currently ongoing in the same area take advantage of that infrastructure, and production is tied into the existing production facilities and pipe lines.

Development of formation evaluation technologies for azimuthal, deep-reading measurements and accurate and flexible 3D rotary steerable drilling systems have made it possible to provide truly proactive well placement. Real time use of new and advanced LWD data in horizontal drilling gives the opportunity to extend the envelope for well planning and reservoir information gathered in a single run. Optimum interpretation from real time data acquisition facilitates a reformation of the way horizontal wells are planned and drilled. This paper shows a well where the information was extracted and included in the decision making process to an extent that sets a new industry standard. Applying an accurate 3D rotary steerable system with openhole sidetrack capabilities increase well design flexibility and the ability to act on the real-time LWD data. The bottom hole assembly used consisted not only the standard LWD services such as gamma ray, propagation resistivity, density, neutron porosity and LWD gamma ray and density imaging services, but also formation pressure testing while drilling and the newly introduced azimuthal propagation resistivity. The azimuthal propagation resistivity provides unique information of the approaching bed and fluid contacts. Verification or change of the geological model during drilling through comprehensive use of forward resistivity modeling and real-time geological interpretation based on both the newly introduced azimuthal propagation resistivity service and resistivity from multiple depths of detection as well as wellbore images from both density and gamma ray, give a solid and enhanced base for real time well placement in horizontal drilling. The horizontal interpretation of resistivity data together with structural interpretation of image data gives an unmatched understanding of the geology and aids in placing the well better. Horizontal real time wellbore placement is then accompanied by real time reservoir characterization through real time formation pressure measurement to validate any fluid movements and fluid compartmentalization of the reservoir. This paper is based on wells drilled in a chalk field in the North Sea where real time data acquisition plays a significant part and illustrates to what level LWD data can facilitate proactive well placement and comprehensive reservoir characterization. Introduction The Ekofisk Field is located in the southernmost part of the Norwegian North Sea (Fig. 1) and was discovered in 1969. It is one of the North Sea Giants with a STOIIP of 7 mmbo. The field was put on production in 1971, and has been through several phases of development and re-development. The most important event in the Ekofisk field history was the implementation of the Water Injection Project in 1987, which brought the production from 70,000 bopd to above 300,000 in 2005. Current production at Ekofisk is about 270,000 bopd.