Carbonate rocks are well known for their complex petrophysical behavior where, in contrast to siliciclastic rocks, different parameters, including porosity and permeability, usually are not directly related. This behavior is the result of thorough reorganization of porosity during diagenesis, and it turns prediction of reservoir quality of carbonate rocks into a challenge. The study presented here deals with the problem of utilizing NMR techniques in prediction of petrophysical properties in carbonates.We employ a visual porosity classification as a priori knowledge for better interpreting NMR data for prediction purposes. This allows for choice of suitable T 2 cutoff values to differentiate movable from bound fluids adapted for the specific carbonate rock, thus resulting in better interpretation of NMR data. The approach of using a genetic pore type classification for adapting the conventional method for T 2 cutoff determination, which originally was developed for siliciclastic rocks, is promising. Similarly, for permeability determination on the basis of NMR measurements, the classification of carbonate rocks based on porosity types also shows potential. The approach implemented here has the promise to provide a basis of standardized interpretation of NMR data from carbonate rocks.

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The typical rating for downhole measurement-while-drilling equipment for oil and gas drilling is between 150°C and 175°C. There are currently few available drilling systems rated for operation at temperatures above 200°C. This paper describes the development, testing and field deployment of a drilling system comprised of drill bits, positive displacement motors and drilling fluids capable of drilling at operating temperatures up to 300°C. It also describes the development and testing of a 300°C capable measurement-while-drilling platform. The development of 300°C technologies for geothermal drilling also extends tool capabilities, longevity and reliability at lower oilfield temperatures. New technologies developed in this project include 300°C drill bits, metal-to-metal motors, and drilling fluid, and an advanced hybrid electronics and downhole cooling system for a measurement-while-drilling platform. The overall approach was to remove elastomers from the drilling system and to provide a robust "drilling-ready" downhole cooling system for electronics. The project included laboratory testing, field testing and full field deployment of the drilling system. The US Department of Energy Geothermal Technologies Office partially funded the project. The use of a sub-optimal drilling system due to the limited availability of very high temperature technology can result in unnecessarily high overall wellbore construction costs. It can lead to short runs, downhole tool failures and poor drilling rates. The paper presents results from the testing and deployment of the 300°C drilling system. It describes successful laboratory testing of individual bottom-hole-assembly components, and full-scale integration tests on an in-house research rig. The paper also describes the successful deployment of the 300°C drilling system in the exploratory geothermal well IDDP-2 as part of the Iceland Deep Drilling Project. The well reached a measured depth of 4659m, by far the deepest in Iceland. The paper includes drilling performance data and the results of post-run analysis of bits and motors used in this well, which confirm the encouraging results obtained during laboratory tests. The paper also discusses testing and performance of the 300°C rated measurement-while-drilling components – hybrid electronics, power and telemetry - and the performance of the drilling tolerant cooling system. This is the industry's first 300°C capable drilling system, comprising metal-to-metal motors, drill bits, drilling fluid and accompanying measurement-while-drilling system. These new technologies provide opportunities for drilling oil and gas wells in previously undrillable ultra-high temperature environments.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractNuclear Magnetic Resonance (NMR) was identified as a critical technology for reducing uncertainty and minimizing risk during the planning phase of a major field development project. The reservoirs in the subject field contain heavy oil/tar in the flanks, and accurate knowledge of viscosity trends becomes essential for the placement of water injectors. Since NMR logs can be used to estimate heavy oil viscosity, the development plan required running logging while drilling (LWD) NMR logs in the extended-reach horizontal injectors, in addition to some selected producers.A program heavily based on slim hole drilling presented a practical challenge for the execution of the development plan, since at the time no service company offered slim hole LWD NMR services. Considering the business impact of this technology gap, the operator decided to collaborate with the service industry to develop LWD NMR technology for hole sizes ranging from 5⅞-to 6⅛-in. Within a year, a joint project was established with a major technology provider for the development of a slim LWD NMR tool. The first two prototypes were delivered for field testing in less than 18 months.The prototypes have been run in nearly a dozen wells to date and in a variety of environments, including extended-reach wells with high salinity muds. Data obtained from drilling and reaming runs agree very well with those from other porosity tools, including wireline NMR. Furthermore, close coordination and cooperation between the operator and the service provider during testing runs have resulted in significant improvements in downhole firmware, data acquisition modes and signal processing.Two factors weigh heavily for the successful fast delivery of the project goals: clear requirements from the operator, and proven expertise in NMR tool design from the technology provider. Given continuing reliable and robust performance from the prototypes, the slim LWD NMR service is expected to be commercially available shortly. In fact, the high level of confidence gained from early field tests has already allowed the use of the data in critical well placement decisions in some wells.

fax 01-972-952-9435. AbstractThe economic recovery of hydrocarbons from deepwater reservoirs continues to be a major challenge facing the exploration and production industry, not just contending with the multitude of market uncertainties, but also, more importantly, reservoir deliverability uncertainties associated with deeply deposited pay targets. One large field subject of this study is such, deposited in stacked Pliocene sandstones. These are high net-to-gross, with predominant very finegrained sands. The efficient sweep of the oil in place requires a detailed understanding of the network of the reservoir pore structure, and the permeability distribution and capillary bound fluids.To better understand and characterize the permeability and to help quantify the potential reserves, a novel low gradient magnetic resonance LWD tool for application on conventional drilling assemblies was used. This is a major departure from the more conventional techniques which use high gradient magnetic resonance on post-drilled wireline platforms. Advantages of an LWD approach are twofold; the wellbore is in good condition at the time of drilling, yielding high quality data, and the gain in rig time is significant.The high quality magnetic resonance dataset acquired was confirmed by overlaying with stationary measurements. The data was integrated with offset core data to normalize permeability models and saturation functions. LWD density images acquired during drilling were also used to provide detailed visualizations of the internal laminations of the turbidites, as well as a reservoir structural setting. Formation pressures and mobility measurements acquired during drilling were also integrated in the normalization process to characterize the deliverability of the sands. The resulting permeability model was used to study and redesign future development in the field. The saturation results also provide an improvement over the previous resistivity-only based saturation values, which were pessimistic due to the fine-grained structure of the reservoir sands.