NMR Logging System Profiles Reservoir Fluids In Situ
- Robert Leveridge (Schlumberger)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- August 2008
- Document Type
- Journal Paper
- 28 - 34
- 2008. Copyright is retained by the author. This document is distributed by SPE with the permission of the author. Contact the author for permission to use material from this document.
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For many years, petrophysicists have been differentiating reservoir fluids by means of wireline logging instruments. However, this process has been time consuming, and for a number of environments, challenging. For nuclear-magnetic-resonance (NMR) measurements there have been further obstacles, such as job-preparation issues, availability of expert knowledge, and nonroutine workflows. The use of NMR fluid-identification methods, therefore, usually has been restricted to specialists.
Petrophysicists and reservoir engineers have long wanted to identify formation-fluid types, estimate their volumes, and determine their in-situ properties. A key goal has been to characterize formation hydrocarbons, regardless of variations in formation water salinity, thin beds, or low-contrast pay zones. With such information, it becomes possible to make a continuous log of oil viscosity for completion optimization, to determine fluid-storage volumes by means of lithology-independent porosity measurements, and to determine residual oil saturation in all mud types. An additional objective has been the ability to take measurements in rugose boreholes, or in zones with thick mud cake.
A new-generation NMR wireline logging tool developed by Schlumberger is able to meet these and other needs. Called the MR Scanner, the tool uses a multifrequency, multiantenna, deep-reading measurement at logging speeds up to 3,600 ft/hr to perform precise radial profiling of fluids surrounding the borehole (Fig. 1). Tool performance is unaffected by hole rugosity or variations in lithology, and measurements are obtainable regardless of borehole size or geometry, with axial resolution as good as 7.5 in. Most important, the use of the tool saves rig time because all measurements are made simultaneously.
A variety of quick-look outputs in user-friendly formats are made available onsite, including oil and water saturations, total and effective porosity, bulk volume irreducible water, crude oil and brine transverse relaxation time (T2) distributions, and hydrocarbon-corrected Timur-Coates permeabilities. In addition to T2, the longitudinal relaxation time (T1) is available for vuggy porosities, or in zones containing light hydrocarbons.
Tough Tests Prove Technology’s Value
Recently, a North Sea operator needed to determine if gas condensate, light oil, and water were present in a well drilled with oil-base mud. While that was challenging enough, the operator also wanted to identify the contact level of these fluids, if present. Conventional logs had been run in the well, but the interpretation results were inconclusive, largely because of the invasion of oil-base mud filtrate.
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