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S onic I nv e stig a tions I n a nd A round th e B ore h ol e

J . L . A rroy o F ra nc o

M . A . M e rc a d o O rtiz Pemex Exploració n y Producció n Reynosa, Mexico

G op a S . D e

Chevron Energy Technology Company San Ramon, California, USA

L a sse R e nl ie Statoil ASA Stjø rdal, Norway

S te p h e n W il l ia m s Norsk Hydro ASA Bergen, Norway

For help in preparation of this article and in acknowledge- ment of their contributions to the development of the Sonic Scanner acoustic scanning platform and applications, thanks to Sandip Bose, Jahir Pabon and Ram Shenoy, Cambridge, Massachusetts, USA; Tom Bratton and Adam Donald, Denver, Colorado, USA; Chung Chang, Tarek Habashy, Jakob Haldorsen, Chaur-Jian Hsu, Toru Ikegami, David Johnson, Tom Plona, Bikash Sinha and Henri-Pierre

V alero, Ridgefield, Connecticut, USA; Steve Chang, Takeshi Endo, Hiroshi Hori, Hiroshi Inoue, Masaei Ito, Toshihiro Kinoshita, Koichi Naito, Motohiro Nakanouchi, Akira Otsuka, V ivian Pistre, Atsushi Saito, Anthony Smits, Hitoshi Sugiyama, Hitoshi Tashiro and Hiroaki Yamamoto, Sagamihara, Kanagawa, Japan; Rafael Guerra and Jean- Francois Mengual, Rio de Janeiro, Brazil; Dale Julander, Chevron, Bakersfield, California, USA; Larry O’Mahoney, Chevron, New Orleans, Louisiana, USA; Marcelo Osvaldo Gennari, Reynosa, Mexico; Pablo Saldungaray, V eracruz, Mexico; Keith Schilling, Bangkok, Thailand; Kwasi Tagbor and John Walsh, Houston, Texas; Badarinadh V issapragada, Stavanger, Norway; Canyun Wang, Beij ing, China; Erik Wielemaker, The Hague, The Netherlands; and Smaine Z eroug, Paris, France.

Array-Sonic, CBT (Cement Bond Tool), DSI (Dipole Shear Sonic Imager), ECS (Elemental Capture Spectroscopy), FMI (Fullbore Formation MicroImager), HRLA (High- Resolution Laterolog Array), LSS (Long-Spaced Sonic Tool), MDT (Modular Formation Dynamics Tester), OBMI (Oil- Base MicroImager), Platform Express, Sonic Scanner, TLC (Tough Logging Conditions) and V ariable Density are marks of Schlumberger.

1. Lé onardon EG: “Logging, Sampling, and Testing,” in Carter DV (ed): History of Petroleum Engineering. New York City: American Petroleum Institute (1961): 493–578.

2. Slowness, also called interval transit time, is the reciprocal of speed, or velocity. The common unit of slowness is microseconds per foot (µ s/ft).

S onic m e a sure m e nts h a v e c om e a l ong w a y sinc e th e ir introd uc tion 5 0 y e a rs a g o.

T h e l a te st a d v a nc e m e nt in sonic te c h nol og y d e l iv e rs th e h ig h e st q ua l ity d a ta se e n to d a te , a l l ow ing a c oustic m e a sure m e nts to c h a ra c te riz e m e c h a nic a l a nd  uid p rop e rtie s a round th e bore h ol e a nd te ns of f e e t into th e f orm a tion.

Finding and producing hydrocarbons efficiently and effectively require understanding the rocks and fluids of a reservoir and of surrounding formations. Three basic oilfield measurements— electromagnetic, nuclear and acoustic— have been devised to achieve this end. With advances in tool design and in data acquisition, processing and interpretation, each measurement type has evolved to produce more and different information. None, perhaps, has evolved more than the acoustic, or sonic, measurement. In their early days, sonic measurements were

relatively simple. They began as a way to match seismic signals to rock layers.1

Today, sonic

measurements reveal a multitude of reservoir and wellbore properties. They can be used to infer primary and secondary porosity, permea- bility, lithology, mineralogy, pore pressure, invasion, anisotropy, fluid type, stress magnitude and direction, the presence and alignment of fractures and the quality of casing-cement bonds. Improvements in sonic measurements are

enhancing our ability to determine some of these properties. Accuracy is improving in the basic measurements, which consist of estimates of compressional- (P-) and shear- (S-) wave slow- nesses.2

Variations in slowness are also becoming more fully characterized, leading to an improved understanding of how formation properties change over distance and with direction.

Formation properties often vary directionally, so to be completely described, they must be measured in three dimensions. The borehole has a natural, cylindrical 3D coordinate system: axial, or along the borehole; radial, or perpen- dicular to the borehole axis; and azimuthal, or around the borehole. Variations around and away from the borehole depend on many factors, including the angle the borehole makes with sedimentary layering. Axial variations are typical of vertical boreholes in horizontal layers, and can indicate changes in lithology, fluid content, porosity and permeability. Radial rock- and fluid- property variations arise because of nonuniform stress distributions and mechanical or chemical near-wellbore alteration caused by the drilling process. Azimuthal variations can indicate aniso- tropy, which is caused by layering of mineral grains, aligned fractures or differential stresses. Improved characterization of compressional and shear slownesses in terms of their radial, azimuthal and axial variations is now possible with a new sonic tool, the Sonic Scanner acoustic scanning platform. High-quality waveforms and advanced processing techniques lead to more accurate slowness estimates, even in unconsoli- dated sediments and large boreholes, and also to reliable through-casing slowness measurements. These improvements result in better characteri- zation of subsurface rock and fluid properties, meaning more stable wellbores, longer-lasting completions and enhanced production.


Oilfield Review

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