March 2015

What’s new in well logging and formation evaluation

Part 1: In this first of two installments, the latest developments in well logging and formation evaluation are assessed. General developments include ongoing efforts to improve the accuracy of the logging depth measurement and wellbore position, improving standards for well-log deliverables, and multi-log correlation. New developments in LWD, openhole wireline, and sensor design and methodology are discussed in detail.
Stephen Prensky / Consultant, Silver Spring, Maryland

The purpose of this article, which is based solely on published technical papers and publicly available literature, is to inform readers of new and potential technologies in well logging and formation evaluation. This article does not endorse or promote any particular technologies or service providers. Some of the technologies described in this article may be available, as commercial services, while others may still be in the development or test phases.

The big news, over the past year, is the sharp drop in oil prices that began in the second half of 2014. As operating companies cut back on their current and planned activities, to accommodate the lower price of oil, service companies have been forced to drastically reduce their expenses, and to seek greater efficiencies through major reductions in staff and mergers. In November, Halliburton agreed to purchase Baker Hughes for $34.6 billion. If approved by regulators, the combined operations, research and development activities are anticipated to result in an improved competitive position and market power, higher profit margins, and savings of approximately $2 billion. The combined company will retain the Halliburton name.


Depth correction. A recent modeling study examined the sources of errors, and corrections needed, for appropriate use of accelerometer data to correct depth measurements. Accelerometer noise, measurement system noise, cable tension and stretch, friction and drag, and filters were all taken into consideration. The study concluded that the critical accelerometer design issues for improvement are lower intrinsic noise, higher resolution and a wider dynamic range. If these factors are handled appropriately, faster accelerometer response is not required for accurate depth control, in either the wireline or LWD case.1

Wellbore position. A new MEMS- (microelectrical mechanical system) based gyroscope has been developed by Laserlith, with project funding from the U.S. Department of Energy.2,3 The new gyroscope, which has been designed for use in ultra-deepwater applications, has a compass accuracy better than 0.1°, and it is rated for operation in borehole temperatures of up to 260°F. The new design enables the inertial guidance system to be positioned next to the drill bit, in contrast to existing magnetometer guidance systems, which are, typically, positioned 50–80 ft behind the bit. Near-bit proximity enables faster response in well placement, cutting casing windows, and intermediate-radius reentry, thus reducing rig time and drilling costs. Laserlith is seeking partners to pursue commercialization.

Accurate well orientation is required for both precise wellbore placement and acquisition of azimuthal well log data. Orientation quality depends on the acquisition of high-quality accelerometer and magnetometer information. Anomalous magnetization within the wellbore and formation can influence accelerometer and magnetometer measurements. Sources of well magnetic anomalies include geological remnant magnetization, magnetic materials near—but not in—the well, the magnetic field below the casing shoe, and magnetic debris in the well. Detection and proper correction for these magnetic anomalies is important to maintain the integrity of the orientation data, and the results derived from these data.

Baker Hughes developed a fast, robust method that improved the quality of the directional components, through the application of quality control and corrections for these magnetic field disturbances. Field tests have demonstrated that the orientation software is sensitive enough to detect, and correct, certain magnetic sources; comparisons to gyro data have verified results obtained in several wells.4

Standards for well log deliverables. At the present time, there is wide variation in the specific log data, and data formats, that logging service companies provide to customers. The basic requirements, which are specified in the published API Recommended Practices, are followed inconsistently, if at all, and are insufficient to address the large datasets generated by modern wireline and LWD tools. Data processing prior to delivery at the wellsite is common, and each service provider has its own methods for presenting log calibrations. Logging data are delivered in many different formats, and it is difficult to train people to recognize quality issues.

Six Teapot Dome velocity logs before (a), and after (b) automatic simultaneous correlation.6
Fig. 1. Six Teapot Dome velocity logs before (a), and after (b) automatic simultaneous correlation.6 Click image to enlarge.

With the increasingly common separation of data-acquisition and interpretation roles, in many companies, geoscientists may use the data without having sufficient information, and, therefore, not account for the shortcomings inherent in the log-acquisition process. This is a particular concern with LWD data. Failure to properly calibrate log data, and identify bad data, can have serious consequences in the cases of challenging interpretation issues, reinterpretation of vintage data, fluid saturation management, enhanced recovery, unitization and redetermination. The authors of a recent paper stress the need for implementing existing standards, and preparing new standards that will ensure acquisition deliverables contain a complete, correct record of the acquisition, which will allow their valid use, now and in the future.5

Multi-log correlation. Researchers at the Colorado School of Mines have proposed a new method for automatically, and simultaneously, correlating any number of well logs, Fig. 1. Their two-part procedure first uses a modified dynamic warping algorithm, to find a sequence of corresponding depths for each log pair. Then it uses a least-squares method to find depth shifts for every depth, in every log, that maximize consistency among all pairs of corresponding depths. Applying these depth shifts allows for the mapping of well logs in geologic time, rather than depth. The technique provides a globally optimal alignment of all logs, and consistent correlations. It is, relatively, insensitive to the large measurement errors that are common in well logs.6


Telemetry. A new start-up, Cold Bore Technology, is developing an acoustic telemetry system that uses the drillstring to transmit the acoustic signal (see World Oil, June 2014, p. 128).7 Technical details have not yet been published.

Acoustic cement evaluation. Qualitative cement evaluation by LWD acoustic tools has been demonstrated previously (see World Oil, June 2013, p. 75). However, because the casing and tool collar have similar slowness values, quantitative evaluation is difficult, except in some conditions.8 The dual-attenuation system that exists in LWD acoustic tools, i.e., between the transmitter and closest receiver, and across the receiver array, results in a positive trend of apparent attenuation in sections with low bonding values, but a negative trend in well-bonded sections.

A new, hybrid method combines the bond index, from the amplitude approach for low bonding values, with the apparent attenuation approach, for the well-cemented section. Field test results compared well with the bond index, which was computed using wireline data, and modeling suggests that the method may extend quantitative cement evaluation to the full range of bond index for a wider range of casing sizes, cement type, and borehole fluids, if the ambient noise level permits.9

Ultrasonic calipers. Acoustic calipers generate real-time images of the borehole (both 3D and 4D). These images can be used to analyze the evolution of wellbore geometry, and provide early detection of instability issues, thus enabling countermeasures in real time.10 A new, high-frequency (300 KHz) design uses a dual-sensor that allows determination of the borehole-fluid acoustic velocity, at in-situ pressure and temperature conditions. Because the acoustic velocity of the drilling fluid is a constant value at a particular depth, when the composition of the mud changes, such as with the influx of gas during a kick, the acoustic velocity in pure gas or the fluid-gas mixture will drop dramatically, thus providing kick detection in real time.11

Diagram of Weatherford’s azimuthal resistivity tool.14
Fig. 2. Diagram of Weatherford’s azimuthal resistivity tool.14 Click image to enlarge.

A second caliper design from Smart Reamer Drilling Systems (Smart Calliper) is a fit-for-purpose system for providing measurements of borehole diameter (i.e., geometry) in real time via mud-pulse telemetry or in memory mode. Survey measurements are taken at a rate of 1,500/sec, and the survey resolution can be user-defined, to suit the drilling application. The tool includes vibration and directional/inclination sensors. A primary application is pinpointing undergauge borehole sections for underreaming operations.12

Azimuthal resistivity. Weatherford reported on the development and field-testing of a new azimuthal resistivity geosteering tool (GuideWave) that incorporates conventional and oriented (tilted) transmitters and receivers, Fig. 2. The shallow and deep transmitter spacings operate at 400 KHz and 2 MHz, and the ultra-deep spacing operates at 100 KHz. The compensated phase and attenuation resistivity measurements are used to determine distance to boundaries in sub-horizontal wells.

The tool can detect formation boundaries at distances in excess of 20 ft from the borehole, depending on formation resistivity. In addition, the resistivity data are used to evaluate horizontal and vertical resistivity, dip angle, and strike angle at any relative dip angle, allow proactive geosteering. The tool will be available in both 4.75- and 6.75-in. sizes, and be rated to temperatures and pressures of 302°F and 20,000 psi (standard) or 30,000 psi (optional).13,14

Baker Hughes is developing and field-testing a new, extra-deep, azimuthal resistivity (EDAR) tool to increase the depth of investigation, to interpret multiple bed boundaries while drilling, to improve strategic well placement and geosteering decisions. The tool design allows both compensated coaxial resistivity measurements (attenuation and phase shift) and cross-component measurements, obtained by using a transmitter that is orthogonal to the tool axis.15

Schlumberger has commercialized its new, mapping-while-drilling service (GeoSphere) (see World Oil, June 2012, p. 82). The tool consists of three pairs of tilted antennas, spaced along an LWD bottomhole assembly (BHA), and operates at multiple frequencies and depths of investigation, Fig. 3. The location of the tool’s measuring depth is usually 12 to 15 m behind the bit. The very long transmitter-receiver spacing allows the tool to provide an extra-deep depth of investigation (DOI) of ≥100 ft. However, the intrinsic DOI depends on the tool spacing, transmission frequency, measurement noise, and formation resistivity and geometry.

For each T-R spacing and frequency, the tool measures the full nine-component resistivity tensor. These tensor components are extracted and combined to produce four types of calibrated phase-shift and attenuation resistivity measurements. Each is sensitive to different parameters: boundary proximity, deep bulk resistivity, anisotropy, and apparent formation dip. For a typical three-spacing BHA, the tool acquires 216 channels (measurements), including channels related to the 3D aspects of the formation, and formation orientation. The full measurement set from the tool is sent uphole, in real time, for three to four frequencies.

Fig. 3. Schematic showing Schlumberger’s mapping-while-drilling service (GeoSphere) tool architecture. Subs containing systems of tilted antennas are spaced along a BHA. The measurement’s depth of investigation is proportional to the transmitter-receiver spacing. The tool is configurable with up to three T-R spacings (only two are shown). For a given spacing, the basic architecture consists of three pairs of tilted antennas. Nine tensor components are extracted and combined to define eight calibrated measurements.16
Fig. 3. Schematic showing Schlumberger’s mapping-while-drilling service (GeoSphere) tool architecture. Subs containing systems of tilted antennas are spaced along a BHA. The measurement’s depth of investigation is proportional to the transmitter-receiver spacing. The tool is configurable with up to three T-R spacings (only two are shown). For a given spacing, the basic architecture consists of three pairs of tilted antennas. Nine tensor components are extracted and combined to define eight calibrated measurements.16 Click image to enlarge.

The selection of the optimum frequency range depends on the expected formation-resistivity profile and transmitter-receiver spacing. The low-frequency range (~1 to 5 KHz) is used to obtain maximum DOI in low-resistivity formations, to facilitate landing in a reservoir with overlying conductive shale, while the high-frequency (≥50 KHz) range is more appropriate for use in high-resistivity reservoirs and also short spacing measurements that have low DOI. The high-frequency range provides better delineation of geologic structure.

The ability to detect resistivity contrasts ≥100 ft allows real-time mapping of multiple reservoir layers and fluid contacts at the reservoir scale (between conventional logs and seismic). The relative dip of the formation layer can be determined, both at the trajectory and also away from it. The multi-layer inversion used in the answer product generates a map of the resistivity distribution, above and below the borehole. In addition to the 1D (layer-cake) resistivity mapping, the tool provides a map orientation perpendicular to the formation structure planes (oriented curtain section).

These maps are provided in real time and can be used to improve the accuracy of well placement, help reduce drilling risk, and increase reservoir exposure, i.e., increase production. When used in combination with seismic surveys, this new mapping service also can help confirm, and refine, reservoir structure and geometry. The tool is available in 6.75-in. and 8.25-in. diameters for use in borehole sizes ranging from 8.5 in. to 9.875 in. and 12.25 in. to 14.75 in., respectively. Both tools are rated to 302°F and 25,000 psi.16, 17, 18

Magnetic resonance imaging. Baker Hughes’ new large-diameter (8.25-in.) LWD NMR tool (see World Oil, June 2013, p. 76) is undergoing field-testing. The tool design, which has been adapted specifically for T2 acquisition in the large-hole environment, uses a low magnetic field gradient (2.4Gs/cm), a higher operating frequency (460 KHz), and a shorter inter-echo time (TE = 0.4 msec). The low magnetic field gradient minimizes the adverse effects of lateral motion, which increases echo accuracy. The use of shorter TE results in a number of benefits, including: a) improved vertical resolution, b) greater accuracy of short-T2 porosity (e.g., clay-bound water, heavy oil, and carbonate microporosity), and c) improved accuracy of the raw echoes.

Fig. 4. Layout of Weatherford’s SineWave microresistivity borehole imager.21
Fig. 4. Layout of Weatherford’s SineWave microresistivity borehole imager.21 Click image to enlarge.

A larger sensor outer diameter (10.625 in.) reduces the distance between the tool and the borehole wall, thereby: 1) increasing the NMR signal; 2) reducing thermal noise and distance to the sensitive volume, i.e., improving SNR and raw-echo precision; and 3) reducing the power requirements for the radio-frequency (RF) transmitter, thus enabling acquisition of more echoes, per sequence, to compensate for a shorter TE. The tool aperture (vertical resolution) is 4.6 in., the diameter of investigation is 18 in., and the tool is rated to 302°F and 30,000 psi. The tool is powered by an electrical alternator, which is driven by the mud turbine.19

Borehole imaging. Weatherford has introduced a new, high-resolution, LWD microresistivity imaging tool (SineWave) that provides full borehole coverage and real-time images, in highly conductive, water-based mud, for use in geosteering and formation evaluation. The tool employs two measurement electrodes, 0.20 in. and 0.5 in. in diameter, which provide images at different resolutions and depths of investigation, in a wide range of mud and formation resistivity values and borehole conditions, Fig. 4. Images are available in real time as 16-, 32-, or 64-bin images, or in 128-bin, full-360° scans in recorded (memory) mode. The electronics can acquire 128-bin, full-borehole scans, as fast as one per second, which provide high-resolution scans, even at high rates of penetration. The 4.75-in. diameter, battery-operated tool is designed for use in 6- to 6.75-in. boreholes. The conventional tool is rated to 302°F and 20,000 psi. An optional HPHT version is rated to 329°F and 30,000 psi.20, 21, 22

Slimhole through-the-bit system. Mineral exploration, typically, uses slimhole drilling (<80-mm diameter) and core-retrieval technologies that are incompatible with conventional oilfield wireline and LWD systems. Consequently, geophysical logging is not used commonly in mineral exploration. A novel, “through-the-bit” LWD system for use in mineral exploration is being developed through the Deep Exploration Technologies Cooperative Research Centre (DET CRD) in Australia. This system, which will be backwards-compatible with existing slimhole diamond drilling technologies, will not require modifications to existing drilling rigs.

Fig. 5. Illustration of the measurement sonde deployed ahead of the bit.23
Fig. 5. Illustration of the measurement sonde deployed ahead of the bit.23 Click image to enlarge.

The new system does not use cable or wireline—the inner core assembly is replaced, prior to trip-out, with sensors that are placed at the end of the drillstring and log the open hole through the bit, as the drillstring is pulled out of the borehole—measurements are acquired during bit changes or at the end of drilling, Fig. 5. The sensor assemblies are restricted to <40-mm diameters for operation within NQ drill-rods (47-mm core, 75-mm borehole), which is the most common size used in mineral exploration. The initial sensor package is a total count, gamma (TC Gamma) sensor. Other sensors being integrated to the sonde are magnetic susceptibility, induction resistivity, pressure sensor, and an accelerometer system for depth registration.

When the drillstring is still during trip-out, data from the pressure sensor are used to interpolate the data between the rod intervals, providing a rate of ascent of the drillstring. Thus, with a reported starting depth, the data may be reconstructed from two time series: the pressure sensor and the petrophysical measurement versus time. Because the drillstrings are relatively short (typically <2 km), compared with oilfield use, there is little pipe stretch, and temperature changes within mineral-exploration environments are generally small.

Field tests demonstrate that despite the relatively rapid withdrawal of the drillrods, compared to conventional wireline logging rates, i.e., 10-20 m/min. versus 2-5 m/min., the data quality and good depth registration compares well with wireline data, and are suitable for geological interpretation. It is hoped that the availability of this, and similar systems, will foster the application of geophysical logging in mineral exploration.23

Sourceless density measurement. There are fundamental differences in the physics underpinning the conventional, chemical-sourced, gamma-gamma measurement of bulk density (GGD) and the new, “sourceless,” pulsed-neutron-derived neutron-gamma density (NGD) measurement (see World Oil, June 2013, p. 77). There is an ongoing discussion, whether the NGD measurement can provide a reliable, and acceptably accurate, density measurement that can fully replace GGD measurements in log analysis/interpretation.24, 25

Schlumberger has conducted a series of field tests, in different wells, to determine whether there is any practical difference between the two measurements. A series of multi-function LWD tools was configured to run both chemical and pulsed-neutron sources simultaneously. This allowed the two measurements to be obtained independently, using the same tool, in the same well.26 In this study, the average difference between the measurements was 0.001 g/cm3 for the entire dataset. This difference is well within the SNGD measurement accuracy specification of 0.025 g/cm3 for clean formations, and 0.045 g/cm3 for shale. The authors concluded that the study results justify placing confidence in the NGD measurement, in wells where there is a high risk of losing the BHA containing a chemical source, and in countries or states where the use of radioactive chemical sources is heavily regulated or not permitted.


Downhole Raman spectroscopy. Following an extensive laboratory and field development program, WellDog Inc. (aka Gas Sensing Technology Corporation) in Laramie, Wyo., in collaboration with Shell International Exploration and Production, has developed a new technical service for locating natural gas accumulations in shale formations. The service, now in beta trials, combines WellDog’s patented downhole Raman spectroscopy (see World Oil, March 2009, p. 58) with Shell’s expertise in geochemical and petrophysical evaluation of shale formations.

The technology, which was developed specifically for use in coalbed methane exploration, includes a ruggedized, compact wireline, downhole Raman-spectroscopy analytical system. The Raman-spectroscopy-based sensor provides real-time determination of in-situ borehole fluid chemistry, and also quantifies trace amounts of methane gas in solution, by relating the solution-gas level (i.e., the amount of methane dissolved in formation water or borehole fluid) to the partial pressure of methane. By determining the effective partial pressure of methane, reservoir properties, such as gas content and gas saturation, can be derived.27, 28

Borehole imaging. The design and field-testing of Schlumberger’s new, high-definition, microresistivity imaging tool, designed for non-conductive, i.e., oil-based, mud, (see World Oil, June 2014, p. 132) is described in a recent paper.29 Commercialized in August 2014, Schlumberger’s new photorealistic reservoir geology service (Quanta Geo), which includes the new high-resolution microresistivity imager, produces oriented, photorealistic, core-like images of the formation in wells drilled with oil-base mud (OBM). Interpretation of the images identifies geological features and predicts reservoir trends in 3D with a high degree of certainty.30

The physics of the Quanta Geo service’s high-resolution array of 192 microelectrodes provides geologically representative images of 0.24 in. vertical resolution by 0.13 in. horizontal resolution and 98% circumferential coverage in an 8-in. borehole. The articulated caliper and independently applied pads enable down-logging at up to 3,600 ft/hr, which significantly reduces rig time while mitigating operational risk and delivering data assurance.

Baker Hughes introduced a new, multi-frequency, microresistivity imaging tool, designed for operation in OBM. The tool provides high-resolution images, in both the vertical and azimuthal directions. The imager comprises six individually articulated pads, which cover 80% of an 8-in. borehole. There are two symmetrically placed, transmitting electrodes, and 10 azimuthally distributed sensors, mounted on each of the six pads, which provide microresistivity impedance measurements with 0.8-in. vertical resolution and 0.3-in. azimuthal resolution. Each pad simultaneously measures all individual button currents, which are then converted from respective voltages into amplitude and phase values, by comparison to a
transmitter signal.

The complex resistivity data are sent by the telemetry module to the surface for use in estimating the real and imaginary components of impedance associated with the measuring buttons. The real components are used to generate static and dynamic resistivity images, and the imaginary parts are used to generate an image of stand-off. The combination of the unique mechanical design, advanced signal processing electronics, and high-frequency voltage amplifiers give the tool high measurement accuracy.31

Pressure transient testing. Schlumberger has developed a single-crystal, dual-mode pressure and temperature gauge (Signature CQG Crystal Quartz Gauge) for use in high-performance downhole reservoir testing systems. The use of a dual-mode oscillator allows the single quartz crystal to measure both parameters simultaneously, which reduces the temperature-related errors in measurement accuracy that often accompany the use of separate pressure and temperature sensors, particularly in HPHT environments—this results in greater resolution and measurement accuracy. The overall size of the battery-operated gauge has been reduced, which shortens its thermal dynamic equilibrium time. The simple design increases the maximum pressure and temperature limits. The gauge is rated for operation up to 347°F and 16,000 psi, and achieves ±1.2-psi sensor accuracy and 0.003-psi resolution.32

Downhole fluid analysis. Weatherford and Avo Photonics have collaborated on the design and development of a new downhole, multi-channel photometer to analyze formation fluids in HPHT wells. The wireline-deployed optical fluid analyzer (Reservoir Fluid Analyzer) provides real-time, in-situ characterization of reservoir fluid type and composition. The sensor conforms to a 4.5-in. diameter space and is rated to 351°F and 30,000 psi. The new design has been deployed in several field trials, and it is currently in manufacturing.33

Baker Hughes has developed a new density/viscosity sensor that employs a highly precise torsional resonator that changes its resonance characteristic, resonance frequency and damping, depending on the density and viscosity of the fluid that the sensor is immersed in. Originally designed for LWD devices, the sensor also can be used in wireline formation testers.34 The resonator is made of high-strength, high-corrosion-resistant metal that makes the sensor extremely robust and suitable for high-temperature and high-ambient-pressure drilling conditions. It performs well in conductive and nonconductive fluids.

The sensor uses wireless excitation and sensing via electromagnetic coupling between electrical coils, outside the sensing chamber, and a magnet embedded in the tine head of the resonator. The two measured values, resonance frequency and damping, are correlated to values of viscosity and density, via a mathematical model and from an empirical calibration curve built for each sensor. However, the empirical calibration is the preferred method. Depending of the characteristics of the fluids, the entire viscosity and density measurement takes about one second, and can be performed when the pressure is constant in the pump’s drawdown period. The density measurement accuracy and precision achieved in the laboratory are >0.01 g/cm3 and ±0.001 g/cm3, respectively. The accuracy and precision of the viscosity measurement are >10% for viscosity >1 mPa•s or > 0.1 mPa•s for viscosity <1 mPa, and >±1%, respectively. The sensor has been laboratory-tested to 392°F and 2,000 bar (29,000 psi). wo-box_blue.gif 


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About the Authors
Stephen Prensky
Consultant, Silver Spring, Maryland
Stephen Prensky is a consultant to logging service companies, with 40 years of working experience in petroleum geology and petrophysics. He previously worked for Texaco, the U.S. Geological Survey and the U.S. Minerals Management Service.
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