What’s new in well logging and formation evaluation

Canadian company Quest Coring recently cut a record 120 ft of 3½-in. core in a single run for an operator working in the Niobrara shale of Colorado, using its QuickCore wireline retrievable coring system. In January, Quest entered a partnership with Reservoir Group for distribution of the large-bore coring technology.

New developments include an ultrasonic wireline imager, an electromagnetic free-point indicator, wired and fiber-optic coiled tubing systems and extreme-temperature LWD tools. 

STEPHEN PRENSKY, Consultant, Silver Spring, Maryland

The drilling of horizontal wells has been increasing dramatically, due in great measure to the strong interest in unconventional reservoirs where these wells are critical to development economics. Consequently, many of the recent advancements in wireline and logging-while-drilling (LWD) technology covered in this article are designed to assist in the placement (geosteering), completion (cement integrity and fracture treatment), and production optimization (well intervention) of horizontal wells.

The continued consolidation in 2010 of logging and petrophysical service providers (Table 1) means that these innovations are increasingly being provided by a few large companies.

WIRELINE

Advances over the past year have occurred in a wide array of wireline technologies, including acoustic logging tools, borehole imaging, nuclear logging, and formation testing and analysis.

Slimhole acoustic tools. Weatherford International launched a slimhole (2¼-in.) cross-dipole tool as part of the company’s line of compact logging tools.¹ The 26-ft-long Compact Cross-Dipole Sonic, or CXD, tool can be run as part of a quad-combo compact logging string. The multipole tool uses three wideband transmitters (one monopole and two low-frequency cross-dipole) and an eight-station receiver array, with each station consisting of four hydrophones aligned with the dipole transmitters. It records 96 waveforms to provide compressional, shear and Stoneley wave slowness. Shear wave and anisotropy orientation are available when the tool is run in combination with either the Compact Borehole Navigation or Compact Microimager tool.

The new tool is designed for use in boreholes ranging 3.5–15.7 in. and is rated to 275°F and 15,000 psi. It can be deployed in vertical or highly deviated/horizontal wells using wireline, slickline, coiled tubing (CT), dropoff, well shuttle or conveyed through drill pipe.

Ultrasonic acoustic scanner. Halliburton introduced a version of its circumferential acoustic scanning tool (CAST) that runs on monoconductor cable (CAST-M) to provide high-resolution images in open hole and in cased hole for casing and cement evaluation.² Because of monocable’s limited bandwidth, most processing tasks are performed downhole to enable real-time transmission of high-resolution data. All waveforms are stored in downhole memory and available for surface reprocessing; most of the cement-bond processing is done at the surface.

There are three operational modes: borehole-image mode (acoustic traveltime and amplitude), pipe-inspection mode (acoustic frequency) and cement-inspection mode (transducer signature and resonance). The acoustic scanner acquires up to 180 azimuthal samples and up to 36 samples per foot (in high-resolution mode) for 100% borehole/casing wall coverage. The 3⅛-in. tool operates in open boreholes and casing with OD ranging 4½–9⅝ in. and is rated to 350°F and 20,000 psi. The tool can be run at logging speeds up to 75 ft/min. in 4½-in. casing. A built-in scanner-head centralizer (Fig. 1) keeps the tool precisely centered in the well, enhancing log quality.

Table 1. Corporate mergers and acquisitions in logging and formation evaluation during 2010

Downhole cameras. Downhole video cameras operating on fiber-optic cable, e-line, slickline or CT are used to identify and diagnosis well-integrity problems (e.g., fluid entry, damaged tubulars and junk/debris) in producing wells. The latest high-resolution systems from Expro include a 111/16-in.-OD, battery-powered slickline memory camera (SL2K) and a similarly sized e-line camera (Hawkeye IV). Both are highly portable and can be run on CT for inspection of horizontal wells and in wells with corrosive fluids (e.g., H2S or CO2). The battery-powered slickline memory tool is rated to 225°F and 10,000 psi, while the e-line camera is rated to 257°F and 10,000 psi.

Fig. 1. Monocable circumferential acoustic CAST-M scanner tool with mud velocity sensor.

The e-line tool can acquire and store images at rates up to 30 frames/sec. and transmit them via the electric line to the surface for real-time viewing or playback. A downlink from the surface control software can vary the capture rate from 1 to 30 frames/sec. by storing images in the tool and transmitting them in batches to the surface. The e-line camera is also available in a ViewMax model incorporating a second, side-pointing, camera that can rotate to allow unobstructed views of the wall of the pipe or openhole formation.³

The slickline tool can capture up to 2,200 video images at capture rates of 1, 2 or 5 frames/sec.—equivalent to a 36-minute e-line survey or a 5-minute full-motion video—that are viewed when the tool is retrieved at surface. Depth is recorded at surface during the survey and is later integrated with the video images. Examples of images and videos captured by both downhole cameras can be viewed on Expro’s website.

Dielectric logging. A new generation of array dielectric logging tools has been designed to provide improved formation evaluation in freshwater, carbonate, thinly bedded sand/shale, and laminated heavy oil reservoirs. The most recent antenna configurations also provide compensation for tool standoff, mudcake effects and borehole rugosity. Dielectric logging tools are high-frequency electromagnetic devices that provide high-resolution measurements of dielectric permittivity and conductivity in the flushed zone. This information enables invasion profiling and calculation of water saturation in freshwater or waterflooded reservoirs, and the high vertical resolution makes them useful in thin-bed and low-resistivity reservoirs. When combined with devices that measure the flushed-zone resistivity measurement Rxo, dielectric measurements can be used to compute the Archie cementation exponent, m.

Halliburton’s Microwave Formation Evaluation Tool is a 1-GHz tool that uses two transmitter antennas and three receiver antennas mounted in an articulated pad (Fig. 2) to provide six-phase and attenuation resistivity measurements with varying depths of investigation and extended dynamic range. The tool also measures formation temperature, which is important for steam injection wells in which the thermal gradients have been altered. Additional tool output includes dielectric constant, water porosity, electromagnetic travel velocity and formation temperature (for profiling steam injection).⁴

Schlumberger’s recently commercialized Dielectric Scanner multifrequency dielectric dispersion service (first discussed in the March 2009 edition of this article, p. 55) has applications in carbonates, thin beds, heavy oil fields and mature fields that use freshwater or steam injection for improved recovery. An important feature is its ability to quantify residual oil saturation in mature carbonate reservoirs despite wide variations in the Archie parameters m and n, as well as in the salinity of the invaded zone around the borehole.

At the heart of the device is an articulated pad antenna containing a borehole-compensated array of crossed-dipole transmitters and receivers. The transmitters are excited at four frequencies and two polarizations, ranging from 20 MHz to 1 GHz. Nine separate auto-calibrated sets of  measurements are made. The measurements are symmetric and include both phase shift and attenuation components. A complete measurement is defined as the amplitude ratio and phase shift measured at each specific receiver with respect to the signal from the transmitter. Two additional coaxial probe antennas provide a quality control measurement and continuous mud and mudcake dielectric properties.

Fig. 2. The articulated pad on Halliburton’s Microwave Formation Evaluation Tool.

The pad itself is pressed firmly against the borehole wall by a hydraulically powered eccentering caliper designed to optimize pad contact in rugose boreholes. The tool is capable of accurately measuring beds as thin as 1.0 in., and is fully combinable with a wide variety of wireline services.

The ability to combine multifrequency dielectric measurements at different depths of investigation and two polarizations (longitudinal and transverse) allows interpretation of permittivity and conductivity at each frequency. With continuous measurement of dispersion, m, n and cation exchange capacity can be determined in situ and presented as a continuous log.

Free-point indicator log. Determining the free point of stuck drill pipe, casing or tubing is a necessary element in drilling and abandonment operations. Traditionally, this has been accomplished through a series of stationary strain measurements to detect drillstring stretch or rotation while the free-point tool is mechanically anchored in the drillstring and force is applied to the pipe. Measurements are made with the drillstring in a neutral condition and then again with either tension or torque applied during each recording. This method often requires many hours of rig time.

A new logging tool from Halliburton, the Magnetic Effect Freepoint Tool, uses the magnetostrictive effect to identify the free point. When a mechanical stress (torque or tension) is applied to steel pipe, the magnetization of the free pipe changes, while that of the stuck pipe remains the same.^5,6 The tool uses a permanent magnet to create a small magnetic field in the drillstring, and measures the magnetization using four highly sensitive orthogonal magnetometers that detect very small magnetic field changes in the radial, tangential and longitudinal directions. The radial and tangential measurements detect and distinguish changes induced by torque and rotation in the drillstring.

An initial logging pass creates a small magnetic field on the pipe and records the pipe magnetization information with the pipe in a neutral weight condition. A second logging pass records the magnetization information after the pipe is stretched or torqued between logging passes. The free point is detected by comparing the two logging passes, Fig. 3. An optional third pass with torque applied can also be beneficial in some cases.

The magnetometers in the longitudinal orientation can also be used as a high-sensitivity collar locator. The short (8-ft), small-diameter tool is run centralized and is deployed by e-line in near-vertical wells and by pumpdown or tractor in highly deviated or horizontal wells. Logging speeds range 60–120 ft/min.

Nuclear logging. The US government’s concern that the chemical sources used in well-logging tools represent a national security risk has resulted in the Radiological Source Replacement Program, administered by the National Nuclear Security Administration. The program’s objective is to find alternative technologies to nuclear and isotope-based well logging.⁷ The primary concern is with the americium-beryllium (241AmBe) sources commonly found in porosity logs.

Some service companies have begun using californium sources or electronic neutron generators (deuterium-tritium, or D-T) as alternatives. However, major challenges have limited deployment, particularly high cost, high maintenance and the impact the large difference in neutron energy—14 MeV for D-T vs. 4 MeV for AmBe—has on subsurface evaluation. The latter means that data from the two sources are not directly comparable. New electronic (50–100 keV, D-T) neutron sources are under development at the Los Alamos and Lawrence Berkeley National Laboratories. An industrywide effort is needed to develop calibration functions that can provide direct correlation between the new technologies and historic libraries of AmBe-based data.⁸

A newly designed three-detector, through-tubing pulsed neutron tool from Halliburton, with 11/16-in. diameter, provides improved sigma measurements through reduced environmental effects. The TMD-3D tool also provides improved gas detection and quantification in tight gas and shale gas reservoirs, replacement of openhole triple-combo logs (by means of artificial neural network-generated synthetic logs) in densely drilled fields, oxygen activation for water flow detection, and silicon activation for gravel-pack evaluation.⁹ The additional detector, positioned 10 in. beyond the traditional far-detector spacing, provides a deeper-reading set of count rates with larger formation gas response and an additional sigma measurement, each with reduced environmental effects, and is optimized for gas quantification and cased-hole density logging. The spacing of the conventional near and far detectors remains unchanged.

Fig. 3. A Magnetic Effect Freepoint Tool log showing differential sticking of the drill pipe.

New detectors made of yttrium orthosilicate and gadolinium/yttrium orthosilicate are significantly faster—reducing dead-time effects—and have improved spectral response, which improves the estimations of Si/Ca ratio as well as oxygen and silicon activation. A complete redesign of the electronics has significantly improved tool reliability and tool-to-tool repeatability. The new tool uses a function of certain long-spaced detector gates as a gas detector.

Weatherford’s battery-powered, memory-mode Pulsed Neutron Decay Spectrum tool can be run on slickline, CT or wireline.¹⁰ Operation in memory mode allows the use of smaller, less expensive slickline units and pressure equipment. Battery-powered operation in sigma and inelastic modes is made possible through a combination of improved power management, new lithium-ion battery technology, and neutron pulsing at 200–1,000 Hz in sigma mode and 1.4 kHz in inelastic mode. The batteries can power the tool for up to 16 hours.

Redundant software and mechanical systems have been implemented to prevent premature activation of the neutron generator at surface, and an additional magnetically operated safety switch can be used to kill the neutron generator if it is still active when the tool is retrieved. Downhole memory (128 MB) allows up to 100 hours of acquisition time. The tool includes a gamma-ray casing-collar locator for correlation and can be combined with a cement-bond log or through-casing resistivity.

Downhole formation analysis. Accurate, quantitative in-situ description of reservoir fluids in real time is important for reservoir characterization, estimating reserves, predicting reservoir performance, flow assurance, production strategies and facility design.

Baker Hughes’ In-Situ Fluids eXplorer service provides real-time in-situ measurements of reservoir fluid properties (e.g., density, viscosity, gas/oil ratio, compressibility and sound speed) for fluid typing and contamination monitoring. Fluid velocity, which is sensitive to properties such as water salinity and compressibility, is used to ensure collection of low-contamination formation water samples in water-based mud (WBM) environments and to differentiate live oil from oil-based mud (OBM) filtrate. The tool provides near-infrared spectra, fluorescence spectra and continuous refractive index of the formation fluid being pumped. Sensor responses are monitored to minimize contamination of samples. Fluid density can be used to confirm and correlate pressure gradients. Measurements of fluid mobility and viscosity are used to provide formation permeability. Identifying changes in fluid composition distinguishes different zones and reservoir compartmentalization.¹¹

PRODUCTION LOGGING

The objective of reservoir monitoring is to measure, control and predict reservoir performance. Traditional borehole monitoring (surveillance) involves repeated (i.e., time-lapse) measurements, typically using pulsed-neutron logging devices. In recent years there has been widespread adoption of fiber-optic sensing systems in production logging. Fiber-optic sensors are highly reliable because they are passive sensors; i.e., they have no moving parts or downhole electronics. They can operate over a wide range of borehole conditions without loss of production and are ideal for use as permanent sensors.

A variety of available fiber-optic sensors provide measurements of temperature, pressure, acoustic noise (velocity and amplitude), strain and vibration. Surveys are repeated at specific time intervals to monitor production fluid flow, sand production and flow behind casing, to locate zones of lost circulation and to identify the top of cement. Other applications include monitoring of thermal floods (steam injection profiling and steam channeling), tubular leaks, acid stimulation, water fingering and sweep efficiency of waterflooding, and—most recently—sand production and hydraulic fracture treatments. In distributed sensing systems—temperature (DTS) is the most common—sensors are typically mounted at 1-m intervals, which allows real-time depth profiling along the length of the well. The sensors can be deployed via wireline, fiber-optic-enabled CT,^12,13 or as permanent in-well installations.

Fiber-optic sensing. A fiber-optic-based logging system has been introduced by Sensornet for real-time live-well intervention applications, such as well integrity, flow and injection allocation, crossflow verification and monitoring and steamflood performance. The ZipLog system can be operated remotely on the rig floor without requiring conventional wireline, tractor or CT units for deployment.

DTS sensors are mounted on a semi-rigid, spoolable 0.6-in.-diameter carbon-composite rod that is pushed into the well to evaluate inflow performance. The self-straightening rod can be deployed in vertical, high-angle and horizontal wells. The rod is run to depth and parked temporarily (in retrievable mode) or permanently to monitor production or injection rates. DTS sensors are mounted at 1-m intervals and have a resolution of greater than 0.01°C. The current depth limit is 16,000 ft. The bullnose termination can also incorporate pressure and vibration sensors.

The logging system has several components: DTS data acquisition, point pressure monitoring, composite carbon rod with the sensors, injector head and well-control equipment. Full interpretation of the DTS data requires information on the geology, reservoir fluids and completion. The system’s small footprint and low weight allow faster rig-up and safer operation.¹⁴

Shell is field testing a fiber-optic distributed acoustic sensing (DAS) system for monitoring frac treatments in vertical and horizontal tight-gas wells.¹⁵ The system relies on sensing vibro-acoustic disturbances near the fiber-optic cable. The interrogator system uses the measurement of backscattered light and advanced signal processing to segregate the optical fiber into an array of individual “microphones.” Each acoustic signal corresponds to 1- to 10-m-long segments (channels) in the fiber. Each time sample contains a snapshot of the acoustic field averaged over the selected interval of cable at that particular sample section; interval length and other operating parameters can be adjusted to optimize performance. Raw acoustic data are passed from the interrogator unit to the processing unit, which provides signal interpretation and visualization.

The data recordings (images) made during the tests (Fig. 4) indicate that DAS is a sensitive, robust and highly cost-effective technology for real-time monitoring of downhole and completion operations, such as milling, fishing, setting bridge plugs, perforating and fracing. The quality of the acoustic recording represents a significant improvement in the ability to optimize fluid and proppant placement through real-time intervention during the treatment, and in the ability to diagnose the effectiveness of limited-entry treatment designs through post-job diagnostics and analyses. Other potential downhole applications include distributed flow measurement, sand detection, gas breakthrough and artificial lift optimization.

Permanent downhole SP sensors. Recent studies at Imperial College London have shown promising results regarding the feasibility of using electrokinetic potential (SP) for reservoir monitoring via permanently installed downhole electrodes in intelligent wells. The SP signal peaks at the location of the moving waterfront, where there are steep gradients in water saturation and salinity, and decays with distance from the front. SP measurements could detect and monitor water encroachment at distances of tens to hundreds of meters.^16,17 Larger signals would be obtained in low-permeability reservoirs produced at high rates, saturated with formation brine of low salinity or with brine of a very different salinity from the injected fluid.

Additional applications could include determination of the water saturation in the near-wellbore region through inversion of the measured signals in conjunction with available reservoir data, and regulation of flow into intelligent wells to maintain or increase oil production and delay or prevent water production. The authors of one of the studies state that “significant uncertainties remain to be resolved before the measurements can be interpreted with confidence.”

TELEMETRY

New and improved telemetry systems increase operational efficiency and help to optimize drilling, well placement, completion and well intervention, especially in horizontal boreholes.

Wired tubing and drill pipe. A second-generation prototype of National Oilwell Varco’s Intelliserve networked (wired) pipe is undergoing testing. This new system will operate at a rate of 2 Mbit/sec. with 1 Mbit/sec. reserved for data telemetry.¹⁸ The first-generation pipe, which has a 57-kbit/sec. transmission rate, is capable of interrogating and controlling downhole tools and rotary steerable systems in real time.

Sensors mounted in the signal-booster packages located every 1,500 ft along the drillstring, or closer if desired, can provide distributed temperature and pressure sensing to assist in detecting kicks, lost circulation or cuttings blockage, and in determining equivalent circulating density. Work is underway to add drilling-dynamics sensors to monitor drillstring operational parameters, such as acceleration, tension, compression and torque, to optimize drilling performance. The higher rate in the second-generation pipe is designed to facilitate full-wave transmission of seismic-while-drilling (vertical seismic profile) data, drillstring monitoring and control (e.g., vibration, torque, energy loss, compression, tension, strain and stress), and monitoring and automatic adjustment/configuration of downhole tools to remediate problems and optimize tool performance.

MWD/LWD electromagnetic telemetry. The dramatic development of low-permeability reservoirs such as shale and tight gas sands, which require large numbers of horizontal wells to achieve economic viability, has been accompanied by an upsurge in the use of electromagnetic telemetry for transmitting MWD and LWD data. EM telemetry is typically used in situations where conventional mud-pulse telemetry is prohibited by either 1) drilling conditions, such as wellbore instability, lost circulation and underbalanced drilling using noncompressive drilling fluids (air or nitrogen foam), or 2) the high cost of other options, such as wired pipe. EM telemetry systems transmit signals through the Earth and are therefore not limited by the type of borehole fluid, the presence of lost-circulation materials, or the need for fluid circulation. Continuous transmission of directional surveys, even when the mud pumps are off (during pipe connections), results in faster surveying that translates into significant savings in the overall drilling time for a well.

As with mud-pulse telemetry, EM telemetry rates are typically less than 15 bits/sec. Commercial EM services, such as Baker Hughes E-MTrak and Halliburton ZoomXM, typically offer two-way data communication to enable surface adjustment of the downhole settings.^19,20 EM data transmission rate is a function of signal attenuation—i.e., formation geology and well depth. In the Baker Hughes system, transmission frequency and modulation schemes can be adjusted while drilling to optimize signal transmission. However, the service provider recommends performing pre-drill simulations to select the optimal downhole parameters for the subsurface conditions.²¹ EM telemetry has been used successfully in wells exceeding 14,000 ft.¹⁹

An EM telemetry system field tested and marketed by Sharewell Data as Spectra-Elink is a product of the US Department of Energy’s Deep Trek project, whose purpose is to develop new technology to facilitate production of deep gas resources. The system uses data fusion technology to extract very weak signals from large amounts of ambient noise by allowing the receiver to more effectively discriminate signal from noise. The receiver uses multiple input channels to fuse various data sources into a single, decodable message packet.²²

Fig. 4. Processed DAS measurements from a horizontal wellbore during a four-cluster limited-entry frac job. The colors represent acoustic energy levels across the high-frequency range (red is high, blue is low), which can be correlated with injection rates by careful selection of frequency bands.

Telemetry-enabled CT. New telemetry systems preinstalled in coiled tubing provide temperature and pressure data in real time to help optimize completion and production operations, such as milling, fracing, cleanouts and gas lift. The thin electrical or fiber-optic telemetry cable does not restrict fluid flow or pump rates, does not impede CT operations, and is typically compatible with most oilfield fluids and slurries. The cable also supports the use of production logging tools.

Baker Hughes’ (formerly BJ Services’) TeleCoil system comprises an instrumented bottomhole sonde and a preinstalled conductor cable. The system uses standard end fittings and attaches to the bottomhole assembly (BHA) with mechanical and electrical quick connectors. At surface, a data acquisition system processes and charts the downhole information. The system acquires bottomhole temperature and pressure, as well as motor differential pressure. A casing collar locator provides real-time depth to help ensure accuracy for critical completion operations (e.g., perforating and zonal isolation) and fluid placement. The system supports the use of third-party logging tools and standard ball-activated tools.²³

The ACTive PS service from Schlumberger integrates fiber-optic-enabled CT with standard wireline production logging tools. Combining fiber-optic distributed measurements with production logging can increase logging efficiency and reduce logging time in long horizontal wells.²⁴ In basic CT mode, the 2⅛-in.-diameter, acid-resistant downhole tool records internal and external pressure and temperature, and a casing collar locator provides depth. In addition to real-time telemetry, the fiber-optic cable acts as a distributed sensor that can acquire real-time temperature and pressure measurements along the length of the CT string. Two-way communication allows commands to be sent downhole while, at surface, wireless communication transmits the downhole data from the CT working reel to the DTS monitoring system. In production logging mode, a 111/16-in.-diameter BHA converts the electrical signals from the production logging tools to optical signals, which are transmitted via cable to surface and then converted back to electrical signals. In both operating modes, the BHAs are battery operated.

LOGGING-WHILE-DRILLING

Most MWD surveys use magnetic methods. However, with increased batch drilling of tightly spaced wells from platforms offshore and multiwell pads onshore, the need has increased for nonmagnetic surveys (wireline and while-drilling) that are not affected by the magnetic interference created by close proximity to steel casing in adjacent wells. Gyroscopes, in some cases combined with accelerometers, are used to calculate true north with respect to the instrument axis, which is used to calculate wellbore position, toolface, inclination and azimuth of the bit. With the addition of measured depth from wireline or a pipe tally, true vertical depth can be calculated.

Gyroscopic surveys. Gyro-while-drilling (GWD) sensors (gas-bearing gyroscopes) are located in the MWD string and provide accurate and continuous survey data. The latest microelectrical-mechanical gyroscopes are small enough to fit inside the MWD or rotary steering tool.²⁵ GWD data are transmitted to surface in real time simultaneously with the MWD magnetic data via the mud-pulse or EM telemetry unit. GWD applications include 1) drilling tophole well sections to ensure accurate multiwell planning and slot-target allocation, and to avoid wellbore collisions;^26,27 2) improved well placement off multiwell pads;²² and 3) relief well drilling.²⁸

Extreme-temperature tools. High borehole temperatures damage LWD tool electronics, affect sensor accuracy and precision, and reduce effective tool life. The current generation of LWD tools is rated to 302°F. Many service providers also offer “hostile environment” versions or options for selected services (e.g, directional, gamma ray and resistivity) that are rated to 347°F or 356°F.

However, there is high demand for geosteering services that can operate in reservoirs with even higher temperatures, such as the Haynesville shale, where bottomhole temperatures can reach 380°F. In response, service companies are developing a new generation of extreme-temperature LWD tools.^29,30 Halliburton’s ExtremeHT-200 and UltraHT-230 services include directional, gamma-ray, pressure-while-drilling and vibration sensors, packaged in 4¾-in. and 6¾-in. collar sizes and rated to 392°F and 446°F, respectively.^31,32

Acoustic tools. Weatherford’s new ShockWave LWD sonic tool is available in 6¾-in. and 8¼-in. sizes. Both sizes have an HPHT option that is rated to 329°F and 30,000 psi. Azimuthally focused receivers acquire high-quality acoustic measurements in open and cased hole. Data compression techniques allow transmission of complete semblance projections to enable accurate compressional and shear logs while drilling.³³

Schlumberger has introduced a 4¾-in. multipole (mono- and quadrupole) acoustic-array device, SonicScope 475, for use in 5⅝–8-in. borehole sizes.³⁴ The tool employs a single broadband (1–20-kHz) monopole transmitter and 48 receivers (four azimuthal receivers with 12 axial stations each at 4-in. spacing) to acquire compressional and shear wave slowness in fast formations (high-frequency monopole mode), Stoneley wave slowness (low-frequency monopole mode) and shear slowness in slow formations (quadrupole mode). The tool operates in either real-time (turbine powered) or memory mode (battery powered). Fast-formation compressional and shear slowness data are transmitted in real time; the other data are stored in the tool. A large downhole memory (1 GB) allows continuous recording of all modes for up to six days (at 10-sec. intervals) or 10 days (at 15-sec. intervals).

A design is in lab testing for an acoustic array tool that uses simultaneous generation of multipole modes to increase the quality of LWD shear wave measurements.³⁵ In contrast with conventional LWD acoustic tools, which typically generate a single pure borehole mode (e.g., dipole or quadrupole), the proposed device uses a single source placed on one side of the tool (asymmetric) with four sets of azimuthally arranged receivers to generate and identify signals from different modes. The receiver arrays isolate monopole, dipole and quadrupole modes by coherently adding and subtracting received arrivals. Dispersion analysis is performed, and the shear estimates obtained independently from dipole and quadrupole modes are averaged. Because each mode has a different sensitivity to the shear wave velocity, averaging the two reduces uncertainty in the measurement and yields a more robust estimate.

Microhole BHA. Under a US Department of Energy contract, GE Energy (formerly Sondex) developed an integrated 3⅛-in.-diameter MWD/LWD BHA using proven technologies to facilitate low-cost drilling of small-diameter shallow (less than 5,000 ft) microholes.³⁶ The BHA consists of a mud pulser, a near-bit sub with directional, annular and borehole pressure, gamma ray, weight-on-bit, shock and torque sensors, and a propagation resistivity collar with multiple depths of investigation. Wireless communication transmits data from the near-bit sub to the MWD system located above the mud motor, and mud-pulse telemetry sends data to the surface. The logging data are also stored in downhole memory. A separate gamma-ray sub can be used in place of the near-bit sub, and a memory probe stores the logging data. The BHA is rated to 302°F and 20,000 psi. Although originally intended for CT drilling, the prototypes were also tested in rotary drilling environments. A commercial 3½-in.-diameter system is currently being used in Russia.³⁷

Oil-based-mud imager. Wireline OBM imaging devices achieve the necessary coupling with the formation and high-resolution images through sensors mounted on pads attached to hydraulically activated arms that force the pads into direct contact with the borehole wall. This is an impractical solution for an LWD device since contact with the borehole wall during drilling is deliberately minimized. This is because such contact reduces rotational speed and increases the risk of differential sticking and drillstring or tool failure.

A Halliburton tool now in field testing integrates microelectrical and ultrasonic pulse-echo acoustic imaging devices to derive the benefits of each—i.e., the higher sensitivity of acoustic imaging to borehole irregularities (fractures, vugs and borehole geometry) and the higher pixel resolution or sharpness of microresistivity imaging (lithology, bedding, dip, sedimentary structures and fluid contacts).³⁸ The focused ultrasonic (350-kHz) beam has a higher SNR and provides much sharper acoustic images (e.g., detection of fracture width as small as 0.02 in.) than conventional pulse-echo tools, Fig. 5. Acoustic images based on traveltime and attenuation are provided in both WBM and OBM.

The microelectrical sensor consists of a guarded electrode mounted on the drill collar. The electrode is excited by an AC sine-wave generator, and formation coupling is achieved via displacement currents in the mud. The current flows through the formation by conduction and returns to the tool body surrounding the electrode. The sensor is designed for tool standoff up to 0.5 in. Accurate absolute-resistivity measurements require the mud conductivity to be significantly less than the expected error for the measurement, while high-quality images can be obtained at a 10/1 ratio between mud and formation resistivity.

The 1-in.-diameter, standard-resolution button electrode provides a half-power image resolution of 1.4 in. Fracture widths as small as 1/16 in. can be detected; they generate a characteristic polarization horn. Drillstring rotation and vibration can introduce motion blur in the images, Fig. 6. Microresistivity images are not available in most WBM applications.

Formation sampling while drilling. Pressure tests and fluid sampling are essential elements used in the assessment of reservoir performance. Pressure transient tests measure flowrates and pressures under a range of flowing condition to estimate radial permeability and, ultimately, to predict producibility. Formation-sampling-while-drilling (FSWD) devices represent the natural evolution of the formation-pressure-while-drilling (FPWD) tools introduced in the previous decade. The ability to acquire fluid samples and conduct reservoir analysis while drilling may reduce or eliminate the need for wireline formation testing and special pilot wells, leading to considerable savings in rig time and other well costs. Wireline and while-drilling sampling tools test relatively small volumes of formation fluids compared with drillstem testing, and the challenge of assuring sample quality (minimizing contamination) is central to tool design.

A recently developed FSWD tool from Halliburton has modular design that is similar to its wireline counterpart, the wireline pumpout formation tester; i.e., it has separate probe and sample collection sections. The probe sections, in single-probe configuration, use the same platform as the older FPWD tools, with modifications. Halliburton’s GeoTap IDS device also includes a special power section that contains a mud turbine to power the fluid pump. It has completed field tests and is in commercial service.³⁹

The tool consists of several collar sections: a probe collar at the bottom, followed by a pumping collar, the sample collar(s) and a termination collar at the top. Each sample collar has five 1-liter sample chambers that can be nitrogen compensated. Up to three chamber sections can be stacked, enabling the FSWD tool to take up to 15 samples in a single run.

Fig. 5. Comparison of acoustic image quality from the new LWD tool (right) and a conventional wireline ultrasonic acoustic imaging device in the same borehole. The LWD raw data (without image enhancement) are shown.

Fig. 6. Comparison of LWD microresistivity images obtained in two passes over the same formation (OBM, no image enhancement). Note the increase in image blur at the higher rotational speed (left).

After pumping has commenced, a real-time sensor indicates when contamination has reached the desired level (usually one to four hours after drilling ceases) and a command is sent to fill a sample chamber. The termination section contains batteries for instrument power. The FSWD tool can be placed anywhere within the LWD toolstring, generally above the formation evaluation sensor. With the cessation of drilling, commands are sent to extend the probe, establish a seal and perform a drawdown test to measure formation pressure and calculate formation fluid mobility. After the pretest, a summary containing pressures of important events is pulsed to surface and a decision is made whether to begin collecting samples. A bubblepoint measurement is made as flush pumping begins, and sensors monitor fluid temperature, pressure, resistivity and density for the contamination level. A full set of test and fluid data is stored in downhole memory. A downlink system is used to send commands to initiate the various operations (e.g., pumping and sample collection, adjustment of pump rate or pressure, and bubblepoint testing). After sample collection, commands are sent to stop the pump and retract the probe to allow resumption of drilling. A mud turbine powers the tool’s hydraulic systems, including the fluid pump. The 6¾-in. tool is designed for boreholes ranging 8⅜–10¾ in. and is rated to 302°F and 25,000 psi.³⁹

CORING

Petrophysical analyses performed on large-diameter core, especially in heterogeneous reservoirs such as carbonates and gas shales, provide more representative reservoir data, including porosity, hydrocarbon saturation, permeability, mineralogy, kerogen content and vitrinite reflectance. In response to operator requests for larger sidewall cores, service companies have developed larger rotary coring devices that can deliver sidewall cores that are 1½ in. in diameter by 2–3 in. long, two to three times the volume of current 1-in. rotary coring devices; i.e., the cores are closer in size to standard laboratory core plugs.

Baker Hughes’ MaxCOR service delivers up to 60 core samples of 1.5-in. width and 2-in. length per run, and is rated to 400°F and 25,000 psi.⁴⁰ Halliburton is testing a similar device.

SURFACE LOGGING

Weatherford’s GC-Tracer surface gas detector is a compact, closed-flow system (no gas trap) that uses a membrane-based technique to provide real-time quantitative mud-gas analysis in any drilling fluid. A probe inserted directly into the drilling fluid is used to extract hydrocarbons as well as non-hydrocarbon gases such as CO₂ and N₂. The probe houses a semipermeable membrane that extracts gases as a result of the difference in partial pressure across the membrane. This difference allows each gas component, whether free or dissolved, to permeate across the membrane. The membrane is continuously swept with carrier gas, transporting the components 3 m to the gas detector while maintaining the pressure differential. Gas analysis includes C1 to C10 hydrocarbons and aromatics (benzene and toluene). The time required for hydrocarbon analysis ranges from 55 sec. (C1 to C8) to 135 sec. (C1 to C10). The system, which can be integrated with most rig systems and third-party mud logging services, is monitored onsite by a system analyst.⁴¹

An integrated tool package for automating the analysis of drilling fluid and cuttings parameters has been designed and yard tested.⁴² Real-time automated analysis increases the objectivity of measurements and provides a more efficient method for fluid and solids control. It can also improve response time to unanticipated changes in drilling conditions or borehole geology. The automatic drilling fluid analysis includes viscosity, density, fluid loss, electric stability measurements, pH, H2S content, particle content and particle size distribution. Cuttings are washed and dried before undergoing shape analysis by an image analyzer to determine whether the particles are cuttings or cavings. The mineralogy of the cuttings is automatically determined using a Raman spectroscope, making it possible to continuously evaluate the formations being drilled. A device for monitoring the oil/water ratio of an OBM can also be configured for automatic measurements. Additional refinements are needed before the tool package is ready for rig installation.

LITERATURE CITED
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3 Expro International, 2010, website, http://exprogroup.com/

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