Recent developments in well logging and formation evaluation

STEPHEN PRENSKY, Consultant, Silver Spring, Maryland

Baker Hughes technicians prepare to deploy the MagTrak logging-while-drilling magnetic resonance service to acquire real-time data to locate and identify producible fluids.

The purpose of this article, which is based 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 currently available as commercial services, while others may still be in the development or test phases. Readers are encouraged to refer to the cited references for additional details.

WIRELINE LOGGING

Ultraslim logging tools. Service companies, including Halliburton, Weatherford and Schlumberger, have developed quad-combo systems capable of log evaluation in small-diameter, high-angle and horizontal borehole sections in new wells, and re-entry into existing wells, and those with complex geometries (high dogleg severity). These new systems consist of array resistivity, neutron-density, lithodensity and array-acoustic tools that provide similar or improved measurement quality of the larger-diameter tools but their outer diameters, ranging from 2 to 2½ in., allow logging boreholes as small as 3 or 3⅛-in. diameter. The most recent systems are flexible—they can be deployed as a suite or individually on wireline or memory mode, using a variety of conveyance methods, including through drillpipe below the bit, coiled-tubing, slickline and, in some cases, in wireless mode. The array-sonic tools typically employ multiple (two) transmitters and receivers that provide high-quality compressional and shear slowness, as well as a cement-bond log (CBL) (amplitude) with variable-density log (VDL) display in cased hole.^1-3 Weatherford also offers formation-pressure tester, crossed-dipole sonic, and microresistivity imaging tools capable of logging in these small-diameter holes.²

High-definition imaging in nonconductive mud. Schlumberger has developed an improved imaging tool that offers greater reliability and improved performance in water-based mud (WBM), and high-definition images within an expanded operating window in nonconductive oil-based mud (OBM). The FMI-HD tool employs redesigned tool electronics and signal-processing methods in the standard FMI sonde to achieve improved signal-to-noise and faster analog-to-digital conversion. The higher number of sensors on the existing FMI sonde, compared to the number of sensors used on existing OBM imaging (192 vs. 40 to 48), results in increased tool resolution and borehole coverage. The higher image definition and clarity of formation textural features (Fig. 1) in most borehole conditions increases confidence in image interpretation techniques, such as fracture analysis, sedimentological analysis, and facies classification and rock typing. Although the operational range in OBM has been expanded, ambiguity in differentiating fluid vs. mineral-filled features, e.g., fractures and secondary-porosity, may still occur and require complementary data, such as an acoustic image, to confirm the interpretation. The ideal operating conditions are high formation resistivity, low oil-water ratio and borehole size near 8 in.⁴

Fig. 1. Borehole images from a standard FMI tool, recorded in WBM in a laminated interval of the 6 in. borehole section (left), compared with images from the new high-definition tool acquired in nonconductive mud in the 8 in. borehole section of the same well (right).4

Backscattered ionization. A joint industry project between VisuRay, BP, Shell and Statoil has developed a prototype of a wireline cased-hole borehole imaging system, that uses backscattered X-ray ionizing radiation. It has successfully completed feasibility trials, Fig. 2. The concept is that an ionizing radiation system, unlike existing ultrasonic and video imaging devices, is not affected by heavy mud and fluctuations in temperature and density in flowing wells (ultrasonic imaging) or opaque borehole fluids (downhole video). Potential applications include intervention operations in static and flowing wells in all mud types, without requiring displacement of opaque borehole fluids. In addition, backscattered radiation exhibits an energy fingerprint of the materials from which it scattered that can be detected and analyzed at source to produce spectroscopic imagery, which can improve correlation with the visual imagery. Objects and details in the borehole were easily identified under both static flowing conditions. Potential applications for this device include evaluation of well integrity and perforations, and locating and orienting lost or stuck items and tubulars in the borehole.⁵

Fig. 2. Configuration of the prototype backscattered ionization imaging tool, illustrating the relative position and size of each subassembly.  Because energy supplied to the X-ray source generates heat, the tool design includes a heat-exchange system.5

Production logging and sand dectection. Managing sand production during a well’s productive life is required for minimizing operating costs and optimizing production. The ability of operators to detect and identify the entry depth of sand production is essential for determining the most appropriate and cost-effective remedial action, e.g., installing sand screens or applying chemical treatments. Ultrasonic sand detectors, that can identify and quantify sand production, have been installed at the wellhead and also in intelligent subsea completions for some time. Two different wireline logging tools using ultrasonic techniques have been developed to detect sand production and for inspecting the integrity of completion equipment.

An experimental design sand-detection tool developed by Carigali Hess Operating Company has undergone field trials.6 This tool can identify the exact entry point(s) of sand along the producing interval by detecting and measuring the ultrasonic acoustic energy generated by the impact of sand grains striking the tool, perpendicular to the wellbore. Sand moving parallel to the wellbore is not detected. The tool operates in the MHz range and produces three output curves measuring the level of ultrasound energy in the vicinity of the sensor in specific frequency windows: The A curve, which has the broadest frequency range, is a measure of the general ultrasound energy caused by turbulent flow and other factors; the B and C curves have narrower frequency ranges that represent the high frequencies generated by crystal lattice oscillation due to grain impact. High sand production is normally indicated by responses on both the A and C curves. A high signal-to-background noise ratio allows clear, unambiguous detection of sand entry into the wellbore. The tool, which is 2 in. in diameter and 21 ft long, is run in combination with a suite of production logging tools that has a minimum configuration of temperature, pressure, gamma ray and spinner flowmeter. To account for the episodic nature of sand production, two or more logging passes (both up and down) are made across each zone of interest with the well shut in. A stationary log may be run at any depth, where high sand production is detected.

Seawell has developed a prototype e-line device, also in the testing stage, which uses phased-array ultrasonic technology to generate high-resolution 3D images of the borehole and downhole equipment in all mud types. This tool can be used to diagnose production problems, including the status of 1) tubulars (e.g., corrosion, scale, and collapse); 2) borehole (e.g., fractures and perforations); and 3) integrity of downhole equipment (e.g., sand screens, sliding sleeves and straddle packers). An array of approximately 300 ultrasonic transmitting elements is stimulated in sequence to produce a highly focused beam of ultrasonic energy by superposition techniques. The focused beam is sequentially indexed around the array to capture a scan of the surrounding environment. This technique permits the focal length of the ultrasonic beam to be varied, which in turn, allows variation in the depth of investigation. The data acquired from each scan are used to create a layered shell, such that the 3D geometry of the scanned space can be recreated, allowing the user to view the information as a whole or to view each layer individually. The system generates 128 scans of varying focal length at a frequency of six times a second, resulting in the capture of approximately 250,000 data points per second. In field tests, damage to sand-control screens was imaged successfully.⁷

Gravel-pack imaging tool. Wood Group Logging Services has developed the prototype of a multi-detector, wireline, gravel-pack imaging device that is undergoing field trials.⁸ The 2.5-in. diameter tool uses gamma ray scattering to investigate pack integrity close to the screen, simultaneously providing azimuthal and longitudinal information. The tool consists of a conically focused, cesium-137 source and six detectors that simultaneously investigate six azimuthal segments through a short-spaced, single, Compton-scattered density measurement. Azimuthal data are oriented to the high side of the borehole. The azimuthal data are used to generate the gravel pack images. The source-detector spacing and collimation aperture can be adjusted to optimize the void-space sensitivity for different gravel-pack screens. This tool has a 2 in. region of investigation and is sensitive to voids in the gravel pack as small as 1 in. along the axis of the borehole and less than 0.5 in. transverse direction to the borehole. The tool response to material behind casing is insignificant, and tool readings are immune to variations in cement thickness and formation density. This imaging tool is run centralized on a monoconductor wireline or in memory mode, in combination with collar locator and gamma ray tools. The tool can operate in all types of borehole fluids, and logging speed is 10 ft/min in high-resolution mode, or faster in quicklook/reconnaissance mode.

LWD/MWD

Wellbore position accuracy. The azimuth of the bottomhole assembly is inferred by comparing the magnetic field measured while drilling with a geomagnetic reference model. Several recent studies have highlighted issues related to the accuracy of different MWD surveying methods.

Multistation analysis (MSA) is a technique widely used in MWD directional surveying to provide additional quality control and to correct for systematic errors. A set of fundamental requirements for multistation analysis of MWD has been developed by an industry working group. These requirements 1) make the analysis largely user- independent; and 2) provide consistent, valid outcomes, regardless of the estimation technique being used. The requirements, which consist of basic mathematical measures that describe the well geometry and noise level in the surveys, consider several factors, such as accuracy of the accelerometer and magnetometer sensor measurements, accuracy of the Earth’s gravity and the geomagnetic reference field values, number of survey stations, wellbore orientation relative to the gravity and geomagnetic field vectors, and variation of the wellbore azimuth and inclination.⁹

North-seeking gyroscopic surveys (NGS) are the most accurate means for determining wellbore position in most locations and trajectories. It is often necessary to run NSG surveys in cased holes to achieve maximum accuracy. Every magnetic or gyroscopic survey tool has an associated degree of uncertainty in the accuracy of the acquired data. This error is cumulative and increases with depth as a well is drilled. In high-angle wells, the area of uncertainty may grow to exceed the dimensions of the geological target, thus increasing the drilling risks and potential costs of missing the target. A recent study conducted by Gyrodata shows that simulation and field data studies of effects commonly not accounted for, such as the fact that the geomagnetic field varies with depth, indicate an unrealistically high level of confidence in in-field referencing (IFR) techniques—the uncertainty in real wellbore position, based on in-field referencing (IFR) techniques, may be underestimated by 50% or more. Existing error models (SPE WPTS; see 2009 article) should be replaced with new models that incorporate 1) the horizontal east-west singularity associated with combined IFR-multistation correction surveys; and 2) uncertainty generated by variation in geomagnetic depth.¹⁰

Advanced magnetic-survey processing offers a less-expensive, cost-effective approach to reducing uncertainty and improving magnetic surveying accuracy, and provides an alternative to gyroscopic surveying. New geomagnetic referencing techniques provided by Schlumberger and Fugro Gravity & Magnetic Services use recent improvements in crustal magnetic field modeling to correct readings from measurement-while-drilling (MWD) magnetometer and accelerometer tools in the drillstring. These techniques can integrate real-time data on local magnetic variations in the crustal modeling process, when necessary at high latitudes, and drillstring interference management, and enable MWD surveys to achieve an accuracy approaching that of a gyroscopic survey at a lower cost and in near real time.^11,12

The U.S. National Geophysical Data Center has developed a new high-definition geomagnetic model that achieves more than an order-of-magnitude improvement over previous models. These models are updated regularly using the latest satellite, airborne and marine measurements of the Earth's magnetic field. The new model now accounts for crustal magnetic anomalies, which constitute a significant source of error in directional drilling. The high level of local detail represented in the new model significantly improves the accuracy of the reference field, thereby enhancing the reliability of the well azimuth determination. This, in turn, will lead to improved geosteering, well placement, and help prevent and mitigate wellbore collisions.¹³

Nuclear logging. Two recent reports, one prepared by the Pacific Northwest National Laboratory for the U.S. Department of Energy (DOE), review the issues involved with replacing the sealed chemical radiation sources currently used in well logging, e.g., americium-beryllium (AmBe), californium-252, cobalt-60 and cesium-137, with other less radioactive or nonradioactive methods (see 2008 article). According to the report, major issues of concern to the logging industry are 1) cost and reliability of nonchemical pulsed-neutron generators (PNG); and 2) difficulty in correlating the neutron data acquired with low-energy AmBe or californium sources with those acquired using a high-energy, directional electronic PNG. An equivalency or calibration between the response characteristics of old and new tools is required to assure the industry that it can continue to rely on the extensive database of existing nuclear logs for data correlation and interpretation.^14,15

With an eye to the future and the ultimate replacement of AmBe chemical sources, service companies are developing and testing alternative wireline and LWD neutron- and density-logging technologies. Baker Hughes has developed and tested an experimental tool that uses a 111/16-in. pulsed-neutron generator, and lithium-6 detectors to test the response characteristics of this alternate source and detectors.¹⁶ A shortage of helium, which is used in the most common type of neutron detectors, provided the motivation behind testing the lithium detectors. Test results showed good correlation with data from an older neutron log processed with two different methodologies, and also highlighted areas requiring additional investigation and improvement.

Schlumberger is testing an LWD tool that uses a ruggedized PNG and dual-detectors to acquire a non-chemical compensated formation density measurement. In contrast with the gamma-gamma measurement made by conventional density tools, the PNG in the experimental tool results in a neutron-gamma bulk density measurement.¹⁷

RESISTIVITY LOGGING

Ultra-deep-reading directional device. The current generation of deep-reading geosteering tools have radial depths of investigation between 5 and 7 m.  Schlumberger has developed a prototype, and has conducted field tests, of a very-deep-reading, azimuthally-sensitive electromagnetic LWD tool that shows a radial depth of investigation from the borehole that exceeds 30 m, and the ability to identify multiple layers of resistivity, corresponding to bed or fluid boundaries, over a total vertical depth of 60 m at horizontal distances of up 450 m, Fig. 3.¹⁸  The tool design is based on an earlier, deep-reading tool¹⁹ with the addition of directional sensitivity. Dip data derived from inversion of the resistivity data are in good agreement with dip derived from gamma-ray and density images.

Fig. 3. Display of real-time inversion of new deep-reading EM measurements through a sandstone reservoir (RESB), showing the mapping of the RESB top. The conductive zone is attributed to the presence of injection water.18

Slimhole azimuthal laterolog system. Schlumberger's new 4 3/4-in. azimuthal laterolog tool provides both resistivity measurements and high-resolution borehole images at multiple depths of investigation.^21,22 The device is designed for high-resolution borehole imaging and formation evaluation in slim horizontal boreholes (5⅞ in. to 6½ in. using WBM). The laterolog measurements use five toroidal antennas (transmitter/receivers) and a pair of opposing monitored button electrodes, Fig. 4. An orientation system determines the azimuthal position of the tool during rotation. The resistivity measurements include 1) four calibrated azimuthal button resistivities with increasing depths of investigation, but with the same axial resolution; 2) two non-azimuthal (toroidal) resistivities; and 3) at-the-bit resistivity measurement that can detect fluid and lithology changes to enable an immediate response to unexpected changes. Button and toroidal resistivity are focused to minimize shoulder-bed effects.

Fig. 4. Configuration of a new azimuthal laterolog tool. The device uses toroidal transmitters, two opposing monitored buttons, and an electrode array on a removable stabilizer.20

The resistivity-based  borehole images are acquired in 56 azimuthal sectors while rotating, providing full borehole coverage, regardless of  rotational speed or “stick and slip” conditions. A dedicated data compression algorithm allows real-time transmission of quality images, permitting their use in well placement, fracture evaluation, and structural analysis. The tool also provides azimuthal gamma ray and near-bit inclination. Changing the monitored electrode current path allows a direct measurement of downhole mud resistivity.

An advanced  high-resolution imager consisting of a removable, sleeve-mounted electrode array of multiple button electrodes , capable of delivering images comparable to those acquired during wireline operations is currently under development. Image resolution is a function of the size of the button electrodes.

Acoustic crossed-dipole azimuthal acoustic tool. Halliburton has introduced a crossed-dipole, azimuthal imaging tool capable of measuring anisotropy in the same manner as wireline acoustic tools. The tool has four azimuthal transmitters that can fire either positive or negative waves, which allow operation in monopole, dipole, crossed-dipole or quadrupole mode. Multiple modes are typically run at every depth and the data from the multiple firings are combined via processing to achieve the best results. The source frequency is programmable at the surface and downhole, via a downlink. There are four azimuthally-spaced receiver arrays with six receivers in each array. Acoustic calipers integrated into each of the four receiver arrays provide accurate measurement of borehole size, shape and tool position. The tool can be run in any position in the tool string and centralization is not essential—the effects of eccentering can be accounted for using the tool position provided by the calipers. Image data can be acquired in 1-, 2-, 4-, 8- or 16-sector resolution, where the real-time data might be compressed in 4-sector resolution and memory data would be 16-sector resolution. Anisotropy analysis is performed at the surface, using the high-resolution 16-sector data.²² 

Fluid sampling and analysis tools. The objectives of sampling-while-drilling technology are 1) to retrieve high-quality formation fluid samples at low-contamination levels prior to significant drilling-related fluid invasion; 2) reduce the nonproductive rig time associated with wireline formation fluid sampling; 3) ensure sample acquisition while reducing the risk of sticking a wireline formation tester (WFT); and 4) the ability to acquire in-situ fluid samples in high-angle and horizontal wells. Less contamination means reduced pumpout times, resulting in less time per sampling station. Fluid and pressure data available in real time can assist in geosteering, pore pressure evaluation and for monitoring annuluar pressure to optimize the drilling and casing program. Sampling-while-drilling tools represent an evolutionary advancement to the preceding generation of pressure-while-drilling devices, providing additional functionality while retaining the functionality of those tools, and can be run as part of a conventional LWD toolstring. LWD fluid sampling tools have similar features to modern wireline pumpout testing tools: a modular design that includes a power section, a fluid-sampling probe, fluid pumpout, fluid analysis/identification and sample storage. The fluid analysis unit uses sophisticated measurement techniques to measure fluid properties (e.g., temperature, resistivity, optical analysis, acoustic velocity, density and viscosity) to monitor fluid cleanup, to ensure acquisition of uncontaminated samples and for fluid identification. Probe size can be changed to cover different formation mobilities. The sealing element—a pad or packer—varies by service provider. Downlinks are used to send operational commands downhole to the tool and mud-pulse telemetry sends a data subset containing the critical information needed for real-time decision-making. The full data set is stored in downhole memory. In addition to the Halliburton tool discussed in the 2011 article, prototypes of Baker Hughes and Schlumberger LWD sampling devices are in the testing phase of development.

The Baker Hughes sampling tool uses a pad-type sealing element for the probe and is capable of acquiring up to 16 fluid samples (four 780-cm3 sample chambers per module) per tool run. Sample tanks use a cobalt alloy to avoid fluid alteration and the combination of nitrogen buffering and the tank compressibility system prevents samples from crossing both the bubblepoint and the asphaltene and wax deposition line. The tool is designed for boreholes ranging in size from 8¾ to 9⅞ in., but it can be run in boreholes up to 11¾ in. with a special setup, and is rated to 300°F and 25,000 psi.²³

Schlumberger's prototype tool uses three 450-cm3 sample bottles per module and allows multiple sample modules per run. A flexible pump configuration permits the operating range to be customized to meet specific formation characteristics. When the tool is on depth location and drilling is stopped, a downlink system sends operational commands downhole to the tool to perform a pretest sequence to begin pumping directly. Several improvements maximize the limited mud-pulse telemetry bandwidth: some of the advanced processing previously done at surface is now performed downhole; telemetry frames have been designed to maximize the information content transmitted to surface to allow informed decisions regarding the sampling process. The tool is designed for borehole sizes between 8.5 in. and 10.5 in., and is rated to 300°F and 20,000 psi.²⁴

Badger Explorer. This unmanned (remote) tool drills and buries itself into the subsurface while carrying a set of sensors designed to provide high-quality, continuous recording and transmission of conventional LWD data as well as direct in-situ measurements of formation and fluid properties. This technology (see 2009 article) completed prototype development in 2011 and has advanced to the pre-commercial phase. The primary objective of this drilling technology, which is being developed in partnership with major operating companies, is to conduct subsurface exploration in challenging environments (e.g., deepwater) and to verify the presence of oil and gas without requiring a conventional drilling rig. The first commercial pilot demonstration is planned for the Canadian oil sands, in 2012−2014.²⁵ 

PERMANENT SENSORS

A variety of fiber-optic sensors is being installed permanently in producing wells to monitor completion activities, as well as sand and fluid production. These in-place sensors, used for selective zones or full-well coverage, provide real-time data needed to make completion and intervention decisions to reduce operating costs and optimize production. Acoustic (DAS) sensors are being used to monitor well completion operations, such as hydraulic fracturing (see 2011 article),^26,27 production flow profiling,²⁸ and sand production (distributed vibration).²⁹

Schlumberger has developed a hybrid system consisting of distributed temperature sensors (DTS) and a quartz pressure gauge, to monitor gas-lift performance and minimize the need for production logs, prevent deferred production losses and, thereby, decrease the need for well interventions. This system can be enabled with both single-mode and multimode fiber. This capability  enables monitoring of  temperature, pressure and DAS, all from a single-cable.³⁰ 

Fig. 5. Interior view of the Fiber Express Tube used to monitor temperature and strain at the sand face.33

Shell and Baker Hughes have developed another new fiber-optic system that is undergoing field trials. This system uses a special sleeve (Fiber Express Tube) that fits over conventional downhole equipment (e.g., gravel-pack sand screens) to deploy the sensors directly at the sand face. The fiber-optic sensors are contained in a small-diameter capillary tube that affixes to the inside diameter in a helical wrap (Fig. 5) and monitors strain and temperature at 1-cm intervals. These data are used to infer flow and detect subsidence or compaction of the sand face before the well is compromised, thereby allowing time to plan and execute actions to mitigate the problem. Two 6-channel wet connectors also allow connections to conventional pressure-temperature gauges and DTS fiber-optic systems.^31-33 

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