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The downhole logging program during Expedition 311 was specifically designed to assess the presence and concentration of gas hydrates at the Cascadia accretionary prism. Several LWD/MWD and wireline logging tools were deployed, as described below. Not all tool strings were run in each hole. Refer to the individual site chapters for details of the tool strings deployed at each site.
Downhole logging aboard the JOIDES Resolution is provided by the Lamont-Doherty Earth Observatory Borehole Research Group (LDEO-BRG) in conjunction with Leicester University Borehole Research, the Laboratoire de Mesures en Forages Montpellier, University of Aachen, University of Tokyo, Schlumberger Reservoir Evaluation Services, and Schlumberger Drilling and Measurements.
During Expedition 311, six LWD/MWD tools were deployed at the five sites cored and drilled on the Cascadia margin. These tools were provided by Schlumberger Drilling and Measurements Services under contract with the LDEO-BRG.
LWD tools measure in situ formation properties with instruments that are located in the drill collars immediately above the drill bit. MWD tools are also located in the drill collars and measure downhole drilling parameters (weight on bit, torque, etc.). The difference between LWD and MWD tools is that LWD data are recorded into downhole computer memory and retrieved when the tools reach the surface, whereas MWD data are transmitted through the drilling fluid within the drill pipe by means of a modulated pressure wave, or "mud pulsing," and monitored in real time (see below). MWD tools enable both LWD and MWD data to be transmitted uphole when the tools are deployed in conjunction. The term LWD/MWD is used throughout this volume to cover both LWD- and MWD-type measurements.
The Schlumberger LWD/MWD tools used during Expedition 311 include the GeoVISION resistivity (GVR) tool (formerly known as the Resistivity-at-the-Bit [RAB] tool), the EcoScope tool, the SonicVISION tool, the TeleScope MWD tool, the ProVISION nuclear magnetic resonance (NMR) tool, and the ADNVISION azimuthal density neutron tool. This was the first time the EcoScope, SonicVISION, and TeleScope tools were used during an ODP leg or IODP expedition. Figure F26 shows the configuration of the LWD/MWD BHA, and Table T3 lists the set of measurements recorded. LWD/MWD logs complement wireline logs in an integrated interpretation of gas hydrate saturations. LWD/MWD measurements are made shortly after the hole is drilled and before the adverse effects of continued drilling or coring operations. The invasion of drilling fluid into the borehole wall is reduced relative to wireline logging because of the shorter time elapsed between drilling and taking measurements.
The LWD/MWD equipment is powered by batteries or mud motors and uses erasable/programmable read-only memory chips to store logging data until they are downloaded; a limited amount of data is sent to the surface in real time by the MWD tool. The LWD/MWD tools take measurements at evenly spaced time intervals and are synchronized with a system on the drilling rig that monitors time and drilling depth. After drilling, the LWD/MWD tools are retrieved and the data downloaded from each tool. Synchronization of the uphole and downhole clocks allows merging of the time-depth data (from the surface system) and the downhole time-measurement data (from the tools) into depth-measurement data files. The resulting depth-measurement data are transferred to the processing systems in the downhole measurements laboratory (DHML) for reduction and interpretation. For a detailed description of the depth tracking systems, see the Leg 204 Initial Reports "Explanatory Notes" chapter (Shipboard Scientific Party, 2003b).
LWD/MWD logs were acquired in the first hole drilled at each site to plan coring and pressure coring operations in subsequent holes. As these holes were drilled without coring, the LWD/MWD data had to be monitored to detect gas entering the borehole. This new procedure supersedes the old standard of using gas ratio measurements for hydrocarbon safety analysis. Results of previous gas hydrate drilling programs, such as ODP Legs 146 (Westbrook, Carson, Musgrave, et al., 1994), 164 (Paull, Matsumoto, Wallace, et al., 1996), and 204 (Tréhu, Bohrmann, Rack, Torres, et al., 2003), and, more recently, the Chevron/Texaco Gulf of Mexico Gas Hydrate JIP Drilling Program, have shown that gas hydrate–bearing sections do not represent a significant threat to drilling operations and that as long as the hole is advanced at relatively normal drilling rates with mud temperatures near that of the deeper water column there is no significant gas flow from gas hydrate–bearing formations. The main concern of the LWD/MWD monitoring program was the recognition of free-gas zones within the drilled interval that below the GHSZ; these free-gas zones have the potential to flow.
LWD/MWD measurements sensitive to the presence of free gas include borehole fluid pressure (decrease because of less dense fluids), compressional velocity of the borehole fluid and of the formation (strong decrease with free gas), coherence of measured sonic waveforms (decrease with free gas), electrical resistivity (increase with free gas), and neutron and density logs (decrease of density and neutron porosity; e.g., neutron/density crossover). In addition, the gamma ray log indicates whether the changes in the logs are caused by changes in the lithology rather than in the pore fluid, the NMR porosity gives a reference porosity to calibrate the neutron/density crossover, and the caliper measurement can be used to assess the reliability of the measurements and the possible influence of material falling in the borehole.
The primary measurement used in gas monitoring was the annular pressure while drilling (APWD) measured by the EcoScope tool in the borehole annulus (the space between the drill string and the borehole wall). On the basis of a simple calculation of the effect of free gas on the borehole fluid density, it was determined that a pressure decrease of >100 psi (pounds per square inch) from the general trend of fluid pressure would indicate that a significant amount of gas had been released into the drilling fluid. For example, a pressure decrease of 100 psi corresponds to a 25% gas saturation in a borehole drilled to 300 mbsf. It was also decided to monitor sudden pressure increases of >100 psi, which have been reported as precursors to gas flow into the annulus (Aldred et al., 1998).
We also set the SonicVISION tool to process the borehole fluid velocity in real time because previous drilling experience in North Sea wells had shown that the presence of gas caused the coherence of the sonic waveforms to decrease and the inferred value of fluid velocity to become erratic. In practice, we monitored the coherence of the waveforms used to infer the fluid velocity: a low coherence may indicate the presence of gas. Although the pressure and acoustic sensors are located some distance above the drilling bit (6.46 and 17.7 m, respectively) (Fig. F26), gas moves rapidly upward in the annulus from the point of entry at the bit and would be detected quickly.
The monitoring procedure followed the decision tree shown in Figure F27, which is described below.
A pressure decrease caused by gas flow into the borehole may be preceded by a pressure increase as the result of the acceleration of fluids in the annulus (Aldred et al., 1998). If an increase >100 psi is observed, drilling will cease as a precautionary measure and relevant personnel will be notified. Seawater will be circulated in the hole and the APWD response will be monitored to obtain the baseline pressure. Because no overpressure water flow events are expected or likely in this environment, such a pressure increase could be the result of the aforementioned precursor or drilling-induced pressure increases. A drilling-induced pressure increase will be resolved by cleaning the hole, whereas the precursor event will be followed by a pressure decrease, leading to appropriate response as dictated by the procedure above.
The GeoVISION tool (RAB or GVR6) provides resistivity measurements of the formation and electrical images of the borehole wall, similar to the wireline Formation MicroScanner (FMS) but with complete coverage of the borehole walls and lower vertical and horizontal resolution. In addition, the RAB tool contains a scintillation counter that provides a total gamma ray measurement.
The tool is located directly above the drill bit and uses two transmitter coils and a number of electrodes to obtain several measurements of resistivity:
For quality control reasons, the minimum data recording density is one measurement per 6 inch (15.2 cm) interval; hence, a balance must be determined between the ROP and the sampling rate. This relationship depends on the recording rate, the number of data channels to record, and the memory capacity (46 MB) of the tool. During the Expedition 311 LWD program, we used a data acquisition sampling rate of 5 s for high-resolution resistivity images. The maximum ROP allowed to produce one sample per 6 in interval is given by ROPmax (m/h) = 548/sample rate. This relationship gives 110 m/h maximum ROP for the GeoVISION tool. During Expedition 311, the target ROP was 20–50 m/h, at most ~50% of the maximum allowable ROP for the GeoVISION tool. These reduced rates improved the vertical resolution of the resistivity images to 5–10 cm per rotation. Under this configuration the GeoVISION tool had enough memory to record as much as 6 days of data, which was sufficient to complete the Expedition 311 LWD operations.
The EcoScope tool integrates several formation evaluation, well placement, and drilling optimization measurements in a single collar. The EcoScope tool provides a suite of resistivity, thermal neutron porosity, and azimuthal gamma ray and density measurements. The dual-frequency propagation resistivity array (2 MHz and 400 kHz) makes 10 phase and 10 attenuation measurements at several depths of investigation, providing invasion profiling and formation resistivity. For neutron generation, the EcoScope uses a pulsed neutron generator, which eliminates the need for a chemical source; it still uses a 137Cs gamma ray source for density logging. In addition, the EcoScope provides the first commercial LWD measurements of elemental capture spectroscopy, neutron gamma density, photoelectric factor (PEF), and neutron capture cross-section, or sigma. Drilling optimization measurements include APWD, caliper, and shock detection. We used the APWD measurement to monitor gas in the annulus in real time.
The SonicVISION tool records monopole acoustic waveforms in downhole memory and transmits uphole, in real time, acoustic slowness obtained by processing the recorded waveforms. The principle of the SonicVISION tool is similar to that of wireline array sonic tools (Schlumberger, 1989). The monopole source produces a ~13 kHz pulse that travels into the formation and refracts back into the borehole. Sonic waveforms are recorded at four monopole receivers spaced at 10, 10.67, 11.33, and 12 ft (3.05, 3.25, 3.45, and 3.65 m) above the source.
Sonic measurements made while drilling are affected by drilling noise. Because the upward propagation of energy in the formation is synchronized with the transmitter firing and any residual drilling noise is not, averaging the waveforms from various consecutive firings increases the relative amplitude of coherent signals. A stack size of approximately eight waveforms is deemed appropriate for these conditions. The SonicVISION tool must also be kept centralized in the borehole in order to maximize the strength of the formation signal. In large holes and slow sediments, both the formation itself and asymmetry of the annular space in the hole will attenuate the signal.
To monitor for gas, the SonicVISION tool was configured to process and transmit in real time uphole wave arrivals corresponding to velocity values (1300–1600 m/s) appropriate for the drilling fluid. The SonicVISION tool is configured so that waveform data are stored at 8 s intervals, allowing for 83 h of drilling before the downhole memory is filled. This was sufficient to reach the target depth at each of the Expedition 311 sites at a typical ROP of 25–35 m/h. The maximum ROP allowable to achieve one sample per 6 inch interval is estimated as ROPmax = 1800/8 = 225 ft/h (~68 m/h). SonicVISION waveform data were downloaded from the tool, converted to depth, and processed to estimate fluid wave slowness and waveform coherence using the Schlumberger Drilling and Measurements Integrated Drilling Evaluation and Logging system on the JOIDES Resolution.
The TeleScope tool transmits MWD data uphole by means of a pressure wave through the fluid in the drill pipe. In practice, the TeleScope tool generates a continuous wave within the drilling fluid and changes the phase of this signal (frequency modulation) to transmit relevant bit words representing information from various sensors. Two pressure sensors attached to the standpipe (one near the top and the second near the bottom) on the rig floor measured the pressure wave in the drilling fluid when information was transmitted up the drill pipe by the MWD tool. With the MWD mud pulsing systems, transmission rates can reach 12 bits/s, depending primarily on water depth and mud density. In contrast to real-time data, the downhole memory in the LWD tools records data at a minimum rate of one sample per 15 cm.
The basic technology behind the ProVISION NMR tool is similar to modern wireline NMR technology, based on measurement of the relaxation time of the magnetically induced precession of polarized protons. A combination of bar magnets and directional antennas focuses a pulsed, polarizing field into the formation. The ProVISION tool measures the relaxation time of polarized hydrogen nuclei in the formation, which provides information on the formation porosity. By exploiting the nature of the chemical bonds within pore fluids, for hydrogen in particular, the ProVISION tool can provide estimates of the total porosity and bound fluid volume, and thus be useful to determine whether water, gas, or gas hydrates are present in the formation.
During Expedition 311, the ProVISION tool transmitted only limited data to the surface through MWD and acquired additional data in memory. The relaxation time spectra were recorded downhole, and total porosity estimates were transmitted to the surface in real time. These spectra were stacked during postprocessing to improve the measurement precision. The signal probes a 14 inch cylindrical volume around the borehole, and, for an 8 inch bit size, the depth of investigation of the measurement is ~7 cm into the formation. When the tool is static, the vertical resolution is 6 inch (~15 cm); when the tool moves, vertical resolution is decreased because of the need to maintain accuracy by vertical stacking of relaxation time spectra. For example, at a logging speed of 30 m/h, the vertical resolution is 1.2 m. Lateral tool motion may reduce data quality in some circumstances. Therefore, data from accelerometers and magnetometers contained in the downhole tool are used to evaluate data quality and determine the maximum relaxation times that can be resolved. Unfortunately, postcruise processing indicated that a tool malfunction had prevented the recording of any reliable data from the ProVISION tool during the expedition.
The ADNVISION tool operation is similar in principle to the azimuthal density neutron tool used during previous ODP legs (e.g., Leg 196; Mikada, Becker, Moore, Klaus, et al., 2002). The density section of the tool uses a 1.7 Ci 137Cs gamma ray source in conjunction with two gain-stabilized scintillation detectors to provide a borehole-compensated density measurement. The two detectors are located 5 and 12 inch (12.7 and 30.48 cm) below the source and compensate for the effect of fluid in the borehole. The number of Compton scattering collisions (change in gamma ray energy by interaction with the formation electrons) is related to the formation density. Returns of low-energy gamma rays are converted to a PEF value, measured in barns per electron. The PEF value depends on electron density and hence responds to bulk density and lithology. It is particularly sensitive to low-density, high-porosity zones.
The density source and detectors are positioned behind holes in the fin of a full gauge clamp-on stabilizer. This geometry forces the sensors against the borehole wall, thereby reducing the effects of borehole irregularities and drilling. The vertical resolution of the density and PEF measurements is ~15 and 5 cm, respectively. For measurement of tool standoff and estimated borehole size, a 670 kHz ultrasonic caliper is available on the ADNVISION tool. The ultrasonic sensor is aligned with and located just below the density detectors. In this position the sensor can also be used as a quality control for the density measurements. Neutron porosity measurements are obtained using fast neutrons emitted from a 10 Ci americium oxide-beryllium (AmBe) source. Hydrogen quantities in the formation largely control the rate at which the neutrons slow down to epithermal and thermal energies. The energy of the detected neutrons has an epithermal component because much of the incoming thermal neutron flux is absorbed as it passes through the 1 inch drill collar. Neutrons are detected in near- and far-spacing detector banks, located 12 and 24 inch (30.48 and 60.96 cm), respectively, above the source. The vertical resolution of the tool under optimum conditions is ~34 cm. The neutron logs are affected to some extent by the lithology of the matrix rock because the neutron porosity unit is calibrated for a 100% limestone environment. Neutron logs are processed to eliminate the effects of borehole diameter, tool size, temperature, drilling mud hydrogen index (dependent on mud weight, pressure, and temperature), mud and formation salinities, lithology, and other environmental factors.
In near-vertical drill holes, the ADNVISION tool does not collect quadrant azimuthal data. Data output includes apparent neutron porosity (i.e., the tool does not distinguish between pore water and lattice-bound water), formation bulk density, and PEF. In addition, the ADNVISION tool outputs a differential caliper record based on the standard deviation of density measurements made at high sampling rates around the circumference of the borehole. The measured standard deviation is compared with that of an in gauge borehole, and the difference is converted to the amount of borehole enlargement. A standoff of <1 inch between the tool and the borehole wall indicates good borehole conditions, for which the density log values are considered to be accurate to ±0.015 g/cm3.
Because of difficult sea conditions, some of these tool strings had to be reduced or reconfigured. See individual site chapters for details.
Tool name acronyms, the parameters measured by each tool, the depth of investigation, and the vertical resolution are summarized in Table T3. More detailed descriptions of individual logging tools and their geological applications can be found in Ellis (1987), Goldberg (1997), Rider (1996), Schlumberger (1989, 1994), Serra (1984, 1986, 1989), and the LDEO-BRG Wireline Logging Services Guide (2001).
The HNGS measures the natural gamma radiation from isotopes of K, Th, and U and uses a five-window spectroscopic analysis to determine concentrations of radioactive K (in weight percent), Th (in parts per million), and U (in parts per million). The HNGS uses two bismuth germanate scintillation detectors for gamma ray detection with full spectral processing. The HNGS also provides a measure of the total gamma ray emission (in gAPI) and the uranium-free or computed gamma ray emission (in gAPI). HNGS response is influenced by the borehole diameter and the weight and concentration of bentonite or KCl present in the drilling mud. KCl may be added to the drilling mud to prevent freshwater clays from swelling and forming obstructions. The spectral analysis filters out gamma ray energies below 500 keV, eliminating sensitivity to bentonite or KCl in the drilling mud and improving measurement accuracy. All environmental effects are corrected for during processing of HNGS data.
The SGT uses a NaI scintillation detector to measure the total natural gamma ray emission, combining the contributions of K, U, and Th in the formation. The SGT is not a spectral tool but provides high-resolution total gamma ray data for depth correlation between logging strings. It is included in all tool strings (except the triple combo, where the HNGS is used) to provide a reference log to correlate depth between different logging runs. In the FMS-sonic tool string, the SGT tool is placed between the two tools, providing correlation data to a deeper level in the hole.
The HLDT consists of a radioactive cesium (137Cs) gamma ray source (622 keV) and far and near gamma ray detectors mounted on a shielded skid, which is pressed against the borehole wall by a hydraulically activated eccentralizing arm. Gamma rays emitted by the source experience both Compton scattering and photoelectric absorption. Compton scattering involves the ricochet of gamma rays off electrons in the formation via elastic collision, transferring energy to the electron in the process. The number of scattered gamma rays that reach the detectors is directly related to the number of electrons in the formation, which in turn is related to bulk density. Porosity may also be derived from this bulk density if the matrix density is known.
The HLDT also measures the PEF caused by absorption of low-energy gamma rays. Photoelectric absorption occurs when gamma rays reach <150 keV after being repeatedly scattered by electrons in the formation. As the PEF depends on the atomic number of the elements in the formation, it is essentially independent of porosity and varies according to the chemical composition of the sediment. Some examples of PEF values are pure calcite = 5.08, illite = 3.03, quartz = 1.81, and kaolinite = 1.49 b/e–. PEF values can be used in combination with HNGS curves to identify different types of clay minerals. Coupling between the tool and borehole wall is essential for good HLDT logs. Poor contact results in underestimation of density values. Both density correction and caliper measurement of the hole are used to check the contact quality.
The APS consists of a minitron neutron generator that produces fast neutrons (14.4 MeV) and five neutron detectors (four epithermal and one thermal) positioned at different spacings along the tool. The tool is pressed against the borehole wall by an eccentralizing bowspring. Emitted high-energy (fast) neutrons are slowed down by collisions with atoms. The amount of energy lost per collision depends on the relative mass of the nucleus with which the neutron collides. The largest energy loss occurs when the neutron strikes a nucleus of equal mass, such as hydrogen, which is mainly present in pore water. Once neutrons degrade to thermal energies (0.025 eV), they may be captured by the nuclei of silicon, chlorine, boron, and other elements, with the associated emission of gamma radiation. The neutron detectors record both the numbers of neutrons arriving at various distances from the source and the neutron arrival times, which are a measure of formation porosity. However, hydrogen bound in minerals such as clays or in hydrocarbons also contributes to the measurement, so the raw porosity value is often an overestimate of formation porosity.
The DIT, also known as the spherically focused resistivity tool, provides three different measurements of electrical resistivity, each with a different depth of penetration into the formation. Two induction devices (deep and medium resistivity) transmit high-frequency alternating currents through transmitter coils, creating magnetic fields that induce secondary (Foucault) currents in the formation. These ground-loop currents produce new inductive signals, which are proportional to the conductivity of the formation and which are measured by the receiving coils. The measured conductivities are then converted to resistivity. A third device, a spherically focused resistivity instrument that gives higher vertical resolution, measures the current necessary to maintain a constant voltage drop across a fixed interval
The TAP tool is a "dual application" logging tool (i.e., it can operate either as a wireline tool or as a memory tool using the same sensors). Data acquisition electronics are dependent on the purpose and required precision of logging data. During Expedition 311, the TAP tool was deployed as a memory tool in low-resolution mode; data were stored in the tool and downloaded after the logging run was completed. Temperatures determined using the TAP tool do not necessarily represent in situ formation temperatures because water circulation during drilling disturbs temperature conditions in the borehole. However, from the spatial temperature gradient, abrupt temperature changes can be identified that may correspond to contrasts in permeability at lithologic boundaries or that may represent localized fluid flow into the borehole, indicating fluid pathways and fracturing.
The DSI employs a combination of monopole and dipole transducers to make measurements of sonic wave propagation in a wide variety of formations. In addition to a robust measurement of P-wave velocity, the DSI uses the dipole source to generate a flexural mode in the borehole that can be used to estimate shear wave (S-wave) velocity even in highly unconsolidated formations. When the formation S-wave velocity is less than the sonic velocity of the borehole fluid, particularly in unconsolidated sediments, the flexural wave travels at the S-wave velocity and is the most reliable way to estimate a shear wave velocity log. Meanwhile, the monopole source generates P-, S-, and Stoneley waves into hard formations. The configuration of the DSI also allows recording of cross-dipole waveforms. In many cases, the dipole sources can also provide estimates of S-wave velocity in hard rocks better than or equivalent to the monopole source. A low-frequency (~800 Hz) source enables Stoneley waveforms to be acquired as well.
The DSI measures the transit times between sonic transmitters and an array of eight receivers with 15 cm spacing, each consisting of four orthogonal elements that are aligned with the dipole transmitters. During acquisition, the output from these 32 individual elements are differenced or summed appropriately to produce in-line and cross-line dipole signals or monopole-equivalent (compressional and Stoneley) waveforms, depending on the operation modes. A detailed description of tool configuration and data processing is provided in the Leg 174B Initial Reports "Introduction" chapter (Shipboard Scientific Party, 1998). The velocity data from the DSI, together with the formation density, can be used to generate a synthetic seismogram for correlation with seismic data.
The FMS produces high-resolution images of borehole wall microresistivity that can be used for detailed sedimentologic or structural interpretation. This tool has four orthogonally oriented pads, each with 16 button electrodes (5 mm diameter) that are pressed against the borehole wall (see inset in Fig. F28). Good contact with the borehole wall is necessary for acquiring good-quality data. Approximately 30% of a borehole with a diameter of 25 cm is imaged during a single pass. Coverage may be increased by a second run. The vertical resolution of FMS images is ~5 mm, allowing features such as burrows, thin beds, fractures, veins, and vesicles to be imaged. Resistivity measurements are converted to color or grayscale images for display. FMS images are oriented to magnetic north using the GPIT (see next section). This allows the dip and strike of geological features intersecting the hole to be measured from processed FMS images. FMS images can be used to visually compare logs with the core to ascertain the orientations of bedding, fracture patterns, and sedimentary structures (Serra, 1989; Luthi, 2001).
The GPIT is included in the FMS-sonic tool string to calculate tool acceleration and orientation during logging. The GPIT contains a triple-axis accelerometer and a triple-axis magnetometer. The GPIT records the orientation of the FMS images and allows more precise determination of log depths than can be determined from cable length, as the accelerometer data can be used to correct for cable stretching, tool sticking, and ship heave. Detailed tool motion information is monitored to process the FMS data and obtain accurate images of the formation (Luthi, 2001).
The WST produces a zero-offset vertical seismic profile and/or check shots in the borehole. The WST consists of a single geophone that records the full waveform of acoustic waves generated by a seismic source positioned just below the sea surface. During Expedition 311, we used a 105 inch3 generator-injector air gun as a seismic source. This gun was positioned at a water depth of ~2 m and offset from the borehole by ~50 m on the port side of the JOIDES Resolution. The WST was clamped against the borehole wall at 5 to 10 m intervals, and the air gun was typically fired between 5 and 15 times at each station. The recorded waveforms were stacked and a one-way traveltime was determined from the median of the first breaks for each station, thus providing check shots for calibration of the integrated transit time calculated from sonic logs. Check shot calibration is required for well-seismic correlation because P-wave velocities derived from the sonic log may differ significantly from the velocities determined from seismic data. Causes for this difference include
In addition, sonic logs cannot be measured through the pipe, so the traveltime down to the uppermost logging point has to be estimated by other means.
Data for each wireline logging run were recorded and stored digitally and monitored in real time using the Schlumberger MAXIS 500 system. After logging was completed in each hole, data were transferred to the DHML for preliminary processing and interpretation. FMS image data were interpreted using Schlumberger's GeoFrame.
Logging data were also transmitted to LDEO-BRG using a satellite high-speed data link for processing soon after each hole was logged. Data processing at LDEO-BRG consisted of
Once processed at LDEO-BRG, logging data were transmitted back to the ship, providing near real-time data processing. Processed data were then replotted on board (see the "Downhole logging" section in each site chapter). Further postcruise processing of the logging data from the FMS will be performed at LDEO-BRG. Postcruise-processed data are available directly from the LDEO-BRG web site (iodp.ldeo.columbia.edu/DATA) in ASCII format. A summary of "logging highlights" is posted on the LDEO-BRG web site at the end of each expedition.
Logging data quality may be seriously degraded by changes in hole diameter and in sections where the borehole diameter greatly decreases or is washed out. Measurements that investigate deeper into the borehole wall, such as resistivity and sonic velocity, are least sensitive to borehole conditions. Nuclear measurements (density and neutron porosity) are more sensitive because of their shallower depths of investigation and the effect of drilling fluid volume on neutron and GRA. Corrections can be applied to the original data to reduce some of these effects, but for very large washouts, data cannot be corrected. HNGS and SGT data provide a depth correlation between logging runs. Logs from different tool strings may, however, still have minor depth mismatches caused by either cable stretch or ship heave during recording. Ship heave is minimized by a hydraulic wireline heave compensator designed to adjust for rig motion during logging operations.
With growing interest in natural gas hydrate, it is becoming increasingly important to be able to identify the presence of in situ gas hydrate and accurately assess the volume of gas hydrate and associated free gas within the host sediments. Numerous publications (Mathews, 1986; Collett, 1993, 1998a, 1998b, 2000; Goldberg, 1997; Guerin et al., 1999; Goldberg et al., 2000; Helgerud et al., 2000) have shown that downhole geophysical logs can yield information about the presence of gas hydrate.
Because gas hydrates are characterized by unique chemical compositions and distinct electrical resistivities, physical, and acoustic properties, it is possible to obtain gas hydrate saturation (percent of pore space occupied by gas hydrate) and sediment porosity data by characterizing the electrical resistivity, acoustic properties, and chemical composition of the pore-filling constituents within gas hydrate–bearing reservoirs. Two of the most difficult reservoir parameters to determine are porosity and the degree of gas hydrate saturation. Downhole logs often serve as a source of porosity and hydrocarbon saturation data. Most of the existing gas hydrate log evaluation techniques are qualitative in nature and have been developed by the extrapolation of petroleum industry log evaluation procedures. To adequately test the utility of standard petroleum log evaluation techniques in gas hydrate–bearing reservoirs would require numerous laboratory and field measurements. However, only a limited number of gas hydrate occurrences have been sampled and surveyed with open-hole logging devices.
Reviewed below are downhole logging measurements that together yield useful gas hydrate reservoir information. The downhole measurements considered include density, neutron porosity, electrical resistivity, and acoustic transit time. Most of these measurements are converted to porosity; however, because gas hydrate affects each measurement of porosity in a different fashion, the quantity of gas hydrate can be estimated by comparing porosity measurements made using different techniques.
Density logs are primarily used to assess sediment porosities. The theoretical bulk density of a Structure I methane hydrate is ~0.9 g/cm3 (Sloan, 1998). Gas hydrate can cause a small but measurable effect on density-derived porosities. At relatively high porosity (>40%) and high gas hydrate saturation (>50%), the density log–derived porosities need to be corrected for the presence of gas hydrate (Collett, 1998b).
Neutron logs are also used to determine sediment porosities. Because Structure I methane hydrate and pure water have similar hydrogen concentrations, it can be generally assumed that neutron porosity logs, which are calibrated to pure water, are not significantly affected by the presence of gas hydrates. At high reservoir porosities, however, the neutron porosity log could overestimate porosities (Collett, 1998b).
Water content and pore water salinity are the most significant factors controlling the electrical resistivity of a formation. Other factors include the concentration of hydrous and metallic minerals, volume of hydrocarbons including gas hydrates, and pore structure geometry. Gas hydrate–bearing sediments exhibit relatively high electrical resistivities in comparison to water-saturated units, which suggests that a downhole resistivity log can be used to identify and assess the concentration of gas hydrates in a sedimentary section. The relation between rock and pore fluid resistivity has been studied in numerous laboratory and field experiments. From these studies, relations among porosity, pore fluid resistivity, and rock resistivity have been found. Among these findings is the empirical relation established by Archie (1942), which estimates water saturations in gas-oil-water-matrix systems. Research has shown that the Archie relation also appears to yield useful gas hydrate saturation data (reviewed by Collett, 2000).
The velocity of P- and S-waves in a solid medium, such as gas hydrate–bearing sediment, is usually significantly higher than the velocity of P- and S-waves in water- or free gas–bearing sediments. Studies of downhole acoustic log data from both marine- and permafrost-associated gas hydrate accumulations have shown that the volume of gas hydrate in sediment can be estimated by measuring interval velocities (Guerin et al., 1999; Helgerud et al., 2000; Collett, 2000). Analysis of sonic logging waveforms has also shown that the presence of gas hydrate can generate significant energy loss in monopole and dipole waveforms (Guerin and Goldberg, 2002).
Structural data were determined from FMS and GeoVISION images using Schlumberger's GeoFrame. GeoFrame presents image data as a planar, "unwrapped" 360° resistivity image of the borehole with depth. The image orientation is referenced to north, which is measured by the magnetometers inside the tool, and the hole is assumed to be vertical. Horizontal features appear horizontal on the images, whereas planar, dipping features are sinusoidal in aspect. Sinusoids are interactively fitted to beds and fractures to determine their dip and azimuth, and the data are exported from GeoFrame for further analysis.
Methods of interpreting structure and bedding differ considerably between core analysis, wireline FMS images, and GeoVISION image analysis. Resolution is considerably lower for GeoVISION image interpretation (5–10 cm at best, compared with millimeters within cores and 0.5 cm for FMS images), and therefore identified features are likely to be different in scale. For example, microfaults ("small faults," <1 mm width) and shear bands (1–2 mm and as much as 1 cm in width) can only be identified in FMS data. This should be taken into account when directly comparing FMS and GeoVISION images. GeoVISION provides 360° coverage at a lower resolution; FMS provides higher resolution data but coverage is restricted to only ~30% of the borehole wall. Fractures are identified within GeoVISION images by their anomalous resistivity or conductivity and from their contrasting dip relative to surrounding bedding trends. Differentiating between fractures and bedding planes can be problematic, particularly if both are steeply dipping and with similar orientations.
We correlated the results of some of the seismic surveys acquired in the area with the Expedition 311 LWD/MWD and wireline logging data. The correlation included core physical properties, wireline logs, and two-dimensional seismic survey images. To ensure accurate correlation of the data, it was important to ascertain the accuracy of the navigation of each of the associated surveys, the hole deviation, the drill string position at the seafloor relative to the sea surface, the accuracy of the depth-converted seismic data, and the vertical and horizontal seismic resolution. Accurate correlation is critical to extend the study of the direct measurements of the subsurface physical properties away from the borehole using seismic data.