The latest generation of sonic logging tool (Sonic Scanner) can record monopole and dipole waveforms data in wider range of formation types and logging condition than the previous generation of the sonic tool could through the advance in tool design and associated technology such as electronics, sensor and so on. Wider frequency bands, better modal purity, increased signal-to-noise of the recorded sonic waveforms and the configuration of the transmitters and receivers enable to measure formation acoustic characteristic around the borehole, which was not possible before. While more measurements became possible, the most important outputs from the sonic logging are P and S wave velocities (Vp and Vs). To obtain Vp and Vs from array waveform data, slowness-time-coherence (STC) processing technique is commonly used. With appropriate processing parameters, this processing method results in accurate and robust slownesses (reciprocal of velocity) for non-dispersive coherent arrivals, which is usually the case of P and S waves in monopole data. When the dipole waveform data are processed for formation shear slowness, dispersive STC method is used to take dispersive nature of flexural mode into account before calculating semblance. For quality control, the shear slowness estimated by dispersive STC is overlaid on slowness-frequency-analysis (SFA) projection log, and if the estimated slowness matches the low-frequency limit of the SFA projection, the quality of the estimated slowness is high. Acoustic logging data were conventionally used for seismic tie, velocity modeling, porosity evaluation, lithology analyses, gas detections, cased-hole analyses and so on. The shear anisotropy analysis using cross-dipole data had been available with the previous generation of the sonic tool and has been used for characterization of fractures and the stress field around the borehole. Clean dispersion curves of monopole and dipole data in wide frequency band from the latest sonic tool further enable identifying the dominant mechanism of observed elastic anisotropy as well as near wellbore formation alteration. Vp, Vs, anisotropy parameters and fast shear azimuth are important input for mechanical earth model (MEM) to better understand the rock mechanical properties and assess the state of the stress. Using MEM, the stability of the wellbore can be modeled, and mud weight and the design of well trajectory can be optimized for safe and cost effective drilling. This would be particularly important for unconventional explorations like gas hydrates and CO2 geosequestration due to special concerns about wellbore and formation stability.
Velocity is valuable information for finding the methane hydrate-bearing sediments. Only use of velocity for finding MH-bearing sediments is not enough and recent surveys have shown that the presence of MH in sediments has significant influence on seismic attenuation. Seismic attenuation can be conveniently separated into the intrinsic attenuation and apparent attenuation. Intrinsic attenuation is a measure of the amount of energy that is irreversibly removed from a seismic wave as it propagates through an inelastic medium due to energy conversion mechanisms. In contrast, apparent attenuation is due to elastic scattering from velocity and density heterogeneities, and commonly is referred to as scattering attenuation. The intrinsic attenuation is important in characterizing the physical properties of subsurface formations. However, it is generally difficult to distinguish between intrinsic attenuation and apparent attenuation. The purpose of this study is to isolate the scattering attenuation and source-formation radiation coupling from the total attenuation derived from sonic waveform data obtained in MH-bearing sediments at the Nankai Trough area. Firstly, we applied the median frequency shift method and spectral ratio method for sonic waveform data to estimate attenuation and compared their results. Results showed that at the Nankai trough, median frequency shift is better method for estimating attenuation. Secondly, we estimated attenuation due to source-formation radiation coupling and scattering attenuation to isolate intrinsic attenuation. In this paper, we assume that the apparent attenuation includes only both the scattering attenuation and source-formation radiation coupling. Both source-formation radiation coupling and scattering attenuation showed moderate correlation at the MH-bearing layers, but the sizes of the heterogeneities showed that we need the data with higher resolution for precise estimation of scattering attenuation.
Petrophysical log analyses were performed on the 3 different types of reservoirs and different permeability estimation methods were applied as 3 case studies. In the case 1, based on the clear positive correlation between core porosity and core permeability, Coates equation was successfully applied. This case is an example where permeability is mainly controlled by porosity (pore volume). In the case 2, positive correlation between core porosity and core permeability are observed but there is a strong dependency on lithofacies. In order to accurately estimate permeability, facies log is required prior to log analysis and facies-dependent log analysis was performed. This case is an example where permeability is controlled by porosity but the relationship is different from facies to facies. In the case 3, there is no obvious correlation observed between core porosity and core permeability, and any facies/rock type information can not explain the scatter in porosity vs. permeability crossplot. However, there is a systematic relationship between, water saturation, capillary pressure and permeability. By generating a regression surface among these three parameters, permeability was estimated with fair accuracy. This is an example where permeability is strongly controlled by pore geometry. In this case capillary pressure vs. water saturation curve, which is strongly related to pore size distribution and possibly pore geometry, can help to estimate permeability.
Productive fractures in the basement fractured reservoir were characterized from a view point of geomechanics. “The critically stressed fracture model” was assumed in this study, which suggests the fracture under the critical stress state for shear slip is permeable because the apertures are sustained by shear dilatancy, and hence, those fractures are expected to contribute to the productivity of the well. In this paper, fractures in the Cretaceous granitic basement and the tight conglomerate of the Eocene Ishikari Group at depth of around 4,000 m in the Yufutsu oil/gas field, Hokkaido, Japan are discussed. Resistivity images obtained at reservoir section of all the wells in the Yufutsu field were fundamentally utilized to detect fractures. Temperature profiles during production were used to identify the productive zones along the well in the reservoir section. Super wide conductive sinusoids (over 5cm) on resistivity images, hereinafter called “mega fracture”, were found at 70% of the temperature anomaly zones. The number of the mega fractures was well correlated with the productivity of the wells. These facts suggest that the majority of gas inflow from the formation should be controlled by mega fractures, which have super wide apertures. From the geomechanical point of view, the identified mega fractures tend to align along the optimum orientation for shear failure under the critical stress state, corresponding with the critically stressed fracture model. We conclude that the critically stressed fracture model is applicable to the naturally fractured reservoir in the oil gas field.
We evaluated fracture, permeability, porosity and water saturation of fractured low permeability limestone reservoir in the Gulf of Suez, Egypt. We explain the example of applied methods and problems associated with evaluation of the reservoir. It is necessary to understand the characteristics of each logging tool to estimate the reservoir properties appropriately. The subject of this study is an oil field located in northern part of the central Gulf of Suez. The main reservoir in the field is composed of carbonates which are Thebes and Mokattam Limestone of Eocene. In case of carbonate reservoir, empirical methods established for sandstone reservoirs sometimes couldn't be applied due to considerable variations in rock properties including pore geometry. Special wireline logging tool such as NMR, borehole imager, sonic scanner and core analysis are essential for evaluation of carbonate reservoirs, especially in evaluating the fractured reservoir of low matrix permeability. In this study, we estimated open fractures using coherence of shear-wave and anisotropy of shear-wave slowness on dipole source sonic, while all fractures are observed as resistive fractures in the well because open fractures are filled with oil-base-mud. Matrix permeability was calculated by NMR log and calibrated by core analysis. It is possible that each values of NMR permeability in other wells can estimate without NMR log from effective porosity by Neutron-Density logs. We estimated tar volume from wireline log data and core analysis results. The presence of the residual tar in the rock became an obstacle for the conventional interpretation of the reservoir properties. The electrical properties were measured again after sufficient cleaning of the core plugs. As a result, the values of formation resistivity factor and formation resistivity index decreased. Consequently, the Archie parameters determined from the results of the electrical properties after sufficient cleaning were used in SW calculation.
Several difficulties are encountered to construct carbonate geological model which maintain their highly heterogeneous reservoir characters. One of the most difficult tasks is to establish both Reservoir Rock Type (RRT) scheme and its lateral distribution properly. In many cases appropriate RRT scheme for dynamic model tend to lose their reliability on 3D lateral continuity, i.e. further detailed subdivision of the RRT meets reservoir engineering requirements but loses inter-well continuity with technical justifications. This new 3D modeling approach firstly integrates full geological information and findings, and successfully constructed 3D Initial Geological/Lithological Model (IGLM). The IGLM keeps lateral lithofacies distribution with technical and logical justifications. Secondly RRT scheme is constructed purely based on petrophysical data such as MICP, φ-K correlation and Amott wettability. Each RRT contains several lithofacies and doesn't show one to one correlation. Thus in order to construct petrophysical model these RRTs are stochastically plugged in to each lithofacies of IGLM. The benefit of the new 3D modeling approach is to make easy update the model with additional data/information from continuous field development.
In the Athabasca oil sands, which is a large deposit of heavy oil, located in northeast Alberta, Canada, it is common that impermeable shale intricately exists within the reservoirs and can potentially act as permeability baffles. For reservoir management, it is important to precisely delineate the intrareservoir shale. The main goals of this study are to establish a rock physics model of poorly consolidated, heavy oil-saturated sands and to estimate density by applying three-term AVO inversion to P-P reflected and P-S converted wave data. We first explore viscoelastic features of heavy oil by using ultrasonic velocity measurement data collected over a wide temperature range. By using viscoelastic model, temperature and frequency dependences of the bulk and shear moduli are predicted. Furthermore, we establish a rock physics model of poorly-consolidated, heavy-oil saturated sands. For the case of inclusions in a matrix, Generalized Singular Approximation method is used to obtain the effective properties. The model incorporates the viscoelastic features of heavy oil to estimate velocity dispersion associated with the viscosities. Density has a large contrast between reservoir and shale and is a desired property for reservoir delineation in the Athabasca oil sands. A P-P and P-S joint AVO inversion method is developed by extending an Bayesian inversion technique to multicomponent data. We apply the developed method to the Hangingstone oilfield to estimate density volume. The estimated density is practically consistent with the well log, implying that the method can provide a quantitative description of oil sands reservoir.
The Nanjo R1 exploratory well, whose main target was the water-dissolved gas in the basement rock, was successfully completed with a total depth of 2,119.49 m. Results on petroleum geology of the well are summarized as follows. 1) Sandstone members of the Tomigusuku Formation (T1 to T13), which have porosity ranging from 25 to 30%, are widely distributed in subsurface of the southern part of the Okinawa-jima on the basis of well correlation using microfossils and geophysical well logs. 2) Subsurface geologic structures inferred from dipmeter data are roughly in harmony with the published gravity and geological data. 3) The source rock analysis indicates that mudstones in the Tomigusuku Formation have poor source rock potential and are immature, although the basement rock is over-mature. 4) The occurrence of hydrocarbon gases of microbial and thermogenic origins was confirmed by the analysis of headspace gas from the drill cuttings. The thermogenic gases are mainly accumulated in the basement and the T13 member.