A falling-stage deep-water succession is characterized by sandstone-dominated channel-and-overbank deposits and age-equivalent depositional-lobe deposits. In contrast, a lowstand deep-water succession is muddier and is characterized by a thickening-upward pattern of distal overbank deposits. The base of the falling-stage deposits is characterized by a distinct erosional surface compared with the base of the lowstand deposits, which is commonly represented by a gradational contact to the underlying falling-stage deposits.Deep-water channels commonly exhibit meandering patterns similar to fluvial channels, and the channel-fill deposits are encased in muddy overbank deposits. The distribution patterns and volumes of coarse-grained channel-fill deposits developed mainly during falling- and lowstand stages can be estimated from outcrop and seismic data on the basis of several empirical relationships among width, depth, and sinuosity of deep-water channels. Hyperpycnal flows have recently been interpreted to be one of the important mechanisms for developing thick to very thick-bedded, deep-water massive sandstones (DWMSs). DWMSs commonly exhibit sheet-like geometry and abruptly thin out and fine to the downslope direction. These abrupt changes in thickness and grain size of DWMSs are interpreted to be a result of deposition of a sufficient volume of sand particles from precursor hyperpycnal flows, which are subsequently transformed into buoyant plumes with finer-grained sediment particles associated with residual lower-density turbidity currents flowing to the further downslope direction. Modulation and transformation of turbidity currents into debris flows at a channel-to-lobe transition zone were recognized. The transformation of turbidity currents into debris flows is interpreted to have occurred in response to incorporation of many siltstone clasts and finer-grained sediment particles into the precursor turbidity currents from muddy substrates. The finding indicates that a laterally continuous sandstone body from middle-fan channel to depositional lobe deposits internally contains muddy baffles, which develop heterogeneity of fluid flows in reservoir sands and sandstones.
The result of MITI Nankai Trough wells drilled in 1999-2000 proved the occurrence of methane hydrate in the Nankai Trough area from recovered core and well logging data. This result gave a big impact on both the Japanese strategy for energy and scientific interest. And it eventually motivated Japanese government to commence the national project named “Japan's Methane Hydrate Exploitation Program”, which started since 2001. From the results of the 2D and 3D seismic survey acquired in the Nankai Trough area by METI in 2001 and 2002, widely-distributed BSR was recognized in the area, which was expected the wide distribution of methane hydrate. For the volume quantification, we needed to evaluate reservoir parameters of methane hydrate reservoir such as thickness, saturation, and porosity of sediments. And we inferred methane hydrate bearing layers are inhomogeneous and discontinuous in space and depth. And we also found a good correspondence between methane hydrate layer and the zone which is characterized by seismic attribute as high P-wave velocity, high P-wave impedance, high S-wave impedance, low pseudo Poisson's ratio and high attenuation.Consequently, we conclude that the pre- and post-stack seismic attributes are so helpful tools to delineate the methane hydrate reservoir.
The effective production of hydrocarbons from the Birkhead Formation in the Eromanga Basin, onshore Australia relies on understanding the complex distribution of reservoir and seal rocks deposited in a fluvial environment. To visualize this complexity, sequence stratigraphic concepts applied to non-marine basins were combined with 3D seismic data visualization in a study of the Birkhead interval over the Merrimelia, Meranji and Pelican fields. Fluvial channel, crevasse splay channel, floodplain-crevasse splay complex and floodplain facies were recognized from the well log motifs in the Birkhead Formation. The interval is interpreted as an alluvial transgressive systems tract bounded by flooding surfaces consisting of shaly or coaly intervals with lateral discontinuity of the fluvial facies. Combining the spatial distributions of sedimentary facies from the well logs and seismic amplitude distributions in the upper part of the interval results in the interpretation of a fluvial meandering channel belt including point bars and abandoned channels. The point bar sandstones in the channel belt should make good reservoirs and the juxtaposition of the point bar and abandoned channel facies can result in a stratigraphic trap component within the channel belt. Although the point bars are known to be wet in this area, it is useful to consider their capacity as oil reservoirs, since they may serve as analogues for similar untested point bars elsewhere. Multiple realizations of the distribution of sandstone thickness of the point bars were generated by conditional simulation, using seismic amplitudes to control extrapolation of the well data. This gave 10m thick in maximum of net sandstone in a point bar area and a potential reserves distribution with a mean value of 18.8 million bbl in place. The complexity of the fluvial channel described in this paper should aid understanding of the reservoir and seal distribution and help optimize production from other fields.
Three dimensional geological models were constructed in the JACOS Hangingstone SAGD operation area, Alberta, Canada, integrating three dimensional seismic data of 5.4 square kilometers and 76 well data. The objectives of the study were to establish the detailed reservoir distribution and configuration for the reservoir characterization and to optimize the deployment of the SAGD injector/ producer well pairs. Sedimentary environments of the Lower Cretaceous McMurray Formation, which comprises the main layer of oil sands, were considered as fluvial to upper-estuarine channel fill deposits, and oil sands reservoirs were formed as the vertically stacked incised valley fill sands. Sequence analysis using well data was conducted at first, and framework of the stacked incised valley system was established. Further detailed sequence structural model was then constructed using seismic data. Property model which describes the sedimentary facies distribution was constructed through the interpretation of the acoustic impedance inversion and multi-attribute analysis from three dimensional seismic data. Constructed models were used for the actual SAGD horizontal well pairs planning as well as the reserves estimation. Top and bottom depths of the reservoir were estimated in the range of 2.0 meters near the existing wells even in such a channel sands environment which often changes its sedimentary facies abruptly.
The distribution pattern of the Green Tuff rock type and facies in the Niigata Sedimentary Basin, with a central focus on the ‘Nagaoka Area’, may have been controlled by rifting and other structural development in the Nanatani Stage. The term “Volcanic Sequence” model is now propounded as a volcanostratigraphic framework for the compound Green Tuff succession which encountered in the Minami Nagaoka Gas Field, based on the comprehensive interpretation and crossed understanding of a large variety of volcanic rock types and facies and their changes in physicality and geochemical composition. The model comprises five volcanic sequences such as the Volcanic Sequence I, II, IIIR, IIIB and IV in ascending order. The Volcanic Sequence I and II consist of non-acidic rocks, and the former characterized with an extremely high resistivity is sharply distinguished from the latter. The acidic Sequence IIIR which has a bimodal relationship with the basaltic Sequence IIIB consists of multi-stacked rhyolitic lava-flows and/or lava-domes. Those are able to be identified based on the composite interpretation of the presumed rock facies together with dipmeter data in each well. The Sequence IV, a thin basaltic flow unit, is limited its distribution to the northern part of the field. Reservoir geological interpretation based on the “Volcanic Sequence” model might be able to explain heterogeneous facies distribution, and different productivities and pressure performances among wells..In the ‘Nagaoka Area’, some of the vintage wells encountered acidic rocks corresponding to the Volcanic Sequence IIIR and the lowermost part of the underlying non-acidic rocks are extremely resistive like the Volcanic Sequence I. In order to predict the distribution of acidic volcanic bodies which remain undiscovered, it is worth trying to re-interpret the vintage wells and seismic data from the aspect of the “Volcanic Sequence”
A domestic gas field was modeled and flow-simulated. Its reservoir body comprises stacked rhyolite lava domes erupted under submarine environment. Porous network developed inside and chilling by seawater formed hyaloclastite to deposit around it. Although hyaloclastite is also porous, its permeability has been dramatically reduced by clay minerals. Impermeable basaltic sheets and mud seams are also present. Each facies plays a specific role in the pressure system of the field. Stratigraphic correlation originally identified multiple reservoirs. Gas has been produced according to priority assigned to each, assuming that it is sealed from others. However, it is noticed by now that pressures of unexploited units have also declined with variety of rates. In addition, some unusual local pressure behaviors have been recorded. It was decided to re-model the whole pressure system to reasonably explain these observations. Combination of multi-point geostatistics and probability perturbation theories was employed. It successfully reproduced non-linear features of stacked lava domes, while allowing pressure data for controlling geo-body distributions in larger scale. A common difficulty of building a proper training image, further pronounced for a volcanic reservoir, was solved by iteratively adjusting its prototype until the number of perturbations for history matching was minimized. Ambiguous reservoir boundary, due to lava growth in random directions, was stochastically represented by populating a predetermined modeling space with both pay and non-pay pixels. Resulted realizations closely simulate pressure history to every detail and look realistic in facies distribution. They ascribe the uneven pressure decline between different units to tortuous flow channels connecting them. They also uncovered the cause of the unusual smaller-scale pressure performances. OGIP evaluated by 20 equally probable realizations stay within ±15% around the mean. Incremental recovery by adding a new well indicates wider scatter than that by installing a booster compressor, which quantifies geological risk associated to it.
“Equivalent grain size (EGS) method” is a unique approach to represent the top seal capacity in terms of the ideal grain size. Theoretical consideration of the capillary seals suggests that the capillary pressure, which controls the seal capacity, depends on the size of the pore-throat. The EGS method uses the pore-throat size calculated from known or measurable parameters, such as hydrocarbon column height, fluid densities, contact angle, and interfacial tension. Furthermore, the pore-throat size can be converted to porosity and the grain size by the experimentally derived function.Gas, which is less than oil in density, behaves to migrate above the oil column in a trap. Consequently, only gas would be entrapped in such a trap where the trap height is smaller than the maximum gas column height which can be held by top seal capacity, whereas such a trap where the trap height is larger than the maximum oil column height would be dominated by oil. This point of view and case studies in this paper demonstrate that the relationship between the trap height and the top seal capacity plays also important role to determine the hydrocarbon fill (oil or gas) as well as the geochemical factors.Thus, the EGS method can provide new insights into understanding hydrocarbon fill patterns in fields and prospects.
This document seeks to review and summarize issues about 3D seismic reservoir characterization and current technology trends for overcoming such issues. We list major difficulties in quantitative reservoir property estimation from 3D seismic data as i) poor understanding about the relationship between seismic attributes and reservoir properties, ii) the scale difference between seismic data and target geological model, and iii) integration of qualitative geological understanding into quantitative modeling framework. We then introduce several key efforts in two field examples for resolving them through integrated modeling. In the first example in a carbonate reservoir, rock physics study led to physical understanding of the identified correlation between Vp/Vs ratio and the absolute permeability, as well as AI(Acoustic Impedance) and porosity. We subsequently conducted porosity and permeability modeling using these relations, including a vertical downscaling step by the Gaussian Simulation with Locally Varying Mean method, which accomplished the final model consistent with well and seismic data. In the second example in a deep sea sandstone reservoir, non-unique relationship between seismic attributes, AI and EI(Elastic Impedance), and reservoir properties(lithology and pore fluid type) was quantified through statistical expression using PDFs(probability density functions) derived from well log data. The PDFs were used for interpreting seismically derived AI and EI to provide most-likely facies/fluid distribution. Finally, we present an example of applying multiple-point geostatistics for integrating seismically derived facies probability and prior geological information about the facies distribution. These field examples lead us to a conclusion that seismic reservoir property estimation methodology should be defined after careful consideration of the geological and geophysical background of the target fields, as well as the quality, quantity, and density of available data.
This paper attempts to seek an effective methodology for integrated sedimentological, seismic geomorphological and geostatistical reservoir-distribution analysis. Recent developments in sedimentology (e.g.,depositional systems and sequence stratigraphy) and 3D seismic geomorphology have improved our understanding of three-dimensional reservoir distributions on the basis of genetic and deterministic concepts. As geologic constraints, the sedimentological and seismic geomorphological information is used for a geostatistical reservoir characterization to obtain realistic distribution maps on reservoir properties. In this characterization flow, it can be efficient that known facts derived from sedimentological concepts are dealt with deterministically, whereas unknown territories (e.g., internal heterogeneity) are dealt with stochastically.
A carbonate reservoir of a giant oil field, the Early Cretaceous Kharaib Formation in the Middle East, has complex limestone lithofacies, and unexpected breakthrough of injection water has been observed at some of the wells. Previous studies have suggested that the heterogeneous reservoir property which cause in the unexpected breakthrough of the water is mainly related to lithofacies changes within the reservoir. To make a better estimate of the reservoir property distribution, high-frequency sequence stratigraphy has been developed in the field. Integrating detailed core observation, well-log correlation and stacking pattern analysis for the reservoir, we identified fifteen lithofacies and six high frequency (4-5th order) sequences in the reservoir interval, and the depositional models for each systems tract were derived. We are building a new reservoir simulation model with this integration such as layering scheme, distribution of lithofacies and reservoir properties derived from high frequency sequence stratigraphy. Field scale lithofacies model was constructed based upon the regional depositional concepts, isopach trends for each sequence stratigraphic unit and observed core lithofacies. The layering scheme for the new reservoir model is defined based on sequence stratigraphic interpretation, and the sub-layers are derived from subdivision of sequence stratigraphic units into proportional smaller layers to represent the vertical lithofacies variation. 3D seismic data is utilized to construct the framework of the structural model with fault geometry. Permeability model is constructed by deterministic method using lithofacies model and regression function of relationship between porosity and permeability for each lithofacies. In addition, Flow Zone Indicator (FZI) which is parameter of combination of porosity and permeability based on Pulsed Neutron Capture (PNC) log data, is also integrated for the permeability modeling in order to represent heterogeneity of high permeability and match with the behavior of injected water. The above-mentioned methodology makes it possible to modify the flow model by geological concepts, e.g. by review of lithofacies model and permeability estimation, during history matching in the next dynamic reservoir simulation phase.
The Rang Dong oil field is located in the Cuu Long basin, offshore Vietnam. The field was discovered by Japan Vietnam Petroleum Company Ltd. in 1994. The field has naturally fractured basement reservoir, which is producing with 14 producers and 7 injectors as of now. One of the production bottlenecks of the Rang Dong field is gas and water break through. High bubble point pressure oil provides secondary gas cap drive system to the reservoir. But control of the liberated gas production by coning is difficult. Deeper completions to avoid gas break through often result in water break through, although there is no significant pressure support from aquifer. Currently, water injection is applied to the field to control reservoir energy and gas cap development. With this situation, development of reliable model to predict field performance is a key technical requirement to manage the field. This paper describes evolution of the reservoir modeling. Generally, characterization of fractured crystalline rock reservoir is more difficult than sedimentary rock reservoir. After some lessons learnt, new approaches such as 3D seismic reprocessing, highly deviated-horizontal wells, extended well testing were applied to fully evaluate the reservoir. These new approaches made a lot of improvement to understanding of the fracture system and resulting simulation models. Integration of different disciplinary data introduced key concepts such as discrete fractures, productive network and dynamic data matching. The fracture data gathered so far were re-evaluated in the view of connectivity to the productive network. The simulation model consists of discrete mega-fracture framework and associated relatively continuous lower order fractures. The model is calibrated with both static and dynamic data, using such data as seismic, log and well test. This model describes pore space distributions and their connectivity in single porosity system and can re-produce the history of break through and predict the reservoir performances with some practical accuracy in natural depletion condition.
In high-temperature formation drilling, the life of drill bits becomes shorter due to thermal damage to the O-ring seal set in the bearing part. An increase in the formation temperature has been regarded as a major reason for the temperature of drill bits increasing. However, mechanical factors such as WOB(Weight on Bit)and rotation have not been fully taken into consideration. In this study, an experimental device that can simulate situations for drill bits during drilling was fabricated. The test piece was designed to simulate a cone of a 8-1/2 "tri-cone bit. Two types of bearings were prepared for the test pieces; journal bearing and roller bearing types. Experiments using the device were performed under various mechanical loaded conditions to investigate heat generation in tri-cone bits with cooling affected by circulation fluid. In these experiments, the range of the weight on a cone was 2.5−5.1 t(corresponding to 7.5−15.3 t of WOB), and the range of the cone rotation speed was 60−120 rpm(corresponding to 40−80 rpm of drill pipe rotation speed). In these experimental conditions, the heat generation in the cone in tri-cone bits was 100−160 kJ/min for journal bearings and 30−60 kJ/min for roller bearings. It was also found that the surface temperature of tri-cone bits was almost the same as the temperature of the circulating fluid at the bottom of the hole, under flow rate conditions at a rig site. Further, based on the experimental results, we suggested two estimation methods for determinations of the temperature in drill bits during drilling wells, especially near the radial loaded bearing part in which temperature is important for thermal damage of the O-ring. Using these methods, in the case where a bottom-hole temperature is given, the temperature of drill bits can be estimated. The method will be useful to assist in deciding drilling conditions that will not cause thermal damage to the O-ring seal in a bearing.
A lot of contaminated site with many kinds of pollutants exists all over the world and it makes the earth environment seriously. Oil is the one of the most common pollutants for shoreline, groundwater and soil. This paper describes about on-site remediation technologies, which are using physical, chemical and biological methods, for contaminated soil with oil particularly. In addition, it shows the present condition of oil contamination and analytical methods in Japan.
Pressure Temperature Core Sampler (PTCS) was designed and developed as a special coring tool in the methane hydrate (MH) R & D project in Japan. In order to recover in-situ methane hydrate bearing sediments without major dissociation while retrieving to the surface, inner barrel of PTCS retains downhole pressure by closing a ball valve and retains downhole temperature by an insulated chamber. A 2-5/8"(66.7 mm) OD × 3 m core sample is cut by 10-5/8"(269.9 mm) OD core bit and the inner barrel containing the core sample is wireline retrievable through special 6-5/8"(168.3 mm) drillpipe. The 1st PTCS was used on the occasion of the drilling campaign named MITI “Nankai Trough” in 1999-2000. After several elements had been improved, the 2nd PTCS was used on the drilling campaign named METI exploratory test wells “Tokai-oki to Kumano-nada” in 2004. In this campaign, the 2nd PTCS retrieved 161.3 m of high quality MH core samples at approximately 80% recovery.