Lufeng 13-1 Oil Field operated by JHN Oil Operating Company (JHN) is located in South China Sea. For enhancement of oil production rate, the 6th and 7th drilling campaigns were carried out from 2004 to 2006 on the basis of the geological and reservoir study. Ten horizontal wells were drilled in total on these campaigns. The wells on the 6th drilling campaign show rapid decrease of oil production rate with rapid increase of water cut after production start (categorized as Type 1). On the other hand, most of the wells on the 7th drilling campaign perform gradual decrease of oil production rate with gradual increase of water cut (categorized as Type 2) or stable oil production rate with much lower and stable water cut (categorized as Type 3). These types seem to be controlled by geological factors; permeability of the oil reservoir, presence of the low permeable zone such as mudstone or muddy sandstone just below the oil reservoir etc. The wells of Type 2 and Type 3 contribute to enhance oil production rate of the oil field significantly. The present oil production rate on the 7th drilling campaign accounts for nearly 50% of the total oil production rate in the oil field. Two important knowledge concerning control factors of water cut and oil production rate in late development stage of the oil field are derived from the result of the 6th and 7th drilling campaigns. (1) Careful considerations of the presence of the low permeable zone acting as “barrier” or “filter” below the reservoir are needed as well as the oil reservoir quality in the target section (2) Precise skills of reservoir navigation are required to secure enough oil reservoir section contributing in stable oil production as planned.
In the Minami Nagaoka gas field located in Niigata Prefecture, Japan, additional perforations were conducted in a hydraulically fractured well to increase the productivity of the well. To our best knowledge, successful additiona lperforation treatments in hydraulically fractured wells have not been reported. A well, Minami Nagaoka MHF-1, was performed six-stages fracturing with limited perforation intervals. Since the production logging data was necessary to perform an efficient perforation job, the production logging was run just before the additional perforations. The additional perforations were conducted at some intervals where gas inflow concentrated to mitigate non-Darcy effects due to the excess gas inflow. Post-job evaluation confirmed that the additional perforations contributed to increase the productivity by a factor of two.
Normally, the inverse problem to map a reservoir compaction from surface subsidence data is an ill-conditioned system since the subsidence bowl gradually changes its curvature, hence, the boundary of pressure depleted area cannot be clearly identified from subsidence bowl. However, the analysis in this paper shows that the peak of lateral surface movement approximately coincides with the pressure depleted periphery. Therefore, if both subsidence and lateral movement maps are constructed, the approximate shape of the pressure depleted area and the lateral distribution of reservoir compaction can be identified. These two maps may be used without processing as a diagnosis tool to identify the location of sealed fault, extent of reservoir section and non-recovered hydrocarbon section. Imaging the reservoir compaction is further improved if a proper inverse method is applied with the subsidence and surface displacement maps as input data. This paper suggests, for inverse problems with real field conditions where reservoir compaction and elastic moduli are both unknown, to lump multiple layers into a few layers with equivalent anisotropic Young's moduli and to inversely calculate the reservoir compaction and the lumped anisotropic elastic moduli. The resolution and fluctuation of seek parameters are effectively adjusted by the Potter's error covariance off-diagonal elements. The inverted compaction map shows, more clearly than the original surface displacement maps, the location of sealed fault, extent of reservoir section and non-recovered hydrocarbon section even for relatively deep reservoirs.
Premature water breakthrough of injection water has been observed in some oil producers under five-spot pattern scheme in a carbonate reservoir of a giant oil field, offshore Abu Dhabi. Preferential water movement has been suspected and its influence on oil production and recovery has been expected. Recent time-lapse saturation surveys suggested significant water movement in upper sub-layers although their matrix permeability was low. Previous matrix-dominated models failed to explain such observed phenomena, which prompted investigation of fracture contribution to flow in these sub-layers. An objective of this study was to construct a reliable permeability model integrated with information related to fractures from well data and seismic data. A conceptual model of fluid flow system with the contribution of matrix and fractures was constructed incorporating with ‘diffused fractures’ controlled by layer properties and ‘fracture swarms’ associated with faults. Various data sources such as curvature analysis of 3D seismic time structure or fracture density from core observations were used for indicators of these fractures. Based on this conceptual model, following two steps were taken in the actual modeling; (1) 2D distribution of flow capacity controlled by well-tests was generated by curvature of time structure surface. (2) Estimated flow capacity from fractures was decomposed to each layer considering fracture density data from core observations. It could be integrated to a layer-based flow capacity of a matrix model. In this particular example, characteristics of the reservoir could be controlled by both matrix and fractures. Therefore, a complex process with successive iterations was required to construct a reasonable permeability model. Its result indicated remarkable improvement in history match with dynamic data from the field in flow simulations.
Systematic approaches to uncertainty analysis in undeveloped oil or gas fields are everlasting challenges in the oil industry. Probabilistic estimations of recoverable reserves, and plateau period are far from being simple because reservoir parameters often have so-called the interacting effects. Further difficulty stems from the fact that they need many flow-simulation runs before running the Monte Carlo simulations. Solutions to reduce the number of necessary simulation runs without losing the accuracy of estimation have been studied. In this decade, experimental design (ED) approach is focused on instead of the conventional one-factor-at-a-time (OFAAT) method. One of the advantages of ED is that much less flow-simulation runs are needed to obtain relatively unbiased probabilistic estimates, while the OFAAT method needs more flow simulation runs, and tends to yield a narrow range of probabilistic distribution. This report reviews the ED approach in the oil industry and the results of application to our field development case.
Reservoir geochemistry, which studies the compositional variations of petroleum reservoir fluids at a variety of spatial and temporal scales, provides information about details of reservoir filling and leakage, and about petroleum mixing and alteration. This information is useful not only for exploration but also for development and production, and gives us insights not available from other methods. Our study carried out in the Higashi-niigata gas field clearly shows that reservoir geochemistry using light hydrocarbons is effective for assessing reservoir continuity and charge mixing. We recommend a routine geochemical analysis of reservoir fluids during production.
Carbon isotope compositions of methane, ethane and propane, and hydrocarbon ratios in gas samples provide information of their origin (microbial vs. thermogenic), maturity of thermogenic component, compositional change due to migration, and extent of biodegradation. Mixing of gases with different origins or different maturities can also be evaluated using gas isotopic and molecular compositions. While these gas geochemical data have been used mainly for petroleum exploration, their applications for development, production and operation issues are also increasing. Headspace gas analyses can be used to delineate reservoir compartments and pay zones. Carbon isotope compositions in commingled production could be used to allocate contributions form individual production zones if isotopic differences exist between the gases from the contributing reservoirs. Origin of gas seepage in production sites could be investigated by the gas molecular and isotope compositions if enough reference data exist in the area.
The field of interest is a heterogeneous carbonate reservoir, offshore Abu Dhabi. A pore system in the field is classified into three categories based on the pore throat size, i.e. macropore, mesopore and micropore. Such pore size variation is a key parameter that controls oil/water displacement, especially when imbibition/drainage processes can frequently take place in a reservoir in conjunction with subsequent wettability alteration. This study evaluates the cross-correlation between the pore system, imbibition/drainage processes, wettability alteration and oil recovery by integrative core analyses. Two core waterflooding tests were conducted under different wettability conditions, such as water wet and oil wet. The oil recoveries were both high while there were some differences in the irreducible water saturation (Swir). The similarity and differences can be explained by the proposed pore system, which can control fluid flow based on the pore size.
Following the success of the first gas hydrate production test in JAPEC/JNOC/GSC Mallik 5L-38 Methane Hydrate Research Well in 2002, MH21 Research Consortium for Methane Hydrate Resources and Natural Resources Canada jointly conducted the second production test in the Mallik area, Northwest Territories, Canada applying depressurization method in the early April of 2007. During the twelve and half hours of the pump operation, at least 830 Sm3 of gas was produced from a gas hydrate bearing formation until the sand problem put an end to the production. The result brought us positive perspective about the applicability of the method, as well as many technical challenges.
The Shinzan Rhyolites are the uppermost part of the Monzen Formation and discordantly cover the Kamo Lavas of the same formation. The volcanic succession from the Kamo Lavas and correlative Kuguriiwa Lavas to the Shinzan Rhyolites has been accepted to range in isotopic age from 34 Ma to 24 Ma with a large time gap of 2 or 3 million years between the Shinzan Rhyolites and the underlying two units. This paper reports new isotopic ages of the Shinzan Rhyolites, ca. 34 Ma by Ar-Ar and K-Ar dating of biotite and ca. 37 Ma by fission-track dating of zircon. A new fission-track date of the welded felsic tuff from the Kamo Lavas is ca. 36 Ma. These new age data are mutually consistent and much more reliable than the ever-reported isotopic age, and obviously indicate that 1) the Monzen Formation is to be Late Eocene to Early Oligocene in age and 2) the time gap between the Shinzan Rhyolites and the Kamo Lavas should be much smaller than or negligible relative to the time span of the entire volcanic succession. The main part of the Shinzan Rhyolites would be slightly younger than the shallow marine Shiose-no-misaki Sandstone and Conglomerate (34-36 Ma) and perhaps demonstrates the Late Eocene to Early Oligocene rifting precedent to the rapid opening of the Japan Sea.