Most sedimentary basins of the world have already been maturely explored, and the competition in acquiring exploration acreage and development assets has become very severe. To cope with this “age of maturation and competition”, decision making in various exploration and development stages is examined scientifically and quantitatively to avoid heuristic bias. This includes optimum bidding method, quantification of dominance in joint venture, sequential POS correction, value of information, correction of bias in reserves estimation and exploration risk management. These methods and techniques will guide us in establishing rational and effective strategy, and make petroleum exploration a profitable business, even in this “age of maturation and competition”.
Geophysical exploration technologies have been developed through several innovative steps in the history. Data acquisition and processing technologies evolved since 1960s. Since 1980s, these technologies started to be integrated first to reservoir description, then to reservoir modeling (characterization), and recently to reservoir management technologies. These developments have taken place due to the recent tendency to have their target structures in smaller scale or more complex than it used to be. We may summarize these technical developments as follows : a) 3D to 4D data acquisition to realize reservoir management, b) 4-C marine data acquisition (tri-component geophone and pressure gauge), c) single sensor acquisition supported by well-developed multi-channel signal processing techniques for true amplitude recovery without any instrumental spatial filtering, d) new acquisition technologies such as fiber-optic sensor arrays. We believe that further new development would surely be attempted to satisfy the needs to visualize underground structure, to understand what is on-going for the state of natural resources under development, and to enhance our management capabilities to control the production from existing reservoir.
In geologic time scale, flow of secondary migration of hydrocarbon is controlled by capillary (resistive) and buoyancy (driving) forces. The relationship between capillary threshold pressure of formation and buoyancy of hydrocarbons is considered as one of the most important aspects for petroleum system analysis. As high quality 3D seismic data is acquired in common, high resolution 3D basin simulation of capillary-dominated multi-phase flow regimes is the effective technique to realize the generation, migration and accumulation of hydrocarbons in reservoir scale. Two case studies are carried out to reveal the usefulness of 3D basin simulation in reservoir and new exploration ideas based on the seal evaluation. Case studies indicate that the invasion percolation for simulation algorithm enables to realize the migration pathways controlled by sand distribution, seal capacity and trap geometry. Working hypothesis of Matryoshka pressure model also enables that the reevaluation of the pressure data in discovered fields will produce some remaining exploration potential, even in mature fields and basins.
Integrated geological and geophysical study was carried out using newly acquired 3D seismic data in order to evaluate further exploration potential for sandstone pinch-out traps, offshore Kitakanbara, Niigata, Japan. The 3D seismic PSTM negative amplitude was useful for predicting the sandstone distribution in spite of the dominant frequencies as low as 10-12Hz. Depositional systems of the turbidite successions were estimated in sequence stratigraphic framework by integrating thickness, seismic amplitude and seismic facies maps which were calibrated with depositional facies associations defined in the wells. A deductive hydrocarbon migration simulation was then carried out for the purpose of migration and seal risk assessment. The study highlighted hydrocarbon accumulation to sandstone stratigraphic traps in downdip portion of structural highs. During a series of study, Stratimagic and MPath applications played an important role as new technology tools for seismic facies mapping and hydrocarbon migration evaluation, respectively, especially in combination with 3D seismic data.
Hydrocarbon was discovered in the Astero structure located in the northern part of Norwegian North Sea. The reservoir, Oxfordian turbidite sandstone, is also reservoir of a nearby field and commonly indicates Class-IV AVO anomaly. The sandstones can be separated based on the type of fluids on the cross-plot of well-based AI vs. Vp/Vs. Since the structure is compartmentalized with different contacts, in-house seismic inversion was planned and carried out for investigating the hydrocarbons in place. Seismic data used in this study was acquired in 1992. Offset records (Near-, Middle- and Far-offset) re-processed in 2005 were used in this study. Hampson Russell's software was used in the inversion and the model base inversion was adopted. A low AI zone is generally expected to suggest possible hydrocarbon bearing reservoir. AI results in this study, however, do not have enough vertical resolution to separate sandstone with different fluids. Most of the low AI zones extend further deeper depth than the OWC confirmed by the wells. On the other hand, generally low Vp/Vs ratio is observed in the sandstone interval and does not show difference in different fluids. A 3D cube multiplying AI and Vp/Vs was made to predict spatial variation of the reservoir quality. Based on the cross-plot of AI and Vp/Vs of the well data, hydrocarbon-bearing sandstone has lower AI and Lower Vp/Vs and could be emphasized in this product. As a result, sandstones are fairly well separated by this product from over- and under-lying shale. Sandstones with different fluids, however, are not distinguished. This is partly because that the thickness of the hydrocarbon bearing zone is as thin as a half dominant wavelength. There is a well which penetrated the equivalent Oxfordian sandstone 5.5km away from the discovery well. In this well, the Oxfordian sandstone becomes thin and is cemented by calcite. The product of AI and Vp/Vs seems to indicate changes in the reservoir quality as well as thickness between these two wells and shows potential being utilized in the lithostratigraphic interpretation and geo-model construction, etc..
It is a key to identify the distribution of multi-reservoir sand layers for exploration and development of Copa Macoya gas field in East Venezuela basin. However, it is difficult to estimate reservoir distribution because the each target sand layer is not thick enough to be detected by the limit of seismic resolution. In addition, synthetic seismograms cannot be tied with surface seismic data because well logs are distorted by borehole washouts, formation damage and other factors. In order to address this problem, damaged data was corrected by applying correlations of highest quality well log data obtained from the surrounding wells, and then pseudo logs were drawn. By using these corrected data the correlation between seismic and synthetic seismograms was improved. These data were used to define lithology index (LI) based on rotation of coordinate axis, using the relation between acoustic impedance (AI) and shear impedance (SI) as an attribute to delineate between sandstone and shale. Next, simultaneous inversion was carried out and LI volume was determined from AI and SI volumes. The LI volume was then processed with spectral whitening in order to improve the resolution of the result of the inversion. In this research, distribution of sand layers was studied by using high resolution LI volume. As a result, distribution showed better correlation with well data than in the past for some of the sand layers. However, the anomalies that indicate the distribution of sand layers in this study area could not always be obtained, because of the limitation of the methodology applied in this study.
Japan Vietnam Petroleum Co., Ltd. (JVPC) discovered oil accumulations in the Lower Miocene sandstones and the fractured granitic basement at the Rang Dong structure in Block 15-2, offshore S.R. Vietnam in 1994 and started oil production in 1998, and phased-mannered field development has been implemented due to the uncertainty in reservoir extent and connectivity. The Lower Miocene Reservoir consists of thin alternations of sandstone and shale which is supposed to be deposited in marginal area between terrestrial and marine environment. As the field development proceeded, it became evident that reservoir quality differs more than expected. A major focus of reservoir management therefore has been to place new development wells in optimal locations in order to increase the well productivity of development wells. And as one of new technologies, geosteering technique was introduced. The keys to the success of the well placement are understanding of the field, preparation prior to drilling, continuous interpretation of the real-time data while drilling, integrated teamwork at the well-site and good communication with office for the fast and consented decision. In addition to these essentials, real-time resistivity image, which is newly introduced to JVPC together with standard LWD data, provided helpful information to understand “where and how we are drilling”. The well trajectory was modified on real-time if required based on the interpretation of these data, the correlation with offset wells and geological models. A series of wells have been drilled with this process and achieved significant improvement of well productivity. This paper demonstrates recent geosteering examples and the results in the Rang Dong Field.
In the Gulf of Thailand oil- and gasfields, natural gas exploration proceeded in the 1970s and commercial gas sourced from Miocene coal beds (Unit 3) came on stream in 1981. In the 1990s, crude oil from Oligonene lacustrine source (Unit 1) was discovered and lead to commercial development. Oil and gas in the Gulf of Thailand are accumulated in numerous Miocene fluvial sandstones, which are complexly separated by numerous normal faults. Through exploration and development history in such fields with complex geology, 3D seismic technology, slim hole infill wells and crude oil development played significant role. In addition to the operator's efforts during the history, MOECO has been performing its own in-house studies during the time. Among those studies, Fault Seal Analysis is focused in this paper. For the study, “Faultap” PC-based software was used as a tool for analyzing petroleum migration systems that formed complex oil and gas accumulations. In the study, “Juxtaposition Diagram (Allan Fault Diagram)” and several fault seal parameters were investigated, and it was recognized that “FSFP” (Fault Seal Failure Probability) is the most useful parameter in the studied field.
The Shiose-no-misaki Sandstone and Conglomerate (SSC) in the Oga Peninsula is believed to represent a latest Eocene to early Oligocene marine succession located on the back-arc side of NE Japan. This unit is, however, isolated from adjacent units, and its stratigraphic position has remained in debate. On a sea cliff adjacent to the type locality of the SSC, surface soil and vegetation recently slid down by heavy rain to disclose a succession that contains the SSC and the overlying early Miocene non-marine unit correlative to the Daijima Formation. The SSC at the new outcrop comprises scorialapilli tuff and parallel to wavy laminated fine sandstone, both of which are intruded in dike by thinly bedded pumicelapilli tuff, pumice-bearing tuff, sandstone and mudstone as observed also in the adjacent SSC. The overlying succession is over 20 m thick and dominated by massive very coarse to coarse sandstone with a basal, normally graded cobble to granule conglomerate 1.3 m thick. Pumice lapilli tuff occurs between the conglomerate and the overlying sandstone with a thickness of 30 cm, and tuffaceous mudstone and coaly shale beds 20 to 30 cm thick occur in between the sandstone. The conglomerate and sandstone commonly contains gravels and/or sand grains of dacite welded tuff derived from the adjacent early Miocene Hokakejima Dacite (the lowest unit of the Daijima Formation). Pumice lapilli tuff in the upper unit is 20 Ma in FT age, suggesting slightly younger than the FT ages of 22-21 Ma for the Hokakejima Dacite. The pollen assemblage from the SSC likely reflects a cool temperate climate that might have prevailed in accordance with Oligocene to Early Miocene cooling. We thus suggest the SSC is a part of the late Eocene to early Oligocene Monzen Formation extensively distributed to the west of Cape Shiose-no-misaki.