In October 1992, a Production Sharing Contract of Block 15-02, offshore southern Vietnam, was signed between Petro Vietnam (Vietnam State Oil Company) and ex-Mitsubishi Oil Company (present-Nippon Oil Company Ltd.). Following exploration activities, Rang Dong oil field has been tracking the phased development steps of increasing oil production level. A fractured reservoir in Granite basement is one of this field's characteristics, which shows severe uncertainty in the fracture distribution and connectivity. To mitigate the risk of these uncertainties, phased development, where reserve has been confirmed by pre-drilling, has been adopted. Also, extended reach horizontal drilling has become common for development well planning to penetrate multiple fractures to enhance well productivity. History of development of Rang Dong oil field to cope with its reservoir uncertainties and difficulties in increasing its production levels with increasing production facilities, is presented in this paper.
Bitumen from oilsands that has been regarded only as an alternative resource for the next generation in Japan is recognized as what makes up production decline of conventional petroleum resources at the North American crude oil market. One third or more of the total oil production in Canada is from synthetic crude oil based on the bitumen or the diluted bitumen. Therefore, the bitumen has already shown its presence and will no longer be called unconventional. The order of Canadian oilsand in-place is equal to that of Saudi Arabia's. The Energy Resources Conservation Board (ERCB) estimated that Athabasca area has 1, 600 billion bbls of bitumen in-place and it has been regarded as one of the largest hydrocarbon reserves in the world. The amount of reserves is formally evaluated as 175 billion bbls by ERCB and the Alberta Energy Utilities Board (AEUB) at present. Major oil companies are positively involved in the Canadian oilsand development as oil business, positioning it as one of the important investment options for making balance against the investment risks in geopolitically unstable areas, so that it is included in their global portfolios from a viewpoint of stable oil supply. There is a prediction that the bitumen production will reach two thirds of the oil production in Canada within a decade and will also increase three times by 2017. The huge amount of the bitumen reserves will fill the gap between supply and demand of the North American oil market. Athabasca may become one of the main production centers and the oilsand bitumen may be in a global portfolio of oil companies as a long-life and stable resource. Solutions to problems such as total process establishment, stabilization of netback bitumen price and gas price, and expansion of the market are breakthrough points to make the story much more realistic.
The Snorre field is located in the northern part of North Sea, about 150km west of Floroe on the Norwegian west coast and in water depth of 300-350 meters. The field was developed in two phases because of complex reservoirs. Stochastic reservoir modeling techniques were developed and applied for modeling Snorre field. Phase 1 was installation of the TLP (Tension Leg Platform) and 6km away, the subsea production system (SPS) in the southern part, and put on stream in August 1992 with water flooding as the primary recovery mechanism. Phase 2 was installation of a SSPV (Semi-Submersible Production Vessel) in the northern part, and put on stream in June 2001. For several years, gas injection was not applied, because only associated gas injection could not maintain reservoir pressure sufficiently. In February 1994, a WAG pilot test was initiated. WAG was well known techniques for improving oil recovery, but Snorre field was the first applied case in North Sea area. The evaluation of the WAG project showed that early gas break through might be a potential problem. Then, the use of foam for gas mobility control, gas shut-off and to improve of sweep efficiency had been considered as a means of improving the WAG process. Foam Assisted WAG (FAWAG) pilot test had been conducted in the period 1998 to 2001. For gas front monitoring, 4D (time lapse) seismic surveys were carried out in 1997 and 2001. These results were used for history matching of the reservoir simulation, and optimizing in-fill well locations. Horizontal wells were applied for both producers and injectors. And as an intelligent well completion, DIACS (Downhole Instrumentation And Control System) was applied for Snorre field. The functions of DIACS are not only monitoring the reservoir pressure/temperature, but also changing the downhole choke size.
In Middle and South America, demand for natural gas is growing rapidly due to the growth of electricity consumption and the general trend of shifting the source of energy from oil to gas. The governments in those areas are less protective in providing opportunities for foreign oil companies. In these circumstances, chances of realizing business opportunities in gas development projects are expanding. Teikoku Oil Co., Ltd. is expanding gas development business in Middle and South America area. In Venezuela, Teikoku has been operating oil fields in two blocks since 1992. In East-Guarico block, Non-associated gas production was resumed in 2000 within the operating block and currently 80mm scf/d of gas is being produced. Also in 2002, Teikoku farmed in two gas exploration blocks: San-Carlos and Tinaco and currently conducting exploration works. In Mexico, Teikoku has participated in two blocks for MSC (Multiple Service Contract) contract with Petrobras and providing development and production services for PEMEX. It is expected that the opportunities for foreign companies will be expanding in Mexico.
A small-scale hydraulic injection experiment was conducted in the Yufutsu gas field in October 2003, to see the feasibility of AE (acoustic emission) monitoring for the purpose of the fractured reservoir delineation. Although many success stories have been reported from the area of geothermal fields, none of the study in oil/gas reservoir has been done in Japan. This is the first experiment in oil/gas reservoirs in this country. We have succeeded in recording more than 450 of good quality AE signals by downhole sensors installed at 2, 700-2, 790m depths during the injection of 280 tons of brine solution into the depth interval 4, 412-4, 995m in the gas saturated reservoir. As the results of AE analysis, it becomes clear that the distribution of the AE events has close relationship with the distribution of pre-existing fractures along the well and that the shearing associated with AE events improves the injectivity of the injection well. The results of the field experiment were discussed through numerical simulations by using the "SHIFT" that simulates the shearing of fractures and relating permeability changes. The simulated results show a good matching in the pressure response and the AE activity, and provide us with useful understandings of the dynamics of the reservoir.
Dimethyl ether (DME) is currently used as propellant of spray can, while it could be a clean and economical alternative fuel if it is produced in a large quantity at low cost. The properties of DME are similar to those of LPG and it can be used for various sectors; household, transportation, power generation, etc. DME direct synthesis technology, synthesize DME directly from synthesis gas (hydrogen and carbon monoxide), not via the conventional methanol dehydration process, has been developed by JFE Holdings Co., Ltd. as a large scale, at low cost DME production method. The 100 tons/day DME direct synthesis demonstration plant project, subsidized by METI Japan, is being carried out by DME development Co., Ltd. from 2002 to validate newly developed DME direct synthesis technology to apply DME commercial production. The demonstration plant has been completed in November 2003 and plant operation is now in progress, and will continue till mid 2006. In this paper, feature of newly developed DME direct synthesis technology, results of the first stage plant operation, and belief results of a feasibility study about DME commercial production from natural gas are described.
Time-lapse seismic changes can be compared with pressure and/or saturation changes derived from a flow simulator by using petro-elastic model. As the number of seismic data is huge and it has a 3D character, it is expected to be a great help to condition the reservoir model. An (automated) history matching loop comprises the following four stages: 1) parameterization, 2) objective function definition, 3) optimization and 4) loop-stopping criterion. Focusing the objective function, the brief explanation of some element technology is done. With the introduction of time-lapse seismic as an additional constraint, history matching is performed to construct a more reliable reservoir model, which can be used to predict a future oil production. The impact of data integration on production forecasting uncertainty is analyzed. The synthetic model used representative for a gravity fault system, such as East flank of Statfjord field. By changing the constraining data, i. e. time-lapse seismic and production data, its impact on the probability density function (pdf) of the future cumulative oil production (FCOP) can be quantified. The variance of FCOP-pdf is reduced and the maximum pdf value is increased by adding extra information to the reservoir model. For this specific synthetic model, the seismic data gives a reservoir model with a higher probability than the production data. The most probable models are obtained when conditioning the reservoir model with both types of data.
JNOC (Japan National Oil Corporation) has been evaluating "geologic chance of success (i. e. probability of finding oil or gas)" and "probabilistic reserves distribution" for exploration prospects since 1997 and has been carrying out post audit to compare the results with predictions to improve qualities of the evaluation since 1999. This paper introduces the overview of results of the JNOC's geologic risk evaluation over more than five years. Post audit has been recognized as an important process to monitor and improve evaluation accuracy in the prediction of geologic risk. Four main factors/indicators have been compared between predictions and results in JNOC's post audit: (i) predicted versus actual success ratios, (ii) predicted critical risk versus actual failure reason for dry holes, (iii) expected reserves for each prospect versus size of discovery, and (iv) expected reserves for the portfolio versus actual amount of discoveries.
Planktonic foraminiferal biostratigraphy is established for the late Pliocene Yabuta Formation exposed in the Yabuta, Kosugi and Oosakai sections in the Himi-Nadaura area, Toyama Prefecture, central Japan. The Orbulina universa/Globorotalia ikebei Zone (PF6) and the Neogloboquadrina pachyderms (dextral)/Globorotalia orientalis Zone (PF7) of Maiya (1978) and Miwa et al. (2004) are recognized in the Yabuta Formation. In addition, No. 3 Globorotalia inflata bed which is characterized by the abundant occurrence of G. inflata group (G. orientalis and G. inflata praeinflata) is identified in the Yabuta Formation. The base of the No. 3 G. inflata bed lies between the first occurrence of Neodenticula koizumii (diatom, 3.5Ma) and the rapid increase of N. koizumii (3.0-3.1Ma), and dated at about 3.25Ma by interpolation.
Two well-known bell-shaped curves in the disucussion of petroleum resources, namely the "Hubbert curve" for production history and the log-normal curve for field size distribution were examined. The conclusion was that other curves are considered to be more appropriate for these purposes and its implication in the future of petroleum resources was discussed. The resulting ultimate recoverable resources were estimated to be 3-4 trillion barrels.