In 1986, the number of EOR projects were boosted upto more than 500 in the USA, which produced about 600, 000 b/d of crude oil and occupied 7% of the total oil production. According to the unfavourable low price environment during the past decade starting 1986, however, the number of new EOR projects started to decline. But the oil production from EOR continued to increase slowly and steadily. In early 1996 the world produces oil from EOR at 2.2 million b/d which is as much as 3.6% of the world crude oil production and about 33% of which, namely 724, 000 b/d is shared by the USA. Thermal recovery methods such as steam flooding now occupies 60% of the total EOR production and gas flooding such as CO₂ injection is gaining momentum and shows promise for further gains. But chemical flooding has suffered from less interest and less additional oil production.
This paper reviews definitions of EOR and IOR terms because the latter word has been widely prevailed in oil operations in North Sea, Canada and Alaska during the last decade. Although recent cost data on EOR and IOR are scarce in literatures, several available cost data are presented in this paper. Finally the author proposed several subjects relating to future IOR/EOR technology development for Japan to be implemented in order to secure stable supply of crude oil in the course of the 21st. century.

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TRC has been studying the Microbial Enhanced Oil Recovery (MEOR) process since 1987. Now, TRC is planning a field trial to promote our MEOR study to the next stage. As a target of MEOR application, a shallow oil field which has been under waterflood for over 20 years has been selected. In the technical feasibility study, adaptabilities of microbes to the field were investigated to select candidate microbes for injection. Effects of reservoir conditions, namely, reservoir water, temperature, nutrient, additives and original microbes in the reservoir, on the microbial growth and their metabolism were tested. A field trial will start in late 1996 to prove these laboratory results.

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Crude oil (bitumen) in oil sands is extremely heavy and the API gravity of the bitumen is usually around ten degree or less. The viscosity varies from 100, 000mPa•s to 8, 000, 000mPa•s at reservoir condition. Due to this remarkably high viscosity and low gas solubility, conventional methods of recovery are not applicable. Thermal techniques aim at reducing oil viscosity in order to increase its mobility, through the application of heat.
The oil sand deposits in Alberta of Canada contain about 270 billion cubic meters of bitumen and are expected to play an increasingly important role in the Canadian and world energy picture in the near future.
SAGD (Steam Assisted Gravity Drainage) process is a newly developed thermal recovery technique with a pair of horizontal wells, originated by Dr. Butler in 1978. The pilot test has been conducted at UTF (Underground Test Facility) project in Alberta province by using SAGD process since 1987. The production performance of the pilot test wells is actually much better than that of the wells of the commercially operated projects such as Esso's Cold Lake, Amoco's Wolf Lake and Shell's Peace River.
This paper introduces the UTF project and explains the drilling method of a pair of horizontal wells and the basic mechanism of SAGD process comparing with CSS (Cyclic Steam Stimulation) process which is a conventional thermal technique in bitumen recovery. It also discusses the economics of the existing commercial projects and the future commercial projects by SAGD process.

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The comprehensive reservoir study for the First and Second Bahrain Sand reservoir has been performed utilizing the existing simulation models. But it has been realized that the models do not have sufficient capability to predict the detailed water flow behavior and hence water production performance partly because the available models were constructed using the relatively simplified geological models and partly because fluid flow behavior has not been fully examined. In order to improve calculation accuracy and predict water production performance accurately, therefore, it was decided to construct new reservoir simulation models for both reservoirs based on the newly evaluated detailed geological models.
To construct the detailed geological model, the concept of the sequence stratigraphy and sedimentological log facies analysis were applied to the interpretation of the frequent lateral lithological changing fluvial complex.
Before re-constructing full-field models, the regional model study to construct a sector model which covers about 2km×4km area in southwest part of Second Bahrain Sand reservoir was performed in order to recognize how fine grid model based on the detailed geological model can simulate formation water behavior.
This report describes the regional model study.

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Large hydrocarbon deposits occur in deep-seated volcanic rocks of the Middle Miocene age in Minami-Nagaoka gas field, Japan. As a consequence of repeated volcanisms, rhyolite eruptiots were deposited one after another forming a thick formation with a rapid change of rock facies, each of which exhibits a different degree of natural-fracture development to another.
Most of the wells drilled in this field yield heterogeneous behavior during pressure tests, to which several interpretations are possible and no unique reservoir model can be determined through the limited information of pressure transient data. To overcome this difficulty another set of information is desired, and production loggings are conducted during production and shut-in periods. Crossflow through the wellbore is quantitatively detected through production-log analyses ; and, thus, a layered reservoir model appears to be a good idea to describe the subject formation. This paper describes the comprehensive approach that combines pressure-transient analyses and production-log analyses to characterize the thick volcanic formation with severe heterogeneity.
A systematic and comprehensive approach presented in this paper is applicable to any thick formation with vertical heterogeneity.

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With hostile drilling environment, multi-performance has been required for tubular connections in addition to conventional performance, so premium connection with metal-to-metal seal has become popular. This paper deals with the performance properties of tubular connections used in typical oil and gas wells, and describes the appropriate make-up operation and the torque resistance of the connections.
The make-up torque was measured in the laboratory under the simulated field operations. The connection performance was evaluated using the full-size combined loading tester under the simulated conditions of hostile wells such as horizontal wells, sour service wells, and steam injection wells.
As for the results of the test, the make-up torque increases when the grease quantity is small and the temperature is low. In wells, the torque resistance of the connection improves under axial loading, pressurizing, and bending. The joint strength of Round connection is lowered by bending, though that of Buttress and premium connection is not degraded. However, the joint strength decreases in direct proportion to the wear area ratio of the pipe body. Bending moment is not more detrimental to sealing integrity than the axial loading. In sour service wells, there are some possibilities of SSC occurrence at the coupling, so the casing design is required to control the hoop stress on the coupling less than the threshold stress. In steam injection wells, the casing pipe is deformed by the excessive axial load due to the thermal expansion and only the premium connection can maintain the gas tightness.
In conclusion, the make-up torque can be stabilized by solving the effects of operation factors, and the connection performance described in this paper may be effective for planning a more economical and reliable casing design in oil wells. Dope of the sufficient compound grease, avoidance of the low temperature make-up, and usage of the weight compensator are recommended to avert some make-up troubles.

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Stochastic models of petroleum reservoir geological attributes are used in reservoir studies to: (i) generate effective reservoir properties at the reservoir gridblock scale; and (ii) assess uncertainty in reservoir performance forecasting. The present paper formalizes the methodology in terms of transfer functions and introduces an alternative implementation of the sequential indicator simulation algorithm based on relative indicator variables. In addition, the determination of effective block permeabilities from stochastic images of point support-scale permeability fields is presented in the context of generalized power averages. Applications of the above are demonstrated in the simulation of reservoir lithofacies and gridblock permeabilities. The effects of stochastic imaging and reservoir characterization in assessing reservoir forecasting are illustrated.

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