Unconventional oil and gas attract attention as next generation energy, because of their vast amount of resources. A part of the unconventional oil and gas has been already produced on a commercial scale, while the development of some of them is still in the stage of research. Reservoir modeling and simulation are now playing an important role towards the development planning for unconventional oil and gas. This paper first gives an outline of unconventional oil and gas, from the viewpoints of reserves, development/production methods and problems/challenges. Then, some examples of reservoir modeling and simulation specializing in unconventional oil and gas resources are introduced. Two main methods of cold production and thermal method are being applied to the development of heavy-oil/extra-heavy-oil/bitumen. For the simulation predicting cold production performances, it is requested to reproduce the incremental oil recovery due to foamy oil flow and wormholes. For the production by thermal methods, several innovative simulation studies are reported. Examples of such simulation include the automated optimization of steam injection strategies, reproduction of the combination of steam and solvent injection and thermal simulation of advanced in-situ combustion. For shale gas/oil development, reservoir modeling and simulation are focusing on the characterization of the area of high productivity (so-called ‘sweet spot’). To clarify the mechanism of fluid flow in sweet spots, sensitivity studies are conducted using not only simple double porosity/permeability models but also more complicated multi-porosity/permeability models. The research work for the development of methane hydrate has started recently. Although the superiority of the depressurization method has been revealed through numerical simulation, the recovery of methane by depressurization is predicted to be not more than 50-60%. The methodologies that can be applied in conjunction with and/or after depressurization are being pursued. Displacement of methane with carbon dioxide is expected as one of such methods.
Enhanced oil recovery (EOR) processes have been applied to improve mobility of heavy oil and bitumen. This article has introduced three topics on numerical models for heavy oil and bitumen productions based on laboratory measurements and their scaling up to field reservoir simulations using CMG STARS™. First one is CO2 gas foaming by depressurizing after immiscible CO2 dissolution in heavy oil. Saturated CO2 solubility and apparent swelling after foaming were measured on decreasing pressure processes using PVT apparatus and a high pressure cell. The numerical models of apparent viscosity and swelling ratio for foamy heavy oil have been proposed based on the measurement data and applied to a field scale oil-reservoir by Huff-n-Puff production method The second one is bitumen emulsion (water in oil) formed by the Steam Assisted Gravity Drainage (SAGD) method for oil-sands layers, because condensed fine water-droplets diffuse into bitumen at the steam-chamber boundary. The characteristic of heavy-oil viscosity was measured against water/oil ratio (W/O) and temperature. The model of viscosity ratio (emulsion/original) vs. W/O has been presented and investigated its effect on bitumen-production from a typical oilsands reservoir by SAGD method. Finally, it has been shown that cumulative bitumen-production increases with bitumen swelling function of W/O. The third one is heavy oil recovery by in-situ combustion with injecting air or O2 gas. Recently, the Toe-to-Heal Air Injection (THAI) method using a vertical injector and a horizontal producer is expected to be able to keep stable combustion front and oil drainage flow into the producer. Based on our numerical history-matching study on the tube combustion test for bitumen sands-pack, the reaction model consists from 3 major reactions were screened from 8 chemical reactions on Maltenes, Asphaltenes and Coke. Finally, the model was successfully applied to a heavy-oil in-situ production from a typical field oil reservoir.
Canada has the third-largest oil reserves in the world, after Saudi Arabia and Venezuela. Of Canada's 173 billion barrels of oil reserves, 170 billion barrels are located in Alberta, of which about 168 billion barrels are recoverable from bitumen. In 2012, 1.8 million bbl/day were produced from the oil sands of which 800,000 bbl/day was from mining and 1.0 million bbl/day were recovered by in situ techniques. Looking ahead to 2020, oil sands production will reach 3.2 million bbl/day by the end of the outlook. And in situ production is forecast to produce more than 2.0 million bbl/day. JACOS (Japan Canada Oil Sands Limited: subsidiary company of JAPEX) started their expansion project at Hangingstone lease in Alberta, Canada. The Hangingstone Expansion Project is a joint venture project to develop an area adjacent to the current Demonstration Project by JACOS and Nexen Energy ULC (Nexen) in which JACOS holds a 75% participating interest as the operator, while Nexen holds the remaining 25% interest. Completing the front end engineering design and obtaining Scheme Approval from the Alberta provincial government in November, 2012, the partners have commenced full-scale development work aiming at production start-up in 2016. The initial stage will result in bitumen production capacity of around 20,000 barrels per day. A decision on expansion of the facilities to bitumen production capacity of approximately 30,000 barrels per day will be made after start-up of the operation. Bitumen production will continue for around 30 years using the steam-assisted gravity drainage (SAGD) method, which has already been utilized at the Hangingstone Demonstration operation for more than 10 years.
Alberta Energy Regulator (AER) announced that Alberta's annual raw crude bitumen production will rise to 4,100,000 barrels per day by 2023 twice as much as 2,100,000 barrels per day of the present. It is an infallible situation to continue to put a lot of energy into production of bitumen as an Alberta state government. However, the production of bitumen is not easy because of its viscosity. A lot of steam is needed for production and diluents (such as condensate and naphtha) about 30 % of bitumen are needed for transportation. So the supply cost of bitumen is higher than that of crude oil. Moreover, much of diluent is import from U.S. and also a large number of the “Dilbit” (bitumen with diluent) are exported to U.S. As a result, increasing of production is dependent on U.S., so it is problem from a viewpoint of energy security in Canada. Partial upgrading technology is one of solution to the needs. Partial upgrading technology converts bitumen into synthetic crude oil which can be transported on pipeline. But synthetic crude oil is different from product of refinery such as gasoline. In the presentation, the Supercritical Water Cracking (SCWC) technology (one of the Partial upgrading technology) will be described for the one of solution for the needs. This technology is developed by Japan Oil, Gas and Metals National Corporation (JOGMEC) and JGC. It is focused on its merit and the present status of technology development.
Coal reserve of Japan is about 20 billion tons. A half of them is in Kyushu and the other is in Hokkaido. The most gassy coal field in Japan is Ishikari coal field in Hokkaido. In Ishikari coal field there were so many underground coal mines, but now all of them were closed. The gas content of coal in the Ishikari coal field is more than 12 m3/t and CBM resources in Ishikari coal field is estimated about 40 billion m3. There are some reasons why CBM has never been developed in the coal field. One is that the Ishikari coal field is mountain area and most of it is covered with National Forest. Therefore, it is difficult to find the drilling site from the surface and to develop CBM on a large scale. The other one is that it is difficult to drill wells in a soft coal seam such as Yuubari coal and to maintain the wells. Therefore, we are planning to develop CBM to use for local energy in this area.
In recent years, the exploration of unconventional shale gas has been active in North America and production amount is currently still increasing. Shale gas is a hydrocarbon generated by source rocks and it is remained in place without migration. Usually these source rocks are shale. Furthermore kerogen is present in the pores of the source rocks, and shale gas exists in the nm order kerogen nanopores. Since the nanopore diameter is small, it is necessary to consider different physical properties compares with the conventional gas. That is, knowing the adsorption and absorption properties of shale gas to kerogen and the flow properties of the gas in the nanopore inside kerogen are essential matters for the future exploration and development activities for shale gas. In order to understand details of these phenomena, we simulate the adsorption and absorption phenomena of methane molecules to the kerogen molecules by using molecular dynamics method. Also the flow of the methane molecule through the nanopores is investigated by molecular dynamics, and indicating the presence of a slip flow. In order to scale up molecular simulation results, lattice Boltzmann method is adopted. Through these, we tried to build a numerical modelling system that can reproduce the physical and flow properties of shale gas in the nanopores.
Soon after US shale gas revolution, Canadian shale gas development is also energized, especially in Western Canada. Canada has the advantage of availability of industrial equipment, materials and pipeline connecting to US due to the neighboring. On the other hand, rapid development may raise concerns over the issue of water management in the respect of usage and disposal. In British Columbia, Oil and Gas Commission is positively supervising and managing water usage with consideration for environmental impacts. And operating companies in Canada are also trying and developing new technologies and methods of production which can reduce usage of fresh water. In the shale gas project in Canada which INPEX is joining to, the operator is working on water management in advance of future fullscale development based on assessment of environmental impact, and has newly developed and tested fracturing pumping system which could provide a capability of utilizing raw water of non-potable deeper aquifer.