|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Two of the world's wealthiest men have put their vast resources behind what the nuclear industry calls small modular reactors (SMRs) in the quest for the perfect carbon-free energy source. TerraPower, founded by Bill Gates, and PacifiCorp, owned by Warren Buffett's Berkshire Hathaway, are sponsors of the project. The first SMR from TerraPower, the Natrium reactor project, will be built in Wyoming--the nation's primary coal producer--at the very location that once housed a coal station, where the infrastructure for a steam-cycle power plant and distribution to the electrical grid already exist. Last year, the state legislature passed a law authorizing utilities to replace coal or natural gas generation with small nuclear reactors and the US Department of Energy awarded TerraPower $80 million in initial funding to demonstrate Natrium technology; the department has committed additional funding subject to congressional approvals. Just ask anyone in Texas where a combination of frozen wind turbines and unprecedented demand last winter darkened the state for days.
POWER FROM RESIDUES THE SNAMPROGETTI EXPERIENCE ON IGCC Guido Collodi Snamprogetti, Italy Introduction The three Italian IGCCs (Integrated Gasification Combined Cycle) from refinery residues (ISAB, SARLUX, API) are in commercial operation, having passed most of the contractual test-runs. This paper will give an update of the commercial status of ISAB Energy (approx. 510 MWe) and Sarlux (approx. 550 MWe), i.e. the two Italian IGCCs built by Snamprogetti in consortium respectively with Foster Wheeler Italiana and with Nuovo Pignone/General Electric. ISAB Energy has been the first Italian IGCC to go in commercial operation and has been taken over by the Owner on April 2000, while for Sarlux this happened on January 2001. The Two Projects The main features of the two IGCC are herebelow reported: Isab Energy The guaranteed electrical production is approximately 510 MWe from asphalt gasification (approx. 130 t/h). The project is executed by a Consortium formed by Snamprogetti and Foster Wheeler Italiana. The split of work between SP and FWI is "vertical" for the engineering and procurement activities, while the construction, commissioning and other field activities are directly under the Consortium responsibility. The Combined Cycle Unit is supplied ready at site by Ansaldo Industria. Sarlux The guaranteed electrical production is approximately 550 MWe with co-production of approximately 40,000 Nm3/h of Hydrogen and 180 t/h of medium and low pressure steam. The normal feedstock to the gasification is Tar (approx. 150 t/h). A Consortium formed by Snamprogetti with Turbotecnica (Nuovo Pignone) and General Electric executed the project. The split of work among the parties is completely "vertical" being SP responsible for the supply of the process and utilities units, and NP/GE for the combined cycle. When the two IGCC are in operation, their total power production of more than 1000 MWe corresponds to about 3.5% of the Italian production, on annual basis. Isab Energy And The Integrated Gasification Combined Cycle (IGCC) configuration is shown herebelow in the Sarlux: Main Dif- ferences Process Block Diagram and is known to this audience (see for example the paper presented last BLOCK 2 -- FORUM 12 497 POWER FROM RESIDUES THE SNAMPROGETTI EXPERIENCE ON IGCC year - Reference 1). It is very similar in both Italian Snamprogetti projects. The main differences will be highlighted in the text. IGCC Complex Process Block Diagram SOLIDS TO DISPOSAL WASTE WATER TO AIR WASTE WATER SULPHUR BIOTREATMENT AIR OXYGEN SULPHUR SEPARATION PRETREATMENT RECOVERY UNIT NITROGEN (STEAM TO EXPORT) HYDROGEN SULPHIDE FEEDSTOCK SYNGAS GAS COOLING SULPHUR FEEDSTOCK PREPARATION GENERATION AND AND COS REMOVAL SOOT EXTRACTION HYDROLYSIS STEAM BOILER FEED ELECTRIC (EXPANDER) POWER COMBINED CYCLE SYNGAS (HYDROGEN (STEAM TO (HYDROGEN) EXPORT) UNIT SATURATION PRODUCTION) DEMIWATER (SYNGAS TO POST FIRING) DESALTED DEMIWATER WATER PRODUCTION Fig. 1 · The oxygen necessary for the partial ox
The Philippines, by the end of 1980, has attained 446 MW of installed geothermal power generating capacity. This ranks second, after the United States, among countries g geothermal energy for power generation.
In the 5-year (1981-1985) national energy development programme, it is envisaged that additional generation units will be installed to increase the share of geothermal from the present 9.8% to 18.6% of the nationwide power generation, or to 16.58 million barrels-of-oil equivalent. power generation, or to 16.58 million barrels-of-oil equivalent. How the Philippines in such a short time to be a leading user of geothermal energy and the reasons for optimism as to its further development are. The strategies that went into its rapid development and which will be relied on for the expansion programme are presented and rationalized.
For a country that does not produce its own oil, the Philippines has, as we have found out later, unwisely placed too much reliance on petroleum for the energy needs of the country. Up to 1979, about petroleum for the energy needs of the country. Up to 1979, about 93-95% of the country's energy needs was supplied by oil.
When the oil crisis commenced in 1974, the Philippines embarked on an energy strategy designed to reduce dependence on petroleum. The first approach to this philosophy works in the energy supply side mandating accelerated diversification from depletables to alternative sources of energy with emphasis on indigenously abundant and regenerative forms. To achieve this supply objective of the government, geothermal was tapped as one of the major indigenous sources of energy.
This paper will demonstrate why the Philippines has put a lot of confidence on her geothermal resources.
Geothermal studies in the Philippines were initiated by the Commission on Volcanology in Tiwi, Albay in 1962, with research funds provided by the National Science Development Board. Very limited provided by the National Science Development Board. Very limited in-house expertise was relied on to carry out the research project while a few qualified people undertook crash training in geothermy in New Zealand and Italy.
On April 12, 1967, for the first time in the country, an electric bulb was lighted using geothermal energy. One of the shallow gradient holes managed to bring up steam and with a small borrowed turbogenerator, electricity was generated. That initial success provided the impetus to carry the research undertaking forward. The next step was the completion in 1968 of a larger well at a depth of 641 feet. A 2.5-KW geothermal pilot power plant was then tapped to this well for demonstration purposes. The well, after 13 years, is still alive and is also now being used to evaporate sea water in connection with a pilot salt-making plant.
By 1970, the Government, recognizing the benefits that can be realized from geothermal energy ordered the National Power Corporation (NPC) to develop and exploit the Tiwi field. Because of very limited skilled manpower locally available to carry out the massive undertaking, a service contract was entered into in 1971 by the Corporation with Union Oil of California through its subsidiary, the Philippine Geothermal, Inc. for the latter to develop the steam field while NPC put up the necessary generating plant. This important decision somehow prepared the country when the energy crises of the seventies came.
The Philippines began using geothermal energy commercially in July 1977 with the operation of a 3-MW geothermal pilot power plant in Tongonan, Leyte. The steam was supplied from one of plant in Tongonan, Leyte. The steam was supplied from one of the wells drilled by PNOC-Energy Development Corporation (EDC). However, it was only in 1979 that large scale geothermal power was started to be harnessed in Tiwi, Albay and Mak-Ban, power was started to be harnessed in Tiwi, Albay and Mak-Ban, Laguna. Two 55-MWe plants were commissioned in each of these areas, adding 220 MWe of generating capacity to the Luzon grid and displacing 2.73 million barrels-of-oil equivalent in 1979. This was followed in the ensuing year by an additional two 55-MW plants each in Tiwi and Mak-Ban and two 1.5 MW pilot plants in Palimpinon, Southern Negros, placing the total geothermal power Palimpinon, Southern Negros, placing the total geothermal power generation capacity to an amazing 446 MW by the last quarter of 1980. This means a displacement of about 5.5 million barrels-of-oil equivalent which at the current crude oil price means a savings of US $176 million annually in the country's foreign currency reserves.
With 446 MW of installed capacity, the Philippines now ranks second among countries using geothermal energy, surpassed only by the United States. The Philippines, however, is now the largest developer of the hot water-dominated type geothermal reservoir, even surpassing New Zealand who pioneered the utilization of this type of resource.
The 1973-1980 Energy Scene
There was perhaps no single event of international import in the last decade that could compare with the energy crisis of 1974. It brought drastic and serious economic dislocation to develop and developing countries alike and clearly demonstrated the mistake of overdependence on foreign sources of energy. For the Philippines, it provided one of the more severe tests in resent times of the nation's economic and political resilence.
A clear view of the energy scene emerges when we look at the country's energy mix (Fig. 1). On a sectoral basis, industry uses almost 43% of the total energy consumption followed by transportation amounting to about 36%. From another viewpoint, power generation consumes about 33% of the energy supplies. Looking at the sources of energy supply, it is seen that geothermal presently delivers about 4% of the country's energy needs. This is translated into 446 MW of installed capacity.
The Philippines is committed to a program of industrial and economic growth. On this assumption, there is little choice but to consume more energy commercially. An interesting picture comes up when we look at the percentage contribution of industries to GNP accounts and energy consumption per capita (Fig. 2).
Detection and evaluation of abnormal formation pressures is critical to exploration, drilling, and pressures is critical to exploration, drilling, and production operations. production operations. Occurrence and distribution of abnormally high formation pressures encountered in the exploration for hydrocarbon resources has been studied on a regional basis in the Northern North Sea. Detailed data on subsurface pressure environments encountered in wells drilled in Norwegian and U.K. waters are presented for the Viking Graben, East Shetland Basin and the Bergen High.
To date, more than 200 wells have been drilled offshore in the Norwegian North Sea (Figure 1). Most of the wells have encountered abnormally pressured formations of almost all geological ages (Figure 2). Overpressures occur in the Tertiary (Miocene through Paleocene) as well as in both Upper and Lower Cretaceous and certainly in the most important exploration target these days, the Jurassic. Ambitious casing programs are needed, continuous pressure follow-up and monitoring of drilling parameters are essential to safely reach these targets. Since distances between wells are great, the need for a regional understanding of the origin, occurrence and distribution of overpressure regimes is important. This paper presents a first attempt to understand geopressures in the Norwegian North Sea. It is based on analysis of pressure information available for more than 60 offshore wells. Data from RFT, FIT, DST and leak-off tests, lost circulation, kicks, drilling parameters and well logs has been compiled and provides the backbone for this discussion.
REGIONAL SETTING OF STUDY AREAS
Based on the present exploration activity the Norwegian North Sea has been divided into two different areas, Region I in the south and Region II in the north (Figure 3). In the south (Figure 4), exploration interest has been rekindled and present exploration drilling is targeted for the Upper or Middle Jurassic in areas where the well known Danian-Maastrichtian reservoirs of the Ekofisk-type are already producing. In the north (Figure 5), which includes the Murchison, Statfjord, Brent, and Frigg field areas, through still south of the 62 degrees latitude, the main exploration effort takes place. Important hydrocarbon discoveries, such as the 3 1/2 gas discovery and the 34/10 ("Golden Block") oilfield, still encourage continuing exploration drilling.
Southern Study Area - Region I
The Central Graben is the dominating tectonic feature (Figure 4). Salt domes originated from the Zechstein salt formation have penetrated the younger sediments and the well established hydrocarbon-bearing formations are chalks of Danian Maastrichtian age. More recently the Jurassic has also proven to be of interest. Encountered at depths between 3500 to 4000 m, it is overpressured. In the south pressure gradients in the order of 1.95 to 2.0 g/cc MWE (i.e. mud weight equivalent) have been encountered. The Cretaceous is a limestone-chalk section and contains the important reservoirs of the Ekofishtype. Depths range from 3000 to 3200 m and the formations are overpressured up to approximately 1.4 to 1.5 g/cc MWE.
American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. This paper was prepared for the Oklahoma City SPE Regional Meeting, to be held in Oklahoma City, Okla., March 24–25, 1975. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract Production of geothermal energy in the U.S.A. to date is 410 MWe. On an "accelerated program", this is to increase to 20,000 MWe by the year 2000. The geothermal projects that will contribute to this growth include dry steam fields, hot brines, moderate temperature/low salinity fluids, geopressured reservoirs, hot dry rock, and magmatic deposits. Introduction The contribution of geothermal energy to the total current U.S. energy needs is 410 MWe. This is approximately equivalent to a daily oil production of 16,400 bbls. per day. This amount of energy is less than .1% of the U.S. daily oil consumption. The Federal Energy Administration (FEA) was asked to compile a report on what can be done in all energy fields for the U.S. to become energy self-sufficient by the year 1985 with projections to the year 2000. The FEA asked the National Science Foundation (NSF) to compile a portion of this Project Independence Report concerning Geothermal Energy. Geothermal energy production is very small at present and will not progress at sufficient speed without being accelerated on a large scale to be a significant part of "Project Independence" by 1985 and 2000. The nest projections were made on business-as-usual condition. This would mean that private industry would continue its current pace using present guidelines, procedures, and practices. The projections were finally procedures, and practices. The projections were finally estimated on an accelerated program. This means that a Federal research program would assist private industry in solving the problems that currently inhibit or restrict their current exploration efforts.