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a close matching of output to local demand (removing the cost of transmission), small-scale tidal power could have a very bright future, particularly in South America and the Asia-Pacific region, where grid connection is a major structural issue.
Wave energy
In the wave energy sector, a number of devices have been designed and deployed, but no one device has yet to reach either universal acceptance or widespread commercial use.
The last decade has, however, seen significant developments in efficiency and reliability that have brought wave energy from a conceptual to a development phase in its progress to commercialization.
There is also growing local, national, and international support for the fledging industry that should lead to competitive commercial applications before 2010.
The UK and Japan have dominated the development of wave energy devices over the past 15 years and currently account for over 60% of worldwide development expenditures.
The UK industry has recently been boosted by the announcement that Europe's largest dedicated research facility is to be built at Blyth in Northeast England. Containing a large converted dry dock, the facility is capable of testing full-size devices of up to 30 kw.
The submarine windmill, proposed by the UK company Marine Current Turbines Ltd. (part of IT Power), consists of an axial flow rotor of 15-20 m in diameter, which drives a generator via a gearbox much like a hydroelectric turbine or a wind turbine. The power unit is mounted on a tubular steel monopile just over 2 m in diameter. Fitted with a patented lifting device that raises the turbine out of the water for servicing and maintenance, this variant of the tidal turbine is rated at 600-1,000 kw. Image courtesy of MCT.
Geothermal energy
Perhaps the best-known example of geothermal energy use is in Iceland, where it is the second-largest source of energy. Reykjavik, with a population of more than 145,000, pipes hot water to every house at a cost lower than cold. water.
The global potential is spread quite evenly across the regions, although realizable prospects are likely to be concentrated in Europe, Asia, and North America. However, as a result of an extensive research and development program, the US has the largest quantifiable resource.
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Hydrothermal reservoirs are large pools of steam or hot water trapped in porous rock. To create electricity, the steam or hot water is pumped to the surface, where it drives a turbine that spins an electric generator. Because steam resources are rare, hot water is used in most geothermal power plants.
Steam and hot water power plants use different power production technologies. A standard geothermal power generation plant may have 6-10 producing wells and 1-4 injection wells costing $1.5-3 million each.
In the US, there are subsurface volcanic hot spots under Yellowstone National Park and Hawaii and intraplate extension with hot springs in the Great Basin of the US West.
California generates the most geothermal electricity, with about 824 Mw at the Geysers complex in northern California (much less than its capacity but still the world's largest developed geothermal field and one of the most successful renewable energy projects in history), 490 Mw in the Imperial Valley in southern California, 260 Mw at the Coso resource in central California, and 59 Mw at smaller plants elsewhere in the state. There are also geothermal power plants in Nevada, Utah, and Hawaii.
Due to environmental advantages and low capital and operating costs, direct use of geothermal energy has skyrocketed, with over 450,000 geothermal heat pumps installed. In the western US, hundreds of buildings are heated individually and through district heating projects with geothermal energy.
Biomass
It is estimated that biomass accounts for at least 15% of total world energy, and in some developing countries this figure rises to 35-50% of domestic energy supply.
The conversion of biomass for electric power generation is often referred to "bio-energy." Modern biomass usually involves large-scale plants and aims to substitute for conventional fossil fuel energy sources. It includes forest wood and agricultural residues, urban wastes, and biogas and energy crops.
Traditional biomass is generally confined to developing countries and small-scale uses. It includes fuel wood and charcoal for domestic use, rice husks, other plant residues, and animal dung. Industrial applications include combined heat and power, electric power generation, space-heating boilers in public buildings, domestic heating boilers, and decentralized energy applications.
Biomass plants have been installed across the world, burning a wide range of renewable fuels. India has a national program of typically small, 5 Mw plants. Plants in the US are burning wood processing residue and in the UK, straw and poultry litter. The UK's first - and the world's largest - straw-fired
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power station at Ely was built for capital outlays of $90 million and has an output of 36 Mw.
While the North American market will remain significant, South America is likely to contribute most of the bio-mass energy growth in the Americas. Indonesia, India, and China will drive forward the Asian market for biomass electric power generation.
Small-scale hydro
Large-scale hydro is a mature industry that, while involving a renewable energy resource, is also generally regarded as having unacceptable environmental consequences. However, the small-scale hydro market is a different matter.
Small-scale (< 10 Mw) hydro schemes normally involve a diversion of some of the flowing water rather than a complete holdback-and-discharge format of larger schemes. From being one of the earliest forms of power generation, it has for the past 30 years been overshadowed by the development of large-scale hydro schemes.
Improvements in turbine and generator efficiencies, particularly over the past 10 years, have seen small-scale hydro grow into a distinct industry. The extent of this transformation can be highlighted by the active involvement of major turbine manufacturers such as General Electric Co.
The small-scale hydro market has grown over the past decade to become a $2 billion/year industry. Through 1995-2000, small-scale hydro has been reassessed in many of its major markets, and new financial incentives have been put into place that are leading to increased interest and activity.
Asia - in particular China - is the backbone of the small-scale hydro industry, representing nearly 50% of expenditure, a situation that is likely to remain through 2010.
WEC: Sound energy development key to sustaining global economy
Sound energy development is the key to global economic sustainability. That message emerged loud and clear in speeches and panel discussions at the 18th World Energy Congress held in Buenos Aires Oct. 21-25.
The theme of the congress was "Energy Markets: The Challenges of the New Millennium." That theme played out as a consensus that the sustainability of the world's economies and people - especially those in the developing world - hinges on the energy industry being able to secure conventional energy supplies to the world at a reasonable cost.
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Dovetailing with that message was a key subtheme focusing on how social responsibility programs are playing an increasingly important role in energy industry operations.
Other key presentations focused on industry's support for economic globalization, the ongoing dispute over oil prices between exporting and consuming nations, the emerging global gas trade, and the outlook for investment in Latin America
The conference, which drew over 5,000 delegates, was marked by extremely heavy security measures in the wake of recent terrorist attacks on the US.
Fitting the theme of the globalization of energy and its impacts on developing nations, an official of the Philippines energy sector was named the new chairman of the Word Energy Council, the multinational, multi-energy organization that hosts the triennial congress. Taking over WEC reins is Antonio del Rosario, who is the first WEC chairman to hail from a developing nation. He is president and CEO of Trans-Asia Oil & Energy Development Corp, Trans-Asia Power Generation, and Asia Coal Corp., all based in the Philippines. Del Rosario previously held posts with Philippine National Oil Co. and the Philippines Ministry of Energy.
Oil, gas demand growth
In order to meet the energy needs of the estimated 6-7 billion global population expected by 2010, oil demand will have to rise to 90 million b/d from the current level of 77 million b/d, and natural gas demand will have to rise to 280 bcfd from 220 bcfd today.
By 2010, oil and gas will hold a two-thirds market share of global energy demand, and that share will increase, Sutherland asserted: "To be in denial of this fact is a major mistake."
Natural gas demand growth will account for the lion's share of that incremental market share growth, he noted, adding that the fuel now accounts for 40% of BP's current production, up from 15% only a decade ago.
At the same time, while conservation and renewable fuels development efforts continue to make inroads, they will fall short of the mark in meeting global energy demand needs, Sutherland said.
Even while BP has invested more than $200 million in photovoltaics to carve out a niche in the growing solar energy sector, "…the time frame for renewables to develop a significant share of the world's energy supplies is probably 30-40 years."
He also noted that, for every 1 % improvement in energy efficiency, the corresponding reduction in total energy use growth vs. business-as-usual growth is a difference of only 4%.
"[The world] has 40 years of oil reserves life and 60 years of gas; the challenge is to use it wisely."
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Centralized control improves operating efficiency
Enbridge Pipelines Inc., subsidiary of Enbridge Inc., Calgary, at yearend 2001 had completed consolidation of its 16 control centres in North America into a single centralized centre in Edmonton, Alta.
Consolidation of terminal and tankage facilities, accounting for 10 of the 16 control centres required the most work and posed the largest hurdle to the project's success. This article details the technical issues faced in the consolidation, specifically those surrounding remote control of terminal and tankage facilities.
Technical issues included providing:
Full control of facilities in a compressed timeframe.
A single expanded control centre.
A stable, reliable SCADA communication infrastructure.
A SCADA system with full redundancy and failover.
Protection mechanisms in the event of a loss of remote control.
A seamless transition from local control to remote control. Goal: improve efficiencies
An operations review begun in late 1999 identified ways Enbridge Pipelines could improve the efficiency of its operations. The main recommendation was to centralize pipeline and terminal control functions. This entailed consolidation of 4 pipeline control centres and 10 terminal control centres into an expanded control centre in Edmonton.
The consolidation effort included merging of two liquid-gathering systems into a control centre in Estevan, Sask. The project scope was later expanded to include centralized control of Vector Pipelines' gas transmission system along with Enbridge's Consumers Gas distribution system into the Edmonton control centre.
The technical goals of the project were:
Complete the consolidation by the end of 2001 (18 months).
Complete the project without shutting down facilities.
Complete the project with no safety or environmental incidents.
Complete the project on budget
The project began in April 2000. Upon completion at the end of 2001, total project cost was $ 8 million.
The new Edmonton control center houses consoles dedicated to liquid transmission pipelines and terminals as well as gas transmission and distribution. The liquid pipeline consoles are responsible for 15 pipelines ranging in diameter from 12 in. to 48 in. and lengths up to 1,100 miles. The total system includes 8,200 miles of pipeline on 4,000 miles of right-of-way,
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powered by 184 pump stations with an average power consumption of about 300 Mw.
Overall, the pipeline system transports more than 2.2 million b/d of 75 different commodities of crude oil, NGL, and refined products.
The gas consoles are responsible for Vector Pipeline, which transports 1 bcfd with 30,000 hp of compression. In addition, the gas consoles control the Enbridge Consumers Gas system, which serves southern Ontario. This distribution system has 3,100 miles of transmission lines and 18,600 miles of distribution lines. The customer base is 1.5 million with a peak demand of 3 bcfd and 100 bcf of storage capacity.
The terminal consoles are responsible for 16 terminal sites with a total of 166 tanks. The working volume is 22 million bbl with typical storage of 10-15 million bbl.
Technically, the most difficult project component was consolidation of the terminal facilities. These centres all had existing supervisory control and data acquisition (SCADA) systems that were built under the assumption that the SCADA system would be local to the facility.
3) Разработка и эксплуатация нефтяных и газовых месторождений
Brazilian test evaluates all-electronic intelligent completion
An onshore injection well, in Brazil, is the site of an all-electronic, multizone intelligent well completion being tested for eventual use by Petroleo Brasileiro SA (Petrobras) in its deepwater Campos basin wells. The joint Baker Oil Tools and Petrobras testing-qualification program focuses on live-well demonstration of functional compliance, reliability, and fitness-for-use.
Baker Oil Tools installed the equipment in the Varginha 8-VRG-8RN well on May 22, 2001.
The Baker Oil Tools InCharge system's design allows an operator to optimize flow from critical wells without shutting in production or performing costly intervention work. The system monitors pressure, temperature, and flow conditions at the sandface in real time, thereby enabling selective control of individual zonal flow rates in response to changing downhole conditions.
Downhole equipment
Baker Oil Tools says one aspect of its system that is particularly valuable to subsea operators is that a single control line penetrates packers and wellhead. From this control line, the operator can monitor and control up to 12 zones in a single well and up to 12 wells from a single control system.
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The system incorporates an electric downhole wet-disconnect anchor that Baker Oil Tools claims to be the world's first such system. It says this disconnect eases maintenance and repair in the upper portion of the completion string through an electric umbilical to the surface that can be repeatedly disconnected and reconnected.
As discussed in a presentation at last week's Deep Offshore Technology (DOT) Conference in Rio de Janeiro, the main equipment run in the test well included:
•A 5½-in. by 20 ft expansion joint, non-separating and capable of prespaced positioning.
•Electromechanical downhole disconnect-reconnect device.
•A 9 ⅝ by 5½-in. packer compatible with system.
•Adjustable 5½-in. choke with integrated position sensor, and internal and external pressure-temperature sensors.
•A 5½-in. Venturi flow meter for single-phase flow.
•Adjustable 3½-in. choke (shrouded) with integrated position sensor, and internal and external pressure-temperature sensors.
•A 3½-in. Venturi flow meter for single-phase flow.
•A ¼-in. OD tubing encapsulated conductor (TEC) with 11 by 11 mm encapsulation.
•TEC protection system.
•Subsea wet electrical connectors.
Improved method makes a soft landing of well path
Research and field experience have shown that well-path control is important in many cases, not only to reach the desired coordinates, but also to arrive at the well completion target from the preferred trajectory.
The authors developed an advanced 3D model that employs two arcs in respective planes, separated by a straight section, and base the model on the premise that the arc curvature remains constant in each section.
Starting from a given location, the well path used by the model is the simplest one possible to hit the expected target from a specified trajectory. The method works in an iterative fashion, avoiding a trial-and-error procedure.
The equations are exact, the calculated results are accurate, and the method represents a significant improvement over the traditional well-path planning techniques. The model and formulas were programmed into computer software; the results proved satisfactory for directional and horizontal wells in China.
Accurate well-path planning is the prerequisite for operators to drill directional or horizontal wells successfully. Engineers can plan well paths in a
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2D plane, if no special requirements are imposed by either the surface location, underground conditions, or drilling operational considerations.
Circumstances often require that well planners employ 3D well trajectory calculations, however, as highlighted in the following situations.
● The operator must avoid underground obstacles. The surface location may be offset from the target, such as the case with an offshore platform or when other obstacles are present on land.
Also underground obstacles in the vertical plane between the wellhead and the well completion target, such as existing well bores, salt domes, metallic deposits, faults, gas caps, and water cones, will force engineers to employ 3D well trajectories.
The well planner must consider bit walk. Effectively using the natural formation deflection that causes bit walk, engineers can reduce the workload of well trajectory control and drilling cost. They must design the 3D well path, especially in areas where bit walk is considerable.
The driller must make a path correction. When a well trajectory deviates from the planned path, the correcting section must employ a 3D trajectory to hit the predetermined target. This is similar to a sidetrack or branched well when the target is not in the vertical plane defined by the well-bore direction at the sidetrack or branch point.
Companies design wells with multiple completion targets. Since the multiple completion targets are not normally in a same plane, drillers must employ 3D well paths to reach the targets successively.
Preferred trajectory
Existing methods for planning 3D trajectories are available, but their objectives are only to hit the expected targets.
In some cases, however, adjusting the trajectory to the preferred direction is more important than only reaching the target. For example, trajectory direction is more important than the wellbore's coordinates in space, when attempting to hit every target in 3D, multiple-target wells.
When drilling horizontal wells, engineers must focus on trajectory direction to land the build-up section successfully and continue drilling the horizontal lateral. The industry has not found a method, however, for planning a well trajectory, from a given starting location, that reaches an expected target from a specified direction.
Generally, drillers use a bent housing motor or other steering equipment, operating in sliding mode, to change well-path direction. The trajectory curvature is regarded as a constant arc in 3D space.
Based on this concept, the authors devised a double-arc model to solve the problem. The method yields a well trajectory that hits the predetermined
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target from a specified path direction, with no need for trial-and-error procedures.
Downhole Upgrading of Extra-Heavy Oil by Use of Hydrogen Donors
An extra-heavy crude oil downhole upgrading process involves the downhole addition of a hydrogen donor additive under steam injection conditions. Physical simulation experiments show an increase of approximately 3 degrees APT in the treated crude oil gravity, a three-fold viscosity reduction, and approximately 8 wt % decrease in the asphaltene content. Compositionalthermal numerical simulations were performed and the results showed a good match between calculated and experimental API gravities of the upgraded crude oil for all conditions studied.
Introduction
Downhole extra-heavy crude oil upgrading processes have high potential value because of the possibility of improving crude oil quality. Underground processes have several advantages when compared with their aboveground counterparts. Use of the porous media as a natural chemical catalytic reactor improves upgraded crude oil properties and reduces expenses for downstream refining operations.
Some methods of underground extra-heavy crude oil upgrading that have been reported include physical separation (steam distillation), underground cracking or hydrocracking, hydrogen precursor injection, and in-situ combustion.
Experimental
Batch physical simulation upgrading experiments were performed in a stainless steel 300-ml batch Parr reactor equipped with magnetic stirrer, a heating mantle, and a temperature controller. In a typical experiment, the reactor was loaded with extra-heavy crude oil sands (containing approximately 10% crude oil) from the Orinoco belt, water, and tetralin (hydrogen donor) with a weight ratio of 10:1:1. The reactor was heated at 5 degrees C/min to 260 to 280 degrees C generating a final pressure of approximately 11 032 kPa for 24 hours. After the experiment, water and tetralin were separated from the oil sands by vacuum distillation at 300 degrees C. The reactor then was cooled to room temperature and oil was removed from the sand by solvent extraction with dichloromethane. Gas production was less than 10 wt% and results presented were an average of at least three different reactions.
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Continuous bench scale physical simulation experiments were performed in a continuous bench scale plant at 11 031 kPa constant pressure at temperatures from 280 to 315 degrees C and residence times from 24 to 64 hours. Extra-heavy crude oil, water, methane, and the tetralin hydrogen donor were fed into the sand-containing reactor. The pressure was relieved at the vessel outlet to separate the CH4. Then, the reaction mixture was continuously distilled to remove water and tetralin from the upgraded crude oil. Results were measured when equilibrium conditions were reached, i.e., no change in properties of the upgraded crude oils were observed with time.
Numerical Simulations
A reaction model involving four pseudocomponents was used and the kinetic parameters were determined. Asphaltenes were removed by precipitation with n-heptane and light, medium, and heavy fractions were obtained by vacuum distillation.
Results and Discussion
By use of a batch autoclave, the reaction of Hamaca extra-heavy crude oil in the presence of tetralin, steam, the natural formation, and methane at 280 degrees C for 24 hours resulted in a 3 degree increase in API gravity, a threefold reduction in viscosity, and an approximately 8-wt% decrease in asphaltene content in the upgraded product. Because only 6 wt% of the tetralin was consumed during the upgrading process, the remainder can be recycled. In general, the tetralin reacts with the extra-heavy crude oil to generate upgraded crude and naphthalene.
Consistent with these results, upgrading experiments with Cerro Negro and Boscan extra-heavy crude oils resulted in increases of 2 to 3 degree API and significant reductions in viscosities in the upgraded product. However, the decrease in asphaltenes were only 1 to 3 wt% compared with 8 wt% for the Hamaca extraheavy crude.
Use of a lower-capacity hydrogen donor such as toluene, resulted in a product with properties similar to the original Hamaca crude oil. This indicates that the presence of the hydrogen donor is crucial for downhole upgrading of extra-heavy crude oil under steam-stimulation conditions.
The API gravity increases and the percentage of asphaltenes decreases with reaction time and temperature. For 315 degrees C, the gravity reached a 14.6 degree API maximum value and the asphaltenes reached a minimum of 19 wt% for a 32-hour residence time compared with 11.9 degree API and 21.8 wt% asphaltenes at 280 degrees C.