Minimizing Energy losses in surface oil and gas facilities
Requirement for the surface facilities for the steam based includes; treatment for boiler feed water generation, water pipelines, produced water recycle, steam generation plants, and wastewater treatment units in conjunction with oil treatment, gas treatment units, gathering systems, well pads, and other utilities and offsite parts (ISO 13702 1999). These facilities intended for in-situ burning processes needs steam generation on a smaller scale, produced gas treatment, oil treatment, water treatment air compression units, and other utilities and offsite units. This paper is much concerned about facilities for steam based and in-situ combustion, oil recovery methods. The surface facilities may possibly consist of carbon capture sour gas treatment, equestration units’, cogeneration units for electric power, and s sulfur recovery, being inclusive of the general project.
Thus, the process technique of surface facilities includes process combination and energy regulation to reduce general expenses of steam and power production and increase heat recuperation making out the costs of operating between capital and trade-offs, and reducing the general heat loss and utility heating or cooling. Consequence and risk studies according to Seveso-II (2002) are often referred to as worst-case assessments.
Natural gas covers for 29 percent of the total energy supply in United States’ (2009) and plays a significant role in satisfying our energy needs.1 Although the U.S. at present generates approximately 21 trillion cubic feet (Tcf) in a years, other sources of supply have to be brought in for three major reasons. Primarily traditional sources have been exhausted and new sources must be initiated to cover for this loss. Second, use of natural gas is projected to increase since natural gas taken by many as a necessary part of any tactic to implement optional forms of energy to fight global warming. Third, to attain the national goal of increased energy independence, additional energy generation is required because U.S. production is not enough to achieve demand.
The major sources of air emissions (continuous or non-continuous) as a result from onshore activities comprise the use of compressors, and heat generation, and combustion sources from power pumps, and reciprocating engines (boilers, turbines, and other engines); emissions as a result from venting and flaring of fugitive emissions; and hydrocarbons
All reasonable effort s should be made to increase energy efficiency and modify facilities to reduce energy use. The general goal should be to decrease air emissions and assess less costly alternatives for minimizing emissions that are technically viable. The other suggestions on the management of energy conservation and greenhouse gases are noted in the General EHS Guidelines.
Energy optimization is a significant part of surface facilities process method. The following are general approaches to optimize the energy;
Calculate and measure the thermodynamic shortcomings of the treatment procedures. The actual energy usage has to be higher than the thermodynamic minimum Select procedures with lower thermodynamic lowest energy needed.
Select the surface process unit operating situations go hand in hand with the reservoir working conditions. Thus, the exchange of heat will be reduced. Any heat exchange will have efficiency limitation owing to entropy alterations.
reduce transportation of hot liquid for treatment to keep away from insulation losses
Calculate if straight contact heat exchange can be attained as it will be more resourceful than indirect heat exchange.
If cogeneration is essential, ensure efficiency of fuel by heat recovery steam production.
Keep away from too much production of low-level heat because of seasonal changes of ambient temperatures; less heat from process cooling will have to be detached expending energy in air or water-cooling.
Make the most of heat combination between hot and cold process streams to reduce outside cooling or heating.
Choose equipment like steam pumps, heater turbine s and boilers, with increased efficiencies.
Consider waste heat energy recovery units, If low level heat generation could not be evaded
Thermodynamics gives less energy necessities and most thermodynamic efficiency for a separation procedure, the minimum thermodynamic work needed for separating a uniform mixture in to pure products at stable temperature is given by the rise of Gibb’s free energy of the products over the input (Semiat 8196).
Venting and Flaring
Related gas brought to the surface with crude oil process of oil generation is at times disposed of at onshore facilities by flaring or venting to the environment. This exercise is now extensively seen to be a waste of a valuable supply, as well as an important source of GHG eliminations. Nevertheless, venting or flaring are also significant safety procedures used on onshore oil and gas facilities to make sure gas and other hydrocarbons are carefully disposed of in the time of power, equipment failure, or emergency.
Steps consistent with the Global Gas Venting and Flaring Reduction Voluntary Standard (part of the World Bank Group’s Global Gas Flaring Reduction Public-Private Partnership (World Bank Group 2004) should be taken on when considering flaring and venting alternatives for onshore activities. The standard gives direction on how to remove or attain reductions in the f venting and flaring of natural gas.
Constant venting of associated gas is not seen as current accepted exercise and should be evaded. The related gas stream should be directed to an efficient flare method, even though constant flaring of gas should be evaded if viable options are available. Before adopting flaring, viable options for the use of the gas should be calculated to the maximum point possible and incorporated into production method.
Other options may entail export of the gas to a neighboring facility or to market , gas injection for reservoir pressure maintenance, gas utilization for on-site energy requirements, enhanced recovery using gas lift, or gas for instrumentation. An evaluation of options should be effectively documented and filed. If none of the alternative courses is currently viable, then steps to reduce are volumes should be assessed and flaring should be seen as a temporary resolution, with the eradication of continuous production associated gas flaring as the ideal objective.
In the situation of a need or equipment failure, or plant trouble conditions, supplementary gas should not be vented but rather be sent to a resourceful flare gas system. Emergency venting may be essential under particular field events where flaring of the gas stream is impossible, or where a flare gas method is unavailable, such as a lack of enough hydrocarbon content in the gas stream to support burning or a lack of enough gas pressure to let it to go into the flare system. Explanation for not including a gas flaring system should be completely documented before an emergency gas venting facility is well thought-out.
To reduce flaring situations as a because of equipment failure and plant upsets, plant consistency should be 95 percent and equipment sparing and plant turn down should be provided for in order.
If flaring is essential, non-stop upgrading of flaring through putting up of best practices and new technologies should be established. The following control steps and pollution prevention ought to be taken into consideration for gas flaring: Putting in place of source gas reduction steps to high extent possible;
Use of resourceful flare information, and optimization of the number and size of burning nozzles;
Making best use of flare burning efficiency by controlling and optimizing flare fuel / air stream flow rates to make sure the right ratio of support stream to flare stream;
Reducing flaring from wash out and pilots, without compromising security, through steps comprising;, flare gas recovery units, inert wash out gas, setting up of wash out gas reduction equipments, and setting up of conservation pilots, soft seat valve technology where suitable;
Reducing danger of pilot blow-out by making enough exit velocity and giving wind guards; Use of a dependable direct ignition system;
Setting up high reliable instrument pressure protection systems, where suitable, to minimize over pressure situations and evade or minimize flaring events.
Reducing fluid carry-over and entrainment in the gas flare stream with a appropriate fluid separation system;
Reducing flame lift off
Using flare to manage odor and visible smoke emissions Constructing flare at a secure distance from local communities and the labor force including workforce accommodation units;
Putting in place of burner replacement and maintenance programs to make sure non-stop total flare efficiency;
Metering of the flare gas.
To reduce flaring situations because of equipment failure and plant breakdown plant dependability should be 95 percent and provision are supposed to be made for plant turn down and equipment sparing protocols. Flaring quantities for brand facilities should be anticipated during the primary commissioning time so that fixed quantity flaring objectives can be made up. The quantity of gas flared for all flaring events should be wrote down and reported.
Cooling and Heating Systems
Water preservation opportunities given in the General EHS rule should be well thought-out for oil and gas facility cooling and heating systems. If cooling water is to be used, it should be given out to surface waters in a place that will let utmost mixing and cooling of the thermal plume to make sure that the temperature is ranging 3 degrees Celsius of ambient temperature at the edge of the distinct mixing region or within 100 meters of the discharge place
If biocides and or additional chemical additives are used in the cooling water system, concern should be given to residual result at discharge using methods such as risk-based assessment.
Fire and Explosion
Onshore oil and gas production facilities should be designed, built, and used as per international standards10 for the control and prevention of fire and explosion risks (Ontario Fire Marshal 2010). The major effective method of stopping fires and explosions at oil and gas facilities is by controlling the discharge of combustible substances and gas, and the early disruption and detection of leaks (Wormald n.p). Possible ignition sources should be kept to a lowest and sufficient isolation distance between possible ignition sources and combustible material, and between processing facilities and nearby buildings11, should be in place. Facilities should be categorized into risk areas, as per international good practice,12 and according to possibility of discharge of combustible gases and fluid (IFC 16).
All equipment ought to be scrutinized on a daily basis for any of leakage, with corrective step taken, as required, to make sure the equipment keep on operating in a secure and environmentally satisfactory way. All disposal and injection sites supplied with tubing and packed should occasionally oversee the tubing covering annulus pressure in order check the reliability of the packer and tubing. If a well is not finished with a packer, alternative techniques should be implemented, such as temperature logs or tracer logs to make sure the liquids imputed are appropriately controlled and are going into an appropriate disposal formation. Rate of testing depends on the working state. Like, if an area has many corrosion breakdowns, then testing for the mechanical reliability of the well should be regular (API 12).
Interstage Cooling (IC) is a smart alternative for upgrading the efficiency of the HTGR PCS. As extra phases are added, the standard temperature over which injected energy is increased remains higher and/or the standard temperature over which rejection energy is decreased remains lower. If only these were the single effect of the IC, the cycle efficiency would all the time raise with more phases. However, with each extra phase, pressure go down is present.
Additional inter-phase pumping must be completed to cover up for this extra pressure drop. Since the pumps aren’t 100% competent, in the end the entropy loss at some stage in an additional pumping operation results in a lesser overall energy input than without that phase. When this happens, the cycle efficiency in reality reduces. When cycle efficiency upgrading is not justified for the extra cost, the extra phase can be evaluated against attainable component performances.
Intercooler boosts the cycle effectiveness because of reducing the temperature input to the compressor. One intercooler upgrades the cycle effectiveness by approximately 3 %. Once the primary intercooler is used, the second and third intercooler gives much slighter efficiency boosts (Barner 2006).
Major ordinary type of cooling equipment employs a compression cooling cycle. Subsequent to the refrigerant being evaporated through heating from the cooling load, the steam is compressed. This increases the temperature of the gas well beyond ambient temperature, so the heat in the gas can be extracted by cooling it with water or air at ambient temperature. Extracting heat leads the compressed gas to condense back to a warm fluid.
Warm refrigerant liquid coming from condenser is directed into the cooling place by a flow control machine of some kind. The pressure in the cooling place is determined by the suction of the compressor and by the rate of cooling. Because the evaporator pressure is, lower than the condenser pressure, a small part of the liquid refrigerant spark into steam when it goes through the control machine. This sparking cools the remaining fluid to the temperature of the evaporator. The liquid refrigerant is prepared to take up heat from the cooling load, going through the phase (Wulfinghoff 1300).
Compression cooling method may as well have accomplice devices or specialized qualities, like; hot gas bypass circuits, , purge units, crankcase heaters valves for controlling the flow of refrigerant to different parts of a coil and many others. The majority of these accessories are particular to specific models, types, or system models.
The temperature differential between condenser and cooling pace is normally higher than those of the real cooling load. This is an issue of great attention, since the temperature differential is the main theoretical aspect that confines COP. As a reasonable example of how the temperature differential comes up, the example of an air-cooled water chiller used for air conditioning is taken into consideration.
Gas Turbines Energy Losses
Gas compressor engines gets their power from burning fuel in a combustion compartment and using the rapid flowing burning gases to move turbine in almost the same manner as the high pressure vapor moves a vapor turbine. It has the second turbine stand-in as an air compressor put on the similar shaft. The air compressor takes in air, compresses it, and provides it at high pressure into the burning engines hence increase the strength of the flames burning.
It is an encouraging response mechanism. As the gas engines speeds up, it also makes the turbine to run hence forcing a lot of air through the burning compartment, which on the other hand boost s the combustion speed of the fuel sending extra high pressure burning gases into the gas compressor raising its momentum more. An exit not controlled is taken care of by controls on the fuel provider line that minimizes the quantity of fuel imputed to the compressors hence minimizing its speed.
Gas turbine uses reasonable quantities of power just to move its turbine. with all cyclic heat turbines, a highest working temperature in the mechanism entails bigger effectiveness (Carnot’s Law), but in a compressor it too entails that extra energy is lost as misuse heat via the burning exhaust gases whose temperatures are usually over 1,000°C . As a result simple cycle compressor effectiveness is low. For heavy machines, design effectiveness varies between 30% and 40%. (The effectiveness of aero machines is in varying of 38% and 42% whereas a low power micro turbine attains simply 18% to 22%). Although raising the firing temperature raises the yield power at a given pressure proportion, there is too a sacrifice of effectiveness as a result of rise in losses because of the cooling air necessary to uphold the turbine mechanism at sensible working temperatures. Compression raises the air temperature so that the air at the discharge of compressor is at a higher temperature and pressure (Brooks 2).
Gases going through a perfect gas turbine experience three thermodynamic procedures. These are isobaric compression, isentropic (constant pressure) burning and isentropic expansion. Jointly, these make up the Brayton cycle.
In a practical gas compressor, gases are primarily speeded up in either an axial compressor or a Centrifugal. They gases are subsequently slowed by use of diverging nozzle called a diffuser; these procedures raise the temperature and pressure of the process. In a perfect method, this is isentropic. However, in practical, energy is lost to heat, because of turbulence and friction. Gases then go from where it diffuses to a burning chamber, or same machine, where heat is increased. In a perfect method, this happens at steady pressure (isobaric heat addition). Since there is no vary in pressure the particular of the gases rises. In practical circumstances these procedures normally go together with a small loss in pressure, because of friction. Lastly, this larger volume of gases are extended and sped by nozzle lead vanes before energy is taken out by a turbine. In an perfect system, these gases are long-drawn-out isentropically and come out of the turbine at their initial pressure. Practically, this procedure is not isentropic as energy is once more lost to turbulence and friction.
Recent research by Bolszo and McDonnell (2009) on emissions optimization of a biodiesel fired 30-kW gas compressor shows that biodiesel liquid properties is a consequence of inferior atomization and prolonged evaporation periods in contrast to hydrocarbon diesel. It emerged that the smallest amount NOx emission levels attained for biodiesel goes beyond the least attained for diesel, and that optimizing the fuel injection procedure will upgrade the biodiesel NOx emissions (Fagbenle 38).
Theoretical research was recently doner by Glaude et al. (2009) to elucidate the NOx index of biodiesels in gas compressor taking natural gas and conventional petroleum gas oils as reference fuels. The adiabatic flame temperature was seen as the main determinant of NOx emissions in gas compressors and used as a solution for NOx emission.
API, Environmental Protection for Onshore Oil and Gas Production Operations and Leases. API Recommended Practice 51rfirst Edition, July 2009
Chang H. Oh Robert Barner, Effects of Interstage Cooling on Brayton Cycle Efficiency: ANS Annual Meeting, 2006. Web. http://www.inl.gov/technicalpublications/Documents/3479831.pdf
C. D. Bolszo and V. G. McDonell, Emissions optimization of a biodiesel fired gas turbine, Proceedings of the Combustion Institute, Vol 32, Issue 2, 2009, Pages 2949-2956.
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Richard ‘Layi Fagbenle (2010). Exergy and Environmental Considerations in Gas Turbine Technology and Applications, Gas Turbines, Gurrappa Injeti (Ed.), ISBN: 978-953-307-146-6, InTech
Pierre A. Glaude, Rene Fournet, Roda Bounaceur and Michel Moliere, (2009). Gas Turbines and Biodiesel: A clarification of the relative NOx indices of FAME, Gasoil and Natural Gas
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World Bank Group. 2004. A Voluntary Standard for Global Gas Flaring and Venting Reduction. Global Gas Flaring Reduction (GGFR) Public-Private Partnership. Report No. 4. Washington, DC: The International Bank for Reconstruction and Development / World Bank.
Wormald, Fire Protection Solutions for the Oil & Gas Industry Reduce the risks associated with highly flammable and explosive products, 2009. web. http://www.wormald.com.au/__data/assets/pdf_file/0010/153955/Wormald_ResourcesBrochure_Dec09_EmailCopy.pdf