Category Archives: Energy Basics

Jevon’s paradox – Energy Basics

Efficient use of energy must be the logical first step for anyone trying to slow carbon change. The benefits of not wasting energy are so evident that it should be a high priority for our civilization. Unfortunately it’s not quite that simple.

1865’s The Coal Question introduced what we now call Jevon’s paradox – that technological progress in the efficiency of using a resource leads to increases in resource consumption.

Jevon’s paradox is an inconvenient truth for energy efficiency. It’s not that efficiency doesn’t work – we do use less primary energy per unit of utility. It’s what happens afterwards where the gains in efficiency are cancelled out by more global effects.

Lets look at some of the possible first, second and third order effects (thanks Ray Dalio for this mental model). We will use gas fired heating as the example.

The first order effect of improving heating efficiency is that less gas is required to supply the same amount of heat. This effect is positive – we don’t burn as much gas to provide the same utility.

A secondary effect of improving heating efficiency could be that we now get more heat for the same amount of money. We spend the same amount, we get more heat – but no carbon saving. We can afford to heat bigger homes for the same amount of gas.

A third order effect could be that increased efficiency leads to less gas consumption – meaning saved carbon and money.  The question is then what does the economy do with the saved money?

If the saving is spent on taking a long haul holiday, we could actually see an increase in global carbon emissions. We improve the efficiency of supplying heat but overall as a civilization we burn more carbon. Alternatively if the saving is spent on building cleaner energy generation then even increases in utility could lead to a carbon saving.

It’s very difficult to generalize on what effect Jevon’s paradox has across different consumers, economics and technologies. Measuring the first order effects of energy efficiency projects is notoriously difficult – let alone any second or third order effects.

It’s important to note that energy efficiency is still worthwhile. It allows economic progress – this alone is worth doing. Yet for someone purely concerned with decarbonization, energy efficiency may not be the correct first option.

Jevon’s paradox is not guaranteed to occur. Any negative second or third order effects of energy efficiency can be smaller than the efficiency saving. It perhaps suggests that focusing on making sure any energy we use comes from as clean a primary source as possible is a safer bet than trying to use less dirty energy.

Further reading

Inertia in electricity systems – Energy Basics

Energy Basics is a series covering fundamental energy concepts.

Perhaps you’ve had critics of the energy transition shout “inertia” at you. Perhaps it’s keeping you up at night. Is our dream of a clean energy future impossible? This article will reassure you that losing inertia is something clean energy technologies can deal with.

Large, fossil fuel and synchronous generators have historically dominated our electricity system. Fossil fuels are burnt to force high temperature and pressure gases through turbines. These turbines rapidly spin shafts connected to alternators that generate AC electricity.

We are transitioning to a very different electricity system. We are building small-scale, clean and asynchronous generators. Wind turbines that spin at variable speeds, much slower than synchronous generators. Photovoltaic solar panels and batteries have no moving parts at all.

A key difference between these two systems is the inertia of the generators. Fossil fuel generators posses a lot of inertia due to the rapidly spinning & heavy turbine connected to the alternator. Once the turbine is spinning it’s hard to get it to stop – in the same way that it’s hard to stop a truck traveling at speed.

The speed at which the shaft & alternator needs to spin at is directly proportional to the desired grid frequency. In fact the grid frequency is the result of the speed that all these synchronous generators spin at. The frequency of electricity generated by a synchronous generator is given by

Poles refer to poles of the alternator.  120 is used to convert minutes to seconds and poles to pairs of poles.

The grid is an interconnected system – changing grid frequency requires changing the speed of every generator connected to the grid. This interrelationship becomes useful during times of supply & demand mismatches. Any imbalance needs to work to change the speed at which every generator on the grid spins. If these generators posses a lot of inertia, then the imbalance needs to work harder to change the grid frequency.

This is the value of inertia to the grid – it buys the grid operator time to take other actions such as load shedding or calling upon backup plant. These other actions are still needed – inertia won’t save the grid, just buy time for other actions to save the grid.

So now we understand that fossil fuel generators have inertia and how it is valuable to the grid (it buys the system operator time during emergency events). What does this mean for our energy transition? Do we need to keep around some fossil fuel generators to provide inertia in case something goes wrong? The answer is no.

Modern wind turbines can draw upon kinetic energy stored in the generator and blades to provide a boost during a grid stress. This ‘synthetic inertia’ has been used successfully in Canada, where wind turbines were able to supply a similar level of inertia to conventional synchronous generators.

Figure 1  –  Conceptual fast frequency response from a wind turbine

Photovoltaic solar and batteries also have a role to play. Both operate with inverters that convert DC into AC electricity. The solid-state nature of the devices means that they operate without any inertia. Yet this solid-state nature allows inverters the ability to quickly change operation in a highly controllable way. Inverters can quickly react to deliver whatever kind of support the grid needs during stress events.

Clean technologies are ready to create a new electricity system. Now we need to make sure we incentivize the technology that our grid needs. Market incentives should support technologies that can supply inertia on our cleaner grid. The level of support could be logically set so that the level of inertia on the grid will remain at the same level as our old fossil fuel based grid. That way, no one can complain.

Thanks for reading!

Cheat sheet for gas engine & gas turbine CHP – Energy Basics

In my previous life at ENGIE I specialized in the technical modeling of combined heat & power (CHP) plants.

I developed models to support sales projects and to optimize operation of existing sites – such as the district heating scheme at the Olympic Park in London.

CHP is an attractive technology for maximizing the recovery of heat & electricity from fuel. The technologies are mature and will deliver carbon benefits in most electricity grids.

This post aims to give concise practical details about the two most commons forms of gas based CHP. Together the gas engine and gas turbine are around 90 % of installed capacity of CHP in the UK.

Table 1 – CHP in the UK (from DECC)

This post focuses on the facts that matter in the day to day world of energy management.

common for both gas engines & gas turbines
  • Both have total efficiencies (electric + thermal) roughly around 80 % HHV.
  • Both operate with a maximum electric efficiency at full load.
  • In part load operation total efficiency remains around 80 % HHV – reductions in electric efficiency are counteracted by increases in thermal efficiency.
gas engines

Figure 1 – a simple gas engine schematic
Key practical advantages
  • High electric efficiency.
  • Cheap maintenance cost.
  • Cheap capital cost.
Key practical disadvantages
  • Half of the recoverable heat is generated as low quality (<100 °C).
  • Usually only economic at sizes below 5 MWe.

A gas engine has a high electric efficiency (30-38 % HHV).

A gas engine generates roughly the same amount of electricity and heat – i.e. the heat to power ratio is around 1:1.

The recoverable heat generated in a gas engine is split roughly half high grade (>500 °C), half low grade (<100 °C).

Gas engines are typically economic up until 5-6 MWe.  Beyond that size gas turbines become competitive.

Gas engine CHP is low maintenance (0.6 – 1.2 p/kWh @ 8,000 hours/yr) and captial (500 – 1,500 /kWe total project) cost.

Having half of the heat generated as low quality means that a low-grade heat sink is required.

Many industrial processes only require high-temperature heat (typically served using steam). Without a low-grade heat sink for the low-grade heat the economics of a gas engine will suffer.

Typical low-grade heat sinks include space heating, boiler feedwater heating on sites with low condensate return rates and low-temperature process heating. This makes district heating and hospitals good applications of gas engine CHP.

gas turbines
Figure 2 – a simple gas turbine schematic
Key practical advantages
  • All of the heat generated is high quality.
  • Supplementary firing can be used to generate more heat at high efficiency.
  • Potential to combine with steam turbines to generate more power.
Key practical disadvantages
  • Lower electric efficiency.
  • Complex emissions control systems.
  • Usually limited to sizes above 5 MWe.

A gas turbine operates with a lower electric efficiency (25-35% HHV) than a gas engine.

A gas turbine generates roughly twice as much heat as power – ie the heat to power ratio is around 2:1.

Unlike a gas engine, all of the heat generated by a gas turbine is high grade (>500 C).  This makes gas turbines ideal for industrial sites that need high-temperature steam to run their processes.

This also allows gas turbines to be used in combined cycle mode (steam is generated off the exhaust and used to drive a steam turbine).  More gas can be fired into the exhaust to further increase steam generation (known as supplementary firing).

This can be a key advantage of gas turbines, as the marginal efficiency of supplementary firing is higher than generating heat in a shell or water tube boiler.

Oil Reserves Growth – Energy Basics

Energy Basics is a series covering fundamental energy concepts.

As we consume non-renewable resources, the amount of that resource depletes. Makes sense right?

Yet when it comes to oil reserves we find that oil reserves actually grow over time! This is known as ‘oil reserves growth’. Why does this phenomenon occur?

First, let’s start by defining some relevant terms.

Oil reserves are the amount of oil that can be technically recovered at the current price of oil.

Oil resources are all oil that can be technically recovered at any price.

Oil in place is all the oil in a reservoir (both technically recoverable & unrecoverable oil).

oil reserves growth

Figure 1 – Proved oil reserves and Brent crude oil price (BP Statistical Review 2016)

So why do reserves grow over time? There are three reasons.

One – Geological estimates

Initial estimates of the oil resource are often low. It’s very difficult to estimate the amount of oil in a reservoir as you can’t directly measure it. Often a lot of computing power is thrown at trying to figure out how much oil is underground.

It’s also good engineering practice to stay on the low side when estimating for any project. I expect geologists intentionally do the same for geological estimates.

Two – Oil prices

Oil reserves are a direct function of the current oil price. Increasing oil prices means that more of the oil resource can be classed as an oil reserve.

Historically we have seen oil prices increase – leading to growth in oil reserves (even with the oil resource being depleted at the same time).

But increasing prices can also have secondary effects. A higher price might incentivise an oil company to invest more into an existing field – leading to an increase in oil recovery.

The reserves growth of existing fields can actually be responsible for the majority of additions to reserves.  Between 1977 to 1995 approximately 89% of the additions to US proved reserves of crude oil were due to oil reserves growth rather than the discovery of new fields.

Three – Technology

Improvements in technology have two effects. The first is to make more of the oil in place technically recoverable at any price (ie to increase the oil resource). Hydraulic fracturing (fracking) and horizontal drilling now allow

The first is to make more of the oil in place technically recoverable at any price (ie to increase the oil resource). Hydraulic fracturing (fracking) and horizontal drilling now allow access to oil that previously was technically unrecoverable.

The second is that as technology improves it also gets cheaper. This improvement in economics means that more of the oil resource can be classed as an oil reserve (even at constant or falling prices).

Thanks for reading!

The Complexity of a Zero Carbon Grid – Energy Insights

Energy Insights is a series highlighting interesting energy content from around the web.

Previous posts in this series include Automated Cars and How to save the energy system.

I’m excited to present this Energy Insights post. I’m highlighting a few interesting insights from the ‘The Complexity of a Zero Carbon Grid’ show.

This is very special as The Interchange podcast has only been publically relaunched recently.

The show considers what may be necessary to get to levels of 80-100% renewables. Stephen Lacey and Shayle Kann host the show with Jesse Jenkins as the guest.

The concept of flexibility

Jenkins observes that the concept of flexibility of electrical capacity appearing in literature. Flexibility means how quickly an asset is able to respond to change.

A combined cycle gas turbine plant is usually more flexible than a coal or nuclear generator. One reason for this is the ability to control plant electric output by modulating the supplementary burner gas consumption.

We will need flexibility on a second, minute, hourly or seasonal basis.

This concept of flexibility was also recently touched on by the excellent Energy Analyst blog. Patrick Avis notes that we need both flexibility (kW or kW/min) and capacity (kWh) for a high renewables scenario.

The post ‘Flexibility in Europe’s power sector’ could easily be enough material for a few Energy Insights posts. Well worth a read.

One investment cycle away

Jenkins observes that the investment decisions we make today will affect how we decarbonise in the future. Considering the lifetime of many electricity generation assets, we find that we are only a single investment cycle away from building plants that will be operating in 2050.

Most deep decarbonisation roadmaps include essentially zero carbon electricity by 2050. We need to ensure that when the next investment cycle begins we are not installing carbon intense generation as it would still be operating in 2050.

For both gas and coal the implied cutoff date for plant operation to begin is between 2010 – 2020.

Increasing marginal challenge of renewables deployment

The inverse relationship between the level of deployment of renewables and the marginal value added is well known. Jenkins notes that this relationship also applies to the deployment of storage and demand side response.

As renewable deployment increases the challenges for both storage and demand side response also increase.

Seasonal storage technologies

1 – Power to gas

Electricity -> hydrogen -> synthetic methane.

Figure 3 – Apros Power to Gas

Intermittency of the supply of excess renewable generation means that power to gas asset wouldn’t be fully utilized.

Didn’t cover the possibility of storage of electricity to allow a constant supply of electricity to the power to gas asset.

2 – Underground thermal

Limited to demonstration scale.

Didn’t cover the feasibility of generating electricity from the stored heat.

I would expect that the temperature of the stored heat is low.  Perhaps the temperature could be increased with renewable powered heat pumps.

Thanks for reading!


Energy Basics – Capacity Factor

All men & women are created equal. Unfortunately the same is not true for electricity generating capacity.
Capacity on it’s own is worthless – what counts the electricity generated (kWh) from that capacity (kW). If the distinction between kW and kWh is not clear this previous post will be useful.

Capacity factor is one way to quantify the value of capacity. It’s the actual electricity (kWh) generated as a percentage of the theoretical maximum (operation at maximum kW).

For example to calculate the capacity factor on an annual basis:

There are many reasons why capacity will not generate as much as it could.

Three major reasons are maintenance, unavailability of fuel and economics.

Burning fossil fuels creates a challenging engineering environment. The core of a gas turbine is high pressure & temperature gases rapidly rotating blazing hot metal. Coal power stations generate electricity by high pressure steam forcing a steam turbine to spin incredibly fast.
These high challenges mean that fossil fuel plants need a lot of maintenance. The time when the plant is being maintained is time the capacity isn’t generating electricity.
Renewables plants need a lot less maintenance than a fossil fuel generator. No combustion means there is a lot less stress on equipment.
Availability of fuel
Yet while renewables come ahead in terms of maintenance, they fall behind due to a constraint that fossil fuel generation usually doesn’t suffer from – unavailability of fuel.
This is why renewables like wind & solar are classed as intermittent. Fuel is often not available meaning generation is often not possible.
Solar panels can’t generate at night. Wind turbines need wind speeds to be within a certain range – not too low, not too high – just right.
This means that wind & solar plants are often not able to generate at full capacity – or even to generate at all. This problem isn’t common for fossil fuel generation. Fossil fuels are almost always available through natural gas grids or on site coal storage.
The final reason for capacity to not generate is economics.
The relative price of energy and regulations change how fossil fuel capacity is dispatched. Today’s low natural gas price environment is the reason why coal capacity factors have been dropping.
Here renewables come out way ahead of fossil fuels. As the fuel is free renewables can generate electricity at much lower marginal cost than fossil fuels. Wind & solar almost always take priority over fossil fuel generation.
Typical capacity factors
The capacity factor wraps up and quantifies all of the factors discussed above.
Table 1 – Annual capacity factors (2014-2016 US average)

CoalCCGTWindSolar PVNuclear
Annual Capacity Factor56.13%53.40%33.63%26.30%92.17%


Table 1 gives us quite a bit of insight into the relative value of different electricity generating technologies. The capacity factor for natural gas is roughly twice as high as solar PV.


We could conclude that 1 MW of natural gas capacity is worth around twice as much as 1 MW of solar PV.

How useful is the capacity factor?

Yet the capacity factor is not a perfect measure of how valuable capacity is. Taking the average of anything loses infomation – capacity factor is no different.
Two plants operating in quite different ways can have the same capacity factor. A plant that operated 50% for the entire year and a plant that generated for half of the year at full capacity will both have an identical capacity factor.
The capacity factor loses infomation about the time of energy generation. The time of generation & demand is a crucial element in almost every energy system.
Generation during a peak can be a lot more valuable to the world than generation at other times. Because of the nature of dispatchable generation it is more likely to be running during a peak.
This leads us to conclude that low capacity factor generation could be more valuable than higher capacity factor generation.  This is especially true for solar in many countries as a) the peak often occurs when the sun is down and b) all solar generation is coincident.
The solution to the intermittency problem of renewables is storage. Storage will allow intermittent generation to be used when it’s most valuable – not just whenever it happens to be windy or sunny.
Thanks for reading!

Energy Basics – Average vs Marginal Carbon Emissions

Carbon savings might seem like a simple calculation – yet many professionals are getting it wrong. I know because I was making this mistake in my previous job!

Accurate calculation of carbon savings is crucial in the fight against climate change.  Knowing how much we save from a project can be compared to other projects such as renewable generation.

So where are people going wrong?  The key is to understand the difference between average and marginal carbon emissions.

Average carbon emissions are calculated using the total carbon emissions and total amount of electricity generated:

Table 1 – Calculation of average carbon intensity (for Base Case – see below)
Carbon emissionstC83,330
Electricity generatedMWh182,827
Carbon intensitytC/MWh0.456
This average intensity can be used to calculate carbon savings.  For example if we had a project that saved 2 MWh we would calculate 2 * 0.456 = 0.912 tC as the saving.  This is wrong!

To understand why we need to the concept of the marginal generator.  In reality as electricity is saved the reduction in generation is not spread across each generator.  The reduction occurs in one plant – the marginal generator.  Let’s run through an example.

Suppose we have a grid where electricity is supplied by either wind or coal (the Base Case).  If we save 1 GW of electricity, the generation of the coal plant will reduce by 1 GW (Case 1).

The wholesale mechanism operating in most electricity markets will reduce output on the most expensive plant, not reduce the output of all plants equally.

Figure 1 & 2 – The effect of saving 1 GW of electricity.  Note that the generation from wind is unchanged.
Table 2 – The daily results for the Base Case & Case 1 (you can download the model below)
Base CaseCase 1Saving
Carbon emissionstC83,32961,48921,840
Carbon intensitytC/MWh0.4560.3870.910
Our carbon saving is equal to 1 GW multiplied by the carbon intensity of the marginal plant.

If we were to use the average grid carbon intensity (0.456 tC/MWh) we calculate a daily carbon saving of only 21,480 tC.

You might be asking – how do we know what the marginal generator will be?  It’s likely to be the most expensive generator at that time (it may not be if the plant needs to be kept on for technical reasons).   As renewables are characterized by low marginal costs they are the unlikely to be pushed off the grid.

Luckily high marginal cost generators like open cycle gas turbines are usually also carbon intense – so your saved electricity is likely doing valuable work – and potentially more than you previously thought!

You can download a copy of the model to see my assumptions here:

Energy Basics – Fixed versus Variable Costs

Fixed versus variable costs is a basic business concept. It is also a basic concept in energy engineering. Unfortunately this not stop energy professionals from getting into trouble by misunderstanding it.

In my previous role we had a project looking at the feasibility of a Combined Heat & Power (CHP) plant at a pharmaceuticals site. Previously two consultants had looked at the site and concluded that a 2 MWe gas engine would be an economic project. We expected that good CHP projects would have payback periods of five to six years. These two consultants had modeled a payback below two years!

We took a look at the technical fundamentals (annual profiles of site heat & power demands) and agreed that the site was well suited to a 2 MWe gas engine. However once we took a step further and started to evaluate the economics things started to unravel.

A crucial part of any energy project are prices – for CHP electricity prices in are crucial. To know what price we should model we took a look at twelve months of electricity invoices for the site.

What we wanted to know was the variable electricity price. This price will represent the savings for reducing import electricity to site through use of on site generation.

Table 1 – A simplified electricity invoice

Electricity consumedMWh2,500
Variable electricity price£/MWh65
Variable electricity cost£162,500
Fixed costs£100,000
Total annual cost£262,500
Delivered electricity cost£/MWh105

When we compared our analysis of the electricity invoices to the prices used by the two consultants, we were shocked to find they had used they delivered electricity cost in their model – not the variable cost.

This overstated the value of electricity saved and the value of the CHP project.

To understand why this is a problem think what would happen if we saved all 2,500 MWh of electricity. This would mean we have no variable cost – a saving of £162,500. But even with no electricity consumed we still incur fixed charges.

However if we use a value of £105/MWh, we calculate a saving of £262,500 – which is incorrect!  While this seems obvious when spelt out, two consultants from separate well renowned energy companies made this mistake.

 It was difficult going back to the pharmaceuticals site and telling them their fantastic project was perhaps not so fantastic. But it is far better to understand it now rather than after the engine was installed.

You might be wondering why people calculate a delivered electricity cost at all. It can be useful for understanding the total cost for delivering electricity to a site.

But it is not useful for understanding the savings from projects like CHP or reducing site electricity consumption.

Key lessons to take away are:

  • Always check your customer’s actual invoices. It takes time but it is worth it to build up an accurate picture of what is going on by replicating the invoice from the rates (£/MWh) and amounts (MWh). What you want to arrive at is a total marginal and a total fixed cost.
  • Be aware that not all £/MWh costs are equivalent!  When you are given an electricity price to use in a model be sure that you understand what that price represents.

Energy Basics – Four Negative Effects of High Return Temperatures

This post is one of many in a series explaining energy for a technical and non-technical audience.  Previous posts include topics such as the Ambient Temperature Impact on Gas Turbine Performance or the difference between kW and kWh.  

High return temperatures are a major problem in district heating (DH) networks.  High return temperatures lead to:

  1. Increased flow rate of water pumped around the network.
  2. Lowers the capacity of the network to deliver heat.
  3. Increases heat losses from the network.
  4. Decreases heat recovery from gas engines and biomass boilers.

Before we dive into why lets give a brief overview of how a district heating network operates.  Figure 1 shows a simple flow diagram for a district heating network.

Figure 1 – District heating system operating with a return temperature of 50 °C

The system delivers heat to the building heating system via a heat exchanger.  Hot water is pumped around the district heating network and then returned to the energy centre for heating.

What then are the four negative impacts of a high return temperature?

1 – Increasing flow rate of water pumped around the DH network

Most district heating networks operate with a fixed flow temperature. This is set by the temperature of the water generated in boilers or CHP plants.

A high return temperature means that the temperature difference across the network (TFLOW – TRETURN) will decrease.

A smaller temperature difference means pumping more water to deliver the same amount of heat.  See this earlier post if you are not clear how this relationship works.

Pumping more water means more electricity consumed by the pumps. This means increased electricity cost and carbon emissions from the scheme.

2 – Lowering the capacity of the network to deliver heat

Pipe sizes limit the capacity of a DH network to deliver water.

At peak flow rate a small temperature difference means we can deliver much less heat than the same network with a high temperature difference.

A scheme with a temperature difference half of the design means we are doubling the effective capital cost of our network per MW of heat capacity.

A larger temperature difference means we may be able to avoid installing new pipework (and the associated capital cost!) as our network expands.

Design of new networks with large temperature differences would mean smaller pipes. Smaller pipes means less capital cost and lower heat losses.

3 – Increasing heat losses

Heat losses are a function of the pipe surface area and the difference in temperature between the pipe and ambient. A higher return temperature means more heat losses in the return pipes.

Heat losses are a drawback of DH schemes versus local gas boilers. DH schemes lose a lot more heat due to the long length of the network pipes versus local systems. Minimizing heat losses is crucial in operating an efficient DH network.

Increased heat losses means more heat generation required in the energy centre. This means higher gas consumption and carbon emissions.

4 – Decreasing heat recovery from gas engines and biomass boilers

District heating schemes bring a net benefit to customers and the environment by the use of low carbon generation in the energy centre.

The efficient use of technologies such as gas engines or biomass boilers is central to the success of district heating.  The benefits of using low carbon generation can offset heat lost from the DH network.

District heating schemes use gas engines to generate heat and power together.  Gas engines generate roughly half of their recoverable heat as hot exhaust gases (> 500 °C) and half as low temperature (<100 °C). Biomass boilers generate only a hot exhaust gas.

The thermodynamic reasons for the loss of heat recovery are the same for of these three heat sources.  An increased DH return temperature increases the final temperature the heat source can be cooled to.

This means that less heat is transferred between the heat source and the DH water.  Below we will look at the example of recovering gas engine low temperature heat.

Gas engines operate with a low temperature hot water circuit.  This water circuit removes the jacket water and lube oil from the engine.  This heat can generate hot DH water for use in the scheme.

Figure 2 shows that a network return temperature (85 °C) leads to us only being able to cool the engine circuit to 85 °C.  This limits heat recovery in the heat exchanger.

Figure 2 – Gas engine low temperature waste heat recovery with a high return temperature

It also forces us to use a dump radiator to cool the engine circut to the 70 °C required by the engine.  If the scheme was not fitted with a dump radiator then the engine would be forced to reduce generation or shut down.

Figure 3 shows the temperature versus heat (T-Q) diagram for the heat exchanger when return temperature is low (50 °C).  Operating with a low return temperature means we recover a full 1 MW from the engine water circut.

Figure 3 – Heat recovery from engine with a low network return temperature (50 °C)

Now look what happens when return temperature is high (80 °C).  Figure 4 shows that we now only recover 400 kW of heat.

Figure 4 – Heat recovery from engine with a high network return temperature (80 °C)

Gas boilers will need to generate the additional 600 kW of heat required by the network.  This means increased gas consumption and carbon emissions.

The same principle applies to the recovery of heat from higher temperature sources such as gas engine exhaust or biomass boiler combustion products.  A high DH return temperature will limit heat recovery.

Why do high return temperatures occur?

High network return temperatures can occur for variety of reasons.  Most commonly it is due to heating systems designed for local gas boilers connected to DH networks.

A major issue is the use of bypasses.  Bypasses divert a small amount of the hot DH water being fed to a heat exchanger directly from the flow into the return.  Figure 5 shows a bypass increasing network return temperature from 80 to 95 °C.

Figure 5 – Bypass causing high return temperature

Bypasses are installed to maintain a minimum amount of flow across the network when demand for heat is low.  This prevents starving pumps at low heat demands.

Bypasses cause no issues in local boiler building heating systems but are a major problem in district heating.

These bypasses are pipes designed to only allow a small amount of water to bypass the heat exchanger.  However when network flow is low they also have a proportionally large effect on the return temperature!

Instead of installing bypasses pump systems should operate with higher turndowns.  This can be achieved through multiple pump systems.

Another reason for high network return temperatures is building circuits which use higher temperature water than they require.  For example local hot water cylinders require temperatures above 60 °C to prevent legionella.

Local water storage does not make sense on a DH network – heat storage should occur in the energy centre.  This will allow the DH network operators to optimally manage the heat storage.

Local hot water cylinders can also cause peaks in demand if they are set to charge at the same time.  This will be seen as a huge peak in heat demand on the entire network.  Peak demands can be difficult for DH network operators to deal with.

Energy Basics – Ambient Temperature Impact on Gas Turbine Performance

This post is one of many in a series explaining some energy insights for a technical and non-technical audience.  Previous posts include topics such as the First & Second Law of Thermodynamics or the difference between kW and kWh.  

Gas turbine power output increases when it is cold and decreases when it is hot.

Understanding why will impress both your technical and commercial colleagues!  The energy engineer must also take account of this relationship in any modeling work of gas turbine plants.

To explain the reason for the variance you need to link together a few insights:

  1. A gas turbine is a fixed volume machine.  You can only squeeze a fixed volume of air through the compressor and turbine.
  2. The density of air increases when it is cold.  Colder air means more mass of air in the same amount of volume.
  3. The amount of power generated in the turbine increases with a higher mass of air flowing through the turbine.

So colder air means we get a higher mass flow rate of air in the gas turbine leading to more power generated.

When it gets hot the opposite effect occurs.  Power output decreases due to less mass flowing through the turbine.

Ambient temperature also has an affect on the compressor.  Colder air improves compressor efficiency.  This means the compressor consumes less power, leading to a more efficiency gas turbine.

Effect of ambient temperature on gas turbine performance. Source – Rahman et. al (2011) – Thermodynamic performance analysis of gas-turbine power-plant

De Sa & Zubaidy (2011) proposed an empirical relationship for a 265 MW gas turbine:

For every K rise in ambient temperature above ISO conditions the Gas Turbine loses 0.1% in terms of thermal efficiency and 1.47 MW of its Gross (useful) Power Output.

This is a problem in hot climates where peak demand for electricity (for space cooling) will occur at the same time as poor gas turbine performance.

When an energy engineer models a gas turbine system she needs to be careful to account for this variation.  Most ideal is using a years worth of ambient temperature data on an hourly basis.

A simple linear regression between the variable (such as gas turbine output or efficiency) and ambient temperature will account for the variation for each hour.  Multiple linear regression can be used if both ambient temperature and gas turbine load are varying.