Reducing Emissions from Upstream Oil and Gas

Article by Tom Baxter CEng FIChemE

From the reservoir rock that contains the hydrocarbons to the downstream refinery gate, Tom Baxter provides a walk-through of unit operations and equipment, identifying opportunities to save energy at your process facilities

MOST oil and gas facility operators are investigating options for reducing their greenhouse gas (GHG) footprint. Chemical engineers can help their employers achieve this by looking systemically at how energy is being used at their process plants and suggesting ways to reduce it.

Table 1 shows how a typical heat and power requirements for an all-electric upstream oil and gas asset might look. I’ll revisit this at the end of the article and estimate what it might look like with energy efficiency options deployed.

Table 1: Asset power requirements

Production wells

The producing well connects the reservoir, which is often many thousands of metres below the surface, to the process and facilities plant.

Understandably, operators are driven to maximising the flow of valuable hydrocarbons. The flow to the surface is constrained by the hydrostatic head of the fluid in the wells. This hydrostatic head can be reduced by lowering the fluid density by injecting gas into the well. Accordingly, gas lift, where gas is injected into the lower regions of the producing well, is often deployed on oilfields.

Not all wells behave in the same way, so allocating lift gas to each well is important. Gas lift optimisation is key to minimising the CO2 equivalent footprint of the asset.

There are established optimisation techniques that, given a constrained gas quantity, will consider the well thermohydraulics and identify gas rates on a best bang for your buck basis.

The regulating valve that controls well flow is referred to as the choke. As with most valves, the pressure drop across the valve results in non-recoverable energy. The obvious question is, could that pressure drop be recovered? Theoretically, a turbine could be used but the well duty is very erosive and that makes a turbine a concerning option.

Perhaps a more effective option for energy capture is from the well fluid temperature. Here a Rankine cycle could be deployed.

An organic liquid is vaporised by the heat from the wells and the vapour drives a turbine coupled to an alternator. The turbine outlet vapour is condensed and then pumped to turbine inlet pressure. The cycle is shown in Figure 1.

Figure 1: Rankine cycle

Oil, gas, water separation

A typical oil, gas, water train is shown in Figure 2. The train is designed to condition oil for export specifications and disposal of produced water to environmentally acceptable standards.

In this instance, the pressure from the well is stepped down in two stages of separation – high pressure (HP) and low pressure (LP). The LP separator is pressure- and temperature-controlled to vaporise the light hydrocarbons (methane, ethane) to ensure oil product vapour pressure control. Light hydrocarbons flashing off in a refinery tank are highly dangerous.

Oil heating also promotes oil-water emulsion breaking and water separation – the refinery does not want to buy water.

The major energy users are the export pumps and the interstage heater. The pump’s carbon footprint can be improved through the selection of high efficiency pumps, the sparing philosophy, use of variable speed drives, and optimised control system.

The main influences on pump hydraulic efficiency are:

  • disc friction (secondary vortex between outer surface of impeller and casing)
  • surface roughness
  • leakage (backflow from discharge through seating gaps)
  • mixing losses (flow direction changes)

These combine to reduce the hydraulic efficiency of the common centrifugal pump to typically 70–80%: the inefficiencies manifesting themselves as heat. Pump efficiencies exceeding 80% are possible by using advanced manufacturing techniques, but the penalty is increased capital cost. This is often the case with energy efficiency options – they cost more.

It should be noted that a pump operating at low efficiency might not be apparent to the operations engineer. Hence, opportunities to save energy by repairing or replacing components and optimising systems are often overlooked.

Pumps do exactly what you don’t want. As a consequence of the head flow characteristic, they produce higher pressures at low flows. To balance the hydraulics, the high discharge pressure is reduced across a control valve – thereby wasting energy.

Rather than a control valve, a variable speed drive could be used – matching speed to required discharge pressure and thereby improving efficiency. Similarly, pump sparing could be adopted, where multiple pumps in parallel are matched to throughput. However, both options increase cost and complexity.

Use of drag-reducing agents could also reduce pump power requirements, but such chemicals are very expensive.

The interstage heater generally uses a heating medium. The duty of the heating medium can be reduced by deploying heat integration – using the hot oil exiting the LP separator to pre-heat the oil leaving the HP separator.

Furthermore, pump mechanical losses in seals and bearings should be minimised, while deploying high efficiency electric motors.

Figure 2: Oil, gas, water separation train

Gas compression

Gas is a valuable sales product and, as previously mentioned, is also used to provide well lift. An associated gas compression train is shown in Figure 3.

The gas is compressed in stages. As the gas is compressed, the temperature increases. The compressor discharge temperature is a limiting feature for the mechanical design – typically 160°C. Hence the gas is cooled before being forwarded to the next downstream compressor. The cooling action results in the condensation of natural gas liquids. These are usually recycled back to the separation plant as they contain valuable liquid products such as propane and butane.

Highly efficient compressors can be manufactured, but as previously stated, a more efficient machine will cost more money and may take longer to fabricate.

Many industrial compressors will have an anti-surge control system that will recycle gas at low flow conditions. Alternatively, to avoid surging, suction throttling can be used to deliver increased suction volume. In both cases there is waste of energy, but it is simple, and it works – key aspects for low-capital, reliable operations.

Many control systems are set up too conservatively, resulting in unnecessary throttling and recycling. A review of the surge characteristics and control algorithms often delivers a low-cost energy win by allowing for operation closer to surge.

Like pumps, energy efficiency and surge management could be improved by deploying a variable speed drive.

Suction cooling reduces suction volume hence reducing compressor power requirements. Reducing piping and equipment pressure drops will also reduce power requirements.

Contractual obligations may result in operational line packing. Essentially, the pipeline is used as a reservoir of gas in case of supply failure. The pipeline can be unpacked to provide agreed gas delivery rates, allowing time for the supply to be reinstated. This means that the pipeline is operated at a much higher pressure than required for steady state conditions. While packing makes good commercial sense, it is poor from an energy efficiency viewpoint.

Between the HP2 and HP3 compressors, fuel gas is extracted to power gas turbines.

Figure 3: Gas train

Gas treatment

To condition gas for sales, a range of quality specifications are required. Common features are hydrocarbon and water dewpoint, temperature, pressure, and maximum composition of hydrogen sulfide (H2S), CO2, mercury, and sulfur compounds.

Water dewpoint limits are required to avoid corrosion and hydrate formation (ice-like solids).

Gas is often dehydrated to pipeline specifications by glycol absorption. The process is shown in Figure 4.

Figure 4: Glycol dehydration

Reconcentrated (lean glycol) enters the top of the contactor where it absorbs water from the rising gas. The rich glycol (high in water content) leaves the contactor at around 30°C and flows through the top of a still where it provides reflux to enhance glycol water separation. The rich glycol then flows to heat recovery preheaters. Heat recovery reduces energy consumption in the reboiler but at the cost of the heat exchangers.

The rich glycol enters a reboiler where most of the water is driven off at around 200°C. The hot reconcentrated lean glycol flows out of the reboiler into a surge drum.

The lean glycol is pumped and cooled back to contactor temperature and pressure.

The glycol reboiler is the main energy user. Reboiler duty can be reduced by heat integration as shown.

The contactor typically operates around 50 bar with the reboiler close to atmospheric pressure. The glycol pump can be turbine-driven using the high-pressure glycol, thus reducing energy requirements.

Care must be taken to optimise lean glycol concentration and circulation rate to minimise energy consumption.

Minimising the contactor pressure drop will reduce the energy requirements of the gas compressors.

Another similar absorption and regeneration process is used to treat gas to meet CO2 and H2S (acid gas) specifications. An amine-based solvent is used, and the energy efficiency options are similar to the aforementioned glycol absorption system.

A split-flow amine system can be used to reduce energy requirements associated with an amine system. Figure 5 illustrates a split-flow arrangement. Here the lower part of the contactor uses amine with a higher H2S/CO2 content to deliver a coarse cut at acid gas removal. The upper part uses a much purer amine but less of it, as the lower part of the contactor has removed much of the H2S/CO2. The split-flow arrangements reduce the reboiler duty but again will cost more.

Figure 5: Split-flow amine absorption

Water injection

Water injection is frequently adopted to improve the recovery of oil and associated gas.

As hydrocarbons are withdrawn from the reservoir rock, the pressure in the reservoir will decline and ultimately production will cease due to lack of pressure. At that point there may be considerable hydrocarbon reserves remaining.

However, if the volume of produced fluids extracted is replaced by an equal volume of water, then reservoir pressure can be maintained, and recoverable reserves enhanced.

The water also displaces oil from the rock pores, pushing it towards the production wells.

Figure 6 shows the main components of a water injection system. It serves three main purposes: solids removal, oxygen removal and pressure boosting of lifted sea water.

The main energy users are the lift, vacuum, and injection pumps. As a result of the volumes of seawater required, the injection pumps have a power requirement of many MWs. Indeed, one of the largest centrifugal pumps in the world is located on an oilfield in Azerbaijan – 4 x 27 MW. Improving the efficiency of the pumps is the same as discussed under separation.

To manage corrosion, oxygen is removed from the seawater using a vacuum deaerator. The vacuum pump is often a liquid ring pump.

The duty of the vacuum pump can be reduced by deploying multi-stages with the vacuum at each stage reducing to around 0.01 bara. Multi-stages saves energy as the upper stages provide bulk oxygen removal hence the duty at the lowest vacuum is less.

To meet the very low levels of residual oxygen required – typically 2–5 parts per billion – oxygen-scavenging chemicals are added to the deaerator sump.

Figure 6: Seawater injection


Like any process plant, the main process operations are supported by a range of utilities – HVAC, cooling water, instrument and plant air, lighting, chemical injection pumps etc.

Although of second order in terms of GHG footprint there are many energy savings to be made here. Every little helps.

Power generation

Figure 7 is from the North Sea Transition Authority’s Emissions Monitoring Report 2022 for UK oil and gas production facilities.1 It clearly shows that gas turbines are the largest source of CO2e emissions, with power generation the largest source of asset GHGs.

Figure 7: Facility emissions by source and category, 2021 (Original source: EEMS)

Upstream installations most often burn associated gas to produce electricity in open cycle gas turbines. The principle is the Brayton cycle as shown in Figure 8. Air is drawn in through inlet filters and compressed in stages by an axial compressor, and then passes to the combustion chamber.

Figure 8: Gas turbine thermal cycles

In the open cycle arrangement fuel and air are combusted. The combusted hot gases are expanded through nozzles and fed into a power turbine that drives an alternator. A portion of air is used to cool the outer surfaces of the combustion chamber and the turbine nozzles.

The thermal efficiency of an open cycle gas turbine is around 25–40%. The efficiency is affected by the parasitic load of the air compressor, the combustion temperature and pressure, use of diluent air to reduce material operating temperatures, suction air temperature, and site elevation. Aero-derivative gas turbines are often 5–10% more efficient than industrial equivalents.

As previously mentioned, the oil separation process often requires many MWs of heat input. A waste heat recovery unit (WHRU) could be deployed in the GT exhaust to heat a heating medium. The hot medium is used to provide heat for heaters and reboilers.

Combined heat and power can push thermal efficiencies up to around 80% – a very significant GHG footprint saving.

Another energy efficient option is combined cycle. Here a second open cycle is added to the exhaust gas. A heat recovery steam generator (HRSG) provides steam for a steam turbine.

Combined cycle will typically increase thermal efficiency from mid-30% to mid-50% – clearly a significant GHG reduction.

Gas turbines (GTs) operate most efficiently at full load. Figure 9 shows a typical efficiency trend against load for an aero-derivative gas turbine.

Figure 9: Gas turbine load vs efficiency

Consider an installation with 2 x 50%, 10 MW GTs operating with a load demand of 10 MW. Clearly the load can be served by operating one machine on full load, leaving a GT on standby. If the online GT trips then a standby machine can be brought into service. However, rapidly starting a standby machine can be problematic, resulting in failure to start with a consequent full power trip.

To avoid this, the operator will often operate two machines running on part load (spinning reserve), in this case two machines at 5 MW. This provides a comfort to the operator that, in the event of a GT trip, it is much more reliable to spin up an operating GT than start an idle machine. As can be seen from the load chart, two machines at 50% are operating with around 6% lower efficiency when compared to a full-load GT. Clearly, spinning reserve is a poor option for an energy efficiency standpoint.


Upstream operations like all chemical plants produce products to agreed specifications.

The cautionary note here is compounding contingencies. The buyer provides a specification, the design engineer adds a margin, and the operating staff add a margin. The outcome is a plant in operation using more energy than required.

Operations excellence

A stable plant is an energy-efficient plant. Plant trips often result in the need to safely dispose of the gas inventory with consequent impact on GHG footprint. Here the designer can also help, with compact plants with low gas inventories.

Control loop tuning can yield energy savings. According to Control Engineering, energy savings of 5–15% can be realised.2


Although not associated with power generation, flaring is a large contributor to GHG footprint.

Gas is continuously flared as a result of a relatively small continuous flow from process operations, passing valves, pilots, and purges. Large quantities of flared gas occur during times when the gas plant is unavailable, when the plant trips, and during startup. Note that flaring is preferred to venting, as methane has around 25 times the global warming potential of CO2.

Purge gas is required to prevent air ingress during low flow, flaring operations. Air ingress could initiate a running flame and explosion in the flare system. The purge gas is normally oxygen-free process gas and is therefore a continuous source of emissions. Operators tend to play safe and often use more purge than required.

Pilot gas is another continuous source of emissions. Pilot gas could be replaced by a spark ignition, but the industry generally views electric ignition as much less reliable.

In addition to minimising continuous flaring from process operations, a flare gas recovery system (FGR) could be deployed. Although seldom used in the UK, such systems are common in Norway. Figure 10 shows the key system components.

Figure 10: Flare gas recovery system

The flare valve is closed, and gas flowing to the flare drum in normal operations is returned to the process using the recovery compressor, hence there is no continuous flaring. Nitrogen is used as a purge to prevent flare header air ingress.

In the event of a plant trip and system blowdown, a large quantity of gas will be released to the flare system. This is detected by rising pressure in the flare drum (normally two out of three voting), the rising pressure initiates the opening of the flare valve and at the same time a ballistic pellet is fired at a striker plate adjacent to the flare tip. The pellet creates an array of sparks that ignite the gas. A bypass, bursting disc around the flare valve acts as a failsafe if the flare valve fails to open. This system avoids continuous flaring together with hydrocarbon purge gas and pilot gas.

Energy monitoring

The phrase “What you don’t monitor you can’t manage” is particularly relevant when it comes to GHG management.

If upstream operators are not given the tools to allow staff to measure and manage energy, then opportunities for GHG saving will be missed. Hence, the facilities design must incorporate appropriate metering and monitoring provisions.


A chemical engineer is trained to manage energy and I believe that most energy-saving opportunities will be self-evident to the chemical engineer. However, justifying them is another matter. Investment decisions will seek to find a balance between capital cost, operating cost, reliability, revenue, safety, environment, and company reputation.

Herein lies the quandary. Many energy-efficient options result in more equipment, hence increased capital cost and more complexity. More complexity in general means more leak paths making the plant less safe, more manpower, and reduced reliability. While energy efficiency will generally reduce operating costs, discounted cash flow makes it much less important to the accountant. The upshot is that many energy-saving opportunities are difficult to justify.

I began the article with a typical installation electric load list. Energy savings will of course be application specific. My experience indicates that by deploying energy-saving equipment and operational practices the revised load might look like Table 2 – a heat and power saving of almost 30%.

Table 2: Revised load list with deployment of energy-efficiency opportunities



Article by Tom Baxter CEng FIChemE

Chemical engineering consultant and visiting professor at the University of Strathclyde

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