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NGL production out of associated petroleum gas

Michael Boldyrev, head of gas processing department

After the “Russian LNG market: new frontiers of development” conference materials

A hydrocarbon gas is a source for natural gas liquids (NGL for short), while the cost of NGL production depends primarily on source or feed gas quantity and quality. The rest of the process parameters — even the volume of the end product is secondary and play no big role.

A 100 mln. scm/year associated petroleum gas (APG for short) processing plant costs around 25 — 30 mln. USD on turn-key basis; a cryogenic plant of 0,5 billion scmy of natural gas (from a gas condensate production field) costs a comparable 30 — 40 mln USD on the same turn-key basis. Your typical “paper plan” payback period on such investment is 3-5 years. Despite this, deviations of a “real-life” return on investment period may be quite substantial.

However, if we were not sure that a good project is a reachable goal we wouldn’t start this topic to begin with. So, what is the way of our thinking that has led us to this subject from the start?

There are two ways to become entangled in the propane-butane fuel production: to be a part of the NGL market or to be a part of NGL production process i.e. to play a part in design, fabrication and procurement of the process equipment. Our case is the latter.

APG utilization

Mid 2000-s have seen a massive push towards reduction of harm to the environment from APG flaring by many governments (and Russia is no exception) onto the production companies. The producers of the APG are companies that are initially in the business of exploring crude oil deposits and recovery of crude. APG is not a part of their business and was of no concern to them. So the drive to reduce APG flaring has turned into an ultimatum to “utilize 95% of the produced APG volume”. This regulation was supported by the penalties and sanctions towards the companies that were reluctant to invest their capital into new and daring process technology.

An interesting fact: A requirement to utilize 95% of the APG is stipulated in the Russian Federation State regulation that was passed on the 8 November 2012 and bore a heavy title of Regulation N 1148 “On the aspects of penalties calculation for pollutants produced by associated petroleum gases incineration by flares or venting”.

This regulation only refers to the mineral resources recovery companies, i.e. the same APG transferred to the other entity for treatment/process is considered fully utilized... whatever happens with the gas at this treating/processing entity does not concern the regulator.

Unwillingly the oil companies began to search for “gas utilization” methods. Lack of in-house gas-process professionals within the oil companies and a backward attitude of existing engineering companies employed by Gazprom or similar regional monopoly companies such as Kazmunaigas in Kazakhstan, united national company in Turkmenistan, family consortiums in Uzbekistan and such created an opportunity for new businesses that have previously never dealt with the oil producers to occupy the market for design of APG solutions and subsequent equipment procurement. Within 10 years a whole new market of clients and customers was formed and the capex for first implemented solutions generally went through the roof.

For example, the cost of Lukoil-Overseas projects for “Turgai Petroleum” and “Karakudukmunai” were 1,5-2 times higher than the normal figures we’ve given at the start of the article.

On the other hand, smaller companies had to deal with their APG as well. Without the abundance of capital of their larger colleagues these had to exercise a different approach and have ended up with a reasonably priced production. There were, of course, shortcomings in both scenarios (such as ineffective process adaptation, mistakes in the end products predicaments, overstaffing of the operational personnel etc.) but in the end this situation has created an opportunity for a new wave of engineering companies specialized in gas processing.

NGL production

We were fortunate ourselves to successfully complete three projects: two small scale gas processing plants with NGL production (around 50 thousand tons of NGL product a year each):

Along with these two we have implemented a rather unique ethane production project in the Tatarstan Republic, where the ethane production increased by 40%.

Our team has played a key part in these projects while generally keeping to the financial estimates provided at the start of this article. This is an encouraging fact that allows to assume that we’ve accumulated some valuable positive experience.

We are now witnessing a fall of the “APG-utilization” wave, however an overall demand for gas treatment and processing is still there. The base has grown. As a result, there is a lot of potential NGL projects currently on the market: whether the feed is APG, gas condensate fields, refinery and petrochemical gases. The process trains are quite similar in all cases. There are aspects peculiar to each feed gas scenario but there aren’t fundamental differences.

Gas composition

It’s simple. From the physics standpoint APG, natural gas or refinery/petrochemical gases do not differ. There is a hydrocarbon gas at a certain pressure, containing a range of target components and additives. Typical feed gas parameters are as follows:

Natural gas (APG included)

Petrochemical and refinery gas

Processed products

C1 (methane)

C1, H2 (hydrogen)


C2 (ethane)

C2, C2 = ethylene

Gas or NGL

C3 (propane)

С3, С3 = propylene


C4 (butane)

C4, C4 = butylene


C5+ (penthane and heavier)



H2S, CO2, N2 etc.

H2S, NH3, CO2 etc.


There are, of course extremes such as an 89% nitrogen content in a Bashkiria and sub-Ural APG, low pressures of Natural Gas at depleted production fields, extremely lean gas of Senoman layers, high sulfur content in the Bayanda and Astrakhan production fields. Gases such as these bring some fun and enjoyment to an engineer’s life and are likely to ruin investment mobilization... On the other hand, generally the gas composition is a slight variation of the content shown in the table above.

NGL production abroad

North America (USA and Canada) leads the way in the international NGL production. Gas production of the region was always more or less on par with the production in Russia, but NGL production was several times larger than that in Russia. A typical North American process flow diagram is illustrated below.

Gas processing in this market is occupied by a swarm of highly specialized companies that form a whole sub-industry called “midstream”. Midstream-companies’ business is to collect and treat/process the gas that is provided by different production companies. NGL is a key product of their process. Depending on the contract, NGL end product either becomes the midstream company commodity or is transferred back to the production company for a fraction of the cost to compensate the process capex and opex.

Midstream companies’ numbers in the northern America is huge. There is even a particular form of ownership — MLP (Master Limited Partners), that is devoted to this activity and serves for quick investment mobilization, set up and launch of a gas treating/processing company, profit earning and subsequent disengagement to look for new project opportunities.

Throughout the 2000 a number of midstream-companies in the US alone was in the range of 150 — 250 companies, decreasing with the crisis years and booming again after the shale gas expansion. Needless to say Canada is an apt follower in the number of such businesses.

To give one a comparison in Russia as an outcome of the “APG utilization” campaign only two specialized gas processing companies evolved. Namely BlueLine that built two plants in Khanty-Mansiisk Region and Globotech, that has tried to implement a project in Tomsk region. The second company has perished since.

This really sums it up. All of the other gas processing facilities are either incorporated into the production holdings or, such as in the Sibur case, petrochemical companies. Having said that, Sibur may be the closest comparison to one of the top 10 US midstream-companies.

Subsequently, according to Minenergo (Russian State Ministry of Energy) statistics a meagre 11.4% of the produced gas in Russia has been processed in 2014.

By 2020 (realistically by 2030) this percentage will double when Amur gas processing plant will become operational. At the same time when the process is not artificially overcomplicated a standard LPG production plant may be constructed and commissioned in 16-18 months. From scratch. This is the time from the investment decision being made to turn key commissioning.

Turboexpander unit for gas temperature decrease in gas fractionation process


Minnibay GPP compressor equipment yearly technical maintenance


Glycol dryer


"Keymir" gaslift compressor station startup and commissioning