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Ninety per cent of production lost. That was the worrying scenario the team in Malaysia faced when experiencing issues with the gas lift system on the Cendor Field. They needed to find a solution – and in their words failure wasn’t an option.

Operations, petroleum engineers, reservoir engineers and the offshore crew came together to evaluate a number of potential solutions to bring production back to life.

What was a difficult situation became a story about problem-solving and teamwork at its very best. The team was a collaborative force to be reckoned with and their solution was incredibly innovative, having never been done before in Petrofac.

A mature field off the east coast of Malaysia, production began on Cendor in 2006 with Petrofac acting as operator. The development comprises wellhead platforms connected to a floating production storage and offloading (FPSO) vessel.

Eventually, there comes a point in the lifecycle of a well when it won’t flow naturally anymore. As the oil depletes, the well pressure drops, and water starts to break through. As water is denser than oil, it becomes difficult for the well to flow naturally. A gas lift system injects gas at the bottom of the well to aerate the oil. In simple terms, it injects some fizz to lift the oil to the surface.

Huda Nawi, Head of Reservoir Engineering and Reservoir Management at Petrofac, explains: “The field’s wells comprises 80% water and only 20% oil, so we are highly dependent on the gas lift system and when we lost this in 2020, we lost 90% of our production.”

Before the gas lift system failed due to a parted flow line, the field produced on average seven thousand barrels of oil per day. The team was left with the prospect of very little oil from the field for at least eighteen months until the issue was resolved and a new gas lift line replacement could be procured and fabricated. They brainstormed a variety of options, with no stone left unturned. They never got disheartened as ideas were evaluated and disregarded.

These included using an existing water injection pipeline as a temporary gas lift line, an alternative artificial lift option like a submersible pump, as well as pipeline replacement options. In fact, they came up with around 20 ideas before whittling them down.

After much deliberation, the solution they settled on was a ‘finite energy gas lift system’ – using gas produced from a deeper, high pressure reservoir via an idle well directly connected at surface to the oil-producing wells. The advantages of this system were that it could be implemented quickly, it could accommodate a large number of wells, and it was inexpensive and relatively simple.

“The solution we chose required minimum modifications and it was cost effective – the turnaround was only about eight months,” says Huda. “We spent four months going through ideas, mitigating risks, and ensuring it could be done. Nothing like this had been done by Petrofac before, so we had to make sure we defined the problem and solution. It then took another four months to set it up.”

In the end, it was a gamechanger, and succeeded in recovering around 50% of production.







The team initially examined the idle wells (oil and gas wells which are not in use for production, but have not been sealed) in the surrounding vicinity to establish whether they could be a source of gas for the gas lift.

“The well we identified as a candidate had never been flowed or tested. We had to establish whether we had enough gas and enough high pressure gas,” says Huda, when talking about the technical difficulties they had to solve.

Lead Engineer Firdaus Ishak continues: “When we talked about which idle wells to choose, we had to understand the flow type – is it dry gas or wet gas? Based on our understanding, we believed the idle well would produce dry gas. However, in our projections, we included the worst-case scenario that it would produce wet gas, which would induce corrosion and over time we would need to replace the pipeline. So, we included the estimated costs to replace the whole set of pipelines in the project design.”

The team then had to work out how many wells in the field they could supply with gas, based on the pressure of the idle well. “The difference between this and a normal gas lift is that you have to supply a constant pressure into the wells without the aid of a gas lift compressor. The more gas you produce, the more the gas depletes and the pressure drops. So, if you are too aggressive and serve too many wells, suddenly after a few months there would be little production again. So, identifying the candidates to receive gas was also a challenge as was ensuring sustainability, as production needed to last for at least one year. Up to 12 wells received gas from the idle well.”

So, how does it work? They used high pressure gas from an idle well. A new, short pipe connection was fabricated between this gas source from the idle well and the existing gas lift headers. Then, the gas lift is re-distributed to the recipient wells accordingly.

“Nothing like this had been done by Petrofac before, so we had to make sure we defined the problem and solution.”
Huda Nawi

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Explained: A finite gas lift system

Dynamic modelling forecast how much gas they could flow from the well without a significant drop in pressure. The team then monitored pressure and flow daily to ensure this corresponded with their results from the dynamic modelling. And from the data available, the team saw no corrosion and confirmed the well is indeed flowing dry gas.

But, there was an unexpected issue when production commenced, as Firdaus continues. “When we opened the idle well for production as the gas lift source, we found there was no flow. We quickly investigated with the team and found that there was liquid trapped in the well inside the tubing. The team quickly arranged for a temporary chiksan connection to connect the well to the production header. By diverting the well to the production header, it had more capacity to flow with lower downstream pressure to release and unload the well. Then we diverted the well back to the gas lift header.”

In just a few days, the idle well was up and running. The finite energy gas lift system was subsequently successfully replicated in a second well on a second Cendor wellhead platform.

What is perhaps even more impressive about this project is that it was done during the pandemic amid some of the tightest restrictions in the world at the time. “We were monitoring our laptops at home,” says Huda. “All the brainstorming was done online.”

So, what lessons have they learned? “We needed to be agile, we needed to act quickly, and we needed to be open with effective collaboration and communication. We needed to think outside the box here,” says Firdaus. Huda adds: “Before you even start anything, you have to define the issue at hand holistically. Once you understand your parameters you can start looking at solutions.”

Both Huda and Firdaus say that it has been incredibly rewarding to see the team’s idea come to life. “Within the space of a year, we were able to come up with a solution, test it, execute it and gain a lot of production,” says Huda. “There was a lot of hard work from a lot of people to make it happen.”

“Seeing the production increase from day to day was really satisfying,” says Firdaus. “We were able to bring production back to life.”

At the time of writing, the Cendor gas lift system has now been safely and successfully reinstated. Petrofac Malaysia assembled a team to undertake a project called the ‘Cendor Pipeline Riser Replacement Project’; that project was executed well despite the typical challenges associated with a project small or large.

“We needed to be agile, we needed to act quickly, and we needed to be open with effective collaboration and communication.”
Firdaus Ishak

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