Decisions about how and when to implement techniques and infrastructure to address declining wells are difficult to make. companies need a fresh approach to technology to get the best out of those wells, writes piers ford
Getting the best return from brownfield sites remains one of the greatest and most complex challenges for the oil and gas industry. With so much already invested in technology and infrastructure, decisions about how and when to address declining production are invariably based on a complicated mix of financial, technical and geographical considerations – all of which will vary according to the individual circumstances of a well.
A 2011 white paper from The Boston Consulting Group (BCG), Mature Fields Matter, shows how operations come under severe strain in brownfield sites.
“Ageing wells and facilities create integrity and reliability challenges, making operations less predictable and damaging performance,” according to the report.
“Meanwhile, partner engagement can become complex as the fields face declining importance in partners’ overall portfolios, and gaining approval for investments becomes more challenging. In response to this challenge, many larger operators have in recent years divested mature assets to smaller or more focused specialists, feeling that their capital is better deployed to fund long-term growth investments.
Others have continued to invest, either unwilling to give up reliable foundations to their production base, or socially committing to remain in countries that represent their ‘legacy heartlands’. At the same time, selected mature field specialists have delivered widely publicised successes.”
As well as creative project framing, valuation, and accelerated development planning and execution, BCG also identifies structured technology application as a key lever for boosting the productivity of mature fields.
The incentive is clear. The need for fresh approaches typically kicks in once 40% of a well’s resource has been realised, when unreliable pressure and the varying consistency of oil in the reservoir become increasingly disruptive.
However, according to Frost & Sullivan, if companies could generate just one percent more efficiency from their existing wells, they could supply global demand for oil for between three and five years (based on 2013 consumption).
“In a greenfield site, you have natural pressure,” explains Ole Njaerheim, managing director of Econ Oil & Gas, who acts as a contractor to global consultancy Pöyry. “When you start producing, it falls, and in the end there is very little pressure – and then you get less oil.
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Other complications could arise with flow characteristics, which might deteriorate between different areas of the reservoir. One way to maintain pressure is to inject gas or water into the reservoir. Or you might consider fracking technology, or drilling new wells to other parts of the reservoir. Any consideration will be measured against the cost and likelihood of increased recovery.”
Added to this, the top side equipment, always a vast capital outlay, might not be suited for the later phases of a reservoir, and pressure injection technologies that use water usually require processing facilities to separate the oil once it has been extracted.
“These are critical issues, particularly in areas where lifting costs are high in relation to the value of what’s actually coming out,” says Chris Shannon, CEO of Fotech Solutions, which supplies the industry with Distributed Acoustic Sensing (DAS) technology for gathering data about the exploration, production and delivery of oil and gas.
“Without this information, it is much harder for operators to assess any well integrity issues and make sound commercial decisions about the future of a brownfield site. If you look at Iraq and Kuwait, for example, many of the big global companies have massive brownfield sites, with infrastructure that is tens of years old – and technology to match.
The bulk of the efforts are spent trying to manage and maximise the production of each well. When drilling on brownfield land, it’s difficult for engineers to truly know exactly what the state of the site is ad how much product there is left.
Given the lack of visibility engineers have of down-hole operations, it’s difficult to get completely accurate information from well surveys to monitor the drainage of reservoirs in the fine detail required to maximise the efficiency of drilling operations on brownfield sites.
Gaining high quality real-time intelligence to inform and accelerate decision making before, during and after the extraction process is a challenge for the oil & gas industry in general.”
Shannon said the unique challenges of working on brownfield sites has driven the search for technologies that give greater visibility of down-hole procedures deeper into the science lab.
“Once in a while an innovation in technology will create a breakthrough,” he explains. “In the 1990s the breakthrough was Distributed Temperature Sensing (DTS) using fibre optic cables as a temperature sensor, which started life in university laboratories but is now used extensively in the oilfields around the world.”
“The breakthrough technology of this decade is DAS, which uses a fibre optic cable as an acoustic sensor that senses the movement and changes in well characteristics via acoustic vibrations allowing the geoscientists and engineers to ‘visualise’ and record what is going on down hole at every point of the well in real time. This gives well engineers greater clarity than ever before and allows them to focus time and effort on value-adding activity and, ultimately, increasing recovery,” he explains.
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Iguerran Ripert, senior consultant at Frost & Sullivan, agrees that digital systems are increasingly important, meeting companies’ needs to know more about how well their equipment is reacting with the extraction technologies being used.
“Connecting to a central analytics capability in real-time means you can see the immediate effect of increased pressure or the combination of surfactant, and that means you can react accordingly,” he says. “These companies want to spend as little as possible and need to find easy ways to make fast, effective decisions.”
Oil & gas companies remain focused on the mechanical challenges of enhanced recovery in brownfield sites. The Petroleum Institute (PI) of Abu Dhabi, for example, is collaborating with BASF on research into technologies for removing aggressive sulphur compounds from acid gases, and exploring the use of absorbents to develop methods with low energy consumption.
“BASF’s gas treating solvents react with the acid components like CO2 and H2S from incoming gases in an acid-based reaction,” said Jens Rudolph, who is responsible for Middle East in the OASE global gas treatment team of BASF.
“The acid components are then separated from the solution by adding energy, allowing the gas treating solvents to be recycled. This process requires relatively low energy input, featuring very high availability, and delivers high yields of high-purity gases.
It is flexible enough to allow specific gas components to be separated selectively. For example, the process facilitates the selective removal of H2S from a gas that contains both CO2 and H2S. The gas treating solvents that are used feature high stability and a long, useful life, requiring minimal replenishment as a result.”
The problem of liquid loading is particularly acute for brownfield gas production. Corac Energy Technologies, which focuses mainly on technology research and development in the fields of natural gas compression and enhancing gas well production, is developing advanced compact compressors to enhance performance in gas production.
“As pressure in the reservoir falls, the wells begin to load with liquid and methods to remove water are required to maintain gas flow. Even in higher producing fields, some wells will decline faster than others. If the common line is at a higher pressure fed by the healthier wells, the weaker one will stop producing,” says Phil Curtis, commercial enterprise director at Corac Group.
Corac compressors have been developed using patented technologies including gas bearings, compact permanent magnet motors and advanced aerodynamic and cooling concepts. The result is a compact machine that in the down-hole case can be packaged inside the seven inch casing of a typical gas well.
“The biggest challenge faced so far is the management of liquids and other contaminants in the gas stream,” said Curtis.
“The compressors themselves are tolerant of a limited amount of fluid, but when this is exceeded, external conditioning measures are necessary. Corac is working with partners to complement the core compression technology with separation and re-introduction systems to work towards an integrated solution, much of which will be located within the production pipework.”
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Frost & Sullivan’s Ripert said oil recovery technologies fall broadly into three categories: established, a second generation of increasingly integrated variants, and experimental technologies.
Established technologies include steam flooding, cyclic steam stimulation, which uses vibration to detach more viscous oil from cavities in the reservoir, miscible gas, which uses gas with properties that attach it to oil, and changes the heat capacity of the product), polymer flooding, steam assisted gravity drainage and low salinity water flooding.
A second generation of technologies includes alkaline surfactant polymer (a type of soap that attaches to the oil without sticking to the well), high pressure steam injection, contaminated acid gas, in situ combustion heavy oil recovery, and in situ upgrading, all of which provide variations on established technologies that can be used to suit different factors: rock type, oil quality and geography.
However, some of the evolving technologies that have captured the imagination of the major companies at an early stage are likely to have a significant impact as demand grows for more efficient and environmentally friendly ways to exploit oil remaining in brownfield sites.
One of these, microbial enhanced oil recovery, uses bacteria that are harvested and thrown into the well, where they thrive in certain temperatures and produce carbon dioxide, which raises the pressure.
This builds up organically so that it is equal across the site.
Once the bacteria have done their job, the temperature is raised and they are destroyed. Shell is among the giants investing in this technology, which Ripert said is probably still 10 years from being commercially viable.
“The reason why these technologies have emerged is that steam and pressure techniques have limits and become very expensive once production is past a certain threshold,” he says.
“Also increasing pressure in non-homogenous environments could be dangerous, because certain parts of the well might be very fragile. With microbial technology, still very much an experiment, there are fewer fissures because you are making a less damaging entry into the well.
Other emerging technologies such as nitrogen and carbon dioxide foam are also a nice way of minimising the environmental impact. The carbon dioxide foam has properties which expand as the temperature increases, which helps the oil to come out, but it is essentially a neutral substance.”
