Less salt, more oil
When it comes to injecting water into hydrocarbon reservoirs to improve oil recovery, BP has determined that lowering the salinity of the water can have the welcome effect of delivering more oil
For BP, the latter is the case - and a very welcome one - for an investigation which the company began in 1992, delving into a phenomenon which appeared to hold out the attractive promise of helping BP produce more oil from its reservoirs. The investigation, which sought to find out why water of lower salinity than that normally used in reservoir waterflooding operations seemed to coax reservoir rocks into releasing more oil, recently culminated in a significant success on the North Slope of Alaska.
'We have been conducting a carefully designed and monitored field trial in the BP-operated Endicott field in Alaska for more than a year now,' says Andrew Cockin, research and development manager within BP's Pushing Reservoir Limits (PRL) team in the company's exploration and production technology group. 'The purpose of the Endicott trial was to determine if injection of reduced salinity water is as effective when applied at scale in the field as it has shown to be in the laboratory. This has proved to be the case - the additional oil production has exceeded what we would expect from conventional waterflooding techniques.'
Such is the confidence in the effectiveness of this approach to enhanced oil recovery, backed by BP's in-depth understanding of how it works and how best to apply it, that the company has trademarked its know-how as LoSal™ enhanced oil recovery (EOR) technology, a proprietary technique which is now a technology leadership area within BP's exploration and production portfolio.
'We saw a real difference in recovery at Milne Point and it confirmed ideas we had about the advantages of controlling the salinity of injected water,' says reservoir engineer Kevin Webb, low salinity subsurface project manager in the PRL team. 'The events at Milne Point added to the growing evidence that we were on the right track.'
For much of its history, the major mechanism behind waterflooding was considered to be a physical one - where the pressure of the injected water is used to sweep oil out of the reservoir and into the producing wells. Polymers, for example Bright Water™, were developed to improve the physical mechanisms behind the sweep - Bright Water was based on a BP idea and co-developed by BP and other companies, including Nalco (Frontiers, December 2007).
When it comes to the chemistry of waterflooding, there is good understanding of some aspects of the chemistry of the injection water - seawater, for instance, contains sulphates which can combine with elements such as barium and strontium present in formation water to create unwanted sulphate scales that can precipitate in plant facilities or in the reservoir itself, requiring scale inhibitors to be applied. But generally, less consideration has been given to how the chemistry of the injection water itself could influence the mechanism and degree of oil recovery.
The conceptual breakthrough came during a study designed to elucidate why some rocks tend to become more 'oil wet' while others lean towards being more 'water wet'. Laboratory experiments conducted during the course of the research hinted at an increase in oil production when the salinity of injected water was reduced. These observations were later confirmed at BP's Sunbury laboratories by flooding tests of oil-bearing rock cores taken from a reservoir. The combined evidence indicated that the benefits of using reduced salinity water for waterflooding were potentially significant.
Appreciating the possible impact of the findings, from the late 1990s onward BP continued to work with researchers at the University of Wyoming, led by Professor Norman Morrow, to explore this hypothesis further. After carrying out more than 30 flood tests using reduced salinity water on core samples from different reservoirs around the world, Webb and his colleagues at BP were excited.
'Every time we carried out a core flood test we saw more and more benefits,' Webb recalls. 'Our test results showed that reducing the salinity of the injected water resulted in improvements in oil recovery ranging from two to three per cent in some reservoir rocks to over 40 per cent in others.'
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To understand the effects on a larger scale, in 2003 the team began carrying out single well chemical tracer tests in a number of BP reservoirs around the world. These tests, which inject a chemical tracer into a reservoir and can measure the amount of oil left in the rock, make it possible to analyse the effect of different salinity brines on oil recovery up to six metres into the reservoir. They revealed that controlling the salinity of injected water could improve oil recovery by up to 54 per cent.
The road to Endicott
With such positive results coming in, all of which were adding to BP's understanding of the recovery mechanisms involved, the next step was to test the performance of LoSal EOR technology at the field level in an inter-well test. Two wells in the Endicott field in Alaska were chosen, one a producer and the other an injector. The test involved injecting low salinity water into the injector, then monitoring the resulting changes in oil recovery in the producer over a timescale of many months.The Endicott field, located on the Alaskan North Slope adjacent to the giant Prudhoe Bay field, is the first 'offshore' development in the Arctic - the field is operated from a man-made island connected to the mainland by a causeway. Endicott came on stream in 1987. The field, which produces from a high porosity, high permeability sandstone reservoir, had estimated oil in place of just over one billion barrels, plus some 30 billion cubic metres of gas. Around 500 million barrels of oil have so far been produced.
'Sand quality, the proportion of clays and the amount of residual oil after waterflooding combine to make Endicott a well-suited place to employ the LoSal EOR mechanism,' says John Denis, BP's resource manager for the Endicott field, based in Anchorage.
'The Endicott team had the appetite to take on the challenge of testing and proving this new technology but the logistics involved in carrying out such carefully controlled tests in an Arctic environment were very challenging.
'We were employing new or developing technology on several fronts. Working with vendors and co-ordinating this work from Anchorage with the field teams on the North Slope required a constant focus, but we received great support and engagement in what we were doing.'
The injection of reduced salinity water ended in May 2009, says Chris Mair, a reservoir engineer who works with BP's LoSal EOR deployment team.
'The results were exciting. We saw an increase in oil output in the producing well, combined with a drop in water cut,' he reports. 'The Endicott team is continuing to monitor the effects of LoSal EOR water injection in nearby wells, but the data so far confirm that the mechanism works at the reservoir scale - not only to release oil from the rock, but also to allow more of that oil to reach the producing well. It's a great result.'
BP's believes its fundamental understanding of the technology and accumulation of know-how, supported by its growing intellectual property portfolio, has made its LoSal EOR technology distinctive.
'The results of the inter-well tests at Endicott,' concludes Webb, 'are the keys to unlocking other LoSal EOR developments. Endicott is now a candidate to benefit from the full scale deployment of LoSal EOR, and BP is also studying other offshore applications of the technology.
'Our vision when we started was to make low salinity water the water of choice in BP's sandstone reservoirs. The 10 years and more we've spent working on LoSal EOR technology encompass a whole sequence of events and a technology which could change the world of waterflooding as we know it.'
LoSal™ EOR is a trademark of BP plc
Bright Water™ is a trademark of Nalco Company
