Hydraulic fracturing, or fracking has helped spark U.S. oil and gas output in the past five years, but the practice also uses massive amounts of fresh water. Millions of gallons of water are needed to frack just one well. A lack of water can easily hinder fracking, which would in turn slow oil and gas output.
To ensure a continuous water supply for fracking, some drillers – especially drillers in parts of the country affected by droughts and water shortages — are exploring the use of recycled water. Drought has become an issue in Texas over the last few years, and although the recycling practices are slow to catch on there, some of these new methods are proving to be very beneficial.
Apache Corporation has more wells in the Permian Basin of West Texas than any other drilling company. In fact, in the Permian Basin’s Wolfcamp shale play, Apache is a water recycling pioneer. The production manager for Apache says that the company recycles 100% of “produced” water, a byproduct of oil and natural gas drilling. Moreover, the company recycles “flowback” water, the water that is pushed out of the well during the fracking process.
In addition to the recycled, produced and flowback water, Apache uses brackish water from the Santa Rosa aquifer, and has completely eliminated the need for a fresh water supply from at least one of its oil wells in Wolfcamp.
Apache treats produced and flowback water with chemicals to remove bacteria and unwanted minerals such as iron. Once treated, the water is stored above ground and piped to a well to use in fracking. Recycling has turned out to be an economical solution for Apache: treating flowback water costs an average of 29 cents a barrel. If the flowback water isn’t recycled, Apache has to pay $2.50 per barrel for a third-party company to dispose of it.
Slowly Catching On
Despite Apache’s successes with reusing water, recycling has been slow to catch on in most of Texas. Although a recent drought caused a shortage of water, in general, fresh groundwater is low cost and plentiful. Furthermore, waste disposal is relatively easy in Texas compared to other states. For example, in the Marcellus shale play in Pennsylvania, operators must drive their waste to Ohio because the geography around the play doesn’t allow for disposal wells.
Although slowly, water recycling is catching on in the Lone Star State and Apache isn’t the only company to reuse fracking water. For example, Fasken Oil and Ranch, operating near Midland, recycles close to half of the water it uses for fracking. However, unlike Apache, which has saved money by recycling, Fasken says that recycling is actually adding to their cost—about $70,000 for each hydraulic fracture. In this specific case, recycling is costly for Fasken because access to fresh groundwater from the 165,000 acres owned by the company bears almost no cost.
Permit applications show further evidence that water recycling is catching on in Texas: Applications for oil field water recycling have gone up from just one or two per year to 9 so far in 2013, and 13 last year. However, there may be more even more recycling going on because the state does not require “mobile recyclers,” which recycle water on or near a fracking site, to get permits.
Conclusion: The Future of Water Recycling
Although water recycling hasn’t eliminated the demand for fresh water in fracking, there has been a shift in attitudes in recent years. Because of factors like droughts and community concern over water usage, companies are beginning to see produced water as an asset instead of waste that needs to be disposed of. If water recycling becomes fully adopted by oil and gas companies, then it’s likely that more money will go into future development. The possibilities go beyond fracking, too – water is already used for other purposes, such as cooling water in power plants. If water recyclers can get water clean enough that it can be used for drinking and household purposes, we could see considerable value.
The original source for this post can be found here.
On the 50th anniversary of the issuing of the first licenses for the extraction of oil and gas from the UK continental shelf (UKCS), we asked oil executives what their main concerns were in an increasingly challenging period in the sector’s turbulent history.The consensus was that the industry needs to learn to collaborate if it is to survive these challenges.
Issue 1: Operating expenditure is going up while production forecasts are going down
Production from assets fell by 38 per cent between 2010 and 2013, equating to a drop of around 500 million barrels of oil equivalent (boe) and a drop in tax receipts of approximately £6 billion.In exploration, just 15 wells were drilled on the UKCS last year, compared to 44 in 2008, while operating expenditure rose to a record level of £8.9 billion, and is expected to increase further to about £9.6 billion this year. But there are reasons for optimism: while approximately 42 billion boe have been produced from the UKCS to date, it is estimated that a further 24 billion boe could remain.
Issue 2: The contracting model is failing from the cost base perspective
Attendees at an executive briefing noted that the supply chain had received little mention in the Wood Review. Significant sums were being spent on ‘low value-high volume’ work, leading the executives to consider the question: is there a genuine appetite within the industry to look at a transitional approach to costs in terms of fixed price agreements? One executive commented “We’re not talking about the 2009 solution of going in and saying rates have gone down by 10%. That’s not going to work. We have got to see cleverer business models. That may include more remote location working not just in Manchester … but going much further, to India or China for example, to try and get services from there.”
Issue 3: The industry is not planning for decommissioning
Oil executives in the North Sea recognise that the industry needs to plan more effectively now for end of life assets, or face potentially catastrophic consequences down the line. “The industry is not planning for decommissioning, we are just hoping (an incident) won’t happen, then when something does we will cope with the crisis and everybody will jump into action. But nobody is willing to take that first step,” the head of one company said. It has been suggested that decommissioning costs should be included in the design stage to offset their impact.
Issue 4: A new regulator will not change anything
While the Wood Review’s approach to regulation is welcomed, many executives are questioning what we can expect to be different this time around. “Why should we expect a new nirvana with the Regulator?” asked one operator, while others expressed doubt as to whether the Regulator would be able to push back against future treasury demands.
Issue 5: The industry is facing a knowledge shortage, not a skills shortage
While much has been made about the shortage of skilled people in the oil and gas industry, not enough is made of the importance of knowledge transfer, which requires greater collaboration within the industry. “Working on a brownfield site can give you the ability to learn the skills to work on a greenfield site, but you need to have gained that experience beforehand to make that change,” said one director. All these issues require collaboration in an industry in which, as one operator said, “competition is bred into you”. These concerns are just some of the key points raised at an executive briefing we held with executives from across the industry.
The original source for this post can be found here.
Originally posted on Our Finite World:
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