Can oil and water really mix? (part 1)
About to enter its fourth year, the California drought has resulted in stringent controls on water usage, to say the least: Governor Jerry Brown has imposed unprecedented measures to cut water use by 25 percent across the state—and even though farmers in the delta of the Sacramento and San Joaquin rivers have volunteered extra reductions, efforts to stave off further mandatory cuts have failed thus far.
However, as California’s agriculture sector struggles to reduce its consumption of water – estimated to be 80 percent of the state’s total – eyes are turning to California’s other big producer: the oil and gas industry.
California is not only the biggest producer of fruits, nuts and vegetables in the U.S., the state is also the third biggest producer of oil in the country, extracting roughly 200 million barrels per year. The rock formations that bear oil in the region also tend to harbor large volumes of brackish saltwater. The ratio of water to oil produced by operators in the region is, on average, ten to one.
As Chevron recently explained, the Kern River oilfield neatly illustrates the situation.
Kern River is the second-highest producing oilfield in California; moreover, for every barrel of oil, the field also produces around nine barrels of water.
Almost 25 percent of this water is treated to remove solids as well as free, dispersed and dissolved hydrocarbons before being used in enhanced oil recovery (EOR) applications. Because the Kern River field tends to produce heavy oil, steam flooding is used to reduce the crude viscosity and boost production.
Continuing with the case of the Kern River oilfield, 75 percent of the produced water is not required for further oil extraction, which is at the lower-end of the range for oil producers in California (many of whom often have to dispose of, or find ways to re-use, up to 99 percent of their produced water).
This, coupled with recent discussions by state officials regarding the closure of nearly 100 disposal wells, will more than likely push the reuse of this produced water even further.
Naturally, however, that remaining water still needs to be treated, and until now there has been little economic incentive for operators and farmers to get together in an effort to work out a deal for the treated water: Historically, re-injection has been cheaper than re-use given the treatment that is required even for agricultural purposes.
But that financial equation has not taken into account a record-breaking drought, nor does it allow for the precipitous drop in oil prices, which have had a heavy impact on the state’s producers’ bottom-line: On the one hand, farmers need water to maintain healthy production of essential crops; on the other, oil producers are looking for innovative and cost-effective solutions to boost their margins.
For the most part, these solutions look at how best to optimize output from existing wells or minimize production costs.
But technological advances mean that there are now solutions available that make it possible to treat produced water on a much more cost-effective basis.
Not only does this reduce the OPEX associated with finding new freshwater or disposing of produced water safely and compliantly, it could provide oil producers with a new asset to offer to market: water that is fit for agricultural purpose.
The numbers add up. Farmers typically buy fresh water at approximately 25 cents a barrel. Even taking into account a lower cost for recycled water – say 18 cents a barrel – it is now possible to perform the necessary processing for less than this amount for significant quantities of produced water, if not all of it. Even considering initial capital costs, when the difference is factored up by several million barrels a day, the results can be significant both for the operators and the farmers.
So what treatment is required in California?
Look for the answer in the second part of our two-part series, coming soon!
Drax advances biomass strategy with Pinnacle acquisition
The Group’s enlarged supply chain will have access to 4.9 million tonnes of operational capacity from 2022. Of this total, 2.9 million tonnes are available for Drax’s self-supply requirements in 2022, which will rise to 3.4 million tonnes in 2027.
The £424 million acquisition of the Canadian biomass pellet producer supports Drax' ambition to be carbon negative by 2030, using bioenergy with carbon capture and storage (BECCS) and will make a "significant contribution" in the UK cutting emissions by 78% by 2035 (click here).
This summer Drax will undertake maintenance on its CfD(2) biomass unit, including a high-pressure turbine upgrade to reduce maintenance costs and improve thermal efficiency, contributing to lower generation costs for Drax Power Station.
In March, Drax secured Capacity Market agreements for its hydro and pumped storage assets worth around £10 million for delivery October 2024-September 2025.
The limitations on BECCS are not technology but supply, with every gigatonne of CO2 stored per year requiring approximately 30-40 million hectares of BECCS feedstock, according to the Global CCS Institute. Nonetheless, BECCS should be seen as an essential complement to the required, wide-scale deployment of CCS to meet climate change targets, it concludes.