One of the most affected segments of the oil and gas industry in the lower-for-longer price environment has been offshore EOR. In the early 2010s with the price of oil sitting comfortably in the $90-plus range research institutes and federal agencies like the National Energy Technology Laboratory (NETL) and the U.K.’s Oil and Gas Authority (OGA) were touting the potential recoveries and economic value that EOR afforded.
For example, in June 2014—when oil was trading for more than $108/bbl—NETL published a study into offshore CO2 EOR that reported more than 4.3 Bbbl of oil were recoverable with “next-generation” CO2 technology. The report promoted a sense of urgency in recovering oil from mature Gulf of Mexico (GoM) fields but also made the push based on the assumption of $90/bbl oil. And although the potential recoveries and need to optimize production in offshore reservoirs may still be accurate and relevant, the reality is that few companies are willing to spend the millions of dollars it takes to implement widespread EOR efforts offshore in an environment in which companies are looking for ways to curb spending.
Despite that, some companies are preparing for a future in which offshore EOR eventually is economically feasible—a future that might not be too far off. And while other companies wait for the proper economic window to unleash EOR offshore, BP is moving ahead with its LoSal technology and a variety of other EOR methods that company experts think are key to its offshore portfolio, even in a sub-$50/bbl oil economy.
The U.K. has seen such a need for EOR in the U.K. Continental Shelf (UKCS). The OGA published a report last year summarizing the substantial economic impact EOR production would have in the UKCS and outlining a plan on how to best implement widespread EOR methods. The report claimed that 250 MMboe in incremental reserves are recoverable in the UKCS over the next decade, primarily through polymer EOR.
“Successful EOR can play a huge role in maximizing economic recovery from the UKCS,” the report stated. “EOR can significantly increase the volume of recovery [and] extend field life by as much as 10 years.”
EOR technologies
At Prudhoe Bay BP is utilizing miscible gas injection and seeing recovery rates of 60% or more. At the Magnus Field in the North Sea BP is recovering 40% of reserves as a result of miscible gas. Bharat Jhaveri, BP senior adviser of gas EOR, said the company’s Ula Field would not be producing if not for EOR.
“To my knowledge this is the only offshore platform in the world that is just producing EOR oil,” Jhaveri said in a company release. “Some people consider EOR to be something that’s nice to have—the icing on the cake—but, in fact, it’s Ula’s lifeblood now.”
BP has been researching EOR methods for more than 40 years. The company’s Designer Water, Designer Gas and Bright Water are among its leading EOR technologies.
“The challenge has been to deliver more cost-effective EOR technologies alongside conventional reservoir drainage approaches like infill drilling or displacement techniques such as waterflooding and gas injection,” the company said in an emailed statement. “The ability to cost-effectively recover more oil from existing fields makes good business sense whether the oil price is high or low. BP’s strategy of developing low-cost step-change widely applicable EOR technologies is therefore well suited to the current market conditions.”
BP’s latest EOR tool is its LoSal low-salinity waterflooding technology. The low-salinity water interacts with the clay in the reservoir to release oil that is stuck to the clay. LoSal was first deployed in the Clair Ridge development, located 75 km (46 miles) west of Shetland, at a cost of $3/bbl. BP is targeting 640 MMbbl of recoverable resources for Clair Ridge.
BP also utilizes its Bright Water EOR technology, which is a microscopic thermally activated particle based on a BP concept. According to BP, Bright Water expands deep in the reservoir, diverting injection water into poorly swept areas and increasing oil recovery. BP said it has deployed Bright Water in more than 140 wells worldwide at an average cost of $6/bbl.
Overcoming EOR economics
Outside of BP’s projects, offshore EOR projects are few and far between despite the potential recoveries.
In the Energies 2016 study, “Screening Criteria and Considerations of Offshore Enhanced Oil Recovery,” the authors reported 19 “successful cases” of offshore EOR projects. But because of the high cost of implementing EOR and the difficulty in outfitting aging offshore platforms with EOR capabilities, future implementation is mostly on hold, industry experts stated.
Elena Escobar is the reservoir stimulation technology manager at Repsol. The company operates several offshore projects, but none currently utilize EOR despite the company possessing the technology and the reservoir understanding to do so.
“Almost all of our reserves offshore are [under] primary and secondary recovery; there is not too much tertiary recovery,” Escobar said. “It’s not just Repsol. All companies are having this problem.”
She explained that in some reservoirs the conditions may be well suited for EOR, and Repsol might have determined designs for tertiary chemical recovery but has not implemented them into the field because it is waiting for oil prices to recover.
“We have found a very good case to apply chemical EOR to an offshore reservoir in Brazil,” Escobar said. “We’ve made all of the estimations, all of the designs, [and] everything is ready. We’re just waiting for a window in economics to apply it.”
Both BP and Repsol have indicated that offshore EOR economics could work if operators include tertiary recovery methods in their IP plans. And BP said EOR methods at mature fields could prove to be more economically feasible than exploring offshore for new finds.
“The BP Technology Outlook suggests that we have probably reached a point globally when the potential additional oil from enhanced recovery exceeds the potential from new exploration frontiers such as the Arctic or ultradeep water,” the company reported.
Research institutions like NETL and companies like Repsol, along with others, have recently identified the GoM as the region with the highest potential payout from EOR methods.
“There is a great opportunity to economically apply CO2 EOR in major offshore reservoirs in the GoM,” Escobar wrote in a 2014 report. “[A Repsol study] recommended designing CO2 EOR in the conceptualization stage of the development plan for new deepwater offshore projects, which could greatly reduce the overall cost and make the application of these processes more attractive in the future.”
NETL identified in its 2014 report three resource targets in the GoM Outer Continental Shelf for CO2 EOR: mature shallow-water oil fields; more recently discovered deepwater oil fields; and undiscovered oil fields, primarily in deep and ultradeep waters.
Although the current commodity prices might not make it economically feasible for the industry to implement EOR technologies on a widespread scale, companies like Repsol continue to research tertiary recovery methods for the day when it does make financial sense to use them. Onshore operators have discovered the right matrix to make onshore production economical at $50 oil, and it is only a matter of time before offshore does as well.
“Little by little, [companies] are opening up opportunities to apply these things,” Escobar said. “But in the case of offshore, it’s always going to be more difficult.”
Contact the author at bwalzel@hartenergy.com.