DuPont Touts MEOR Technology
Trent Jacobs, JPT Technology Writer
DuPont is ramping up the commercial-scale implementation of its microbial enhanced oil recovery (MEOR) method after nearly a decade of development and testing of what it says is a low-risk way to improve production from mature fields. Using its bioanalysis technology, DuPont has isolated microbes able to promote flow conformance through the production of a biofilm that restricts flow by reducing permeability. The company has also identified and isolated microbes that have oil-releasing (or wettability-changing) qualities to reduce residual oil adhering to the rock. Based on successful results both in the lab and in the field, the company says that its MEOR solution can increase production rates by as much as 25% at a cost of USD 10 per incremental barrel. DuPont presented the details of its laboratory tests and discussed the results of field trials at the SPE Improved Oil Recovery Symposium in Tulsa in April.
Despite the extreme pressures, temperatures, and other harsh conditions found inside an oil reservoir, where there is water, there is often life. And while scientists and engineers have long known there to be thousands of species of bacteria found in these reservoirs, they have only recently begun to find how to make use of them, thanks to advancements in biotechnology and DNA analysis. “Most of these oil wells are very much alive with bacteria,” said John Fisher, a global technology manager at DuPont and a coauthor of several papers of the company’s MEOR technology. “The key is to identify the ones that will do the function that you want, isolate those, take them out of the reservoir, grow them up, and put them back in at a higher concentration.”
This process of reintroducing, or inoculating, a laboratory-grown batch of indigenous microbes into the reservoir is what DuPont says separates its MEOR technology from others. By starting off with a microbe that is already adapted for the reservoir’s unique environment, the chance that it will not survive is eliminated. But to get it to thrive, DuPont has developed a “tailored suite” of nutrients to be sent down into the reservoir to preferentially feed and grow the selected microbes. The initial inoculation operation can last 8 to 14 hours, but it requires production to be shut down for 5 to 6 days to allow the microbes and nutrients to flow deep into the reservoir—away from the near-wellbore area. After that, monthly injections of the nutrients, lasting about an hour each, are needed to sustain their greatly increased populations. Because the microbes are dependent on these regular deliveries of nutrients, DuPont’s MEOR process is completely reversible. “If you stop feeding them, they die and revert back to the natural levels they were at before, based on the food that was already there,” Fisher said.
With this MEOR technique, the operator also faces very low up-front cost. Because the process simply involves the deployment of bacteria and nutrients into the well, there is no significant capital investments. “You do not need to put in big expensive facilities like you do for a CO2 flood or polymer flood,” Fisher said. “You basically come in with a tank-truck of microbial solution and nutrients, pump it in the well, go away, and come back a month later to pump it in again.”
The criteria that DuPont has developed for the application of MEOR includes fields with reservoir temperatures below 160°F and moderate salinity levels of up to 100,000 ppm. The reservoir must also be undergoing a waterflood treatment and have permeability above 30 md to carry the microbes and nutrients deep into the reservoir, where they can establish a growth zone.
Wintershall Sees EOR Promise in New Biopolymer
Trent Jacobs, JPT Technology Writer
After a year of field testing, a new type of biopolymer developed by Wintershall, Germany’s largest oil and gas producer, is showing promise as an effective enhanced oil recovery (EOR) tool in one of the country’s longest producing oil fields. The company presented the first-year results of its pilot project using the biopolymer in a pair of technical papers in April at the recent SPE Improved Oil Recovery Symposium in Tulsa. The biopolymer, Schizophyllan, is named after one of the most widespread fungi found in the forests of Germany. What is novel about Wintershall’s biopolymer is that it can survive inside high-salinity reservoirs with temperatures as high as 275°F. The triple-helix configuration of the molecular structure provides durability and high viscosity. According to the company, these tolerances are unmatched by all other commercially available polymers and will enable polymer flooding in reservoirs previously considered too harsh for such a treatment.
The biopolymer gains these superior characteristics in part from the triple-helical configuration of its molecules. This differentiates it from other synthetic polymers that have a single-strain molecule, as well as Xanthan, a widely used polymer that has a double strain. “If you untangle these three strains, a single strain by itself will not have that high mechanical stability anymore,” said Bernd Leonhardt, project manager of Schizophyllan EOR project at Wintershall’s research and development department.
The Bockstedt oil field selected for the test pilot has been producing for 60 years and has a relatively high salt content of 19%, making it ideal for the deployment of a salt-tolerant solution. Within the field, a compartment with one injection well and three producers was selected for the test. To deliver the biopolymer flood, Wintershall takes produced water from the field and pipes it 5 miles away to a treatment facility for particle removal before transporting it back to the test site. “Then it is mixed on the fly with this mother solution of the biopolymer and run through some filters and injected into the injection well,” Leonhardt said.
Since the injection of the biopolymer solution began in December 2012, the cumulative recovery rate from the well located closest to the injection site is 20% to 25% higher than what the company would have expected to see from conventional waterflood. “(In) the other wells, which are much further away from the injection site, we have not seen a change in the (production) trend yet,” Leonhardt said.
To make the biopolymer, Wintershall partnered with chemical company BASF to convert an existing facility outside of Frankfurt, Germany, into a production plant. The finished product contains mostly synthetic brine water and 0.5% to 1% of the active ingredient. When introducing biopolymers into a reservoir, sometimes unwanted bacterial growth occurs that inhibits production. To prevent this, the company injects a regular dose of biocide, which has so far worked. The company plans to expand the facility to produce more of the biopolymer and will continue with its flooding and surveillance operations through 2015 to determine the effect on the well farthest from the injection site.
Two Big Equipment Makers Working On Tougher Fracture Pumping Systems
Stephen Rassenfoss, JPT Emerging Technology Senior Editor
Pumping fracturing jobs is an equipment killer. To begin with, the job requires running enormous quantities of water and sand through a pump, which is an abrasive mix that damages pumps in ways that cannot be fixed. Adding to the pressure is the trend toward clustering wells on pad sites to allow larger, non-stop, multi-well jobs that extend run time.
To search for new ways to ensure more reliable performance, two large British companies have created a venture on the theory that they can integrate pumps, diesel engines and transmissions to create systems that outperform what is on the market today.
Pump maker Weir Oil and Gas, and diesel engine maker MTU, a Rolls Royce power systems brand, announced the venture to create systems for the hydraulic fracturing market at the Offshore Technology Conference in Houston in May. “The mechanisms will be integrated to work as one system with smart controls to optimize performance,” said David Paradis, vice president of sales and marketing for pressure pumping at Weir. He said field testing was expected to begin later this year on equipment resulting from the collaboration.
Engineers from the two companies have been working together for a while and hope to deliver their first system in mid-2015, according to new releases. One area of interest is limiting issues caused by differences in how diesel engines and pumps vibrate, with a goal of mechanically managing these differences in natural frequencies.
Another interest is condition monitoring, which can be used to schedule maintenance before a part fails, or to predict the life of a system, reducing the risk of a pumping unit dying in the middle of a job. To guard against time lost due to breakdowns, operators often pay to have an extra unit around as insurance, Paradis said.