Journal of Petroleum Technology October 2012 : Page 36

Increased Oil Production With Something Old, Something New Stephen Rassenfoss, JPT Emerging Technology Editor Pumping is stopped to allow a pressure test to see if the formation will allow free movement of chemicals used to free the remaining oil in this old 36 3 6 Oklahoma field. J P T T• • O OC C T TO TOB OB O B E ER R 2 20 201 01 0 1 2 JPT OCTOBER 2012

Increased Oil Production With Something Old, Something New

Stephen Rassenfoss, JPT Emerging Technology Editor

Pumping is stopped to allow a pressure test to see if the formation will allow free movement of chemicals used to free the remaining oil in this old Oklahoma field. Enhanced oil recovery (EOR) has become fertile ground for emerging—and re-emerging—technologies. Emerging from laboratories are materials based on nanotechnology that could change what is possible with aging reservoirs. Researchers are working on making carbon dioxide foams built to last, time-release coatings to deliver gels deep into reservoirs, and tracers for real-time waterflood tracking. Re-emerging are chemical EOR methods that have been around for 30 years but whose development was stunted by a long stretch of low oil prices. Higher prices are now inspiring a second look at EOR methods, taking advantage of advances in chemistry and computing to create cost-effective ways to rework underperforming old fields. “It didn’t happen when the technology stopped developing in the 1980s,” said Jeff Harwell, a professor at the University of Oklahoma, who has been a catalyst for this reemerging technology. “My perception is we are just to the point in the industry where oil prices have risen to the level where it is economic.” Continued oil prices near USD 100/bbl makes EOR an attractive possibility—the estimated cost to produce plus the profit margin needed to justify the risk is about USD 60/ bbl, Harwell said—but, for the many independents that own older fields, the cost of reducing salinity levels in their fields in order to use the available chemicals has been prohibitively high. Harwell said he and others he knew in EOR realized that, while the economics once again favored it, work was needed to make EOR a realistic option for small and mid-sized operators whose budgets and appetite for risk are both limited. They worked with chemical companies to develop improved surfactants that worked without having to make costly modifications to fields, improved techniques for analyzing and planning EOR projects to increase the chance of success, and started a company to demonstrate what they could do. He is not alone. Harwell pointed out that others, such as Gary Pope, a professor at The University of Texas at Austin, whom he describes as the EOR guru, is working with a chemical company to create improved surfactants. Big EOR service providers, such as Tiorco and Surtek, are also working on new things. It is a tough sell, but one with big potential. In Oklahoma, only 14 billion bbl of the 82 billion bbl in the ground have been produced, he said. Many fields date back to the early days of oil exploration when the focus was on pumping oil as fast as possible. “It was really before petroleum engineering was a discipline,” Harwell said. Production was limited by early overproduction and poorly done waterflooding experiments, adding to the petroleum engineering expertise required to rework these fields. “A lot of mature waterfloods are badly in need of optimization. I really think we can recover as much oil as has been produced,” Harwell said. In Oklahoma, he puts that at more than 10 billion bbl, which compares to the 7 billion bbl in estimated oil reserves in the Eagle Ford and Bakken shale oil plays, according to a 2011 study by Intek, commissioned by the US Department of Energy (DOE). But the numbers that matter most will be the production levels as more EOR projects are completed. “We need to prove it in the field,” he said. “Once chemical flooding starts to develop a successful track record, the sky’s the limit. Until then, it will be the risk takers who blaze the trail.” Next-Generation Carbon Dioxide A study commissioned by the US DOE’s National Energy Technology Laboratory (NETL) predicted that improved EOR using next-generation CO2 technology could increase the amount of recoverable US oil reserves by 68 billion bbl, or about 4 million B/D of oil output. Based on grants by NETL, next generation means using more carbon dioxide. That will require producing more of it because the number of ongoing projects is limited by the supply of the gas. The supply keeps the price of CO2 relatively high, which limits the amount injected and the parts of the US where it is used. Another line of research is finding ways to make carbon dioxide thicker so that it can improve the ability of the waterflood to evenly sweep a reservoir and produce more oil. A third area of research, carbon dioxide sequestration, shows how the US government and the industry perceive the benefits differently. Federal officials want to take carbon dioxide, which is said to affect global warming, out of smokestack emissions and bury it forever in the ground. The industry needs more CO2, which industrial facilities produce a lot of, to increase the amount of oil it can get out of the ground. One of the hard parts of the next generation plans is finding ways to capture what comes out of a smokestack cheaply enough to cover the cost of building a pipeline network to deliver it. Another is changing the nature of CO2 to realize its potential to mobilize oil and get it out of the reservoir. “CO2 or any gas is a lot more mobile. It snakes through the reservoir,” increasing the chance of premature breakthrough, said Mehran Sohrabi, a professor at Heriot-Watt University. In a core flood test simulating reservoir conditions at the university in Edinburgh, Scotland, the CO2 foam cleared out twice as much heavy crude oil in porous rock as did a mixture of water and straight CO2. Creating a CO2 foam able to do that in the ground has been an industry goal for a decade. Doing so would require changing the nature of something that is inherently unstable. “Like a beer foam, it will collapse,” said Chun Huh, a research professor at The University of Texas at Austin. While carbon dioxide foams can easily be made from surfactants, which are the chemicals used to make soap bubbles, tests of that approach in the 1980s ended with more misses than hits. That technology was largely dormant until recently, when a new surfactant developed by Dow Chemical and the University of Texas was tested in the Sacroc field in west Texas. Looking ahead, researchers at The University of Texas and New Mexico Tech are trying to create low-cost, durable CO2 foams using commercially available silica (SiO2) nanoparticles. They are specially treated to ensure they adhere to the surface of each CO2 bubble, acting like chainmail, preventing bubbles from collapsing, which is called coalescence. They have created foams able to survive long periods at the pressures found in reservoirs. Huh said they are “making slow but steady progress” on creating fortified foams able to survive in harsh reservoir conditions. A graduate student on his team, Andrew Worthen, has generated a durable foam at 50°C with a high salinity brine (8% sodium chloride and 2% calcium chloride), Huh said. The goal is to create foams able to stand up to hightemperature, high-salinity reservoirs, where alternative chemicals used for EOR cannot be used, and then leave the carbon dioxide behind. This technology is young—the first paper on nanoreinforced CO2 foams for oil recovery was published in 2010 by a University of Texas team—and nowhere near ready for a field test, which will be closely watched. “When I do a presentation at a conference, people from the industry want to know if you have done some field testing,” said Ning Liu, a research scientist at New Mexico Tech, which, along with The University of Texas, is developing and testing nanotech foams with NETL support. The answer is, “not yet.” Sinisha “Jay” Jikich, a project manager at NETL who manages next-generation CO2 research work—which he defines as early-stage work that would not be able to draw investor support—said he is pushing the universities to conduct foam field tests when their contracts conclude in 2014. He said an international oil company has expressed an interest in participating. Past efforts at making foams found that contact with crude is destructive. Liu of New Mexico State said nano-reinforced CO2 foams should stand up better to oil than CO2 foams made using surfactants, but neither lab has tested that yet. A review of the previous generation of CO2 foam testing, which ended in 1990, offered multiple reasons why CO2 foams did not work that were not related to the staying power of the foam. The challenge this time around will be to deliver better results than those achieved with current methods, such as alternating injections of water and CO2 [water alternating gas (WAG)]. “CO2 foams would have to compete with WAG for mobility control,” said Robert Enick, a professor at the University of Pittsburgh who was the lead author on the NETL survey of past work. “Until there are a few field tests showing that this can be reliably done, I don’t think CO2 foams will be widely implemented.” Seeking a Delayed Reaction The increased financial rewards for improved oil recoveries has also increased the interest in ways to get more out of the current technology by delivering chemicals farther into reservoirs. University of Kansas Professor Jenn-Tai Liang explains the purpose of this work by saying, “You can only recover oil that you can get into contact with.” The problem has to do with the ways gels are created in the ground. The ingredients are injected into a reservoir, where they combine to form a gel. This normally occurs within a few hours of injection, placing the gel in the reservoir relatively close to the well where it is not likely to move much. Liang has created a chemical carrier that can delay gel formation by days or weeks. “It is like a targeted cancer treatment. To protect the healthy organs in a human body, you need to be able to delay its release until you have reached the target cancerous cells,” Liang said. The formulation—chemically, it is a polyelectrolyte complex (PEC)—can be varied to time the reaction. More than 5 years of work, supported by ConocoPhillips, has gone into adapting the PEC chemistry to oilfield conditions. Liang said it is ready for field trials and several companies have expressed an interest in doing so. Enhanced Digital Exploration Advanced chemistry is not going to change the fact that “It is hard to fix things in a reservoir,” Harwell said. Enhanced oil recovery will continue to depend on an understanding of the reservoir, which may indicate that increased recoveries will require directional drilling. A large leap in available computing power is a positive in that regard. In the early days of chemical EOR, personal computer owners were happy if the machine could run a word processing program. “The software is just night and day compared to what it was, as is the computing power,” Harwell said. “We can sit around the table with a laptop and explore different scenarios.” Labs testing next-generation materials are also engaged in improving the simulations of how these molecules will behave in the ground. “We noticed a lot of conventionally available simulators are unable to reproduce what we have seen in the lab,” said Sohrabi, director of the Centre for Enhanced Oil Recovery and CO2 Solutions at Heriot-Watt. The university is now working on a simulation based on the work with CO2 foam and heavy oil. On the molecular scale, Baker Hughes nanotechnology experts are working on applying computational physics programs originally developed for materials research in US government laboratories to predict what sort of molecular structures would be able to do things, such as reduce the interfacial tension binding an oil molecule to a rock. “I believe this problem of recovering more oil comes down to the surface chemistry at a very microscopic level,” said Guarav Agrawal, director of Enterprise R&D for Baker Hughes. The company has used the approach to improve the way it makes artificial diamonds for drill bits. “By doing some computer games, we can eliminate some options,” Agrawal said. EOR Made Simpler Sasol Olefins and Surfactants has returned to selling chemicals for enhanced oil recovery (EOR) after a hiatus dating back to the early 1980s. Since then it has focused on making surfactants for detergents, shampoos, plastics, and paints, as well as supplying chemicals others used to make EOR chemicals. There was far more demand for surfactants capable of cleaning grease off fry pans than ones to free oil from reservoir rock. Things began to change for the former Conoco unit 5 years ago with a US-funded research project to develop surfactants to clean up the ground around leaking tanks at gasoline stations. That was followed by a project to create cost-effective surfactants for oil fields with high salinity levels. Behind both projects was Jeff Harwell, a professor from the University of Oklahoma. Back then, he was thinking oil prices were finally high enough to justify EOR. The idea started turning into action when Bruce Roberts, who had recently retired as a senior scientist at Kerr McGee, said to him, “Have you seen what’s happening with oil prices? We need to get back into chemical EOR. It is going to work this time.” They decided to pursue that thought, with Roberts preparing the economic analysis needed to win a grant from the US DOE’s National Energy Technology Laboratory (NETL) to develop improved surfactants and EOR methods for small operators. That led to work with Sasol and three other chemical makers—Huntsman, Dow, and Pilot Chemical. Starting With Surfactants Developing surfactants capable of mobilizing oil that years of waterflooding had not was an essential first step. Affordable new versions of the chemicals used to reduce the surface tension bonding oil to rock and mobilize the crude so it can be pushed out by the waterflood were needed. And they had to work in reservoirs with high salinity levels. That last detail was the hard part. Surfactant makers were asked to create a molecule able to work in reservoirs with salinity levels in excess of 20% of the brine weight. At the time, Harwell said the commonly assumed limit was 5%, so saltier reservoirs required fresh waterflooding for those surfactants to work. “You start looking at multiple pipelines and watertreatment facilities, and you never make it past the capital investment,” he said. It was up to the chemical companies to create molecules able to tolerate that level of salinity in formations with temperatures of around 50°C. A lot of surfactants were eliminated immediately because they cannot tolerate high levels of salt. The list was narrowed further because many surfactants require agitation. Water injected into oil fields to maintain production moves a foot or less per day. That is not enough agitation to activate the sort of surfactants used in laundry detergent to lift dirt off cloth and then emulsify it in the wash water, said Victoria Stolarski, market development manager for the Americas at Sasol Olefins & Surfactants. In addition to being effective in sluggish, highly saline waterfloods, the surfactants developed by Sasol and others had to be cost competitive. Sasol created an alcohol propoxy sulfate surfactant brand named Alfoterra, that can be used in concentrations of 0.1 to 0.5% of the volume of injected water, or about 10% of what was required for older options, according to Sasol. Covering the Risk The next step is to demonstrate that the chemicals and methods developed by Harwell and his team work. That led to the start of an EOR consulting company—Chemical Flooding Technologies (CFT)—along with Mid-Con Energy Partners, which is majority owner. “We will do a 5-acre pilot starting in the design phase and do the whole thing for less than USD 1 million,” he said. An important part of that is developing a reliable, affordable system to test if chemical EOR is a good option. Multiple surfactant suppliers were needed because CFT’s approach uses a blend of them. Work by another original team member, Ben Shiau, an assistant professor of petroleum engineering at the University of Oklahoma, found that multiple surfactants are best able to deal with variations in the reservoir rock. CFT, which has a handful of jobs lined up, has tested three pilot wells in a field in Oklahoma where it is now conducting a field test. Harwell likens these first few jobs to the early wells drilled leading up to the shale boom. The future will depend on whether they can generate enough positive case studies to convince the many small operators that own wells in states like Oklahoma, where 90% of the wells produce less than 10 B/D. The estimated incremental cost of adding a barrel of production using chemical EOR is USD 10–15 per bbl, Harrell said. Adding the costs of producing a barrel of oil in an older field brings the total estimated cost per barrel to around USD 40. On top of all that, the profit margin needs to be high enough to justify the risk, pushing the estimated minimum oil price to justify chemical EOR up to around USD 60 per bbl, he said. The next goal for CFT is to demonstrate that its system for testing reservoirs and planning EOR jobs can reduce the risk and popularize what is now just a pilot project. One limit is the expertise required to analyze reservoirs and design jobs tailored to the conditions, which can determine the success of a project. During the EOR downtime, advances in the hardware and software available for petroleum geology have made the computing power needed for EOR project planning both cheap and portable. Harwell is working on an easier way to create reservoir simulations based on pilot test data with funding from the Research Partnership to Secure Energy for America. But, he and Roberts are part of a small group of experienced experts in the field that was largely dormant after the oil price collapse in the early 1980s. “I am 60 years old, and I earned one of the last PhDs in this area,” Harwell said. “There is a big gap in graduate students in this area.” Building Better Bubbles to Recover More Oil A video showing carbon dioxide foam at work shows why researchers keep trying to find ways to make foam for enhanced oil recovery (EOR) despite decades of dead ends. The experiment at Heriot-Watt University begins with foam pumped into one end of a test chamber with a rock whose pores hold heavy crude left after water injections. The foam soon plugs the widest channels and gradually spreads through the maze of side paths. The heavy crude turns from black to brown—an indication of a sharp viscosity drop—and the oil is pushed out by the CO2 foam. In the 1-day period covered by the video, about 90% of the heavy crude is moved out of the maze. The test in the micro model by Mehran Sohrabi, a professor at Heriot-Watt University, was confirmed by a core test and showed that CO2 foam might work better with heavy crude than light crude. Reproducing the result from a narrow chamber 4 cm long in an oil field, though, has kept these foams from EOR use. A lot of work has been done on creating thicker forms of CO2 for injection. Coreflood tests at Heriot-Watt found that a CO2 foam removed 70-75% of the heavy oil in the rock, about two times more than the widely used combination of water and CO2 gas. “With no additive, it will zip through reservoirs, which is why it has to be injected again and again,” said Chun Huh, a research professor in the Department of Petroleum and Geosystems Engineering at The University of Texas at Austin. The study offered three reasons why CO2 foam performs better than water or CO2 gas injections. • It ensures more even flooding. CO2 gas injections can be diverted by a high permeability zone, particularly one at the high end of the formation. • It reduces the viscosity of the oil up to 97%. Its slow movement puts it in contact with the oil longer than CO2 gas, which has to be injected multiple times to have the same effect. • Its higher viscosity allows a more uniform push. That study was based on foams using surfactants, which are used in soaps to make them bubble; but, field trials of those foams have yielded more misses than hits. The search for more viscous carbon dioxide goes back to the 1970s with support from the US Department of Energy (DOE). The pursuit for a more viscous form of CO2 included an as-yet-fruitless search for a cost-effective way add CO2 to a direct thickener—the lead author of the review, Robert Enick, professor at the University of Pittsburgh, is still looking—and 13 tests of foams made using surfactants, only five of which offered positive results. The bottom line was that the oil industry largely lost interest in CO2 foams. There has been a rekindling of interest in developing and testing foams made using surfactants. Dow Chemical and The University of Texas developed a new surfactant for creating foam, brand named Elevate, which was successfully tested by Kinder Morgan in the Sacroc field in West Texas. A paper on the results of the test, to be presented at the SPE 2012 Annual Technical Conference and Exhibition, showed two things that regularly show up in discussions of CO2 foam projects: • It can be quite effective. Two wells were expected to produce significantly more oil than they would with tradition CO2 injection methods. • It depends on the location—two other wells were taken out of the test because the oil gains were exceeded by the rise in CO2 gas produced. Also university laboratories are working on a new generation of foams using nanotechnology to create lasting foams, with support from the DOE’s National Energy Technology Laboratory (NETL). The foam research work at The University of Texas at Austin, led by professors Steve Bryant, Keith Johnston, and Huh, has been taking commercially available silica (SiO2) nanoparticles and treating them so that they work together to protect CO2 bubbles by adhering to their surface. The result is a protective network that works like chainmail armor, preventing their collapse. In the laboratory, foams are created by forcing a mixture of gas, brine, and nanoparticles through a tube filled with tiny glass beads. The process forces the nanoparticles to adhere to the CO2/water interface using shearing, the process used to create whipped cream by shooting a high-pressure stream past a thin edge on the nozzle of an aerosol dispenser. Huh says nanoparticle-stabilized forms are more durable than past foams, most made using surfactants, which are also used to create foams for washing clothes. “With the use of silica nanoparticles, the advantage will be mainly the robust stability that the particles bring to foam, due to their large adhesion energy (of the particles) at the CO2/water interface, compared to that of surfactant,” Huh said. The surfactant can easily be released (desorb) from that interface, destabilizing the foam, which is not the case with nanoparticles. This stability has allowed the researchers to create foams able to stand up to increasingly high temperatures and salinity levels, Huh said. In theory, this should also allow the new CO2 foams to stand up to oil, said Ning Liu, a research scientist at New Mexico Tech; but, that has not been tested yet. While the nanoparticles should allow foams to regenerate, there is no way to observe what it occurring inside the pore systems of rocks, he said. The negative effects of oil could be mitigated by using foam in areas with heavy oil—Sohrabi found foams stand up better to higher saturations of heavier crudes—and in largely depleted reservoirs where the foam is used to go after residual oil that other methods cannot reach. Going to the Ground Creating longer-lasting foam using nanotechnology appears to be an attainable and useful step, but that will not solve all the issues identified in past CO2 foam experiments. “Making a foam is quite doable,” said Enick, who conducted the survey of past work on creating more viscous forms of CO2. “Getting it to form exactly where you want it to form and to have a mobility reduction of exactly how much you want is a challenge.” Past testing suggested a list of problems, including highly fractured reservoirs and a failure to get the foam into the reservoir. “I do not think that low-durability foams were the big problem but a combination of many factors that differed from test to test,” Enick said. New Mexico Tech has been testing how well nanoreinforced CO2 foams move in reservoir rock. They passed freely through cores made of limestone and sandstone but less-porous dolomite presented some problems, Liu said. As a CO2 foam moves away from a wellbore, its velocity decreases and its viscosity rises, Sohrabi said. That means it is first likely to move into thief zones—high-porosity areas allowing flooding to bypass remaining oil-rich areas—and, when those are clogged, travel into tighter passages. Foam strength is a balancing act. The goal is bubbles durable enough to last but viscous enough to move deep into the field. CO2 foam is reversible with water injections. Sohrabi said he sees CO2 as a lower-cost substitute for other solvents being tested for heavy-oil recovery. “CO2 is much better than with propane, where you do not get the same viscosity drop that you get with CO2 but you pay much more,” Sohrabi said. “It is not as expensive and, in reservoirs around the world, including the North Slope of Alaska, you have CO2 in associated gas.” Journeys Through Inner Space The vision of using nanotechnology to investigate oil fields is moving closer to reality. An early indication of that is a glass vial holding specially treated iron-based particles developed in the laboratory of Andrew R. Barron, a professor at Rice University. It looks like nothing more than a bottle of water. To demonstrate otherwise, a strong magnet is put underneath and, gradually, a faint, dark-gray accumulation appears on the bottom. These are ultrasmall bits of magnetite, a naturally occurring form of iron oxide. These tiny bits of magnetite are capable of changing their magnetic properties at different temperatures. The unique magnetic signatures offer the potential to create tracers able to travel through reservoir rock and be collected and identified later. The particles in the bottle are called FracEnsure, because the plan is to market it as a way to track the path of fracturing fluids. “We are scaling up to do a full field trial,” Barron said. “The first stage would be to inject FracEnsure into a well and collect the flowback and see if it can be detected.” The technology is still in its early days as researchers compete to find ways to harness the properties of ultrasmall particles to create particles that can travel into an oil reservoir to observe what can now only be inferred. A top priority from the founding of the AEC has been to find ways to use nanotechnology to gather reservoir insights to improve oil and gas recovery rates. Its long-term vision includes sensors, whose size can be measured in billionths of meters. That are able to enter a reservoir, make a measurement, and then flow to where it can be pumped out of the reservoir and the data extracted. Since it was founded in 2008 the AEC has supported 40 research projects at more than 25 universities, with total spending expected to reach more than USD 30 million by year’s end, said Sean Murphy, program manager at the AEC. A variety of approaches are being tried for tracers alone. The foundation for all of it is learning how to create nanoparticles able to to move through harsh reservoirs, which is the goal for one quarter of the AEC’s projects to date, he said. For a consortium where much of its work is focused on the long term, the natural qualities of magnetite offer a nearterm goal, The AEC is using magnetite to help illuminate the reservoir. The goal is to use the particles as a contrast agent to improve the quality of images created by sending electromagnetic signals through a reservoir from one well to another. “The focus is on acquiring better resolution data from the inner well space,” said Mohsen Ahmadian a project manager for AEC. It plans to use specially treated nanoscale magnetic particles to map the flow paths of injected fluids in real time. Murphy said that material scientists and chemical engineers have been developing nanoparticles that could be used for proof-of-concept tests. In the fall, the AEC is planning an intermediate scale test and has a goal of field testing in a reservoir within the next 2 years. Meanwhile, Chun Huh, a research professor at The University of Texas at Austin, who is using nanotechnology to create long-lasting carbon dioxide foams to increase oil recoveries, said he is looking for a way to use magnetite to create a CO2 foam that can be tracked underground. Going With the Flow Barron, whose nanotech inventions have been used to start Oxane Materials, a company making proppant, and Lance Energy Services, a second company now testing a water-treatment system, is taking a different path. The plan is to use FracEnsure as a way to follow the flow of fluids after they have been injected into a well during fracturing. This unique marker is supposed to show whether fluids are contaminating water supplies. This requires taking a sample and analyzing it with ultrasensitive equipment developed by David Potter, a physics professor at the University of Alberta, who is a collaborator on the project. Other possible uses would be tracking the flow of water from injection wells to production wells or instances where fractures from one shale well connect with another well nearby. Both possibilities take advantage of the unusual magnetic properties of magnetite—described as a super paramagnetic mineral—which vary at different temperatures. The number of variations should make it possible to create a variety of markers. One plus, according to Barron, is that the particle can be detected in concentrations as low as a few parts per trillion. Chemicals used for tracking water flows in fields need to be used in large quantities to ensure a measurable amount is collected after the dilution that occurs as it goes from an injection well to a production well. As a result, Barron said a relatively small proportion of the tracer is needed—on the scale of the fracturing additives that make up less than 1% of the fracturing fluids. Free-flowing nanoparticles also have the potential to offer an advantage over alternatives, such as chemical tracers, where large quantities are required because a large part of the chemical is lost in the reservoir. Delivering on that potential depends on how well the nanoparticles are functionalized. Functionalization is the treatment used to ensure that the nanoparticles remain suspended in solution and will not stick to reservoir rock along the way. Testing the Limits The FracEnsure marketing plan is an indication of what Barron thinks the material is capable of doing and what it is not. He questions whether creating magnetite to create moredetailed reservoir images, as AEC is trying to do, is a practical option. “In theory, it is doable if you have enough magnetic material and use high-end magnetic detectors,” said Barron, who based his comment on a previous AEC presentation. “You need a ton of nano metallic material, and then all you can say is it is somewhere in Texas.” Sean Murphy, program manager at AEC, said Barron’s comment reflects dated information. “This doesn’t reflect recent modeling simulations, lab scale experimental validation, or scaled up testing with partners Lawrence Berkeley National Labs and service providers Schlumberger and Halliburton,” Murphy said. That work has not been reported publicly. “A key part of the research is coming up with something that is economical for the oil industry,” said Jay Kipper, associate director of administration at the Bureau of Economic Geology, who helped found the AEC. “History has demonstrated that as nanomaterial synthesis is scaled to production levels, the prices drop and it becomes economically feasible.” Treating a Body of Rock Old oil fields and cancer patients have something in common. Both require treatments using carefully timed releases of chemicals. Jenn-Tai Liang, a professor of chemical and petroleum engineering at the University of Kansas, saw the parallel in the work by a fellow professor, Cory Berkland, who was using nanotechnology to control the delivery of drugs. In cancer treatment, the goal is to deliver drugs to the site of targeted cancer cells without those often toxic substances harming the body’s organs along the way. In enhanced oil recovery, the goal is to ensure that gels used to improve the effectiveness of a waterflood are delivered to a target location deep in the reservoir. The technique using polyelectrolyte complex (PEC) nanoparticles delays the combination of the two components forming the gel—the polymer and the cross-linking agent—from hours to days or even weeks. Five years of development work was required to convert the pharmaceutical technology into a delivery device for oilfield chemicals. It was developed with support from ConocoPhillips, which shares the intellectual property rights. It has not been field tested; but, Liang said, “Several potential applications are under development.” From Biology to Geology While the chemistry sprung from methods used for delayedrelease pharmaceuticals, the final product had to be quite different. Cancer patients are willing to pay large amounts for small dosages of chemicals that go into a biological system where the temperature is predictably mild—around 37°C—salinity is low, and the pH is neutral. Oil companies are cost-conscious buyers of huge volumes of chemicals to treat enormous formations where the temperatures, salinity, and chemistry can be harsh and variable, Liang avoids specifics about PEC making. The ingredients are a combination of polyanion and polycations, which he described as “low-molecular weight polymers, each of which carries a different charge.” In an oil reservoir, the PEC mixture is used to entrap and control the release of one of the components that combine to form a gel. It has been shown to work at temperatures up to 160°C in oilfield brines; but, Liang said the practical limit is set by the chemicals it delivers, which is often lower. In the longer term, Liang said he plans to adapt the method to allow delayed delivery of a wide range of reservoir chemicals, from gel breakers to hydrate inhibitors. Liang did not quote a price but said the small quantity of PEC needed would not add significantly to the cost of enhanced oil recovery. The need exists for a way to deliver chemicals farther away from the wellbore, said Jeff Harwell, a professor from the University of Oklahoma. “There is an opportunity there,” he said. “There is an economically targetable resource out there.” For further reading: SPE 154260 Improved Oil Recovery by Chemical Flood from a High Salinity Reservoir by B.J. Ben Shiau, University of Oklahoma, et al SPE 152996 Visualization of Oil Recovery by CO2-Foam Injection; Effect of Oil Viscosity and Gas Type by Alireza Emadi, Mehran Sohrabi, Heriot-Watt University, et al SPE 154122 Mobility and Conformance Control for CO2 EOR via Thickeners, Foams, and Gels—A Literature Review of 40 Years of Research and Pilot Tests by Robert M. Enick, University of Pittsburgh et al SPE 154285 Nanoparticle Stabilized Carbon Dioxide in Water Foams for Enhanced Oil Recovery by Andrew J. Worthen, The University of Texas at Austin, et al SPE 129925 Nanoparticle-Stabilized Supercritical CO2 Foams for Potential Mobility Control Applications by David Espinosa, The University of Texas at Austin, et al SPE 153337 Study of Adsorption and Transportation Behavior of Nanoparticles in Three Different Porous Media by Jianjia Yu, New Mexico Institute of Mining and Technology, et al SPE 157123 Magnetic Characterization of Nanoparticles Designed for Use As Contrast Agents for Downhole Measurements by Carolina Avendano, Rice University, et al

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