[Editor's note: A version of this story appears in the December 2019 edition of Oil and Gas Investor. Subscribe to the magazine here.]
Maybe give that bacteria that’s downhole some vitamins. Or pump that field gas back into the well. Soak the hole with CO₂? Soak it in water? Give it some water with a field-gas chaser?
The right recipe for unconventional-rock EOR remains elusive. But operators—from the Bakken to the Eagle Ford to the Permian Basin—are looking at all the formulae yet imaginable. They’ve started with what conventional-rock formations seem to like.
Most of it works at least a bit; some of it doesn’t work for very long. And, then, there’s the cost of this method vs. that method—and in contrast to what additional oil it nets. In addition, the math has to factor for production lost while the well is offline during treatment.
Ultimately, though, the perfect cocktail will boost wells’ EUR by a worthwhile fraction—without an operator paying for another hole at a cost of another 640 acres, 20,000 feet of pipe, dozens of frack stages, thousands of barrels (bbl) of water and hundreds of tons of sand.
Field-gas injection, Bakken
In the Bakken, Liberty Resources LLC did a rich-gas huff-n-puff (HnP) pilot, Stomping Horse, in 2018 through this past May. It anticipates a second trial next year that will be larger.
The test involved injection in five wells of 11 in a two-section Liberty unit in McGregor Field in eastern Williams County, along the Nesson Anticline. Offset wells were monitored for whether the injected gas was leaving the targeted unit.
The gas was wellhead—primarily 60% methane, 20% ethane and 10% propane—with British thermal unit content of about 1,500.
A great deal was learned, according to Liberty’s follow-up report to the North Dakota Industrial Commission in September. Among the findings: This is going to need a lot more gas.
In the target area, Liberty operates adjacent sections except one north. That one is operated by Murex Petroleum Corp., which provided operational intel about the four wells in its unit as Liberty conducted the tests. The four Murex horizontals came online in 2010 through 2012 and have produced a combined 958,000 bbl of oil and 1.2 billion cubic feet (Bcf) of gas.
Overall, pilot results indicated a “demonstrated ability to inject gas within [an HnP] scheme, build pressure, contain gas within the Bakken/Three Forks intervals of the [unit] and recover injected gas,” said Gordon Pospisil, Liberty vice president, business development, and lead on the EOR projects.
The injected gas stayed within the Liberty unit. August 2019 production from the Murex wells averaged 43 barrels per day (bbl/d) and 121,000 cubic feet per day (cf/d), according to state files. June 2018 production, prior to the Liberty pilot, averaged 40 bbl/d and 111,000 cf/d.
Liberty injected a total of 158 MMcf in its wells; into this past August it had recovered 143 MMcf.
The scope was limited by the amount of gas produced from the unit and available for injection, Pospisil said, “which restricted the impact—the pressure build—within the depleted intervals and, thus, the magnitude of the oil response.”
Reservoir pressure in the unit had been more than 6,000 psi when the wells were completed; at the time of injection, pressure was less than 1,000 psi except for one well at about 1,100. Bubble point is approximately 2,500 psi.
The second pilot will involve injecting a larger amount of gas “and target wells with less depletion and higher initial bottomhole pressures,” Pospisil said.
The results from each of the five injection wells:
Leon 2MBH had been brought online in March of 2016 with a 24-hour IP of 428 bbl. Cumulative production through this past August was 75,842 bbl and 300 MMcf. Injected was 13.8 MMcf during 18 days in August of 2018. Pressure pre-injection was about 1,100 psi. Oil the month prior averaged 48.5 bbl/d; the month after injection, 55.6 bbl/d.
Leon 3TFH had been brought online in March of 2016 with an IP of 272 bbl/d. Cumulative through this past August was 92,564 bbl and 330 MMcf. Injected was a total of 10.8 MMcf in two sets: 12 days in July of 2018 and six days in September of 2018.
Pressure at the time was about 900 psi. Oil the month prior to the first injection was 33.4 bbl/d; during the month between injections, 43.3 bbl/d; the month after the second injection, 35 bbl/d.
Gohrick 5MBH had IPed 1,032 bbl/d in December of 2014. Cumulative through this past August was 240,507 bbl and 608 MMcf. Injected was a total of 42 MMcf in two sets in the fourth quarter of 2018: one for 11 days; the other, 33 days.
Pressure at the time of injection was less than 600 psi. Oil the full month prior to treatment was 21.4 bbl/d; the first full month after the set of injections, 45.1 bbl/d.
Gohrick 4MBH IPed 1,191 bbl/d in November of 2014. Cumulative through this past August was 229,557 bbl and 563 MMcf. Injected was a total of 75 MMcf over 29 days during this past January into May. Psi at the time was less than 1,000.
Production the full month prior to the first injection was 17.5 bbl/d; the first full month after the last injection, 17.9 bbl/d.
Gohrick 6TFH IPed 1,067 bbl/d in January of 2015. Cumulative through this past August was 141,367 bbl and 455 MMcf. Injected was 17.4 MMcf during 15 days in May. Psi at the time was 713. Production in the month prior to injection was 17.8 bbl/d; in the month after injection, 33.5 bbl/d.
All five of the wells were returned to production in August. Liberty cited several issues in the follow-up report:
- The pilot-project gas supply was limited to what the unit had been producing;
- The wells used were fairly depleted; static bottomhole pressure was well below MMP (minimum miscibility pressure) of about 2,450; and
- The oil the wells didn’t make—while shut-in during injection—was cumulatively more than what additional oil Liberty got post-injection.
However, Liberty added, the project demonstrated:
- Injection is possible and can be done as part of routine operations;
- The injected gas can be contained within the Bakken and Three Forks and within the unit itself. Also, it can be recovered—for sale or for re-use in EOR;
- Pressure was building, thus MMP is likely achievable with more intense injection;
- A substantial amount of gas is needed to restore pressure to at least 2,450 psi in Bakken and Three Forks wells. But it would be better to start with wells with at least 2,450 psi in the first place; and
- It’s probably best to inject more gas than just what the lease is producing.
Liberty’s next pilot will use a less-depleted unit, thus having a higher psi at the time of commencing injection. It expects this will reduce how much gas is needed and how long the wells will be shut in.
Bakken west to east
James Sorenson, an assistant director with North Dakota’s Energy & Environmental Research Center (EERC), and James Hamling, EERC principal engineer and oilfield operations group lead, reviewed Bakken EOR projects in 2016, reporting the findings in American Oil & Gas Reporter.
The projects ranged from CO₂ to field-gas injection to waterflood and looked at the Bakken from the play’s far western boundary to the far east.
Far western Bakken, CO₂, 2009. Over in Elm Coulee Field, where the fracked, horizontal Bakken play began in 2000, three operators signed on to see what would happen if doing a CO₂ HnP in the play-maker well, Burning Tree State 36-2H, in Richland County, Mont.
The well had been brought online in May of 2000 by operator Lyco Energy Corp. with Halliburton Co. as a partner. In 2009, Continental Resources Inc., Enerplus Corp. and XTO Energy Inc. began injecting gas into it, Sorensen reported.
Prior, the well was producing some 35 bbl/d. Some 45 MMcf of CO₂ was injected in 45 days; the wells were capped for 64 days to let the CO₂ soak in. Production peaked at 160 bbl/d eight days after brought back online and returned to 30 bbl/d before the month’s end.
In a few months, it wasn’t flowing at all. Put on pumpjack, the pre-injection rate of production resumed, according to Sorensen. It was a year since the well had been taken offline to start CO₂ injection.
Sorensen added that offset wells weren’t monitored for CO₂ migration off-lease; it’s also unknown whether there was CO₂ migration intra-lease.
Elm Coulee made 168 MMbbl of oil through 2016, the last year for which Montana published an annual oil and gas review. In that year, it remained the No. 1 oil-producing field in the state with 8.4 MMbbl.
Far eastern Bakken, CO₂, 2008. Meanwhile, EOG Resources Inc. did a CO₂ test on Austin 1-02H in Parshall Field, Mountrail County, N.D., beginning in late 2008, Sorensen wrote. The well had been brought online in December of 2007 and had been a part of the “east of the Nesson (Anticline)” play-opener, taking fracked horizontal success to the eastern boundary of the Williston Basin.
The different aspect of what EOG was doing east of the Nesson was its use of staged fracturing; the play-opener Burning Tree State in Montana had been openhole.
Austin 1-02H had IPed 781 bbl on Dec. 13, 2007, according to state files. Cumulative was 602,769 bbl through this past August.
Sorensen wrote that 30 MMcf of CO₂ was used in the 2008 EOR pilot, but data were not available on pre- or post-test reservoir conditions. “However, after 11 days of injection, CO₂ breakthrough was observed in offset well [Austin 2-03H] 1 mile west.” (Austin 2-03H’s cumulative through this August was 667,943 bbl.)
Meanwhile, three other wells within a mile of Austin 1-02H “did not see CO₂ breakthrough, suggesting that understanding the local natural fracture system is key to EOR planning,” Sorensen wrote.
Far eastern Bakken, waterflood, 2012. Also in Parshall Field, EOG tested waterflooding Wayzetta 4-16H in 2012, injecting 39,177 bbl of produced water that April through May and another 45,171 bbl in October through November, totaling 84,348 bbl, according to state data.
Wayzetta had IPed 667 bbl of oil in July of 2008, according to the well file. Cumulative through this past August was 499,957 bbl. Cumulative water—deducting for what was injected—through August was 89,219 bbl.
Sorensen wrote, “Again, no data on pre-test or post-test reservoir conditions are publicly available. There was no observable incremental improvement in oil production attributable to water injection.”
State data show the well made 135 bbl/d of oil in the month prior to injection. In the first full month post-treatment, it made 59 bbl/d. That improved to 83 bbl/d before the second treatment began.
When brought back on the second time, it was making 50 bbl/d. That improved to 82 bbl/d in subsequent months.
After taking the well offline for work that EOG didn’t describe in the well file, it came back on with 227 bbl/d in January of 2014. This past August, it was making 18 bbl/d.
Far eastern Bakken, water with a gas chaser, 2012-2014. Sorenson wrote of a third EOG pilot in Parshall Field. In this, 447,471 bbl were injected into Parshall 20-03H beginning in April 2012 and through February 2014.
The well had IPed 1,347 bbl in May of 2008, according to state data. Production prior to treatment was 60 bbl/d. Output when brought back online in 2014 was less.
EOG followed with field-gas injection that summer, totaling 89 MMcf, according to state data. The well came back on with 95 bbl/d.
Altogether, the well was offline for 26 months. Production this past August was 30 bbl/d.
Sorensen wrote, “No data on pre- or post-test reservoir conditions are available, and there is nothing in the well file to suggest that the testing activities were considered successful by the operator.”
He added that “changes in fluid production rates were observed in two offset wells, demonstrating that communication between wells can occur rapidly.”
Sorensen added in his report that “it is important to keep in mind that the Bakken is an unconventional tight oil play.
“When viewed through a ‘conventional’ lens, a reservoir that is highly fractured with a tight matrix is not a good candidate for any conventional CO₂ EOR approach,” he wrote. “That is why these early [tight-rock EOR] tests should be viewed in the context of pioneering efforts and judged accordingly.
“The findings strongly suggest that a conventional [HnP] approach will not be effective in unconventional formations.”
Hess Corp. is looking at where in its Williston Basin leasehold EOR will work, Dougie McMichael, Hess director, Bakken well factory, told E&P magazine. Hess operated conventional-rock CO₂ EOR in the Permian, selling it to Occidental Petroleum Corp. for $600 million in 2017.
McMichael said that, while the Bakken “is complex with a dense rock matrix,” the formation “is variable across the basin.”
A Hess predecessor, Amerada Petroleum Corp., made the North Dakota oil discovery well, C. Iverson 1, in 1951. Hess’ name is on thousands of the state’s well files. With its large Bakken leasehold, it “can look at the characteristics of the rock across the formation to decide on where we think the application has the best chance of success,” McMichael said.
Challenges include whether the EOR effort will make enough additional oil, what injectant works best without requiring a lot of it—that is, being too costly—and how to keep it on lease.
Other tight-rock operators across U.S. shale plays are keeping their EOR intel tight—“as you can imagine for a technique that might have a competitive advantage,” McMichael added.
But, from what is public, it looks like the EOR challenges in other shales are similar to those of Bakken operators, he said.
EOG, Eagle Ford EOR
Operators tight-hole as much as they can for as long as they can. For example, when EOG deployed staged fracturing in the eastern Williston Basin, it asked the state to change the confidential-status policy to begin at IP rather than after spud.
Fracked horizontals take a long time, so the six-month-since-spud rule wasn’t fair, EOG had petitioned. The rule was changed to tight-hole results through up to six months after completion.
Over in Texas, operators have to file an H-13 form with the Railroad Commission (RRC) if wanting a 50% discount on severance taxes when an EOR project indicates “positive response.” Seven of the H-13 applications to date have been approved, according to Shale IOR LLC.
The firm has put together all publicly available data for 30 Eagle Ford EOR pilots and projects to date. Something certainly learned from EOG’s and others’ EOR pilots is to not do a “pilot” in the volatile-oil fairway, George Grinestaff, CEO, told attendees at Hart Energy’s DUG Eagle Ford conference in September.
Rather, the “piloting has already been done for you,” he said. So, instead, “you may want to go with a full project.”
If looking at “the low-API black-oil window, now we need to talk,” he said. EOR work there is too nascent. “We have to really start doing some design. But I would never say the black-oil window is a no-go because we [in the industry] always surprise ourselves with what we can do.”
Shale IOR looked at well, pad/unit and other details among the 30 EOR targets. “It’s not so easy to get, but we’ve gone through all of the [locations],” he said.
In the Bakken, a challenge has been to get the reservoir back up to bubble point or higher, due to natural fractures. The Eagle Ford, though, “can achieve surface injection pressures up to 8,000 psi, and that’s really what you need to achieve high recovery with lease gas,” he told Investor in October.
Grinestaff estimates 2,500 Eagle Ford wells per year are approaching their economic limits. “There are areas where EOR will not be a candidate because of oil quality and/or gas availability,” he added.
Meanwhile, EOR should be anticipated when developing the leasehold, he said, but operators have minimal resources and drilling and completion “has been the name of the game.” Still, some EOR infrastructure can be installed as part of the unit’s development and “it’s not terribly expensive.”
The best time to start gas injection is at least before putting a well on pump. In the Permian, for example, where operators aren’t getting much, if anything, for their associated gas, reinjection may be worthwhile.
“One of the largest expenses in a gas-injection project is buying the gas to fill up depleted wells. Once fill-up is achieved, 90% of the gas is recycled,” he said. “But the earlier you start, the less expensive gas fill-up will be.”
Patience is essential. “It typically takes two to four years to start doing a process like this. It moves very slowly.”
Chris Barden, Shale IOR COO, said, “The bottom line is it works. It’s been proven now.” Losing the gas to neighbors’ wells, if not owning all of the offset wells, “is really the biggest risk.”
Most important is to understand the hydrocarbon-phase behavior in gas-injection EOR, Grinestaff said at DUG Eagle Ford. In the Eagle Ford pilots, “it’s really vaporizing. The gas itself is mobilizing a lot of oil, and you’re producing the well just like you would a gas-condensate well, so you really have to focus on the phase behavior.”
Start-up may cost $10 million; meanwhile, cash flow declines during refill. “If you can use your own gas and processing, the economics change. But it is a robust process.
“The oil is there, and we believe you can get a consistent, robust result—an incremental 200 bbl/d.”
Eagle Ford EOR, ConocoPhillips
Among the Eagle Ford projects Shale IOR has studied are some by ConocoPhillips, which has more than 1,200 wells in the play to date. Cumulative production is more than 375 million barrels of oil equivalent (MMboe), net, beginning in 2009.
Current projects are three gas-injection HnPs, all in the black-oil window where there is lower gas drive, Erec Isaacson, ConocoPhillips vice president, Gulf Coast business unit, said at DUG Eagle Ford.
“One of the key things we’re doing during our EOR pilots, again, is gathering data—data that we can use to advance the technology, to innovate as we’re going through our EOR processes, so we can understand what mechanisms are impacting EUR most for us in the various areas of our Eagle Ford field.”
A legacy asset, “it’s one of our crown jewels. We have  billion bbl yet to produce in front of us. We have thousands of wells yet to drill,” he said.
Marty Thalken, chairman and CEO of Protégé Energy III LLC, told conference attendees that the EOR projects he has seen to date involve some 400 wells. “The results have to be reported to the Texas RRC [in an H-13 positive-response certificate] if they’re getting incremental recovery.”
He pointed to EOG’s Vincent eight-well EOR pilot in Karnes County, Texas. Pre-EOR, the forecast was of eventual production of 1.4 MMbbl per well based on the decline at the time. Post-EOR results suggest 2.4 MMbbl.
He estimates Eagle Ford gas-injection EOR at $55 oil has an 80% or higher ROR; at $40 West Texas Intermediate, the IRR is more than 40%.
“Those that have reported to the Texas RRC to date remain in various stages; however, the range of incremental oil recovery they are indicating varies from about 120,000 to 520,000 bbl during between 15 and 31 months,” he said.
CO2 treatment, Permian
A longtime CO₂-in-conventional-rock operator, Oxy has EOR pilots underway in tight rock in the Midland and Delaware basins, according to an E&P report. It aims to integrate EOR at the well-development level eventually.
Permian shale production is largely due to “a solution-gas-drive recovery mechanism” and has “steep production declines and low expected ultimate recoveries,” Shunhua Liu, an Oxy reservoir engineer, reported as lead author of a paper presented at the Unconventional Resources Technology Conference (URTeC) in 2018.
Oxy team members, along with Core Laboratories NV, did a lab-level experiment on Wolfcamp core samples taken from a new well. The samples were introduced to CO₂, methane and unfiltered field-produced gas. The average sample had porosity of 7%.
In the PVT (pressure, volume, temperature) test, injection of each of the three gases demonstrated “miscibility at initial reservoir pressure conditions, but CO₂ was the most efficient solvent, with first-contact miscibility at the lowest tested pressure,” Lui reported.
The team then tested what would happen if using shale core plugs—each 1 inch in diameter and 2 inches in length—with CO₂ at reservoir conditions. These “showed favorable results, including good oil recovery and CO₂ utilization in up to seven consecutive [HnP] cycles.”
The oil changed during the cycles as well. A nuclear magnetic resonance test showed “significant oil-saturation reduction,” thus “the extraction efficiency of this process.”
The greatest oil recovery—0.25 gram—was from the first HnP cycle “as expected,” but subsequent HnP cycles collected additional oil with 0.035 gram coming “even in Cycle 6.” The oil produced from the seventh cycle wasn’t enough to measure.
“The multicycle incremental recovery—even at the small core-plug scale—suggests the significant potential for multiple HnP EOR cycles for a future [Wolfcamp] unconventional EOR project design,” Lui wrote.
The lightest oil—less than C16—was produced in the first cycle; the heavier oil came later.
EOR tests in the Bakken and Eagle Ford—using CO₂- and produced-gas injection as well as trying chemical injection—have been tried by operators. But the rock and fluid properties of these systems are different than in the Permian, Lui added.
Bio-stimulation, Permian Basin
Using two Permian wells, researchers looked into whether some—or maybe even a lot—of steep shale-well decline is because of contamination induced during completion. The test fed bacteria that are naturally occurring downhole, activating them to eat up materials clogging the induced fractures, including each of the nearly invisible grains of proppant.
The findings of the field-level, Permian shale “microbial HnP” EOR test were reported at URTeC this summer by lead author Jacob Jin, ULTRecovery Corp. chairman and CEO. Participating in the study was the University of Oklahoma.
The reasons for rapid decline and low EUR from unconventional rock are myriad, Jin wrote. But among them is contamination—such as from gellants and partially hydrolyzed polyacrylamide (HPAM) that “is the main component of slickwater.”
The group unclogged the pores by “injecting microbial nutrients to the stimulated reservoir volume (SRV) to grow the indigenous beneficial microbes to degrade the residual fracturing-fluid chemicals.” What happened was “the otherwise-blocked flow paths are reopened.”
The field tests were done in July of 2018 in a vertical and in a horizontal. The wells’ owners weren’t identified in the report.
The vertical—in the northern Midland Basin—was completed in 2015 in lower Spraberry and Wolfcamp A at about 9,000 feet with crosslinked, guar-based fluid. Its IP was about 110 bbl/d; cumulative by June of 2018 was about 13,200 bbl.
“This well pump could not run 24 hours per day due to [the] low liquid-production rate,” Jin wrote. Wellhead pressure at the time of the EOR trial, which pumped 500 bbl of vitamins for the indigenous bacteria into the hole, was about 48 psi.
Pre-treatment production was 274 bbl per month; post-treatment peak was 662 bbl per month a few months later. Average daily production in March 2019 was 113% more than in June 2018. “The project payout is about four months, and the ROR is far more than 100%,” Jin wrote.
The tested horizontal is in the northern Delaware Basin west of the Pecos River. The 4,500-foot lateral was completed with 20 stages in 2014 at about 9,900 feet in Wolfcamp A with slickwater. Initial pressure was about 7,000 psi, and IP was about 630 bbl/d.
By June of 2018, it had produced about 174,000 bbl. Wellhead pressure was some 300 psi. In this one, 500 bbl of vitamins were injected as well.
George Grinestaff, CEO of Shale IOR LLC, estimates 2,500 Eagle Ford wells per year are approaching their economic limits. Meanwhile, EOR should be anticipated when developing the leasehold.
Pre-treatment production was 138.5 bbl/d; post-treatment peak was 303 bbl/d in September 2018. In January 2019, six months after treatment, average daily production was 122% more than pre-treatment, suggesting to the research team that the bacteria were continuing to work downhole.
The additional EUR is about 25,000 bbl or about 9% from one treatment. Payout was about 2.5 months; the ROR, “far more” than 100%, Jin reported.
Overall, among the two trials, liquid production improved between 40% and 127% in 180 days, “which means the otherwise-polluted SRV was unblocked by the stimulated, beneficial microbes.”
In eight months after treatment, the vertical made 1,500 bbl more than the pre-treatment decline rate suggested it should; the horizontal, after eight months, about 12,000 bbl more.
“The incremental of EUR of the fractured vertical and horizontal wells was 2,100 bbl and 25,000 bbl, respectively,” Jin wrote. “And the EUR after the treatment is increased by [between] 9% and 12%.
“The payouts for both treatments were [in] two to four months. The ROR for both pilots is more than 100%.”
In both cases, “considering only 500 bbl [of] microbial nutrients were injected and not all the fractures were contacted by the nutrients, a larger treatment in future might incur more incremental EUR.”
As the bacteria-based tests suggest vertical-well EUR may improve by about 12% and horizontal by 9%, “the total EOR potential of the current existing wells in the five major U.S. shale oil plays is 549 MMbbl” of oil as the low case.
“If the [HnP] treatment is repeated several times, more additional oil might be recovered.”
He noted that producers are reluctant to perturb bacteria downhole, though, with concern that it could result in “souring, biocorrosion, hydrogen sulfide, plugging the reservoir, etc.”
The ULTRecovery process doesn’t contain sulfate, though, Jin wrote.
Hess Explores For EOR Advances
In the ongoing effort to extract ever more stranded hydrocarbons from reservoirs, Hess Corp., Dow and the U.S. Department of Energy (DOE) have partnered in a joint program to fund research at the University of Wyoming (UW) into foam-assisted EOR technologies.
In August, the DOE contributed $8 million as part of a grant research and field pilot test program for which Dow, UW and Hess also contributed a combined $2 million. Researchers at UW believe foam-assisted hydrocarbon gas injection technology could help recover 3% to 5% more of the oil in place from unconventional reservoirs.
“The main driver for us is really to have the ability to recover more crude oil from unconventional reservoirs,” said Khalid Shaarawi, senior manager for Bakken technology at Hess.
“Right now, a significant portion of oil is left behind during primary depletion. So we want to find a way to get more oil out of the ground, unlocking those billions of barrels left behind.”
Shaarawi said that if an eventual test pilot for the technology is successful, it would be a “game-changer” for recovering stranded reserves.
Srini Prasad, head of reservoir engineering for Hess, said the research being conducted at UW builds upon previous efforts that initially focused on applying gas injection as an EOR process.
“What we have found is that the gas injection works in the lab,” he said. “It can extract oil, but one of the problems we have is breakthrough issues because of the natural and hydraulic fractures in the reservoir.
“That’s the reason we are embarking on this next stage of EOR where we are going to be using foam, using chemicals developed by Dow, where we test it in the lab and then field test it to be able to do a better job of enhancing the recovery than just using gas injection.”
Prasad said that field testing on Bakken EOR has been conducted on a smaller scale, but this venture will be the first large-scale pilot for Hess.
UW researcher and Wyoming excellence chair in petroleum engineering Mohammed Piri said that the knowledge gained throughout the course of the research project will be used to calibrate computational simulations to better predict field performance, assess and mitigate potential risks and ensure successful implementation in the field.
According to Hess, the EOR research will be conducted at an advanced experimental oil and gas research facility housed at the university’s High Bay Research Facility, which was established in partnership with Hess. During the past six years, Hess has contributed $25 million to UW’s College of Engineering and Applied Science to improve the understanding of complex rock-fluid interactions in plays such as the Bakken.
“Hess has a strategic collaboration with [UW] that does deliver a lot of value at Hess, and that helps us provide solutions to meet the world’s growing energy needs,” Shaarawi said. “We rely on [UW] for its groundbreaking research capabilities as well as their high-end technical services they give us.” —Brian Walzel
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