Journal of Petroleum Technology September 2012 : Page 34

HEAVY OIL TECHNOLOGY OIL SANDS GET WIRED Seeking More Oil, Fewer Emissions Stephen Rassenfoss, JPT Emerging Technology Editor T wo projects in Canada are out to show that oil sands production need not remain in the steam age. Both are powered by electricity, though they use it quite differently. The motivations are the billions of barrels of crude in formations where current methods are not practical or economic, and a desire to find a way to produce heavy crude with less energy and water. No one is talking about replacing steam for heavy oil production—it is an extremely efficient method for delivering the heat needed to reduce the viscosity of the heavy crude called bitumen. But the potential payoffs for finding a workable alternative is huge. Of the total bitumen resource in the ground in Alberta, 7% is shallow enough to be mineable, said Todd Zahacy, senior engineering consultant for exploration and production at C-FER Technologies. While production using in-situ extraction techniques from deeper reserves has recently exceeded the output from mining, only about 9% of that vast resource is counted as reserves in Alberta’s 2012 survey of its oil, gas, and coal resources. “There is a massive prize out there if you can go after those areas that are not currently technically producible,” said Zahacy, with the research and testing company that has been evaluating electric methods for a client. An antenna used to heat the heavy crude in an oil sands deposit is tested at Suncor’s Steepbank Mine. The 2-month trial showed it was able to heat the rock as predicted by simulations and the partners in the ESEIEH Consortium are now working on a production test.

Heavy Oil Technology • Oil Sands Get Wired

Stephen Rassenfoss

Seeking More Oil, Fewer Emissions Two projects in Canada are out to show that oil sands production need not remain in the steam age. Both are powered by electricity, though they use it quite differently. The motivations are the billions of barrels of crude in formations where current methods are not practical or economic, and a desire to find a way to produce heavy crude with less energy and water. No one is talking about replacing steam for heavy oil production—it is an extremely efficient method for delivering the heat needed to reduce the viscosity of the heavy crude called bitumen. But the potential payoffs for finding a workable alternative is huge. Of the total bitumen resource in the ground in Alberta, 7% is shallow enough to be mineable, said Todd Zahacy, senior engineering consultant for exploration and production at C-FER Technologies. While production using in-situ extraction techniques from deeper reserves has recently exceeded the output from mining, only about 9% of that vast resource is counted as reserves in Alberta’s 2012 survey of its oil, gas, and coal resources. “There is a massive prize out there if you can go after those areas that are not currently technically producible,” said Zahacy, with the research and testing company that has been evaluating electric methods for a client. The goals of these two programs are electric-powered heating methods capable of eliminating the costly equipment needed to produce steam and process large volumes of water on site. Lower-temperature methods may also reduce energy use and open up access to underground formations not suited for high-pressure steaming. The search for electric-powered heating in heavy oil fields goes back decades, but no one has made it work on a commercial scale. Les Little, executive director of energy technology for Alberta Innovates, has long followed the experiments with electric heating technology, and he knows many question if it can be more successful this time. The government technology promotion agency is backing another round of testing, though, because he said this technology “is not your dad’s electrical heating system.” The province is putting up more than USD 23 million from the Climate Change and Emissions Management Corporation—the government arm is funding half the budgeted cost—because the two electric-powered heating projects could reduce the environmental impact of heavy oil production as measured by water use and carbon dioxide emissions. That is a potent motivation in Alberta. Projects critical to tapping the oil sands, such as the Keystone pipeline running from western Canada to US Gulf Coast refineries, have been threatened by environmentalists who point out the energy and water required for heavy oil extraction mean it has a larger environmental impact than conventional production. Reducing costs is an important goal on the business side because the high energy and capital costs associated with steam-assisted methods make bitumen among the most expensive crudes to produce. Little said electric heating methods that do not require water could reduce the energy used by about 40%. If that goal is reached that would mean significantly lower emissions, even when factoring in those associated with generating the power. “If the savings shown in the early work can be reproduced on a commercial scale, these will be comparable with the lowest emissions per barrel of any refinable crude in the US,” Little said. Different Ways to Heat a Reservoir The two Canadian projects, plus a third involving Siemens, show the range of electric-powered heat sources: ◗ E-T Energy uses electrodes in wells to send a current through the water in a heavy oil reservoir. Electrical resistance raises the temperature to about 130°C, reducing the viscosity of the bitumen and allowing it to be pumped out of production wells. E-T is short for Electro-thermal Dynamic Stripping Process (ET-DSPTM). ◗ The ESEIEH group plans to combine heat created by broadcasting radio frequencies (RF Heating) with solvents, such as butane or propane. The acronym, pronounced “easy,” stands for Enhanced Solvent Extraction Incorporating Electromagnetic Heating. ◗ Siemens has been developing a third technique using a coil looped inside a well to create an eddy current covering an area 50 m to 100 m from the well. The device generates electromagnetic fields that produce heat. Siemens’ testing program has demonstrated its ability to heat the ground. It is seeking an oil industry partner to demonstrate whether its method can be used for bitumen production. Siemens and others in this field are in search of widely recognized exploration and production applications. There are opportunities for its heating system in formations where gas or water is present above or below the oil deposit causing thermal losses, or are not now producible, such as deeper formations where pressure is a problem for steam injection. “The first request is to achieve high enough temperature, which means: not higher than necessary, for low enough viscosity,” said Andreas Koch, R&D project manager for electro magnetic heating at Siemens Oil & Gas. This typically ranges from 100°C to 150°C, but can go lower depending on the reservoir. Secondly, there needs to be a drive mechanism pushing the oil. Siemens has investigated options including nitrogen injection and combining electromagnetic and steam injection. The well design affects the energy used and the emissions impact. Incorporating electromagnetic heating in a traditional Steam-Assisted Gravity Drainage (EM-SAGD) design could speed startup and reduces emissions by about 15%, he said. Marrying it to nitrogen injection could widen the reduction to 40%. E-T Energy has formed a partnership with Total E&P Canada, which has promised to support future development in the venture’s Poplar Creek project in exchange for a 30% stake in the field, as well as intellectual property rights, according to a presentation to investors on E-T’s website. The E-T project is using technology developed in the mid-1970s at the University of Alberta. What was created as a heavy oil recovery technique has been used since as an in-situ method to clean up about 50 underground concentrations of hazardous chemicals as part of the US Superfund program, according to E-T’s website. The ESEIEH process began as a way for Harris Corporation to profit from what it has learned about sending electromagnetic waves long distances through the Earth, to send radio waves no farther than the boundaries of a reservoir. It recently announced results of a test showing it can heat an oil sands deposit in a predictable way. Electric powered heating methods must be able to efficiently raise the reservoir temperature, and heat rocks at a distance from the well. Now the partnership, which includes three Canadian oil companies, Suncor Energy, Nexen, and Laricina Energy, has the more difficult challenge of proving it can effectively combine that heating method with solvents to efficiently produce oil. The combination reduces the viscosity of crude at temperatures below the boiling point of water at reservoir pressure. The success of the venture depends on the expertise and experience of partners inside, and outside, the oil business. “When dealing with petroleum production, petroleum engineering people are focused on rocks and mechanical solutions. This is very focused on electrical engineering. You have to tap into some different resources,” said Marty Lastiwka, senior research engineer, production operations for C-FER Technologies. In July, Nexen agreed to a buyout offer from CNOOC, an oil company controlled by the Chinese government. Soon after, two US Senators objected to the takeover of the Canadian company, which has significant holdings in the US Gulf of Mexico. Harris said in late July that it was still early and it was “working with our partners to identify and address any potential implications,” said Sleighton Meyer, senior manager for communications at Harris Corp., the US defense contractor. Little pointed out that the technical details of how the device works is covered by Harris’ confidentiality agreement limiting disclosures to its partners. Mining Is Just Scratching the Surface E-T’s production horizon is not much deeper than the normal limit of oil sands mining, which is limited by the high cost of digging and processing the crude, as well as restoring the land afterward. The company’s website says Canadian oil sands from 50 m to 150 m hold an estimated 173 billion bbl of stranded oil in Canada. These deposits usually cannot be produced using steam injection because they lack the cap rock needed to contain the high-pressure water vapor used for the most common in-situ method: steam-assisted gravity drainage. E-T’s method is drilling intense because of the limited range of its heating method. It relies on clusters of tightly spaced, shallow, vertical wells—in the current test they are up to 18 m apart—divided between electrode wells, named after the equipment sending current into the well, and production wells to pump out the oil. For its upcoming third phase, E-T’s website said it planned 23 electrode wells and 14 production wells. Another six observation wells will be drilled. Some water needs to be added to cool the electrodes and ensure there is water present to maintain the connection with the reservoir. In an operating field, a small amount of fresh water is needed when a well is started up, but after that the water needed can come from produced water. E-T projects that by employing a tight well pattern to heat the formation it will be able to recover more than 55% of the oil in the ground in about a year. Its goal is to produce 50,000 b/d of oil by 2016. To do that, E-T said in a presentation, it would need to drill 5,000 shallow wells a year. Drilling and completions will represent an estimated 50% of its estimated expenses, while electric power will equal about 25%. The energy value of the oil produced using the method is expected to be 30 times the energy needed to get it out of the ground, compared to a ratio closer to 5 for SAGD, said Bruce McGee, the company founder and largest shareholder who has turned over management of the operation to others and is president and CEO of McMillan-McGee, which uses the technique for treating hazardous waste sites. But first E-T needs to show it can profitably meet its production goals. “A commercial field test is in progress and we are ramping up production,” McGee said. “It is too early to tell if we will hit all our target objectives.” ESEIEH Is Only Pronounced Easy Success for the ESEIEH group depends on proving it can put together two emerging technologies—RF heating and solvents—in a way that overcomes their limits if used individually. The heating method is capable of matching the heat from steam, but it costs too much to do so. Adding solvents is expected to mean more oil production using RF heating at lower temperatures. ESEIEH is building on past work by Neil Edmunds, vice president of enhanced oil recovery for Laricina Energy, who is an expert on combining solvents with steam to increase SAGD output, and creating computer simulations of novel bitumen production techniques. The company is running an antenna underground that emits enough energy to heat the ground to around 50°C (120°F). “We figure it is warm enough for solvent drainage at an effective rate, but cool enough to use electricity to heat the reservoir,” Edmunds said. This is not necessarily going to be the temperature that will be used. Little mentioned 75°C or more. The group is not disclosing the details. Given the newness of the method and the lack of experience, a key goal for the partnership is to test how varying combinations of radio frequency heating and solvents compare with what is predicted by the models. For now the group is working on obtaining a permit from provincial regulators to drill a pilot in-situ well, and using what it has learned from its 2-month mine test to fine tune its simulations and modify the equipment to ensure it is built for a long stay in the ground.“You have to be able to hit it with a sledgehammer,” Little said. “It needs to be as simple as possible and as robust as possible and function with minimal downtime.” JPT Sending Out Radio Waves to Fine Tune Heavy Oil Recovery Harris Corp. is a defense contractor known for building communications systems able to efficiently broadcast radio signals around the globe. Now it is trying to make money in enhanced oil recovery (EOR) by inefficiently sending radio waves on journeys through the ground that will be measured in meters and used for heating. “We can transmit halfway around world through the ground and water,” for military communications, said Derik Ehresman, the senior manager at Harris leading the project. “What we are doing here is using a shorter wavelength to heat up an oil reservoir.” The method combines heat created by an antenna sending out waves on frequencies normally associated with AM radio, with a boost from a solvent, such as propane or butane, further reducing the viscosity of the heavy oil known as bitumen. The combination, called Enhanced Solvent Extraction Incorporating Electromagnetic Heating (ESEIEH, pronounced “easy”), can change the crude from as immobile as peanut butter to something that flows like olive oil. For it to cost less than steam it must be able to do this at a much lower temperature than steam, which is where the solvent comes in. The expertise required to make these emerging technologies work in tandem is coming from outside and inside the oil industry. The ESEIEH consortium is relying on three oil company partners Laricina Energy, Nexen, and Suncor Energy, for their knowledge of heavy oil production as well as their support of field testing for the USD 33 million project. Half the budget is coming from Alberta’s Climate Change and Emissions Management Corp. program, which funds project reducing carbon dioxide emissions. The partnership recently reported that it successfully tested its radio frequency heating (RF heating) equipment by running it inside a horizontal well 15 m below the surface of Suncor’s Steepbank Mine. The 2-month test was monitored using heat and pressure sensors in multiple monitoring wells. “This is the first stage in a 3-year long project. We were testing if we could deliver a controlled amount of heat into oil sands using RF technology,” said Mark Trautman, Harris’ chief of reservoir analysis. The test confirmed the system design is capable of delivering the heat as expected, and that the equipment is robust and can be installed, said Les Little, executive director of energy technology for Alberta Innovates, the government technology support agency that is covering half its budget. As of mid-summer the ESEIEH partners were preparing to request a drilling permit for a test next year to see if the heat plus solvents can be used to commercially produce oil. Broadcasting Heat Harris’ journey into exploration and production began with a brainstorming session with drilling consultants from Canada. The purpose of the meeting was to consider new drilling technologies for the US Defense Advanced Research Projects Agency (DARPA), which does research for the US Defense Department. “One of the consultants asked, ‘If you can get this (antenna) into a hole in the ground, can you heat the ground?’ ” The answer was yes: “We do that by accident all the time. When we lay an antenna down for testing, it will heat the ground.” It seemed like a promising idea, so Harris started researching heavy oil extraction by contacting Canadian companies in the business. The problem was, using RF heating to equal to temperatures reached using steam is not energy efficient. Its range is limited and is a function of how much energy is used. While reducing the viscosity of bitumen does not require the high heat common in steam-assisted gravity drainage (SAGD)—the 200°C to 250°C temperature is needed to get the steam to the end of the hole—switching to a lower temperature raised questions about how effective it could be. Neil Edmunds, vice president of enhanced oil recovery for Laricina Energy, suggested the solution: adding solvents with RF heat could mobilize more bitumen at a lower temperature. “The light bulb went on,” Trautman said. “We started looking at the feasibility” and got the support of Laricina, Nexen, and Suncor. Zap It in the Radiowave The easiest analogy for RF heating is: It is like microwaving something. But there is a big difference. The electromagnetic wavelengths used are in the lower part of the spectrum commonly associated with AM radio. Microwaves do not work because they do not travel far enough into a reservoir. The goal of this method—also called dielectric heating because it generates heat a couple of ways—is a localized signal concentrated within the oil-bearing rock. There is no payoff for heating the overburden. “As the wave propagates in the formation, energy is absorbed, the signal loses strength as it heats the formation,” Trautman said. Larger formations require higher power to cover a larger area. “This gives you more knobs than a typical process. You can vary frequency and change the penetration depth by changing the power,” Trautman said. “With steam you cannot do that by instantly changing the knob on a control panel up or down.” To take advantage of the adjustability of the system, accurate computer models are needed to sift through the many possible combinations of radio frequencies, power levels, solvents, and well designs to point to the options most likely to work in a specific location. Computer simulations will also be called on to answer economic questions: What is the most profitable mix of equipment, solvents, and power, and how does that compare to the alternatives? “If you extrapolate that further, that can be used to build economic models of the most profitable way to manage production,” said Mark Blue, an advanced programs engineer involved in energy solutions at Harris. The mine test results were in line with the simulations, which was a pleasant surprise considering the early stage of the testing, Little said. There was also an unexpected extra, he said. The Steepbank Mine results suggested this approach might offer an attractive alternative to digging up the oil sands for processing. Seeking Solvent Solutions The next step is to see how the combination of RF heating and solvents do at producing oil. The ESEIEH group is planning on applying this unfamiliar technology in a familiar well design—a pair of wells configured like the ones used for steam-assisted gravity drainage (SAGD) production. The upper well is for heating and injection of solvent, and the lower well for capturing the oil and solvent flowing down through the reservoir. Oil output will be compared with the cost inputs. On the operating side there is the cost of energy and solvents. The power cost variables include the ideal reservoir temperature—the cost of equaling the temperature reached by steam heating is prohibitive. Solvents are more valuable than heavy crude so a high percentage of them must be recovered for this method to be practical. The equipment needed to source, heat, and treat water for SAGD, which represents about 50% of the cost of a SAGD field development according to Laricina, is not required on the ESEIEH process. Some water is produced—Trautman estimated about 0.2 bbl of water for 1 bbl of oil—but it is a fraction of what is associated with SAGD. The ESEIEH group plans to reinject the water removed from the produced oil. Another possibly positive variable is crude quality. Based on observations from past tests, Little said the quality of crude produced using electrical methods has been better than expected based on the bitumen in the ground. Some have theorized that the electromagnetic energy may alter the molecules in the bitumen, resulting in lighter crude, he said. The added control allowed by electric-powered heating might aid that effort in producing from rocks that are far more variable, and fractured, than oil sands. This may figure into Laricina’s work to find a way to produce oil from carbonate formations. RF heating could more uniformly heat highly irregular rock formations than steam’s fluid heat transfer mechanisms, Trautman said. Harris is looking into other possible uses for the antenna, from using it to heat a heavy oil field to speed the startup of production, to using it for fracturing, said Travis Berrier, a business development manager on the project, adding: “We are looking for blue ocean opportunities, where there is not currently an economic process.” JPT Drilling Fast and Carefully to Open a Shallow Frontier The future of E-T Energy hinges on a different sort of oil well, and lots of them. The Canadian company typically drills six wells a day, with each taking about 6 hours to reach a total depth of from 90 m to 100 m. Completion requires wiring them to send a current among the tightly spaced wells to warm the reservoir allowing the company to produce the viscous crude oil. “This is a paradigm shift on oil sand development,” said Bruce McGee, the founder of the company who developed the technology employed in the company’s first large-scale field development. Its goal is producing 10,000 b/d of crude by 2014 from wells able to recover 50% or more of the crude in that spot within about 1 year. It will take what sounds like an enormous number of wells to get there—a company presentation estimated 5,000 wells a year to produce 50,000 b/d—but McGee points out that “when you look at a mining operation digging up 60 m of overburden to get the same oil, that looks more challenging than drilling.” E-T’s target depth, which it extends to 250 m, is below the depth where oil sands mining operators lose interest because of the high cost of removing the oil-rich sand and all that is on top of it and hauling it off for processing, By running a current from wired holes, called electrode wells, to an extraction well, it is able to warm the reservoir. The temperature range is low compared to the steamheating methods commonly exceeding 200°C. E-T’s field temperature ranges now from as much as 130°C near the well to around 40°C closer to the production wells where it is pumped out using progressing cavity pumps. Over time, the oil field heats up and the oil cut rises, to a level around 80% oil, McGee said. Rather than pumping in high-pressure steam, it is reducing the viscosity of the immobile crude by warming the reservoir water using electrical resistance. The temperature drop demonstrates a big engineering problem facing ET—the level of electrical resistance limits the area that can be heated this way. An unexpected side effect of the process is the gas trapped in the bitumen comes out of solution, producing bubbles increasing the pressure inside the formation, he said. This can be seen in videos online showing produced crude in barrels bubbling like a carbonated espresso milkshake. Another surprise has been the viscosity of the crude, which is lower than what is found in the formation. McGee said, “We have seen our numbers and do not understand what it happening.” Lab work will be required to see if the process is capable of causing an electrochemical reaction that alters the oil. This has also been an adjustment for those drilling the wells. During its early well tests, the failure rate for electrodes was around 75% over the short life of the well. It is now around 5%. The reduction reflected changes in the equipment, the completion method, and the habits of rig workers, said McGee, adding, ”You cannot have the culture of banging things around when dealing with sensitive electrical equipment.” JPT For further reading: SPE 148932 Electromagnetic Heating for In-Situ Production of Heavy Oil and Bitumen Reservoirs by Bernd Wacker, Siemens, et al. SPE 150686 Evolution of In-Situ Oil Sands Recovery Technology in the Field: What Happened and What’s New? By Ian D. Gates, Department of Chemical and Petroleum Engineering, University of Calgary, et al. SPE 154140 Numerical Simulation of Electromagnetic Driven Heavy Oil Recovery by Igor Bogdanov, CHLOE, et al. SPE 154123 Evaluation of Electromagnetic Heating for Heavy Oil Recovery From Alaskan Reservoirs by V. Peraser, The University of Alaska Fairbanks, et al.

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