[Subjectivist]

CALGARY – Joseph Kuhach faces a daunting task. For his company to grow, he will need to convince oilsands producers to change the way they extract oil from northeastern Alberta.

“The industry has historically been shy about taking dramatic steps to change things,” Kuhach said. “They want to be first to be second.”

Kuhach is chief executive of Calgary-based Nsolv, which operates a 300-barrel-a-day pilot project on a Suncor Energy Inc. oilsands lease and is actively looking for an energy company to partner with on a new, full-scale commercial facility.

Any such partner would need to be comfortable that Nsolv’s process would work in a 5,000 bpd facility — despite the fact other new oilsands extraction technologies have had difficulty operating on a commercial scale.

“Getting across the valley of death for companies, from technically demonstrated to commercially demonstrated, that’s the big challenge,” Kuhach said.


In 2011, Petrobank Energy and Resources Ltd. tried to commercialize a lab-tested oilsands extraction technology called “toe-to-heel air injection,” or THAI, which the company said could increase the amount of oil produced from deeper-lying bitumen deposits.

Petrobank promoted THAI as a superior process to the two main techniques used in the oilsands called “steam assisted gravity drainage,” or SAGD, and “cyclic steam stimulation,” or CCS, which both use large quantities of water to produce oil.

Petrobank was never able to demonstrate that THAI worked at a commercial scale in the oilsands, and the company eventually merged with Touchstone Exploration Inc., which is primarily focused on operations in Trinidad and Tobago.

Kuhach is well aware other companies have been unable to demonstrate commercial viability, but he contends Nsolv’s process can work and that it can save energy producers money while helping reduce greenhouse gas emissions. He said the process, named “bitumen extraction solvent technology,” or BEST, can live up to its acronym.

On March 4, Nsolv secured a $13 million grant from Sustainable Development Technology Canada, which gives the company a boost but not enough to build a commercial-scale plant. Kuhach still needs a partner in the oilsands.

On Friday, Imperial Oil Ltd. announced it had filed an application to build a new 50,000-bpd facility using its own solvent-based process, signalling that commercial-scale solvent extraction techniques are getting closer to reality in the oilsands.

Getting across the valley of death for companies, from technically demonstrated to commercially demonstrated, that’s the big challenge
Where SAGD and CCS operators pump large volumes of steam at high pressures and high temperatures into oilsands reservoirs, Nsolv’s process pumps solvents down a well into the reservoir at both lower temperature and lower pressures.

Nsolv’s solvents dissolve the bitumen in the reservoir, allowing that heavy oil to flow to the surface while leaving the sulphurs, heavy metals and other undesirable products in the ground, Kuhach said.

“That’s really what makes the oil that we have in the oilsands so heavy. When you pull that out, you’ve got something that’s more along the lines of conventional oil,” he added.

The operation uses less energy and produces higher quality oil with far fewer unwanted byproducts than the techniques in use across the oilsands now, Kuhach said.

“We think we’ve got at least a three-quarters improvement and we would generate somewhere around a quarter of the greenhouse gasses that would be generated by a SAGD project on an apples-to-apples basis,” he said.

Some oilsands operators are struggling to produce oil economically with prices hovering around US$30 a barrel, and virtually every player in the industry has pared back their growth plans.

But now, under the provincial NDP government’s climate change legislation, oilsands producers face an upper limit on how much carbon they are cumulatively allowed to emit. In addition, companies with higher emissions will need to pay more in carbon taxes than companies with lower emissions.

“I think folks are starting to realize that carbon is going to cost more,” Kuhach said, adding he believes the new policies could provide a boost to Nsolv and companies like it, that seek to reduce the emissions in the oilsands.

He is also hopeful companies will take a longer look at his company’s pilot project while oil prices remain low. “You can’t do SAGD, you can’t even think about it at $35 oil. We believe, with our technology, at the commercial scale of 5,000 to 10,000 barrels a day, you can still make money at $40,” he said.

Nsolv is operating its pilot project in northern Alberta and looking to grow. Kuhach said the company has been in talks with a number of large oilsands producers but wouldn’t give details on how close he is to signing a deal to build a larger facility.

Financial Post

[email protected]

http://business.financialpost.com/entre ... =5666-3624

[ROCKMAN]

"THAI is as old as this web site." How old is the site? We began using THAI for heavy oil secondary recovery 24 years ago in 1992.

[AdamB]

"THAI is as old as this web site." How old is the site? We began using THAI for heavy oil secondary recovery 24 years ago in 1992.

You mistaken assumed that pstarr wasn't getting "carried away" with his faux facts again.

[Tanada]

News flash Pstarr, lots of the different recovery methods used by the oil industry are formation or even location within a formation specific. THAI is however not just a tar sands technique, it is also used for very heavy and extra heavy liquid oil formations like the Orinoco Belt in Venezuela and a variation of it is also used for Underground Coal Gassification.

Why is it that no matter what technique or technology anyone posts about you discount its useful aspects and potential for use in other situations? Every wedge solution is another little bit of help in a sad world of limits.

[rockdoc123]

"THAI is as old as this web site." How old is the site? We began using THAI for heavy oil secondary recovery 24 years ago in 1992.

well obviously not THAI persay given that is a patent held by Petrobank. But certainly other means of "fire flood" technology was used as early as the seventies (I was involved in a fire flood test project in northern Alberta back in the late seventies). Not sure what the exact detail was that allowed for Petrobank to patent THAI.
In any event I think THAI is now defunct. Petrobank merged with a company called Touchstone Exploration back in 2014 and currently the only production Touchstone has is out of Trinidad. They do not seem to be touting THAI at all and all of their E&P program is based on infill drilling and recompletions in a number of onshore fields.
The former principles of Petrobank are long gone and doing other things. John Wright the former CEO of Petrobank went on to be CEO of Lightstream Resources which held properties in Alberta Cardium and Saskatchewan Bakken tight oil/gas. Lightstream went into CCAA protection (Company Creditors Arrangement Act which is more or less the same as Chapter 11 in the US) in September and is now attempting to sell all of its assets. Chris Bloomer who was the COO of Petrobank for a short while was CEO of a small Canadian company seeking Mexico opportunities and is now CEO of the Canadian Energy Pipeline Association an industry not for profit that lobbies on behalf of the various pipeline transmission companies in Canada. So as far as I can tell THAI has died the good death. But as I said before there are likely all sorts of different fire flood schemes being deployed in various heavy oil pools

[Subjectivist]

I put the link above because a new company is using a "improved" THAI process and looking for partners in the tar sands to work with.

[rockdoc123]

Yeah sub....should have gone to the first post and the link. I see they are calling it something different
Interesting when you go to the site of this new company turns out I know the founder of the nsolv process, John Nenniger. The company I worked for used him quite a bit for dealing with waxy and heavy crudes many years ago (his forte is oil rheology and what affects it). He definitely knows his stuff.
But I'm a bit confused as Thai deals with pumping down oxygen and combusting an oil front above a horizontal producer, driving the superheated oil to the heel. nsolv actually pumps down a warm solvent that partially upgrades the heavy oil and forces it to the heel. Quite a bit different so I'm not sure why the Financial Post article is directly comparing it to Thai....not the same thing at all. Confusing.

[Synapsid]

rockdoc,

Is nsolv the same as the solvent-based approach being used (or tried?) on the waxes in Utah?

Come to think of it, that process is supposed to be water-free with the solvent recoverable, so I guess not nsolv. I believe it's a Canadian company calling itself "American"...something that uses it. Are you familiar with it?

[rockdoc123]

not sure but generally the goal of a solvent directed at waxy crudes is to change the state of paraffin from solid to liquid. With the heavy oils the heated solvent essentially cracks the heavier elements which decreases viscosity. Generally waxy crudes are most dependent on temperature as to whether the wax is beyond the solidus curve or not whereas heavy crude viscosity can be independent of temperature.

[Tanada]

Link to long and detailed report at link below quote.

Lag times in toe-to-heel air injection (THAI) operations explain underlying heavy oil production mechanisms

Under a Creative Commons license

Open access
Abstract

From a time value of revenue point of view, it is preferred that the time between reservoir stimulation and oil production response is small. Heavy oil combustion processes have a lag time between air injection and liquid production, but the common practice in production data analysis uses simultaneous injection and production data when seeking a relationship between them. In this research, the time scales of production for the Kerrobert toe-to-heel air injection (THAI) heavy oil project in Saskatchewan, Canada, is analyzed by using cross correlation analysis, i.e. time delay analysis between air injection and oil production. The results reveal two time scales with respect to production response with two distinctive recovery mechanisms: (1) a short time scale response (nearly instantaneous) where oil production peaks right after air injection (directly after opening production well) reflecting cold heavy oil production mechanisms, and (2) a longer time scale (of order of 100–300 days) response where peak production occurs associated with the collective phenomena of air injection, heat generating reactions, heat transfer, and finally, heated mobilized heavy oil drainage to the production well. This understanding of the two time scales and associated production mechanisms provides a basis for improving the performance of THAI.

1. Introduction

Bitumen in the Western Canadian oil sands were formed millions of years ago as lighter oils underwent severe biodegradation resulting in present-day oil viscosities with thousands and up to millions of centipoise (Zhou et al., 2008; Li and Huang, 2020; Chang et al., 2021). Over the past few decades, in situ steam based technology such as steam assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS) have been the most used thermal recovery methods in the oil sands industry in Western Canada (Ali, 1994; Batycky, 1997; Butler, 1998; Edmunds, 1999; Donnelly, 2000; Jiang et al., 2009; Bao et al., 2016, 2017; Trigos et al., 2018). With the global shift to decarbonize, there is a desire to find new recovery process options with lower greenhouse gas (GHG) emissions (Gates and Larter, 2014; Safaei et al., 2019). Research has been conducted on foam, polymer, solvent injections, and nanoparticles into heavy oil reservoirs to reduce the oil viscosity (Wang et al., 2011; Shi et al., 2015; Chen et al., 2019; Sun et al., 2020). Injection of oxygen into the reservoir is another alternative to the injection of steam into the reservoir. In this case, when the oxygen reaches the oil, providing the oxygen partial pressure is high enough, combustion occurs generating heat within the reservoir. This consequently raises the temperature of the oil leading to oil mobilization (viscosity reduction) and production. In addition, the combustion zone can generate in situ steam which can mobilize additional oil. One such process where air is injected into the reservoir is the toe-to-heel air injection (THAI) process (Turta, 2013; Ameli et al., 2018).

THAI is an in situ combustion method for producing heavy oil invented by Greaves and Turta (1997). Unlike a conventional fireflood method that uses two vertical wells, the THAI process utilizes a well configuration which consists of one vertical injection well and one horizontal production well, as shown in Fig. 1. The air is injected continuously near the toe of the production well through the injector. After combustion initiates, a series of reactions such as low temperature oxidation (LTO), high temperature oxidation (HTO), aquathermolysis, pyrolysis are taken place to generate heat and mobilize cold bitumen (Song et al., 2009; Kapadia et al., 2013; Jia et al., 2016). The fire front moves in a toe-to-heel progression along the producer, expanding the depletion zone as mobilized oil drains under gravity to the horizontal well.
Fig. 1

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Fig. 1. Schematic of toe-to-heel air injection (THAI) (Greaves and Turta, 1997).

Previous research on THAI was mainly based on three-dimensional (3D) combustion cell experiments (Greaves and Al-Shamali, 1996; Greaves and Al-Honi, 2000; Greaves et al., 2001; Xia and Greaves, 2002, 2006; Xia et al., 2003, 2005). In general, they demonstrated high oil recovery and partial upgrading of heavy oil: Xia and Greaves (2006) used virgin Athabasca tar sand in a 3D THAI combustion cell experiment which demonstrated >80% oil recovery and more than +8° API upgrading. Furthermore, the oil viscosity was lowered by a factor of four and the upgraded oil contained about 70% saturates compared to 14.5% in the original bitumen. Other 3D THAI combustion experiments (Greaves et al., 2001; Xia et al., 2002, 2003) using other oils (Wolf Lake oil, Lloydminster oil, medium heavy and light oil) all showed high oil recoveries (>80%), partially upgraded oil, and drastic reduction of the oil viscosity. Prior simulation studies of THAI validated the experimental results (Coates and Zhao, 2001; Greaves et al., 2012b; Ado et al., 2017). Field operations have also validated the technical viability of the THAI recovery process for heavy oil production (Ayasse et al., 2005; Petrobank, 2012; Turta and Greaves, 2018), however, field oil production (Wei et al., 2020, 2021) have not been as promising as lab-based results, nor as good as predicted by field scale simulation models (Greaves et al., 2011, 2012c; Ado, 2020b, a). There is limited field data analysis and lack of research on examining the production difference between laboratory experiments and field production.

Greaves et al. (2012a, c) simulated a combustion cell experiment (0.6 m × 0.4 m × 0.1 m) whereas Coates and Zhao (2001) simulated a 3D combustion cell (0.4 m × 0.4 m × 0.1 m) experiment conducted by Greaves and Al-Honi (2000). From these simulations, the production mechanism of THAI process was determined to be mainly gravity driven which mitigates gas channeling issues experienced by conventional in situ combustion process. Furthermore, the simulations identified that the steam zone ahead of the combustion front is a major mechanism for transporting heat from the combustion gases to the cold oil reservoir beyond (Coates and Zhao, 2001; Greaves et al., 2012a, c; Ado et al., 2017). An in situ combustion field study by Hajdo et al. (1985) indicated that heavy oil production can lag air injection by several weeks determined from observations of the field data. The production profiles of an experimental run 984 by Xia et al. (2003), experiment run 3 of Greaves and Al-Honi (2000), and experiment run 2000-01 by Greaves et al. (2012a) all showed a trend of drastic oil decline at the beginning followed by another peak oil rate at around 100–300 min followed by a gentle decline. However, this trend of delayed peak oil production rate was not matched nor observed by prior simulation models (Greaves et al., 2012a, c; Ado et al., 2017). The simulation study by Greaves et al. (2012a) even showed a countercurrent production trend at the beginning compared to the experimental result. Thus, the literature reveals that the recovery mechanisms and the link to how the recovery profile evolves during the process remains unclear.

The research documented here aims to use lag time analysis to improve the understanding of the recovery mechanism in the context of the response of production to stimulation. The time scale for this lag nor the physical reason for the lag is not well understood and this time scale can be instructive as to the underlying mechanisms that limit or enhance process performance.

Lag time effects have been studied extensively in many fields of science to gain insights into possible interaction mechanisms between different physical and chemical processes (Runge et al., 2014). For example, DeWalle et al. (2016) studied the lag times between atmospheric deposition and changes of stream chemistry to improve an understanding of the ecosystem and to refine pollutant control strategies. In another example, Bello et al. (2017) evaluated the effect of longitudinal multi-pollutant mixture exposure on health outcomes in later life. Chen et al. (2018) made an attempt to quantify the lag time between hydrodynamic action and reservoir bank accumulation landslides and Jong et al. (2013) investigated how vegetation growth relates to climatic factors such as precipitation and temperature using lag time analysis. In the oil and gas sector, lag time between stimulus and response has been used in seismic signal processing interpretation (Kelly, 2012) and monitoring reservoir changes during production (Wikel et al., 2012). The lags in the response of gasoline prices to changes in crude oil prices has been studied by Radchenko (2005). Khalifa et al. (2017) found the impact of changes in oil prices on active rig counts has lag times up to one quarter. Thus, lag time analysis can be used to understand the physics of system to understand how to improve the performance of a system or how to predict the behavior of a system.

Despite prior extensive research on the THAI process in experimental and simulation settings, there has been no studies, as yet, on the lag time between air injection and oil production and the implication with respect to the underlying production mechanisms in the process. An understanding of the production lag time will lead to greater understanding of the relative importance of physical, chemical and fluid flow processes as well as to indicate the strength of underlying production mechanisms. This understanding can lead to options for performance improvement.
2. Kerrobert THAI heavy oil project

REPORT