Worth a Second Look
A paper that JCPT has published in the past that deserves renewed attention.
Prospects for Commercial Bitumen Recovery from the Grosmont Carbonate, Alberta is a ‘legacy’ JCPT article that has been included to provide a background for the discussion of this resource. The authors provide a concise summary of the history, geology, and potential recovery processes. Helpful information is included on both the piloting work conducted approximately 30 years ago and modern interpretation of that work suggesting that the prior and somewhat negative conclusions may have been overcome by subsequent development of gravity-based exploitation processes. Also included is a concise description of the geology containing evidence as to why the vertical permeability required for these gravity-based processes is likely to be present. The geology section also discusses whether the heterogeneous nature of the Grosmont Carbonate makes it too difficult to numerically model, and states this problem has been overcome. This article concludes with discussions of why both steam recovery and cold solvent recovery are theoretically sound.
What follows is a reprint of a JCPT article from 2009.
The correct citation for the paper would be:
Edmunds, N., Barrett, K., and Solanki, S., et al. 2009. Prospects for Commercial Bitumen Recovery from the Grosmont Carbonate, Alberta. J Can Pet Technol 48 (9): 26–32. PETSOC-09-09-26. http://dx.doi.org/10.2118/09-09-26.
PAPER 2008- 154
Prospects for Commercial Bitumen Recovery from the Grosmont Carbonate, Alberta
N. Edmunds, K. Barrett, S. Solanki, M. Cimolai, Laracina Energy Ltd., and A. Wong, Laricina Energy Ltd./University of Calgary
Provenance—Original Petroleum Society manuscript, Prospects for Commercial Bitumen Recovery from the Grosmont Carbonate, Alberta (2008-154), first presented at the 9th Canadian International Petroleum Conference (the 59th Annual Technical Meeting of the Petroleum Society), June 17-19, 2008, in Calgary, Alberta. Abstract submitted for review January 7, 2008; editorial comments sent to the author(s) July 2, 2009; revised manuscript received July 29, 2009; paper approved for pre-press July 29, 2009; final approval August 4, 2009.
The last few years have seen the end of the Athabasca land play and the revival of interest in Alberta’s bitumen resources in carbonate reservoirs. Of these, the Grosmont Formation is the most promising in terms of resource size and concentration. It is also the best known, in terms of having been the subject of several in situ pilots operated in the late ‘70s and early ‘80s.
The data recorded from these early pilots is priceless in terms of having a touchstone of reality for new process concepts. On the other hand, the interpretations written in those days (‘before gravity’) are not necessarily as helpful. This paper looks at the Grosmont in terms of facts and fundamentals, and presents the case for Grosmont exploitation
There is good evidence that the Grosmont has very high bulk permeability as a result of karst porosity development, and fracturing. This bodes well for the use of modern gravity drainage methods in the Grosmont.
Grosmont Piloting History
The Grosmont Formation in north-central Alberta is a dolomitized, karsted and fractured platform carbonate containing a massive bitumen accumulation. An excellent historical summary of various Grosmont pilots was recently provided by Alvarez et al.(1) Cyclic Steam Stimulation (CSS), steam drive and forward combustion were all attempted in the Grosmont during the ‘70s and ‘80s. CSS was the most widely and successfully piloted method. The best well, at 10A-5-88-19W4, recovered about 100,000 bbls of oil over 10 cycles, with a cumulative steam-oil ratio (CSOR) of about 6. Results of other tests were mixed, as were the operating procedures; most of these were based on horizontal flooding concepts. However, responses to well-executed CSS first cycles were reasonably similar at a number of widely-spaced wells. Notably, steam injectivity was generally sufficient so that a few hundred tonnes/day could be injected at pressures that were significantly below overburden pressure (ruling out geomechanical enhancement of permeability).
A degree of pessimism, or at least great caution, has been expressed with respect to the supposed complexity of the reservoir, and hence, prospects for commercial recovery. In particular, it is often said that the reservoir is very heterogenous, and that this explains the historical failure of attempted steam drive and fire flood processes.
Review of the Unocal Buffalo Creek and McLean scheme reports(2, 3) suggests that much of this originates in the interpretations of the contemporary operators, who largely explored conventional EOR concepts involving horizontal displacement. They expected to recover oil by means of horizontal, radial flow. When this failed it was natural to assume that the problem lay in a failure to maintain the ‘radial’ part of the prescription, due to permeability heterogeneity.
Figure 1 presents the performance of the Buffalo Creek 10A-5 CSS test in perspective with a contemporary test, and two modern-day, commercially-optimized CSS wells (the data is publicly available from the Alberta Energy Resources Conservation Board). It can be seen that the Grosmont well had comparable performance to a Clearwater CSS test of the same vintage. The last cycle of the Leming test also suggests the major optimization needed at the time; which was bigger cycles. The latter day Cold Lake well, 2A18, is in essentially the same reservoir as Leming N3. The better performance is almost entirely due to optimized operations. Finally, a Primrose horizontal CSS well is included, which has slightly lighter oil than Cold Lake, but less than ⅓ of the pay thickness. It’s performance is nevertheless comparable to the vertical well.
Figure 1 suggests that technology and execution are just as important as reservoir quality to thermal recovery performance. This should be kept in mind when interpreting historical performances.
The discussion of heterogeneity in the Grosmont largely misses the point in the SAGD age. SAGD is not a displacement process, and is not subject to viscous instability. To extend a favorite metaphor of Dr. Butler’s, a bathtub will still drain promptly and fully, even if it is full of toys. Instead, the major concern for SAGD is the general level and continuity of reservoir permeability. If permeability is high enough (on the order of 1 Darcy), then gas-liquid flows in the reservoir will be gravity dominant.
Gravity dominance means that the rate of gravity segregation (i.e. the relative vertical velocity components) between gases and liquids exceeds any horizontal velocities, so that when both phases are mobile, one or both is moving essentially vertically. Flow direction is no longer determined by horizontal pressure gradients or anisotropy.
As an analogy, the general direction of a diver’s air bubbles in a swimming pool can be predicted by considering only the direction of the dominant forces acting on the bubbles. Any resistance to movement in the horizontal direction is not material, nor are the bubbles effective in pushing much water sideways.
Gravity dominance occurs in high permeability systems; vertical segregation rates go up as permeability increases. There is good evidence of very high permeability in the Grosmont, including vertical, and the resulting strong gravity dominance is a plausible explanation for the observed behaviour of the reservoir during the early pilots. With reference to the swimming pool analogy, just because a lot of steam can be injected does not necessarily mean that much oil will be displaced.
The Grosmont Reservoir
A recent interpretation of Grosmont Reservoir geology in the Saleski area has been provided by Barrett et al.(4) The formation is divided into 4 units, labelled A through D from the bottom up (formerly Lower Grosmont + Upper Grosmont I, II and III). Each unit is separated from the others by marl layers typically a few metres thick. Individual units can be further subdivided into facies or sub-units up to 12 m thick. At Saleski, the oil column includes the C and D units.
Figure 2 is a type log, with gamma ray, dolomite porosity, SP and resistivity. The marl dividing the C and D units is at 346 m. The indicated cutoffs are at 12% porosity and 100 ohm-m.
All of the features described above, and to a large extent the secondary modifications described below, are well correlated on strike (i.e. roughly parallel to the subcrop) for distances of tens of kilometers or more. Figure 3 is a stratigraphic cross-section of the D and C units covering approximately 75 km NW-SE. In the northernmost log at the left, some of D has been eroded. The resistivity logs show features just a few metres thick that can be correlated over this distance.
The Grosmont was originally a limestone marine shelf deposit. Shortly afterward it underwent dolomitization, wherein calcite was converted to CaMg(CO3)2, resulting in a matrix of dolomite crystals with about 10% porosity and milliDarcy permeability. Dolomitization was selective on the smaller calcite grains, and left larger calcite pieces, such as shell pieces, unaltered.
The next event was uplift and exposure of the Grosmont and/or Ireton to the air. This allowed fresh meteoric water to circulate through the porous dolomite. This water, which was weakly acidic from carbon dioxide (which at the time was more concentrated in the atmosphere than current levels), preferentially dissolved the remnant calcite pieces, resulting in centimeter-scale vugs embedded in the matrix. Calcite dissolution went essentially to completion within the C and D units, leaving nearly pure dolomite, some of which has also been dissolved.
Continued dissolution of rock by meteoric water led to the progressive collapse of zones as their porosity exceeded about 40%(4) resulting the breccia (rubble) zones. The most remarkable aspect of these breccia (rubble) zones is that they correlate over such large distances. The processes leading to the final ‘mega-porosity’ observed in the Grosmont all seem to have worked to the same effect on a regional scale; many of them to completion.
Finally, the Grosmont has a very dense concentration of small (10 cm) sub-vertical fractures. These are thought to be the result of stresses induced by local dissolution and/or differential collapse of lower zones. They seem to connect vugs and are often widened by dissolution. Depending on the facies, it is common to observe several fractures in a single cross-section of core.
Figure 4 has photographs of a typical extracted core, and Figure 5 shows some density cross-sections of various facies taken by X-ray tomography.
To summarize, the Grosmont porosity system appears to be dauntingly complex at core-scale, ranging more or less continuously from micron-scale matrix pores to cm-scale vugs and fractures, and consisting, in part, of rubble zones that are the embodiment of heterogeneity. On the other hand, cores from wells that are far apart but in the same facies are very similar. The deposition and subsequent modifications that produced such a complex pore system seem to have all operated to a remarkably uniform degree, over thousands of square kilometers. Heterogeneity, therefore, is a question of scale.
The Grosmont was reburied during the Cretaceous and eventually charged with 50 m or more of oil. The oil was subsequently degraded to bitumen through the action of continued meteroic water circulation. The bitumen is found to be within the range of properties of the bitumen found in the McMurray Formation.
Average porosity of individual subunits ranges from about 5 to 40%. The average porosity of the combined C and D gross pay interval (e.g. the steamed interval) is about 20%. There is excellent agreement between core and log-derived porosity. From tomographic studies, it is estimated that about half of the total porosity is greater than ~0.5 mm (pore diameter or fracture width). Studies are ongoing to further quantify the distribution.
As with many carbonates, the Grosmont is oil-wet. Log resistivities typically range from 100 to >2000 ohm-m. Bitumen appears to fully saturate the clean dolomite matrix; what little water there is probably occurs in muddier facies or clasts, and perhaps as droplets within the oil in larger pores. Average oil saturation is estimated at 85-90% based on Dean-Stark analysis. There is uncertainty as some fluid is typically lost from vugs before the cores can be frozen. This appears to be mostly oil, which sometimes pools in the bottom of the core boxes. The situation is further ‘muddied’ by massive drilling fluid losses that typically occur while penetrating the Grosmont.
Evidence for High Permeability
Core matrix permeabilities are typically around 100 mD. Only the more competent samples can be measured. Many zones are recovered as rubble or else disintegrate when the oil is removed. Even where voids are present, their full path (if any) through the rock appears to be tortuous on a scale somewhat greater than core diameter.
The potential implications of cm-scale vugs and dense fractures can be appreciated by calculating equivalent permeabilities for specified density and size of idealized geometries; namely tubes and planar fractures. In the first case, if we equate Poiselle’s relation for (laminar) flow in a tube of diameter d to Darcy’s law, the permeability due to N tubes per unit area is:
For a single, 1 cm diameter tube per square meter, this works out to be equivalent to 245 Darcys (1D ≈ 10-12m2).
Similar results can be derived for model fractures, but in either case these features are small in length, and their overall contribution to bulk permeability depends on how well, and in what directions, they are connected together. Tomography has given some clues, but it too is ultimately limited by core size.
Better estimates of bulk effective permeabilites are those based on observed field injectivity of significant volumes of fluids, and associated interference monitoring.
An operator’s first indication of Grosmont permeability is, typically, loss of circulation upon penetrating the Grosmont, which at Saleski (T85-R19W4M) has an initial pressure less than ⅓ hydrostatic. This occurs consistently and in the absence of mobile water or gas.
Injectivity data for the first cycles of several Grosmont CSS wells are available from the Unocal reports(5). Most wells accepted 150-250 m3/d or more of steam, at pressures well below the overburden stress; the completed intervals were about 10 m. Injectivity typically increased with time; 10,000 bbl (1600 m3) slugs could be injected over a few weeks at declining pressures. Production response was qualitatively indistinguishable from typical CSS wells in the Clearwater.
Extensive history matching studies have been conducted of the first 5 cycles of Unocal 10A-5-88-19W4, some of which were reported by Novak et al.(5), in order to put realistic bounds on Grosmont bulk permeabilites. Large uncertainties remain in terms of pore compressibility for such a system, but updated conclusions from this work are:
- the minimum formation bulk permeability is comparable to the best Cretaceous sands, i.e., on the order of 10 D. However, this requires use of an improbably high pore compressibility;
- using a more probable value for Cr, permeabilities in the range of 100’s of Darcys are needed to match steam injectivity; and
- field behaviour is best explained when vertical permeability exceeds horizontal.
The simple calculation above provides support for extreme permeability in the Grosmont. In hindsight the last conclusion is also reasonable, considering the observed high density of sub-vertical fractures, and the largely vertical passage that meteoric water would have taken through the rock, seeking and widening the most direct (i.e. vertical) pathways from the surface to the water table.
Heterogeneity, Scale and EOR Engineering
The secondary porosity in the Grosmont raises the question of whether a dual-porosity modelling approach is required. Such a formulation, which accounts separately for conditions in the fractures versus the matrix rock, is required if there is significant time lag between these two domains. This depends on both the spacing between fractures and what kind of diffusion controls the time lag.
For example, in conventional reservoirs, dual-porosity modelling is needed when the pressure diffusivity in the matrix is small relative to the fracture spacing and the rate at which the fracture pressure can be drawn down.
In the case of steam injection, the lag is between temperatures, and is controlled by thermal conduction. The equilibration time is controlled by thermal diffusivities, which are relatively high compared to practical steam injection rates, and are insensitive to porosity/permeability. It can be shown that, for any practical rate of steam injection, fractures would have to be at least several metres apart before matrix temperatures would significantly lag behind steam temperature in the fractures.
For SAGD modelling, metre-scale grid blocks are required to resolve the drainage front. In other words, the blocks are too small in the first place for further refinement to make any difference (on the other hand, the grid is fine enough to explicitly model heterogeneity on any scale that matters).
A conventional single porosity formulation has been successfully used for history matching of field and core tests(5). A primary focus is the quantitative characterization of the pore size distribution. This is more or less continuous over a range from less than a micron to more than a centimeter.
From a pore size distribution, synthetic relative permeability and appropriate capillary pressure functions can be estimated for the bulk system. This will help to constrain the history matching process and therefore improve our predictive capability.
The first consideration for economic steam recovery is the ratio of moveable oil within the reservoir, relative to the rock and water that must also be heated. Table 1 compares values of the factor (fDSo) for typical McMurray vs. Grosmont properties. Mostly because of the lower porosity of the carbonate, the Grosmont requires about 50% more steam per volume of oil drained than the McMurray.
The above term only accounts for heat in the reservoir, however. In a typical McMurray SAGD application, the same amount of heat, or more, will be lost to confining strata. That is, if a McMurray SAGD project has a Cumulative Steam-Oil Ratio (CSOR) of 2.5, about 1.5 of that will be heat lost outside the reservoir. This amount is inversely proportional to the reservoir thickness. Therefore, other things being equal, the amount of heat lost from the reservoir (per unit of oil) will be smaller for the Grosmont than the McMurray, because the Grosmont is a thicker reservoir.
The final consideration for CSOR prediction is the lifetime of the pattern(6). Based on our above interpretation of Grosmont permeabilities, the lifetime of a Grosmont SAGD pattern is not expected to differ significantly from typical McMurray applications.
When porosity, permeability and thickness are all considered together, it is expected that SAGD performance in the Grosmont will be comparable to that in high-quality McMurray reservoirs.
In the majority of cases, the regional marl between the Grosmont C and D zones does not appear to be a flow barrier(3). If the marl is a local barrier, however, it would only be a barrier to flow and not heat conduction. In other words, heat lost from the top of the C will end up in the D, as heat lost from the bottom of the D would end up mostly in the C. If both zones are steamed simultaneously, the marl will absorb a small amount of heat in proportion to its thickness, after which losses from the top of the C and bottom of the D will effectively cease, as if the marl was a perfect insulator.
Therefore, the combined steam-oil ratio obtained by simultaneous development of a separate C and D is expected to be about the same as if the C and D were a single, contiguous reservoir of the combined thickness.
Wettability within carbonates can display a degree of heterogeneity, although the Grosmont is believed to be more dominantly oil-wet. Water saturations from core analysis occasionally measure below 5 percent, with higher values most often reflecting bound water within associated clays and marlstones.
Water imbibition in the rock matrix can be a significant drive mechanism for oil recovery in fractured carbonates, but would be largely impeded in the dominantly oil-wet, bitumen-saturated Grosmont. However, thermal operations have been reported to induce a favourable wettability alteration in oil-wet carbonates(7-9), where steam acts to both lower viscosity and reverse wettability to a water-wet state. With the shift to water wetness at steam temperature, steam condensate can preferentially imbibe into the pore framework, displacing oil into the higher permeability vug/fracture network within the formation.
In a laboratory test, steam was circulated around a vertically suspended 1 metre length of Grosmont core, with the bottom 15 cm partially immersed in water. CT imaging of the core at 1 cm intervals was taken before and after steaming, yielding a density mapping across the scan face, to which the density difference provides a measure of bitumen mobilization within the test conditions. The results in Figure 7, revealed a bimodal distribution in the density reduction through the core length. The bottom water-immersed section (dataset shown as red squares) displayed an increased density change or movement of bitumen from the core, as subsequently confirmed by Dean-Stark analysis. This preliminary indication of an imbibition drive mechanism to steaming operations within the Grosmont suggests a high recovery factor may be achieved both within the rock matrix and the open fracture system.
It was also determined that bitumen mobilization occurred at all scales within the Grosmont core. Figure 6 illustrates the initial and post steaming density scan within a Grosmont breccia section, where a density reduction can be seen within the suspended matrix clasts, the dolomite grainstone and the open fracture system (a lightening of the color distribution, or density, throughout the post-steaming scan). The mobilization of bitumen throughout the rock framework demonstrates the pervasive impact of steaming the Grosmont.
Cold Solvent Recovery
The highly developed, finely disseminated secondary porosity in the Grosmont suggested a unique possibility for recovery by injecting a suitable cold solvent. Within the fractures and vugs, convective transport should be easy and rapid. About half of the oil in place occurs in the secondary porosity, which will have negligible residual saturations. It therefore seems likely that this much oil will be readily recoverable, and in a non-thermal context, that is enough to be economically viable.
In the matrix porosity (the other half of the resource), molecular diffusion will control solvent transport. Inspection of core suggests that such diffusion need only span distances of centimeters between the larger porosity; over this distance only a week or so is required to substantially saturate the matrix bitumen. Bitumen in the matrix will therefore absorb solvent rapidly and swell, forcing much of it into the secondary network from where it can be drained and recovered.
Stage-gated development of this technology is being pursued at Saleski. Positive results at each stage have given confidence for increased investment at the next stage, some of which are highlighted in the following sections.
The advantages of addressing a large bitumen resource without the use of steam are fairly obvious, but bear re-stating:
- Based on work to date, operating cost (primarily for the net solvent retained in the reservoir) is expected to be about half that for steam.
- The entire water/steam plant, and its extensive supporting infrastructure, are replaced by a modest compression facility.
- The field piping can be buried in the conventional manner, without piles, expansion loops, insulation or freeze protection.
- No source water is required, and the long-term producing water-oil ratio will probably be around 10%.
- Carbon emissions from the operation would be negligible on a “well-to-wheels” basis.
- Work so far suggests the ultimate recovery factor will be comparable with that for SAGD, i.e., exceeding 50%.
- Depending on the chosen configuration, individual well productivity may approach levels typical of SAGD or CSS wells.
Any of the first three points alone would imply a significant cost advantage over steam. The combined effect of all of these on resource NPV is a multiple of 2 or more. The advantage over SAGD increases when margins are lower.
Laboratory Core Soak
In 2007, the University of Calgary’s Tomographic Imaging and Porous Media (TIPM) laboratory conducted an experiment with Grosmont core to demonstrate recovery using a cold solvent mixture. An 80 cm length of preserved core was supported inside a holder in such a way that fluids could flow freely around the core. In other words, no pressure gradient was applied, so that diffusion, swelling and gravity were the only mechanisms available to recover the oil.
The test was run at reservoir initial temperature and pressure. A non-condensable carrier gas was saturated with propane to the dew-point. The saturated gas flowed into the top of the core holder and circulated out the bottom, along with produced bitumen. X-ray tomography was taken before and after the test to visualize the depleted zones.
Figure 8 is a plot of the test production. Of the bitumen initially present in the recovered core, 54% was recovered after 10 days. The first half of this volume was recovered in the first 60 hours. When corrected for bitumen that was lost during core recovery, the overall recovery from this test exceeded 60% OOIP.
Little deasphalting was observed, although the test conditions were expected to promote this, especially in the matrix. Produced oil gravity increased by about 1°API, and the gravity of the residual oil in the core decreased by about the same.
In addition to a direct demonstration of cold solvent potential, the test also provided data on the uptake, and therefore diffusion rate, of propane into the core.
Saleski Winter Solvent Test
In the winter of 2007-2008, a single-well cold solvent injection test was conducted at 2-26-85-19W4. The principal objective was to test and refine our reservoir model, especially with respect to bulk permeabilities and communication through the marl. This was done by measuring the pressure response during and after injection of small volumes of solvent and gas.
Pressure data was collected with a quartz bottomhole gauge, and also a piezometer located on the outside of the casing. The well was perforated low in the C zone, and the piezometer was located in the D zone, above. The well was equipped with a conventional progressing cavity pump.
Two slugs were injected during the 3-week operation, each followed by a production period. The second cycle was truncated by spring breakup after about 5 days of production.
Figure 9 is a photo of an untreated wellhead sample that had a small amount of dissolved propane. If the propane is allowed to ‘flash’ from bitumen that is not heated or diluted, the bitumen reaches high viscosities as the solvent leaves. This is enhanced by the refrigerant effect of evaporating propane, and the result is a strong foaming tendency, as shown. A skid was used to remove produced propane from the production so that bitumen could be safely handled and the propane sent to flare.
At this time, analysis of the results continues, but some early conclusions can be drawn:
- Injectivity was close to design values, which were based on the reservoir model resulting from a history match of a historical CSS test.
- As oil appears to be the only mobile phase present, the only way to explain the observed injectivity of solvent (or steam) is to assume permeabilities on the order of 100 Darcys.
- Certain observations from both this test and Buffalo Creek, strongly indicate that the vertical permeability is about 5 times greater than the horizontal.
- Oil was mobilized and produced in bulk. Production was modest but limited by the small amount of solvent used, which resulted in higher-than-ideal bottomhole viscosity.
- From this test, we can extrapolate that commercial production rates, especially from a horizontal well, are achievable with non-thermal methods at Saleski.
- No problems with solids or asphaltenes were encountered.
- Some water was produced, but the cumulative amount was a small fraction of the fluid lost while drilling the well.
The Next Stages
Ongoing and supporting each stage, we are developing and validating a predictive numerical modelling capability. As is the case with steam, so far, we believe a single porosity model is adequate because of the extraordinary density and connectivity of the secondary porosity. The work described above, in parallel with apparent success in the use of simulation to reproduce experiments at core- and field-scale, has given confidence in further investment at larger scale. At this stage, cold solvent looks like a credible challenger to SAGD as the primary commercial technology for Saleski.
Another, larger solvent slug was injected at 2-26 in the winter of 2008-2009. The primary objective would be to demonstrate production parameters reasonably in line with predictions. That, in turn, would justify a full pilot, i.e., one including solvent recycle facilities. For commercial application, we are studying a number of configurations which include both vertical and horizontal wells, in addition to cyclic stimulation versus continuous injection of solvent. A solvent pilot would proceed in parallel to the Saleski steam pilot (for which application has already been made).
An extensive geological and engineering review of historical and current data has revealed an alternative picture of bitumen recovery from the Grosmont; one of:
- a massive resource, having facies units correlatable over distances on the order of 100 km;
- excellent to extraordinary bulk permeability as result of rock that is densely fractured and vugular;
- cm-scale access to the matrix porosity, via the above;
- vertical permeability that exceeds horizontal;
- an attractive combination of porosity, oil saturation and thickness for steam recovery; and
- a unique opportunity for large-scale, low-cost recovery of bitumen by non-thermal solvent technology.
The authors wish to thank Laricina Energy Ltd. for the opportunity to prepare and present this paper. Many others have contributed to the ideas and data presented here, including: Dr. John Hopkins, University of Calgary; Dr. Apostolos Kantzas, TIPM Laboratory at the University of Calgary; and Dr. An Mai, Rick Shenton, Gord Rouse and Derek Keller, who are all Laricina staff.
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2. UNION OIL COMPANY, Buffalo Creek Scheme Progress Reports ER 81-17, 81-38, and 82-08; Alberta Energy Resources Conservation Board (ERCB) Approval #2367c, Calgary, AB, 1981-82.
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Neil Edmunds is Vice President EOR for Laricina Energy Ltd., in Calgary. Mr. Edmunds has over 30 years in the oil and oil sands industry focused primarily on thermal recovery of heavy oil. He has held positions with AOSTRA, CS Resources and EnCana Corp., working respectively on the UTF Phase A&B, Senlac and Foster Creek SAGD and Vapex projects. In 2008, he was appointed Adjunct Associate Professor at the Schulich School of Engineering, University of Calgary. Neil holds a Bachelor of Science in mechanical engineering from the University of Alberta. He is a member of the Canadian Heavy Oil Association, the Petroleum Society and the Association of Professional Engineers, Geologists and Geophysicists of Alberta (APEGGA).
Kent Barrett is a carbonate geology specialist focused on understanding and expanding Laricina’s bitumen resource in Paleozoic strata. Kent has 30 years of industry experience in Western Canada working for various large, midsized and small E&P companies. Most of his experience has been devoted to developing exploration models and exploring for oil and gas in the Devonian of the Western Canadian Sedimentary Basin. Kent has a M.Sc. in geology from the University of Manitoba and is a member of APEGGA, the Canadian Society of Petroleum Geologists and the American Association of Petroleum Geologists.
Sandeep C. Solanki is currently the Asset Manager for Laricina Energy Ltd. Mr. Solanki brings a strong technical background of over 20 years in the oil and oil sands industry. Prior to his current position with Laricina, Mr. Solanki was Coordinator of Special Project SAGD with EnCana’s Oil Recovery BU from 2001 to 2007, where he provided reservoir and operations direction for SAGD operations for EnCana’s Senlac, Christina Lake and Foster Creek projects. He led implementation and development of new pumping methods for SAGD wells. Just before leaving EnCana, he led the reservoir teams for the Senlac Pilot and the Borealis Development. He was lead for EnCana’s technical solution to Gas-Over-Bitumen and coordinated field implementation at Christina Lake. Prior to EnCana, Mr Solanki was a Senior Engineer at C-FER Technologies, where he led projects for pump (ESP’s) reliability and downhole oil/water separation systems. He holds two patents and has co-authored numerous papers on technologies related oil sands and oil recovery. Mr. Solanki holds Masters and Bachelor of Science degrees in civil engineering from the University of Alberta. He is a well-respected researcher, author and presenter of the many issues, challenges and technological advancements for heavy oil and bitumen recovery. Mr. Solanki is a member of the Canadian Heavy Oil Association, the Society of Petroleum Engineers and the Association of Professional Engineers, Geologists and Geophysicists of Alberta.
Mauro Cimolai is a Technical Advisor with Laricina Energy Ltd., involved with reservoir characterization and the development of exploitation strategies within Laricina’s bitumen recovery projects.. Mauro’s career covers 28 years in the industry, previously with Core Laboratories as Vice-President, Reservoir Characterization and Modeling, and working with several producing companies, including 10 years focused within the Alberta Deep Basin at Canadian Hunter Exploration. Mauro’s career interests have centered on subsurface reservoir evaluation and numerical simulation.
Angie Wong received a Bachelor of Science in chemical engineering with distinction from the University of Calgary in 2009. She worked as a reservoir engineer internship student for Laricina Energy Ltd. Currently, she works as an Engineer-in-Training at Laricina Energy Ltd. and her work focuses on reservoir simulation of new and existing recovery technologies.