Applying the Albertan Experience to Biodegraded Petroleum Systems around the World!

A detailed knowledge of the distribution of fluids in reservoirs containing conventional and biodegraded heavy oil such as those found in Alberta is essential for the pre-drill prediction of oil quality in exploration plays and for the development of efficient recovery strategies. Through our successful experience in the Alberta basin, at Gushor Inc. we have developed advanced strategies to provide accurate physical and chemical property measurements on fluids residing in petroleum reservoirs. We have also developed methods for monitoring the progress of natural or thermal recovery processes, which can be quickly adapted to analogous accumulations around the world.

But, why is the Alberta basin the perfect laboratory? Most of the world’s heavy oil reserves are accumulated towards the flanks of foreland basins in North and South America.  The Alberta basin in Canada and the Orinoco heavy oil belt in Venezuela are the largest single deposits of biodegraded oil in the world. The Alberta basin is an ideal example of a natural suite of sequentially biodegraded oils, hosting conventional oils through to severely biodegraded heavy oil and bitumen. The heavy oil and bitumen deposits were formed from conventional oils that migrated to the flank of the foreland basin, suffering biological alteration in place and possibly during migration. The range encountered in oil physical properties and chemical compositions have been largely introduced by varying degrees of biodegradation across the Alberta basin. The regional trend of improving oil quality from northeast to southwest is related to the increase in reservoir temperature as the basin deepens, such that west of the Peace River oil sands, reservoirs were exposed to temperatures in excess of 80 ºC which represents the temperature limit for biodegradation i.e. the reservoirs have been pasteurized. The oil compositional gradients and biodegradation trends within individual oil columns, meanwhile, can be explained by variable proximity of oil to the water leg, the height of the water leg, charge mixing between fresh oil and paleobiodegraded oils, biodegradation rate and varying reservoir rock properties. The good news is that the variations in oil quality commonly encountered in biodegraded petroleum systems are predictable!!!

The methodologies we have developed and proved in Alberta are currently being successfully applied to analogous case studies, such as the Colombian Llanos Basin. The Llanos basin, as the Alberta basin, is also a foreland-type sedimentary basin. The burial history of the Llanos basin varies from west to east. Several potential petroleum source rocks have been identified in the Llanos basin and therefore several oil expulsion events or continuous oil charge with progressive maturity levels can be expected. Biodegradation took place when the reservoir temperature was below 80°C, although currently, several reservoirs in the area exceed that temperature. Multiple oil charges have been documented and the indicators of severe biodegradation (e.g. presence of 25-norhopanes and 25-nortricyclic terpanes) are evident in the oils molecular composition. In this scenario, the final viscosity of the oil residing in the reservoirs is mainly controlled by the relative interplay of biodegradation along with mixing of multiple oil charges. High quality quantitative analysis of oil composition, numerical modeling of biodegradation and most importantly our “know-how” are some of the tools that we utilize at Gushor to predict fluid properties and distribution of oil quality, de-convolute oil mixtures, allocate production, and monitor thermal recovery operations for heavy oil and bitumen accumulations, among other applications for the characterization of biodegraded petroleum systems.

If you have any questions or wish to discuss further please contact Gushor at or (403) 457-4874.

Author: Dr. Norka Marcano, Sr. Project Manager – Gushor Inc.


Posted in Bitumen, Geochemistry, Heavy Crude Oil, Heavy Oil, Oil Sands, Research and Development | Tagged , , , , , , , , , , , , , , , , , | Leave a comment

Everything You Wanted to Know About Viscosity (but were afraid to ask)!

Decades of research on the topic of crude oil biodegradation revealed that successively increasing levels of alteration recorded amongst the hydrocarbon components in crude oils is often accompanied by the deterioration in physical properties such as viscosity. However, when correlations were attempted on large viscosity and geochemical data sets the final results proved largely disappointing. After all correlations should exist, since biodegradation produces increasingly viscous oils with increasingly altered hydrocarbon compositions! During March 2008, Gushor revolutionized the analytical protocols, from sample collection, shipping, handling and laboratory processing that provides us with the opportunity to acquire highly reproducible and accurate concentration data for individual hydrocarbons.  In addition, data generated since March 2008 is consistent with the data that is generated today, paving the way for many applications that require consistent data sets over periods of many years. Today’s geoscientists are benefitting from highly accurate quantitative data that is well inside the 5% errors on a suite of target compounds.

Meanwhile, considering the issues surrounding viscosity measurements, Miller et al. (2006) called for the introduction of standardized procedures such as an ASTM method to qualify the viscosity measurements. Researchers at the University of Calgary, concerned by the errors in viscosity data measured on oil samples recovered from oil sand cores, came up with the idea of literally squeezing oil out of rocks! The plunger was invented which led in 2006 to the birth of Gushor Inc, a service and research company demonstrates the successful transfer of technology out of the University of Calgary and into the corporate world.

Today Gushor Inc. has recognized many of the issues that were contributing errors to the viscosity measurement and has provided numerous solutions which are documented in peer reviewed journals, have been presented at major national and international conferences, and disclosed in several patents.  This document serves to provide you with the information to select the best route to the most accurate viscosity data that can be obtained on oils recovered from core samples. Indeed, accurate viscosity data is critical in determining thermal vs. cold production and the costs associated with the wells development plan.

The methods typically employed for the recovery of oil from core samples are based either on chemical extraction or mechanical extraction. Here we present a critique on the methods and also recommend the best practice to truly define the oil properties in your reservoir.

1)    Chemical Extraction methods:

 a)   Froth Flotation (The Clark process)

Froth flotation involves mixing oil sand with water at an elevated temperature (40-60 ºC) in a bubble bath! The combination of elevated temperatures, an open system and bubbling air through the system leads to the recovery of a froth that is enriched in bitumen, but depleted in volatile compounds and also contains water (typically 50%) plus residual solids, all of which are detrimental to the accuracy and precision of the final viscosity measurement.

b)   Mineral dissolution and froth flotation (applicable to carbonates)

The potential issues are as above, plus chemical alteration due to the interaction of hydrochloric acid with bitumen components e.g. hydrochloric acid interaction with basic nitrogen compounds form salts rendering their solubility in water, hence the compounds will be removed from the oil.

c)   Solvent extraction (Dean & Stark)

Although all of the oil in the core is recovered using solvent extraction, there are significant problems with solvent removal and this is exacerbated with higher viscosity oils:

                i.          Toluene removal from heavy, viscous oils can be very difficult, requiring up to several hours on a rotary evaporator. Incomplete solvent removal results in lower than true viscosities with as little as a few percent residual solvent changing the viscosity by more than a factor of two (compare data from pre-1985, when mechanical extraction was introduced).

              ii.          Conversely, completely removing solvent (the boiling point of toluene is 110 ºC) also removes volatile liquid components from the oil resulting in higher than expected viscosity data. The oil sample is damaged!  The measured viscosity is higher than the true viscosity.

             iii.          Due diligence experiments carried out by Gushor showed that there was no inflection or other way to detect when the solvent was more or less completely removed and even after the sample had been damaged and the viscosity had increased beyond the nominal, known value, there was still residual toluene that was detectable in the samples.

Interestingly, a number of researchers highlight the problems of measuring viscosity associated with solvent extraction, whereas the viscosity experts at Gushor have the solutions that have been published in peer a reviewed journal (Jiang et al., 2010).


We are able to recommend chemical extraction methods that work!

  • GViscTM – solvent based extrapolation (also see gAPI)
  • ProxViscTM – requires a calibration data set built on fresh samples



GViscTM is a solvent hybrid technology whereby the amount of solvent added to a bitumen or heavy oil extract from core is accurately determined. The viscosity of the mixed solvent – heavy oil (or bitumen) is determined with different solvent contents and the resulting viscosity versus solvent content curve is extrapolated to zero solvent content where the viscosity is given. GViscTM may be applied to core samples with low bitumen contents (e.g. transition zones near the base of the water line) and/or cuttings samples.

In Figure 1, where both GViscTM and plunger viscosities were measured on samples representing the oil column, the data are highly comparable. However, plunging the samples from the transition zone yielded only water. The GViscTM technology is able to work with oil lean samples and shows that the viscosity trend continues to increase down through the transition zone. The increasing trend in viscosity is also supported by the changes in hydrocarbon composition (not shown).

   Viscosity Graph - Figure 1   

Figure 1. Plot of viscosity obtained by GViscTM and plunger versus depth (m) in a Peace River oil sands well.


ProxViscTM is a viscosity prediction method based on correlations established between viscosity and geochemical data that is compiled on fresh core samples. Once the correlations have been established, the geochemical data may be generated on small samples of old stored cores, oil lean cores, cuttings samples and contaminated cores. Figure 2 shows the viscosity profiles obtained from the plunger (measured) and the predicted viscosity using ProxViscTM are closely aligned. Where core samples (or cuttings) are contaminated by drilling mud additives (e.g. base oil), only specific components indigenous to the oil/bitumen are selected for ProxViscTM thereby avoiding the contamination.

In the event that a ProxViscTM model has been established in one well location, fluid property information may be obtained on cuttings samples from vertical and horizontal wells, therefore coring is not always necessary thereby reducing costs for reservoir evaluation.

 Viscosity Graph - Figure 2

Figure 2. Plot of plunger and ProxViscTM predicted viscosity profiles versus depth (m) in the Peace River Oil Sands.

2)  Mechanical extraction methods:


a)   Centrifugation (Wallace et al., 1984)

Centrifugation is carried out under a partial vacuum which inevitably promotes the loss of light ends. The variable length of “spin” times according to the viscosity of the oil/bitumen and the grain size distribution of the reservoir rock control the required spin time. The very high pressure extraction system also mobilizes water/oil/solids material into a single collection vessel. Therefore there is inevitably some clean–up required to recover the oil sample. Any laboratory handling promotes the loss of light ends further compromising the resulting viscosity data. Incidentally, in the case that the oil residing in the core is super viscous the oil may remain immobile even after prolonged centrifugation.

Due to these issues we don’t use centrifugation (see Adams et al., 2008).

b)   Gushor mechanical extraction (PlungerTM)

The Plunger method was developed in response to the poor correlations observed between viscosity and geochemical data. After all, biodegradation produces increasingly viscous oils with increasingly altered hydrocarbon compositions; therefore correlations should exist between viscosity and hydrocarbon data!

In general, the Plunger leads to the recovery of 10 g bitumen from 200 g of oil sands core (or cuttings) by mechanical displacement without the use of solvent. The recovered oil passes through a filter system leading to oil/bitumen with negligible fines and low water (1-6%) content. The viscosity range of the fluids recovered from plunging range from <1kcP to 10s McP (measured at 20 °C, close to typical reservoir temperatures). The plunger may be deployed at rig site, enabling viscosity measurements to be conducted on core samples retrieved as the core is brought to the surface. The field viscosity logging program allows the recovery of oil from fresh core with the volatile liquid components that are usually lost during shipping and storage.  Oil can be recovered and viscosity measured before the petrophysical logging runs are completed.

The Plunger operates under a sealed system allowing the oil sample to be collected in a PVT bottle. In the event that a pressurized core could be loaded into the Plunger, then a live (gas containing) oil may be recovered.

In addition, multiple plunging runs can be made to ultimately collect large volumes of oil for PVT and/or assay analysis. The versatile nature of the Plunger afford the recovery of bitumen from carbonates such as the Grosmont Formation in Alberta and also the Middle East demonstrating that oil may be recovered from rock material.

In the event, that the core samples are obtained from transition zones or oil lean intervals, the produced water may be submitted for water chemistry and stable isotopes analysis to determine the properties of formation water.

Since the introduction of the Plunger, we now see very strong correlations between viscosity and geochemical data (R2 = 0.99) that paves the way for applications such as ProxViscTM. Correlations established between reliable viscosity (Plunger recovered oils) versus accurate hydrocarbon concentration (and fingerprints) data (Fig. 3) contribute to the ultimate viscosity prediction model – ProxViscTM.

Viscosity Graph - Figure 3 

Figure 3. Plot of measured viscosity versus predicted viscosity based on Partial Least Squares treatment of the hydrocarbon concentration data and viscosity.


3) Plunger versus centrifugation

Due to the errors associated with viscosity data an alternative extraction method had to be found to test the efficacy of centrifugation. The Plunger method was launched in 2006 with impressive results. The issues surrounding viscosity measurements on oils recovered from core samples and the solutions have been documented in Adams et al. (2008).

Figure 4 shows the hydrocarbon data obtained during solvent extraction, centrifugation (spun oil) and Plunger recovery of oil from core samples. The compositions are very consistent between the methods indicating the lack of fractionation amongst the aromatic hydrocarbon compounds using the different recovery systems.

Geochem- Figure 4 

Figure 4. Partial reconstructed mass chromatograms representing C1-C5 alkylnaphthalenes and C0-C1-alkyldibenzothiophenes (m/z 142, 156, 170, 184 and 198) and C0-C2-alkylphenanthrenes (m/z 178, 192 and 206) following GC-MS analysis of total hydrocarbon fractions isolated from solvent extract, spun oil and plunged oil.

The composition of the medium volatile compounds appears to show no difference between the centrifuged oils versus the plunged oils (Fig. 4); however we have observed a significant discrepancy between the viscosities of the recovered oils. In Table 1, the viscosity data are compared between the centrifuged oils versus the plunged oils. The core samples were selected and the oils recovered from the core using centrifugation and plunger at the same time, such that the viscosity data were obtained within 48 hours i.e. a direct comparison. In all cases the viscosity of the centrifuged oils were higher than the Plunger recovered oils, perhaps reflecting the higher water content and solids material in the centrifuged oil, while loss of volatile liquid components e.g. alkylmethylcyclohexanes (Fig. 5) is promoted under the conditions of a partial vacuum in the centrifuge contributing to increased viscosities.

Table 1. Dead oil viscosity data, water content (wt%) determined by Karl Fischer (KF) analysis and sediment fines content (wt% by ASTM D-473) for the oils recovered from Peace River oils sands cores by mechanical extraction using the plunger and centrifugation methods.  

Viscosity Chart - Table 1 

Viscosity difference between plunged and centrifuged oils indicated in parentheses with viscosity measurements at 20 °C; n.m. = not measured (due to lack of oil recovery). * = measured at 25.5 °C.

 Geochem- Figure 5

Figure 5. Partial reconstructed m/z 97 mass chromatograms following GC-MS analysis of oils recovered by centrifugation (spun) and plunger processing.

One of the concerns that has often been raised by researchers and plunger skeptics is “Does the Plunger recovery cause fractionation of the oil?” The Plunger configuration has allowed us to test the potential influence of fractionation as a function of oil production since we are able to collect aliquots of oil as the Plunger process is in progress. It is not clear that this test has ever been investigated during the centrifuge process. Figure 6 shows the viscosity data for a suite of oil samples collected as separate aliquots during plunging. The viscosity data are consistent from the 1st aliquot through to the 6th aliquot. In addition, the viscosity falls close to the original measured data and the viscosity of the average of the summed aliquots.  Furthermore, Gushor Inc. has carried out experiments to demonstrate that the residual core sample after the plunging process has been complete is chemically identical (by GC-MS and SARA analysis) to the oil that was recovered.

Viscosity Graph - Figure 6 

Figure 6. Plot showing the viscosity associated with produced oils collected from the plunger as a function of time, compared to the viscosity of the original full volume collected sample and the average from the sum of the aliquots.

4)  Viscosity bullet points

 Controls on dead oil viscosity measurement from core:

  1. Storage and handling of core/oil 
  2. Oil extraction method (spin or plunge or solvent)
  3. “Contamination” of the extracted oil with water and rock matrix material (increase viscosity by factor of 2 to 3)
  4. Machine error + Type of viscometer + Technician measurement error + non-Newtonian fluid effects (±20% error)
  5. Extrapolation of measured intermediate temperature (e.g. 40-50-60 ºC) viscosity data to reservoir temperatures (e.g. 20 ºC) has been known to underestimate bitumen viscosity by up to an order of magnitude.

 Representative samples require consistent sample handling & viscosity measurement!  We have met the challenges and to date we continue to provide the oil industry with the most accurate viscosity data available. In addition, the Plunger recovered oils provide viscosities that are comparable to produced oil viscosities, indicating that Plunger recovered oils provide the ultimate guide to indicate the likely recovery strategy i.e. when risking cold versus thermal production

If you have any questions or wish to discuss further please contact Gushor at or (403) 457-4874.

Author: Dr. Barry Bennett – Director of Geoscience Technology – Gushor Inc.


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Viscosity & Geochemical QA/QC

Do You Take Oil Viscosity and Geochemical Data QA/QC Seriously?  We Certainly Do!

Viscosity Measurements

We employ a highly diligent approach for measuring the viscosity of heavy oils and bitumen. Here we use a suite of standard fluids (at 25 ºC), not only to determine that the instruments are operational, but to indicate that the measurement parameters are optimized to the viscosity range of the samples we plan to measure. For example, when making viscosity measurements on the bitumen recovered from the Grosmont Formation carbonates, we include standard fluids with viscosities of 1.641 and 5.151 McP. However, in the event that we are measuring the viscosity of plunger recovered oils from the Peace River Oils sand (PROS) cores; we use “lower viscosity” fluid standards (see Table 1). Also, within a reservoir, fluids sometimes provide somewhat unexpected viscosities, e.g. in the PROS the viscosity of a bitumen extracted using the plunger may vary from thousands to millions of centipoises (at 20 ºC), so the decision regarding selecting the most suitable viscosity standards may be revised during the project.  Since the paper on “Should you trust your heavy oil viscosity measurement?” appeared in the Journal of Canadian Petroleum Technology (Miller et al., 2006) – we have worked hard to produce the best and most accurate viscosity data for you (see Adams et al., 2008. Viscosity determination of heavy oil and bitumen. Cautions and solutions. Paper 2008-443 World Heavy Oil Conference Edmonton 2008).

The viscosity measurements are often supported by geochemical analysis, whereby the hydrocarbon composition of the heavy oil or bitumen sample is determined through GCMS analysis. In general, in the biodegraded oilfields of Alberta we often observe trends in the relationship between oil viscosity and hydrocarbon composition i.e. high viscosity oils tend to show highly altered hydrocarbon compositions, while the converse applies to low viscosity oils.

Quantitative petroleum geochemistry (Q2-comp)

Petroleum geochemical analysis requires consistent methods for handling, processing and recovering fractions to ensure data consistency between oils, core extracts and drilling cuttings samples. There is also a necessity that data is reproduced consistently over periods of several years representing the lifetime of a resource recovery program. Since we made a breakthrough in our analytical procedure many years ago, we have been able to relate today’s hydrocarbon composition data with the benchmark data sets based on viscosity and hydrocarbon quantitative geochemistry that were compiled many years ago. Table 2 shows the results of a selection of standard geochemical molecular ratios that are measured on a standard heavy oil as part of our QA/QC procedure (we also include conventional oil, although it is not shown). As you will observe in Table 2, we include ratios that prove challenging to reproduce due to chromatographic performance, such as the abundance of mono-aromatic steroid hydrocarbons relative to tri-aromatic steroid hydrocarbons (TAS/(MAS+TAS)) and a sulfur compound versus an aromatic compounds (DBT = dibenzothiophene / P = phenanthrene). For comparison go to the link below to check the acceptance criteria for geochemical ratios, I trust you will find the data in Table 2 quite appealing.  (page 57 – for NSO-1)

The geochemical insights provided by the highly accurate quantitative data have been revolutionary since we invested the time and effort into resolving the multiple analytical issues that contributed to the variation amongst data; including sample collection, storage, processing and the GCMS instrument variables.

We use methods capable of handling any sample type, core, oils, oils with water, cuttings. We use a cocktail of standards which show similar properties (chromatography and boiling point range) to the compounds we are interested in measuring; basically there is absolutely no point in measuring the concentration of volatile compounds with a high molecular weight compound. A change in the relative abundance of the light components to heavy components is one way to indicate there is an issue with the condition of the GC inlet requiring attention. For example, a decrease in the relative abundance of naphthalene-d8 compared to other standards, indicates that the concentration data for naphthalene (and other volatile compounds) may have been compromised during the analytical procedure and through assessing the amount of naphthalene-d8 that has been evaporated accidentally provides a means to indicate whether excessive loss may have occurred, requiring a repeat analysis, or if the error associated with the loss is minimal and the resulting concentration data may fall within statistically acceptable limits. The result is that we are able to generate accurate and reproducible hydrocarbon concentration data which is shown in Table 3 for a heavy oil sample that was processed in sextuplicate. Basically six aliquots of the heavy oil sample were processed through the analytical protocol, including standard addition, solid phase extraction and GCMS analysis. The results provide a benchmark to define the quality of the data being produced in our lab.

Why is accurate and precise data necessary? Gushor uses concentration data to make statistical models of viscosity such that we can use ProxVisc to assess viscosity from problem samples or where legacy data sets are understood to be vulnerable to the impact of storage decay. Gushor uses concentration data for its production allocation work and also to detect barriers and baffles in reservoirs. Gushor pioneered quantitative GCMS in petroleum geochemistry and is recognized internationally for being able to make determinations that no one else can. You may not be interested in the details but we take care of that to ensure you get the best interpretations possible, based on the best data possible. 

If you have any questions or wish to discuss further please contact Gushor at or (403) 457-4874.

Author: Dr. Barry Bennett – Director of Geoscience Technology – Gushor Inc.


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To Top, or Not To Top: That Is The Question!

The debate continues within the Petroleum Geoscience community regarding the practise of “oil topping” i.e. removing the volatile liquid components (ca. C15- compounds) from an oil sample prior to chromatographic separation. We prefer to process samples whereby the volatiles are retained and subsequently analysed to support geochemical interpretations, since the volatile components provide important clues that help to understand the origin of fluid property (e.g. viscosity) variations in petroleum reservoirs. These concepts are brought to light in many biodegraded oil reservoirs around the world, for example the Orcutt Field in California; where mixing between different fluid phases introduces fluid property variations across the field and they ultimately impact the recovery of the resource.

Some of the most useful information is locked in the diamondoids, which are compounds that may easily be lost from the oil residing in cores during storage or where oils are stored with air headspace, while they may also be impacted during laboratory processing. In essence, why is it necessary to remove components that represent an integral component of the oil? The mass chromatograms displayed in Fig. 1 shows the presence and absence of the methyladamantanes (MAD) whereby a heavy oil sample is processed with the aim to retain volatile liquid components and the same sample where the volatile components have been removed by evaporation i.e. topped. Incidentally, the practise of topping an oil can result in fairly extensive removal of components including naphthalene, methylnaphthalenes, biphenyl, alkylbenzothiophenes among others. Molecular parameters based on these compounds provide important information regarding the source thermal maturity and level of biodegradation thus topping compromises the employment of such data.

Figure 1. Partial reconstructed m/z 135 mass chromatogram representing the methyladamantanes (MAD) and extended hopanes in a heavy oil sample (not the diagnostic ion for hopanes (i.e. m/z 191), but displays their relative distributions).

To date, the simplest interpretations for invoking the presence of mixed oil populations residing in reservoirs is based on binary mixing systems, for example the most commonly cited examples invoke mixing between paleobiodegraded oil (25-norhopanes) and a later fresh oil charge (n-alkanes) that has not been biodegraded to the same extent. However, what happens if the n-alkanes and branched alkanes representing the later fresh charge are removed as biodegradation continues to impact the oil composition. Can we identify mixing between paleobiodegraded oils and biodegraded fresh charge contributions? Yes, we can simply do this by investigating the relative abundance of biomarker and diamondoid concentrations. In general, biomarkers are dominant in oils generated during the early oil window stage of petroleum generation while diamondoids are encountered in significant quantities in late stage oils and condensates. Figure 1 shows the m/z 135 mass chromatograms representing the methyladamantanes (MAD) and hopanes in total hydrocarbon fractions isolated from the solvent extracts of oil sands core. The diamondoid concentration increases from a background level of 140 ppm to 210 ppm providing circumstantial evidence for the presence of a late charge contribution. Meanwhile, the concentrations of biodegradation resistant aromatic steroid hydrocarbons decreased from 850 ppm to 740 ppm which translates into dilution by the additional oil charge lacking these components. Interestingly, the oil containing the enhanced diamondoid concentrations has a lower viscosity (µ = 50 kcP versus 250 kcP ((at 20 ºC)), which is consistent with mixing between pre-existing paleobiodegraded oil and a later volatile enriched charge which has also undergone heavy biodegradation. Interestingly, the evidence typically sought after for recognising the additional charge contribution (n-alkanes and branched alkanes) has been removed, while the biodegradation resistant diamondoids remain. In this case study, the diamondoids provide a vital piece of evidence to better understand the field wide variations in fluid properties and help define the geographic extent of the “sweet spot”.

Figure 2. Partial reconstructed m/z 135 mass chromatograms representing the methyladamantanes (MAD) and extended hopanes in solvent extracts from two fresh core samples containing different viscosity (µ at 20 ºC) oils.

The revolution in geochemical tools, such as those developing correlations between viscosity and geochemical data are based on solid foundations that require data from fresh core and oil samples. As the clock starts ticking from the moment the core or oil samples are collected from the well, volatile liquid components are progressively lost at rates according to sample storage conditions.

Simply allowing practises that promote the loss of light ends during sample collection, storage and laboratory processing is sheer MADness!

If you have any questions or wish to discuss further please contact Gushor at or (403) 457-4874.

Author: Dr. Barry Bennett – Director of Geoscience Technology – Gushor Inc.


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Do You Understand Your Petroleum Reservoir Well Enough for a Sustainable Production?

Petroleum systems include a series of elements and processes that lead to the formation of oil and gas accumulations. A given petroleum composition and its distribution in the basin are the result of a combination of multiple processes within the system. In order to exploit oil and gas reserves efficiently, a sensitive understanding of the corresponding petroleum systems is crucial. From the source to the wellhead, petroleum geochemistry provides essential tools to help with the better understanding of the processes that affects oil quality distribution and flow units in the reservoir. This allows to assess issues such as the existence and distribution of highly viscous or immobile oil zones (tar mats), asphaltene precipitation, compartmentalized reservoirs and in general to support the design of a development plan that fits your reservoir and leads to a sustainable production of the resources. Using integrated approaches with multiple disciplines is a key factor!

Typically, only parameters based on ratios of biomarkers and some non-biomarker compounds are used in the oil and gas industry with oil-source rock correlation purposes and to assess levels of maturity of source rocks, and the effect of other post accumulation processes. However, the information obtained from ratios is very limited, particularly when it comes to their application to oil fields development. The absolute concentrations of the multiple components of the oil give the information required to determine, for example, levels of biodegradation and the existence of oil quality gradients associated with this alteration process, mixing of different oil charges and contributions from different sources, migration distances, development of steam chambers during thermal recovery of heavy oil, water breakthrough during secondary production or flooding procedures, proximity to oil-water contacts, production allocation, reservoir compartmentalization and assessment of seal integrity, among other benefits. Hence, a detailed baseline molecular characterization of the hydrocarbon and polar fractions of the oil before starting the production operations is strategic and will definitely save money. Other geochemical techniques, such as for instance stable isotopic composition, elemental analysis and metal content, and the direct determination or estimation of oil physical properties also provide key information.

We at Gushor have developed analytical methods that assure high accuracy in the determination of absolute concentration of multiple oil components and measured oil physical properties from conventional to extra-heavy oil. Moreover, our solid expertise on the several issues related with petroleum exploration and production, as well as our experience with a diversity of petroleum systems, allows us to provide our clients with not only top quality data and excellent turnaround times, but also a complete interpretation to help with the decision making process. With this purpose, we consider that the sampling strategy is instrumental. The determination of the composition of a single petroleum or source rock sample will not make it. An evaluation of the spatial relationships between samples is a must to allow the determination of the main processes involved and to predict the distribution of oil quality on a local or basin scale based on geochemical and fluid information integrated with geology and reservoir engineer data.

If you have any questions or wish to discuss further please contact Gushor at or (403) 457-4874.

Author: Dr. Norka Marcano, Sr. Project Manager – Gushor Inc.


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Heavy Oil Biodegradation – Important?

Most of the world’s oil is biodegraded as exemplified by the super-giant viscous heavy oil and bitumen deposits in Venezuela, here in Western Canada and elsewhere. Understanding in–reservoir oil biodegradation is of significance for petroleum exploration (e.g. pre-drill prediction of the likelihood a prospect is biodegraded) and production (e.g. selection of reservoirs, well locations and operating strategies in biodegraded oil fields where fluid properties will be most favourable for production). The technology we use today came from basic and applied research done in universities and industry over many years and that research sought to understand the processes that are involved in the formation of such heavy oil deposits, the rates of oil degradation over geological timescales, the importance of microbial activity in the deep biosphere for heavy oil formation and factors that control the occurrence of heavy oil and its viscosity variations.

The outcome of this research has been a new model of in-reservoir oil biodegradation where anaerobic processes, primarily oil degradation linked to methanogenesis, drive oil biodegradation and that site of biodegradation is the oil water transition zone in the reservoir leading to variations in oil composition and extreme fluid property gradients in the reservoirs. Understanding the nature and magnitude of these fluids property gradients has already had commercial benefit in the sighting of wells and in oil recovery process operations. In addition to practical applications, these gradients have allowed biodegradation rates to be estimated and deep biosphere processes to be elucidated. We have shown that reservoir geometry, formation water salinity and most significantly reservoir temperature are key controls on whether in reservoir oil biodegradation will occur. Even if a reservoir is currently at a low temperature, if it has experienced temperatures much in excess of 80°C, then the oil is unlikely to be biodegraded and we have developed a model known as the palaeopasteurization hypothesis to explain this phenomenon. This not only has significance for our understanding of petroleum systems but provides fundamental insights on the deep biosphere, indicating that once palaeopasteurized, reservoirs are not readily recolonized by hydrocarbon degrading microorganisms from the surface. It also suggests that in harsh deep subsurface sediment environments, that the upper temperature limit for life is considerably lower than in high energy systems such as hydrothermal vents where the thermal limit for life may be in excess of 120oC. A good summary of the basic research in this area is in Head, I.M. et al (2003). Biological activity in the deep subsurface and the origin of heavy oil. Nature 426 344-352.

How does this affect your bottom line? The biodegradation process produced ubiquitous vertical and lateral oil composition variations and oil viscosity gradients in your reservoirs; it produced immense amounts of gas which sometimes formed small local gas zones which then filled with water as the gas leaked away to form top and middle water zones as oil was too viscous and too dense to flow to replace gas; the biodegradation process also increases the thickness of low water saturation zones at the base of pay. Biodegradation also produces consistent chemical changes in oil composition spatially in 3D in a reservoir, this provides a unique tool with which to understand which oil is flowing in a reservoir by analysis of produced oils and relating the oil composition to a prior baseline study.

Value proposition-why is viscosity and variable oil composition so important??

The flow of a fluid such as oil(or water)through a porous and permeable medium such as a rock is controlled by Darcy’s law and both the properties of the rock medium(relative permeability) and the oil viscosity are factors in controlling oil flow rate under any fluid potential gradient driving flow to a production well. Higher oil viscosity means lower flow rates and vice versa. It is often tempting to think that when one heats bitumen in a thermal recovery process, that when the oil reduces in viscosity from the sometimes millions of cP under native reservoir conditions to the around 5-20cP target viscosity in SAGD processes, that it doesn’t matter if it is 5 or 20cP at oil flow temperature (commonly lower than steam temperature). In reality of course a fourfold change in viscosity can have a substantial, economically important impact on actual SAGD well flow rate. In reality bitumen reservoirs do not have uniform permeability and neither do they have uniform oil viscosity at either native conditions or at oil flow temperature(or even steam temperature). This further impacts well flow rates unless operations are designed to allow for these inherent heterogeneities. While it is the( up to X 50), vertical variations in native reservoir bitumen viscosity that grab headlines, the lateral oil viscosity gradients also seen in oil sands are probably a bigger impactor of well economics as they impact the uniformity of steam chamber development during SAGD startup. Fluid viscosity variation between the injector and producer is a major control on SAGD performance during startup and in SAGD mode and cold spots at startup are notoriously persistent. Variations in viscosity at oil flow temperature are real and need to be understood as they do impact production flow rates. This is best done through high resolution vertical and lateral oil viscosity studies from core or from cutting samples performed soon after sampling.

Understanding the processes by which heavy oil and bitumen deposits form, coupled with field observations of bitumen column variations in well over 1000 wells shows that in continuous pay sections, gradual consistent and ubiquitous compositional gradients are seen in all bitumen reservoirs. Where baseline compositional studies have been performed, comparison of the composition of produced oils with the baseline background compositional variations using neural networks, partial least squares or other multivariate data analysis methods allows us to assign the produced oil spatially within the reservoir-an oil production allocation. This is very useful in assessing how productive the whole well length is in cold or thermal recovery and can also be used to assess casing and cement failures when production profiles change suddenly or when leakage occurs. The key to such production allocation studies is having a reference baseline study available and this is always most cost effective before problems arise rather than after. Perhaps our largest growing area of study is on barrier and baffle assessment pre steaming or pre cold flow. The processes that produce heavy oil and bitumen result in gradual, consistent and ubiquitous compositional gradients in continuous pay sections. Where continuous shales or other features compartmentalise a reservoir, the reservoir filling and biodegradation process always produces a discontinuity or step in oil composition at the barrier. This sometime is also seen in a viscosity profile which may show a step but geochemical oil composition is a much more reliable preproduction indicator of barriers. Where a reservoir zone contains partial flow barriers (baffles), changes in the slope of compositional gradients and smaller discontinuities are seen. Geochemical reservoir profiling is probably the best preproduction technology for barrier and baffle detection in a heavy oil or oil sands reservoir. The key step is making a baseline study before well placements and problems occur!
While we tend to focus on production issues it is clear after many years of looking at the oil sands that there is much regional and local variation in oil properties related again to the mechanistic origins of heavy oil and bitumen from the competition between slow geological timescale charging of fresh oils to the reservoirs from multiple source rocks and slow geological timescale biodegradation and alteration of the oils in the reservoir. Oils nearer the charge points are better than oils further away. Late charge is good and water is bad for oil quality. As the oil sands formed, fresh oils from a least two source rocks gradually became more viscous as they became biodegraded during charging. Locally the oils likely became so viscous they froze and stopped charge and the oil charge rivers moved elsewhere in a manner similar to the stop-flow behaviour of those 70s student gimics-lava lamps. Add to this the local vertical and lateral viscosity gradient generating mechanisms we understand well and we can start to see why the oil sands have such variability at a range of scale in oil viscosity. Oils at the top of reservoir can have native reservoir dead oil viscosities as low as a few thousands of cP while oils at the bottom can have viscosities up to several tens of millions. The range of oil viscosities in the oil sands is colossal, opening up many innovative opportunities for alternate recovery strategies and packages of processes for companies who understand the giant geobioreactor that is the Albertan oil sands and its impact on the nature and distribution of the reservoired oils.

If you have any questions or wish to discuss further please contact Gushor at or (403) 457-4874.

Author: Dr. Stephen Larter, Chief Executive Officer – Gushor Inc.


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Tools for a 21st Century Low Carbon Energy Supply – QcompGCMS – Functional Solutions for conventional and unconventional resource assessment.

Exploration petroleum geochemistry saw a peak of discovery and development around the 1970’s/early 1980s with few radically new concepts, methods or approaches since then. The 70/80s also saw the development of quick screening methods for assessing oil/gas source rock potential (e.g. Rock-Eval), the development of approaches to assessing temperature history of oil and gas source rocks (maturity), methods for relating different oils/gases to one another or source rocks through molecular or isotopic fingerprints and the definition of practical approaches to modeling oil/gas generation from source rocks. These methods and approaches however are not always portable as tools for the exploration/production activities of unconventional resources and it is surprising to us that low resolution screening tools such as RockEval, useful as they are for screening source rocks, have become such front line tools in the evaluation of several types of unconventional resources. What happened to all the new technologies developed in the 90s and early 21st century-oops-there aren’t any! In essence the scientific revolution from 30 years ago needs a reboot! One new technology was developed in that period and that was routine quantitative analysis of petroleum component concentrations. Such a straightforward approach, measuring precisely and accurately the concentrations of key components in crude oils hardly seems radical, yet still today few labs in the world can do it, and even fewer do! We have been improving the precision and accuracy of quantitative GCMS for many years to the point where we have abandoned the traditional compound ratio approaches still used by most petroleum geochemists today. Why, well quantitative data provides better estimates of oil maturity than traditional peak abundance ratio approaches and can be used to make very subtle maturity assessments in self sourcing reservoirs. Accurate quantitative GCMS data often shows trends in biodegradation related compositional changes which are invisible to peak ratio approaches and quantitative data is mandatory for production allocation and viscosity prediction studies in oilfields, therefore Gushor’s barrier detection and production allocation processes depend on accurate quantitative data.

Q2compGCMS is a technology package providing proven practical solutions to unconventional resource, exploration and production problems. It is a system that provides ultra stable, accurate quantitative molecular data from petroleum mixtures and supporting software to provide output solutions for unconventional energy exploration and production. It provides a major advance over the qualitative approaches to petroleum geochemistry currently still in use worldwide. It has applications to mapping heavy oil fluid viscosity profiles from reservoir core and horizontal well cuttings; mapping SAGD busting- steam stopping barriers in oil sands reservoirs and providing reservoir engineers with information on spatial well performance in cold and thermal heavy oil production. Q2compGCMS also allows for effective conventional petroleum geochemical applications including accurate maturity assessment, demixing of mixed oil charge to accumulations; assessment of oil-oil and oil-source rock correlations and for other conventional and unconventional oil and gas exploration and production problems. Petroleum geochemical technology did not stop development in the 20th century but has carried on.

If you have any questions or wish to discuss further please contact Gushor at or (403) 210-7594.

Author: Dr. Stephen Larter, Chief Executive Officer – Gushor Inc.


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