Sustainable Production

January 18th, 2012

 

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.

Author: Norka Marcano, Sr. Project Manager, Gushor Inc.     Copyright: Gushor Inc.

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Heavy Oil Biodegradation

October 26th, 2011

 

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.

Author: Steve Larter, Chief Executive Officer, Gushor Inc. (www.gushor.com)

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Tools For the 21st Century

July 11th, 2011

 

Tools for the 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 info@gushor.com or (403) 210-7594.

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