The value of geochemistry in heavy oil development

Introduction

Heterogeneity can be a major challenge in the development of heavy oil reservoirs; fluids often change dramatically over short distances – both laterally and vertically. While it is impossible to know exactly what type of oil will be encountered when drilling a new well, the uncertainty can be reduced through geochemical characterization of the reservoir. In addition, geochemical characterization will help to place wells optimally for maximum productivity.

With SAGD, and some other heavy oil recovery strategies using horizontal wells, the production wells are usually placed close to the bottom of the reservoir to enable gravity drainage of the maximum possible sequence. However, oil often grades from lightest at the top of the reservoir to heaviest at the bottom. In addition, when the oil is underlain by water, microbial activity can dramatically increase oil viscosity close to the oil/water interface. Variations in this biodegradation can lead to significant lateral changes in viscosity over distances as short as 300m [1,000 ft]. Production wells placed in high viscosity layers are unlikely to perform optimally, and better results can often be obtained by placing wells some distance from the basal water, which may only be present in pockets dispersed around the field. 

Oils able to flow sufficiently without thermal stimulation are often recovered using CHOPS and vertical wells. Here, foaming is frequently a major component of production drive. The pressure differential at the well decreases pressure in the surrounding reservoir, causing gas to come out of solution to create a foam that has considerably lower viscosity than the in-situ oil. CHOPS wells often die once there is no more gas to come out of solution and the foamy oil mechanism ceases to function.  

Geochemical characterization of a reservoir can evaluate gas content and its likely behavior. It can also indicate where to drill and/or perforate to avoid viscous zones and tar mats. McCarthy observes that, in Canada, those operators who until recently “just drilled” without first performing a thorough reservoir characterization are now frequently changing their policies; taking the time to core and sample every well.

Mapping compositional gradients

Determination of compositional gradients is usually based upon representative samples taken at available well locations. The results are then mapped to predict gradients throughout the field. Samples are often “dead oil”, taken from surface production facilities. Gas Chromatography (GC) provides a full chemical breakdown of the samples, however both the chemistry and viscosity of samples will change as gas is lost during production. Samples should ideally be taken at different levels of the reservoir and kept in their original downhole pressure, volume and temperature (PVT) conditions throughout analysis. It should also be noted that accurate measurement of viscosity is difficult in any case, because laboratory rheometers typically have an accuracy of +/- 10%.

Thermodynamics

After viscosity, the second most important factor in geochemical characterization is to determine the relationship between the geochemistry and the thermodynamic behavior of heavy oil. This process often begins with “SARA analysis”, in which samples are fractionated into components belonging to four different solubility classes: saturates, aromatics, resins, and asphaltenes. Asphaltenes are of particular importance, because although small molecules individually, they easily group together into substances that have a major impact on viscosity.

Biomarkers

Biological markers (biomarkers) can provide a valuable insight into the history of an oil deposit. These are complex molecular fossils derived from biochemicals, particularly lipids, in once-living organisms (Source: The Biomarker Guide: Biomarkers and isotopes in petroleum systems and Earth. Kenneth Peters et al). These compounds are very resistant to post-generation processes, and so maintain their chemistry since the original creation of a crude oil.

Biomarkers can help to determine the thermal maturity or the temperature (T) of burial. As T rises, the chemistry of biomarkers undergoes a subtle non-reversible conversion. The resulting chemical balance can therefore be used to estimate T in the source rock. These T conditions have a major impact on viscosity. In general, viscosity is reduced as source rock temperature rises, so oil that has not been deeply buried and heated is more likely to have higher initial viscosity. Subsequent biodegredation will further increase viscosity.

In addition to T, analysis of biomarkers can provide indications of the type of source rock, migration path, and alteration history. Most heavy oil deposits are related to biodegradation, in which volatile conventional oil components are lost. This makes biomarkers of particular value in the characterization of heavy oil reservoirs. 

Burial history of Canadian heavy oil

Biomarkers help to understand geographical variations in the geochemistry of Canada’s onshore heavy oil deposits, which follow a roughly E-W trend. Oil in the Athabasaca region, in the east of Alberta, is high viscosity bitumen. Viscosity tends to decrease moving west towards the Rocky Mountains, due to the higher T conditions resulting from increasingly deep basin fill.  

Offshore oil resources allocation

GC analysis can provide a unique “fingerprint” of the geochemistry of the oil in each zone of a reservoir. Produced fluids from several reservoir zones and/or wells are often commingled before reaching the surface, particularly offshore. Geochemical analysis of samples of the fluids produced at the surface can determine the proportions coming from each zone or well. This knowledge can not only be used to optimize production strategies, but is often a legal requirement to enable accurate fiscal allocation.  The process can be applied to oils of all types, but is likely to be of particular value to allocation of the increasingly heavy oils that are being developed in areas such as offshore West Africa, Brazil and Mexico.

 Optimizing development strategies

Full reservoir characterization, including geochemistry, prior to field development can provide a much better indication of the reservoir fluids and the most effective steam, solvent, or other potential production method. Solvents can be used either alone or as part of an alternating steam/solvent cycle. Injecting an inappropriate solvent, or rushing SAGD operations, can kill a well. Geochemical pre-characterization can aid the selection of appropriate solvents.

SAGD operators are understandably keen to ramp-up production as soon as possible; however, pumping steam too fast can cause waters (formation, interstitial, connate and injected) to change acidity, potentially dissolving matrix minerals and resulting in formation damage and subsequent collapse. Geochemical monitoring of scale formation and produced fluids can detect increases in mineral content that might indicate dissolution of the reservoir formation. Potential preventative measures include reducing the rates of steam injection, increasing steam quality or chemical treatment of injection water to alter its acidity. It should be noted, however, that water recycled during SAGD operations is likely to contain small volumes of condensate, which can dramatically increase pH. In addition, the high temperatures inherent to SAGD operations result in high chemical reaction rates.

The value of geochemical characterization

Geochemistry has long been an important issue in the development of all types of hydrocarbons, and its particular value for heavy oil is increasingly being recognized. Oil companies are spending more time understanding the effects of biodegradation, and geochemistry is being written into basin modeling workflows and packages such as the PetroMod petroleum systems modeling software.

About Kevin McCarthy

Kevin McCarthy is a Geochemist at the Schlumberger Heavy Oil Regional Technology Center in Calgary, where he performs research and provides technical support to operator’s geochemical issues related to heavy oil. His research areas include determining methods and applications for identifying lateral and vertical compositional gradients, biodegradation and basin modeling. Prior to joining Schlumberger in 2008, Kevin gained experience working as an environmental scientist focused on hydrogeology and water quality issues on various projects in Florida.  He also has experience on both ends of the altitude spectrum:  On one end, he has been involved in deep sea hydrothermal research and has been on board the submersible ALVIN to a depth of 3700 meters.  On the other end, he was part of Tufts University’s project to analyze soil samples retrieved on Mars in support of NASA’s Phoenix Mars Lander Mission.