Martin G. Fowler

The controls on the composition of biodegraded oils in the deep subsurface: Part II - Geological controls on subsurface biodegradation fluxes and constraints on reservoir-fluid property prediction

The principal controls on the fluid properties of biodegraded oil systems have been determined by a combination of petroleum geochemistry, numerical modeling of oil biodegradation in reservoirs, and analysis of oil property data sets from a variety of geological settings. Petroleum biodegradation proceeds under anaerobic conditions in any reservoir that has a water leg and has not been heated to temperatures more than 80C. In most reservoirs with low concentrations of aqueous sulfate, methanogenic degradation is a primary mechanism of petroleum degradation, whereas in waters containing abundant sulfate, sulfate reduction and sulfide production may dominate. Net degradation of petroleum fractions in reservoirs is primarily controlled by the reservoir temperature, the chemical compounds being degraded, and relationships between the oil-water contact (OWC) area and oil volume. The relative volumes of water leg to oil leg, prior level of oil biodegradation, and reservoir water salinity act as second-order controls on the process. Typically, degradation fluxes (kilograms of petroleum destroyed per square meter of oil-water contact area per year or kg petroleum m2 OWC yr1) for fresh petroleum in clastic reservoirs are in the range of 103–104 kg petroleum m2 OWC yr1 and increase with decreasing reservoir temperature, from zero near 80C, to a maximum flux at the OWC of less than 103 kg petroleum m2 OWC yr1 at a temperature less than 40C. At very low reservoir temperatures and with severely degraded oils, such as are seen in the near-surface Canadian tar sands at the present day, the net degradation fluxes are much less than maximum values. Nutrient supply from the aquifer and adjacent shales, mostly buffered by mineral dissolution, probably provides the ultimate control on the range of degradation flux values. Oil compositional gradients and resulting oil viscosity variations are common on both reservoir thickness and field scales in biodegraded oil reservoirs and are a defining characteristic of heavy oil fields produced by crude-oil biodegradation. Continuous vertical gradients in the oil columns document episodic degradation for many millions of years, suggesting that the time scales of oil-field degradation and petroleum charging are similar. The flux-temperature relationship we have derived, coupled with typical reservoir charge histories, defines the range of variation of fluid properties seen in many biodegraded oil provinces and identifies oil charge, mixing of biodegraded and fresh oils, and reservoir-temperature history as the primary controls on fluid properties. These flux-temperature relationships are easily integrated into prospect charge modeling procedures; sensitivity analyses show that the limiting factor in fluid property predictions, using even this first-level approach, are ultimately constrained by the accuracy of current oil-charge modeling estimates. The absence today of any functional geochemical proxies for assessing oil-residence time in oil fields and the substantial uncertainty in petroleum-charging times estimated by forward basin modeling is a major obstacle to more accurate fluid-property predictions that needs to be addressed.

The influence of thermochemical sulphate reduction on hydrocarbon composition in Nisku reservoirs, Brazeau river area, Alberta, Canada

Abstract The Upper Devonian Nisku Formation reservoirs of the Brazeau river area of west-central Alberta, Canada, produce oil and sweet and sour gas condensate. Generally, oil pools are located updip in the study area and sour (6–31% H2S) gas condensate downdip. H2S in the study area is formed by thermochemical sulphate reduction (TSR). All liquid hydrocarbons probably have one source, with the Duvernay Formation being the most likely candidate. Assessing the relative maturity of the oils and condensates is difficult because of the wide variation in thermal maturity and the effects of TSR, but the ratio of pristane/n-heptadecane does appear to decrease with increasing maturity for this sample set. With increasing TSR, the following changes were noted: decrease in the saturate/aromatic hydrocarbon ratio; increase in the relative abundance of organo-sulphur compounds (e.g. benzothiophenes); δ34S values of liquid hydrocarbon samples approached the values for anhydrite of the Nisku Formation in the study area; and an increase in δ13C of the saturate fraction. H2S concentrations in hydrodynamically “isolated” pools provide a good estimate of the extent of TSR in these reservoirs. However, other pools have anomalously high H2S concentrations for their depth, suggesting that the H2S was generated at greater depths and migrated updip into these pools.

Applications of petroleum geochemistry to exploration and reservoir management

Abstract Petroleum geochemistry improves exploration efficiency by accounting for many of the variables that control the volumes of crude oil and natural gas available for entrapment, including source-rock distribution, richness and quality, thermal maturity, and the timing of generation-migration-accumulation relative to trap formation. It is most powerful when used with other disciplines, such as seismic sequence stratigraphy and reservoir characterization. Four key technology milestones form the basis for most modern applications of geochemistry to exploration. These are the concepts and applications of (1) petroleum systems and exploration risk, (2) biomarkers, stable isotopes, and multivariate statistics for genetic oil-oil and oil-source rock correlation, (3) calibrated three-dimensional thermal and fluid-flow modeling, and (4) controls on petroleum composition by secondary processes. Petroleum geochemistry offers rapid, low-cost evaluation tools to aid in understanding development and production problems. Some technology milestones in reservoir geochemistry include (1) assessment of vertical and lateral fluid continuity, (2) determination of proportions of commingled production from multiple zones and leaky casing, (3) prediction of oil quality in reservoir zones, and (4) prediction of gas/oil and oil/water contact locations. As described in the conclusions, future research will continue a trend toward predictive geochemistry. Examples of predictive tools that draw major research support include piston-core surveys to assess deepwater petroleum systems prior to drilling and three-dimensional basin modeling to predict the regional timing of generation, migration, and accumulation of petroleum. Among other research objectives, models are needed to better predict the distribution and quality of petroleum in reservoirs.

Hydrogen isotopic compositions of individual alkanes as a new approach to petroleum correlation: case studies from the Western Canada Sedimentary Basin

Isotopic compositions of carbon-bound hydrogen in individual n-alkanes and acyclic isoprenoid alkanes, from a number of crude oil samples, were measured using gas chromatography-thermal conversion-isotope ratio mass spectrometry. The precision of this technique is better than 3‰ for most alkanes, compared to the large range of δD variation among the samples (up to 160‰). The oils were selected from major genetic oil families in the Western Canada Sedimentary Basin, with source rocks ranging in age from Ordovician (and possibly Cambrian) to Cretaceous. The hydrogen isotopic composition of alkanes in crude oils is controlled by three factors: isotopic compositions of biosynthetic precursors, source water δD values, and postdepositional processes. The inherited difference in the lipids biosynthetic origins and/or pathways is reflected by a small hydrogen isotopic variability within n-alkanes, but much larger differences in the δD values between n-alkanes and pristane/phytane. The shift toward lighter hydrogen isotopic compositions from Paleozoic to Upper Cretaceous oils in the WCSB reflects a special depositional setting and/or a minor contribution of terrestrial organic matter. The strong influence of source water δD values is demonstrated by the distinctively lower δD values of lacustrine oils than marine oils, and also by the high values for oils with source rocks deposited in evaporative environments. Thermal maturation may alter the δD values of the alkanes in the oil to some extent, but secondary oil migration does not appear to have had any significant impact. The fact that oils derived from source rocks that could be of Cambrian age still retain a strong signature of the hydrogen isotopic compositions of source organic matter, and source water, indicates that δD values are very useful for oil-source correlation and for paleoenvironmental reconstructions.

Unique distributions of hydrocarbons and sulphur compounds released by flash pyrolysis from the fossilised alga Gloeocapsomorpha prisca, a major constituent in one of four Ordovician kerogens

Abstract Kerogens isolated from four rocks of Ordovician age from North America have been analysed by combined pyrolysis-gas chromatography-mass spectrometry to compare and contrast the type and distribution of sulphur-containing compounds and aromatic and aliphatic hydrocarbons present in the pyrolysates. When pyrolysed, all of the kerogens released several series of heterocyclic sulphur compounds including alkylthiophenes, alkylthiolanes, alkylthianes and alkylbenzothiophenes together with n -alkanes, n -alklenes and alkylcyclohexanes as well as alkyl-substituted benzenes and naphthalenes. One of the kerogens, isolated from the Guttenberg oil rock, consisted predominantly of the alga Gloeocapsomorpha prisca , which produced sulphur compounds and hydrocarbons with fingerprint pyrograms that were different from those of the other three kerogens. The data provide prima facie evidence that these distributions may act as pseudo “biological markers” for this species of alga, namely that unsaturated kerogen moieties available for the uptake of sulphur, or which can cyclise to form hydrocarbons, distinguish Gloeocapsomorpha prisca from the contributing organisms of the other kerogens analysed.

Biological marker and conventional organic geochemistry of oil sands/heavy oils, Western Canada basin☆

Abstract Forty-three samples of oil sands/heavy oils from most of the major Cretaceous deposits and the Upper Devonian Grosmont Formation of the underlying “carbonate trend”, have been examined by gas chromatography and gas chromatography-mass spectrometry. Major organic geochemical differences observed between samples/deposits include the presence or absence of n-alkanes and isoprenoid alkanes, together with changes in the distributions of biological marker compounds. These differences reflect the degree of biodegradation suffered by the deposits. As noted earlier by others, there is a trend toward increased biodegradation from west to east in the basin. Three geochemical factors demonstrate that at least the Cretaceous samples are strikingly similar to one another, once the effects of biodegradation are discounted. These factors are the carbon number distribution of steroidal alkanes (C27, C28, and C29 diasteranes); the presence of 28,30-bisnorhopanes; and the relative abundance of 28,30-bisnorhopanes and gammacerane as compared with the ubiquitous 17α(H)-hopanes. These distinctive biomarker compositions are ratios indicate that the same or very similar sources generated the Cretaceous oil sands/heavy oils, despite the enormous volumes and their widespread geographic and stratigraphic distribution. The extent of isomerization of regular steranes and hopanes indicates that the bitumens show the same general level of maturity. All these data suggest that the Cretaceous bitumens were derived from a mature, conventional oil which was in turn derived from a presently unknown source fecies. This oil must have migrated over large distances, suffering extensive biodegradation in place and possibly during migration. There appear to be at least two mechanisms of biodegradation that the biomarkers have undergone in the Cretaceous oil sands/heavy oils. Most samples from which regular steranes have been removed by extensive biodegradation do not show 25-norhopanes. In four Wabasca Deposit Grand Rapids A sand samples, however, 25-norhopanes are present in variable amounts relative to regular hopanes, despite the fact that three of these four samples still contain regular steranes. Possible candidates for source facies may be present in the Mesozoic clastic succession as suggested by others, but systematic work at all stratigraphic levels is required to discover a source facies with the requisite geochemical properties and the potential of having generated the enormous volumes of oil contained within the oil sands and heavy oil reservoirs of the Western Canada Basin.

Effect of maturity and petroleum expulsion on pyrrolic nitrogen compound yields and distributions in Duvernay Formation petroleum source rocks in central Alberta, Canada

Abstract A quantitative study of pyrrolic nitrogen compounds was conducted on a series of marine carbonate petroleum source rock extracts taken from the Upper Devonian Duvernay Formation in the central Alberta portion of the Western Canada Sedimentary Basin. With increasing thermal maturity, concentrations of various pyrrolic nitrogen compounds in the rock extracts increase drastically, together with significant compositional variations related to alkyl substitution position. The study provides circumstantial evidence for adsorptive interactions operating between organic nitrogen compounds and solid organic/mineral phases in subsurface sedimentary rocks during petroleum generation and expulsion. The absolute concentrations and relative distributions of pyrrolic nitrogen compounds in the extracts of different maturity ranges provide background information for the calibration of such data in migrated petroleums, as an independent measurement of secondary oil migration range of Duvernaysourced oils in the basin

Depositional Environment and Oil Generation in Ordovician Source Rocks from Southwestern Ontario, Canada: Organic Geochemical and Petrological Approach

The Ordovician Trenton Group (Sherman Fall and Cobourg formations) and the Lindsay (Collingwood Member) and Blue Mountain formations of southwestern Ontario were examined using Rock-Eval pyrolysis, gas chromatography, gas chromatography-mass spectrometry, and incident-light microscopy to evaluate their paleodepositional environments, thermal maturities, and source rock potential. All units contain sufficient amount of oil-prone (type II), predominantly marine organic matter to be considered as petroleum source rocks. Unstructured bituminite with varying proportions of unicellular alginite are the dominant dispersed organic matter macerals. The bituminite typically occurs in massive to laminated, granular or patchy populations that commonly show microtextural relationships. Persistent inclusions of Leiosphaeridia telalganite demonstrate that planktonic algal debris was a primary organic substrate for blooming microbes. Disseminated coccoidal Gloeocapsomorpha prisca is found in minor amounts, usually in association with common to abundant acritarchs. Zooclasts (chitinozoa, graptolites, scolecodonts) and solid bitumen also are present as maceral inclusions within the bituminite network. The biomarker distributions for all of the studied units are those expected for marine organic matter deposited in a clastic-dominated environment. The extracts are characterized by a smooth n-alkane profile, with low abundance of C20+ members, typical for marine derived organic matter. Pristane/phytane ratios range from 0.97 to 1.72, indicating dysoxic conditions during deposition. Smooth C31-C35 homohopane profiles, Ts/Tm ratios (typically above 1.0), and a higher concentration of diasteranes relative to regular steranes all appear to indicate the clay-bearing character of these rocks. The predominance of C30 hopane over C29 regular sterane is interpreted to reflect a primary microbial input and extensive reworking of the organic matter. Optical (reflectance, fluorescence) and geochemical (Tmax, biomarker data) thermal maturity parameters indicate that the Trenton and Blue Mountain strata are within the zone of prolific oil generation throughout the whole area of study. The Collingwood shales are mature with respect to petroleum generation in the eastern part (Toronto area) and only marginally mature in the northern part (Georgian Bay area) of the study area. In general, the biomarker composition of the extracts from all examined units is compatible with that of the oils found in the Trenton reservoirs of southwestern Ontario; however, geochemical and geological evidence suggests that the organic-rich shaly laminae within the Trenton Group are the principal source of these oils. Accumulation of organic carbon in the Ordovician sediments of southern Ontario is suggested to derive from low-energy, normal-marine environments grading from shallow-shelf into deep-shelf and open-basinal settings. The nutrient availability and, consequently, higher bioproductivity, more intense consumption of oxygen, and progressing anoxia, controlled by a low-latitude location, diminished water circulation, stratification of the water column, and a depressed pycnocline resulted in high preservation rates. The amorphous nature of kerogen reflects significant microbial interaction at the water/ sediment interface and within the sediments where reducing conditions must have periodically predominated.

Bakken/Madison petroleum systems in the Canadian Williston Basin. Part 2: molecular markers diagnostic of Bakken and Lodgepole source rocks

Abstract The uppermost Devonian-Mississippian Bakken Formation black shale and the Mississippian Lodgepole Formation carbonate represent two of the most important source rocks in the Canadian Williston Basin. Quantitative analyses of both saturated and aromatic hydrocarbon fractions reveal significant differences in the relative distributions and absolute concentrations for a wide range of molecular markers between the extracts of the two source units. Among others, the Bakken shales are characterized by their high relative abundance of trimethyl aryl and diaryl isoprenoids likely derived from green sulfur bacteria Chlorobiaceae. In contrast, the Lodgepole carbonates at similar maturity levels display a C35 homohopane prominence and abundant benzohopanes, ring-D monoaromatic 8,14-secohopanes and a tetracyclic monoaromatic hydrocarbon. The distinctive nature of molecular marker “fingerprints” diagnostic of the two source rocks is clearly related to their different organic inputs and depositional environments. Additionally, the large difference in the absolute concentrations of these compounds observed in both source units may potentially lead to biased geochemical interpretations if strictly conventional, saturate-based biomarker approaches were used for oil-oil and oil-source correlation.

Geochemical constraints on models for secondary petroleum migration along the Upper Devonian Rimbey-Meadowbrook reef trend in central Alberta, Canada

Abstract The Upper Devonian Rimbey-Meadowbrook reef trend of central Alberta, Canada, is one of the classical examples that was originally used to support Gussows model of differential hydrocarbon entrapment. However, the clear discrepancies existing between the ideal hydrocarbon distribution predicted by this model and the one actually observed led to several alternative geological models, most of which have not been constrained by organic geochemical data. The present study uses a wide range of bulk and molecular parameters to determine the oil source characteristics and thermal maturity along the reef trend. The concentrations and isomeric distributions of alkylcarbazoles and non-alkylated benzocarbazoles in oils are employed to study petroleum migration pathways and to constrain the existing secondary petroleum migration models. The data indicates that Gussows principle is generally applicable, as the oils in the up-dip direction generally have longer implied migration distances although this is not always the case. Other factors not recognized previously, such as the presence of two subfamilies of the Duvernay Formation sourced oils, may also have contributed significantly to the discrepancies in the oil and gas distributions between the model predictions and the actual observational data.