Biodegradation and Impact on Oil Quality - Wenger Et Al - SPE

8/9/2019 Biodegradation and Impact on Oil Quality - Wenger Et Al - SPE

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Multiple Controls on PetroleumBiodegradation and Impact on

Oil QualityLloyd M. Wenger, Cara L. Davis, and Gary H. Isaksen, ExxonMobil Upstream Research Co.

SummaryBiodegradation of oils in nature is important in reservoirs coolerthan approximately 80°C. Oils from shallower, cooler reservoirstend to be progressively more biodegraded than those in deeper,hotter reservoirs. Increasing levels of biodegradation generallycause a decline in oil quality, diminishing the producibility andvalue of the oil as API gravity and distillate yields decrease; inaddition, viscosity, sulfur, asphaltene, metals, vacuum residua, andtotal acid numbers increase. For a specific hydrocarbon system(similar source type and level of maturity), general trends exist foroil-quality parameters vs. present-day reservoir temperatures of


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separation of wet gas components during gas processing. Gasbiodegradation decreases GOR (Fig. 1) and wet gas percentages(Fig. 2) and increases the percentage of CO 2 (Fig. 3).

H2 S in gas causes significant handling and processing expensebecause of its high toxicity and corrosivity (sulfuric acid is formed

when H 2 S interacts with water). Small amounts of H 2 S (as low as4 ppm) impact handling and economics and can result from res-ervoir souring initiated by the addition of sulfate to the reservoirduring waterflood operations and the consequent activities of sul-fate-reducing bacteria. 1 – 4 High H 2 S contents may be the result of thermochemical sulfate reduct ion in gas-bearing, high-temperature, carbonate, and anhydrite reservoirs, or off-structurein an overmature drainage area.

CO 2 levels in natural gas have a variety of sources and controls:• High contents of CO 2 (>∼15%) in natural gases may result

from high-temperature thermal decomposition of carbonate rocks(limestone and dolomite).

• Lower-level CO 2 ( ∼5%. High CO 2 content alsoincreases the cost of surface gas processing.

Source and Maturity Controls on HydrocarbonProducts and CompositionOrganic-matter type, depositional environment, and the sourcerock ’s level of thermal maturity determine primary (generative) oilquality. Organic-matter type provides initial constraints on theexpected hydrocarbon products and their distribution. Land-derived plant material tends to generate gas plus liquids, whilemarine algal organic matter generally produces liquids. Liquidsfrom land-plant organic matter are often lighter and waxier andcontain less sulfur and polar and asphaltenic material compared tomarine-algal-derived oils. Not all land-plant organic matter hasequal generation potential; some types are more oil-prone (e.g., theNiger Delta and southeast Asia are known for an abundance of land-plant-derived oil along with gas). Source rocks dominated byland-plant organic matter tend to show more lateral and verticalvariability in organic-matter type than those dominated by marinealgal organic matter.

The depositional environment in which source rocks are de-posited is also very important in controlling primary oil composi-

tion. Source rocks are most commonly deposited subaqueously inanoxic-to-dysoxic bottomwater conditions that promote the pres-ervation of organic matter. In marine depositional settings, sulfate-reducing bacteria rework sedimentary organic matter underanaerobic conditions, producing H 2 S as a byproduct. Clays usuallyprovide iron to the depositional environment, which reacts rapidlywith any available H 2 S to form iron sulfides (precursors of pyrite).When iron is not available, H 2 S produced by sulfate-reducingbacteria may accumulate to high levels and be incorporated intoorganic-sulfur compounds. Therefore, in clastic-dominated (shale)source-rock environments, sulfur is dominantly incorporated intomineral phases. In carbonate and marly depositional environmentswhere clays are scarce, organic matter tends to be sulfur-rich.Compared to clastic source rocks, carbonate and marly sourceswith sulfur-rich organic matter begin oil generation at lower ther-mal maturity levels and yield heavy, high-sulfur oil with moreresidua content and other detrimental components such as metals.Shale source rocks from depositional environments rich in clayand iron tend to generate lighter, sweeter oils.

The maturity level of a source rock is a measure of the domi-nantly thermal stress it has experienced. The level of maturityneeded for hydrocarbon generation depends on the organic-mattertype, composition, and depositional setting. For a given sourcerock, early-generated oils tend to be heavier and have poorer oilquality (e.g., lower API gravity and higher sulfur contents). Atprogressively higher levels of maturity, generated liquids containfewer high-molecular-weight hydrocarbons and polar components.Hence, oil quality and value typically increase at higher levels of maturity within the oil-generative “window ” (if maturity is too

Fig. 1—Reservoir temperature vs. gas/oil ratio (GOR) by level ofsolution gas biodegradation for oil reservoirs in an area with amarine organic-matter-type source. GOR generally declineswith increasing level of biodegradation; scf/STB×0.1781076=m 3 /m 3 .

Fig. 2—Reservoir temperature vs. %C 2+ hydrocarbons by levelof solution gas biodegradation for solution gases from oil res-ervoirs in an area with marine organic-matter-type source.Gases become drier with increasing levels of biodegradation.

Fig. 3—Reservoir temperature vs. %CO 2 by level of solution gasbiodegradation for solution gases from oil reservoirs in an areawith marine organic-matter-type source. CO 2 content generallyincreases with increasing levels of biodegradation.

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high, gas may be produced instead of oil). For an equivalent levelof biodegradation, higher-maturity oil typically maintains better oilquality than lower-maturity oil from the same source. Generalizedranges of initial (as-generated) hydrocarbon properties for differ-ent source-rock types, at their respective mainstage- generationmaturity levels, are summarized in Table 1.

Biodegradation and Impact on Oil QualityBacterial degradation of oils in reservoirs has long been recog-nized. 5 – 7 Many of the early examples that cited in-reservoir bio-degradation and oil-quality decline were from shallow, onshore oilfields in which meteoric water influx was suspected. This obser-

vation contributed to the dogma that biodegradation of oil wascarried out by aerobic bacteria only and required a supply of oxy-gen to the reservoir. 8 – 10 Shallow onshore reservoirs with hydro-dynamic drive from fresh meteoric influx are certainly prime can-didates for heavy biodegradation. However, as drilling progressedoffshore into deep water, observations of biodegradation in shal-low, cool reservoirs continued to be commonplace. In these areas,it was difficult to explain where fresh, oxygenated water could becoming from. This led to the conclusion that anaerobic bacteria,such as the sulfate-reducing bacteria, must be capable of biode-grading petroleum. Recent studies from the bacteriologic litera-ture 11 – 17 have verified that sulfate-reducing bacteria, iron oxide-reducing bacteria, and bicarbonate-reducing (fermenting) bacteriaare capable of biodegrading oils in reservoirs in the absence of dissolved oxygen. In addition to an oxygen source (free or com-bined), bacteria need water and certain nutrients to metabolizehydrocarbons. Adequate pore size and surface area are also nec-essary. The connections between oil quality, microbes, and reser-voir properties are summarized in Fig. 4.

Although traditional dogma also suggested that biodegradationmust occur at the oil/water contact, recent findings suggest thatbiodegradation may occur elsewhere in the hydrocarbon column.Irreducible (bound) water within the reservoir may provide anadequate water supply, and bacteria have been observed inhabitingthe interface between water adsorbed to mineral grains and hydro-carbons in pore spaces. The high solubility of water in natural gasat relatively low temperatures and pressures, especially if CO 2 ispresent, may further enhance biodegradation.

The reservoir temperature range is critical to bacterial degra-dation. Above temperatures of approximately 82 °C, petroleum-degrading bacterial activity is significantly inhibited. At tempera-

tures just below this limit, bacteria are generally operating at less-ened efficiency. Lower-temperature reservoirs (e.g.,


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at mainstage oil-window maturity levels ( ∼36 to 37 ° API with a

GOR of ∼

800 scf/STB). The complete suite of n-alkanes is intact,and n-alkanes are greater than adjacent isoprenoids (e.g., as moni-tored by pristane/ n-C 17 and phytane/ n-C 18 ratios). The unresolvedcomplex mixture (UCM) of branched and cyclic compounds underthe resolved peak envelope on the GC is small. With very slightbiodegradation, n-alkanes in the approximately C 8 –C15 range areattacked first, as illustrated in Fig. 5. By the next stage (slightbiodegradation), this carbon-number range is further depleted, andisoprenoid-to-alkane ratios increase as the >C 15+ n-alkanes areattacked. Note in Fig. 5 that at the slight biodegradation stage,pristane > n-C 17 and phytane > n-C 18 , and the UCM is slightlylarger. For moderate levels of biodegradation, n-alkanes are sig-nificantly depleted, and the UCM hump is much larger. The iso-prenoids survive, and the pristane/phytane ratio is still unalteredand virtually the same as the less-degraded oils. By the heavybiodegradation stage, virtually all n-alkanes and isoprenoids havebeen removed and the UCM hump is large.

For all the oils in the biodegradation series shown in Fig. 5, themultiring biomarkers remain unaltered, even at heavy levels of biodegradation. These compounds are not typically detected inGCs; rather, they are monitored by combination GC/mass spec-troscopy for genetic source and maturity information. These com-ponents are relatively resistant to biodegradation and are very use-ful in extracting geochemical affinities from highly degradedsamples and providing a means for correlation of unbiodegradedand biodegraded oils. Eventually, the biomarker components arealso subject to alteration as biodegradation goes beyond heavy intothe severe stage. Within the various biomarker groups, there is alsoa general order of removal by bacteria (Table 2). If biodegradation

reaches extremely severe levels, a series of compounds (25-nor-

demethylated hopanes) is formed in response to bacterially medi-ated ring-opening processes. The co-occurrence of demethylatedhopanes with less-resistant components (e.g., n-alkanes) is strongevidence for a multigeneration charge and degradation history,where severe biodegradation of an initial charge is followed bylater recharge and, possibly, additional biodegradation.

The biodegradation stages described herein and presented inTable 1 have been used to describe the alteration state of hydro-carbons in reservoirs and to describe the predicted biodegradationlevel as it relates to oil quality in unpenetrated compartments.Published biodegradation scales 21 have limited applicability foroil-quality assessments in the industry because they are focused onheavy and severe biodegradation when complete removal of cer-tain compound series (e.g., n -alkanes, isoprenoids) and the alter-ation of biomarker components occurs. However, the greatest im-pact on oil-quality parameters for conventional production occursat much lower levels of biodegradation. In deepwater offshoreplays, oil-quality reduction caused by biodegradation may render adiscovery uneconomic without proceeding to levels at which anyof the more resistant biomarker constituents have been altered.

An example of a complicated alteration history is shown in Fig.6. Geochemical analyses were performed on oils from two reser-voirs in the same well. The shallower reservoir contains the de-methylated hopane series, indicating that severe biodegradationhas occurred. It also contains a full suite of n-alkanes and regularhopanes, which are incompatible with the demethylated hopanesunless multiple charges have occurred. The present reservoir tem-perature (85 °C) is too high to support ongoing biodegradation.Therefore, the shallower oil was probably emplaced when the

very slight slight moderate heavy severemethaneethanepropaneiso -butanen -butane

pentanes

n -alkanesiso -alkanesisoprenoidsBTEX aromaticsalkylcyclohexanesn -alkanes, iso -alkanesisoprenoidsnapthalenes (C 10+)phenanthrenes, DBTschrysenesregular steranesC 30-C 35 hopanes

C 27-C 29 hopanestriaromatic steranesmonoaromatic steranesgammaceraneoleananeC 21-C 22 steranestricyclic terpanesdiasteranesdiahopanes25-norhopanes**seco-hopanes**

**Appearance, rather than removal of compounds (these c ompounds believed to be created during biodegradation).

C 1 5 - C 3 5

b i o m a r k e r s

C 1 5 - C 3 5

H C s

Level of Biodegradation

C 1 - C 5 g a s e s

C 6 - C 1 5

H C s

*Table represents a generalized sequence of degradation. Different biodegradation pathways (aerobic vs. anaerobic) and different types of bacteria will attack specific molecules and compound ranges. Degradation sequence is based on observation of reservoired oils and seabottom seeps. BTEX refers to benzene, toluene, ethylbenzene, and xylene.

TABLE 2—REMOVAL OF SELECTED COMPOUND GROUPS ATVARIOUS LEVELS OF BIODEGRADATION*



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reservoir was shallower and cooler than it is today. Severe bio-degradation was then followed by later recharge. Oil from the

deeper, hotter reservoir has a GC very similar to that for theshallower reservoir, with a full, unaltered suite of n-alkanes. How-ever, the deeper oil does not contain any demethylated hopanesand shows no other evidence of biodegradation. As a consequence,the deeper oil is 10 ° lighter in API gravity.

Progressive biodegradation almost invariably reduces oil qual-ity. As the high-quality saturated hydrocarbons are removed, thereis residual enhancement of the low-quality, high-molecular-weightmultiring hydrocarbons and the nonhydrocarbon compounds, suchas asphaltenes. These compositional changes lead to lower gravity,higher viscosity, and higher sulfur, nitrogen, and asphaltene con-tents. Metals, ash, and residua contents also are enhanced. Thesechanges result in lower value for the crude oil, diminished recov-ery efficiency, and possible additional production problems asso-ciated with handling and processing heavier oils. One oil-qualityparameter that does not always get worse with biodegradation iswax content. High wax content and high pour-point oils are com-mon in areas such as southeastern Asia. Because waxes are high-molecular-weight n-alkanes, they are attacked at slight-to-moderate biodegradation levels. Although this loss may contributeto decreased API gravity, a slight API decrease is often offsetby lowered pour points and less wax deposition in tubularsand facilities.

In addition to the concentration of low-quality oil componentsduring biodegradation, new compounds can be formed that nega-tively impact quality. Bacteria appear to manufacture acids, mostof which are naphthenic (i.e., cyclic) acids, during the biodegra-dation of petroleum. 22 Because of solubility differences, low-molecular-weight ( ∼C1 -C 5 ) acids occur predominantly in associated

formation waters, 23 while higher-molecular-weight species ( ∼C6+ )are concentrated in the oil phase. The distribution of the various

naphthenic acid species in oils is poorly understood. Acid contentsare usually monitored as a TAN determined by potentiometrictitration as per the ASTM D-664 method. This method is wroughtwith potential interferences and interpretive problems, 24 but itremains a standard method by which oils are assayed and valued.TAN generally increases with increasing levels of biodegrada-tion. The current activity of biodegrading organisms may be mostimportant in determining organic acid contents because acidsmay dissipate rapidly owing to relatively high water solubilityand reactivity.

Elevated naphthenic acid contents (TAN > ∼1 mg KOH /goil ) aredetrimental to crude-oil value because acids cause refinery equip-ment corrosion at high temperatures. 25 – 27 This can result in anadditional valuation debit. Naphthenic acids and their salts (naph-thenates) also may lead to the formation of emulsions upon pro-duction of biodegraded oils. Sometimes these emulsions can betight and difficult to break by conventional means. The additionalexpense associated with breaking emulsions, especially on produc-tion platform sites in deep water, can further challenge field eco-nomics. Low-molecular-weight organic acids in water often impartvery foul odors and can cause wastewater disposal problems inrefineries processing some biodegraded oils.

Biodegradation and Impact on Gas QualityBiodegradation of natural gases generally decreases the GOR (so-lution gas in oil legs) and wet gas content and increases the relativeproportion of methane (gas caps and solution gases), as illustratedin Figs. 1 through 3. Biodegradation also may cause CO 2 contentsto increase (a byproduct of bacterial oxidation). In addition to

Fig. 5 —Whole oil GCs illustrating the progression of increasing biodegradation and the decline in oil quality. All oils are from thesame basin, but from different depths and or wells, and have essentially identical source and maturity, as indicated by biomarkerdistributions (not shown). Increasing pristane/ n- C 17 ratio illustrates the preference for n -alkanes over isoprenoids in biodegrada-tion. N -alkanes over the approximately C 8 –C15 range are attacked first. (Pr=pristane; Ph=phytane; MCH=methyl cyclohexane;n -C 6 ...=homologous n -alkane series.)

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compositional changes, bacterial degradation causes carbon isoto-pic changes in individual gas components. Geochemical analysesof reservoir gases from around the world have shown that bacteriapreferentially attack propane during the initial stages of biodegra-dation. 27,28 The decrease in concentrations of propane is accom-panied by a fractionation of the stable carbon isotopic composition.During biodegradation, the residual (parent) propane fraction be-comes enriched in the heavier 13 C isotope, whereas the CO 2byproduct (daughter) is isotopically enriched in 12 C. Bacterial-enzymatic processes and C-C bond energies control these compo-sitional and isotopic changes. 29 Less energy is required to break a12 C- 12 C than a 12 C- 13 C bond, and bacteria follow the path of greatest reward (energy from oxidation) for the least amount of work (bond energies). A comparison of gas analyses from a NorthSea field (see Table 2 and Fig. 7) with gases from two nearbyfields indicates that the reservoirs contain three distinct gas com-positional groupings. All fields received the same hydrocar-bon charge.

Relatively heavy isotopic compositions for wet gas (C 2+ ) com-ponents in Field C gases suggest significant biodegradation. Gasesfrom Fields B and A show less intense alteration (Fig. 7). Therelative intensity of biodegradation becomes apparent when theisotopic difference between propane and n-butane is plottedagainst the isotopic composition of propane (Fig. 8). This trendresults from the fact that propane is degraded preferentially ton-butane. For samples from Field B, biodegradation is greatest forSample 1 and least for Sample 12. Molecular compositions alsosupport the degradation trend indicated by isotopic compositions.

In biodegraded samples, propane is depleted relative to n-butane,and n-butane is depleted relative to i-butane.

Other In-Reservoir Alteration ProcessesIn addition to biodegradation, other in-reservoir alteration pro-cesses can impact hydrocarbon quality. These include water wash-ing, phase separation, gravity segregation, gas de-asphalting, andin-reservoir oil cracking. These processes are reviewed as followsand summarized in Fig. 9.

Fig. 6 —Comparison of whole oil GCs and mass/charge (m/z) 177 biomarker scans for two reservoirs from Well A. The deeperreservoir shows no evidence of biodegradation, while the shallower shows biomarker evidence of severe biodegradation, followedby recharge with fresh oil. Current reservoir temperatures in both reservoirs are too high for active biodegradation. Geochemicalanalyses constrain the filling and degradation history of reservoirs. [C28DM=C 28 -25-nor-demethylated hopane; C29DM=C 29 -25-nor-demethylated hopane; C29H=C 29 hopane; C29Ts=C 29 -22,29,30-norhopane; C29M=C 29 normoretane; OL=oleanane; C30DM(1) &(2)= C 30 -25-nor-demethylated hopanes; C31DM=C 31 -25-nor-demethylated hopanes; C31H=C 31 hopanes; C32DM=C 32 -25-nor-demethylated hopanes; C32H=C 32 hopanes; C33H=C 33 hopanes; C34H=C 34 hopanes; C35H=C 35 hopanes; peak labels on whole oilGCs as per Fig. 5.]

δ

Fig. 7 —Average wet gas isotope ratios for select North Seafields. Stable carbon isotopic ratios are plotted against the wet-gas components.



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Water Washing. Alteration of oil by water washing occurs whenthe most water-soluble components (e.g., light aromatic hydrocar-bons) are removed from the oil by contact with formation waters.The limited solubility of hydrocarbons in water increases at highertemperatures and pressures and declines with increasing salin-ity. 30,31 Water washing often occurs simultaneously with biodeg-radation in reservoirs < 80 °C. The two processes are sometimesdifficult to distinguish.

Phase Separation. When both gas and oil phases are present in areservoir, faulting or other seal-related processes may allow gas toescape preferentially. This gas may migrate to a shallower reser-voir where lower pressure and temperature conditions cause exso-lution of a lighter liquid phase. The residual oil remaining in thedeeper reservoir will be light-end depleted and generally of poorerquality than it was before gas loss 32,33 occurred. Phase separationis generally recognized by the relative enrichment or depletion of more gas-soluble (e.g., saturated hydrocarbons) vs. less gas-

soluble (e.g., aromatic hydrocarbon) components of similar mo-lecular weights.

Gravity Segregation. The stratification of an oil column by den-sity is referred to as gravity segregation. This process typicallyrequires high permeability and most often occurs in steeply dip-ping reservoirs where heavy-end components from the oil settle tothe lower portion of the reservoir. There may be a time require-ment for the development of a segregated column.

Gas De-Asphalting. De-asphalting of oils in the refinery is oftenaccomplished by bubbling natural gas through the oil. This desta-bilizes heavy asphaltene molecules, causing their precipitation.This same process can occur in reservoirs if gas is directed into anoil reservoir through diapir-related reservoir tilting or other geo-logic processes. Tar mats commonly result from in-reservoir gasde-asphalting.

In-Reservoir Cracking. The thermal cracking of oils in reservoirsoccurs when the reservoirs are exposed to high temperatures(>∼150 °C), usually because of deep burial. As heavier oil compo-nents thermally crack into lighter molecules, a lighter hydrocarbonproduct results. Should burial to higher temperatures continue,further cracking might result, ultimately yielding gas and solidbitumen residue (pyro-bitumen).

Applications of Biodegradation and Oil Qualityto Prospect Evaluation and Risking

Exploration Risking and Block Ranking. Oil-quality risking isan important assessment parameter when making exploration de-cisions regarding the viability of plays or prospects. Calibrations of expected reservoir temperature and biodegradation level to oil-quality parameters provide the groundwork for predrill predictions.Local calibration of parameters, or selection of appropriate ana-logs, is critical because degradation trends are dependent on ef-fective hydrocarbon system(s) and are tied to source type, sourcedepositional environment, maturity, and filling history. 34 Selectionof the appropriate biodegradation trend calibration is based on thegeochemistry of nearby discoveries or shows, if available. In manydeepwater frontier areas, surface hydrocarbon seeps provide initialinformation on source type and maturity level before any drill-ing. 35 In the absence of geochemical data on actual hydrocarbonsamples, the characteristics of the effective source can be esti-

mated from depositional models and thermal yield calculations.36

Field Development. Geochemical analyses and interpretations,when integrated with pressure trends and a geologic and geophysi-cal framework, provide important input to development and pro-duction planning. Exploitation geochemical approaches are espe-cially pertinent to help determine continuity or segmentation of reservoir compartments when pressure or geologic data are am-biguous. Understanding reservoir continuity is critical to optimiz-ing field-development planning. Identification of reservoir seg-mentation is also important to the efficient placement of injector/ producer pairs when pressure maintenance by water injection isplanned. Differences in biodegradation level can sometimes indi-cate segmented compartments. Geochemical analyses also candetect gradients in hydrocarbon properties within continuousreservoirs (e.g., caused by gravity segregation). Recognition of such gradients is important for reservoir models and field planning.In heavy-oil fields, geochemical analyses of sidewall cores canhelp to identify oil-quality variations and “sweet spots ” for tar-geted production.

Corrosion/Facilities Design. As exploration proceeds into deeperwater offshore, biodegraded oils appear to be more commonlyencountered in many basins as cool, shallow reservoirs are pen-etrated. An increasing number of elevated TAN oils will thereforebe developed and produced in the future. In addition to lower crudevalues resulting from high-temperature corrosion problems in re-fineries, biodegraded oils tend to have associated problems such astight emulsion formation. The need to handle and remediate pro-

δ

δ

δ

Fig. 8 —Biodegradation of wet gases in select North Sea fields.The difference in isotopic ratios between propane and n -butaneis plotted against the stable carbon isotopic ratio of propane toshow the increase in biodegradation of wet gases toward theupper right in the plot. Sample labels refer to the sample num-bers in Table 3.

OIL & GAS QUALITY:

Fig. 9 —Summary of factors affecting oil and gas quality. Sourcefacies and level of maturity control generative hydrocarbon(HC) composition. After potential fractionation along the migra-tion pathway, a range of possible processes can occur in thereservoir, including biodegradation at temperatures lower thanapproximately 82 °C. The timing of HC charge event(s) and thetemperature history of the reservoir after filling also ultimatelycontribute to the quality of oil and gas in the reservoir.



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duced fluids on deepwater production sites will continue to impactand challenge economic scenarios. An increased understanding of biodegradation processes, including the origin and molecular-weight-range distributions of organic acids and related compoundsin oils and waters, can aid in early recognition and reconciliationof potential problems while in the planning stages. This permitsbetter early valuation of new crude-oil grades and early recogni-tion of processing and handling requirements impacting both up-stream and downstream business decisions.

Conclusions

Oil and gas quality determines the direct value of a hydrocarbonproduct and the economics of its development. Hydrocarbon qual-ity is determined by source-rock composition and thermal maturityand by the degree of alteration. Biodegradation is the most impor-tant process altering reservoir hydrocarbons in many areas, butwater washing, phase separation, gravity segregation, gas de-asphalting, and thermal cracking also can impact hydrocarbonquality. Biodegradation, active at reservoir temperatures < ∼80°C,can significantly reduce hydrocarbon quality, particularly in theshallow, cool reservoirs that have dominated recent deepwaterexploration. As biodegrading organisms attack higher-quality hy-drocarbon components, they residually concentrate poor-qualitycomponents, including sulfur, asphaltenes, and residua. Becausebacteria attack different hydrocarbon compounds based on an or-der of preference, the biodegradation stage can be determinedbased on the alteration of specific compound classes and structures.

The classification of biodegradation stages presented herein isimportant for describing and predicting oil and gas quality. Somecompounds are produced during biodegradation, notably naph-thenic acids and demethylated hopanes. Naphthenic acids contrib-ute to oil-quality debits and may cause additional processing anddownstream handling problems. Bacterial activity is strongly con-trolled by temperature, but it also may be impacted by formation-water salinity, availability of free or combined oxygen, reservoircharacteristics, and the timing of charge(s).

Gas biodegradation results in the decline and loss of wet com-ponents and, often, the production of undesirable gases such asCO 2 . The stage of gas biodegradation is not necessarily linked tothat of the associated oil.

Geochemical analyses are relatively quick and inexpensive andprovide critical information regarding oil and gas quality. If cali-bration data are available, predictive models of oil and gas degra-dation often can be constructed that improve predrill estimates of hydrocarbon quality during the exploration and developmentphases. After production commences, routine collection and analy-sis of fluid samples at little cost can allow changes in productioncharacteristics to be determined and efficiently exploited. Appli-cations include recognition of the production-stimulated break-down of natural reservoir baffles, rapid and inexpensive diagnosisof tubing or casing damage, and production allocation from com-mingled reservoirs. It is therefore critical to collect and analyzerepresentative samples through all phases of a field ’s history.Wireline or drillstem test samples from early exploration oftenprovide the only characterization of individual reservoir zones be-fore commingling. Even the analysis of sidewall cores in reservoirzones can provide important information. Later, routine (e.g.,monthly) sampling of the production stream permits compositionalchanges to be monitored and evaluated.

Acknowledgments

The authors thank ExxonMobil Upstream Research Co. for per-mission to publish this work. Productive discussions with SteveHinton and Winston Robbins at ExxonMobil Corporate StrategicResearch Co. are gratefully acknowledged. Constructive review of the manuscript by Paul Mankiewicz (EMURC; during the great

Houston Flood of 2001) and additional discussions and insightswere most helpful. W. Allen Young provided useful comments.Jan Herbst assisted in figure and manuscript preparation. The SPEEditorial Review Committee is acknowledged for their efforts andeditorial suggestions that improved this paper.

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SI Metric Conversion Factors°API 41.5/(131.5+ °API) g/cm 3

bbl × 1.589 873 E –01 m 3

ft × 3.048* E –01 m°F (°F–32)/1.8 °C

*Conversion factor is exact.

Lloyd M. Wenger is a petroleum geochemist with ExxonMobilUpstream Research Co. His work focus has been on the appli-cation of geochemical technologies to exploration, develop-ment, and production problems and linkage to downstreamorganizations for early recognition of value and handling/processing issues. After many years of working in the Gulf Coastand the Gulf of Mexico, he has worked primarily in west Africa,including Nigeria and Congo, and he is currently involved indevelopment and exploration activities in deepwater Angola.Wenger holds a PhD degree in organic geochemistry fromRice U. Cara L. Davis has been with ExxonMobil Upstream Re-search for 5 years, focusing on oil quality and reservoir geo-chemistry research and applications. She holds a PhD degreein geology (specializing in organic geochemistry) from IndianaU. Gary H. Isaksen is Research Supervisor for Petroleum Geo-chemistry with ExxonMobil Upstream Research Co. Since join-ing Exxon in 1985, the major themes of his work have beenintegration of geology and petroleum geochemistry, molecu-lar geochemistry, play-element risking, and applications ofgeochemistry to field development and production. From1993 to 1995, he worked frontier and established plays withinU.K. and Norwegian acreage, and from 1997 to 1999, heworked regional- and prospect-scale assessments within Azer-baijan, Turkmenistan, Uzbekistan, and Russia. His current geo-science focus is on applied research to solve exploration, de-velopment, and production problems. Isaksen holds a PhD de-gree in petroleum geochemistry and petroleum geology fromthe U. of Bergen, Norway.


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Biodegradation and Impact on Oil Quality - Wenger Et Al - SPE