Multiple Controls on Petroleum Biodegradation and Impact on Oil Quality

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Multiple Controls on Petroleum Biodegradation and Impact on

Oil Quality

Lloyd M. Wenger, Cara L. Davis,andGary H. Isaksen,ExxonMobil Upstream Research Co.

Summary

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

<80°C. However, other controls on biodegradation may also have significant effects, making predrill prediction of oil quality difficult in some areas.

It has long been observed that fresh, oxygenated waters in contact with reservoir oil can cause extensive aerobic biodegradation. More recently, it has been recognized that anaerobic sulfate- reducing and fermenting bacteria also can degrade petroleum.

Highly saline formation waters may inhibit bacterial degradation and effectively shield oils from oil-quality deterioration. The timing of hydrocarbon charge(s) and the post-charge temperature history of the reservoir can have major effects on oil quality.

Reservoirs undergoing current charging with hydrocarbons may overwhelm the ability of bacteria to degrade the oil, resulting in better-than-anticipated oil quality. Fresh charge to reservoirs con- taining previously degraded oil will upgrade oil quality. Calibrated methods of oil-quality risking, based on a detailed evaluation of reservoir charge and temperature history and local controls on biodegradation, need to be developed on a play and prospect basis.

Introduction

Biodegradation of hydrocarbons, and the resulting decline in oil quality, is common in reservoirs cooler than approximately 80°C.

Petroleum biodegrading organisms have a specific order of preference for compounds that they remove from oils and gases. Pro- gressive degradation of crude oil tends to remove saturated hydrocarbons first, concentrating heavy polar and asphaltene components in the residual oil. This leads to decreasing oil quality by lowering API gravity while increasing viscosity, sulfur, and metals contents. In addition to lowering reservoir recovery efficiencies, the economic value of the oil generally decreases with biodegradation owing to a decrease in refinery distillate yields and an increase in vacuum residua yields. Furthermore, biodegradation leads to the formation of naphthenic acid compounds, which increase the acidity of the oil (typically measured as Total Acid Number, or TAN). Increased TAN may further reduce the value of the oil and may contribute to production and downstream handling problems such as corrosion and the formation of emulsions.

Reservoir gas caps and solution gases also undergo biodegradation in cool reservoirs. C2+ gas components, particularly propane (C3) and n-butane (n-C4), are preferentially removed from natural gas, making biodegraded gases drier through the enrich-

ment of methane (C1). Most biodegrading organisms also generate carbon dioxide (CO2) as a byproduct when they degrade hydrocarbons, increasing the CO2content of solution gas or gas caps.

Elevated CO₂contents can impact development economics nega- tively by necessitating the use of special steels to resist corrosion.

Evaluating the decline in hydrocarbon quality associated with biodegradation has become critical in recent years as offshore drilling has progressed into deeper water depths. In many areas (e.g., offshore west Africa, Brazil, mid-Norway, South Caspian, eastern Canada), reservoir targets in deep-to-ultradeep water are shallow, and geothermal gradients are low. These factors make oil quality a major risk because decreased recovery efficiency and oil value compound with higher deepwater operating costs to significantly impact economics, even on major discoveries.

Risking oil quality predrill in shallow compartments is a major challenge. Reservoir temperature and the consequent level of biodegradation must be estimated. To do this, knowledge of the primary (generative), undegraded oil composition is essential. The major controls on primary oil composition are characteristics of the source rock: (1) organic-matter type, (2) depositional environment, and (3) level of maturity. These controls exert the dominant influence on as-generated gravity, viscosity, gas/oil ratio (GOR), sulfur, and residua contents. Geochemical analyses of natural oil seepage on the sea bottom often provide direct evidence for evaluation of source-rock characteristics (sedimentary facies) and maturity. Thermal modeling of hydrocarbon generation timing and mapping of source rocks from seismic also contribute to the understanding of the hydrocarbon system.

After emplacement in cool reservoirs, hydrocarbons are subject to biodegradation, in addition to a number of other potential alteration processes, including water washing, phase separation, gravity segregation, and de-asphalting. Some reservoirs have a complex history with multiple episodes of charge and degradation. Fresh charge to a reservoir may upgrade quality, while earlier episodes of severe degradation (possibly when the reservoir was shallower and cooler than at present) may downgrade quality. Thus, knowledge of generation and charge timing and reservoir temperature history can help improve predrill predictions of oil quality.

Oil and Gas Quality

Oil and gas quality reflects the compositional characteristics of hydrocarbons that impact the economic viability of an exploration, development, or production opportunity. Compositions may affect the direct value of the product (e.g., crude valuation relative to a benchmark oil) or the development or facility costs (e.g., additional wells required, emulsion processing, use of special steels), or they may even cause the oil to be unrecoverable. Typical oil- quality properties include API gravity, viscosity, sulfur, asphaltene, and metals (e.g., vanadium, nickel, and iron content), residua (e.g., vacuum residua or Conradson carbon content), acidity (TAN), wax content or pour point, and sensitivity to emulsion formation upon production. Biodegradation impacts essentially all oil-quality properties.

Gas quality reflects the content and distribution of hydrocarbon gas constituents and the presence and content of nonhydrocarbon gases, such as H₂S and CO₂. Within the hydrocarbon gases, heat- ing value (e.g., BTUs) increases with methane content and declines with wet gas (C₂₊) content on a per mass unit basis. Generally, the increased value of individual natural gas liquids encourages the

This paper (SPE 80168) was revised for publication from paper SPE 71450, first presented at the 2001 SPE Annual Technical Conference and Exhibition, New Orleans, 30 Septem- ber–3 October. Original manuscript received for review 18 November 2001. Revised manuscript received 29 July 2002. Paper peer approved 22 August 2002.

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separation of wet gas components during gas processing. Gas biodegradation decreases GOR(Fig. 1)and wet gas percentages (Fig. 2)and increases the percentage of CO2(Fig. 3).

H2S in gas causes significant handling and processing expense because of its high toxicity and corrosivity (sulfuric acid is formed when H2S interacts with water). Small amounts of H2S (as low as 4 ppm) impact handling and economics and can result from reservoir souring initiated by the addition of sulfate to the reservoir during waterflood operations and the consequent activities of sulfate-reducing bacteria.^1–4High H₂S contents may be the result of thermochemical sulfate reduction in gas-bearing, high- temperature, carbonate, and anhydrite reservoirs, or off-structure in an overmature drainage area.

CO₂levels in natural gas have a variety of sources and controls:

• High contents of CO₂(>∼15%) in natural gases may result from high-temperature thermal decomposition of carbonate rocks (limestone and dolomite).

• Lower-level CO₂(<2.5%) in gases may originate from early thermal maturation of organic matter in source rocks (although much generated CO₂is subject to loss owing to high water solubility). These sources of CO₂can be differentiated by their carbon isotopic compositions. Land-plant organic material generates more CO2than marine-algal organic matter.

• Oxidation of oil and gas by hydrocarbon-degrading bacteria in shallow, cool reservoirs may produce elevated CO2 contents (Fig. 3). CO2in gas causes corrosion in production facilities because of its acidity when dissolved in water and can require the use of special steels when contents are >∼5%. High CO2content also increases the cost of surface gas processing.

Source and Maturity Controls on Hydrocarbon Products and Composition

Organic-matter type, depositional environment, and the source rock’s level of thermal maturity determine primary (generative) oil quality. Organic-matter type provides initial constraints on the expected hydrocarbon products and their distribution. Land- derived plant material tends to generate gas plus liquids, while marine algal organic matter generally produces liquids. Liquids from land-plant organic matter are often lighter and waxier and contain less sulfur and polar and asphaltenic material compared to marine-algal-derived oils. Not all land-plant organic matter has equal generation potential; some types are more oil-prone (e.g., the Niger Delta and southeast Asia are known for an abundance of land-plant-derived oil along with gas). Source rocks dominated by land-plant organic matter tend to show more lateral and vertical variability in organic-matter type than those dominated by marine algal organic matter.

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

tion. Source rocks are most commonly deposited subaqueously in anoxic-to-dysoxic bottomwater conditions that promote the pres- ervation of organic matter. In marine depositional settings, sulfate- reducing bacteria rework sedimentary organic matter under anaerobic conditions, producing H₂S as a byproduct. Clays usually provide iron to the depositional environment, which reacts rapidly with any available H₂S to form iron sulfides (precursors of pyrite).

When iron is not available, H₂S produced by sulfate-reducing bacteria may accumulate to high levels and be incorporated into organic-sulfur compounds. Therefore, in clastic-dominated (shale) source-rock environments, sulfur is dominantly incorporated into mineral phases. In carbonate and marly depositional environments where clays are scarce, organic matter tends to be sulfur-rich.

Compared to clastic source rocks, carbonate and marly sources with sulfur-rich organic matter begin oil generation at lower thermal maturity levels and yield heavy, high-sulfur oil with more residua content and other detrimental components such as metals.

Shale source rocks from depositional environments rich in clay and iron tend to generate lighter, sweeter oils.

The maturity level of a source rock is a measure of the dominantly thermal stress it has experienced. The level of maturity needed for hydrocarbon generation depends on the organic-matter type, composition, and depositional setting. For a given source rock, early-generated oils tend to be heavier and have poorer oil quality (e.g., lower API gravity and higher sulfur contents). At progressively higher levels of maturity, generated liquids contain fewer 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 40

50 60 70 80 90

200 400 600 800 1,000

GOR, scf/STB ReservoirTemperature,oC

Level of Gas Biodegradation

NoneSlight Moderate Heavy Severe

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

m³/m³.

ReservoirTemperature,oC 40 50 60 70 80 90 100

0 7 %C₂₊HC_s 14 21

Level of Gas Biodegradation

NoneSlight Moderate Heavy Severe

Fig. 2—Reservoir temperature vs. %C2+hydrocarbons by level of 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.

40 50 60 70 80 90

0.0 2.0 4.0 6.0 8.0 10.0 12.0

%CO₂

ReservoirTemperature,oC Level of Gas

Biodegradation NoneSlight Moderate Heavy Severe

Fig. 3—Reservoir temperature vs. %CO₂by level of solution gas biodegradation for solution gases from oil reservoirs in an area with marine organic-matter-type source. CO₂content generally increases with increasing levels of biodegradation.

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high, gas may be produced instead of oil). For an equivalent level of biodegradation, higher-maturity oil typically maintains better oil quality than lower-maturity oil from the same source. Generalized ranges of initial (as-generated) hydrocarbon properties for different source-rock types, at their respective mainstage- generation maturity levels, are summarized inTable 1.

Biodegradation and Impact on Oil Quality

Bacterial degradation of oils in reservoirs has long been recognized.^5–7Many of the early examples that cited in-reservoir biodegradation and oil-quality decline were from shallow, onshore oil fields in which meteoric water influx was suspected. This observation contributed to the dogma that biodegradation of oil was carried out by aerobic bacteria only and required a supply of oxygen to the reservoir.^8–10Shallow onshore reservoirs with hydro- dynamic drive from fresh meteoric influx are certainly prime can- didates for heavy biodegradation. However, as drilling progressed offshore into deep water, observations of biodegradation in shallow, cool reservoirs continued to be commonplace. In these areas, it was difficult to explain where fresh, oxygenated water could be coming from. This led to the conclusion that anaerobic bacteria, such as the sulfate-reducing bacteria, must be capable of biodegrading petroleum. Recent studies from the bacteriologic litera- ture^11–17have verified that sulfate-reducing bacteria, iron oxide- reducing bacteria, and bicarbonate-reducing (fermenting) bacteria are capable of biodegrading oils in reservoirs in the absence of dissolved oxygen. In addition to an oxygen source (free or combined), bacteria need water and certain nutrients to metabolize hydrocarbons. Adequate pore size and surface area are also nec- essary. The connections between oil quality, microbes, and reservoir properties are summarized inFig. 4.

Although traditional dogma also suggested that biodegradation must occur at the oil/water contact, recent findings suggest that biodegradation may occur elsewhere in the hydrocarbon column.

Irreducible (bound) water within the reservoir may provide an adequate water supply, and bacteria have been observed inhabiting the interface between water adsorbed to mineral grains and hydrocarbons in pore spaces. The high solubility of water in natural gas at relatively low temperatures and pressures, especially if CO2is present, may further enhance biodegradation.

The reservoir temperature range is critical to bacterial degradation. Above temperatures of approximately 82°C, petroleum- degrading bacterial activity is significantly inhibited. At temperatures just below this limit, bacteria are generally operating at less- ened efficiency. Lower-temperature reservoirs (e.g., <50°C) are much more likely to undergo heavy-to-severe degradation. Forma- tion-water salinity also may impact the efficiency of biodegrading bacteria, necessitating consideration of the combined temperature- salinity environment. High formation-water salinities appear to lower the maximum temperature at which petroleum biodegradation can occur.¹¹Thus, it is possible that relatively shallow, cool reservoirs in salt-diapir provinces with high formation-water salinity levels may protect oils from biodegradation. This is difficult to document conclusively because formation-water salinity levels are known to be highly variable around salt diapers,¹⁸ and ad-

equate water samples or log data to map isohaline contours rarely exist. In addition, the recharging of reservoirs with fresh hydrocarbons along salt diapir faults may result in better-than-expected oil quality. Collapsed salt stocks associated with salt diapirs, particularly when source-rock intervals are penetrated by the stock, are thought to be among the most effective hydrocarbon migration pathways to reservoirs.^19,20In areas with active hydrocarbon systems, it can be difficult to determine whether relatively undegraded oils in cool reservoirs adjacent to salt are the result of reduced biodegradation caused by high water salinity or the result of a very recent hydrocarbon charge.

The impact of biodegradation on oil-quality parameters can be significant. As biodegradation progresses, compounds are removed from oil according to the sequence shown in Table 2.

Although different bacterial types and reservoir environments do have some effect on the order of compounds removed, the general order-of-preference trends described are usually applicable. The straight chain n-alkanes are typically attacked before branched saturates (e.g., isoprenoids), cyclic saturates, and aromatic hydrocarbons. A series of whole oil gas chromatograms (GCs), which illustrate the impact of increasing biodegradation levels on GC appearance and bulk fluid properties, is illustrated inFig. 5.All these oils are from the same basin and have been generated from the same source-rock facies at similar maturities. The multiringed biomarker compounds tend to be resistant through moderate-to- heavy biodegradation levels, and they provide an excellent means of correlating biodegraded and unbiodegraded oils. Large differences in GC distributions and bulk properties of the oils shown in Fig. 6are tied directly to the level of biodegradation.

The unbiodegraded oil in Fig. 5 largely reflects the composition of the original oil as generated from its marine shale source rock

Oil Quality

Microorganisms Reservoir Properties

Specific Biodegradation Controls on Oil Biodegradation

Growth Requirements - Different microbes degrade

different oil components - Reservoir properties restrict

the variety of HC degrading microbes

- Availability of oxidant ( e.g., O2, FeO, SO4, HCO3) - Salinity

- Temperature

- Porosity/permeability/surface area

Fig. 4—Connections between oil quality, microbes, and reser- voir properties. (Figure provided by Steve Hinton, ExxonMobil Corporate Strategic Research Co.)

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at mainstage oil-window maturity levels (∼36 to 37° API with a GOR of∼800 scf/STB). The complete suite ofn-alkanes is intact, andn-alkanes are greater than adjacent isoprenoids (e.g., as monitored by pristane/n-C₁₇and phytane/n-C₁₈ratios). The unresolved complex mixture (UCM) of branched and cyclic compounds under the resolved peak envelope on the GC is small. With very slight biodegradation,n-alkanes in the approximately C₈–C₁₅range are attacked first, as illustrated in Fig. 5. By the next stage (slight biodegradation), this carbon-number range is further depleted, and isoprenoid-to-alkane ratios increase as the >C₁₅₊ n-alkanes are attacked. Note in Fig. 5 that at the slight biodegradation stage, pristane >n-C17 and phytane >n-C18, and the UCM is slightly larger. For moderate levels of biodegradation,n-alkanes are significantly depleted, and the UCM hump is much larger. The isoprenoids survive, and the pristane/phytane ratio is still unaltered and virtually the same as the less-degraded oils. By the heavy biodegradation stage, virtually alln-alkanes and isoprenoids have been removed and the UCM hump is large.

For all the oils in the biodegradation series shown in Fig. 5, the multiring biomarkers remain unaltered, even at heavy levels of biodegradation. These compounds are not typically detected in GCs; rather, they are monitored by combination GC/mass spec- troscopy for genetic source and maturity information. These components are relatively resistant to biodegradation and are very useful in extracting geochemical affinities from highly degraded samples and providing a means for correlation of unbiodegraded and biodegraded oils. Eventually, the biomarker components are also subject to alteration as biodegradation goes beyond heavy into the severe stage. Within the various biomarker groups, there is also a 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 demethylated hopanes with less-resistant components (e.g.,n-alkanes) is strong evidence for a multigeneration charge and degradation history, where severe biodegradation of an initial charge is followed by later recharge and, possibly, additional biodegradation.

The biodegradation stages described herein and presented in Table 1 have been used to describe the alteration state of hydrocarbons in reservoirs and to describe the predicted biodegradation level as it relates to oil quality in unpenetrated compartments.

Published biodegradation scales²¹ have limited applicability for oil-quality assessments in the industry because they are focused on heavy and severe biodegradation when complete removal of certain compound series (e.g.,n-alkanes, isoprenoids) and the alteration of biomarker components occurs. However, the greatest impact on oil-quality parameters for conventional production occurs at much lower levels of biodegradation. In deepwater offshore plays, oil-quality reduction caused by biodegradation may render a discovery uneconomic without proceeding to levels at which any of 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 reservoirs in the same well. The shallower reservoir contains the demethylated hopane series, indicating that severe biodegradation has occurred. It also contains a full suite ofn-alkanes and regular hopanes, which are incompatible with the demethylated hopanes unless multiple charges have occurred. The present reservoir temperature (85°C) is too high to support ongoing biodegradation.

Therefore, the shallower oil was probably emplaced when the very slight slight moderate heavy severe

methane ethane propane iso-butane n-butane pentanes

n-alkanes iso-alkanes isoprenoids BTEX aromatics alkylcyclohexanes n-alkanes, iso-alkanes isoprenoids

napthalenes (C10+) phenanthrenes, DBTs chrysenes

regular steranes C30-C35 hopanes C27-C29 hopanes triaromatic steranes monoaromatic steranes gammacerane oleanane C21-C22 steranes tricyclic terpanes diasteranes diahopanes 25-norhopanes**

seco-hopanes**

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

C15-C35 biomarkersC15-C35 HCs

Level of Biodegradation

C1-C5 gasesC6-C15 HCs

*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 AT VARIOUS LEVELS OF BIODEGRADATION*

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reservoir was shallower and cooler than it is today. Severe biodegradation was then followed by later recharge. Oil from the deeper, hotter reservoir has a GC very similar to that for the shallower reservoir, with a full, unaltered suite ofn-alkanes. How- ever, the deeper oil does not contain any demethylated hopanes and shows no other evidence of biodegradation. As a consequence, the deeper oil is 10° lighter in API gravity.

Progressive biodegradation almost invariably reduces oil quality. As the high-quality saturated hydrocarbons are removed, there is residual enhancement of the low-quality, high-molecular-weight multiring hydrocarbons and the nonhydrocarbon compounds, such as asphaltenes. These compositional changes lead to lower gravity, higher viscosity, and higher sulfur, nitrogen, and asphaltene contents. Metals, ash, and residua contents also are enhanced. These changes result in lower value for the crude oil, diminished recovery efficiency, and possible additional production problems associated with handling and processing heavier oils. One oil-quality parameter that does not always get worse with biodegradation is wax content. High wax content and high pour-point oils are common 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 contribute to decreased API gravity, a slight API decrease is often offset by lowered pour points and less wax deposition in tubulars and facilities.

In addition to the concentration of low-quality oil components during biodegradation, new compounds can be formed that nega- tively impact quality. Bacteria appear to manufacture acids, most of which are naphthenic (i.e., cyclic) acids, during the biodegradation of petroleum.²² Because of solubility differences, low- molecular-weight (∼C₁-C₅) acids occur predominantly in associated

formation waters,²³while 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 contents are usually monitored as a TAN determined by potentiometric titration as per the ASTM D-664 method. This method is wrought with potential interferences and interpretive problems,²⁴ but it remains a standard method by which oils are assayed and valued.

TAN generally increases with increasing levels of biodegradation. The current activity of biodegrading organisms may be most important in determining organic acid contents because acids may dissipate rapidly owing to relatively high water solubility and reactivity.

Elevated naphthenic acid contents (TAN >∼1 mgKOH/goil) are detrimental to crude-oil value because acids cause refinery equip- ment corrosion at high temperatures.^25–27 This can result in an additional valuation debit. Naphthenic acids and their salts (naph- thenates) also may lead to the formation of emulsions upon production of biodegraded oils. Sometimes these emulsions can be tight and difficult to break by conventional means. The additional expense associated with breaking emulsions, especially on production platform sites in deep water, can further challenge field economics. Low-molecular-weight organic acids in water often impart very foul odors and can cause wastewater disposal problems in refineries processing some biodegraded oils.

Biodegradation and Impact on Gas Quality Biodegradation of natural gases generally decreases the GOR (solution gas in oil legs) and wet gas content and increases the relative proportion of methane (gas caps and solution gases), as illustrated in Figs. 1 through 3. Biodegradation also may cause CO₂contents to 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 the same basin, but from different depths and or wells, and have essentially identical source and maturity, as indicated by biomarker distributions (not shown). Increasing pristane/n-C₁₇ratio illustrates the preference forn-alkanes over isoprenoids in biodegrada- tion. N-alkanes over the approximately C₈–C₁₅ range are attacked first. (Pr=pristane; Ph=phytane; MCH=methyl cyclohexane;

n-C₆...=homologousn-alkane series.)

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compositional changes, bacterial degradation causes carbon isotopic changes in individual gas components. Geochemical analyses of reservoir gases from around the world have shown that bacteria preferentially attack propane during the initial stages of biodegradation.^27,28The decrease in concentrations of propane is accom- panied by a fractionation of the stable carbon isotopic composition.

During biodegradation, the residual (parent) propane fraction becomes enriched in the heavier ¹³C isotope, whereas the CO₂ byproduct (daughter) is isotopically enriched in ¹²C. Bacterial- enzymatic processes and C-C bond energies control these compositional and isotopic changes.²⁹Less energy is required to break a

12C-¹²C than a ¹²C-¹³C 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 North Sea field (see Table 2 andFig. 7) with gases from two nearby fields indicates that the reservoirs contain three distinct gas compositional groupings. All fields received the same hydrocarbon charge.

Relatively heavy isotopic compositions for wet gas (C2+) components in Field C gases suggest significant biodegradation. Gases from Fields B and A show less intense alteration (Fig. 7). The relative intensity of biodegradation becomes apparent when the isotopic difference between propane and n-butane is plotted against the isotopic composition of propane(Fig. 8). This trend results from the fact that propane is degraded preferentially to n-butane. For samples from Field B, biodegradation is greatest for Sample 1 and least for Sample 12. Molecular compositions also support the degradation trend indicated by isotopic compositions.

In biodegraded samples, propane is depleted relative ton-butane, andn-butane is depleted relative toi-butane.

Other In-Reservoir Alteration Processes

In addition to biodegradation, other in-reservoir alteration processes can impact hydrocarbon quality. These include water washing, phase separation, gravity segregation, gas de-asphalting, and in-reservoir oil cracking. These processes are reviewed as follows and summarized inFig. 9.

Fig. 6—Comparison of whole oil GCs and mass/charge (m/z) 177 biomarker scans for two reservoirs from Well A. The deeper reservoir shows no evidence of biodegradation, while the shallower shows biomarker evidence of severe biodegradation, followed by recharge with fresh oil. Current reservoir temperatures in both reservoirs are too high for active biodegradation. Geochemical analyses constrain the filling and degradation history of reservoirs. [C28DM=C₂₈-25-nor-demethylated hopane; C29DM=C₂₉-25- nor-demethylated hopane; C29H=C₂₉hopane; C29Ts=C₂₉-22,29,30-norhopane; C29M=C₂₉normoretane; OL=oleanane; C30DM(1) &

(2)= C₃₀-25-nor-demethylated hopanes; C31DM=C₃₁-25-nor-demethylated hopanes; C31H=C₃₁ hopanes; C32DM=C₃₂-25-nor- demethylated hopanes; C32H=C32hopanes; C33H=C33hopanes; C34H=C34hopanes; C35H=C35hopanes; peak labels on whole oil GCs as per Fig. 5.]

Ethane Propane n -Butane i-Butane

-31 -30 -29 -28 -27 -26 -25

-24 Sample 1

Sample 3 Sample 5 Sample 10 Sample 13 Sample 17 Field C

Field B

Field A 13C(ävs.PDB)δ

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

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Water Washing.Alteration of oil by water washing occurs when the most water-soluble components (e.g., light aromatic hydrocarbons) are removed from the oil by contact with formation waters.

The limited solubility of hydrocarbons in water increases at higher temperatures and pressures and declines with increasing salinity.^30,31Water washing often occurs simultaneously with biodegradation in reservoirs < 80°C. The two processes are sometimes difficult to distinguish.

Phase Separation.When both gas and oil phases are present in a reservoir, faulting or other seal-related processes may allow gas to escape preferentially. This gas may migrate to a shallower reservoir where lower pressure and temperature conditions cause exso- lution of a lighter liquid phase. The residual oil remaining in the deeper reservoir will be light-end depleted and generally of poorer quality than it was before gas loss^32,33occurred. Phase separation is 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 molecular weights.

Gravity Segregation.The stratification of an oil column by den- sity is referred to as gravity segregation. This process typically requires high permeability and most often occurs in steeply dip- ping reservoirs where heavy-end components from the oil settle to the 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 often accomplished 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 an oil reservoir through diapir-related reservoir tilting or other geologic processes. Tar mats commonly result from in-reservoir gas de-asphalting.

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

Applications of Biodegradation and Oil Quality to Prospect Evaluation and Risking

Exploration Risking and Block Ranking.Oil-quality risking is an important assessment parameter when making exploration decisions 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 effective hydrocarbon system(s) and are tied to source type, source depositional environment, maturity, and filling history.³⁴Selection of the appropriate biodegradation trend calibration is based on the geochemistry of nearby discoveries or shows, if available. In many deepwater frontier areas, surface hydrocarbon seeps provide initial information on source type and maturity level before any drilling.³⁵In the absence of geochemical data on actual hydrocarbon samples, the characteristics of the effective source can be estimated 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 production planning. Exploitation geochemical approaches are especially 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 segmentation is also important to the efficient placement of injector/

producer pairs when pressure maintenance by water injection is planned. Differences in biodegradation level can sometimes indi- cate segmented compartments. Geochemical analyses also can detect gradients in hydrocarbon properties within continuous reservoirs (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 can help to identify oil-quality variations and “sweet spots” for tar- geted production.

Corrosion/Facilities Design.As exploration proceeds into deeper water offshore, biodegraded oils appear to be more commonly encountered in many basins as cool, shallow reservoirs are penetrated. An increasing number of elevated TAN oils will therefore be developed and produced in the future. In addition to lower crude values resulting from high-temperature corrosion problems in refineries, biodegraded oils tend to have associated problems such as tight emulsion formation. The need to handle and remediate pro-

-29 -28 -27 -26 -25 -24

-1.5 -1 -0.5 0 0.5

1 1.5

2 Well 1-4

Well 5-8 Well 9-12 Well 13-16 Well 17-18

3 4 1

2

7 8 5

6

9

10 11

12

13 14

17 18

15 16

13C propane (ä vs. PDB)

13Cpropane-13Cn-butane

Increasi

ngBiodegradation

δ

δδ

Fig. 8—Biodegradation of wet gases in select North Sea fields.

The difference in isotopic ratios between propane andn-butane is plotted against the stable carbon isotopic ratio of propane to show the increase in biodegradation of wet gases toward the upper right in the plot. Sample labels refer to the sample num- bers in Table 3.

OIL & GAS QUALITY:

Value and producibility

Reservoir Alteration

WATER WASHING GAS DE-ASPHALTING

PHASE-SEPARATION GRAVITY SEGREGATION

temperature oxidant

salinity nutrients Reservoir

Conditions

BIODEGRADATION Bacterial

Activity

C15+

C₆-C₁₄ C₁-C₅ Source Facies

Generative HC properties

Migration Alteration

History of charge, reservoir conditions

Thermochemical SO4Reduction

CRACKING

IncreasingMaturity

YieldHC (PVT effects)

Fig. 9—Summary of factors affecting oil and gas quality. Source facies 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 the reservoir, including biodegradation at temperatures lower than approximately 82°C. The timing of HC charge event(s) and the temperature history of the reservoir after filling also ultimately contribute to the quality of oil and gas in the reservoir.

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

Conclusions

Oil and gas quality determines the direct value of a hydrocarbon product and the economics of its development. Hydrocarbon quality is determined by source-rock composition and thermal maturity and by the degree of alteration. Biodegradation is the most important process altering reservoir hydrocarbons in many areas, but water washing, phase separation, gravity segregation, gas de- asphalting, and thermal cracking also can impact hydrocarbon quality. Biodegradation, active at reservoir temperatures <∼80°C, can significantly reduce hydrocarbon quality, particularly in the shallow, cool reservoirs that have dominated recent deepwater exploration. As biodegrading organisms attack higher-quality hydrocarbon components, they residually concentrate poor-quality components, including sulfur, asphaltenes, and residua. Because bacteria attack different hydrocarbon compounds based on an order of preference, the biodegradation stage can be determined based on the alteration of specific compound classes and structures.

The classification of biodegradation stages presented herein is important for describing and predicting oil and gas quality. Some compounds are produced during biodegradation, notably naphthenic acids and demethylated hopanes. Naphthenic acids contribute to oil-quality debits and may cause additional processing and downstream 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, reservoir characteristics, and the timing of charge(s).

Gas biodegradation results in the decline and loss of wet components and, often, the production of undesirable gases such as CO₂. The stage of gas biodegradation is not necessarily linked to that of the associated oil.

Geochemical analyses are relatively quick and inexpensive and provide critical information regarding oil and gas quality. If calibration data are available, predictive models of oil and gas degradation often can be constructed that improve predrill estimates of hydrocarbon quality during the exploration and development phases. After production commences, routine collection and analysis of fluid samples at little cost can allow changes in production characteristics to be determined and efficiently exploited. Appli- cations include recognition of the production-stimulated break- down of natural reservoir baffles, rapid and inexpensive diagnosis of tubing or casing damage, and production allocation from com- mingled reservoirs. It is therefore critical to collect and analyze representative samples through all phases of a field’s history.

Wireline or drillstem test samples from early exploration often provide the only characterization of individual reservoir zones before commingling. Even the analysis of sidewall cores in reservoir zones can provide important information. Later, routine (e.g., monthly) sampling of the production stream permits compositional changes to be monitored and evaluated.

Acknowledgments

The authors thank ExxonMobil Upstream Research Co. for per- mission to publish this work. Productive discussions with Steve Hinton and Winston Robbins at ExxonMobil Corporate Strategic Research Co. are gratefully acknowledged. Constructive review of the manuscript by Paul Mankiewicz (EMURC; during the great Houston Flood of 2001) and additional discussions and insights were most helpful. W. Allen Young provided useful comments.

Jan Herbst assisted in figure and manuscript preparation. The SPE Editorial Review Committee is acknowledged for their efforts and editorial suggestions that improved this paper.

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SI Metric Conversion Factors

°API 41.5/(131.5+°API)⳱g/cm³

bbl × 1.589 873 E–01⳱m³

ft × 3.048* E–01⳱m

°F (°F–32)/1.8⳱°C

*Conversion factor is exact.

Lloyd M. Wengeris a petroleum geochemist with ExxonMobil Upstream Research Co. His work focus has been on the appli- cation of geochemical technologies to exploration, development, and production problems and linkage to downstream organizations for early recognition of value and handling/

processing issues. After many years of working in the Gulf Coast and the Gulf of Mexico, he has worked primarily in west Africa, including Nigeria and Congo, and he is currently involved in development and exploration activities in deepwater Angola.

Wenger holds a PhD degree in organic geochemistry from Rice U.Cara L. Davishas been with ExxonMobil Upstream Re- search for 5 years, focusing on oil quality and reservoir geochemistry research and applications. She holds a PhD degree in geology (specializing in organic geochemistry) from Indiana U.Gary H. Isaksenis Research Supervisor for Petroleum Geo- chemistry with ExxonMobil Upstream Research Co. Since join- ing Exxon in 1985, the major themes of his work have been integration of geology and petroleum geochemistry, molecular geochemistry, play-element risking, and applications of geochemistry to field development and production. From 1993 to 1995, he worked frontier and established plays within U.K. and Norwegian acreage, and from 1997 to 1999, he worked regional- and prospect-scale assessments within Azer- baijan, Turkmenistan, Uzbekistan, and Russia. His current geo- science focus is on applied research to solve exploration, development, and production problems. Isaksen holds a PhD degree in petroleum geochemistry and petroleum geology from the U. of Bergen, Norway.