Geomicrobiology Journal, 27:43–52, 2010

Copyright © Taylor & Francis Group, LLC

ISSN: 0149-0451 print / 1521-0529 online

DOI: 10.1080/01490450903232181

Interactions between Microorganisms, Crude Oiland Formation Waters

Dorota Wolicka,1 Andrzej Borkowski,2 and Dariusz Dobrzynski3

1Institute of Geochemistry, Mineralogy and Petrology, Faculty of Geology, University of Warsaw,

Warsaw, Poland2Department of Soil Science, Faculty of Agriculture and Biology, Warsaw Agricultural University,

Warsaw, Poland3Institute of Hydrogeology and Engineering Geology, Faculty of Geology, University of Warsaw,

Warsaw, Poland

Crude oil and formation waters surrounding oil deposits consti-tute two environments that harbor various groups of microorgan-isms, such as sulphate-reducing bacteria, iron-reducing bacteria,fermenting bacteria and methanogenic archaea. Microorganismsoccurring in crude oil and formation waters, which are usually min-eral waters or brines, can modify the chemical composition of bothoil and aqueous solution, affect dissolution/precipitation reactionsof mineral phases, and consequently may influence the hydraulicproperties of reservoir rocks and the conditions for hydrocarbonmigration.

This paper describes the potential biogeochemical reactions,which can take place in oil deposits and formation waters with theparticipation of microorganisms and the results of their activity.The results of geochemical modelling of formation waters based onhydrochemical data (obtained from Polish Oil & Gas Company) arediscussed in terms of carbonate mineral stability. The modellingconfirms theoretical predictions of the formation of the mineralphases through abiotic and biotic processes in the formation waters.

Keywords biogeochemistry, crude oil, formation waters, geochemi-cal modelling, geomicrobiology

INTRODUCTION

Crude oil and formation waters occupy an extreme environ-

ment. It is characterized by high pressure (40–80 MPa) and

temperature and by high salinity, exceeding 20% or 30%. The

essential factors determining growth of bacteria in crude oil

Received 16 February 2009; accepted 26 June 2009.We would like to thank the Polish Oil & Gas Company, especially

for Waldemar Wojcik, Jozef Potera and Tadeusz Kozimor from SanokBranch of Polish Oil & Gas Company (PGNiG).

Address correspondence to Dorota Wolicka, Institute of Geo-chemistry, Mineralogy and Petrology, Faculty of Geology, Univer-sity of Warsaw, Zwirki I Wigury 93, Warsaw 02-089, Poland. E-mail:d.wolicka@uw.edu.pl

beds are salinity and pH of formation waters. Salinity can vary

greatly, from below 1 g/kg of water to above 300 g/kg; pH ranges

from 5 to 8 (measured at atmospheric pressure), but when the

higher solubility of gases such as hydrogen sulphide at higher

pressures is considered, the pH in situ may range from about 4

to 9 (Chung et al. 2000; Boszczyk-Maleszak et al. 2006).

It has been possible to isolate and identify many different

groups of microbes from both crude oil and formation wa-

ters. These include sulphate-reducing bacteria (SRB), ferment-

ing bacteria and methanogenic archaea. The group of bacteria

that is isolated the most frequently from both crude oil and for-

mation waters is SRB (Aeckersberg et al. 1991; Rueter et al.

1994; Rozanowa et al. 2001). Data on the occurrence of this

group in oilfield brines date as far back as 1926 and represent

the first attempt to explain the constant presence of sulphides

in oilfields (Jenneman et al. 1999). The presence of SRB in

oilfields and crude oil mining fields raises above all the issue

of the biocorrosion of mining equipment. The SRB are respon-

sible for the characteristic hydrogen sulphide odour associated

with oil fields. Because of the common association of SRB with

crude oil and formation waters, they have been regarded in the

past as indicator organisms when searching for new oil deposits

(Postgate 1984). This was when the soil environment was not

as ubiquitously contaminated with crude oil derivatives as they

are today.

Most of the hydrocarbons found in crude oil are toxic,

which is primarily related to the structure of the compounds

(Gałuszka and Migaszewski 2007). These hydrocarbons include

both aliphatic and aromatic hydrocarbons and polycyclic aro-

matic hydrocarbons (PAH), whose toxicity increases in propor-

tion to the number of carbon atoms. PAH molecules with more

than four benzene rings are particularly toxic.

Microorganisms native to a given environment are able to

cope readily with the prevailing physical and chemical condi-

tions. The activity of resident microbes may modify their envi-

ronment over a long period of time (Bak and Cypionka 1987;

43

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44 D. WOLICKA ET AL.

Ehrlich 1996, 1998). In the case of oil fields this activity takes

place in crude oil and in formation waters. The oil field envi-

ronment includes some uncommon properties for bacteria, such

as a low redox potential and a lack of the common terminal

electron acceptor oxygen, but the electron acceptors sulphate

and carbon dioxide are present (Chesneau 2000; Gardner and

Stewart 2002; Waites et al. 2001; Watanabe et al. 2002; Olliver

and Magot 2005).

Various energy sources utilizable by different group of bacte-

ria in oil fields include organic acids, such as acetic, benzoic, bu-

tyric, formic and propionic acids, and naphthenic acids, at con-

centration up to 100 mM (Magot et al. 2000), and aliphatic and

aromatic hydrocarbons and hydrogen. Important carbon sources

include N-alkanes, cycloalkanes, mono- and polycyclic aro-

matic hydrocarbons, including BTEX (benzene, toluene, ethyl-

benzene, xylene), and heterocyclic compounds (Huang et al.

2004; Vieth and Wilkes 2006), which can be biodegraded.

Resins and asphaltenes can be important sources of electron

donors, particularly in immature oil, and their metabolic useful-

ness can be explained by the fact that anaerobic microorganisms

can grow on pure crude oil without any modifications in the com-

position of alkanes and lighter aromatic hydrocarbons (Rueter

1994; Kodama and Watanabe 2003).

Bacteria associated with oil droplets may include au-

tochthonous and allochthonous types, which are difficult to dis-

tinguish from each other in practice, especially in environments

of low salinity and temperature. So far, detailed characteriza-

tions of autochthonous communities in this environment are

lacking.

The objective of the present paper is to describe the inter-

actions between microorganisms, the products of their activity,

crude oil and waters surrounding the deposit, and their influence

on the stability of carbonate mineral phases.

BACTERIAL ACTIVITY AT THE INTERFACE BETWEEN OILAND FORMATION WATER

Different groups of microorganisms develop under the anaer-

obic conditions existing in a crude oil deposit (Obiaku and Abu

2003; Ajayi et al. 2008). One of the most important group is that

of the sulphate-reducing bacteria (Beeder et al. 1995; Nielsen

et al. 1996, 1996a; Tardy-Jacquenod et al. 1998; Ravot et al.

1999; Head et al. 2003; Roling et al. 2003; Olliver and Magot

2005). They play a very important role because of their abil-

ity to metabolize aliphatic, aromatic and polycyclic aromatic

hydrocarbons (PAH). In anoxic ecosystems the mineralization

of organic matter is usually more complex than under aerobic

conditions and requires the cooperation of different groups of

microorganisms. Each group carries out a specific stage of sub-

strate oxidation, and the end products are metabolized by con-

secutive links of the food chain until complete mineralization is

achieved.

Practically simple organic compounds can be completely

mineralized by sulphate reducing bacteria. In environments

rich in dissolved sulphate, such as crude oil and other for-

mation liquids, the degradation of compounds is carried out

by at least three groups of microorganisms acting in sequence.

The first group consists of fermenting bacteria, the second con-

sists of SRB, which dissimilate organic products formed by

the fermenters to acetate, CO2 and H2, and the third consists

of methanogens, which form methane from acetate and from

CO2+ H2 produced by the second group. All three groups have

been isolated from crude oil and formation waters by many re-

searchers (Ravot et al. 1999; Grigoryan and Voordouw 2008;

Wolicka 2008). If the crude oil and formation liquids contain,

for instance, iron (III) and oxidized nitrogen compounds, then

bacteria reducing iron and denitrifying bacteria, respectively,

also develop (Jorgensen et al. 2001; Thiel et al. 2001; Roling

et al. 2003).

Potential biogeochemical dependencies, and the participation

of microorganisms in the system crude oil – formation liquids,

are presented in Figure 1. In those cases in which sulphates and

organic compounds are accessible to SRB, the dissimilatory re-

duction of sulphates is the main process in the mineralization of

organic matter. Non-hydrocarbon components, such as sulphur,

nitrogen or oxygen, are much less abundant, but significantly

affect the quality of the recovered oil. One of the factors deter-

mining the concentration of the mentioned components is the

age of the crude oil. Generally, the older the crude-oil, the higher

the concentration of hydrogen and the lower the amount of the

heteroatoms S, N, O and P (Surygała et al. 2006).

As far back as 1975, Goldhaber and Kaplan had already

demonstrated a positive correlation between the extent of sul-

phate reduction and increasing amount of organic carbon in

rapidly forming deposits. Sulphate-reducing bacteria produce

hydrogen sulphide as a result of anaerobic respiration on sul-

phate, according to the reaction:

SO2−4 + 8H+ + 8e− → H2S + 2H2O + 2OH− [1]

in which the electrons that are consumed derive from the organic

carbon that is respired.

As a gas it migrates towards the upper parts of the deposit,

but frequently on its way up reacts with iron forming, for in-

stance, biogenic pyrite, which under these conditions becomes

a secondary mineral, or can react with any other metal present

in the crude oil. These, for instance, can include trace elements

such as Zn, Ti, V or Cu (Surygała et al. 2006).

Other bacteria in the community that includes the SRB may

oxidize reduced inorganic sulphur compounds. The absence of

oxygen, which is the main electron acceptor for these bacteria,

does not rule out their presence since at least some of them

are able to grow under anoxic conditions utilizing, for example,

NO−3 . A typical example is Thiobacillus denitrificans. Many

authors have pointed to the potential role of sulphide-oxidizing

bacteria in the formation of the sulphur that accompanies oil

fields (Kodama and Watanabe 2003; Kodama and Watanabe

2004).

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MICROORGANISMS, CRUDE OIL AND FORMATION WATERS 45

FIG. 1. Likely interactions between different group of microorganisms, formation waters, crude oil and gas deposit.

The SRB induce the formation of carbonate minerals through

the production of CO2 as a result of the biodegradation of organic

matter. The precipitation of CaCO3 depends on the activity of

CO2−3 and Ca2+ species in formation water. Reactions carried out

by SRB employing various electron donors lead to the formation

of HS− ions, for instance according to reactions (Hao et al. 1996;

Hammes and Verstraete 2002):

2 C3H6O3 + 3SO2−4 → 3S2− + 6CO2 + 6 H2O [2]

C16H34 + 12.25 SO2−4 → 16 HCO3− + 12.25 HS−

+ 3.75 H+ + H2O [3]

Carbon dioxide produced during sulphate reduction may

bring about carbonate precipitation, according to the reactions:

2[CH2O] + SO2−4 → 2 CO2 + 2H2O + S2− [4]

CO2 + CaO → CaCO3 ↓ [5]

Theoretically, if both magnesium and calcium are present in

formation waters, conditions favouring dolomite CaMg(CO3)2

formation exist. The entire dolomitization process has not been

completely elucidated. Conditions are optimal for growth of

SRB in the conditions where the SRB exist are anaerobic. But

inflowing seawater will most likely by aerobic (Hardie 1987;

Warren 1988; Slaughter and Hill 1991; Vasconcelos et al. 1995;

Wright 1999; Wright and Wacek 2004).

In an open system, in which a continual inflow of seawater

containing sulphates and various metal cations occurs, condi-

tions for the development SRB are optimal if anaerobic condi-

tions prevail where the SRB are active. Such conditions may

support formation of carbonate minerals from bicarbonate gen-

erated by the SRB. Also, it is not entirely explained what is the

minimal concentration of Ca2+ or Mg2+ cations for dolomite

formations.

The SRB live in close syntrophic association with

methanogenic archeons. In effect, oil fields may contain

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46 D. WOLICKA ET AL.

methane derived from microbiological processes. It is possi-

ble that the consortium SRB – methanogenic archeons living

in these conditions can also be involved in the formation of

carbonates according to the reactions (Valentine 2002):

3SO2−4 + CH4 → HCO−

3 + 3HS− + H2O [6]

The carbon in carbonates is available to living organisms

only to a limited extent, e.g., as a result of the dissolution of

CaCO3 in the course of the oxidation of sulphides, e.g. sulphide

oxidizers (Dupraz and Visscher 2005):

3HS− +4 O2 +CaCO3 +HCO−3 → 2[CH2O]+Ca2+ +3SO2−

4

[7]

and such microorganisms as fermenters according to reactions

(Dupraz et al. 2008):

3[CH2O] + CaCO3 + H2O → 2HCO−3 + Ca2+ + C2H6O [8]

The products of the above reactions are automatically incor-

porated into the cycle of biogeochemical transformations in the

oilfield.

If Fe (III) in formation waters, a condition exists for the de-

velopment of iron-reducing bacteria. (Nazina et al. 1995; Moser

and Nealson 1996; Greene et al. 1997; Rooney-Varga et al.

1999; Head et al. 2003; Roling et al. 2003). The products formed

from organic carbon in the formation waters by these bacteria

in their Fe (III) respiration include bicarbonate ions and iron

(II). In the presence of calcium ion, calcium carbonate may be

formed:

C7H8 + 36 Fe(OH)3 + 58 HCO−3 + 65Ca2+ → 65 CaCO3

+ 36 Fe2+ + 87 H2O [9]

In practically every reaction carried out by microorganisms

in the environment of crude oil and formation waters, various

products can be formed, including HS−, HCO−3 , CO2, Fe+2, N2

and CH4. These compounds significantly affect the properties

of both crude oil and formation water, as well as the properties

of the reservoir rock, which can be of enormous significance in

exploitation. The products of microbial activity bring about a

considerable change in the chemistry of the whole system oil –

formation liquids.

The vital activity of microorganisms, through the genera-

tion of various kinds of metabolic products, has a considerable

impact on the chemical composition of crude oil and its proper-

ties, and thus on the mining process. Such metabolic products

include, for example, organic acids, which can modify the struc-

ture of reservoir rock, increase its porosity and permeability, and

by interacting with calcium carbonate, produce CO2 according

to the reaction:

2CH3COOH + CaCO3 → H2O + CO2 + Ca(CH3COO)2 [10]

The biomass formed in the course of metabolic processes

may or may not selectively block or impede the flow of hydro-

carbons. As a result of the presence of biomass and its adherence

to hydrocarbons, modification of the surface of mineral phases

takes place, i.e. wetting, degradation and an altered composition

of the oil, reducing viscosity and lowering the melting point of

the oil, as well as oil desulphurization.

A factor resulting in greater oil migration in reservoir rock

include increased gas pressure from microbially generated CO2,

CH4 or H2, which reduce the viscosity of crude oil. CO2 may also

promote an increase in porosity of the reservoir rock through

dissolution of carbonate minerals.

Some microorganisms produce surface active agents (sur-

factants), which reduce interface tension and thus contribute to

changing the wettability of the reservoir rock (Kowalewski et al.

2006). In addition, the lowered tension at the oil – formation wa-

ter interface frequently leads to the emulsification of crude oil.

Microorganisms producing surfactants live in formation waters

and produce compounds in order to gain access to crude oil,

some components of which may serve as energy sources. In

addition to emulsifying and reducing interface tension, these

compounds can favour the detachment of the hydrocarbon coat

from rock surfaces. For example, until the late 1970s, surfactants

in the form of trehalolipids produced by Nocardia rhodochrus,

were employed to increase oil recovery from a deposit by 30%

(Singh et al. 2007). On the other hand, some nutrients added

to stimulate the growth of microorganisms, e.g., phosphorus,

can have an unfavorable effect by increasing interface tension

(Kowalewski et al. 2006).

Wetting of reservoir rock, as a result of the activity of bacteria

in the deposit, may have one of two consequences, depending on

the initial conditions. In the case of rock that is initially coated

by oil, it will become more wettable with water, and in the

case of rock that is initially extensively wetted by water, it will

become less extensively wetted. In some studies, however, no

significant effect of bacteria on wettability has been observed,

which does not always necessarily mean that no reduction in

wettability occurred because it may be a result of ineffective

measurement methods.

Wetting by bacterial activity can be affected by stimulation

of bacterial growth, for instance, by the addition of phosphate

to the aqueous phase. On the other hand, clay minerals that are

common in bedrocks probably may reduce this effect. These

minerals nay adsorb biopolymers and biosurfactants and re-

duce the effectiveness of these wetting agents with respect

to other rock minerals (Mokhatab 2006). It must also be re-

membered that microorganisms frequently participate in the

transformations of primary aluminosilicates (e.g. K-feldspar)

into secondary mineral phases, such as clay minerals (e.g.

kaolinite):

2 KAlSi3O8 + 11 H2O + 2 CO2 → Al2Si2O5(OH)4 + 2 K+

+ 2 HCO3− + 4 H4SiO4 [11]

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MICROORGANISMS, CRUDE OIL AND FORMATION WATERS 47

Both bacterial cells and the biopolymers that they produce

can block the flow of hydrocarbons and formation waters in

pores and fissures. Biopolymers enable bacteria to join and form

biofilms, which in turn facilitates the acquisition of nutrients

and reduces sensitivity to toxic compounds (Mokhatab 2006).

Initially the biofilm is deposited on the leading faces of obstacles

and then is strongly developed in pore throats. Single bacteria

can detach from a biofilm and the whole structure can slowly

migrate (Dunsmore et al. 2004). The extent of microbial growth

may be limited by a decrease in inflowing formation water as

a result of decreased permeability of porous rock, leading to

a decrease in available carbon source for the microbes. The

decreased rock permeability will result in a change in direction

of the flow of formation waters.

Desirable properties of biopolymers produced by bacteria

are: resistance to high temperature, high viscosity of the so-

lution, compatibility with formation waters, constant viscosity

within a broad pH, temperature and pressure range, and resis-

tance to biodegradation in the environment of an oil field. A

substance that has been well studied from this point of view

is xanthan. However xanthan may be less effective in divert-

ing flow than more recently discovered substances, such as

scleroglucan, because they are less readily biodegraded than

xanthan. According to Mokhatab (2006) selective plugging of

pore throats by biopolymers is not efficient in the case of ho-

mogenous rocks in which all pores are similarly filled with

water.

The production of bacterial surfactants is very important for

their ability to reduce the viscosity of heavy oil, facilitate emul-

sification and bring about a change in the relative value of the

permeability of the rock by affecting the wettability of reser-

voir rock, factors that together facilitate easier migration of the

oil (Almeida et al. 2004). This property of bacteria is utilized,

amongst others, as a microbiological method for increasing oil

recovery. For example, Bacillus licheniformis is potentially use-

ful in situ in view of its ability to grow under anaerobic condi-

tions, at a temperature of 55◦C and at a salinity of 7%. Moreover,

it produces polymers and is simultaneously able to biodegrade

hydrocarbons. This is a favourable combination when reduc-

tion of the viscosity of high density oils is required. Otherwise,

it is not desirable since it changes the composition of oil and

may reduce its economic value. Some bacteria can also produce

acids and solvents, thereby increasing oil recovery, particularly

in carbonate formations (Almeida et al. 2004).

The production of gas by microorganisms, primarily of CO2,

but also of H2, CO, CH4 and N2 enhances oil recovery by in-

creasing the pressure within the reservoir rock, reducing viscos-

ity and specific density of the oil, thereby increasing its volume.

All these factors together facilitate the migration of oil

through reservoir rocks. Bacillus brevis is able to produce

slime, which can seal fault zones within the reservoir rock

(Bonch-Osmolovskaya et al. 2003). Moreover, all the described

endospore-forming bacteria belonging to the genus Bacillus are

capable of denitrification, with N2 being the end-product of this

anaerobic respiration. This is a microbiological process that is

carried out by heterotrophic, facultatively, anaerobic denitrify-

ing bacteria (DEN). As a result of denitrification, nitrogen (+V)

in nitrates is reduced to N2:

C16H34+22NO−3 +18H+ → 16HCO−

3 +11N2+18H2O [12]

source of carbon

denitrification

mineralization by heterotrophs

sulphate reduction

Ca2+

Ca2+

anoxigenic oxidation of methane

NO3

-

SO4

2-

N2

CO2

SO4

2-

HS-

HS-

CaCO3(s)

Ca2+

Ca2+

Ca2+

Ca2+

Ca2+ Ca

2+

Ca2+

FIG. 2. Participation of the different groups of microorganisms in carbonate forming.

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48 D. WOLICKA ET AL.

Nitrate respiration is an advantageous property due to the

easy control of the growth of microorganisms in a deposit, but at

the same time results in an increased concentration of nitrogen

in natural gas, which can be viewed as undesirable from the

viewpoint of reduced energy value.

The production of biosurfactants by microorganisms is insep-

arably linked with the de-emulsification of crude oil. There are

many microorganisms with known welcome de-emulsification

abilities. These include: Acinetobacter calcoaceticus, A. ra-

dioresistens, Aeromonas sp. Alcaligenes latus, Alteromonas sp.,

Bacillus subtilis, Corynebacterium petrophilium, Kingella den-

itrificans, Micrococcus sp., Nocardia amarae, Pseudomonas

aeruginosa, P. carboxydohybrogena, Rhodococcus auranti-

cus, R. globerulus, R. rubropertinctus, Sphingobacterium

thalophilum and Torulopsis bombicola (Norman et al. 2002;

Mishra et al. 2004; Murygina et al. 2005; Ouyang et al.

2005).

Microorganisms utilize the dual hydrophobic-hydrophilic na-

ture of surfactants or else the hydrophobic surface of the cell

to remove emulsifiers from the surface between oil and water.

De-emulsifying properties are also demonstrated by such bac-

terial products as: acetoin, polysaccharides, glycolipids, glyco-

proteins, phospholipids and rhamnolipids. Increased tempera-

ture favourably affects the process, since it reduces viscosity,

increases the difference in density between phases, weakens the

stabilizing action of the interface coat and increases the coef-

ficient of droplet collision, which leads to coalescence (Singh

et al. 2007).

TABLE 1

Chemical composition of formation waters used in

geochemical modelling. Concentrations in g/L

Formation waters – sample numbers

Parameters 1 2 3 4 5

Density, at 20◦C

[g/mL]

1.1355 1.075 1.036 1.013 1.005

Hardness

[mgCaCO3/L]

23520 15980 6973 3560 216

pH 5.9 6.4 6.7 7.4 8.1

Cl− 125 70 31 9 0.60

Br− 0.100 0.067 0.015 0.01 0.010

I− 0.01 0.036 0.009 0.003 0.003

CO2−3 0 0 — 0 1.14

HCO−3 0.32 0.46 0.48 1.40 5.12

S2− — — 0.001 — —

SO2−4 0.125 0.70 1.03 1.96 0.001

Fe2+ 0.35 0.028 0.04 0.001 0.0006

Ca2+ 8.72 5.11 1.26 1.15 0.029

Mg2+ 0.71 0.97 1.02 0.21 0.038

NH+4 0.11 0.12 0.013 0.012 0.004

SiO2 0.0016 0.009 0.012 0.002 0.016

Contact between the various components of the oil reservoir

system occurs as a result of the inflow fresh groundwater of me-

teoric origin throughout fissures and faults. Fresh groundwater

may introduce different chemical compounds, and, moreover,

transport substances which circulate in the system and are fre-

quently involved in biogeochemical reactions.

STABILITY OF CARBONATE MINERAL PHASES INSTUDIED FORMATION WATERS

The stability of carbonate minerals in geochemical systems

depends on various factors, e.g., temperature, pH, salinity and

the activity of species of chemical compounds in groundwater,

and the conditions of groundwater turnover.

The activity of micro- and macro-organisms is also an impor-

tant geochemical factor, because they are capable of inducing

carbonate dissolution/precipitation reactions. Biological precip-

itation of carbonates may be caused by the metabolic activity of

different microorganisms (Figure 2).

FIG. 3. Saturation index (SI) of formation water with respect to selected

mineral phases.

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MICROORGANISMS, CRUDE OIL AND FORMATION WATERS 49

Saturation State of Formation Water with Respect toMineral Phases

For a theoretical elaboration of issues related to geomicro-

biological processes in oil reservoirs, crude oils and formation

waters from five oil fields located in southeastern Poland were

analysed. They were selected because their formation waters

represent a wide range of salinity. The data characterizing for-

mation waters from oil fields were obtained from Polish Oil &

Gas Company. Hydrocarbon content measurements were con-

ducted using a gas chromatograph equipped with a flame ioniza-

tion detector GC-FID. Samples were extracted with petroleum

ether according to norm DIN EN ISO 9377-2 H53. Results of

the gas chromatography indicated that all analyzed samples of

crude oil were of a paraffinic type. The density at 20◦C was

from 1.005 g/mL (sample no. 5) to 1.1355 (no. 1). The chemical

composition of the formation waters was determined by colori-

metric methods (iron – by reaction with NH4SCN, sulphates

– by reaction with BaCl2) and ASA analysis (metal cations).

These results are presented in Table 1.

The chemical analyses of formation waters (Table 1) were

used in geochemical modelling. Geochemical modelling of for-

mation water was performed by applying the PHREEQC code

v.2.15 (Parkhurst and Appelo 1999). Studied formation waters

differed in salinity. Samples nos. 1 – 3 were brines, samples 4

and 5 were mineral waters. Total dissolved solids of formation

waters ranged from 10 to 205 g/L, hence, the saturation state

was calculated using pitzer.dat thermodynamic database.

The saturation index (SI) is widely used in the quantification

of the saturation state of water with respect to solid and gaseous

phases. Saturation index (SI) is defined as:

SI = logIAP

K[13]

where: IAP – ion activity product, K – equilibrium constant at

temperature of analysed solution.

A SI value above zero indicates oversaturation and stability

of the mineral phase, if it is present in the bedrock, or has a

FIG. 4. Saturation index for calcite (A), dolomite (B), gypsum (C), anhydrite (D) vs. contribution of formation water to solution.

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50 D. WOLICKA ET AL.

theoretical tendency to form the phase. A SI value below zero

suggests undersaturation state and conditions favouring disso-

ciation of the mineral phase in contact with the formation water.

At an ideal thermodynamic equilibrium between water and min-

eral phase, SI should equal zero. However, even at real chemical

equilibrium, the SI calculated using the geochemical codes fluc-

tuate around zero. It is caused by the effect of analytical errors

and thermodynamic constant errors. Jenne et al. (1980) stated

that SI values within the range of ±5% log K correspond to

fluctuations around the expected chemical equilibrium. Values

of SI within the ±5% log K range are usually considered as

corresponding to the so-called “equilibrium range”.

The formation waters studied were saturated and/or over-

saturated with respect to carbonate minerals (dolomite, calcite,

aragonite, magnesite) (Figure 3). Among the different samples,

sample no. 2 shows saturation with anhydrite, and sample no. 4

oversaturation with gypsum. The results of solubility state calcu-

lations confirm that carbonate minerals may form in formation

water of different salinity.

Effects of Water Mixing on Mineral Solubility

In real hydrogeologic systems, that are open, formation wa-

ters can mix with fresh groundwaters of recent infiltration in

the shallow subsurface (Fig. 1). Geochemical modelling with

the PHREEQC code was used to estimate the effect on the sat-

uration state by mixing of formation water from five oil fields

with hypothetical fresh water. The fresh water component was

taken to be pure (meteoric) water equilibrated with present-day

atmospheric carbon dioxide, and evaporated to take into account

the effect of evapotranspiration. In this way the modified solu-

tion was regarded as present-day recharging water in the mixing

modelling.

Mixing of formation water with fresh water affects the so-

lution chemistry and saturation state. The saturation index for

selected carbonate (calcite, dolomite) and sulphate (gypsum,

anhydrite) minerals at different mixing ratios are shown on

Figure 4.

Formation water samples nos. 1 – 3 (brines) show saturation

with calcite and dolomite when they were mixed with fresh water

(Figs. 4A, 4B). Formation water nos. 4 and 5 (mineral water of

salinity about 10–20 g/L) were still saturated with calcite and

dolomite even when they are mixed at a groundwater to fresh

water ratio of 1:9 (Figs. 4A, 4B).

All formation waters were undersaturated with respect to

gypsum and anhydrite (Fig. 3). Mixing with fresh water in-

creased the undersaturation state (Figs. 4C, 4D). Formation wa-

ter no. 5 was the most undersaturated with respect to gypsum

and anhydrite because it had a very low sulphate solute content

(only about 1 mg/L of SO2−4 ; Table 1).

Geochemical modelling supports thermodynamically the

suggestion that even in an open oil reservoir, microbes may

promote carbonate precipitation, mainly in the form of calcite

and dolomite, when formation waters mix with fresh waters.

CONCLUSION

We have discussed possible chemical reactions that may oc-

cur in the liquid phase of crude oil reservoirs with participa-

tion of various autochthonous groups of microorganisms. The

chemical reactions that occur in these reservoirs may be mi-

crobial or abiotic. Microbiological processes cannot be ignored

in highly mineralised waters, e.g., brines in crude oil deposits.

Such brines, even though representing an extreme environment,

may favour the presence of various groups of microorganisms

that promote the formation of secondary minerals. Determina-

tion of the saturation index with respect to key minerals of the

reservoir rock with which the formation water is in contact can

aid in determining which secondary minerals may be formed.

Formation of secondary calcite and dolomite may be favoured.

Deposition of these minerals may have a negative effect on hy-

draulic properties of the reservoir rock and in the exploitation

of hydrocarbons in the deposit.

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