Enhanced Oil Recovery Field Case Studies || The Use of Microorganisms to Enhance Oil Recovery

Chapter 20

The Use of Microorganisms toEnhance Oil Recovery

Lewis BrownMississippi State University Biological Sciences, 449 Hardy Road, Room 131 Etheredge Hall,

P.O. Box GY, Mississippi State, MS 39762, USA

20.1 ORIGIN OF THE MEOR CONCEPT

The use of microorganisms to increase oil recovery from petroleum reservoirs

is commonly referred to as microbial-enhanced oil recovery (MEOR). At

times microorganisms are also employed to remove a buildup of hydrocarbons

around the wellbore and while this will help increase the flow of oil from the

reservoir, it is not truly MEOR. Generally speaking, only 10% of the original

oil in a reservoir is recovered during primary production (Ollivier and Magot,

2005). Even after secondary recovery processes, such as waterflooding, nearly

two-thirds of the original oil is left in the ground (Brown, 2010).

The ever-increasing demand for oil is not going to be satisfied by finding

new oil fields, but rather by finding ways to recover a greater percentage of

oil from the existing oil deposits. A multiplicity of tertiary methods of recov-

ering oil have been tried, including polymer flooding, surfactant flooding,

alkaline flooding, injection of steam, or even in situ combustion, but none of

these methods have been adopted by the oil industry. In studying the natural

disappearance of oil from the environment, Beckman pointed out as early as

1926 that the world’s supply of oil is limited and that a large percentage of

the oil remains in the earth (Beckman, 1926). He questioned as to whether

bacteria might be employed to cause the oil to flow again. Nothing was ever

done with his suggestion until ZoBell (1946) received a patent on his process

to get more oil out of the ground. ZoBell’s patent involved injecting

Desulfovibrio hydrocarbonoclasticus and nutrients into a well. The nutrients

consisted of a carbon source and oxidized sulfur compounds upon which the

microorganism would grow and produce products, such as gas, surfactants,

etc., that would increase the recovery of oil. In his patent ZoBell cites five

mechanisms by which microorganisms can liberate more oil from the petro-

liferous formation. These processes are (1) dissolution of limestone and other

calcareous materials, (2) production of gases, such as carbon dioxide,

561Enhanced Oil Recovery Field Case Studies.

© 2013 Elsevier Inc. All rights reserved.

methane, and hydrogen, (3) production of detergents which help remove

hydrocarbons, (4) attachment to solid surfaces which tends to displace oil,

and (5) reduce the viscosity of the oil. However, Beck (1947) carried out

extensive experiments with ZoBell’s culture, but got only inconsistent

results. He concluded that ZoBell’s cultures would be useless in the field.

ZoBell (1953) later received another patent in which he employed organisms

in the genus Clostridium and other hydrogen-producing microorganisms.

Both patents were based only on laboratory results—no field trials were ever

performed.

Updegraff and Wren also obtained a patent in 1953, wherein they injected

microorganisms of the genus Desulfovibrio and possibly a symbiont bacte-

rium. They found that utilization of crude oil by the bacteria was extremely

slow and their patent included the injection of molasses along with the bac-

teria to accelerate growth. Updegraff obtained another patent in 1957

wherein he suggested injecting a gas-producing facultative or obligate anaer-

obe along with a water-soluble carbohydrate (sugar). He also specified a

number of bacteria that could be employed as the bacterium. Once again, the

patent was based on laboratory work, not field experiments.

20.2 EARLY WORK ON MEOR

There is no question that aerobic microorganisms have the ability to utilize

hydrocarbons to produce substances that will enhance oil recovery.

Unfortunately, the anaerobic metabolism of hydrocarbons by microorganisms

was unknown until the late 1980s (Heider et al., 1999). Later it was shown

that microorganisms were able to anaerobically degrade oil in the subsurface

(Aiken et al., 2004; Knopp et al., 2000). While the process was anaerobic, it

was slow and therefore useless in MEOR. However, the procedure of adding

microorganisms to reservoirs to help recover more oil continued in spite of

the concern for plugging. For example, Beck (1947) as well as O’Bryan and

Ling (1949) had plugging problems in their laboratory studies. Furthermore,

Updegraff (1983) pointed out that the by-products of microbial metabolism

alone could cause plugging. Hitzman (1962) suggested using spores rather

than vegetative cells because of their smaller size. Lappin-Scott et al. (1988)

argued that spores could cause plugging and suggested using ultramicrobac-

teria (UMB) because of their smaller size. On the basis of calculations, Jack

et al. (1991) stated that injected microorganisms needed to be small, spheri-

cal, and less than 20% of the size of the pore throat in the formation. Davis

and Updegraff (1954) stated that the diameter of the injected cells must be

one-half the pore entry diameter. Chang and Yen (1984) even suggested

using a lysogenic strain of bacteria since they will disintegrate on their own.

In spite of the problems of plugging the well, patents continue to be

issued on the subject of adding microorganisms to wells as attested to by US

562 Enhanced Oil Recovery Field Case Studies

Patent No. 7,776,795 issued on August 17, 2010, wherein a reservoir is inoc-

ulated with a specific bacterial isolate (Keeler et al., 2010).

In addition to the size, another problem confronting the practitioner of

MEOR is that of temperature. Oil degradation at temperatures exceeding

82�C had never been observed in the 1970s (Philippi, 1977). Further,

Wilhelms et al. (2001) suggested that oil reservoirs were uplifted from hotter

regions where the hydrocarbon-degrading bacteria would have been inacti-

vated at temperatures greater than 80�90�C. Bernard et al. (1992) failed to

cultivate microbes at temperatures higher than 82�C and Grassia et al. (1996)

failed to find microbes that grew above 85�C. Roling et al. (2003) stated that

anaerobic biological hydrocarbon degradation is apparently inhibited at tem-

peratures above 80�90�C. However, Stetter (2006) reported on microorgan-

isms that grow above 80�C up to 113�C, but he did not try to employ these

microorganisms in MEOR. Azadpour et al. (1996) was able to demonstrate

that one of the microbes she isolated from cores from oil reservoirs grew at

temperatures up to 116�C. More recently, as reported later in this paper,

there is good evidence that microorganisms were present in a core taken

from a petroliferous formation at 115�C and that they apparently grew in the

petroliferous formation when supplied with nitrate and phosphate (Schmitz

et al., 2005).

20.3 PATENTS ON MEOR

Actually, the use of microorganisms to enhance oil recovery is not a single

mechanism but a collection of mechanisms. Further, it should be pointed out

that most of the reports and patents on MEOR are based on laboratory results

rather than field work, and many of these studies were carried out on micro-

organisms isolated from production fluid, not from cores from petroliferous

formations. While some of the methods advocate adding microorganisms to

the wells, a few of the methods are designed to employ the microbes present

in the petroliferous formations. This distinction between using laboratory

data versus field data are not apparent in the name MEOR and that is one of

the reasons many professional petroleum engineers are skeptical of MEOR.

In the laboratory the cores from the formation (if indeed the cores came

from the petroliferous formation) are only inches to a few feet in length and

cannot reflect the true characteristics of the petroliferous formation.

Furthermore, the only experience many petroleum engineers have with

microorganisms is that they can plug wells and consequently, they are

opposed to adding microorganisms to their oil reservoirs. Therefore, since

many of the patents are based on laboratory results rather then field data;

they do not prove or disprove MEOR. The only way to test MEOR prior to

going to the field will be to use cores from the petroliferous formation and

use conditions as close to those that exist in the field. The field trials must

be of sufficient duration and incorporate enough scientific proof that indeed

563Chapter | 20 The Use of Microorganisms to Enhance Oil Recovery

the process will enhance oil production without damaging the well or the

petroliferous formation. In other words, for MEOR to be a successful tech-

nology it must be repeatable and proven under field conditions.

Hitzman (1965) points out that the problem of injecting microorganisms

into the production zone of oil wells tends to plug the formation. The micro-

organisms tend to lodge in the area immediately adjacent to the wellbore,

and thus few organisms penetrate very deeply into the formation. He pro-

posed a unique method of getting around the problem. Instead of only dril-

ling the well into the petroliferous formation, he suggested continuing to drill

into the water-bearing formation below the petroliferous formation. The

water formation is then inoculated with a species of the family Bacteriaceae

and a species of the family Pseudomonadaceae. After enough water (approx-

imately 1000 barrels) enters the oil-bearing strata, the water is shut off. The

bacteria which grow at the oil�water interface will assist oil production in a

variety of ways including producing gases or helping dissolve carbonates,

dolomite, limestones, and other stratal materials.

A process is described by Lindblom et al. (1967) wherein a

heteropolysaccharide-thickening agent, produced by a bacterium from the

genus Xanthomonas, is injected to increase oil production. Interestingly

enough they suggest adding a bactericide to the solution containing the thick-

ening agent to prevent microbial growth.

In spite of arguments against injecting microorganisms into oil reservoirs,

there are a number of investigators who still advocate this approach to

recover more oil from petroliferous formations. Because of the potential eco-

nomic value of a process to recover more oil from the ground, processes are

still being patented. For example, in 1984 Thompson and Jack (1984) pro-

posed injecting microorganisms capable of producing insoluble exopolymers

into the petroliferous formation. The introduction of a compound that trig-

gers the formation of the exopolymer is also injected. The exopolymer

reduces the permeability of the more permeable zones and both the microor-

ganism and the trigger compound (sucrose) are injected into the formation in

an aqueous medium. Theoretically, the exopolymer will plug the more

porous zones in the formation. The patent was elaborated on further by

Thompson and Jack (1985).

McInerney et al. (1985) proposed injecting a specific microorganism

(Bacillus licheniformis strain JF-2, ATCC No. 39307) into the petroliferous

formation, nutrients from which the microorganism will produce the surfac-

tant lichenysin, and sealing off the waterflooded formation. The nutrients

injected were molasses, grain malts or grain worts, and one of the following

sources of nitrogen—alkali metal nitrates, ammonia, alkali metal ammonium

salts, protein digests, protein hydrolysates, protein peptones, or corn steep

liquor.

Sometimes during the course of waterflooding as a secondary method of

oil recovery, thickening agents are added to the water employed in the


process. Hitzman (1984) developed a process whereby a well that had

previously been injected with a polymeric viscosifier-thickening agent was

subsequently injected with a microorganism capable of metabolizing the

polymeric viscosifier. Obviously, the thickening agent would have to be bio-

degradable. A list of common genera of microorganisms is listed in his

claims. Interestingly, no mention of temperature is included in the claims

and the genera of microorganisms listed do not contain hyperthermophiles.

Therefore, the temperature of the petroliferous formation in which this

process would work will be a limiting factor.

Clark (1986) realized that it was difficult to prevent microbial cells from

sticking to the material in the formation so he devised a way of getting around

the problem. Microbial cells have a strong surface charge and are, therefore,

adsorbed to the surface of stratal material. His method involved injecting an

agent to adsorb onto the active sites in the formation thereby diminishing the

number of microbial cells adsorbed. For example, when the injected sample

contained 3.433 109 cells the untreated Berea sandstone core allowed the pas-

sage of 8.63 104 cells while the treated core permitted 7.93 105 cells to pass

through the core. Obviously, more of the injected microbial cells will move

further into the formation. The microbial cells will produce metabolic pro-

ducts, like carbon dioxide, that will enhance oil production.

The characteristics of the microorganism to be injected into a reservoir to

increase oil production are delineated by Silver et al. (1989). These charac-

teristics of the microorganism are that it is motile, a facultative anaerobe,

halotolerant, thermotolerant, produces an exopolymer, and sporulates. A

nutrient solution containing phosphate is injected prior to, along with, or

after injection of the microorganism into the formation and hopefully into

the highly permeable zones of the formation.

Bryant’s (1990) patent specifies that the field in which the described pro-

cess is used has a minimum of one injection well and one producing well.

The microorganisms employed in her patent are a surfactant-producing

microorganism (Bacillus licheniformis) and a species from the genus

Clostridium which secretes a solvent. An aqueous solution of molasses is

injected, and the injection well is shut in to give the microorganisms time to

grow and produce the desired products.

Another patent by Silver and Bunting (1990) only has one claim but

proposes to use a phosphate compound which will not precipitate out of solu-

tion, chelate alkaline soil, rare earth, and heavy metal ions and simultaneously

will serve as a nutrient source for bacteria.

Sperl and Sperl (1991) reported that their methodology is for a

carbonate-containing rock formation wherein a denitrifying microorganism is

introduced in the presence of a sulfur-containing compound and produces

sulfuric acid. The sulfuric acid dissolves the carbonate, thereby releasing oil

which then can be produced. The microorganisms specified in the patent are

species of the denitrifying thiobacilli.


Sheehy’s (1990) patent uses the indigenous microorganisms in the petro-

liferous formation to help recover oil. Basically, they limit at least one of the

nutrients required for growth of the culture, thereby causing the cells to be

reduced in volume up to 70%. The reduced cells have increased surface-

active properties which help release oil from the stratal material.

Rather than injecting microorganisms into the petroliferous formation,

Clark and Jenneman (1992) patented a procedure whereby they injected only

microbial nutrients into the formation. However, they also included in their

patent injecting both microorganisms that are indigenous to the formation

and other microorganisms that were sometimes injected into the formation.

Their procedure called for sequentially injecting individual nutrients into the

formation until a complete nutrient medium was generated in the formation

for the purpose of enhancing oil recovery.

It is interesting to note that Sunde (1992) uses aerobic oil-degrading bac-

teria in his enhanced oil recovery process unless there are already aerobic

oil-degrading bacteria present in the formation. He injects the bacteria and/or

the mineral solution plus vitamins into the injection well and produce the oil

from a nearby production well. The microorganisms employed are members

of the genera Pseudomomas, Corynebacterium, Mycobacterium,

Acinetobacter, and Nocardia. The injection water contains at least 5 mg/L of

oxygen. Oil is produced from a nearby production well.

In a later patent, Sundae and Torsvik (2004) used facultative or anaerobic

sulfate-reducing, nitrate-reducing, iron-reducing, or acetogenic bacteria that

are either present in the formation or introduced into the formation. They

supplied them with vitamins, phosphates, and an electron acceptor. The

microorganisms grew on the oil and produced substances that released oil

from the formation.

Lal et al. (2009) employed acidogenic, barophilic and, hyperthermophilic

anaerobic bacterial strains for enhanced oil recovery in oil reservoirs with

temperatures in the range of 70�90�C. These bacteria produce carbon diox-

ide, methane, biosurfactants, volatile fatty acids, and alcohols from specifi-

cally designed nutrient medium. The bacteria are species of

Thermoanaerobacterium, Thermotoga, and Thermococcus. The injection

water contained a carbon source, mineral nutrients, nitrogenous substrates,

reducing agents, trace minerals, and vitamins. The compounds produced by

the bacteria dissociate oil from the strata thereby releasing it for production.

Another recent patent by Brigmon and Berry (2009) is directed toward

wells with strata in the temperature range of 20�65�C using a group of spe-

cific microorganisms (ATCC Nos. PTA-5570 through PTA-5581). The oil

field must have at least one injection well and one production well. The

microorganisms are injected either simultaneously or after the injection of a

nutrient mixture capable of supporting the microbial population. At least one

of the microorganisms should produce a surfactant while another microor-

ganism must produce an enzyme that dislodges oil from the oil-bearing


substrate. The authors also suggest using recycled production water because

it will contain the desired microorganism.

The microorganism, Thauera strain AL 9:8 (ATCC No. PTA 9497), is

the subject of a recent patent by Hendrickson et al. (2010). It is claimed that

this microorganism with one or more additional microorganisms could alter

the permeability of the subterranean formation to improve water sweep effi-

ciency in a waterflood operation. This is accomplished by producing biosur-

factants, mediating changes in wettability, producing polymers that facilitate

mobility of petroleum, generating gases that increase formation pressure, and

reducing the viscosity of oil. These activities of the microorganisms enhance

the recovery of oil.

While there is no question as to the ability of microorganisms to release

oil from oil sands, the introduction of microorganisms into single wells will

only yield a small fraction of the oil remaining in the formation. Therefore,

it seems obvious that if MEOR is to be a tertiary method of recovering more

oil from oil reservoirs, the microorganisms indigenous to the petroliferous

formation will have to be the agents responsible for increasing oil recovery

because of their presence throughout the petroliferous formation and it has

been shown repeatedly that the injection of microorganisms into the petroli-

ferous formation does not allow them to penetrate very far into the

formation.

20.4 OUR PROJECTS ON MEOR

Many of the reports in the literature claiming success of MEOR are viewed

with skepticism due to lack of scientific validation of the processes. This

helped lead the Department of Energy (DOE) in 1992 to initiate a program

entitled “Class I Oil Program-Mid Term Activities” (Stephens et al., 2000).

This led an executive of an oil company (Jim Stevens), a petroleum engineer

(Alex Vadie), and a microbiologist (Lewis Brown) to submit a proposal to

DOE to pursue a contract to try to extend the life of a particular oil field

scheduled to be abandoned in 2004 due to dwindling oil production.

Specifically, the objective of this cooperative project was to demonstrate the

effectiveness of a microbial permeability profile modification (MPPM) tech-

nology to enhance oil recovery from a fluvial-dominated deltaic reservoir

and to document the scientific basis of the technology. The process to be

employed was developed by Mississippi State University with funds pro-

vided in part by industry and improved under a DOE grant in the early

1990s (Stephens et al., 2000; Brown, 1984). The oil field for this study was

the North Blowhorn Creek Oil Unit (NBCU) situated in Lamar County, AL.

At the beginning of the project, the field consisted of 20 injection wells and

32 producing wells. The producing formation was the Carter Sandstone of

Mississippian Age at a depth of about 2300 ft. Analysis of a typical core

sample from the petroliferous formation indicated that it was 90% quartz


containing dolomite (4%). The clay fraction was mixed layer clay (3%) with

2% kaolinite and less than a trace of siderite (FeCO3). Permeability of the

core sample varied widely from 1 to 198 mD and porosity varied from 7% to

19%. Oil saturation varied between 34% and 45% with connate water satura-

tion about 17%. The field was discovered in 1979 and waterflooding began

in 1983.

At the outset of the project, two wells were drilled outside of the area

being swept by the waterflood, specifically to obtain a core for laboratory

studies. Unfortunately, a core was not obtained from the first well drilled,

but a core was obtained from the second well. Special precautions were

taken to insure that the inside of the core was not contaminated with exoge-

nous microorganisms. Immediately upon withdrawal of the core barrel from

the well, the core barrel was opened, the core broken into 1-ft lengths, each

piece was wiped with 70% ethanol, and placed in an anaerobic jar containing

a Becton Dickinson Gas Paks, transported to the laboratory, and the anaero-

bic jar placed in a refrigerator at 4�C. The inner 3.5 in of the 4-in core was

tested for barium (barite used in the drilling mud), but none was found indi-

cating that drilling fluid had not penetrated the core. Samples of the core

were tested and found to contain microorganisms, although few in number.

Two core plugs were drilled from a core using a sterile coring device

under an atmosphere of nitrogen. Each plug was 3�4 in (76.2�101.6 cm) in

length by 1.5 in (38.1 cm) in diameter. An entry and exit port were placed

on opposite ends of the cores and allowed for entry and exit of liquids into

and out of the core. The plugs were then inserted into special heat shrink

plastic tubes and the entire assemblies inserted into thick rubber sleeves and

employed in coreflood experiments in a specially constructed coreflood facil-

ity shown in Figure 20.1.

Control core

Test core

FIGURE 20.1 Coreflood facility.


Initially, sterile simulated production water was allowed to flow through

both plugs for 48 h. Thereafter, the control plug received only simulated

production water while the test plug received simulated production water

containing potassium nitrate and disodium hydrogen phosphate. The control

plug showed a steady increase in flow rate, while the flow rate from the

test plug decreased with time. Oil was found in the effluent from the control

plug only once while oil was found in the effluent from the test plug multi-

ple times. This experiment was repeated three times, each time with a new

core, with the same results. The test was repeated using 0.1% sterile molas-

ses added to two of the test plugs and the results indicated that the MPPM

could be accelerated by the addition of small amounts of molasses to the

feeding regime. The experiment was repeated using actual injection water

instead of simulated injection water with the same results.

Prior to commencing the field study, a tracer study was conducted

wherein tritiated water (containing a radioactive isotope of hydrogen) was

added to the injection water injected into one of the injection wells.

The distance between the injector and the nearest production well was

approximately 0.7 miles. Months later, tritium was detected in three of the

surrounding production wells. The results indicated that it would be 7�12

months before nutrients could be expected to reach the surrounding produc-

tion wells.

The field trial employed 4 of the 20 injection wells as test injectors to

which KNO3 and NaH2PO4 were added as shown in Table 20.1. Molasses

was added to two of the test injectors. The producing wells surrounding the

test injection wells were monitored for oil production. Four other injection

wells were employed as control injectors. The producing wells surrounding

each control well were monitored for oil production and served as control

producing wells. In some cases producer wells served in more than one test

or control pattern. The locations of the test and control patterns are shown in

Figure 20.2.

TABLE 20.1 Nutrient Additions to the Four Test Injectors from November

1994 to April 1996

Nutrient and Concentration Day of the Week Test Injector Well

No. 1 No. 2 No. 3 No. 4

KNO3 0.12% (w/v) Monday 1 1 1 1

NaH2PO4 0.034 (w/v) Wednesday 1 � 1 �NaH2PO4 0.034 (w/v) Friday 1 1 1 1

Molasses 0.1% (v/v) Wednesday � 1 � 1

1 5 addition to test injector; �5 no addition to test injector.


Skids, where the nutrients were mixed prior to injection into the test

injection wells, enabled the chemicals to be dissolved in 100�300 gal of

water prior to being monitored into the injection water being pumped into

each injection test well (see Figure 20.3).

After 12 months, 8 of the 15 wells in the test areas demonstrated an

increase in oil production while none of the seven wells in the control areas

showed a positive response. The nutrient additions to the injection wells

were adjusted after 16 months as shown in Table 20.2. After a total of 30

months of adding nutrients to the four test injection wells, an additional six

field injection wells began to receive nutrients as shown in Table 20.3.

Overall, 11 of the producer wells in the test patterns gave a positive response

as well as two of the control producer well. Two of the test producer wells

also gave a questionable response as shown in Table 20.4.

FIGURE 20.2 Isopach of NBCU Oil Field showing locations of wells in the four test and con-

trol patterns (Stephens et al., 2000).


In order to determine if the nutrients were indeed being distributed in the

petroliferous formation, an additional three wells were drilled in the field.

Chemical analyses showed the presence of nitrate and phosphate in the oil-

producing strata in all three of the new wells, demonstrating that the nutri-

ents were being widely distributed throughout the oil-bearing formation.

Electron micrographs of cores from these three wells showed a large number

of microbial cells (see Figures 20.4 and 20.5).

Originally the field was scheduled to be shut down in 2004 due to pro-

duction dropping below 1500 bbl of oil per month, but the field is still pro-

ducing nearly 3000 bbl per month even though the injection of nutrients had

been stopped after 42 months. Currently, the field is not expected to reach

FIGURE 20.3 Picture of skid in which chemicals are mixed for injection into petroliferous for-

mation (Stephens et al., 2000).

TABLE 20.2 Nutrient Additions to the Four Test Injectors from April 1996

to June 1997

Nutrient and Concentration Day of the Week Test Injector Well

No. 1 No. 2 No. 3 No. 4

KNO3 0.12% (w/v) Monday 1 1 1 �KNO3 0.06% (w/v) Monday � � � 1

NaH2PO4 0.034 (w/v) Wednesday 1 1 1 �NaH2PO4 0.017 (w/v) Wednesday � � � 1

Molasses 0.2% (v/v) Friday 1 1 1 �Molasses 0.3% (v/v) Friday � � � 1

1 5 addition to test injector; �5 no addition to test injector.


1500 bbl/month until 2018. Thus far, MPPM has been responsible for over

360,000 bbl of extra oil production and the field is expected to produce

another 230,000 bbl before being shut down in 2018.

It should be pointed out that certain activities in a reservoir, such as dril-

ling a new well, shutting-in a well, increasing the water injection rate in a

new injection well, etc., can alter the performance of other wells in the field.

Thus, an increase in oil production in a well is not necessarily proof that the

treatment of the field was responsible for that increase.

However, in the above study, our treatment, including the addition of

nitrate and phosphate to feed indigenous microorganisms, did indeed cause

the increased production of oil as attested to by the following.

1. The sulfide content of the produced fluids from the wells was absent after

6 months of nutrient injection. This was not unexpected since both nitrate

and nitrate-reducing bacteria inhibit sulfate-reducing bacteria.

2. Gas chromatographic profiles of oil from 10 of the producing wells in the

test areas indicated the presence of new oil in the produced oil, i.e., the

appearance of new smaller hydrocarbon compounds in the produced oil.

3. There was an increase in the amount of oil produced in 11 of the 15 test

producers being influenced by the addition of nutrients.

TABLE 20.3 Feed and Feeding Regime for all 10 Injectors from July 1997

to June 1998

Well No. Monday Tuesday Wednesday Thursday Friday

34-16 No. 1 0.16N � 0.28M �0.04P

2-4 No. 1 0.10N � 0.20M � �0.03P

2-6 No. 1 0.05N � 0.30M � 0.02P

34-9 No. 2 0.11N � 0.18M � 0.05P

3-16 No. 1 � 0.19N � 0.32M �0.05P

34-7 No. 1 � 0.17N � 0.21M �0.04P

2-10 No. 2 � 0.12N � 0.19M �0.02P

11-5 No. 1 0.15N � 0.29M � 0.04P

2-12 No. 1 � 0.26N � 0.43M �0.07P

2-14 No. 1 0.08N � 0.47M � 0.02P

N5 percent potassium nitrate (w/v); P5percent sodium dihydrogen phosphate (w/v); M5 percentmolasses (v/v).


4. The presence of an increased amount of propane in the produced gas was

more like the original gas produced when the field was new.

5. The slope of decline in oil production had lessened from 18% prior to

MPPM to 7.5% when 10 injection wells received nutrients for 12 months.

In light of the fact that MPPM was apparently effective at a moderate

temperature, the question arises as to whether it will work at higher tempera-

tures. It should be pointed out that the temperature of the Carter sand in the

NBCU field is only 32�C, and the question arises as to the highest tempera-

ture at which MPPM would be expected to work. Oil degradation had been

reported in many reservoirs but never in reservoirs at temperatures exceeding

82�C according to Philippi (1977), although Kashefi and Lovley (2003) had

described a thermophilic microorganism that has a maximum growth temper-

ature of 121�C.

TABLE 20.4 Oil Production Response from all Producer Wells Included in

the Project

Well No. Pattern(s) After 12 months June 1998

2-11 No. 1 T1, T4 Positive Positive

2-15 No. 1 T1 None Questionable

11-3 No. 1 T1, T3 None Positive

2-13 No. 1 T1, T3 Positive Positive

34-7 No. 2 T2, C2 None Positive

34-16 No. 2 T2 Positive Questionable

34-15 No. 1 T2, C3 Positive Positive


34-10 No. 1 T2, C2 None Positive

10-8 No. 1 T3 None Positive

11-6 No. 1 T3 Positive Positive

11-4 No. 1 T3 None None

2-11 No. 2 T4 Positive Positive


2-5 No. 1 T4, C1, C4 None None

35-13 No. 1 C1 Natural Decline Natural Decline

35-14 No. 1 C1 Shut-in �3-1 No. 1 C1, C3, C4 Natural Decline Natural Decline

34-2 No. 1 C2 Natural Decline Positive

34-6 No. 1 C2 Shut-in �3-3 No. 1 C3 Natural Decline Natural Decline

3-1 No. 2 C3, C4 a a

3-9 No. 1 C4 Natural Decline Positive

aOil production increased due to an increase in the volume of injection water in control injectorwell 3-2 No. 1.


To help answer the question in regard to temperature, an opportunity pre-

sented itself wherein we were able to evaluate MPPM in an oil field with a

petroliferous formation at a temperature of 115�C. The experiment was con-

ducted in an oil field that was currently undergoing CO2 flooding as the sec-

ondary method of oil recovery. While no cores were available from the field,

a core was obtained from a nearby field from the same petroliferous

FIGURE 20.4 Electron micrograph of a sample of core from a test production well (note the

scattered microbial cells) (Stephens et al., 2000).

FIGURE 20.5 Electron micrograph of a sample of core from a test production well (note the

large number of microbial cells) (Stephens et al., 2000).


formation. The temperature of the petroliferous formation from which the

core was obtained was 115�C. In order for MPPM to function, microorgan-

isms must be present and be able to grow. Since the temperature of the pet-

roliferous formation was greater than the boiling point of water (100�C), aspecial device was constructed to test for microorganisms capable of growing

at 115�C (see Figure 20.6). Microorganisms must have water in the liquid

state in order to grow and, therefore, by completely filling the device, the

water will remain in the liquid state even though the temperature is greater

than 100�C. Samples from the inner portion of the core were placed in these

specially constructed containers along with simulated injection water con-

taining potassium nitrate and disodium hydrogen phosphate. After 50 days of

incubation at 115�C, stains were made of the contents of the containers but,

microbial cells could not be distinguished from the particulate matter from

the core. Electron microscopic examination also failed to differentiate

between particulate material from the core and microbial cells. Therefore,

the material was stained with propidium iodide, a DNA stain and DNA was

shown to be present in the samples. The material was also stained with a sec-

ond DNA stain (DAPI, 40-6-diamino-2-phenylindole) and it likewise showed

the presence of DNA in the samples. Thus, not only were there microorgan-

isms present in the core material at 115�C, but they were able to proliferate

when given nitrate and phosphate. Since microorganisms were present in the

core from the same formation as the petroliferous formation in the oil field,

it was decided to go forward with the field trial.

While the project is not complete at this time, the results thus far are cer-

tainly encouraging. One of the producer wells has shown an increase of

100 bbl a day, another well has increased production by 50 bbl, and three

other wells have shown 5�10 extra barrels a day. Chemical analyses showed

that there were also changes in the composition of the produced oil

FIGURE 20.6 Device designed to act as a growth chamber that can be incubated in an oven at

a temperature of 115�C.


indicating the presence of new oil. More importantly, it was shown that

microorganisms were indeed present in petroliferous formations at a temper-

ature of 115�C and will grow when supplied with the nutrients necessary for

growth. This greatly expands the number of oil fields where MPPM can

potentially be employed. It also has been shown that fields employing CO2

flooding as the secondary recovery method are candidates for MPPM. The

upper temperature limit at which MPPM can be employed is not known, but

according to Setter, Hoffmann, and Huber the highest theoretical limit for

life is 150�C (Ollivier and Magot, 2005).

20.5 FUTURE STUDIES

A review of the literature reveals that many of the patents relating to MEOR

were conducted in the laboratory, not in the field and, therefore, do not take into

account the problems associated with the characteristics of the petroliferous

formation themselves. As stated earlier, it is virtually impossible to inject micro-

organisms any appreciable distance into the petroliferous formation as shown

by many workers (Beck, 1947; Chang and Yen, 1984; Davis and Updegraff,

1954; Hitzman, 1962; Jack et al., 1991; Lappin-Scott et al., 1988; O’Bryan and

Ling, 1949; Updegraff, 1983). Thus only a small percentage of the oil will be

recovered even if the microorganisms recover 50% of the remaining oil. For

example, if an oil reservoir had a thickness of 20 ft, with a porosity of 18%, and

an oil saturation of 65%, and the injected microorganisms recovered 50% of the

oil within a radius of 100 ft area, it would only recover 4572 bbl of oil.

However, if the injection well was in the center of four producing wells in a

40-acre tract with indigenous microorganisms in the formation, even if it only

recovered 25% of the oil, it would recover 238,858 bbl of oil. Of course it

would require more nutrients, but the reward would be 13 times more oil recov-

ered than if four single wells were treated as above.

Another point worth considering is the purpose for which the microbial

growth is being stimulated. If the purpose of adding microorganisms to the

formation or stimulating them or those indigenous to the formation to grow

and produce solvents, detergents, etc. will require large numbers of microor-

ganisms to produce the quantities of solvents or detergents needed.

Contrariwise, if the purpose of feeding the indigenous microorganisms in the

formation is to alter the direction of the flow of water in a waterflood, it will

require considerably fewer microorganisms to accomplish the goal.

Furthermore, it has been pointed out that microorganisms behave one way in

the laboratory but behave differently in the field (Kashefi and Lovley, 2003).

Obviously, in order to study the microflora of the petroleum formation,

obtaining a core must be done at the time the well is being drilled. While

sidewall samples can be obtained later, their value is limited. Some investi-

gators have attempted to retrieve microorganisms from the production fluids

but there is a serious question as to whether they represent microorganisms


indigenous to the petroliferous formation. Most of the microorganisms in the

petroliferous formations are attached to the stratal material and therefore not

free-floating. Also, many of the microorganisms are in the UMB form, and

our experience has been that many UMBs cannot be cultured in normal

media (many of them require diluted media).

Another consideration that must be taken into account is the temperature

of the petroliferous formation. Temperatures of near the boiling point of

water (100�C) require special facilities in order to grow the microorganisms.

Similarly, some of the waters in the petroliferous formations contain higher

than normal salinities as well as pH values distant from 7.0. While our

experiences have shown that most microorganisms obtained from cores of

the petroliferous formations have the ability to use oil as a food, other micro-

organisms from the formation may have other nutritional requirements.

Most of the procedures involving MEOR are directed toward the produc-

tion of chemicals that assist in the recovery of more oil, such as biosurfactants.

It is evident that this will require large numbers of microorganisms situated

throughout the petroliferous formation to have any impact on the recovery of

more crude oil from the formation. Therefore, the question is whether you can

produce or add a sufficient number of microorganisms to accomplish the pro-

duction of biosurfactant and other products to enhance oil recovery without

plugging the petroliferous formation. Under these circumstances it is easy to

see where the method of redirecting the flow of water from the injection well

to the production wells requires fewer cells to be effective, as is the case in

our examples. The question then becomes how many petroliferous formations

have a resident population of microorganisms. Obviously, more cores from a

variety of wells need to be examined to insure the presence of microorganisms

in the cores. Thus far we have found microorganisms in all of the 17 cores we

have examined from petroliferous formations

It has been pointed out that the MPPM has been the most successful

method of recovering more oil because indigenous bacteria were employed

(Maudgalya et al., 2007). Additionally, when nitrate is used as one of the

compounds to feed the indigenous bacteria, it will inhibit the sulfate-

reducing bacteria that produce hydrogen sulfide that is undesirable in the

produced oil and lowers the value of the produced oil. It is obvious that in

order for the use of microorganisms to gain acceptance by the oil industry,

quantitative measures of microbial performance must be established and ver-

ified scientifically.

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