Research Methods – Individual Assignment .docx

Research Methods – Individual Assignment
FDBPA
Research Proposal
Word count 510
Contents
I.Introduction2
II.Literature Review2
III.Empirical Survey Draft3
IV.Conclusion and expected outcomes4
V.References5
VI.Bibliography5
Introduction
Further Education (FE) college managers are under increased
pressure to present accurate financial information. Government
funding methodologies constantly change, annual guidance
documents verifies this. Funding streams are increasing in
number and complexity. Therefore, managers need an analysis
tool to provide timely, effective and efficient information to
equip them in decision making when matching funding to costs.
Literature Review
For accounting and analysis purposes each qualification taught

in college can be considered an activity. Therefore ABC is
considered most appropriate form of costing. A search of the
latest academic publications produced many articles relating to
Activity-Based Costing (ABC). The table below illustrates
articles chosen with their corresponding research philosophies,
methodologies and methods used to formulate this report. All
five have an epistemological philosophy theory.
Article Title
Paradigm of Social Science
Research Method
Data Collection Method
ABC: Is it still relevant?
Positivism
Quantitative
Survey
Does your costing system need a tune-up?
Interpretivism
Qualitative
Case Study
Performance Operations
Interpretivism
Qualitative
Study Notes Paper
ABC user satisfaction and type of system
Positivism
Quantitative
Survey
Activity-Based Management Systems in H.E.
Interpretivism
Qualitative
Case Study
ABC is the second most used costing system, standard costing

being the most popular and arguments for using ABC were
stronger from current users than non-users of the system. This
indicates a satisfaction of the user once ABC has been adopted.
(Stratton et al, 2009). Results of a quantitative research article
provide ample support for the conclusion that ABC methods
provide significant value to managers (Waldrup et al, 2009).
Higher Education (HE) has similar accounting requirements to
FE and with the introduction to more HE qualifications to FE,
the article on HE activity-based management provides an
informative case study and models.
Empirical Survey Draft
From the hypnosis, will ABC provide FE colleges with an
effective costing system? Empirical evidence will be analysed
combining quantitative and qualitative forms of research.
A questionnaire to all FE college accountants in the UK,
questioning the type of costing systems used and satisfaction
levels of the users. This primary data will be analysed using
computer software process SPSS. The research should be
reliable, valid and objective; these factors will need to be taken
into account when composing the questions. This quantitative
approach to research fits with the philosophical framework of
positivism.
Interviews, one-to-one and/or groups, with college managers of
ABC systems from similar size college and qualification offer.
These will bring a depth of understanding to the research on
ABC. This primary data will enable a qualitative approach to
the research that is usually subjective. Interview questions are
open in nature unlike questionnaire questions that need to be
closed to elicit answers that can be coded for analytical
purposes.
Further literature reviews on ABC will bring about a
triangulation approach to produce an accurate account and
reliable research.
Word count 510Conclusion and expected outcomes
Current changes to FE funding methodology and findings from
the review have suggested a gap in knowledge pertaining to

ABC in FE colleges. This led to a research question, ‘Is
activity-based costing an effective budgetary tool for FE
colleges?’
References
Stratton, W. O., Desroches, D., Lawson, R. A., & Hatch, T.
(2009). Activity-based costing: Is it still relevant? Management
Accounting Quarterly, [e-journal] 10(3), pp. 31-40.
ABI/INFORM complete.
Available at:
http://ezproxy.kingston.ac.uk/docview/222805126?accountid=14
557
[Accessed 07 May 2012]
Waldrup, B. E., C.P.A., MacArthur, J. B., F.C.C.A., &
Michelman, Jeffrey E,C.M.A., C.P.A. (2009). Does your costing
system need a tune-up? Strategic Finance, [e-journal]90 (12),
pp. 47-51. ABI/INFORM complete.
Available at:
557
Bibliography
Grahame, S. (2010). Performance Operations. Financial
Management, [e-journal] Jan/Feb 2010, pp. 40-44. Business
Source Premier
Available at:
http://web.ebscohost.com/ehost/results?sid=ca1c3149-575e-
45e3-940c-
6731be501d42%40sessionmgr111&vid=2&hid=108&bquery=JN
+%22Financial+Management+(14719185)%22+AND+DT+20100
101&bdata=JmRiPWJ1aCZ0eXBlPTEmc2l0ZT1laG9zdC1saXZl

McClery, S., McKendrick, J.and Rolfe, T. (2007). Activity-
Based Management in Higher Education, Public Money &
Management, [e-journal] 27 (5), pp. 315-322. Taylor and
Francis Online
Available at:
http://www.tandfonline.com/doi/abs/10.1111/j.1467-
9302.2007.00602.x
Pike, R. H., Tayles, M. E. and Mansor N. N. A. (2011).
Activity-based costing user satisfaction and type of system: A
research note, The British Accounting Review, [e-journal] 43
(1), pp. 65-72. ScienceDirect
Available at:
http://www.sciencedirect.com/science/article/pii/S08908389100
01198
Quinlan, C. (2011) Business Research Methods. Hampshire:
Cengage
Stratton, W. O., Desroches, D., Lawson, R. A., & Hatch, T.
(2009). Activity-based costing: Is it still relevant? Management
Accounting Quarterly, [e-journal] 10(3), pp. 31-40.
ABI/INFORM complete
Available at:
557
Waldrup, B. E., C.P.A., MacArthur, J. B., F.C.C.A., &
Michelman, Jeffrey E,C.M.A., C.P.A. (2009). Does your costing
system need a tune-up? Strategic Finance, [e-journal]90 (12),
pp. 47-51. ABI/INFORM complete
Available at:

557
Page 1 of 5
LITERATURE REVIEW:
Tarmats is a topic that has not been studied very often, leading
to a lack of published literature on the subject. The limited
literature can very well be explained by the concentration of
this problem in the Middle East.
One of the big contributors to the tarmat literature is Moor who
studied tarmat presence, distribution and nature, as well as
asphaltic sands and bitumens in reservoirs. He found four
different organisms that contribute to the tarmats’ formation
(Moor 1984).
(1) Water Washing: The removal of a portion of light
hydrocarbons, and allowing the asphaltic fraction to locate itself
at the foundation of oil accumulation.
(2) Gravity Segregation: In this procedure the resistance attracts
the heavier hydrocarbons towards the foundation, and the
lighter hydrocarbons move upwards.
(3) Natural Deasphalting: The entrance of natural gases from
source rock and their rise through the hydrocarbon column due
to buoyancy. Such an action would result in a lower solubility
and case the asphaltic fraction to precipitate and rest at the
foundation of the reservoir.
(4) Biodegradation: Meteoric water moves beneath the pooled
reservoir, along transmitting bacteria use to metabolize crude
oil’s lighter fraction. Thermal currents located in the reservoir
would distribute lighter fraction to the oil/water located at the
base where the bacteria is active. As a result, the formation of a
tarmat is witnesses near the foundation of the reservoir.
Moor’s research extends to other areas, such as the five
different groups of subsurface tar seal occurrences due to the

level of concentration, continuation, and the structural position.
The distribution of hydrocarbon within entire basis or
individual traps is controlled by Tar seals associated with
unconformities. Additionally, the tar seal that do occur at the
unconformities are categorized in five different groups (Figure
2.1).
(i) Tar seals with four-way closure located above traps.
(ii) Tar seals located alongside the margins of overly matured
basins
(iii) Oil first trapped by tar seals and then reallocated through
basin deformation.
(iv) Trapped oil by tar seals and deeper structures.
(v) Tar seals advantageously traps the oil.
Those reservoirs which have many levels of these
characteristics are known as tarmat reservoirs. Such type of
reservoir is come across the World mainly in Middle East (Moor
1984).
Figure 2.1 Tar seal Classification (Moor 1984)
Abdul Aziz Al-Kaabi et al tell that there are so many searches
done in WOR and oil recovery and many shapes of layers of tar
are observed physically and also numerically in order to study
the behaviour and working of WOR and recovery of oil. From
all these researches four cases were found which are studied as
square barrier beneath the well a disk beneath the well, a hollow
square or disk beneath the well, and a half plane. The research
conducted on these four cases shows that in hollow tarmat
barrier case, the breakthrough time comes earlier, and if we
consider the disk beneath the well case breakthrough time is
delayed as well because WOR shoots very rapidly. No-barrier
case got the highest recovery from all the cases discussed. And
hollow tarmat barrier got the least recovery. Many of the major
oil reservoirs in Middle East have the issue of tar barrier of oil
zone and the underlying water zone, which have a very strong
bottom water drive. Many investigations are done which can be
used for increasing oil recovery from such type of reservoirs.

There is no work published on this issue in Iraq, Kuwait and
Saudi Arabia. Many models and schemes are made; initially
three zones were set in the models namely oil zone which is at
the top, water zone which is placed in the middle and tar zone
which is placed at the bottom. The oil and tar zone have the
thickness which is varied in order to fulfil the variety of
conditions. And the water zone is protected with water drive.
There are many different types of techniques which is done
named internal water flood with bottom water drive, internal
water flood without bottom water drive, injection of solvent,
injection of steam into (a) water zone, (b)oil zone, (c)tar zone
(Abdul Aziz Al-Kaabi et al 1988)
In Venezuela and North America many literatures were
published on recovery of oil. Tarmats are introduced in
reservoirs in Kuwait, South Iraq and Qatar. In Saudi Arabia
huge accumulations of tar are reported in fields named Manifa,
Khursaniyah and in many others fields. In Ghawar the tar zone
exceeds from more than 15 miles and in Uthmaniya tar zone
goes up to 500 ft with respect to its thickness ( Abdul Aziz Al-
Kaabi et al 1988).
Osman during 1985, published a study regarding Minagish field
located in Kuwait. The case of Minagish field in Kuwait
represented a very typical case of tarmat reservoirs in which tar
is in
cluded at the contact of oil-water and usually has a thickness
that ranges between 30 feet and 115feet. In Figure 2.2 presents
the average rock properties and the structural cross-section of
the MN-26 injector showing the tarmat (Osman 1985).
Initially, the Minagish field was supposed to have water
flooding below the tarmat. This was also the reason, whey the
discussion of a possible tarmat breakdown due to the waterflood
below the tar zone. Figure 2.3 demonstrate the graphical method
that Osman used in order to predict the different pressure rates
at the tarmats depending on the injection rate and time. In
comparison, Figure 2.4 represents the curves of differential
pressure of the water that was injected versus injection time

depending on the distance of the injector. Osman’s study overall
was fascinating; however one of the most important discoveries
was that water injection was the main effect on differential
pressure across tarmats, than the oil production. Lastly, Osman
recommended a way of finding the response time at the well
that can be observed, and allow for time to complete the switch
injection from below to above the tarmat. (Osman 1985).
Regardless, of all the quantitative results that Osman presents,
his model is very simplistic to represent the such a complicated
problem. Osman made a few assumptions that were
questionable, such as:
1) The consideration of a tarmat as a rigid barrier breaking at
15psi/foot as a pressure gradient.
2) The increase in pressure due to water injection is preeminent,
while the decrease in pressure because of oil production is
insignificant.
3) The way he applied the superposition theory is uncertain in
this study at least.
4) Osman fails to mention the rheology and the characteristics
of the tar.
5) Lastly, he fails to provide and discuss the geometric
description of the tarmat that was broken.
An extension of Osman’s work examines the results from
having a sealing fault close to the water injection and the
influence of the sealing fault on the behaviour of the tarmat.
This above mentioned study resulted in a technique that was
able to calculate the time of the tarmat break down, what the
response time was at the nearest well, and lastly the differential
pressure at the tarmat located anywhere in the reservoir (Osman
1986).
TAR MATS CHARACTERIZATION FROM NMR AND
CONVENTIONAL LOGS, CASE STUDIES IN DEEPWATER

RESERVOIRS, OFFSHORE BRAZIL
João de D. S. Nascimento and Ricardo M. R. Gomes -
PETROBRAS
Copyright 2004, held jointly by the Society of Petrophysicists
and
Well Log Analysts (SPWLA) and the submitting authors.
This paper was prepared for presentation at the SPWLA 45th
Annual Logging Symposium held in Noordwijk, The
Netherlands,
June 6–9, 2004.
ABSTRACT
Tar mats can be defined as hydrocarbon horizons
with high asphaltene concentrations (20% to 60%
in weigh) and high viscosity – typically more than
10,000 cp at reservoir conditions. As a
consequence of these characteristics, tar mats
represent a volume of hydrocarbon in place that
are very difficult or even impossible to be
produced and frequently form vertical
permeability barriers. The occurrence of these
high viscosity hydrocarbon layers is generally at
the bottom of the oil column. Therefore they can
isolate the oil leg from the aquifer. In these cases,
the producing drive mechanism will be by
expansion in a volumetric reservoir, instead of
water drive. So, a previous identification of tar
mats will help to correctly quantify reserves and
predict recovery with maximum efficiency.
Nuclear Magnetic Resonance logs in conjunction
with conventional logs can provide accurate
identification of tar mat levels and viscosity

estimation, from empirical relationships. In this
paper we present field examples of tar mat
characterization from NMR and conventional
logs, supported by formation pressure
measurements in the aquifer and in the oil leg.
Despite a very clear continuity of the reservoir all
along the aquifer and oil leg, with an obvious
oil/water contact, pressure data show evidence of
depletion by production in the oil column,
whereas in the water zone no pressure drop is
noted.
In the studied field examples, tar mat levels are
tens of meters thick and estimated viscosities are
around 20,000 cp. The NMR responses (total
porosity and T2 distribution) are very different in
the oil leg when compared to the tar mat
horizons, as a result of the low hydrogen index
levels and high viscosities in the tar mats,
compared to the hydrogen indexes and viscosities
of the medium/light oil. Also, because of the
hydrogen index, the total porosity values
measured by NMR and density logs are very
different in the tar mat levels, but they have good
agreement in the aquifer and oil zone. Neutron
porosity is also affected, in minor intensity, by the
low hydrogen index of tar mats. Additionally,
resistivity logs show different responses due to
the low mobility of tar mats when compared to
the oil leg. The non-consolidated characteristic of
the reservoirs in addition to the absence of mud
cake along the tar mat intervals due to low filtrate
invasion, result in caliper enlargement all along
these high viscosity levels but not in the oil zone
or in the aquifer.

INTRODUCTION
Tar mats in petroleum reservoirs are zones of
variable thickness – less than 1 meter to over 100
meters – containing extra heavy oil or bitumen,
typically with gravity under 10 °API and/or
viscosity in situ above 10,000 cp, generally at the
bottom of the oil column (Nascimento and Pinto,
2003). The high gravity and viscosity of tar mats
stems from the high asphaltene content, normally
20 to 60% weight (Wilhelms and Larter, 1994).
Asphaltenes are considered the highest molecular
weight hydrocarbon compounds in petroleum.
The chemical structure of these compounds is
mainly formed by carbon (100 to 300 atoms per
molecule), hydrogen, sulfur, nitrogen, oxygen and
minor proportions of nickel and vanadium
(Pineda-Flores, 2001).
Gravitational segregation is the main process
causing asphaltene enrichment and tar mat
formation in crude oil. It is governed by different
factors controlling the asphaltene stability in oil
FF
1
solution, like the in situ oil composition, pressure
and temperature (Hirschberg, 1984; Boer, 1992).
Tar mats at the bottom of oil reservoirs can be
expressed as the extreme manifestation of oil

compositional variation, caused by gravitational
segregation of asphaltenes (Hirschberg, 1988).
Tar mats identification in exploration wells is
crucial because this high viscous oil zones may
contain important volumes in place that are very
difficult or even impossible to be produced and
therefore must be considered as non-reserves.
Furthermore, tar mats may occur in large areas,
with high thickness, forming vertical permeability
barriers, isolating the oil leg from the aquifer and
therefore, preventing water drive production
mechanism.
TAR OR BITUMEN IDENTIFICATION
FROM RESISTIVITY LOGS
Because of the very low mobility of high
viscosity oil, such as tar or bitumen, resistivity
logs have been the main wireline devices used for
characterization of this type of hydrocarbon in
reservoirs. Arab (1990) reports the use of deep
(Rt) and shallow (Rxo) resistivity curves to
identify bitumen occurrence in Upper Zakum
Field (Abu Dhabi).
In Upper Zakum Field, with mud filtrate
resistivity (Rmf) higher than connate water
resistivity (Rw), the following typical responses
were achieved, according to Arab (1990):
• In the oil bearing zones ⇒ Rxo reads
less than Rt;
• In the water bearing zones ⇒ Rxo reads
higher than Rt;

• In the bitumen occurrence zones ⇒ Rxo
reads higher than Rt like in the water leg
but with higher resistivity values.
Arab (1990) explained the resistivity responses in
bitumen intervals by the mud filtrate ability to
flush formation water from nearby hole, while not
capable to flush the bitumen. Therefore, in the
invaded zone, Rxo reads bitumen resistivity plus
Rmf while in the virgin zone Rt reads bitumen
resistivity plus Rw. Since Rmf is higher than Rw
and bitumen resistivity is constant in both zones,
then Rxo will read higher than Rt in bitumen
zones, as verified in field case.
Also, according to Kopper (2001), in the Orinoco
Heavy Oil Belt in Venezuela, when Rxo reads
higher than Rt, means that no movable oil (or tar)
exists in the logged interval. A whole interval
core indicated that the zone was oil-satured,
however, it produced very little oil during the drill
stem test.
Some authors such as Wilhelms, Carpentier and
Huc (1994), report the comparison between deep
and shallow resistivity curves plus the Sw and
Sxo values, to recognize tar mats because of their
very low mobility when compared with
producible oil. These authors don’t use the Rxo
higher than Rt condition to characterize the tars.
The same values of resistivity curves, or same
water saturations, are considered enough to
identify tar levels.

TAR OR BITUMEN CHARACTERISTICS
AND VISCOSITY ESTIMATION FROM
NMR LOGS
The NMR porosity is derived from the signal
amplitude, which is proportional to the hydrogen
index (HI) of fluids in the porous rocks. The HI
of pure water is defined as 1 and it is used to
calibrate all the measurements. For alkanes,
which are the major constituents of light crude
oils, the HI is also equal to 1. So, light oils have
the same signal amplitude of water and,
consequently, same values of porosity are
obtained either in a light oil or in water-bearing
reservoir.
Because of the minor alkane constituents, higher
aromatic contents and non-hydrocarbon
components in heavy oils HI tends to decrease
with increment of oil density. The API gravity is
usually a good HI indicator in crude oil, with
accentuated HI reduction when API gravity
declines below 20. According to Kleinberg
(1996), for a 10 API gravity oil HI is close to 0,7.
Consequently, NMR measurements in heavy oil
zones will exhibit porosity deficit proportional to
the reduced hydrogen index.
Another characteristic of the NMR responses in
heavy oils is the short T2 caused by high
2
viscosity. Morris (1997) empirically found out

that viscosity (η) is a function of T2 log mean:
η0,9 = 1200/T2 log mean (1)
for η in centipoises and T2 log mean in
milliseconds.
Additionally, he noted that along with the
increment of oil viscosity, a tail of shorter
relaxation times in T2 distributions also increases,
representing the heavier components with minor
oil mobility.
To determine in situ oil viscosity by NMR logs
using equation (1) is necessary that oil and water
T2 distributions are not overlapping. In cases of
heavy oil viscosity near or greater than 100
centipoises, for example, the expected T2 log
mean is near or minor than 15 milliseconds and,
in addition, the tail originated from more
restricted motion nucleus spans for very short
relaxation times. In such cases, the oil and
irreducible water signals overlap and
consequently it is not possible to have direct
viscosity estimation.
To determine in situ viscosity of extra heavy and
high viscosity hydrocarbons, such as tar and
bitumen, using NMR logs, LaTorraca (1999)
proposed a empirical equation for indirect
determination based on one of the characteristics
of this type of hydrocarbon – the low hydrogen
index (HI) and therefore, the NMR porosity
deficit when compared with porosity
measurements from others logs unrelated to the
HI.

According to LaTarroca (1999), an apparent HI
(HIapp) can be estimated using as inputs the
porosity estimated from a log insensitive to the HI
of the oil (∅ ), the NMR porosity (∅ NMR) and oil
saturation (So) in the following equation:
HIapp = (So∅ _ ∆∅ )/So∅ (2)
where, ∆∅ is the difference between the porosity
not related to HI and the NMR porosity.
However, the HIapp of heavy oils from NMR
logs also depend on the echo spacing (TE) used in
T2 measurements. Because T2 signal is obtained
from samples at the echo peaks, TE is also the
sampling interval and NMR logging tools don’t
have sampling rates fast enough to detect all the
hydrogen in heavy oils (LaTorraca, 1999).
Correlations between HIapp and oil viscosity as a
function of TE have been established leading to
an equation for heavy oil viscosity (η) estimation:
ln(η)=(11+1.1/TE) _ (5.4+0.66/TE)∗ HIapp (3)
for η in centipoises and TE in milliseconds
(LaTorraca, 1999).
CASE STUDIES
Two fields examples from deep-water reservoirs
with tar mat occurrences at the bottom of oil
column are presented. In the first example (figure
1), well “A”, a tar mat about 40 meters thick

occurs above the aquifer. The top of tar in figure
1 is located approximately at xx52m and the base
is close to xx92m, in the same depth of
hydrocarbon/water contact.
One of the main tar mat characteristics from
NMR logs in well “A” (figure 1) is the unimodal
T2 distribution with shorter mean times, caused
by the high hydrocarbon viscosity, when
compared with T2 signal above xx52m, with
bimodal T2 distribution in the medium/light oil
leg, where capillary water and oil signals are
separated. In the tar mat interval T2 distributions
from hydrocarbon and water signals overlap, and
a pronounced tail of shorter signals is evident
below xx60 m, due to a more restricted motion tar
components (track 5, figure 1).
A good agreement between “total” NMR porosity
and density log porosity (track 4, figure 1) is
evident in the water zone (below xx92 m) and in
the oil leg (above xx52 m), whereas an obvious
porosity difference occurs in the tar mat zone,
where the NMR porosity shows about 8 p.u.
deficit compared to the density log porosity. This
feature is typical of hydrocarbons with short
hydrogen index. Using the porosity deficit (∆∅ )
plus other parameters, as ∅ , So and the
operational TE in equations 2 and 3 results in an
estimated viscosity of approximate 20,000
centipoises.
The resistivity curves response (track 2, figure 1)
corroborated another characteristic of very low
mobility hydrocarbons, in the cases when Rmf is

FF
3
greater than Rw, as already mentioned in previous
works. In the oil leg (above xx52 m) the Rxo
reads less than deep and medium resistivity
curves, while in the tar zone (xx52/xx92 m) the
Rxo reads higher than deep and medium
resistivity, similar to aquifer responses (below
xx92 m) but with greater resistivity values. The
differences in resistivity measurements along the
tar mat interval are caused by the lack of bitumen
displacement and probably because of the ionic
exchange between less salty mud filtrate and
more salty formation water.
The wash out in tar mat interval (track 1, figure 1)
makes clear a particular feature caused by the
insignificant bitumen mobility in this
unconsolidated reservoir. In the oil leg and in the
aquifer, where invasion is effective, mud cake is
formed in the well bore, keeping the caliper near
to the bit size diameter. Whereas, in the tar mat,
where filtrate invasion is more difficult, no mud
cake is formed and the well bore is enlarged by
erosion from mud circulation.
An additional indication of tar mat low hydrogen
index can be observed in neutron log porosity
(track 4, figure 1). Although neutron tools are
sensitive to all hydrogens, including that
associated with minerals – instead of NMR tools
that are only sensitive to hydrogen from fluids – a

minor neutron porosity deficit can also be
observed when compared to density porosity in
tar mat. In contrast, no neutron porosity deficit is
observed in the aquifer or in the oil leg.
Another interesting feature shown in figure 1 is a
vertical viscosity variation along the oil column.
The red flags in track 1 indicate that insufficient
wait time for adequate polarizations occurs at the
top of the oil column, caused by the largest T2
distribution in this zone, corresponding to the
lesser viscous oil in the reservoir. So, light oil
with low viscosity at the top of the reservoir
grades to oil with medium viscosity (xx10/xx52
m), ending in a tar mat occurrence, at the bottom.
The evidence of tar mat occurrence in well “A”
are validated from pressure measurements in the
oil and water zones. Although a very clear
continuity of the reservoir all along the aquifer
and oil column, with an obvious
hydrocarbon/water contact, pressure data show
evidence of depletion by production in the oil leg
whereas in the water zone no pressure drop is
noted.
Figure 2 shows a depth vs pressure crossplot from
wireline tests along the oil and water intervals.
The pressure gap between the oil column and
water zone is evident. Because of the enlarged
caliper and or very low fluid mobility, no pressure
was obtained in the tar mat zone. The expected
pressure in the hydrocarbon/water contact
projected from the oil pressure gradient is 150 psi
lesser than measured pressure at the top of aquifer

interval, characterizing the hydraulic
discontinuity between the aquifer and the oil leg.
The second field example (figure 3), well “B”, is
in the same area of well “A”. A tar mat near 55
meters thick and identical well log characteristics
also occurs below the oil column, but in this case,
no aquifer is present, instead the tar mat lies
directly on a shale sequence.
In this example it is not possible to confirm the
tar mat as a hydraulic seal because of the obvious
absence of a hydrocarbon/water contact.
Nevertheless, all well log characteristics noted in
xx52/xx92 m interval of well “A” are also present
in xx20/xx75 m interval of well “B”, which is a
relevant evidence of tar mat occurrence in the
second well.
In well “B” (figure 3), the end of bimodal T2
distribution and the start of overlapping short time
oil signals and water signals are around xx20 m
(track 5). At this depth, initiates the apparent
“total” NMR porosity deficit, compared to density
log porosity (track 4); the neutron porosity deficit,
compared to density log porosity (track 3); the
crossover of resistivity curves with Rxo reading
higher than Rt (track 2) and the washed out hole
section (track 1).
All the described characteristics of well “B” are
restricted to the interval xx20/xx75 m. Above
and below this interval occur respectively
medium viscous oil in a fine and laminated
reservoir and a shale sequence; both with their
peculiar log characteristics, very different from

tar mat log responses.
4
CONCLUSIONS
The tar mat resistivity log responses from field
examples presented in this paper are similar to the
ones described in previous works, for the
common condition of Rmf higher than Rw.
Additionally, another tar or bitumen log
characteristics derived from the low hydrogen
index and high viscosity of this type of
hydrocarbon were recognized in NMR logs and
also discussed. A particular characteristic of non-
invaded unconsolidated reservoirs was also
evidenced from wash outs in the tar mat intervals.
Original pressure in the aquifer and depletion in
oil column after production, confirmed from
wireline pressure data in well “A”, enabled a
validation of the well log indications and created
high confidence log response patterns to a reliable
tar mat identification, including for situations
where the aquifer is absent.
ACKNOWLEDGMENTS
The authors would like to thank PETROBRAS
for the support and permission to publish the data.
We also thank the geologist Almério Barros
França for his valuable help, revising the original
text.

REFERENCES
Arab, H., 1990, “Bitumen Occurrence and
Distribution in Upper Zakum Field”, Society of
Petroleum Engineers, Paper Number 21323.
Boer, R. B. de, et al., 1992, “Screening of Crude
Oils for Asphalt Precipitation: Theory, Practice
and the Selection of Inhibitors”, Society of
Petroleum Engineers, Paper Number 24987.
Hirschberg, A., et al., 1984, “Influence of
Temperature and Pressure on Asphaltene
Flocculation”, Society of Petroleum Engineers
Journal, June 1984, 283-294.
Hirschberg, A., 1988, “Role of Asphaltenes in
Compositional of Reservoir’s Fluid Column”,
Journal of Petroleum Technology, January 1988,
89-94.
Kleinberg, R. L., et al., 1996, “NMR Properties of
Reservoir Fluids”, The Log Analyst, November -
December 1996.
Kopper, R., et al., 2001, “Reservoir
Characterization of the Orinoco Heavy Oil Belt:
Miocene Oficina Formation, Zuata Field, Eastern
Venezuela Basin”, Society of Petroleum
Engineers, Paper Number 69697.
LaTorraca, G. A., et al., 1999, “Heavy Oil
Viscosity Determination Using NMR Logs”,
SPWLA 40th Annual Logging Symposium, May
30 – June 3, 1999.

Morriss, C. E., et al., 1997, “Hydrocarbon
Saturation and Viscosity Estimation from NMR
Logging in the Belridge Diatomite”, The Log
Analyst, March – April 1997.
Nascimento, J. de D. S., and Pinto, A. C. C.,
2003, “Tar Mats – Gênese, Caracterização e
Implicações em E&P”, Internal Report,
PETROBRAS.
Pineda-Flores, G., et al., 2001, “Petroleum
Asphaltenes: Generated Problematic and Possible
Biodegradation Mechanisms”, Revista
Latinoamericana de Microbiología, Volume 43,
Number 3, pp. 143-150.
Wilhelms, A., and Later, S. R., 1994, “Origin of
Tar Mats in Petroleum Reservoirs”, Marine and
Petroleum Geology, Volume 11, Number 4, pp.
418-456.
Wilhelms, A., Carpentier, B., and Huc, A. Y.,
1994, “New Methods to Detect Tar Mats in
Petroleum Reservoirs”, Journal of Petroleum
Science and Engineering 12, pp. 147-155.
ABOUT THE AUTHORS
João de D. S. Nascimento is a geologist at the
Exploration Department of PETROBRAS. He has
been working as log analyst ever since joining
PETROBRAS in 1976.
Ricardo M. R. Gomes is a geologist and
petrophysicist with PETROBRAS, where he has
been working as an exploration geologist since

1977. He holds a B.Sc. degree in geology from
the Universidade Federal do Rio de Janeiro,
Brazil (1976) and a M.Sc. degree in geology from
the Colorado School of Mines (1999).
FF
5

Figure 1 – Log responses in Well “A”. A tar mat was identified
in the interval xx52/xx92 m, from T2
distribution (track 5), large total NMR porosity deficit (track 4),
slight neutron porosity deficit (track 3), Rxo
higher than Rt (track 2) and wash out (track 1).
xx00
xx50
xx00
6
Figure 2 – Depth vs pressure cross plot in well “A”. Pressure
distribution shows the evidence of a
permeability barrier between the oil column and the aquifer,
given by the tar mat at the bottom of the oil
column, as indicated from log responses along xx52/xx92 m
interval.

PRESSURE x DEPTH
3450
3500
3550
3600
3650
3700
3750
3800
3850
4750 4800 4850 4900 4950 5000 5050 5100 5150 5200 5250
5300 5350
PRESSURE (psi)
D
E
P
T

H
(
m
)
Pressures in Depleted Oil Column
Original Pressures in Aquifer
150 psi Gap at HC/Water Contact
Tar Mat Zone
(xx52/xx92 m)
xx
xxxxxxxx xxxx xx xxxx xxxxxxxx
xx
xx
xx
xx
xx
xx
xx
xx
Well “A” - Pressure x Depth

PRESSURE x DEPTH
3450
3500
3550
3600
3650
3700
3750
3800
3850
4750 4800 4850 4900 4950 5000 5050 5100 5150 5200 5250
5300 5350
PRESSURE (psi)
D
E
P
T
H
(
m
)

Tar Mat Zone
(xx52/xx92 m)
xx
xx
xx
xx
xx
xx
xx
xx
xx
Well “A” - Pressure x Depth

Tar Mat Zone
(xx52/xx92 m)
xx
xx
xx
xx
xx
xx
xx
xx
xx
Well “A” - Pressure x Depth FF
7

Figure 3 – Log responses in Well “B”. A tar mat was recognized
in xx20/xx75 m interval, with identical log
responses observed in well “A”. In this case no aquifer is
present. The tar mat lies directly above a shale
sequence.
xx50
xx00
xx50
8

MAIN MENUPREVIOUS MENU---------------------------------
Search CD-ROMSearch ResultsPrint
odd_pg1: SPWLA 45th Annual Logging Symposium, June 6-9,
2004even_pg2: SPWLA 45th Annual Logging Symposium, June
6-9, 2004odd_pg3: SPWLA 45th Annual Logging Symposium,
June 6-9, 2004even_pg4: SPWLA 45th Annual Logging
Symposium, June 6-9, 2004odd_pg5: SPWLA 45th Annual
Logging Symposium, June 6-9, 2004even_pg6: SPWLA 45th
Annual Logging Symposium, June 6-9, 2004odd_pg7: SPWLA
45th Annual Logging Symposium, June 6-9, 2004even_pg8:
SPWLA 45th Annual Logging Symposium, June 6-9, 2004
SPE 163292
Permeable Tar Mat Formation Within the Context of Novel
Asphaltene
Science
Hadrien Dumont, Vinay Mishra, Julian Y. Zuo, Oliver C.
Mullins (Schlumberger)
Copyright 2012, Society of Petroleum Engineers
This paper was prepared for presentation at the SPE Kuwait
International Petroleum Conference and Exhibition held in
Kuwait City, Kuwait, 10-12 December 2012.
This paper was selected for presentation by an SPE program
committee following review of information contained in an
abstract submitted by the author(s). Contents of th e paper have
not been
reviewed by the Society of Petroleum Engineers and are subject
to correction by the author(s). The material does not necessar
ily reflect any position of the Society of Petroleum Engineers,

its
officers, or members. Electronic reproduction, distribution, or
storage of any part of this paper without the written consent of
the Society of Petroleum Engineers is prohi bited. Permission to
reproduce in print is restricted to an abstract of not more than
300 words; illustrations may not be copied. The abstract must
contain conspicuous acknowledgment of SPE copyright.
ABSTRACT
Tar mats at the oil-water contact (OWC tar mats) in oilfield
reservoirs can have enormous, pernicious effects on production
due to possibly preventing of any natural water drive and
precluding any effectiveness of water injectors into aquifers. In
spite of this potentially huge impact, tar mat formation is only
now being resolved and integrated within advanced asphaltene
science. Herein, we describe a very different type of tar mat
which we refer to as a “rapid-destabilization tar mat”; it is the
asphaltenes that undergo rapid destabilization. To our
knowledge, this is the first paper to describe such rapid-
destabilization
tar mats at least in this context. Rapid-destabilization tar mats
can be formed at the crest of the reservoir, generally not at the
OWC and can introduce their own set of problems in
production. Most importantly, rapid-destabilization tar mats can
be

porous and permeable, unlike the OWC tar mats. The rapid-
destabilization tar mat can undergo plastic flow under standard
production conditions rather unlike the OWC tar mat. As its
name implies, the rapid-destabilization tar mat can form in very
young reservoirs in which thermodynamic disequilibrium in the
oil column prevails, while the OWC tar mats generally take
longer (geologic) time to form and are often associated with
thermodynamically equilibrated oil columns. Here, we describe
extensive data sets on rapid-destabilization tar mats in two
adjacent reservoirs. The surprising properties of these rapid-
destabilization tar mats are redundantly confirmed in many
different ways. All components of the processes forming rapid-
destabilization tar mats are shown to be consistent with
powerful new developments in asphaltene science, specifically
with
the development of the first equation of state for asphaltene
gradients, the Flory-Huggins-Zuo Equation, which has been
enabled by the resolution of asphaltene nanostructures in crude
oil codified in the Yen-Mullins Model. Rapid-destabilization
tar mats represent one extreme while the OWC tar mats
represent the polar opposite extreme. In the future, occurrences
of tar
in reservoirs can be better understood within the context of
these two end members tar mats. In addition, two reservoirs in
the

same minibasin show the same behavior. This important
observation allows fluid analysis in wells in one reservoir to
indicate
likely issues in other reservoirs in the same basin.
INTRODUCTION
Tar mats are of critical importance in the oilfield; however,
mechanisms of tar mat formation have not been well
understood.
The confusion extends into terminology where terms bitumen
and tar are sometimes meant to imply distinct yet ill-defined
provenances. In large part, this is due to the prior lack of
detailed understanding of asphaltenes. Indeed, it is only
recently that
the nanoscience of asphaltenes in crude oil has been largely
resolved and codified in the “Yen-Mullins Model”.[1,2] In turn
this has led to the Industry’s first predictive equation for
asphaltene gradients, the Flory-Huggins-Zuo Equation of State
(FHZ
EoS).[3,4] With this new understanding, asphaltenes are now
treated within standard methods of physical chemistry much as
gas-liquid equilibria of crude oils (GOR, bubble point, etc.)
have long been treated with standard physical chemistry models
such as the cubic equation of state. The cubic EoS has been
extended to try to treat the solid asphaltenes because there had

been no alternative. However, the cubic EoS was never designed
to treat colloidal solids such as asphaltenes; consequently,
these cubic EoS methods to treat asphaltenes fail.[1-4] Just as
gradients (e.g. GOR gradients) and phase behavior for gas
liquid equilibria are treated by the cubic EoS, we now have an
equation, the FHZ EoS that treats both asphaltene gradients in
reservoir fluids as well as phase behavior of asphaltenes. Thus,
asphaltenes whether in carbonaceous deposits or dissolved (or
colloidally suspended) in crude oil are now treated within one
scientific framework. Consequently, tar mats are now
understood within the framework of reservoir fluids and
corresponding geologic processes.
2 SPE
By definition, asphaltenes are destabilized by light alkane
addition to a crude oil. (Asphaltenes are defined as being the
component of crude oil, or carbonaceous material that is
insoluble in n-heptane and soluble in toluene.) As has long been
known, the lightest alkane, methane, causes just such asphaltene
precipitation. Moreover, light ends are often added to the
reservoir late in the charge process. In a normal burial
sequence, the lightest charge is expelled at the latest times from
the

kerogen with longer catagenesis times, and higher catagenesis
temperatures. This is similar to refining where higher
temperatures and longer times yields cracking to lighter
hydrocarbons. Second, in colder reservoirs biogenic methane in
substantial quantities can enter the reservoir, again, after the oil
charge, the food for the microbes. The light alkane or gas
enters the reservoir in high permeability streaks and goes right
to the top of the fluid column without fluid mixing except in
the vicinity of the charge path or plane,[5] a schematic of this
process is shown in Fig. 1.[6] In this process, the gas migrates
to the top of the oil column, then diffuses down from the top of
the oil column, asphaltenes are destabilized at the gas-oil
contact and increasingly at lower points with time as the
solution gas gradually increases with methane diffusion.
Figure. 1. Charge history mechanism determines the
hydrocarbon distribution in the Stainforth model.[5] Initially,
the heaviest charge from the kerogen charges the reservoir.
Later in the charging process, lighter hydrocarbons
are expelled from kerogen. These light hydrocarbons migrate to
the top of the oil column through high
permeability streaks and do not mix with in situ reservoir fluids
in this process. Given sufficient time, equilibration
can take place. Light ends can destabilize asphaltenes; this
destabilization process is seen to occur at the top of
the oil column, not at its base where tar mats are frequently
found.

The former lack of understanding of asphaltene nanoscience
created considerable confusion as to how and where asphaltene
destabilization events take place. Specifically, it has long been
assumed that asphaltene instability occurred where asphaltene
deposits are now found. Along these lines, in the laboratory,
light alkane addition to crude oil destabilizes the asphaltenes
then and there. Thus, regional tar mats have been thought to
form at the OWC due to gas entry at the oil-water contact
(OWC). This concept violates well known processes in
reservoirs (cf. Fig. 1) and recent work has clarified actual
reservoir
processes leading to tar mat formation. The reservoir is not like
a distillation tower with bubble plates ensuring equal gas
entry everywhere at the OWC. This is in contrast to the
laboratory where fluid mixing is simple and is part of
asphaltene
flocculation procedures. The crucial point is that asphaltenes
can migrate great distances in reservoirs even when partially
destabilized. Previously it had been thought that with asphaltene
instability, there can only be floc formation, and all agree
that flocs cannot migrate through reservoirs. We now
understand that there are two nanocolloidal asphaltene species,
and that
instability can result in formation of the larger nanocolloidal
asphaltene species; this nanocolloidal particle can migrate

through reservoirs.[7] This will be discussed in greater detail in
the Asphaltene Nanoscience section.
163292
SPE 163292 3
In addition, tar mats can be as thick as 60 meters. Those who
propose that the tar mat forms at the OWC because asphaltene
instability is mediated by a process involving water never
explain how it is that the tens of meters of tar do not seal off
the oil
from the water. (Many high-rise buildings have a thin layer, ≤
1cm, of roofing tar sealing off water entry into the building,
tens of meters of tar are not needed for this purpose!) Once this
sealing process takes place, the tar mat cannot grow further
IF tar mat growth depends on water. For example, if 3 meters of
OWC tar mat creates this seal, then there should be no
further growth of the tar mat. In fact, this conventional
explanation is incorrect; generally, tar mat growth is not
mediated by
water. Frequently, tar mat growth occurs via asphaltene
instability at the top of the oil column with asphaltene transport
through the reservoir to the flank. The thickness of tar mats in
this process is rather unconstrained and is consistent with

thicknesses exceeding 30 meters that are frequently observed.
The key improvement in understanding is the mechanism of
transport of unstable asphaltene through the reservoir. This is
where new asphaltene science, the Yen-Mullins model, has had
a significant impact. Instability of asphaltene nanoaggregates
can yield asphaltene clusters which are only 5 nm in size so
easily migrate through porous media, yet are large enough to
accumulate at the base of the oil column.[1-4]
Case Studies. Gas addition to reservoirs mostly occurs through
spatially restricted high permeability channels without
mixing with existing fluids in the reservoir. The added gas
quickly finds its way to the top of the reservoir or at least to a
local high point in the reservoir. With new gas addition at the
top of the reservoir, the gas diffuses down and expels
asphaltene from the oil in this process. Figure 2 shows a
reservoir caught in the middle of such a process. One can
visually
see lack of asphaltenes at the top of the reservoir, that is where
asphaltene instability occurs.[8]
Figure. 2. A black oil reservoir had a substantial late gas charge
which gave rise to a huge color gradient (see
actual dead oil bottles on the right), and a huge gradient in
solution gas.[8] The late gas charge quickly went to

the top of the black oil column without mixing into this
reservoir crude oil. Subsequently, the gas diffused down as
indicated by white arrows in the cartoon on the right.
Substantial solution gas near the gas-oil contact caused the
asphaltenes to be expelled – thus the oil has very little color at
the top of the column. The gas has not had time to
diffuse to the base of the column, thus, there, the solution gas is
low, and the oil maintains a high concentration of
asphaltenes. In the figure, the calculated color (asphaltene)
gradient is shown from the FHZ EoS coupled with a
methane diffusion term and agrees with the color gradient
evident in the samples.[8]
Figure 2 shows a reservoir where substantial gas has diffused
only partially into the oil column; thus expelling asphaltene
only towards the top of the column. It would take geologic time
for this diffusion process to transport methane to the base of
the column. If the late gas charge has sufficient time to diffuse
to the base of the oil column then the asphaltenes can become
very concentrated at the base and form a tar mat. Figure 3
shows just such a reservoir. In this case, large volumes of gas
entered the oil column expelling most of the asphaltenes. The
asphaltenes migrated ahead of the gas front, most likely by
convective waves. The asphaltene rich fluid went to the base of
the column, and was trapped there by cement underneath.
The gas caught up to the asphaltenes creating a condensate
(high GOR, little asphaltene) and a tar mat underneath. This tar
mat is on cement so has nothing to do with water. The
conventional explanation that the tar mat forms at the OWC

because
that is the location of the asphaltene instability obviously does
not apply here and is generally incorrect. For oil reservoirs at
or very close to surface, biodegradation and even evaporative
and water washing processes can yield very viscous oil, such as
the Athabasca tar sands, but that is distinct from a reservoir
with a tar mat.
4 SPE
Figure 3. A reservoir with a late gas charge. The gas went to the
top of the reservoir and diffused down to the
base of the oil column (depicted by long white arrows in the left
cartoon).[9] The expelled asphaltenes stayed
ahead of the diffusive gas front, presumably by convective
currents. The tar mat is visible in core sections, the
fluorescence image of the core (right image in each of the six
core panels) shows strong fluorescence of the
condensate immediately above the tar mat with no fluorescence
(bottom two core panels with visible image, left;
fluorescence, right). This tar mat rests on cement, water had
nothing to do with this tar mat formation.[9]
Equilibration of reservoir fluids is a geologically slow
process.[10] Recently, a reservoir was reported to have two
separate

gas caps that could each be seen in seismic data. Figure 4 shows
an image of this reservoir.[11] Logging data from the two
wells established that the two separate gas-oil contacts (GOCs)
differ by 20 meters in the true vertical depth (TVD).[11]
Either the reservoir is compartmentalized, each compartment
with its own gas cap, or there is lateral disequilibrium in
solution gas in a single reservoir with two gas caps.
Figure 4. (Left) A reservoir with two separate gas caps (brown)
over oil (green); the two gas-oil contacts differed
by 20 meters true vertical depth.[11] (Right) The continuous
asphaltene gradient measured in three wells
indicated connectivity which was proven in production. There is
lateral disequilibrium of solution gas; the diffusive
processes to cause equilibration in the reservoir are very slow
even compared to geologic time.[10]
The downhole fluid analysis (DFA) data clearly established that
there is a continuous color gradient across the reservoir (in
three wells including the two depicted in the Fig. 4).[11] This
color gradient matched the FHZ EoS analysis and indicates that
the reservoir is connected. The heavy ends are equilibrated
across the field – this requires connectivity. Production proved
the
reservoir is connected.[11] Thus, the reservoir fluid is out of
equilibrium for gas-liquid properties such as GOR. When gas

charges into the reservoir it can get stuck in local reservoir
highs. To equilibrate the two gas caps, gas from the lower GOC
gas cap would have to dissolve in the oil, diffuse across the
reservoir and release into the higher GOC gas cap. This process
is
extremely slow, consequently the reservoir gas-liquid properties
are out of equilibrium. In particular, if there is a late gas
phase charge into the reservoir, it is likely that gas would
collect in local highs and would remain out of equilibrium for a
long time. In contrast, the asphaltenes only partition to the
liquid phase so can equilibrate provided that the reservoir has
good
connectivity. This is indeed what happened in the oilfield
shown in Fig. 4.[11]
163292
SPE 163292 5
Another reservoir experienced only a small light end influx into
a black oil reservoir. With just a slight destabilization event,
but with time for equilibration to take place, black oil can
remain in the crest, whereas heavy oil and a tar mat can reside
in
the low points or the flank or rim of the field. Figure 5 shows a
cartoon of a very large Jurassic anticline field with a four way

dip closure. There was a slight asphaltene instability leading to
asphaltene migration and accumulation of the asphaltenes in
the rim of the field. Most likely, this migration took place in
convective waves of asphaltene rich oil (thus high density).
Diffusion would require on the order of one trillion years (much
longer than the age of the universe), so diffusion alone
cannot account for asphaltene migration in this reservoir!
Figure 5. A large, Jurassic anticline oilfield in Saudi Arabia has
black oil in most of the field, has a mobile heavy oil
rim which is underlain by a tar mat.[12,13] The mobile heavy
oil rim exhibits a gigantic asphaltene gradient (6x) as
shown. The asphaltene gradient fits the gravity term of the FHZ
EoS, with one tightly constrained adjustable
parameter, the asphaltene cluster size, thus the asphaltenes are
equilibrated throughout this huge volume. The
fitted data (above) gives an asphaltene cluster size of 5.2 nm,
very close to the published nominal size of 5.0 nm
(cf. Fig. 6).
This Jurassic field of Fig. 5 had experienced some asphaltene
instability, but not too much as substantial asphaltene remains
in the crude oil, and the GOR is low – both conditions in
contrast to conditions depicted in Fig. 3. The destabilized
asphaltene
accumulated in the flank. The asphaltenes in the mobile heavy
oil section equilibrated laterally over the entire tens of
kilometers circumference of the field and in height of 50 meters

as shown in Fig. 5. Equilibration ultimately does have a
diffusive component; the simple diffusion relation is Dt = x
2
where D is the diffusion constant (which is very small for
asphaltene clusters), t is time, and x is mean distance of
displacement. This large field has a large value of x >>10
kilometers;
consequently, a very long time is needed to reach equilibration.
As noted above, convection must also play a large role in
equilibrating this field. The field is Jurassic, and being
equilibrated, this field identifies what a “long time” is for such
reservoir processes, it is ~150 million years.[13]
Where the asphaltene content exceeded 35%, this is tar mat. For
asphaltene concentration above 4% and below 35%, this is
mobile heavy oil (viscosity < 1000 centipoise). We also note
that unlike the mobile heavy oil, the asphaltene content in the
tar mat in this field is not even slightly equilibrated. The
asphaltene content in the tar mat ranges from ~35% to ~60%,
with
large variations up and down in concentration within a few
meters within individual wells.[12,13] We propose that the tar
mat represents a phase transition; asphaltene is not soluble in
crude oil in all proportions.[13] As the asphaltene continues to
enter low points in the reservoir by accumulation of 5 nm

asphaltene clusters, the crude oil can become supersaturated in
asphaltene content. The asphaltenes then plate out on grain
surfaces. As this process continues, the pore throats become
occluded, and no further fluid exchange can take place. That is,
tar mats are not equilibrated in two meters (vertical) whereas
the heavy oil is equilibrated over many tens of kilometers
(lateral) because the carbonaceous grain coating in the tar mat
precludes any mass exchange necessary for equilibration.[12,13]
Precepts in this explanation are under study.
What had not been appreciated is that destabilized asphaltenes
can migrate in reservoirs, but not when precipitated as flocs.
Asphaltenes in crude oils can exist as three distinct species as
shown in Fig. 6.[1] All of these species are in the nanometer
size range so are tiny with respect to pore throats in rock in
conventional reservoirs. When asphaltenes are slightly
destabilized for example by slow gas addition to a crude oil,
asphaltene nanoaggregates form clusters (containing ~8
nanoaggregates). Clusters are relatively large compared to the
other asphaltene species and consequently, they accumulate
6 SPE
towards the base of oil column by gravity, much more so than
asphaltene nanoaggregates. By this means, asphaltenes that are

destabilized can migrate in reservoirs. The migration process
most likely involves convective waves of asphaltene rich (and
cluster rich) fluids.
Asphaltene Nanoscience and Equation of State
Figure 6. The Yen-Mullins Model. Typical structures for
asphaltene molecules, nanoaggregates (of molecules)
and clusters (of nanoaggregates). At low concentrations as in
condensates, asphaltenes are dispersed as a true
molecular solution (left); for black oils, asphaltenes are
dispersed as nanoaggregates of ~6 molecules (center); for
heavy oils, asphaltenes are dispersed as clusters of ~8
nanoaggregates (right).[1,2]
With the size known, the effect of gravity is determined. For the
asphaltene equation of state, the gravity term is given by
Archimedes buoyancy in the Boltzmann distribution. That is,
the asphaltene particles are negatively buoyant in the crude oil
as described by Archimedes buoyancy. Combining the gravity
term, with a chemical solubility term and an entropy term we
have the equation of state for asphaltene gradients, the Flory-
Huggins-Zuo (FHZ) Equation of state. The Flory-Huggins
theory has long been used to describe polymer solubility, here
we use this theory but we also include a gravity term to treat
asphaltene gradients.

12
21
11
expexpexp
1222
1
2
1
2
hh
a
aa
haha
a
a
a
vv
v
RT
hhgv

RT
v
h
h
hOD
1.
where OD(hi) is the optical density (color) measured by DFA
e
volume of the oil, R is the ideal gas constant, T is temperature,
solubility parameter of the oil, g is earth’s gravitational
oil
density. The solubility parameter of the asphaltene can be
obtained from literature values, and, in an oil column, the

solubility
parameter variation of the oil is primarily due to GOR
variations. In the FHZ EoS, the first exponential factor is the
solubility
term, the second is the gravity term and the third is the Flory-
Huggins entropy term. For low GOR oils, the gravity term
dominates. For moderate GOR oils (700 scf/bbl), typically both
the solubility term and the gravity term contribute to the
asphaltene gradient. With this foundation, the understanding of
many reservoirs is dramatically improved.
In this study, we examine two Pliocene reservoirs each with
multiple horizons with considerably smaller dimensions than the
reservoir of Figure 5. In the case herein, there is massive, recent
gas addition to a black oil with dramatic but unusual effects
manifested in many ways. In particular, this reservoir is
evidently grossly out of equilibrium, but not in a systematic
way as
depicted in Fig. 2, but rather in a seemingly stochastic (random)
disequilibrium variation of fluids properties. With the
reservoir rock being <5 million years, the black oil charge being
younger than that and the gas charge more recent still, we
call this time frame roughly 1 million years; this defines what is
very rapid regarding reservoir fluids. This case study and the
Saudi Aramco study (Fig. 5) bracket short and long times for

reservoir fluids process, 1 million years to 150 million years.
RESULTS AND DISCUSSION
Two fields that share the same minibasin are probed herein;
both fields exhibit similar characteristics of importance to this
paper. We will focus primarily on one reservoir with many
details presented. These fields and the contained oil and gas are
quite young. Any fluid process that has occurred could take no
more than a few million years. Frequently, reservoir processes
take longer than that, and often such young reservoirs have
processes that are still ongoing, such as gas charging;
consequently fluid equilibration is not expected. Two horizons
in each field are of interest. These reservoirs have substantial
structure containing many lobes. The wireline pressure survey
along with some PVT data is shown in Fig. 7 for one reservoir.
163292
SPE 163292 7
x x
x
x

x
x
x x
Well 1
Well 2
Well 3
X,100
X,200
X,300
DEPTH
(TVD, feet)
Figure 7. Pressure survey and PVT data for one of the fields.
The pressures in the one sand in three wells are
essentially on the same trend. The peculiar observation is that
the GOR of one intermediate sampling point is
significantly different and smaller than all other samples. It is
possible the fluids are grossly out of thermodynamic
equilibrium (but in pressure equilibrium) in a connected baffled
reservoir.
Well Logging. The pressure data for the three wells are on the
same trend. Prior to production, aligned pressure
measurements are not a strong indicator of connectivity;

nevertheless, these pressure measurements are consistent with
connectivity. The GOR from the lab PVT reports is also shown
in Fig. 7. The GOR from one sample (one well) is
substantially smaller than the others. Normally this could
indicate compartmentalization. Here, there is a second
explanation.
There could be ongoing massive gas influx into this reservoir,
with gas pockets getting trapped in connected, lobate systems.
In this Pliocene reservoir with (likely) current gas charged,
insufficient time has passed for equilibration. After production,
this reservoir was shut in and all measured pressures returned to
virgin pressure indicating 1) excellent connectivity and 2)
strong aquifer support. This observation is consistent with
connected but disequilibrium fluids as the possible origin of the
unusual GOR measurements in Fig. 7. Other unusual
observations are consistent with this interpretation.
Figure 8. Log of an interval in one primary sand. A whole core
was taken confirming the excellent porosity and
permeability obtained in wireline logging. Nevertheless, large
sections of the producing interval exhibited no
fluorescence as indicated by two brown rectangles in the figure
labeled “Non-fluorescing core”; this is traced to a
tar coating in these core sections.
Whole Core. In one of the wells, whole core was obtained for

much of one of the target sands. Lab data confirmed excellent
porosity and permeability of the target sand. However, a
surprising observation from the whole core is that large sections
of
the oil bearing sand of the whole core did not fluoresce as
indicated in Fig. 8, in spite of the crude oil being highly
8 SPE
fluorescent. The log data exhibits density–neutron crossover
that is associated with gas (shaded yellow in Fig. 8). The gas is
towards and at the top of this interval which is what would be
expected if this interval is vertically connected (but perhaps
around baffles). In addition, the reservoir pressure greatly
exceeds saturation pressure of this oil. The observations of gas
and
an extended section of tar are related as will be discussed.
Figure 9. Whole core (6 feet section in two contiguous 3 feet
sections) from the well in Fig. 8 at the transition from
fluorescent to nonfluorescent sands under ultraviolet
illumination. The core sections are displayed under visible
illumination (left in each 3 foot panel) and under UV
illumination (right in each 3 foot panel). Visible light shows
increasing optical absorption in the nonfluorescent section.
Laboratory analysis confirmed that tar in the core
produced little fluorescence and the dark color of the core. n.b.

The core section with tar is permeable and porous.
The transition from fluorescent to nonfluorescent sand core is
shown in Fig. 9. The nonfluorescent section is due to a coating
of tar in the core. This tar is not typical: it is not at the low
point in the reservoir, it covers roughly ½ of the producing
interval
(cf. Fig. 8) and most importantly the tar zone is porous and
permeable. Moreover, this reservoir exhibits excellent
connectivity and natural aquifer support; shut-in resulted in
virgin pressure. These properties are quite distinct from tar mats
routinely encountered in oilfields. Typically, tar mats are found
at the base of the oil column, they cover a small overall
section of the producing interval, they are not permeable, and
have not been considered porous. Tar mats at the OWC often
preclude natural aquifer support and preclude utility of water
injectors.
To confirm that the tar mat herein is in fact permeable, it is
desirable to perform a downhole flow test. That is, core
properties
can be altered upon depressurization with subsequent lab
measurements. To test the tar zone permeability, a one foot
interval
in the tar zone was perforated and produced by straddling the
perforation with the MDT Dual Packer. Figure 10 shows the

section of core from the well depth that was perforated.
Figure 10. Whole core including the one foot interval that was
perforated and sampled using the MDT Dual
Packer. The entire permeable section of this core depicted here
is coated with tar. (Shale at the base of this core
section is not permeable.) The sampled crude oil is less than 1%
asphaltene while the tar is 35% asphaltene
confirming the coexistence in the reservoir or two immiscible
hydrocarbon phases.
163292
SPE 163292 9
The tar zone allowed flow of a nice light crude oil in the
wireline sampling test confirming that the tar zone is
permeable.
The produced oil contains less than 1% asphaltene while the
residual tar was found to have ~ 35% asphaltene. Consequently,
it is evident that there are two immiscible hydrocarbon phases
present in the formation at the same depth, a light oil and a tar.
Indeed, four hydrocarbon phases have been experimentally
determined to coexist in asphaltenic materials, a gas, two
immiscible liquids and a solid;[14] this reservoir is not
violating any thermodynamic principles. Nevertheless, the
unusual

nature of this tar mat must be explained.
Figure 11 shows a detailed analysis of the phase behavior of
crude oils produced (Left) from the tar zone and
(Right) from a region not near the tar zone. The complex phase
behaviors of these two crude oils are similar. The
tar mat does not signify a large change in properties of the local
crude oil. The asphaltene onset pressure is near
or at reservoir pressure which is expected for a late gas charge
into crude oil that resulted in tar.
Given that the tar represents a phase transition of heavy ends
precipitated out of the oil, it is important to che ck the phase
behavior of crude oils, produced from the tar zone and produced
from a point not so close to the tar. Figure 1 1 shows that the
overall complex phase envelops of these crude oils are similar,
meaning that the tar mat is not associated with some dramatic
change of the corresponding crude oil. Nevertheless, there are
some differences noted in bubble point and details of the
asphaltene onset. As expected for reservoirs with late gas
charge and tar, the asphaltene onset pressure is near or at
reservoir
pressure. Asphaltene is not a homogenous chemical substance.
Some fractions of asphaltenes are more stable in solutions,
others less stable. When gas destabilizes asphaltene sufficiently,
some fraction of asphaltene can for tar. Another fraction can

remain in the liquid phase, but very unstable such that any
pressure reduction causes some of this fraction to precipitate as
shown in Fig. 11. The bubble points of the crude oils are not
near reservoir pressure even though density neutron cross was
observed (cf. Fig. 9) in upper sections of the sand. This is
another indicator that the reservoir fluids are very much out of
equilibrium.
Geoscenario. The explanation consistent with a broad array of
observations is the following: the reservoir rock is of Pliocene
age. More recently, a black oil charged into the reservoir. More
recently still, likely ongoing, the reservoir experienced a
massive gas influx. Roughly, this corresponds to processes
occurring in the last 1 million years. The oil in proximity to the
gas experienced a large, rapid increase in GOR causing rapid
destabilization of the asphaltenes. This destabilization was so
complete that the asphaltenes could fall only small distances
and only vertically in the oil column before they stuck to
available surfaces, the grain surfaces of the rock. This rapid
destabilization did not allow time for the asphaltenes to migrate
to the low points in the reservoir, the OWC. That migration
process, for example that did occur in a large field in Saudi
Arabia, is primarily lateral.[12,13] This rapid destabilization
event did not even allow time for the asphaltenes to fall

vertically all the way to a shale break at the base of the sand.
That process would yield a relatively thin tar mat of no
permeability. Instead, the rapid destabilization of asphaltenes
caused the asphaltenes to “paint” the rock surface over an
extended vertical interval; this occurring after the asphaltenes
fell a short distance in the sand. An extended vertical tar mat
interval is consistent with only a thin layer of tar on the rock;
there was not enough asphaltene in the oil to fill ½ the
producing interval with space-filling tar (cf. Fig. 8). This
geoscenario is consistent with many observations: 1) the
remaining
oil has contains very little asphaltenes, 2) reservoir pressure is
the asphaltene onset pressure, 3) an extended vertical interval
of tar is permeable, 4) much tar is found up-structure and near
gas bearing zones, 5) the evident lack of equilibrated GOR
indicates these processes are very recent; the large GOR
variations indicate massive gas influx recently occurred 6) the
asphaltene destabilization was so dramatic that evidently even
some resins of lower viscosity phase separated. The last point
has significant implications for production as discussed below
in the Production Section.
10 SPE

This rapid reservoir process yielding a disequilibrated fluid
column is essentially at one extreme with a very rapid time
frame.
That is, the GOR and thus methane are not equilibrated, and the
asphaltenes are plated out locally on reservoir rock up-
structure. This defines “very young” and is roughly 1 million
years old. The massive Saudi Arabian reservoir with
equilibrated asphaltenes over a huge length scale is at the other
extreme of time, essentially defining a “very old”. That is, the
asphaltenes are equilibrated over great distance in spite of their
tiny diffusion constant. This Saudi Arabian reservoir defines
what is very slow - and is roughly 150 million years old. These
two case studies, the one herein and the one from Saudi
Arabia [12,13] bracket reservoir fluid processes in time scale.
Other reservoirs should be in between these two in terms of
time frame and thus in terms of observables that affect
production, such as GOR distributions, asphaltene distributions,
tar
location etc.
An important component of tar mats is their structure. Some tar
mats appear to consist of both an immo vable carbonaceous
phase and a heavy oil phase.[13] This is expected from slow
dynamics of asphaltene sedimentation. Tar mats produced in

rapid asphaltene destabilization can have fundamentally
different properties. Asphaltenes from rapid destabilization can
have
lower asphaltene content and higher mobility. That is, strong
asphaltene destabilization that causes fast asphaltene deposition
also causes deposition of some heavy resin components that are
more mobile than a higher purity asphaltene deposit. There
are important consequences of some mobility of tar, even if
permeable.
A confusion can occur in evaluating OWC tar mats vs rapid
destabilization tar mats. In both cases, the tar mats have >35%
asphaltene content (cf. Fig. 10, and Ref. [12, 13]). In both
cases, thin sections exhibit porosity and exhibit a carbonaceous
coat on the grain surface. However, there are distinct
differences. The OWC tar mats can go as high as 60%
asphaltene. And
the OWC tar mats are not permeable, while the rapid
destabilization tar mat is permeable. In both cases, there are two
immiscible hydrocarbon phases present. In the rapid
destabilization tar mat, in addition to the tar, there is a light oil.
In the
OWC tar mat, there is a heavy oil of ~35% asphaltene plus a
carbonaceous coat of extremely high asphaltene content (≥60%
asphaltene). The OWC carbonaceous coat seals off pore throats
trapping heavy oil, and precluding the ability to acquire pure

samples of the carbonaceous coating. The rapid destabilization
tar mats are porous and allow easy isolation of the tar mat
from the light oil. The huge difference is that the rapid
destabilization tar mat is not ultra-high viscosity and can flow
(like a
heavy oil) while the 60% carbonaceous coat of the OWC tar mat
is ultra-high in viscosity and cannot flow under any
conditions.
A thin section of the tar mat is shown in Figure 12.
Figure 12. Thin section of the tar mat. Black is the tar. The blue
is epoxy that displaced movable fluids prior to
preparation of the thin section, and white is the sand grain. This
image is consistent with significant porosity in the
tar zone.
Production. A well test following long term production was
performed after perforation of an interval containing a
permeable tar. (This well test is different than the test presented
in Fig. 10 where a one foot interval was flowed.) In this test,
significant and relatively low viscosity tar was obtained in
tubulars during this test. Figure 13 shows viscous heavy ends
remaining in the tubulars after the well test. Obviously, flow of
such a material is of major concern in production. As shown

herein, understanding the distribution of reservoir fluids and
their organic solids alike within a single framework helps to
identify corresponding production issues that are significant.
163292
SPE 163292 11
Figure 13. Residual tar in tubulars after a well test. This tar is
thought to arise from mobility of an existing tar mat.
This material differs from typical asphaltene deposits in flow
assurance that have a physical consistency and
appearance similar to coal.
Figure 14. A cumulative-oil dependent skin in production is
observed and is attributed to asphaltene concerns,
both mobile tar and asphaltene onset with pressure reduction.
Xylene treatment of the producing well significantly
improves performance. With repeated xylene washes, the rate of
skin deterioration can be reduced.
Consistent with this well test result, a skin that is dependent on
cumulative produced oil has been observed in the formation
when analyzing extensive production data as shown in Fig. 14.
Asphaltene concerns, including both mobile tar as well as

asphaltene deposition with pressure drop are considered
responsible for this increasing skin. Xylene treatments are
effective
in mitigating these production problems. In particular, repeated
xylene treatments reduce the rate of skin deterioration.
Understanding these complex production issues at the outset is
desirable in order to optimize production by dynamic
intervention.
12 SPE
Figure 15. Barrels of oil per day and the GOR of the produced
oil over a multi-year period. It is uncommon to have
such large, seemingly random variations in GOR. The existence
of pockets of connected, disequilibrium fluids in
this young reservoir is consistent with these observations.
Another observation that is not common is the large variation of
the GOR of the produced oil. Figure 15 shows that the GOR
varies up and down by a factor of three in production from one
well in one reservoir. Again, note that the reservoir appears to
be connected with a strong aquifer drive. The large,
nonmonotonic variations of GOR coupled with many
observations
discussed above suggest that there are pockets of significantly

different fluids in the reservoir that have not had time to
equilibrate. Baffles but not barriers might be separating
different fluids. Using literature diffusion constant (D where
t=D/x
2
)
of methane through hydrocarbon filled porous rock of ~10
-5
cm
2
/sec, [15,16] one obtains that it takes a million years (t) to go
a distance (x) of 200 meters. It is plausible that reservoir fluid
variations exist at that length scale being separated by baffles,
with current gas charging, and with no time to equilibrate.
Different Field, Same Observations. Another field in the same
basin exhibits very similar behavior to the field discussed
above. There is tar deposition in a well near the crest of the
field.
Figure 16. Core and logs from a well near the crest in another
field in the same basin. Very similar observations
are made to the case study above; there is tar deposition up-
structure that is porous and permeable. All
production issues discussed above apply to this field.

163292
SPE 163292 13
A question arises as to how common the above case study is.
Figure 16 shows that another field in the same basin but a
significant distance away exhibits the same ‘unusual’
phenomena. There is tar deposition up-structure that is porous
and
permeable. Other production issues such as a skin dependent on
cumulative production and variable GOR in production are
also observed. It is evident that the phenomena discussed in this
paper apply to a class of reservoirs, those with rapid and
recent gas charge into black oil.
CONCLUSIONS
A Pliocene reservoir study is presented with a variety of
putatively unusual observations: there is tar deposition up-
structure
that is porous and permeable. There are large, nonmonotonic
variations in GOR obtained in wireline logging and with
production data over years. There is mobile tar as shown in
photographs, yet the produced crude oil is rather light. A
consistent geoscenario is for a rapid and recent gas charge into
black oil, the time frame being roughly one million years.

This short time is not sufficient for equilibration of reservoir
fluids even though the reservoir exhibits excellent connectivity
and pressure build-up behavior in shut-in. The asphaltenes were
knocked out of solution so rapidly and strongly that they did
not have time to descend in the reservoir to the OWC; rather,
they made it only part way down the individual sand lobes
before sticking to and ‘painting’ the rock surface – thereby
leaving permeability. This deposition process naturally leads to
somewhat higher mobility tar than typically found in OWC tar
mats, enabling limited but important mobility of this tar.
Consequently, a production dependent skin develops and
requires intervention via xylene treatment. These rapid ~1
million
year old processes are in distinct contrast to equilibrated
asphaltenes in a giant, Jurassic Saudi Arabia field, thus old in a
geologic sense. Consequently, short and long time scales are
establish as ~1 million years to ~150 million years for reservoir
fluid processes of interest to major production concerns. Many
other reservoirs are intermediate in this time scale. These new
methods, particularly employing new asphaltene science and
downhole fluid analysis technology are enabling significant
increases in efficiency as increasingly difficult reservoirs are
exploited. Moreover, as shown herein, neighboring reservoirs
within a basin can exhibit very similar fluid variations and

production concerns.
ACKNOWLEDGEMENTS The authors are deeply indebted to
the technologists in the operating company. These
technologists recognized the origins of surprising reservoir
complexities and performed definitive yet uncommon tests to
validate these physical origins. Simply stated, their skill and
clarity of thought is inspiring. We are also indebted to these
technologists and the operating company for permitting this
publication.
REFERENCES
[1] Mullins, O.C., “The Asphaltenes”, Annual Review of
Analytical Chemistry, 2011 Vol. 4, page 393-418
[2] Mullins, O.C.; Sabbah, H.; Eyssautier, J.; Pomerantz, A.E.;
Barré,
L.; Andrews, A.B.; Ruiz-Morales, Y.; Mostowfi, F.;
McFarlane, R.; Goual, L.; Lepkowicz, R.; Cooper, T.;
Orbulescu, J.; Leblanc, R.M.; Edwards, J.; Zare, R.N.;
Advances in
Asphaltene Science and the Yen-Mullins Model, Energy &
Fuels, 26, 3986–4003, (2012)
[3] Freed, D.E., Mullins, O.C., Zuo, Y.J.: “Theoretical

Treatment of Asphaltene Gradients in the Presence of GOR
Gradients”, Energy & Fuels, 24, 3942-3949, (2010)
[4] Zuo, J.Y.; Mullins, O.C.; Freed, D.; Elshahawi, H.; Dong,
C.; Seifert, D.J.; Advances in the Flory-Huggins-Zuo Equation
of State for Asphaltene Gradients and Formation Evaluation,
submitted, Energy & Fuels
[5] Stainforth, J.G., “New Insights into Reservoir Filling and
Mixing Processes” in Cubit J. M., England, W.A., Larter, S.
(Eds.) Understanding Petroleum Reservoirs: toward and
Integrated Reservoir Engineering and Geochemical Approach,
Geological Society, London, Special Publication, (2004)
[6] Mullins, O.C., The Physics of Reservoir Fluids; Discovery
through Downhole Fluid Analysis, Schlumberger Press,
Houston, (2008)
[7] V. Mishra, N. Hammou, C. Skinner, D. MacDonald, E.
Lehne, J.L. Wu, J.Y. Zuo, C. Dong, O.C. Mullins, Downhole
Fluid Analysis & Asphaltene Nanoscience coupled with VIT for
Risk Reduction in Black Oil Production, Accepted, SPE
ATCE, (2012)

[8] Zuo, J.Y., Elshahawi, H., Dong, C., Latifzai, A.S., Zhang,
D., Mullins, O.C., DFA Assessment of Connectivity for Active
Gas Charging Reservoirs Using DFA Asphaltene Gradients, SPE
145438, ATCE, (2011)
[9] Elshahawi, H., Latifzai, A.S., Dong, C., Zuo, J.Y., Mullins,
O.C., Understanding Reservoir Architecture Using Downhole
Fluid Analysis and Asphaltene Science, Presented, Colorado
Springs, SPWLA, Ann., Symp., (2011)
14 SPE
[10] Pfeiffer, T.; Reza, Z.; Schechter, D.S.; McCain, W.D.;
Mullins, O.C.; Determination of Fluid Composition Equilibrium
under Consideration of Asphaltenes – a Substantially Superior
Way to Assess Reservoir Connectivity than Formation
Pressure Surveys, SPE #145609 ATCE, (2011)
[11] Gisolf, A., Dubost, F.X., Zuo, J., Williams, S.,
Kristoffersen, J., Achourov, V., Bisarah, A., Mullins, O.C., SPE
121275,
SPE Europe/EAGE Ann. Conf. Ex., Amsterdam, The
Netherlands, 8-11 June, (2009)
[12] Seifert, D.J., Zeybek, M., Dong, C., Zuo, J.Y., Mullins,

O.C., Black Oil, Heavy Oil and Tar in One Oil Column
Understood by Simple Asphaltene Nanoscience, SPE ADIPEC
158838, Abu Dhabi (2012)
[13] Seifert, D.J., Qureshi, A., Zeybek, M., Zuo, J.Y.,
Pomerantz, A.E., Mullins, O.C., Mobile Heavy Oil and Tar Mat
Characterization Within a Single Oil Column Utilizing Novel
Asphaltene Science, SPE KIPCE 163291, Kuwait International
Petroleum Conference and Exhibition, Kuwait City, Kuwait,
Dec 10-12, (2012)
[14] Shaw, J.M., Zou, X.; Phase behavior of heavy oils, Ch. 19
in Asphaltenes, Heavy Oils and Petroleomics, Mullins, O.C.
Sheu, E.Y., Hamami, A., Marshall, A.G., Editors; Springer,
New York, (2007)
[15] Chen, L.L., Katz, D.L., Tek, M.R., Binary gas diffusion of
methane-nitrogen through porous solids, AICHE, 23, 336-
341, (1977)
[16] Ghorayeb, K., Firoozabadi, A., Modeling multicomponent
diffusion and convection in porous media, SPE Journal, 5,
158-171, (2000)
163292

SPE 163291
Heavy Oil and Tar Mat Characterization Within a Single Oil
Column Utilizing
Novel Asphaltene Science
Douglas J. Seifert (Saudi Aramco), Ahmed Qureshi, Murat
Zeybek, Andrew E. Pomerantz, Julian Y. Zuo and
Oliver C. Mullins (Schlumberger)
Copyright 2012, Society of Petroleum Engineers
This paper was prepared for presentation at the SPE Kuwait
International Petroleum Conference and Exhibition held in
Kuwait City, Kuwait, 10-12 December 2012.
This paper was selected for presentation by an SPE program
committee following review of information contained in an
abstract submitted by the author(s). Contents of the paper have
not been
reviewed by the Society of Petroleum Engineers and are subject
to correction by the author(s). The material does not necessarily
reflect any position of the Society of Petroleum Engineers, its
officers, or members. Electronic reproduction, distribution, or
storage of any part of this paper without the written consent of
the Society of Petroleum Engineers is prohibited. Permission to
reproduce in print is restricted to an abstract of not more than
300 words; illustrations may not be copied. The abstract must
contain conspicuous acknowledgment of SPE copyright.

ABSTRACT
A Jurassic oil field in Saudi Arabia is characterized by black oil
in the crest, with heavy oil underneath and all underlain by a
tar mat at the oil-water contact (OWC). The viscosities in the
black oil section of the column are similar throughout the field
and are quite manageable from a production standpoint. In
contrast, the mobile heavy oil section of the column contains a
large, continuous increase in asphaltene content with increasing
depth extending to the tar mat. Both the excessive viscosity
of the heavy oil and the existence of the tar mat represent
major, distinct challenges in oil production. A simple new
formalism, the Flory-Huggins-Zuo (FHZ) Equation of State
(EoS) incorporating the Yen-Mullins model of asphaltene
nanoscience, is shown to account for the asphaltene content
variation in the mobile heavy oil section. Detailed analysis of
the
tar mat shows significant nonmonotonic content of asphaltenes
with depth, differing from that of the heavy oil. While the
general concept of asphaltene gravitational accumulation to
form the tar mat does apply, other complexities preclude simple
monotonic behavior. Indeed, within small vertical distances (5
ft) the asphaltene content can decrease by 20% absolute with
depth. These complexities likely involve a phase transition
when the asphaltene concentration exceeds 35%. Traditional
thermodynamic models of heavy oils and asphaltene gradients
are known to fail dramatically. Many have ascribed this failure
to some sort of chemical variation of asphaltenes with depth;
the idea being that if the models fail it must be due to the
asphaltenes. Our new simple formalism shows that
thermodynamic modeling of heavy oil and asphaltene gradients
can be
successful. Our simple model demands that the asphaltenes are
the same, top to bottom. The analysis of the sulfur chemistry
of these asphaltenes by X-ray spectroscopy at the synchrotron at
the Argonne National Laboratory shows that there is almost

no variation of the sulfur through the hydrocarbon column.
Sulfur is one of the most sensitive elements in asphaltenes to
demark variation. Likewise, saturates, araomatics, resins and
asphaltenes (SARA); measurements also support the application
of this new asphaltene formalism. Consequently, the asphaltenes
are very similar, and our new FHZ EoS with the Yen-
Mullins formalism properly accounts for heavy oil and
asphaltene gradients.
INTRODUCTION
Previously there have been no proper thermodynamic models for
treating asphaltene gradients in reservoirs. The reason of
this deficiency is clear; nobody knew the size of asphaltene
particles in oil. Without the size known (or mass, m), Newton’s
gravitational force (F=ma where a is earth’s gravitational
acceleration) acting on the asphaltenes is unknown. And without
the ability to model the effect of gravity, one cannot model
gradients in the oil reservoirs. This profound deficiency led to
improper understanding of low gas-oil ratio (GOR) black oils
and mobile heavy oils. It is widely acknowledged that
condensates have large GOR gradients. That is, compressible
reservoir fluids under the force of gravity exhibit density
gradients due to the hydrostatic head pressure squeezing the
base of the oil column to higher density. In turn, this density
gradient of the compressible reservoir fluid provides the
thermodynamic drive to yield a chemical compositional gradient
and
is accurately modeled by cubic equations of state (EoS).
Conceptually, one might view this as the methane being
squeezed
out of the base of the compressible oil column.
In contrast, low GOR black oils and heavy oils are
incompressible. The cubic EoS correctly predicts that the GOR
gradients

for low GOR fluids are tiny. That is, the small methane fraction
in these fluids is homogeneously distributed. The methane
2 SPE 163291
molecule is so small that thermal energy can lift it to great
heights in the reservoir, in the same way that thermal energy
can
lift atmospheric molecules diatomic nitrogen (N2) and oxygen
(O2) to great heights in the earth’s atmosphere. Likewise, the
methane molecule is so small that Archimedes buoyancy forces
are also very small precluding accumulation of dissolved
methane near the top of the column. The cubic EoS also
correctly predicts that the GOR of low GOR black oils and
heavy
oils is nearly homogeneous. Herein lays the source of the
misunderstanding of black oils and heavy oils. The cubic EoS
predicts that the GOR is homogeneous in low GOR black oils
and in heavy oils. Consequently, the gross misinterpretation
has been that low GOR black oils and heavy oils “should be”
homogeneous (according to the cubic EoS); however, the cubic
EoS, which is derived from the Van der Waals cubic EoS
(developed in 1873) is designed to handle gas-liquid equilibria
only. The cubic EoS is not designed to handle nanocolloidal
solids of crude oil, the asphaltenes. (Nanocolloidal asphaltenes
means that the asphaltene molecules aggregate into species that
are nanometer length scale in crude oils.) The cubic EoS
predictions for the asphaltenes are totally deficient. The
reservoir engineering community has depended on the chemical
engineering community for a proper EoS for reservoir fluids.
The cubic EoS works so well for gas-liquid equilibria that its
deficiency for solids has largely been ignored. In fact, it is not
the gas content that defines black oils and heavy oils, it is the
asphaltene content, but this fact has been obscured due to the

inability to model asphaltenes. The chemical engineering
community might have probed thermodynamic models for
asphaltene gradients; except that the literature of the chemistry
community describing specific chemical properties of
asphaltenes had been in disarray. Incredibly, even so basic a
property
such as molecular weight of asphaltene has been the subject of
recent debate, where it has varied over six orders of
magnitude (Mullins 2010; Mullins 2011; Mullins et al., 2012a).
Fortunately, asphaltene science has undergone a renaissance
in recent years (Mullins 2010; Mullins 2011; Mullins et al.,
2012a; Mullins et al., 2007). The molecular and colloidal sizes
of
asphaltenes have been resolved, and the industry’s first
predictive EoS for asphaltene gradients has been developed and
is
discussed.
Asphaltene Nanoscience and Equation of State
In recent years, many of the molecular properties of
asphaltenes, especially the distribution of asphaltene molecular
weight,
have been resolved (Mullins 2010; Mullins 2011; Mullins et al.,
2012a, Mullins et al., 2007). In addition, the aggregate
structures first found for asphaltenes in laboratory solvents are
found to also apply to crude oils. In 2010, a simple
representation of the molecular and colloidal structures of
asphaltenes in crude oils and laboratory solvents was first
published under the name “the modified Yen model.” Professor
Teh Fu Yen was the founder of modern asphaltene science.
This published model has been renamed the Yen-Mullins model
(Ruiz-Morales 2009; Sabbah et al., 2011) and is shown in
Fig. 1.

Fig. 1. The Yen-Mullins model of asphaltene science showing
predominant molecular and colloidal structures of asphaltenes
(Mullins, 2010). At low concentrations as in condensates,
asphaltenes are dispersed as a true molecular solution (left); for
black
oils, asphaltenes are dispersed as nanoaggregates of molecules
(center); for heavy oils, asphaltenes are dispersed as clusters of
nanoaggregates (right).
With the size known, the effect of gravity can be determined.
For the asphaltene EoS, the gravity term is given by
Archimedes buoyancy in the Boltzmann distribution. That is,
the asphaltene particles are negatively buoyant in the crude oil
as described by Archimedes buoyancy. Combining the gravity
term, with a chemical solubility term and an entropy term we
have the EoS for asphaltene gradients, the Flory-Huggins-Zuo
(FHZ) EoS. The Flory-Huggins theory has long been used to
describe polymer solubility, here we use this theory, but we also
include a gravity term to treat asphaltene gradients.

12
21
11
expexpexp 12
22
1
2
1
2
hh
a
aa
haha

a
a
a
vv
v
RT
hhgv
RT
v
h
h
hOD
(1)
Where OD(hi) is the optical density (color) measured by
downhole fluid analysis (DFA) of the fluids at height hi in the

oil
column,
the molar volume of the relevant asphaltene species (cf. Fig. 1),
SPE 163291 3
is the molar volume of the oil, R is the ideal gas constant, T is
is the solubility parameter of the oil, g is earth’s gravitational
oil
density. The solubility parameter of the asphaltene can be
obtained from literature values, and, in an oil column, the
solubility
parameter variation of the oil is primarily due to GOR
variations. In the FHZ EoS, the first exponential factor is the
solubility
term, the second is the gravity term and the third is the Flory-
Huggins entropy term. For low GOR oils, the gravity term
dominates. For moderate GOR oils (1,000 scf/bbl), typically
both the solubility term and the gravity term contribute to the
asphaltene gradient. With this foundation, the understanding of
many reservoirs is dramatically improved. The FHZ EoS has
now been validated on light condensates to heavy black oil in
many case studies. A review and expansion of the FHZ EoS for
reservoir fluids of all types is given by Zuo, et al., (in
progress). The primary work flow is to measure the fluid
gradient
accurately, especially within the solid, liquid and gas fractions
of the reservoir fluids. This measurement is best performed
with downhole presssure measurements and DFA (Mullins,
2008). DFA is a relative new product line in the petroleum
industry. Once the gradients are accurately measured, the cubic

EoS for gas-liquid gradients and the FHZ EoS for asphaltene
gradients are employed to understand the nature of the fluid
column. By this means, a variety of issues can be addressed
including reservoir connectivity, viscosity profiles, and tar mat
character.
One system that clearly shows the Boltzmann distribution is the
pressure gradient of the earth’s atmosphere. If gravity were
the only determinant for the distribution of air molecules, then
all air molecules would be pulled to the surface of the earth
and everyone would suffocate. Thermal energy lifts air
molecules to elevations above the earth’s surface. Because air
molecules are small (two heavy atoms in N2 and in O2), then
available thermal energy lifts air molecules to great heights.
Here, the air molecules are suspended in a vacuum, so the
Boltzmann distribution is simply exp{-mgh/kT} where m is the
weighted molar mass of air molecules, 80% N2 and 20% O2,
and this is what is plotted in Fig. 2 with T=298° Kelvin. Such a
simple prediction (Fig. 2) closely matches observation.
Fig. 2. Calculated atmospheric pressure from the equation exp{-
mgh/kT} using the weighted average of the molecular mass of
air
molecules (and 298 °K) closely matches observations. The
prediction for Mount Everest is slightly high because of the
assumption
of constant temperature. Virtually the same equation applies to
mobile heavy oil gradients substituting the negative buoyancy
of
asphaltene particles for mass.
Archimedes buoyancy (essentially because the liquid is
incompressible so buoyancy is used) and the rest of the

Boltzmann distribution expression remains the same as for the
atmospheric pressure. For low GOR crude oils, the asphaltene
gradient is predominantly just given by the gravity term with
all variables defined above.
(2)
Asphaltene molecules contain ~70 heavy atoms, nanoaggregates
contain ~400 heavy atoms and clusters contain ~3,000
carbon atoms. Consequently, the gravitation gradient of
asphaltenes depends critically on the particular asphaltene
species.
For a fixed thermal energy (temperature), asphaltene molecules
are suspended to considerable height (but much less than air
molecules with only two heavy atoms), nanoaggregates less, and
clusters with ~3,000 heavy atoms, the least height. We are
discussing equilibrium distributions; this means the distribution
doesn’t change with time (like the atmospheric pressure
gradient of the Earth), and the distribution does not change
dramatically with a small change in applied conditions.

kT
hhgv
exp
h
h
hOD
hOD 12a
1a
2a
1
2
4 SPE 163291
CASE STUDIES

Asphaltene Nanoaggregates. The first case study to prove the
utility of Eq. 2 and ushered in the Yen-Mullins model and the
FHZ EoS was a reservoir depicted in Fig. 3 (Mullins et al.,
2007). This field is tilted due to differential uplift from buoyant
salt, Fig. 3 left, and the reservoir contains a low GOR black oil.
In the structuring process the reservoir was faulted and the
largest uncertainty in the reservoir is whether these faults are
sealing or transmissive. The asphaltene gradient was measured
by DFA in the two primary stacked sands, the red and the blue
sands and additionally in a section of the field with a different
sand, the green sand. Equation 2 (the gravity term only from the
FHZ EoS) was used to fit the asphaltene gradient in each
sand. All data conformed to the asphaltenes being in the form of
nanoaggregates (~2 nm particle size), the middle of the three
species shown in Fig. 1. Since the asphaltene nanoaggregates
have a very small diffusion constant, the asphaltenes are
equilibrated (that is, they obey Eq. 2), then the conclusion is
that reservoir must be connected in the sense of a production
time frame. Barriers that impede fluid flow would also impede
equilibration of the reservoir fluids (Pfieffer et al., 2011).
Each sand, the red, blue and the green, contain equilibrated
asphaltenes. Consequently, each of the sands are laterally
connected, but not connected to each other; this has been shown
correct with production data (Mullins et al., 2012c). Other
case studies establish the existence of asphaltene
nanoaggregates in black oils (Mullins et al., 2012c; Dong et al.,
2012).
Fig. 3. Upper and lower horizons are depicted for a deepwater
reservoir (Mullins et al., 2007). The stacked sands, the red and
blue,
are not in pressure equilibration, therefore are not connected.

Each sand (including the green sand) contains equilibrated
asphaltenes; they obey Eq. 2 for asphaltene nanoaggregates.
Consequently, each sand is connected laterally and vertically,
which
has been proven in production (Dong et al., 2012). This case
study proved that the asphaltene nanoscience and
thermodynamic
modeling presented herein are correct.
Asphaltene Clusters. The first study to prove the existence of
asphaltene clusters in oil reservoirs was in Ecuador (Pastor et
al., 2012). Asphaltene clusters form at high concentration and
therefore occur in heavy oils, Fig. 4. The clusters are large and
settle preferentially lower in the oil column, thereby yielding
gigantic gradients.
Fig. 4. The asphaltene concentration gradient is about a factor
of 2 in ~50 ft for samples from a single well in a field in
Ecuador
(Pastor et al., 2012). Clusters form at high asphaltene
concentration, here 10% to 20%. The relatively large cluster
size, 5 nm, causes
preferential accumulation of these asphaltenes towards the base
of the column in accord with predictions of Eq. 2. Here, vertical
connectivity is established and consistent production data.
SPE 163291 5
Recently, a similar heavy oil gradient was observed in
deepwater Gulf of Mexico (Nagarajan et al., 2012) confirming
the

Research Methods – Individual Assignment .docx

Research Methods – Individual Assignment .docx

Recomendados

Recomendados

Mais conteúdo relacionado

Semelhante a Research Methods – Individual Assignment .docx

Semelhante a Research Methods – Individual Assignment .docx (20)

Mais de debishakespeare

Mais de debishakespeare (20)

Último

Último (20)

Research Methods – Individual Assignment .docx