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The material of which a petroleum reservoir rock may be composed
of can range from very loose and unconsolidated sand to a very hard
and dense sandstone, limestone, or dolomite.
The grains may be bonded together with a number of materials,
the most common of which are silica, calcite, or clay. Knowledge of
the physical properties of the rock and the existing interaction
between the hydrocarbon system and the formation is essential in
understanding and evaluating the performance of a given reservoir.
Rock properties are determined by performing laboratory analyses on
cores from the reservoir to be evaluated. The cores are removed
from the reservoir environment, with subsequent changes in the core
bulk volume, pore volume, reservoir fluid saturations, and,
sometimes, forma-tion wettability. The effect of these changes on
rock properties may range from negligible to substantial, depending
on characteristics of the formation and property of interest, and
should be evaluated in the testing program.
Formation damage is a generic terminology re-ferring to the
impairment of the permeability of
petroleum-bearing formations by various adverse processes.
Formation damage is an undesirable operational and economic problem
that can occur during various phases of hydrocarbon recovery from
subsurface reservoirs including production, drilling, hydraulic
fracturing, and work-over operations. As expressed by Amaefule et
al. (1988) Formation damage is an expensive headache to the oil and
gas industry. Formation damage is caused by physico-chemical,
chemical, biological, hydrodynamic, and thermal interactions of
porous formation, particles, and fluids and mechanical deformation
of forma-tion under stress and fluid shear. These processes are
triggered during the drilling, production, work over, and hydraulic
fracturing operations.
Formation damage indicators include permeability impairment,
skin damage, and decrease of well per-formance. Therefore, it is
better to avoid formation damage than to try to restore it. A
verified forma-tion damage model and carefully planned labora-tory
and field tests can provide scientific guidance and help develop
strategies to avoid or minimize formation damage. Properly designed
experimental
technology
Effects of the Workover Fluid on Wellbore Permeability
WellControl
Workover fluids used to kill oil wells for many subsurface
production operations can cause many damaging problems to the
formation near the wellbore. The damage is the result of the
contact of the foreign workover fluid with the native formation
fluids. If these two fluids are not compatible, chemical reactions
occur and scale deposits precipitate depending on the composition
of each fluid and on the pressure in the wellbore. These
precipitations reduce the permeability near the wellbore and
creating what so-called skin effect. This skin if not removed by
workover remedial jobs such as acidizing or hydraulic fracturing,
it will reduce the pro-ductivity of the well and hence decrease the
overall oil recovery from the well. It is therefore, important to
properly select the best suitable workover fluid for any remedial
job in order to avoid the previous problems. The objective of this
study, carried out in the laboratory by selecting different core
samples representing the Farrud oil productive formation in the
field, and water flooding technique using different injection water
mixtures and salinities was imple-mented on these cores, is to
select the suitable non damaging workover fluid to be used for the
oil wells in Farrud formation in Sirte basin Libya.
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and analytical techniques, and the modeling and simulation
approaches can help understanding, diagnosis, evaluation,
prevention, remediation, and controlling of formation damage in oil
and gas reservoirs. The consequences of formation damage are the
reduction of the oil and gas productivity of reservoirs and
noneconomic operation. Therefore, it is essential to develop
experimental and analytical methods for under-standing and
preventing and/or controlling formation damage in oil and gas
bearing formations.
Laboratory experiments are important steps in understanding the
physical basis of formation damage phenomena. These efforts are
necessary to develop and verify accurate mathematical models and
computer simulators that can be used for pre-dicting and
determining strategies to avoid and/or mitigate formation damage in
petroleum reservoirs. Once a model has been validated, it can be
used for accurate simulation of the reservoir formation dam-age.
Current techniques for reservoir characterization by history
matching do not consider the alteration of the characteristics of
reservoir formation during petroleum production. In reality,
formation charac-teristics vary and a formation damage model can
help to incorporate this variation into the history matching
process for accurate characterization of reservoir systems and,
hence, an accurate prediction of future performance.
Formation damage is an exciting, challenging, and evolving field
of research. Eventually, the research ef-forts will lead to better
understanding and simulation tools that can be used for
model-assisted analysis of rock, fluid, and particle interactions
and the processes caused by rock deformation and scientific
guidance for development of production strategies for forma-tion
damage control in petroleum reservoirs.
Factors Affecting Formation Damage1. Invasion of foreign fluids,
such as water and
chemicals used for improved recovery, drilling mud invasion, and
work over fluids.
2. Invasion of foreign particles and mobilization of indigenous
particles, such as sand, mud fines, bacteria, and debris.
3. Operation conditions such as well flow rates and wellbore
pressures and temperatures.
4. Properties of the formation fluids and po-rous matrix.
Formation Damage MechanismFormation damage mechanisms are
described
as follows:1. Fluid-fluid incompatibilities, for example
emulsions generated between invading oil based mud filtrate and
formation water.
2. Rock-fluid incompatibilities, for example con-tact of
potentially swelling smectite clay or de-flocculatable kaolinite
clay by non-equilibrium water based fluids with the potential to
severely reduce near wellbore permeability.
3. Solids invasion, for example the invasion of weighting agents
or drilled solids.
4. Phase trapping/blocking, for example the invasion and
entrapment of water based fluids in the near wellbore region of a
gas well.
5. Chemical adsorption/wettability alteration, for example
emulsifier adsorption changing the wettability and fluid flow
characteristics of a formation.
6. Fines migration, for example the internal movement of fine
particulates within a rock's pore structure resulting in the
bridging and plugging of pore throats.
7. Biological activity, for example the introduc-tion of
bacterial agents into the formation during drilling and the
subsequent genera-tion of polysaccharide polymer slimes which
reduce permeability.
It is commonly accepted that formation damage is due to either
or both liquid and solid penetration. This type of damage commonly
occurs during the drilling of new wells and work over operations.
The invasion of drilling mud and other solids into the formation
creates a cylinder of reduced permeability around the wellbore and
reduces the flow rate of liquid and gas into the borehole. Tough
impermeable filter cake forms on the face of the borehole,
consisting mainly of the solid particles of the drilling fluids,
some of these particles may even penetrate into the formation,
plugging the pores and fractures of the system. The depth of
penetration is difficult to de-termine though it is generally
agreed that the solids penetrate no more than a few inches.
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Results and Discussion
T h e c h e m i c a l composit ions for the Farrud forma-tion
water and the Augi la in j ec t ion water are tabulated in tables 1
and 2 respectively. These chemical composi-tions are prepared in
the laboratory according to the chemical analysis received form the
company. The prop-erties of Farrud, Aguila and the mix-ture of
(50%) waters are also given in ta-ble 3. The properties of the core
samples represent ing the Farrud formation are presented in table
4.
The core samples used in this study numbers 12, 21, 27 and 30
were satu-rated with 100 % Augila, 100 % Far-rud and 50 % mix-ture
respectively as shown in table 7. The porosity and the permeabil i
ty of the cores were calculated, and the results af ter the
saturation process are given in table 4.
The core samples were damaged us-ing the three different waters;
Farrud, Augila and the 50 % mixture of the two waters and the
porosity values for the three damaged cores are tabulated in
table 5.
Table 1: Farrud Formation Water Composition
Table 4: Sample Cores Physical Properties
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By comparing the original core porosity for all the core samples
(table 4) with the cores porosity after saturating with three
waters (table 5), it can be noted that Augila water produced less
decrease in porosity (i.e. less damaging) than the Farrud water and
the mixture (50%) Farrud and 50 % Augila, this is due to the less
salin-ity value of the Augila water. The comparison results are
shown in table 6.
After cleaning and drying the received cores, both air and
liq-uid permeability were measured and calcu-lated gas permeability
values were corrected for the Klikenberg effect. The values for the
core samples (21, 21, 27 and 30) are listed in table 7.
The cores 12, 21 and 30 were saturated with 100% Augila, 100%
Far-rud and 50% mixture. After the saturation process, the cores
were dried and finally the permeability of the cores was measured
and cal-culated using the same above mentioned pro-cedure. The
properties used in the calculation and the final perme-ability
values are listed in table 8.
By comparing the per-meability values before
Table 5: Porosity Calculation After Damaging the Core Samples
with Different Water Sources
Table 9: Final Results of Permeability
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and after saturation, it can be noted that Augila water gives
less damaging than the Farrud and the Mixture (50%) waters, because
it has less salinity which is the same effect on the porosity. The
initial per-meability values and the final one after saturation are
listed in table 9.
Table 10 illustrates the actual core displacement data for core
samples 12, 21 and 21c.
Table 11 shows the relative permeabilities values for core
sample 21 saturated with the Far-rud formation water and displaced
with Augila injection water. Figure 1 illustrates that the Augila
water could not be used for the displacement of oil, because of its
low mobility value which is somewhat far from the mobility value of
the saturated oil.
Table 12 shows the relative permeabilities val-ues for core
sample 21 saturated with the Farrud formation water and displaced
with Farrud injec-tion water. Figure 2 illustrates that The Farrud
water could be used for the displacement of oil and giving higher
values of recovery, because
the mobility value of Farrud water reaches the mobility value of
oil.
Table 13 shows the relative permeabilities val-ues for core
sample 21c saturated with the Farrud formation water and displaced
with 50 % Farrud injection water and 50 % Augila injection water.
Figure 3 illustrates that The mixture when is used as the injection
fluid gives low oil permeabilities
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values compared to the two injection water therefore the mixture
could not be used as the injection fluid for the field.
From table 14 which represent the compari-son between the
re-coverable oil from the different core samples
by injection of different waters as illustrated in table 14. It
can be noticed that the Farrud water gives the highest oil recovery
compared to the Augila injection water and also toot the 50 %
mixture and therefore it is recom-mended to be the water used for
the injection for workover practices.
Conclusions The experimental results indicate that the
porosity of all studied cores decrease when saturated with
Farrud water compared to those saturated with Augila and the
mixture water, whereas the cores saturated with Augila water
produce the lowest porosity decrease, because Augila water has less
salinity compared with Farrud and the mixture waters.
The experimental results also indicate that the permeability of
all studied cores de-crease when saturated with Farrud water
compared to those saturated with Augila and the mixture waters,
whereas the cores saturated with Augila water produce the lowest
permeability decrease, because Augila water has less salinity
compared with Farrud and the mixture waters.
The experimental results indicate that the re-coverable oil
using a mixture of Farrud water with Augila water with a ratio of
50 percent is lower than that obtained from either inject-
ing Augila water only or Farrud water only. The experimental
results indicate that the
recoverable oil with Farrud water as the displacing fluid is the
highest, because the mobility value of Farrud water more reaches
the mobility value of oil compared to that of Augila and the
mixture waters.
The experimental results indicate that Far-rud and Augila waters
are not computable, because it gives the least recovery.
Recommendations It is recommended that Augila water should
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be used as the workover fluid for this res-ervoir because of its
low damaging effect.
It is also recommended that the mixture of both Augila and
Farrud water should not be used as a displacing fluid for this
reservoir because of its low observed recovery factor.
It is also recommended that Farrud water alone cannot be used
either as a workover fluid or a displacing fluid in this reser-voir
because of its great damaging effect. Otherwise a chemical
treatment should be conducted.
AcknowledgmentsThe authors would like to thank the Libyan
Petroleum Institute for providing the neces-sary materials and
technical support used for conducting this study. The appreciation
is also extended to Harouge Oil Operations for provid-ing the data
used in this study. The Petroleum Engineering Department of Al
Fateh University is highly appreciated for providing the
labo-ratory time and equipments used during the course of
conducting this study.
References 1. Tarek Ahmed Reservoir Engineering
Handbook, Second Edition 2001. 2. Zoltn E. Heinemann Fluid Flow
in Po-
rous Media, Volume 1, Leoben, October 2005.
3. F. Civan "Reservoir Formation Damage: Fundamentals, Modeling,
Assessment, and Mitigation", Library of Congress
Cataloging-in-Publication Data, Copy-right 2000 by Gulf Publishing
Company, Houston, Texas.
4. V. Tantayakom, S. Chavadej "Study of Scale Inhibitor
Reactions in Precipitation Squeeze Treatments", paper SPE 92771,
presented for presentation at 2005 SPE international symposium on
oil field chem-istry, Texas, 2-4 February.
5. J. R. Ursin and A. B. Zolotukhin Reservoir Engineering,
Stavanger, 1997.
6. Mehdi H., Leonard K. and Herbert H. Rela-tive Permeability of
Petroleum Reservoirs
7. Gawish A. and Al-Homadhi Relative Per-meability Curves for
High Pressure, High Temperature Reservoir Conditions, 2008.
8. Mike Crabtree, David Eslinger, Phil Fletcher, Ashley Johnson
and George King "Fighting Scale-Removal and Prevention", Autumn
1999.
This publication thanks the following au-thors for providing
this article.
Prof. Mohamed S Nasr, Professor of Petro-leum Engineering
/Department of Petroleum Engineering /Al Fateh University Tripoli
Libya, Professor of Petroleum Engineering at the Francias Institute
de Petrole/ Paris/ France and Professor of Petroleum Engineering at
the Clausthal Technical University Germany.
Prof Nuri K. Ben Hmeda, Professor of Petroleum Engineering
/Department of Pe-troleum Engineering /Al Fateh University Tripoli,
Libya.
AP Amer M. Aborig, Assistant Professor of Petroleum Engineering
/Department of Petroleum Engineering /Al Fateh University Tripoli,
Libya.