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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

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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.