The South Fuwaris Field is located in the Partitioned Zone between Kuwait and Saudi Arabia. The Lower Cretaceous Ratawi reservoirs were discovered in 1961, and production commenced in 1963. There are two major reservoirs – the Ratawi Limestone, which is predominantly developed by vertical wells, and the Ratawi Oolite, which is exclusively developed by horizontal wells. The reservoirs comprise low-moderate permeability limestones. The use of Logging While Drilling (LWD) tools which utilise natural radioactive sources has been always risky since losing radioactive source will necessitates a complex procedure to abandon side track the hole. Recently, a new LWD logging technique that incorporates Pulsed Neutron Generators (PNG) was introduced to Wafra Joint Operations (WJO). This new technique acts generates multiple measurements (Resistivity / Density / Neutron / Sigma / Spectroscopy). The PNG uses electrical power generated from the measurement-while-drilling (MWD) turbine to generate a large cloud of fast neutrons. These fast neutrons interact with the formation atoms to generate formation hydrogen index, sigma, and spectroscopy data. In addition, the fast neutron interactions generate a secondary gamma ray cloud that can be used to measure formation density (similar to standard density measurement). This innovative technique was used for the first time for Wafra Joint Operations in the South Fuwaris Field, with great success. The tool was run in a pilot hole with an inclination of 60°, cutting the Ratawi Limestone and Ratawi Oolite reservoirs. The acquired data were of excellent quality in comparison with conventional LWD data. The formation sigma was used in the water saturation calculations. Spectroscopy analysis was also recorded and used for formation evaluation, especially for clay content. Finally, the new technique has been proven as a good risk mitigation / elimination for future operations.

Reservoir saturation monitoring, through cased wells, usually is the main key factor for proper reservoir management and recovery optimization in the cases of developed and mature oil fields. Thermal decay time tool (TDT) has been the main technique used for monitoring the inter wells water saturations in developed reservoir. One of the main problems that encountered while using TDT log is the reservoirs with low formation water salinity, this problem may also appear in reservoirs that are supported by water injection projects, in which the formation water is diluted by the injected water. This problem has been solved by combining TDT technique and cased hole formation resistivity tool (CHFR). The ability to detect and evaluate bypassed hydrocarbon and monitor fluid movement in sandstone reservoir is a vital question to improve production and increase recovery. It is difficult to interpret the TDT data in reservoirs with low-salinity sandstone formation water. This problem cannot be solved because TDT measurements depend on the salt content in formation brine. Instead the cased hole formation resistivity tool (CHFR) is proposed to overcome the limitations associated with pulsed-neutron tools. This paper presents case studies of pay zones-saturation monitoring obtained from TDT and CHFR logs recorded in wells in mature sandstone reservoir which suffers from high water cut. The results are referenced to open-hole resistivity logs to monitor the vertical movement of reservoir fluids. It was found that water saturations calculated from CHFR logs are more accurate than TDT log in most cases. Water shut-off remedial action to manage water production from producing sections in the studied wells has been much more successful based on CHFR / TDT logs than the proposed remedial action based only on TDT data interpretation.

Determining the capillary pressure behavior of rocks at reservoir temperature and pressure is vital in understanding the displacement mechanism in the reservoir. An understanding of the displacement mechanism is essential to evaluate its effect on fluid saturations and oil recovery. The evaluation of saturations and thus oil reserves from resistivity logs requires laboratory determination of both the cementation factor (m) and the saturation exponent (n) under conditions as representative as possible of reservoir ones. Special laboratory equipment using air and actual formation brine at reservoir temperature and under effective overburden pressure was developed. The porous plate method was used to determine capillary pressure curves and saturation exponent at ambient conditions and at full reservoir conditions, (reservoir pressure and temperature) on sandstone core plugs from a Libyan reservoir. The main objective of this study was to determine whether any difference exists between the capillary and electrical properties obtained at ambient conditions and those obtained at reservoir conditions for rock samples. Prior to the test, the effect of overburden pressure on porosity and formation factor can be studied.

An exploration campaign of RWE Dea AG has discovered several oil fields in carbonate reservoir layers. Log analysis shows that most of the wells have a very long transition zone above Oil Water Contact (OWC). The lower part of the oil column above OWC contains significant amounts of non-producible oil. The length of this zone may falsify the economic significance of the oil column, which appears as too large. An additional hydrocarbon contact is defined and named „Producible Oil Water Contact - POWC". The differentiation between moveable and unmoveable oil in the transition zone helps to identify and assess the producible oil in a more appropriate way. This level may be determined by using fractional flow curves. In this case the contact level is a derived value for water saturation that relates to a specific water cut at surface conditions. If dynamic reservoir modeling is available the POWC can be also determined based on 3D-simulation results, at the lowest level where oil begins to flow. In order to comply with the industry standards for definition of OWC the methods available will be discussed and it will be verified if the newly introduced POWC fulfills common best practice and can be used as supplement. The effect of applying the POWC on oil-in-place calculations and recovery factor is shown with an example for application in reservoirs with long transition zones. It is aimed to concentrate resource calculations to the levels with economically producible oil, in order not to artificially inflate oil-in-place volumes and keep recovery factors reasonable. Furthermore, improved contour mapping based on new POWC can help to find locations for wells with better oil productivity.

In Egypt's Western Desert, water saturation evaluation of the Upper Bahariya reservoirs is complicated by significant uncertainties in the resistivity-based saturation equation inputs, mainly the formation water salinity, but also the cementation factor and the clay cation exchange capacity (CEC). A novel dielectric multifrequency measurement was able to clearly identify zones in which oil was present, regardless of these inputs. It provided a residual oil saturation and clear differentiation of oil-bearing zones from water-saturated zones. The measurement also permitted us to apply constraints to the conventional saturation interpretation from shallow and deep resistivities. This process highlighted the variability of formation water salinity across the well and the mixing of filtrate and formation waters in the zone investigated by microresistivity tools. The dielectric tool also measures dielectric dispersion, from which a parameter (MN) related to the tortuosity of the conduction path can be extracted. This MN parameter was used to refine the water saturation computation from deep-resistivity logs. Variation of the MN parameter between 1.8 and 2 was observed in the reservoir zones. In the zone of interest, a water saturation difference of 7-8 % was observed in the cleanest zone between water saturation computed using the variable MN parameter and that computed using a fixed cementation factor of 1.9. The water saturation recomputed using the data from the dielectric log matches well the irreducible water computed from the nuclear magnetic resonance (NMR) data. Dielectric dispersion was also used to derive the CEC, which was then input as a direct measure of shaliness in the deep-resistivity saturation equation. The dielectric measurement increased the accuracy of the water saturation computation in this challenging environment and provided data that are not directly available with conventional logging.

West Qarun (WQ) and Abrar fields are located in Abu El Gharadig (A/G) basin in the Egyptian Western Desert with a combined area of about (82) Km 2 . Drilling activities in this area were commenced in late 1980s till first oil discovery was announced by (AMOCO) in (1994), Since that; and through February 2009; a total of (4.2) MMSTB oil was produced from six wells in both fields. This paper demonstrates that an intensive review of petrophysical parameters had led to re-discovering the actual unforeseen bigger volume of the old matured fields that had been producing since decades; resulting in boosting up the combined production levels from about 600 BOPD to about 7000 BOPD while still development activities continues to prove extensions to both field and add more reserves. Subject fields are producing upper cretaceous reservoirs of both Abu Roash G (A/R_G) and Upper Bahariya (U.B.) formations; this area was formerly famous for low well productivity and non-encouraging economics; but after Sahara Oil and Gas Co. (SOG) received the operatorship of these oil leases in Feb 2009, a petrophysical interpretation review was applied to find out the reason behind more than 10 years of stable production rates, the review included investigating the validity of the formerly used models for interpreting the existing shaly sand that indicated high water saturations that never matched the production data; also, an individual well interpretation parameters were considered instead of the formerly generalized set of parameters over-all the fields. The conclusion of this paper could be summarized in attracting attention to the importance of a new eye vision when considering a new evaluation of reserves of an oil field that had been formerly considered as a matured one; while still investigating each piece of information that might have over-estimated or under-estimated the never-seen reservoir volume.

This paper presents analytical algorithms to calculate ultimate recovery factors for radial flow systems. The approaching method is similar to the well-recognized Buckley-Leverett equations, but it's accurate for matured fields, especially peripheral water-flooding reservoirs. Buckley-Leverett displacement equations have been derived strictly from linear flow systems, and have been verified by linear flow experiments only. However, nowadays, it's very common to observe multiple water injectors drilled around producers to enhance the recovery factor in mature fields. New analytical equations that consider non-linear flow patterns are more appropriate for these types of operations. The new equations proposed in this paper have been verified with real field data. The original Buckley-Leverett equation generally results in much lower recovery factors that barely match the cumulative production. Consequently, the estimated ultimate recovery (EUR) by volumetric methods tends to be too low. As a result, the production projections according to match this EUR are not reasonable when compared to the historical performance of the wells and Decline Curve Analysis (DCA). The proposed analytical model improves the prediction of reservoir performance. It works as an important supplement to the Buckley-Leverett method for oil fields worldwide.

Porosity, water saturation, and net-to-gross evaluation can be challenging in thinly bedded sands. The use of standard induction resistivity for formation evaluation can lead to the overestimation of water saturation. This work explores the following options to improve formation evaluation in these conditions: the use of high resolution density and nuclear magnetic resonance (NMR) data to improve porosity vertical resolution; the use of high-resolution resistivity from an oil-based-mud microresistivity imaging tool in improving the saturation computation ( S w ); and the comparison of imaging tool resistivity-based sand count and NMR-based thin-bed fraction. Using high-resolution porosity inputs from density and NMR provided a porosity curve with a better vertical resolution to match the high resolution resistivity from the imaging tool. It also identified additional productive thin beds compared to the standard resolution outputs and allowed computation of a high-resolution irreducible water saturation. The induction-based Sw is strongly affected by shoulder bed effect and overestimates S w by approximately 10 to 15%. The high-resolution curve from the imaging tool was used as an input into the S w computation, which was made possible by shallow oil-based mud (OBM) invasion. This approach gave good results in beds thicker than 6 in., where S w from the imaging tool matches the irreducible water saturation computed from NMR, giving 20 to 30% S w . A thin-bed fraction curve was computed from the NMR data. It shows a good match with the image-based high resolution- sand count and the image features, demonstrating that NMR and the imaging tool are equally able to identify and quantify thin beds, even though they have different vertical resolutions. This study showed that the microresistivity imaging tool and NMR are essential tools to characterize thinly bedded reservoirs.

An integrated approach where information and analysis from each discipline like geology, seismic, petrophysics and reservoir engineering is applied to build three-dimensional (3D) geo-cellular model and finally simulating the reservoir to represent the real flow conditions leading to formulate the field development strategy. Most of the present workflows are designed to model the clastic reservoirs integrating geological trend and statistical methods effectively. Limestone formations are highly sensitive to fluctuations in temperature, salinity and bathymetry which affect secondary porosity and permeability within the formation and thus result in randomness. Generally, in limestone the integration of geology and geo-statistics is very difficult due to lack of well defined geological trend or randomness. This difficulty is further enhanced if the wells available within the study area are few. Paper brings out how use of seismic derived porosity trend during property modeling led to a meaningful porosity model in a limestone reservoir. In absence of core based J-function data, use of log derived initial water saturation helped in deciding the rock type distribution and saturation modeling capturing the transition zone observed in wells. Classical methods like WOR & WOR derivative plots and material balance study helped in deciding the type of aquifer support and oil volume in place. The paper deals with a real case example of a carbonate reservoir in an offshore environment with around 12 MMT oil in place and 3 exploratory and around 9 development wells within the study area. Finally, with the help of a real case example, the paper brings out the critical stages where the application of integrated approach leads to an improved reservoir model which gives reasonably good estimate of the oil in place and a satisfactory history match.

Deep water Tertiary reservoirs of Krishna Godavari basin are generally very complex and heterogeneous, ranging from massive thick sands to highly laminated very thin sand/shale sequences beyond the vertical resolution of imaging tools. Verification of log-derived quantities in very thin reservoirs is frequently difficult because of bias and scatter introduced by non-uniform or incomplete plugging of the available over 750 meters of conventional cores. As laminar shale does not occupy or alter the intergranular sand porosity, the conventional way of validation of log derived porosity and water saturation with core data showing excellent correlation does not ensure the correctness of petrophysical evaluations. In this paper, it has been demonstrated that there are potential problems associated with the integration of petrophysical evaluation and core data. Sources of errors are mainly due to the use of different parametric systems viz. using of the terms shale volume and clay volume interchangeably and validating log derived shaliness with clay abundance from XRD core data. Shaliness derived from logs cannot be directly correlated with such core data because neither de-averaging of lithology on log analysis nor averaging of core data is possible for the effective core-log integration. Average hydrocarbon pore volume in laminated reservoirs is linearly related to the average cumulative net sand fraction or shaliness of the formation. Laminar sand porosity and water saturations are independent of shaliness or net sand. Excellent correlation of log derived deconvolved data sets like porosity and water saturation with core measurements does not validate the correctness of hydrocarbon pore volume estimation, which is linearly related to net sand. Accurate estimation of hydrocarbon pore volume requires an accurate calibration of laminar sand/shale volumes, which can be precisely validated only with lamcount data.

Water production is one of the main challenges facing oil and gas producers. It is necessary to carefully manage water production in order to enhance oil production. In order to identify watered out zones, a time lapse cased hole resistivity survey was carried out to evaluate hydrocarbon saturation. In static conditions, the value of cased hole resistivity over other time lapse techniques resides in its deep depth of investigation, which results in increased immunity to borehole fluid reinvasion. This technique was applied on three wells, where the water cut was ranging from 65 % to 90 %. The cased hole formation resistivity clearly identified the watered out zones. A water shutoff operation followed. The objective of the cased hole resistivity acquisition was met as the water cut dropped down to 1 to 40 % after isolation of the watered out zones.

The permeability prediction is of extreme importance in hydrocarbon reservoir management. The reservoir rocks are made up of grains, cement and pore network. The pore network is made up of larger spaces, referred to as pores, which are connected by small spaces referred to as throats. The pore spaces control the amount of porosity, while the pore throats control the movement of fluids and the quantity of rock permeability. The core analysis data for 219 sandstone and limestone samples were available. The data include porosity, permeability and capillary pressure by mercury injection. These samples represent 21 stratigraphic units. The geologic age varied between Cretaceous and Pliocene. Sandstone reservoirs are represented by 179 samples, while 40 samples represent carbonate reservoirs. The data were collected from different geographic areas within Egypt. Pore-throat size distribution parameters were calculated from the data of capillary pressure. These data were used to approximate the distribution of pore volume accessible by throat of a given effective size. A new definition for micro-porosity was proposed based on pore throat size distribution. These data was used to descriminate the sample porosity into micro and macro porosity based on a pore throat cutoff, which was determined from the relationship between storage and flow capacity of the pore network. The relationship between permeability and aspects of pore geometry; micro-porosity, macro-porosity and pore throat parameters have been analyzed and discussed. The interpretation of the results indicates that the permeability is mainly a function of pore-throat size distribution while the amount of the porosity or the porosity configuration is not the main factor that controls the amount of permeability. A new model for permeability prediction was develpoed which incorporate the pore space and pore throat. The obtained results have shown the great influence of pore throat on permeability prediction.

Water is injected in the hydrocarbon reservoir to serve two purposes, to maintain reservoir pressure and to displace oil as production proceeds in the reservoir. In recent years, smart wells coupled with reservoir simulation models are used to improve the results of water injection performance. High frequency data (pressure, flow rate, etc.) that is a product of the smart wells provide the basis for a closed-loop, fast track updating of the dynamic reservoir models. While high frequency updating of the reservoir model remains a challenge, there are emerging technologies that can make such objectives achievable. An integrated approach that combines analytical and numerical solutions with artificial intelligence and data mining is proposed to ultimately achieve the closed-loop, fast track updating system. This study is the first step in that direction. In this work the ability of analytical solutions to calculate reservoir water saturation profiles from field water cut data are investigated. Different flow regimes and reservoir geometries are considered during this study. Diffuse, segregated and capillary influenced flow models are analyzed in both one and two dimensional water injection using a commercial numerical simulator. Different analytical formulations are applied for each flow regime in order to reproduce simulation production data. For each model a specific relative permeability relation is assigned and tuned with the aim of matching water breakthrough time and water cut history. An accurate match is achieved between water saturation profiles generated by the analytical models and the results by the reservoir simulator. The influence of simple reservoir heterogeneity on the robustness of the analytical models is studied.

For oil reservoir with bottom water and/or gas cap, gas and water conings impose serious problems during the oil production. Coning leads to the premature gas and water breakthrough thus results in high water cut and gas oil ratio, which require a higher surface facility capacity to process excessively produced water and larger three-phase separators to separate gas, oil, and water. Consequences of early breakthrough are large footprint due to large facility, more energy to operate field, and low oil recovery. Even though numerous studies had been focused on solving the critical oil rate for gas and water coning problems, to our knowledge none of them considers the effect of capillary pressure on critical oil rate. The ignorance of capillary pressure caused the error of calculated critical rate to rise to 300%, according to the real field case study. The errors caused by neglecting capillary pressure are severe in low permeability reservoirs. For the purpose of good production design, we investigated the effect of capillary pressure on critical rate estimation. Our study showed that the calculated critical rates are close to real field critical rates. The existing methods underestimate the critical rate by not taking capillary pressure into account. Therefore, more accurate critical rates can be obtained using our method. With more accurate result more reliable production plan can be designed to maximize the ultimate recovery.

Mud solid and filtrate invasion are the most common causes of formation damage during overbalanced drilling (OBD), which is a method of drilling in which the wellbore pressure remains greater than formation pressure. During the past ten years, underbalanced drilling operations (UBD), which can be defined as a drilling method in which the wellbore pressure is less than formation pressure, has been growing due to their applications such as prevention of lost circulation, reduction of filtration lost in naturally fractured and mature reservoirs. It is very difficult to always maintain the underbalanced conditions in drilling and completion operations during bit changing and tripping operations. In these cases due to the non-existence of internal and external mud cake, there will be high amount of mud solid and filtrate invasion into the formation. Besides these, the potential of formation damage still exist during UBD due to Counter-current Spontaneous Imbibition (COUCSI) process. In this case, for water-based muds the original water phase pressure in the reservoir is less than the irreducible water saturation. Therefore the capillary pressure and wettability characteristics of the formation can result in water invasion from the drilling fluid into the formation. The main goal of this study is modeling of this process for a vertical and horizontal well in a conventional reservoir, which are being derilled using a water-based mud system in an underbalanced mode, investigating the effects of some factors such as amount of underbalanced pressure difference and exposure time. In addition, the amount of invaded water and invasion distance are discussed too. The numerical modeling and resulting governing system of partial differential equations, the descretized forms and initial and boundary conditions are presented. Based on this numerical modeling, it is shown that for high capillary pressure values, the amount of water invasion increases. Moreover, for lower underbalanced differential pressure and higher exposure times, water invasion and invasion distance increases too.

The reservoir, located in the Sirte Basin, Libya was discovered in the early 1960s. Since then, more than 65 wells have been drilled. By the end of the year 2008, more than 160 MMstb undersatured oil have been produced from the Upper Cretaceous. Water cut has risen to 65% and average reservoir pressure is still 1000 psi above bubble point. The individual well production history is highly influenced by water coning. The field is geologically complex; heterogeneous, contains numerous large and smaller normal faults sometimes associated with fractures, leading to local permeability enhancements. Average gross thickness is about 300 ft. Recovery is mainly (80%) by the strong edge water influx and by expansion (20%). The objective of the History Match (HM) was to accurately determine the distribution of the reminder movable oil, in order to enable reliable performance predictions of existing and future wells. To meet this goal, the total amount of produced fluids on a well-by-well basis as well as the average local pressure must be matched within close limits. Conventional HM techniques failed due to the complex geology and production history. Especially the highly variable water cut could not be matched satisfyingly. For this reason, a new HM method and workflow, called Target Pressure and Phase Method (TPPM), was applied. TPPM ensures, that the calculated average reservoir pressure and the calculated amount of produced liquids match the corresponding measured values at every point in time. This is achieved by regulation of water influx from artificial boundaries and automatic distribution of the inflow along the well trajectories. Thus, the engineer can immediately concentrate on matching the well-by-well performance leading to a considerable reduction in project duration. Additionally, TPPM gave excellent results in HM. Thus reliable future field operation scenarios can be designed and calculated. The presented workflow and method is generally applicable, especially for reservoirs under strong water influx.

A Paleocene dolomite in northeastern Libya was modeled using three porosity types: matrix porosity (intercrystalline plus the separate vugs), horizontal-to-subhorizontal solution-enlarged vuggy porosity generated by dissolution and named "touching vugs," and fracture porosity. The touching vugs, which acted like fractures in their dynamic behavior, are modeled as a very permeable discrete fracture network (DFN) in PETREL* seismic-to-simulation software. Their presence is known primarily due to pressure buildup analysis, and it is expected that they would be interconnected over hundreds of meters. The primary challenge in dual-media modeling is being able to characterize and predict the dynamic behavior of the complex matrix + fracture + touching vug system. There are three wells in this area of northeastern Libya with pressure buildups that have an unusually distinct and pronounced dual-porosity signature. Each well has been matched by adjusting the five primary parameters: matrix and fracture porosity and permeability, and the sigma shape factor. Aquifer strength also had to be adjusted. There are some aspects of the dynamic behavior of this reservoir that are of particular interest: The highly fractured low-porosity parts of the reservoir are the least productive, and the least fractured high-porosity parts with touching vugs are the most productive. The well test shows pronounced dual-porosity behavior and indicates a high level of contrast between the matrix and secondary porosity systems, both in terms of permeability and porosity. There is a strong aquifer and in reservoirs with moderate fracture permeability, we would expect to see the fractures provide a pathway for rapid water breakthrough. Owing to the very high permeability associated with the fracture system, this does not happen as expected; i.e., the reservoir acts to some extent like a tank with a level oil/water contact (OWC). There is not much coning or advancing of water in the secondary porosity system. This paper presents the dynamic features of the reservoir and demonstrates how the simulation model was calibrated using all available information, in particular, the pressure buildups.

South East (S.E.) Gemsa is an oilfield located in Gulf of Suez (GOS) in Egypt. Many challenges have been faced in the reservoir and operation management of this field, such as: - Permeability contrast and water breakthrough in high permeability zones. - Non-uniform vertical water distribution. - Lack of water injection support across zones of low permeability. - Down hole scale build up. - Surface facility "bottlenecks". One of the most critical problems was non-uniform water injection breakthrough into well SE-10B, which is a key oil producer in this field. This paper describes the water diagnosis and well intervention procedure carried out on this well over a period of 2 years (2007/2009) and the results achieved. The main objectives of the conformance workover program were: - Reduce the water production. - Produce the non-contributing intervals. - Enhance the sweep efficiency by adding new intervals. SE-10B is a deviated well (41 degrees) equipped with dual completion string to allow non-commingled production from strata with differential depletion and permeability contrast across the reservoir layers. This well was producing with very high water cut (WC) 95% from both strings. The major operational concern was to diagnose the water source; hence it was decided to run the combined Production logging and Pulsed Neutron logging tools to achieve the main objective of Water Shut-off (WSO). The first logging run was in March 2007. The operator designed a workover program based on the interpretation results which showed the sources of main water contribution. Workover-2007 results tended to increase oil rate by 275% (200 bopd to 750 bopd) and WC dropped to 30% in the long string. The short string did not have any water conformance intervention during this workover; it was producing at 98% WC and was shut down. Another campaign was carried out in February 2009 for time lapse analysis and another conformance workover was implemented, which had impressive results. The short string has started producing 520 bopd with zero% WC versus mostly water before WSO. Long string has produced 1500 bopd and 25% WC versus 250 bopd and 65% WC before WSO. The workover achieved a major reduction in WC levels of both strings, and had a significant positive impact on the daily oil rate that increased considerably to more than 300% of the value before the workover. All the objectives defined were achieved. The outcome of the workover program was completely successful and exceeded operator expectations.

Belayim Land field is one of the oldest and largest oil fields in Egypt. It produces oil from many sandstone reservoirs. Oil is produced from 4-30 ohm-m resistivity in Belayim Formation, while to the contrary, in Rudeis Formation, 70–80 ohm-m resistivity is producing water. Rock characterization program was planned for Rudeis Formation using core material. It includes porosity, permeability, thin section description, SEM, wettability, relative permeability and capillary pressure by mercury injection to obtain pore throat size distribution. The wettability of the reservoir rock was determined by Amott method and proved to be strongly oil wet. The wettability controls the position of fluids within the pore network, where in oil-wet the water saturation distributed as poorly connected droplets within the macro-pores and filled the micro-pores. To simulate the saturation history of the reservoir, restored-state samples at irreducible water saturation were flooded with water to perform electrical resistivity measurements. Non-linear curves were obtained during the electrical resistivity measurements. Two saturation exponents (n) values were proposed to reflect the mechanism of forming continuous water film from the water droplets. The inflection point between the two (n) values was used to determine the resistivity cutoff below which water is produced. In addition, it represents the water saturation cutoff which was confirmed from the calculation of fractional flow of water from relative permeability measurements. The production data confirm the use of variable (n) to monitor the water saturation in oil-wet reservoirs.

Restoring the well's productivity from existing damaged or partially damaged formations has been the objective of many operators over the years. The damaged or partially damged formations requires to diagnose the causes of the damage in order to design the proper stimulation treatment to remove the damage and restore the well productivity. Drilling fluid, completion fluid and kill fluid have the potential to be the most damaging portion of reservoir life.