Les propriŽtŽs d'Žcoulement de plusieurs bruts asphaltŽniques ont ŽtŽ ŽtudiŽes ˆ la tempŽrature du rŽservoir d'origine dans des roches de morphologie et minŽralogie diffŽrentes.Les expŽriences rŽalisŽes mettent en Žvidence une rŽduction progressive de la permŽabilitŽ ˆ l'huile au cours de l'injection, plus ou moins rapide selon les cas. L'existence de dŽp™ts organiques a ŽtŽ vŽrifiŽe par des mesures de pyrolyse Ç Rock-Eval È effectuŽes sur des sections d'Žchan-tillons prŽlevŽes en fin d'Žcoulement ˆ diffŽrentes distances de la face d'entrŽe. Cette technique permet de quantifier le profil des dŽp™ts.L'interprŽtation des expŽriences de colmatage et leur simulation sont traitŽes en assimilant les asphalt•nes dans l'huile ˆ des particules collo•dales en suspension, susceptibles de se dŽposer ˆ la surface des pores et ainsi de rŽduire la permŽabilitŽ du milieu poreux. Les premi•res simulations ont ŽtŽ rŽalisŽes en utilisant le mod•le IFP d'endommagement particulaire Ç PARIS È, qui a ŽtŽ rŽcemment gŽnŽralisŽ au cas de dŽp™t en multicouches. On observe un accord qualitatif satisfaisant avec les rŽsultats expŽrimentaux. PERMEABILITY DAMAGE DUE TO ASPHALTENE DEPOSITION: EXPERIMENTAL AND MODELING ASPECTSThe flow properties of several asphaltenic crudes were studied at reservoir temperature in rocks of different morphology and mineralogy.The experiments performed showed a progressive reduction in permeability to oil during injection, varying in rate according to the system considered.The existence of organic deposits was verified by ÒRock-EvalÓ pyrolysis measurements made on sections of samples taken at the end of flow at different distances from the entry face. This technique enables the profile of the deposits to be quantified.The interpretation of the permeability damage experiments and their simulation are treated by comparing the asphaltenes in oil to colloidal particles in suspension, capable of being deposited at the surface of the pores and thus reducing the permeability of the porous medium. The first simulations were carried out using the ÒPARISÓ IFP particle damage model, which has recently been Se ha procedido al estudio de las propiedades de circulaci-n de varios crudos asfaltŽnicos a la temperatura del yacimiento de origen en rocas de morfolog'a y mineralog'a de distinta 'ndole.Las experimentaciones llevadas a cabo hacen resaltar una reducci-n progresiva de la permeabilidad al petr-leo durante el transcurso de la inyecci-n, m ‡s o menos r ‡pida segoen los casos.La existencia de sedimentos org ‡nicos se ha verificado mediante mediciones de pir-lisis "Rock-Eval" efectuadas mediante secciones de muestras extra'das al final de la circulaci-n fluida y a distintas distancias de la cara de entrada. Esta tŽcnica permite cuantificar el perfil de las sedimentaciones La interpretaci-n de las experimentaciones de entarquinamiento (obstrucciones) y su simulaci-n se tratan asimilando los asfaltenos en el petr-leo a part'culas coloidales en suspensi-n, susceptibles de depositarse en la superficie de los poros y, por ende, r...

Laboratory studies have been conducted to determine the influence of the composition of gas and oil phases on the parameters involved in the description of two-phase flow in porous media when the compositions of the phases vary over a wide range. Relative permeabilities to gas and oil were determined under high pressure and temperature for binary systems (methane/n-heptane, methane/n-decane, etc.), leading to very wide variations of the interfacial tensions values. Investigations were focused specifically on mixtures involving low interfacial tensions, down to 0.001 mN/m. This study has shown that residual oil saturations and relative permeabilities determined from the displacement tests with a filtration velocity of about 20 cm/hr are affected strongly by interfacial tension, especially when it is lower than 10-2 mN/m. Introduction This study deals with the influence of the compositions of the liquid and vapor phases in equilibrium on displacements of oil by gas in porous media. One of the goals of high-pressure or enriched-gas injection is to obtain low interfacial tensions between the in-place oil and injected gas. During the displacement of gas in oil-bearing formations, multiple exchanges may take place between the liquid and vapor phases so that complete miscibility may be achieved. This phenomenon generally is called thermodynamic miscibility. During this process the interfacial tension is reduced progressively to zero. The resulting reduction in capillary forces makes it possible to decrease the residual oil saturation considerably. The same goal also is sought by other enhanced recovery techniques not examined here i.e., surfactant flooding or microemulsion flooding. The purpose of this study is to examine the influence of the thermodynamic conditions on the relative permeabilities in displacements of a liquid phase by a vapor phase when both phases are at equilibrium. The Problem The general equations describing the flows of two phases are the relative permeability equations. They show, for each phase, that the flow rate in a porous medium is a function of the absolute permeability, relative permeability to the fluid involved, fluid viscosity, pressure gradient in this phase, and gravity. In fact, relative permeabilities depend on a greater number of parameters.1 Some of them are the ratio of viscosities, µ2/µ1; the ratio of gravity to capillary forces (Bond number), (?2-?1)gk]/s; the ratio of the inertia forces to the viscosity forces (Reynolds number), (?1·u·k)/µ1; the ratio of the viscosity forces to the capillary forces (capillary number), (µ1·u)/s; and wettability. When they exist, exchanges between the phases can modify the physical and chemical properties of the fluids, especially at the interfaces. Under such conditions the influence of the capillary number (µ1·u)/s is by no means negligible, with the decrease in interfacial tension causing an increase in oil recovery.2 It may be thought that relative permeability to oil is closely dependent on this capillary number,3 especially when the value of s is small, and that this influence is principally apparent with low oil-saturation levels.

Inst. Fran9ais du Petrole; M.J. Argaud, SPE, Elf Aquitaine; and J.-P. Feraud, Total-CFP Summary.Laboratory equipment aimed at determining the exact correlation between resistivity and water saturation under stress, pressure, and temperature conditions is described in the first part of this paper. The porous-plate method adapted to reservoir conditions is used to obtain different saturation values during both drainage and imbibition. With this equipment, the influence of the effective stress on the porosity and formation resistivity factor can be studied before the test. In the second part of this paper, the values of the formation resistivity factor and resistivity index are compared for water-wet samples from sandstone and carbonate reservoirs. These measurements indicate that the influence of the effective stress depends on the nature of the rock sample. In addition, the resistivity/water-saturation law depends on the direction of the saturation change (drainage or imbibition) and on the nature of the fluids (water/oil or water/gas).

Summary Prediction of formation damage that occurs in horizontal wells, often openhole completed, is a critical point for optimizing an oilfield development. The economic impact of near-wellbore induced drilling damage and cleanup efficiency has led to significant progress in both experimental and numerical studies designed to assess the wellbore flow properties during oil production. In a previous paper, a methodology combining both experimental and numerical approaches was presented to evaluate the natural cleanup of horizontal wells drilled with an oil-based mud (OBM). This paper presents an extension of the methodology for simulating both (a) near-wellbore invasion and permeability damage generated with a water-based mud (WBM), and (b) natural cleanup during oil backflow when the well is put into production. There is a fundamental difference between WBM and OBM invasions. In an oil-bearing formation, the displacement of the oil in place with an OBM filtrate is a miscible displacement process, while the displacement with a WBM filtrate is a two-phase flow process (imbibition), generating high wetting-phase saturation in the invaded zone. Then, during oil backflow, a portion of the wetting phase is trapped, leading to residual wetting-phase saturation greater than the initial one. Even in the absence of chemical interaction between filtrate and fluids in place, this induces an adverse water/oil relative permeability effect, which is an additional permeability impairment. This paper describes a numerical approach to model the formation damage with WBM and to predict well performance for natural cleanup when the well is subject to a pressure drawdown. The kinetics of fluid filtrate invasion, the filter-cake properties, and the filtrate/oil relative permeability curves in imbibition and drainage, together with damaged and return permeabilities, are obtained from specific drilling fluid damage laboratory tests. Using these data, the fluid filtrate invasion during the drilling phase is simulated, leading to a cone-type invasion depth along the horizontal well. This approach has allowed us to study the impact of various parameters related to fluids or cake properties, drilling conditions, and natural cleanup processes on the well performance. Introduction It is well recognized that near-wellbore flow properties are altered by drilling-fluid and fluid-filtrate invasion during overbalanced drilling operations. The degree of alteration, generally called "formation damage," depends upon a large number of parameters, such as nature and characteristics of the drilling fluid, formation properties, and operating conditions (shear rate in the drilling fluid, overbalance pressure, temperature, etc.). Formation damage caused by drilling-fluid invasion may create substantial reductions in oil and gas productivity in many reservoirs.1,2 Productivity losses are especially critical for long horizontal wells which are often "openhole" completed.3 In such a case, the near-wellbore damage is not bypassed by perforations and may lead to very large skin values. Therefore, prevention of formation damage generated by a drilling fluid may not always be possible because, first, the drilling time of the horizontal segment in the producing zone is usually many times greater than in a typical vertical well, leading to a much deeper filtrate invasion; and second, the very low drawdown pressure that is needed to produce from a typical horizontal well reduces the viscous forces available to cleanup near-wellbore damage. Generally, the data obtained from production logging of many horizontal wells show severe damage across a large portion of the horizontal wellbore.4 In such a case, the numerical modeling of the full process of fluid invasion and oil backflow may give a better prediction of formation damage and an evaluation of the well performance during production. In a previous paper,5 a simplified numerical approach for modeling the natural cleanup process has been presented in the case of a horizontal well drilled with an OBM. In this paper, this modeling is extended to wells drilled with a WBM and also includes the simulation of filtrate invasion. In the case of a WBM, the two main damaging mechanisms are caused by both particulate invasion during the initial spurt loss period, and by filtrate invasion through filter cakes. Even in the absence of physicochemical interaction between filtrate and formation fluids (compatible rock/fluids systems), there is a fundamental difference between OBM and WBM displacement processes. In an oil-bearing formation, the displacement of oil-in-place with a WBM filtrate is an imbibition process that generates high wetting-phase saturation in the invaded zone, while the OBM filtrate is almost a miscible displacement process. In addition, WBM filtrate is mainly composed of polymer molecules that can deeply invade the reservoir6,7 even if the larger molecular weight species are retained in the filter cake.7 Depending on their molecular weight and filtration conditions, the polymer chains can be stretched by the flow, go through the filter cake, adsorb within the porous media, and even plug rock pores. Polymer chains associated with water increase the capillary retention of water, leading to residual wetting-phase saturation after oil backflow, higher than the initial ones. This induces an additional damaging effect (water blocking) caused by drastic reduction of oil relative permeability.8 Generally, for rating the performance of various drill-in fluid formulations, the permeability damage is quantified through oil return permeability measurements and flow-initiation pressures (FIP), performed at relevant flow rates on core samples damaged during dynamic fluid filtration tests.9–14 But only a few attempts were made to transfer these laboratory data into a near-wellbore model to evaluate the impact of the permeability damage on the well performance. Lane15 and Semmelbeck et al.16 simulated filtrate invasion for improving log interpretation, but their impact on well performance was not investigated. Other researchers17–19 have studied well performance using representative formation damage with nonuniform skin along the well, but laboratory tests were not integrated in their study. In our work, the full process of near-wellbore damage followed by natural cleanup is modeled. The WBM filtrate invasion is simulated using standard waterflooding concepts. This led to a cone-type invasion depth along the horizontal well. Filtrate/oil relative permeability curves (imbibition curves for invasion and drainage curves for backflow) are used as input parameters. In addition, filter-cake properties (thickness and permeability) and final oil permeabilities, obtained from specific laboratory measurements, are used to model the cleanup process.

Cyclic CO 2 huff 'n' puff process in diverse reservoir conditions, such as immiscible, near-miscible, and miscible, has been tested in the laboratory and applied in the fields as a viable secondary or tertiary means to recover the residual oil in water flooded reservoirs or pressure depleted reservoirs. Recently, petroleum operators have shown increasingly interest in taking CO 2 huff 'n' puff process as a preferred option to extract light oil in low-pressure and low-permeability reservoirs.In this paper, experimental results from a series of coreflood tests are presented and operation strategies for cyclic CO 2 injection are optimized to maximize the light oil recovery factor in a low-permeability reservoir with low original reservoir pressure and while, minimize CO 2 utilization. 6 cyclic coreflood tests, 20 cycles in total, are conducted in a 973 mm-long composite core with an average porosity of 9.6% and an average permeability of 2.3mD. The reservoir pressure is 12.9MPa, far below the measured MMP value of 23MPa, which indicates that the reservoir has no sufficient energy support to do primary production. The impacts of primary operational parameters, such as slug size, injection pressure, chasing gas (N 2 ) and CO 2 injection rate on the performance have been investigated.It is concluded that, on the basis of experimental data, 0.1PV seems to be an optimal slug size for the first cycle, with a cycle recovery factor as high as 14.52% when reservoir pressure depleted to 8MPa. The recovery factor is suggested to be sensitive to the maximum pressure and the maximum pressure should be built up to as high as formation permits. In the following cycles, injecting N 2 as chasing gas after CO 2 injection seems to improve the cycle performance significantly and concurrently reduce the CO 2 utilization. The optimal operation should have three cycles and the ultimate recovery factor for these three cycles could reach above 30%. The findings of this paper extend the understanding of cyclic CO 2 operation and may be employed as technique reference for cyclic CO 2 process operations in low-pressure and low-permeability closed boundary reservoirs.

This paper was prepared for presentation at the 1999 SPE European Formation Damage Conference held in The Hague, The Netherlands, 31 May–1 June 1999.

Summary We investigate the invasion of solids and their mobility during cleanup. We study the effect of weighting agent particle size on rock substrates of varying permeabilities. We find permeability damage increases but flow initiation pressures decrease with increasing substrate permeability. We obtain quantitative profiles of solids invasion by scanning electron microscopy/x-ray mapping and synchrotron energy-dispersive x-ray diffraction tomography. We compare these profiles to core sectioning data. We find invasion profiles drop steeply but fines are observed deep within the core. We examine the effect of backflooding on the invasion profile. Near-surface damage is reduced but deeply invaded fines are unaffected by backflow. We develop a deep bed filtration model for solids invasion and consequent permeability reduction. This model is compared to the profiles obtained in the invasion experiments. We find that we can fit the experimental invasion profile for monomodal particles using a single trapping coefficient. Backflow is modeled by reversing the flow rate. We postulate a phenomenological rate of erosion to untrap particles in line with experimental observations (30%). When erosion is included in the model, a peak in the backflow pressure is found. This peak may be correlated with the experimentally observed flow initiation pressure. Introduction Well productivity is critically important if oil and gas reserves are to be developed economically. With the change in economic climate and the maturation of many existing fields has come an emphasis on reduced production costs and optimized productivity. The trend towards openhole completions places additional emphasis on damage avoidance. Near-wellbore permeability impairment from drilling and completion fluids can have a substantial, yet potentially avoidable, impact on well productivity. The proper design and engineering of fluid systems to minimize productivity impairment is therefore important. The fundamental mechanisms involved in formation damage by drilling fluids and its remediation have been investigated as part of a research collaboration between Schlumberger Cambridge Research and the Institut Franc¸ais du Pe´trole and Statoil under the auspices of the EC-Joule Programme.1 In this paper we report studies of particulate invasion and its impact on production. Particulate invasion is one of the primary causes of formation damage from drilling fluids. During the initial stages of filter cake growth particles are forced into the formation, building an internal filtercake which plugs the near surface pores. Removal of this internal cake can be difficult, and can lead to reduced permeability. The importance of minimizing internal filter cake is widely recognized. Most attention has focused on the selection of an appropriately sized weighting agent to bridge across surface pores, thereby minimizing spurt loss.2 Alternative bridging approaches such as the use of structured fluids3 (for example, mixed metal hydroxide-bentonite systems) have also been explored. Despite these efforts, the minimum spurt is not zero and some internal cake does form. This invaded material can be quite tenacious. Francis4 reported significant damage from shallow invasion even after removal of external filter cake. Better understanding of the properties of both the internal and external cake is needed for improvements in drill-in fluids. Visualization has been seen as an important step in understanding the mechanisms of permeability impairment determined through core flood testing.5 However as van der Zwaag observed,6 quantitative analysis of invasion is a much more powerful tool for assessing formation damage, giving information which can ultimately be used to develop predictive models. A number of different approaches have been pursued,5–8 ranging from electron microscopy and x-ray analysis, to chromatic tomography (CT) scanning and nuclear magnetic resonance (NMR) imaging. All have their advantages and disadvantages; some are destructive, while nondestructive techniques often cannot resolve features at the individual pore level. Here we report studies of particle invasion using two techniques: scanning electron microscopy energy-dispersive spectroscopy (SEM-EDS) x-ray mapping, and energy-dispersive x-ray diffraction tomography using a synchrotron source (synchrotron EDD-T). In this paper we report experimental studies on invasion and bridging with particulate weighted fluids and the effect on permeability damage. We locate and profile the damaged zone using different analytical techniques and quantify the effect of cleanup by backflow. Finally we describe a deep bed filtration model of solids invasion and consequent permeability reduction. This model is compared to the invasion experiments. Experimental Methods Formation Damage Measurements. Formation damage measurements were made with three different test configurations. Detailed descriptions can be found in Refs. 1, 3 and 8. Each permitted the in-situ determination of the core permeability before and after exposure to drilling fluids. Two are based on API high pressure-high temperature (HPHT) filtration cells modified to take core samples,3L×d is either 8×38 or 32×25.4 mm with a flat-blade impeller to provide shear for dynamic filtration conditions. The third8 uses long cores of L×d of 190×40 mm. Pressure taps along the core holder at ?5 cm intervals allow direct spatial resolution of the permeability impairment during and after filtration. Before use, cores were vacuum saturated with brine simulating connate water from the Heidrun reservoir. Permeability to brine was measured at a minimum of three flow rates. Unless stated, filtration was conducted for invasion of 1 pore volume under 20 bar differential pressure (in the opposite direction to the permeability determination) and at ambient temperature (23°C). After filtration, permeability to brine was again measured to give the percent of retained permeability. As backflow is imposed, a peak in the pressure is observed. This is defined as the flow-initiation pressure (FIP).9 The accuracy of measurements on short and long cores (32×25.4 and 190×40 mm) was ?1% and reproducibility 5%. Tests with the thin rock slices were less accurate; 10 to 20%. Rock substrates with different permeabilities were used. The majority were sandstones with minimal clay content. Our primary substrate was Clashach sandstone. A polymer-based fluid was used; its formulation is given in Table 1, with different grades of barite and carbonate weighting agents, and particle size data given in Table 2. SEM-EDS Mapping. We used a Philips XL30 SEM equipped with a motorized sample stage and a Noran Voyager energy-dispersive spectrometer. The external filter cake was removed and cores were carefully fractured before air drying for analysis.

This paper was prepared for presentation at the 1999 SPE European Formation Damage Conference held in The Hague, The Netherlands, 31 May–1 June 1999.