Formation Damage Coefficients Research Articles

Experimental investigation on coal fines migration through proppant packs: Assessing variation of formation damage and filtration coefficients

Coalbed methane reservoirs generate coal fines during production that cause irreversible damage to cleat conductivity. In severe scenarios, this can result in temporary closure of recovery operations from the gas well(s). In this work, we simulate the impact of coal fines on proppant conductivity. Four sets of experiments were conducted: effect of salinity – 0 to 3.5 NaCl wt.%, pH – 2 to 11, coal rank - anthracite, high volatile bituminous, and sub-bituminous; and 0.01 wt% additives – Sodium Dodecyl Benzene Sulfonate (SDBS) and Cetrimonium bromide (CTAB) and validated with established analytical models. Moreover, medical computed tomography of three extreme cases was conducted. Results showed that coal fines uniform distribution within a proppant pack does not cause greater conductivity decline than non-uniform distribution owing to clogging and straining. Additionally, results showed that anionic surfactants successfully dispersed coal fines. These research results can be applied to coalbed methane reservoirs, especially during the early water drainage phase, to optimise the impact of coal fines on proppant conductivity.

Permeability Decline in Fractured Porous Media During Mineral Scaling: A Detailed Modeling Study

Brine injection into underground reservoirs is performed commonly in oil, natural gas, and geothermal industries. The injected fluid may contain some reactive ions that can cause mineral scaling. In addition, a porous medium may be naturally fractured or it can be fractured through hydraulic fracking. The existence of a fracture in a porous medium can facilitate the transport of reactive ions, which leads to a change in the deposition pattern and affects the permeability decline. This study presents a numerical method for modeling mineral precipitation–deposition in the fractured porous media. This study contributes to the analysis of the impact of fracture on permeability and porosity variations in porous media caused by mineral scaling. The results of the modeling indicate that deep invasion of reactive ions through fractures leads to steeper permeability reduction. This study showed that, with constant fracture length, a single fracture pattern experiences the highest permeability reduction compared to other patterns such as an internal fracture, a deviated fracture, a looped fracture, and multiple fractures. In addition, the relationship between fracture length and modeling parameters was investigated through inverse modeling. This showed that fracture length has a linear relationship with the formation damage coefficient, but it has an exponential correlation with the reaction kinetics coefficient.

A novel approach for modeling permeability decline due to mineral scaling: Coupling geochemistry and deep bed filtration theory

Mixing incompatible brines is one of the leading causes of mineral precipitation in porous media. Deposition of the precipitated minerals in pore spaces leads to the porosity and permeability reduction. This study, in the first step, proposes a novel coupled approach for modeling mineral precipitation and deposition in porous media based on geochemistry and deep bed filtration theory. In the proposed approach, minerals precipitate as suspended particles modeled by PHREEQC geochemical package, and deposition of the precipitated minerals is modeled through the deep bed filtration theory. During the second step, results of the proposed approach are verified using the reported experimental data, which show the proposed approach is applicable and accurate with a high degree of confidence. In the third step, the impact of mineral scaling on deposition pattern and permeability decline is studied with respect to the porosity heterogeneity, the existence of fracture, and heterogeneity in the matching parameters of the model. The results of this study show that the porosity heterogeneity influences not only the deposition pattern of the precipitated minerals but also the amount of permeability decline. This paper demonstrates that deep invasion of the precipitated minerals through the porosity heterogeneity and fracture intensifies the permeability decline. It is also observed that heterogeneities in the modeling parameters (formation damage and filtration coefficients) do not affect the permeability decline of the porous media.

Uncertainties associated with laboratory-based predictions of well index and formation damage

The filtration and the formation damage coefficients are the parameters in the mathematical models determining the degree of permeability decline during flow of colloidal suspensions in porous media. Measuring pressure in 3 points along the core allows simultaneous calculation of the filtration and the formation damage coefficients. We have calculated the combined standard uncertainties of the filtration and the formation damage coefficients. Application of the law of propagation of uncertainty to Darcy’s equation and the weighted least squares method to impedance index curves for the half- and the overall core resulted in the values of their slopes and intercepts, and the respective combined standard uncertainties. Combination of the values of these slopes into a transcendental equation and solving it analytically fully determined the filtration and formation damage coefficients with their relative combined standard uncertainties being significantly lower than those reported in the literature.

A coupled geochemical and fluid flow model to simulate permeability decline resulting from scale formation in porous media

Scale precipitation due to the mixing of incompatible injected water with formation brine and its subsequent deposition in porous media is an unpleasant phenomenon in water injection projects that can lead to severe injectivity and productivity decline. As a result of the complexity of geochemical reactions, modelling scale precipitation and deposition is a challenge. This paper presents a coupled geochemical and fluid flow model to simulate reactive flow in porous media which models pressure difference increase resulting from scale formation during water injection into porous media. To simulate chemical reactions during scale formation and subsequent rock permeability decline, PHREEQC software was coupled with a fluid transport model. The pressure difference and outlet ion concentration from three laboratory data were successfully matched. The coupled model that is proposed considers injected and formation water compositions and their associated chemical reactions. The formation damage coefficient is the single optimisation parameter of the proposed model. With matching parameters from experimental data, the proposed model can be used for predicting well injectivity decline and sensitivity analysis.

Produced Water Re-Injection and Disposal in Low Permeable Reservoirs

Produced water re-injection (PWRI) is an important economic and environmental-friendly option to convert waste to value with waterflooding operations. However, it often causes rapid injectivity decline. In the present study, a coreflood test on a low permeable core sample is carried out to investigate the injectivity decline behavior. An analytical model for well impedance (normalized reciprocal of injectivity) growth, along with probabilistic histograms of injectivity damage parameters, is applied to well injectivity decline prediction during produced water disposal in a thick low permeable formation (Völkersen field). An impedance curve with an unusual convex form is observed in both coreflood test and well behavior modeling; the impedance growth rate is lower during external filter cake build-up if compared with the deep bed filtration stage. Low reservoir rock permeability and, consequently, high values of filtration and formation damage coefficients lead to fast impedance growth during deep bed filtration; while external filter cake formation results in relatively slow impedance growth. A risk analysis employing probabilistic histograms of injectivity damage parameters is used to well behavior prediction under high uncertainty conditions.

Permeability Reduction of Berea Cores Owing to Nanoparticle Adsorption onto the Pore Surface: Mechanistic Modeling and Experimental Work

This paper examines an integrated approach to study the permeability alteration resulting from nanofluid flow through porous media. Hydrophilic nanostructure particles (NSPs) are dispersed in the brine stream at 0.05, 0.2, and 0.5 wt % concentrations and injected into several oil-wet Berea sandstones. The pressure drops across the cores and the effluent nanoparticle concentrations are monitored. To quantify the nanoparticle adsorption/detachment and straining behavior and associated effects on formation permeability, analytical mechanistic models are derived using the method of characteristics. The interplay between nanoparticles and rocks is described by the classical particle filtration theory coupled with the maximum adsorption concentration model. All of the necessary parameters, e.g., the maximum adsorption concentrations, reversible or detachment adsorption concentrations, nanoparticle adsorption and straining rates, and corresponding formation damage coefficients, are characterized. The experimenta...

Characterisation of formation damage during reactive flows in porous media

Precipitation of solids due to chemical reactions or thermodynamic non-equilibrium is a common cause of formation damage in oil and gas wells. The traditional mathematical model for reactive flow in porous media contains two empirical parameters: the kinetics rate coefficient, which along with the reagent's concentrations determines the reaction rate; and the formation damage coefficient, which reflects the permeability reduction due to solid phase precipitation. These parameters are determined from laboratory coreflooding tests, which involve commingled injection of reacting fluids. A routine laboratory method determines the kinetics rate coefficient from expensive and cumbersome reagent concentration measurements at the core outlet, after which the formation damage coefficient can be calculated using inexpensive and robust pressure drop measurements. The current paper developed a laboratory method for determining both coefficients from pressure measurements only. The method utilised pressure measurements at the core inlet, outlet and some intermediate core port during commingled quasi-steady-state flow of incompatible fluids. The above data treatment was based on the analytical model for one-dimensional commingled flow of reacting fluids. The formulae for determining the model coefficients from pressure measurements have been derived. The intervals for inverse solution existence, uniqueness, and stability were established. The proposed method was validated by high agreement between the model constants determined by the customary method and the three-point-pressure method.

Fines Migration in Fractured Wells: Integrating Modeling With Field and Laboratory Data

Summary Production and drawdown data from 10 subsea deepwater fractured wells have been modeled with an analytical model for unsteady-state flow with fines migration. The simulation results and the field data indicated a good match, within 5%. A sensitivity study conducted on initial concentration of fines, flow rate, maximum fines-mobilization velocity, fines distribution, formation damage, and filtration coefficients confirmed that the model-matching parameters are within values reported commonly in the literature. This paper describes the methodology used to integrate the modeling predictions with field and laboratory data to identify probable causes for increasing skins and declining productivity-index values observed in some of the wells under investigation. It discusses the results of an experiment designed to simultaneously assess the effects of pressure depletion and compaction on fines production and permeability with a triaxial-stress apparatus. This is, to the best of our knowledge, the first time an experiment of this nature is reported in the literature. The good match between the modeling and the field data, further validated with laboratory experiments, allows for discussion of long-term predictions on well productivity impacting current reservoir-management strategies and field-development plans.

Investigation of the Precipitation of Calcium Sulfate in Porous Media: Experimental and Mathematical Modeling

Water injection is used worldwide as an improved oil recovery (IOR) method upstream in the petroleum industry to sweep oil toward production wells or to maintain the appropriate pressure in reservoirs. During the injection of water, differences in the properties of the injection water and the formation water can adversely affect the IOR operations. Such incompatibility leads to supersaturating the water with minerals salts that subsequently precipitate and impair the porous medium. Experiments were performed with three different injection rates to study the effect of the flow rate of the injected brine on damage to the porous medium. In addition, a kinetic mass-transfer model was developed for the transient sweep of the formation water by the injection water within the porous medium. Then, formation damage due to the reduced permeability of the medium was observed and modeled based on the dynamic behavior of scale formation in the cores. The effluent concentrations of magnesium (Mg2+) and calcium (Ca2+) ions were used to obtain the dispersion coefficients and the reaction rate constants for the precipitation of calcium sulfate in the sandstone cores. The formation damage coefficient for each run was calculated by the regression of the experimental and calculated permeability reduction ratios so that the average deviations for this step were less than 3.9%.

Experimental study of colloidal flow in porous media at high velocities

ABSTRACTLatex colloidal particle deposition onto an engineered porous medium has been studied at high suspension velocities at conditions favorable for particle attachment. Low value of ratio between particle diameter and mean pore size ensured the absence of particle straining due to size exclusion. Particle deposition is accompanied by the formation and destruction of bridges at high flow velocities accompanied by a sudden increase in hydraulic resistance. Treatment of experimental permeability data with the Forchheimer equation shows that the formation damage coefficient is a function of the critical retained concentration and inverse function of fluid velocity. The inertia coefficient shows similar behavior at low velocities, although it remained almost constant at low surface coverage. Particle deposition at lower fluid velocities is accompanied by a significant increase of inertia coefficient and formation damage. This is explained by a partial formation of the external cake on the inlet surface of the filter. Deep bed filtration continues even at high surface coverage and is characterized by a high filtration coefficient at lower velocities. © 2013 Curtin University of Technology and John Wiley & Sons, Ltd.

Formation-Damage Evaluation From Nonlinear Skin Growth During Coreflooding

Summary Injectivity decline of oilfield injection wells is a widespread phenomenon during seawater/produced-water injection. The decline may result in significant cost increase of the waterflooding project. Reliable modeling-based prediction of injectivity-index decrease is important for waterflood design as well as for the planning of preventive injected-water treatment. One of the reasons for well injectivity decline is permeability decrease caused by rock plugging by solid/liquid particles suspended in the injected water. The mathematical model for deep-bed filtration contains two empirical functions: the filtration coefficient and the formation-damage coefficient. These empirical coefficients must be determined from laboratory coreflood tests by forcing water with particles to flow through the core samples. A routine laboratory method determines the filtration coefficient from expensive and difficult particle-concentration measurements at the core effluent; then, the formation-damage coefficient is determined from inexpensive and simple pressure-drop measurements. An alternative three-point-pressure method uses pressure data at an intermediate point of the core, supplementing pressure measurements at the core inlet and outlet. The method provides unique and stable values for constant-filtration and formation-damage coefficients. In the current work, we consider a more complex case in which both coefficients are linear functions of retained-particle concentration. In this case, the model is fully determined by four constants. The three-point-pressure method furnishes unique values for the four model parameters. A new semianalytical model for axisymmetric suspension filtration was developed to predict well-injectivity decline from the linear coreflood data with pressure measurements in three core points.

Well Injectivity Decline for Nonlinear Filtration of Injected Suspension: Semi-Analytical Model

Injectivity decline due to injection of water with particles is a widespread phenomenon in waterflood projects. It happens due to particle capture by rocks and consequent permeability decline and also due to external cake formation on the sandface. Since offshore production environments become ever more complex, particularly in deep water fields, the risk associated with injectivity impairment due to injection of seawater or re-injection of produced water may increase to the point that production by conventional waterflood may cease to be viable. Therefore, it is becoming increasingly important to predict injectivity evolution under such circumstances. The work develops a semi-analytical model for injectivity impairment during a suspension injection for the case of filtration and formation damage coefficients being linear functions of retained particle concentration. The model exhibits limited retained particle accumulation, while the traditional model with a constant filtration coefficient predicts unlimited growth of retained particle concentration. The developed model also predicts the well index stabilization after the decline period.

Modified Particle Detachment Model for Colloidal Transport in Porous Media

Particle detachment from the rock during suspension transport in porous media was widely observed in laboratory corefloods and for flows in natural reservoirs. A new mathematical model for detachment of particles is based on mechanical equilibrium of a particle positioned on the internal cake or matrix surface in the pore space. The torque balance of drag, electrostatic, lifting and gravity forces, acting on the particle from the matrix and the moving fluid, is considered. The torque balance determines maximum retention concentration during the particle capture. The particle torque equilibrium is determined by the dimensionless ratio between the drag and normal forces acting on the particle. The maximum retention function of the dimensionless ratio (dislodging number) closes system of governing equations for colloid transport with particle release. One-dimensional problem of coreflooding by suspension accounting for limited particle retention, controlled by the torque sum, allows for exact solution under the assumptions of constant filtration coefficient and porosity. The explicit formulae permit the calculation of the model parameters (maximum retention concentration, filtration and formation damage coefficients) from the history of the pressure drop across the core during suspension injection. The values for maximum retention concentration, as obtained from two coreflood tests, have been matched with those calculated by the torque balance on the micro scale.

Well-data-based prediction of productivity decline due to sulphate scaling

Sulphate scaling can have a disastrous impact on oil production in waterflood projects with incompatible injected and formation waters. This is due to precipitation of barium/strontium sulphate from the mixture of both waters and the consequent permeability reduction resulting in loss of well productivity. The system where sulphate scaling damage occurs is determined by two governing parameters: the kinetics coefficient characterising the velocity of chemical reaction and the formation damage coefficient reflecting permeability decrease due to salt precipitation. Previous work has derived an analytical model-based method for determination of two coefficients from laboratory corefloods during quasi-steady state commingled flow of injected and formation waters. The current study extends the method for determination of kinetics and formation damage coefficients from production well data consisting of barium concentrations in the produced water and of well productivity decline. We analyse production data for five wells from giant offshore field A, submitted to seawater flooding (Campos Basin, Brazil), and obtain values of the two sulphate scaling damage parameters. The two coefficient values were used for prediction of productivity decline for these wells. The values of kinetics and formation damage coefficients as obtained from either laboratory or field data vary in the same range intervals. These results validate the proposed mathematical model for sulphate scaling damage and the analytical model-based method “from lab and wells to wells”.

Characterize Scaling Damage From Pressure Measurements

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 112500, "A New Method To Characterize Scaling Damage From Pressure Measurements," by T. Carageorgos, M. Marotti, and P. Bredrikovetsky, SPE, North Fluminense State University, prepared for the 2008 SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, 13-15 February. The paper has not been peer reviewed. Productivity-decline prediction is based on mathematical modeling with well-known model coefficients. The sulfate-scaling system contains two governing parameters: the kinetics coefficient, λ, characterizing the velocity of chemical reaction, and the formation damage coefficient, β, showing how the permeability decreases because of salt precipitation. This paper extends previous works with commingled injection of two incompatible waters into the same core with two different ratios of formation water (FW) to seawater (SW). Introduction Barium- and strontium-sulfate scaling is a major problem in waterflood projects with incompatible formation and injected waters. Barium sulfate and resulting scale causes formation damage near the production-well zone. This phenomenon is attributed to precipitation of barium and strontium sulfates from the mixture of both waters and the consequent permeability reduction resulting in loss of well productivity. The chemical incompatibility between the injected SW, which is high in sulfate ions, and the FW, which originally contains high concentrations of barium, calcium, and/or strontium ions, may reduce well productivity, making the waterflood project uneconomical. A reliable model that is capable of predicting such scaling problems would help in planning a waterflood project. It also could aid in selecting an effective scale-prevention technique by predicting scaling tendency, type, and potential severity. A reliable predictive model must use well-known values of the model coefficients. The mathematical model for sulfate scaling contains two phenomenological parameters: λ from the active-mass law of chemical reaction showing how fast the reaction and precipitation occurs, and β reflecting the permeability decrease caused by sulfate-salt deposit. Both coefficients depend on rock-surface mineralogy, pore-space structure, temperature, and brine ionic strength. Therefore, they cannot be calculated theoretically for natural reservoirs and must be deter-mined from laboratory corefloods. Reagent- and deposition-concentration profiles during reactive flows are nonuniform, so the sulfate-damage parameters cannot be calculated directly from laboratory measurements. They must be determined from laboratory coreflood data by use of inverse-problem solutions. The λ can be calculated from break-through concentration in a quasisteady-state coreflood with commingled injection of FW and SW. Then β can be determined from the pressure-drop increase during flooding.

Laboratory and well-history based predictions of productivity decline due to oilfield scaling—analytical modelling and field study

Sulphate scaling may develop during offshore waterflood projects where mixing of injected and formation waters causes salt precipitation. Salt deposition results in permeability decline and, consequently, in impairment of well productivity. The problem has been widely presented in the literature for the North Sea, Campos Basin and the Gulf of Mexico. Recently several oil companies have reported several field cases of oilfield scaling in Australia. In this paper, methods are summarised for forecasting productivity decline from the history of well productivity index decline, produced water composition, and also from laboratory corefloods. The methods account for chemical reactions based on exact analytical solutions of inverse and forward modelling of quasi steady state oil-water flow towards producing wells. The main result obtained from the analytical model is a measure of the decline in productivity index with time for either linear flow in the case of a coreflood or the radial flow towards well. The analytical model has been used to predict further productivity decline in scaled-up producers of the deepwater offshore field X (Campos Basin, Brazil). Laboratory corefloods were carried out for field X cores and waters, and the model coefficients were determined. The productivity losses due to barium sulphate scaling have been noticed during several years of seawater flooding. The values obtained for reaction kinetics and formation damage coefficients are similar to those obtained from corefloods.

Coupled Numerical Modelling of Reservoir Flow with Formation Plugging

Abstract Permeability decline occurs during injection of produced water and seawater, resulting in injectivity declines and significant cost increases in waterflooding projects. It is necessary to have a reliable model to predict injectivity decline for preventive water treatment and waterflood design purposes. A classical deep bed filtration (DBF) model has been widely used to predict the injectivity decline. According to this model, the injectivity decline can be characterized by two empirical parameters: filtration coefficient, λ, and formation damage coefficient, β. Different methodologies developed to extract these parameters involve expensive and difficult concentration measurements, laboratory-scaled pressure drop measurements (not truly representative of the real reservoir) and simplifying assumptions of analytical solutions. A simple empirical velocity-based damage model proposed by Bachman et al.(1) is adopted in this work, and extended to multidimensional flow. This model is then compared to the deep bed filtration-based model. The advantage of the empirical model is that it can be easily tuned to either field or laboratory data, and can be easily implemented in reservoir simulators. The paper presents the formulation and numerical implementation of the two coupled reservoir flow and damage models. Different methods of implementing the velocity-based model in multidimensional flow are presented and evaluated. The comparison with the DBF model shows that the two models yield similar damage characteristics. Finally, application of the model to analysis of the published data for offshore Gulf of Mexico is presented. The relationship between the parameters of the two different approaches is validated for these case studies. Introduction As oil fields mature, the volumes of produced water requiring disposal increase significantly. Re-injecting produced water is an attractive, environmentally sound solution to water disposal problems, but entails the risk of poor injectivity. Produced water normally contains varying concentrations of particles, which have a direct effect on the injectivity decline (injectivity index is defined as the ratio of the injection rate to the given pressure head). It has been shown that declining well injectivity is the major cost-increasing item in the case of re-injection. Standard formulation of damage mechanics is based on the classical deep bed filtration (concentration-based) model (DBF). Injectivity decline is characterized by two parameters: filtration coefficient, λ, and formation damage coefficient, β. Methodologies developed to determine these parameters involve expensive and difficult measurements, scaling problems and simplifying assumptions of analytical solutions. Moreover, the model is not easily implemented in reservoir simulators. Bachman et al.(1) proposed an empirical velocity-based damage model that could be easily tuned to field or laboratory data, and easily implemented in reservoir simulators. However, the model was formulated in 1D and its extension (and validity) in multidimensional flow was not shown. This paper presents the development of a 2D formulation and numerical implementation of permeability impairment based on the velocity-based model. The results will be compared with the classical DBF approach to validate the result against deep bed filtration theory. Application of the model to published data from offshore Gulf of Mexico is presented.

Multidimensional Velocity-Based Model of Formation Permeability Damage

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 97169, "Multidimensional Velocity-Based Model of Formation Permeability Damage: Validation, Damage Characterization, and Field Application," by R.S. Mojarad, SPE, and A. Settari, SPE, U. of Calgary, prepared for the 2005 SPE Annual Technical Conference and Exhibition, Dallas, 9–12 October. The loss of injectivity in produced-water and seawater injectors results from formation plugging. Reliable modeling of the permeability loss is key to analysis of field data and to the design and economics of projects. Standard formulation of damage mechanics uses the concentration-based, classical deep-bed filtration (DBF) model, which is not easily implemented in reservoir simulators. This alternative damage-modeling approach is based on the formulation proposed by Bachman et al.: "Coupled Simulation of Reservoir Flow, Geomechanics, and Formation Plugging With Application to High-Rate Produced-Water Reinjection," paper SPE 79695. The numerical implementation of this empirical, velocity-based damage model (VBDM) is extended to 2D flow and is validated by a comparison with the DBF model. The velocity model provides a remarkably accurate approximation of the more complex concentration model. Introduction Injectivity decline caused by particles in the injection water occurs to some extent in most injection wells. To understand and predict this decline, it is necessary to know about the water quality, formation characteristics, and deposition rate. In the classical DBF model, injectivity decline is characterized by two parameters: filtration coefficient, λ, and formation-damage coefficient, β. Methods to determine these parameters involve difficult measurements, scaling problems, and simplifying the assumptions of analytical solutions. Moreover, the model is not easily implemented in reservoir simulators. An empirical VBDM was developed previously that could be tuned to field or laboratory data and easily implemented in reservoir simulators. However, the model was formulated only in 1D, and its extension (and validity) in multidimensional flow was not shown. The full-length paper presents a 2D formulation and numerical implementation of permeability impairment that uses the VBDM. The results were compared with the classical DBF approach to validate the result against the DBF theory. A unique relation between the parameters of the two models was found that was key to developing a new method to determine the λ and β damage-characterization parameters on the basis of matching laboratory or field data with the velocity-based model. In this way, the number of parameters that need to be determined experimentally can be reduced. Mechanisms The injectivity decline caused by contaminated-water injection can be attributed to several primary mechanisms including internal filtration and external filter-cake buildup and its associated permeability reduction. Depending on details of the case studied (e.g., particle-size/pore-throat-size ratio, surface charge, or injection rate), either of the mentioned mechanisms could dominate. Large particles will be intercepted at the porous formation face, resulting in an external filter cake. Small particles can travel through the formation and initially plug the pore throats by bridging, thus creating internal pore restrictions. Continued buildup of internal plugging over time can also lead to an external filter cake. Once valid models have been obtained for each of these mechanisms, they can be coupled to describe the complete system of formation damage.

Damage Characterization of Deep Bed Filtration From Pressure Measurements

SummaryPermeability decline occurs during injection of sea or produced water, resulting in well impairment. Solid and liquid particles dispersed in the injected water are trapped by the porous medium and may significantly increase hydraulic resistance to the flow.We discuss a mathematical model for deep bed filtration containing two empirical parameters - the filtration and the formation damage coefficients. These parameters should be determined from laboratory coreflood tests by forcing water with particles to flow through core samples. A routine laboratory method determines the filtration coefficient with expensive and difficult particle-concentration measurements of the core effluent, and then the formation damage coefficient is determined from inexpensive and simple pressure-drop measurements.An alternative method would be to use solely pressure difference between the core ends. However, we proved in an earlier work that given pressure-drop data in seawater coreflood laboratory experiments, solving for the filtration and formation damage coefficients is an inverse problem that determines only a combination of these two parameters rather than each of them.A new method for the simultaneous determination of both coefficients is developed here. The method's new feature is using pressure data at an intermediate core point, supplementing pressure measurements at the core inlet and outlet. The proposed method furnishes unique values for the two coefficients, and the solution is stable with respect to small perturbations of the pressure data.In this work, the proposed method is used for analysis of laboratory test data on deep bed filtration. The values of filtration and formation damage coefficients are obtained for flow of solid and liquid particle dispersions in a number of different cores. Effects of particle type and porous media wettability on permeability decline are analyzed.