Ali A. Garrouch

The influence of clay content, salinity, stress, and wettability on the dielectric properties of brine-saturated rocks; 10 Hz to 10 MHz

Complex impedance measurements have been performed on 14 shaly sand samples, Berea sandstone, and Ottawa sand-bentonite packs in a frequency range of 10 Hz to 10 MHz, using both the two- and four-electrode techniques. Measurements have been conducted at an effective radial stress varying from ambient pressure to 4000 psi for brine-saturated oil-wet and water-wet samples.The dielectric permittivity is found to correlate with the clay volume fraction, the cation exchange capacity, and electrochemical potential of the rock samples and to depend strongly on the salinity of the brine used. Stress and wettability are shown to have a small influence on the dielectric constant of fully brine-saturated rocks. A lower critical frequency is found to characterize the geometry of the pore space. Empirical correlations between the dielectric constant, frequency, permeability, cation exchange capacity, and porosity are presented for the shaly sands used in this study. These correlations provide a means of estimating important petrophysical parameters such as the permeability and the clay content from a nondestructive complex impedance sweep of shaly sands fully saturated with brine.

Development of an expert system for underbalanced drilling using fuzzy logic

Abstract This paper documents the development of an expert system for screening wells that could be drilled underbalanced, and for aiding in the preliminary selection of appropriate underbalanced drilling fluids for a given range of wellbore and reservoir conditions. This approach combines a qualitative rule-based analysis for assessing formation damage and lost circulation potentials with quantitative analysis for assessing wellbore stability using geomechanical and petrophysical data. To make the analysis complete, a variety of other factors such as pipe sticking potential, wellbore geometry, type of fluid influx anticipated, pore pressure value, and cost benefit are also included in the expert-system decision trees. The main advantage of the expert system, developed in this study, is the use of fuzzy logic for handling cases that lend themselves to partial truth. This feature makes the system a powerful tool for analyzing ambiguous drilling scenarios. Results of compared field cases are encouraging and conformal to field practices. Allowing for human input, when essential data are lacking, makes the system a useful tool that can help less experienced individuals function near the level of proficient drilling engineers.

Effect of heterogeneity on the performance of immiscible displacement with horizontal wells

Abstract A three-dimensional, finite difference, chemical flood simulator (UTCHEM) was used to study the performance of immiscible displacement with horizontal and vertical wells in several heterogeneous reservoirs. Three-dimensional heterogeneous permeability fields were generated geostatistically with Dykstra-Parsons coefficient and spatial correlation as characterizing parameters. A total of 21 permeability fields were generated to cover a wide range of Dykstra-Parsons coefficients and spatial correlations. Initially, simulations of immiscible displacement with two horizontal wells (one injector and one producer) were performed in all these permeable media. The effect of the amount of cross flow between producing layers on the flood performance was investigated. These results were then compared to those obtained with two vertical wells (one injector and one producer) for all the permeable media. Finally, investigations were carried out on a heterogeneous reservoir to study in detail the sensitivity of the displacement performance to the horizontal well length and to the ratio of horizontal to vertical permeability using various well combinations. These well combinations consisted of vertical injector-vertical producer, horizontal injector-horizontal producer, vertical injector-horizontal producer, and vertical producer-horizontal injector. Results show that the degree and the structure of the reservoir heterogeneity have a significant effect on the efficiency of immiscible displacements with horizontal wells. Long horizontal wells in highly heterogeneous reservoirs do not necessarily guarantee improved oil recovery.

A new approach combining Karhunen-Loéve decomposition and artificial neural network for estimating tight gas sand permeability

Abstract The Karhunen-Loeve (KL) decomposition, known for its wide applications in scientific problems for data compression, noise filtering, and feature identification, is used to determine an intrinsic coordinate system, or eigenfunctions, that best represents a data set. Projections of the data set onto these eigenfunctions reduces the data set to a set of data coefficients. Processing the data coefficients of the most energetic eigenfunctions through an artificial neural network (ANN) is found to enhance capturing the hidden complex relationships among the data variables. This approach is demonstrated using tight gas sand data to estimate permeability from effective porosity, mean pore size, and mineralogical data. For an arbitrary neural network architecture, combination of KL decomposition and ANN is found to be superior over ANN alone. This combination of two powerful multivariate analysis tools not only correctly estimates the permeability but also eliminates iterative procedures needed for optimizing the neural network topology.

Predicting the Onset of Inertial Effects in Sandstone Rocks

This study presents a method to determine the onset of inertial effects at the microscopic level, to distinguish between Darcy and non-Darcy flow regions within porous media at the pore level, and to quantify the effects of retained polymer on gas mobility. Capillary pressure and polymer flood experiments were conducted using Elgin and Okesa sandstone samples. The pore-size distributions were used to study the high-velocity flow effects. A modified capillary-orifice model was used to determine the non-Darcy flow effects at the pore level, with and without residual polymer.The overall flow behavior at any flow rate may be described as the average of all contributions from the Darcy and the non-Darcy terms in all pores. Results of this study suggest that the conventional Reynolds number may lead to incorrect analysis of flow behavior when evaluating non-Darcy flow effects in porous media. The Forchheimer number, defined as the ratio of inertial forces to viscous forces, is found more adequate for analyzing microscopic flow behavior in porous media.

A Novel Analysis of the Electrical Transport Mechanisms in Porous Media

Effects of water saturation and wettability on the dielectric constant are investigated experimentally using four-electrode impedance measurements, and theoretically using models that account for the electrical double layer polarization. Complex impedance measurements, performed on Berea sandstone and on Ottawa-sand packs in the frequency range 10 Hz to 1 MHz, appear to indicate that the dielectric constant varies linearly with water saturations above 50%. The rate of change of dielectric constant with saturation is found to be a function of frequency. As the frequency increases this rate of change decreases. The decrease in the slope of the dielectric constant-water saturation profile with frequency is not intuitively obvious, but has been proven theoretically in this work. The dielectric constant of water-wet samples is found higher than that of the oil-wet samples at all water saturations. The difference is more pronounced at high water saturations near unity. The wettability changes have been simulated using a generalized Maxwell–Wagner model by varying the amount of ionic surface charge of rocks. In general oil-wetting agents react with the formation matrix by connecting their positively charged tails to the negatively charged silica surfaces, lowering the surface charge density. Simulations show that the effect of wettability changes on the dielectric constant is very significant. These conclusions are consistent with the experimental results presented in this study.

A classification model for rock typing using dielectric permittivity and petrophysical data

Dielectric and petrophysical data for both carbonate and sandstone brine-saturated rocks have been used in a discriminant analysis for the purpose of developing a model for rock-type classification. A total of eight petrophysical and dielectric parameters were used in this study. The petrophysical parameters consist of a cation exchange capacity (CEC), a specific surface area (SA) and a rock porosity (). The dielectric parameters deduced from the impedance measurements consist of ζs and ζ∞, which are real numbers representing the static and the high-frequency relative dielectric permittivities of the water-saturated rock, respectively, the characteristic relaxation time τ, the spread parameter α and σs, which is the dc conductivity of the water-saturated rock. Outliers have been identified by computing the squared Mahalanobis distances to centroid. Multivariate data cases with relatively large values of the squared Mahalanobis distance associated with small probabilities in the order of 0.001 or less have been removed. Results of the discriminant analysis indicate that only four variables (ζs, ζ∞, , CEC) are sufficient to identify rock types. The analysis reveals the existence of a significant discriminant function to distinguish among two distinct rock types related to two broadly defined lithofacies: sandstones and carbonates. A rock-type classification model based on dielectric permittivity and petrophysical data is, therefore, introduced. The model has been validated by an independent set of testing samples. The results of this study indicate that the use of dielectric permittivity data, in conjunction with basic rock properties such as the porosity and the cation exchange capacity, appears to be a robust approach for hydrocarbon rock-type classification.

Automating sandstone acidizing using a rule-based system

An expert system for automating sandstone acidizing has been developed in this study. The system consists of six stages, which were built following an acidizing logic structure that is presented in the form of decision trees. The six stages consist of formation oil displacement, formation water displacement, acetic acid, HCl pre-flush, main acid, and over-flush stage. The acid blends recommended by the system are damage-type specific, and account for the compatibility between the injected acid and the in situ crude in order to avoid formation of asphaltene sludge, or emulsions. The acidizing expert system has been implemented as an online web-based application. Applicability of this expert system to acidizing design has been illustrated using three documented actual field cases spanning the Niger Delta region, Algyo Oil field in Hungary, and the Dulang oil field in Malaysia. For Niger Delta field and the Algyo field cases the expert system produced an optimal main acid job design with recommended pre- and post-flushes that are in perfect agreement with successful field treatment. For the Dulang oil field, in actual practice, an organic clay acid was injected for removing problems of fines migration in a reservoir that has a high calcite content, with a moderate amount of feldspar and chlorite clay. The acidizing expert system recommended a chelant-based acid, which is a recent innovation that is considered a more cost-effective acid solution for dissolving fines in presence of calcite and other sensitive clay minerals.

Simple Models for Permeability Impairment in Reservoir Rocks Caused by Asphaltene Deposition

Abstract This study formulates two models for estimating permeability impairment caused by asphaltene deposition. The first model is based on a mass balance and is capable of predicting permeability reduction in either vertical or horizontal wells. The model accounts for both the effects of position in the reservoir and time. The second model is formulated on the basis of the capillary tube theory. It accounts for the rock pore-size distribution but does not account for the time dependence. Both models are formulated in integral form to allow for analytic solutions when symbolic formulation exists for the parameters affecting the deposition process. Both modeling approaches account implicitly for the effects of pressure, temperature, and fluid composition, by including the asphaltene radius distribution. Even though the mass-balance model is one-dimensional and is valid for only single-phase flow in porous media, it can be used to estimate the permeability reduction for both homogeneous and heterogeneous formations. The capillary tube model requires less input variables than the mass-balance model and does not depend on any tuning parameters. However, it is neither sensitive to the position in the reservoir nor to the well type penetrating the reservoir. These reasons make the capillary tube model useful only for a qualitative description and thus capable of only giving a first-order estimate of the permeability reduction caused by asphaltene deposition.

Analysis of the Mechanical Stability of Boreholes Drilled in Sedimentary Rocks

Abstract This article presents the method and results of wellbore stability analysis for three common reservoir lithologies consisting of a consolidated sandstone, a shaly sandstone, and a limestone formation. The effect of stress anisotropy on the mechanical stability of wellbores is evaluated while varying the inclination angle from 0 to 90°, for both the Mohr–Coulomb and the Drucker–Prager failure criteria. The selected failure criterion, and the in-situ rock stress regime are found to have significant effects on the safe drilling fluid density required to maintain wellbore integrity. According to some field examples, the Drucker–Prager failure criterion appears to systematically mimic rock conditions more realistically than the Mohr–Coulomb failure criterion. The simulated consolidated sandstone formation is found more stable with lesser drilling fluid density, at any inclination angle, than the simulated shaly sandstone formation. The simulated limestone formation is even more stable than the consolidated sandstone at all inclination angles since it requires lighter fluid density to prevent wellbore collapse. For all these rock types, the higher the deviation angle (from vertical), the higher the drilling fluid density needed for maintaining wellbore integrity. For the depth and rock conditions simulated, both consolidated and shaly sands are unstable in a strike-slip stress regime, but stable in an extensional stress regime. The simulated limestone formation was found stable in both stress regimes. However, in an extensional stress regime, the limestone formation required lighter fluid density to maintain wellbore integrity than in a strike-slip stress regime. This article introduces the theory of using a practically-oriented model to assess the mechanical stability of a wellbore in a linearly-elastic stress field. The model can be used to determine the range of mechanically stable well inclinations for a given formation, and to suggest drilling-fluid density programs tailored to efficient and safe drilling.