bluuebunny/crossref_metadata_2025_split huggingface dataset:
Solids Precipitation in Reservoirs Due to Nonisothermal Injections
Authors: Deo M. D. , Kumar Rajinder 
Published: December 2007

Abstract
In most nonthermal injection processes, fluids are injected at temperatures much lower than reservoir temperatures. Even though injected fluids are heated due to the prevailing geothermal gradient, in most applications, they reach the formation at temperatures far lower than the reservoir temperatures and cool the formation in the vicinity of the wellbore. The temperature lowering could cause solids precipitation particularly for paraffinic crudes and for oils susceptible to asphaltene precipitation. In this paper, the effect of cold-water injection in paraffinic crude reservoirs has been studied.
Temperatures of water reaching the formation were calculated using an analytical wellbore model modified to include realistic wellbore resistances. These temperatures were observed to be below the cloud points of paraffinic crudes. Solid-liquid equilibrium calculations showed that there was a strong possibility of paraffin precipitation under certain injection conditions. The effect of precipitation on oil recovery was analyzed using the method of characteristics approach. The calculations showed the extent of reduction in oil recovery due to paraffin precipitation near the wellbore.
Correlations for predicting Viscosity of W/O-Emulsions based on North Sea Crude Oils
Authors: Rønningsen Hans Petter 
Published: December 2007

Abstract
This paper describes some simple correlations which can be used to obtain reasonable estimates of relative viscosities and viscosities of water-in-crude oil emulsions.
The apparent viscosities of water-in-crude oil emulsions based on eight different North Sea crude oils of different types have been fitted to a general empirical equation which provides estimates of relative viscosities at temperatures between 5 and 40°C, water cuts between 10 and 60% and shear rates between 30 and 500 s‒1. The estimates are in general within 15-30% of experimental values. A correlation between crude oil viscosity and average molecular weight, can be utilized to obtain estimates of emulsion viscosities above about 20 °C, when only the molecular weight of the crude is known.
The yielding (or restart) behaviour of some of the emulsions at low temperature (5 °C) is described in terms of static yield stress as a function of water volume fraction.
Formation Damage by Fines Migration Including Effects of Filter Cake, Pore Compressibility, and Non-Darcy Flow—A Modeling Approach to Scaling From Core to Field
Authors: Liu Xinghui , Civan Faruk 
Published: December 2007

Abstract
The transport of fine particles in formations has been recognized as the major cause of formation damage. In this study, a two-phase, multi-species formation damage model was developed. The model allows for filter cake formation on the sand face, particle mobilization and retention in pore spaces, particle transfer at fluid-fluid interface, and porosity and permeability alteration. The effects of non-Darcy flow, relative permeabilities, capillary pressure, and wettability of fine particles and pore surfaces on two-phase flow formation damage were considered. A one-dimensional numerical simulator was constructed based on the model.
The model was validated using published laboratory data. Parameters involving the formation damage model were also determined using the laboratory data. With respect to field applications, the extent and degree of formation damage around the wellbore and the associated skin factor were predicted by implementing the model in radial flow. This study serves to enhance the understanding of formation damage due to particulate processes. This model is a useful tool for analyzing formation damage in laboratory core tests and simulate and predict formation damage in field operations.
Controlled-Release Scale Inhibitor for Use in Fracturing Treatments
Authors: Powell R. J. , Gdanski R. D. , McCabe M. A. , Buster D. C. 
Published: December 2007

Abstract
This paper describes results of laboratory and field testing of a solid, controlled-release scale inhibitor for use in fracturing treatments. Laboratory testing with a continuous flow apparatus has yielded inhibitor release rates under dynamic conditions. The inhibitor was tested to determine the minimum inhibitor concentration required to inhibit the formation of CaCO3, CaSO4, and BaSO4 scales in a brine. A model to predict the long-term release rate of the inhibitor was developed from data collected on the continuous flow apparatus. Data from treated wells will be compared with predictions of the model.
Inhibitor release-rate testing in a continuous-flow apparatus shows that a solid, calcium-magnesium polyphosphate inhibitor has a sustained release profile. Release-rate testing shows that the inhibitor can be used up to 175°F. The inhibitor is compatible with both borate and zirconium crosslinked fracturing fluids and foamed fluids.
The effective lifetime of the scale treatment can be predicted based on a model developed from laboratory data. The input variables required for the prediction include temperaturewater productionamount of inhibitorminimum effective concentration of inhibitor for the specific brine
The model can be used to aid in the design of the scale inhibitor treatment.
A High-Resolution, Fully Implicit Method for Enhanced Oil Recovery Simulation
Authors: Liu J. , Pope G. A. , Sepehrnoori K. 
Published: December 2007

ABSTRACT
A high-resolution total-variation-diminishing (TVD) finite-difference scheme has been developed and used in our multidimensional multicomponent, multiphase, finite-difference, IMPES-type compositional simulators for years. A variety of simulation results of enhanced oil recovery (EOR) processes have shown that this scheme gives convergent, high-order, accurate solutions. However, a restriction on the timestep size is always needed to ensure stability because of the IMPES formulation. This restriction sometimes can be very severe which means in some cases simulations are of high cost or even infeasible. It is well known that the fully implicit formulation is the most stable method. The standard approach, however, usually adopts lower-order finite-difference schemes for both the temporal and spatial discretizations because of computational requirements and difficulties in the program coding and the implementation of the physical property models. The advantage of the methods thus are overshadowed by the increased amount of numerical dispersion associated with large truncation error, which is especially detrimental to accurate field simulation and process design. A new fully implicit, high-resolution algorithm and a simulator based on the algorithm were developed and are described in this paper. The algorithm is second-order correct in time and uses a third-order finite-difference method to discretize the first-order spatial derivatives and a new total-variation-diminishing (TVD) third-order flux limiter to constrain the gradients of the fluxes to obtain accurate, oscillation-free solutions. All variables and TVD limiter functions are evaluated using the values of the new timestep. The schemes are applied for computing both the interface concentrations and mobilities with flow directions either in or against the coordinate directions and for nonuniform grids. The Jacobian matrix and the residual equations are updated at the end of each iteration. Unlike many numerical schemes in the literature, there are no problems with generalizations of this scheme.
The new algorithm and the simulator are verified by the good agreement between numerical results and analytical solutions. Verification cases with analytical solutions were also used to compare different simulation approaches. The new algorithm has higher resolution than standard methods, is more stable than the IMPES method, and stability is preserved with nonuniform grids.
A Computationally Efficient Gauss-Newton Method for Automatic History Matching
Authors: Tan T. B. 
Published: December 2007

ABSTRACT
Methods for automatic history matching that have been previously published have either required excessive computational time or had linear convergence characteristics. This paper presents a modified nonlinear regression method, the Gauss-Newton method, that has quadratic convergence properties and yet is extremely computational efficient. The modifications to the method are described in full detail. The method has been implemented in a three-dimensional three-phase simulator.
The simulator was applied to a case study using the Seventh SPE Comparative Problem. It was shown to be capable of estimating multiple parameters such as permeability and porosity. Selected matches from actual wells in a field study were also presented. The results of an actual well test were also matched. It was demonstrated that the automatic history matching simulator could identify the reservoir parameters that had significant effect on the observed data.
Dual-Porosity Simulation Incorporating Reinfiltration and Capillary Continuity Concepts Part I: Single Gridcell
Authors: Tan J. C. T. , Firoozabadi Abbas 
Published: December 2007

ABSTRACT
We have developed a method to account for reinfiltration and capillary continuity effects in the simulation of fractured reservoirs, The proposed method requires fine grid simulation of a three-block stack (two-block stack if it is assumed that there is no capillary continuity). The information is then used to construct the drainage curves of different gridcells that may contain a large number of matrix blocks. Variation of capillary pressure, block height, and permeability of various matrix blocks within a gridcell are accounted for without the need for fine grid simulation.
Evaluating Miscible and Immiscible Gas Injection in the Safah Field, Oman
Authors: Hearn Charles L. , Whitson Curtis H. 
Published: December 2007

Abstract
The reservoir modeling approach presented in this paper illustrates how available engineering tools can be used to evaluate the technical feasibility and economics of high-pressure gas injection. The key components to such a study included: 1) equation of state (EOS) modeling of experimental PVT data, matching miscible and immiscible slim tube results, and systematically reducing the number of components used in the EOS model to minimize computational requirements, 2) studying numerical grid effects, displacement mechanisms, optimal well pattern, and injection pressure with 2D cross-section and 3D sector models, and 3) comparing compositional results with simulations based on the black-oil PVT formulation used in full-field history matching and reservoir management modeling.
Estimating Two and Three Dimensional Pseudo-Relative Permeabilities With Non-Linear Regression
Authors: Tan T. B. 
Published: December 2007

ABSTRACT
Pseudo-relative permeabilities are usually generated to match fine grid models of typical cross-sections of the reservoir with coarse grid models and these are then used in full field models to reduce the number of cells. Various analytical formulae have been proposed to calculate these pseudos. In practice, the analytic formulae merely represent an educated first guess of the pseudo-relative permeabilities necessary to match the fine grid model. When used in the coarse grid equivalent of the fine grid model, these pseudo-relative permeability curves often require further trial and error adjustment in order to match the fine grid model results.
This paper describes an approach whereby these pseudos may be easily generated with non-linear regression analysis (automatic history matching). The relative permeability values of the saturation function tables are allowed to vary independently until a match of the observed saturations and production rates of the fine grid model is obtained with the coarse grid model. Calculated pseudo-functions are presented for a difficult previously published problem with non-communicating layers. A case study shows the sensitivity of the pseudos to coarse grid definition and production rates. Previously published formulae have been restricted to two-dimensional vertical cross-section pseudos. As a result, areal heterogeneity and sweep displacement efficiency have been ignored. In this paper, we extend the pseudo concept to three dimensions by generating a single pseudo-relative permeability curve to represent a fine three-dimensional model with a coarse three-dimensional model.
A Complete Hydraulics Model for Horizontal Wells
Authors: Siu Alan , Shin Dalsoo , Subramanian Ganesan 
Published: December 2007

ABSTRACT
A horizontal well usually yields a high rate through its long perforation interval, resulting in a large frictional pressure drop that is believed to reduce the well productivity.
Unlike conventional horizontal well methods which consider the horizontal section only, the proposed model also includes the vertical section of the well and the surface facility from the well head to the GOSP. The hydraulics model was validated stage-by-stage by various known solutions, and then applied to a high rate well.
It was found that the effect of frictional pressure drop on oil rate was not as pronounced as suggested by analytical methods, or some numerical simulation studies. In summary, the pressure drop in the vertical section of the horizontal well plays an especially important role in deciding how much fluid can be produced. Therefore, it is recommended to be an integral part of horizontal well models.
Shocks in Solution Gas-Drive Reservoirs
Authors: Herrera Ismael , Chargoy Lucia 
Published: December 2007

abstract
Black-oil models neglect diffusive mechanisms such as molecular diffusion or mechanical dispersion; this omission produces a propensity to developing shocks. This paper aims to carry out an exhaustive identification of the kind of shocks that can occur when black-oil models are applied to problems in which the bubble-point varies and to establish the conditions under which they are generated. In addition to shocks of Buckley-Leverett type, two other classes of shocks and a bifurcation mechanism, are identified. Except for shocks of Buckley-Leverett type, all other shocks may occur in the presence of capillary forces. The paper contributes to clarify several aspects of black-oil models and to understand pathologies that occur in their numerical implementation.
Dynamic Pseudos: How Accurate Outside Their Parent Case?
Authors: Ekrann Steinar , Mykkeltveit Johannes 
Published: December 2007

Abstract
If properly constructed, dynamic pseudos allow the parent solution from which they were derived to be exactly reproduced, in a certain well-defined sense, in a subsequent coarse grid simulation. The paper reports extensive numerical experimentation, in 1D homogeneous and heterogeneous media, to determine the performance of pseudos when used outside their parent case. We perturb fluid viscosities and injection rate, as well as realization. Parent solutions are produced analytically, via a generalization of the Buckley-Leverett technique, as are true solutions in off-parent cases. Capillarity is neglected in these experiments, while gravity is sometimes retained in order to force rate sensitivity.
Theoretical Investigation of Countercurrent Imbibition in Fractured Reservoir Matrix Blocks
Authors: Chen J. , Miller M. A. , Sepehrnoori K. 
Published: December 2007

ABSTRACT
Countercurrent imbibition is an important oil recovery mechanism in fractured reservoirs. The imbibition process can be described by a nonlinear diffusion equation that has self-similar solutions. In this paper, we use the diffusion equation to conduct numerical experiments of countercurrent imbibition in a single matrix block to identify flow characteristics. The result demonstrates that the widely-used Aronofsky et al.1 exponential relationship is only valid for cases where diffusion coefficients are constant. The nonlinear diffusion equations in one and two-dimensions are analytically solved using a relative flow rate concept to simplify the analysis. The result is a new understanding regarding the effects of various parameters such as capillary pressure, relative permeability, mobility ratio, and fractional flow on countercurrent imbibition.
The solutions can be directly used to modify an existing single porosity model to a dual porosity model for simulating fractured reservoirs. Results show that our approach provides fairly good accuracy compared to a full-scale dual porosity model with little increase in computation time over single porosity modeling.
Characterization of Trapped Gas Saturation and Heterogeneity in Core Samples Using Miscible-Displacement Experiments
Authors: Smith D. H. , Jikich S. A. 
Published: December 2007

ABSTRACT
Trapped gas saturation and permeability heterogeneity were evaluated in Berea cores at reservoir conditions, using standard miscible displacement experiments, with and without surfactants. Pressure and production history were influenced by core heterogeneity and foam lamellae formation when aqueous surfactant was present in the core.
A simple dispersion model and a three-coefficient dispersion-capacitance model (Coates-Smith) were fit to the experimental data. The dispersion-capacitance model successfully matched the experiments in which foam lamella formed, while the simple dispersion model was used only for determining initial core flow heterogeneity.
The objective of the dispersion-capacitance model was to estimate trapped gas saturations; however longitudinal dispersion and mass transfer also were examined. The results show that the dispersion-capacitance model accurately fits trapped gas saturation controlled by rock heterogeneities and foam lamellae for lamella generating mechanisms that allow a continuous gas phase (leave-behind lamellae). The practical applications resulting from this study can aid in core sample selection and scaling short laboratory corefloods to field dimensions for applications to foam stimulation and underground storage of natural gas.
Laboratory Investigation of Parameters Affecting CO2-Foam Mobility in Sandstone at Reservoir Conditions
Authors: Yaghoobi Hossein , Heller J. P. 
Published: December 2007

ABSTRACT
In CO2 floods the large viscosity contrast between the reservoir and injected fluids induces an unfavorable mobility ratio that results in early breakthrough and consequently decreases oil sweep efficiency. There is evidence that the presence of an aqueous surfactant solution will produce a foam with CO2. This not only controls the gas mobility but may also selectively reduce the gas mobility through regions of differing permeabilities. This could be a very favorable phenomenon in EOR processes if it occurs in the reservoir. The purpose of this study is to evaluate foam application from these perspectives.
This study concerns a series of steady-state CO2-foam flow experiments in Berea sandstone cores at typical reservoir conditions. The effects on foam mobility of flow rate, foam quality, surfactant type, surfactant concentration, and rock permeability were investigated. Four commercial surfactants (Chevron Chaser™ CD 1040, CD 1045, CD 1050 and Shell Enordet 2001) at 500 ppm and 2500 ppm concentrations (in 2 wt% brine) were used. In each run the contribution of each parameter on foam mobility was evaluated independently.
Our results have shown that the mobility of 80% quality foam increased with increasing total flow rate for all four surfactants. As evidenced by increased pressure drop, foam was generated in all runs, including those in which the total Darcy flow velocity was as low as 0.04 fit/d. Selective mobility reduction, in which the measured mobility was reduced further in high permeability cores, was observed for some but not all surfactants at certain flow rates. Some sequences of experiments were performed in which the flow rate of one phase was held constant, while that of the second was increased from one run to the next. Between experiments, in each sequence, it was observed that pressure drop depended little on gas velocity. Our results also showed that foam mobility increased with increasing liquid velocity in all the runs. We also found that the foam mobility increased slightly as foam quality increased up to about 85 % and then rose quite rapidly as foam became dryer, up to about 98 % CO2. Foam hysteresis was also investigated in 36 experimental runs and was found to be absent in almost all cases within a reasonable experimental error.
Screening Restimulation Candidates in the Antrim Shale
Authors: Hopkins C. W. , Frantz J. H. , Tatum C. L. , Hill D. G. 
Published: December 2007

ABSTRACT
This paper describes a simple method to identify, prioritize, and evaluate restimulation candidates in the Antrim Shale of the Michigan Basin. This work is being performed as part of an ongoing field-based Gas Research Institute (GRI) project investigating the Antrim Shale. There are between 500 and 1,000 Antrim Shale wells which could be candidates for restimulation due to previous screenouts and/or flowback problems, when sand consolidation material was not used. However, all of these wells might not benefit from restimulation, due to either poor reservoir quality or because the wells are already effectively stimulated. Based on historical results, we estimate the increase in reserves from restimulation could be between 50 and 400 MMscf per well, which could add 50 to 200 Bscf in future reserves from the 500-1,000 candidate wells.
We have developed a novel injection test unit and procedure to help operators identify the best restimulation candidates in a cost-effective manner and in a reasonable amount of time. The test is designed to determine if there is an effective hydraulic fracture connected to the wellbore. To our knowledge, a test of this nature has not been used before for specifically identifying restimulation candidates. To date, we have run 50 tests, and identified potential restimulation candidates from about 1/3 of the tests.
The Use of Production Logs to Evaluate Completion and Stimulation Effectiveness
Authors: Harris Perry , Holsclaw Steve , Mullen Mike , Sagan Mike , Frisch Gary 
Published: December 2007

Abstract
The current economic structure of the petroleum industry often requires multiple completions with production from each zone commingled to reduce completion costs. However, these multiple completions require a different approach for analyzing the effectiveness of both the original completion and possible later stimulation treatments: rather than costly individual zone testing, production logs can be run to detect the contribution of each zone to the total production rate.
When multiple pay zones are treated and evaluated together, the reservoir engineer faces the problem of determining whether or not each zone benefited from the chosen treatment. In the case of multiple completions, well testing using either drawdown and/or buildup is expensive and complicated. Production logs make it possible to determine the type and rate of the produced fluids from each individual zone in a timely manner. By comparing the logging tool responses taken before and after stimulation, the effectiveness of stimulation can be determined. This will identify zones requiring further treatment and help determine the optimal type of treatment. In addition, valuable information for future wells can be gathered efficiently in terms of both time and money.
Guidelines for running production logs are presented and the usefulness of production logs for evaluating multizone completions is demonstrated. Several examples highlight how production logs can be used to analyze multizone completions in tight gas areas.