bluuebunny/crossref_metadata_2025_split huggingface dataset:
Interfacial Effects in Gas-Condensate Recovery and Gas Injection Processes
Authors: Meleán Y. , Bureau N. , Broseta D. 
Published: December 2007

Abstract
Gas condensate production and gas injection processes are strongly influenced by the gas/oil (or condensate) interfacial tension and by the wetting behavior of oil on the porous substrate. Oil (condensate) recovery is favored by low gas/oil (condensate) interfacial tensions and by complete wetting of oil (condensate) on the water phase that often covers the porous rock. The relevant parameters are dimensionless numbers that measure the importance of the oil/gas interfacial tension relative to gravity (Bond number) and to viscous (capillary number) forces. Another important parameter is the oil/gas contact angle on the water that often covers the porous substrate: a zero contact angle corresponds to complete wetting of oil, while a finite angle corresponds to partial wetting. These parameters are increasingly used in modern reservoir simulators for estimating oil and gas residual saturations and relative permeabilities.
We analyze how these parameters vary with the operating conditions (e.g., pressure) and the nature of the injection gas: CH4, CO2 and N2. On approach to gas/oil complete miscibility, both the capillary and Bond numbers diverge, i.e., viscous and buoyancy forces dominate over capillary forces. For nearmiscible conditions, these numbers obey simple scaling laws as a function of the distance to complete miscibility. The prefactors of these scaling laws depend on the particular oil+gas system, which allows to classify the efficiency of the different injection gases. For reducing capillary forces with respect to the viscous or buoyancy forces, supercritical CO2 is more advantageous than off-critical CO2 or CH4, which themselves are more advantageous than N2.
We also present a simple calculation scheme for predicting the conditions under which the transition to complete wetting of oil on water occurs, i.e., the oil/gas contact angle vanishes. The only ingredients needed are the composition and densities of the three coexisting phases (water, oil and gas), calculated by means of an appropriate equation of state. The essential result is that under typical operating conditions, oils or condensates spread on water, the transition to partial wetting being remote from complete miscibility conditions. CO2 is the most effective in promoting the wetting (or spreading) of the oil phase on water, followed by CH4 and then by N2.
Thickening Carbon Dioxide with the Fluoroacrylate-Styrene Copolymer
Authors: Xu Jianhang , Enick Robert M. 
Published: December 2007

Abstract
The fluoroacrylate-styrene copolymer, polyFAST, is the first associative thickener that has been identified for carbon dioxide. Fluoroacrylate is highly carbon dioxide-philic, enhancing the solubility of polyFAST in carbon dioxide. Styrene is relatively carbon dioxide-phobic, but promotes viscosity-enhancing, intermolecular associations. The polyFAST copolymer used in this study had a composition of 29 mol% styrene - 71 mol% fluoroacrylate, a number-average molecular weight of 540,000 and a polydispersity index of 1.63. Carbon dioxide density values of 0.65-0.85 g/cc were required to dissolve 0.25-2.0wt% polyFAST in the 298 – 373 K temperature range. Falling cylinder viscometry measurements at 298 K demonstrated that the viscosity enhancement of CO2 associated with polyFAST increased with increasing polyFAST concentration, decreasing shear rate and decreasing temperature. The non-Newtonian falling cylinder viscometry results at 298 K were fit to a power law model with copolymer concentration-dependent coefficients. Mobility measurements of polyFAST-CO2 solutions flowing through 80-200 md Berea sandstone cores at superficial velocities of 0.00035 – 0.028 m/s (1 - 80 ft/day) at 298 K also indicated that polyFAST was an effective thickener. At a superficial velocity of 0.00035m/s (1ft/day), 1.5wt% polyFAST increased the CO2 viscosity by a factor of 19 relative to neat CO2. Smaller increases in viscosity occurred at lower polyFAST concentrations and higher velocities.
An Effective Continuum Model for the Liquid-To-Gas Phase Change in a Porous Medium Driven by Solute Diffusion: I. Constant Pressure Decline Hates
Authors: Tsimpanogiannis Ioannis N. , Yortsos Yanis C. 
Published: December 2007

Abstract
We derive an effective continuum model to describe the nucleation and subsequent growth of a gas phase from a supersaturated, slightly compressible binary liquid in a porous medium, driven by solute diffusion. The evolution of the gas results either from the reduction of the system pressure at a constant rate. The model addresses two stages before the onset of bulk gas flow, nucleation and gas phase growth. We assume negligible gradients due to gravity or viscous forces, thus the critical gas saturation, which signals the onset of bulk gas flow, is only a function of the nucleation fraction.
We show that the important quantities characterizing the process, such as the fraction of pores that host activated sites, the deviation from thermodynamic equilibrium, the maximum supersaturation in the system and the critical gas saturation depend crucially on the nucleation characteristics of the medium. We use heterogeneous nucleation models primarily in the form of pre-existing gas, trapped in hydrophobic cavities, but also in terms of a rate-dependent nucleation, to investigate in detail the nucleation behavior. Using scaling analysis and a simpler analytical model we show that the relevant quantities during nucleation can be expressed in terms of a simple combination of dimensionless parameters, which include rate effects, for either type of nucleation model.
The theory predicts that the maximum supersaturation in the system is a weakly increasing function of rate, which in the region of typical experimental parameters, can be approximated as a power law with a small exponent. This function depends sensitively on the probability density function of the nucleation cavity sizes. It also predicts that the final nucleation fraction, thus the critical gas saturation, is a power law of the decline rate. The theoretical exponents are shown to be in good agreement with experimental data. The subsequent evolution of the gas phase and the approach to the critical gas saturation is also described.
MRI Tomography of Saturation Development in Fractures During Waterfloods at Various Wettability Conditions
Authors: Graue A. , Aspenes E. , Moe R. W. , Baldwin B. A , Moradi A. , Stevens J. , Tobola D. P. 
Published: December 2007

Abstract
At three different wettabilities, two stacked outcrop core plugs, separated by a 1 mm fracture, were waterflooded. During the experiment in-situ fluid saturations were monitored with Magnetic Resonance Imaging (MRI). The sequence of 2D MRI images corroborated earlier lower resolution, larger scale experimental results on the effect of fractures during waterflooding at various wettabilities. The MRI images of oil saturation development in the fracture clearly revealed two distinct transport mechanisms for the wetting phase, water, across the fracture at several wettability conditions.
When strongly-water-wet, the first core reached its spontaneous imbibition endpoint before water left the matrix and entered the fracture. The displaced water flowed down the exit face to the bottom of the fracture and displaced the oil upward at the rate of water injection. At less-water-wet conditions water droplets formed on the exit face of the first plug and grew large enough to form individual bridges between the two plugs. This happened well before the first plug reached its spontaneous imbibition endpoint. Under these conditions, the fracture filled slowly, as the bridges increased in diameter and additional bridges formed. Due to the capillary continuity of the wetting phase, a viscous pressure drop was established across the stacked core plugs, providing a viscous component to the total oil recovery.
Background and Operational Experience of Multiphase Metering in the Safaniya Field-Offshore Saudi Arabia
Authors: Warren P. B. , Hussain S. , Ghamdi S. 
Published: December 2007

Abstract
An automated and compact multiphase flow meter (MPFM) tested offshore Saudi Arabia has accurately measured three - phase flow rates under existing field operating flow conditions. An extensive eight-month field test in the Safaniya field was conducted from October 1999 to June 2000 utilizing over 350 well tests under varying operating conditions. A meter was installed on an offshore test barge, so that individual wells could be tested in series with traditional test barge methods. For these trial tests, the total liquid rate ranged from 1300 to 12000 barrels per day, the GOR ranged from 150 to 350 SCF/STB and the water cut ranged from 0 to 50%. The results show that over 90% of the wells tested were within +/− 10% of test barge results for all liquid, oil and water cut measurements. While gas measurements were determined to be within +/− 15% in 75% of the wells tested.
As a result of this favorable field test and other economic considerations, a multiphase flow meter is recommended for installation on all Safaniya Field existing offshore platforms. Project installation designs for the first five meters have been completed and plans are being made to install them beginning in early 2002.
Global Optimization of Oil Production Systems, A Unified Operational View
Authors: Vázquez Manuel , Suárez Alexis , Aponte Hugo , Ocanto Leonardo , Fernandes José 
Published: December 2007

Abstract
Oil production systems (OPSs) are complex and heterogeneous. They comprise several equipment and their wells flow naturally or using a variety of artificial lift methods. To optimize these systems, integrated multidisciplinary skilled teams managing a considerable volume of information are required. In practice, OPSs are not optimized globally; instead some subset of the system is optimized locally or many simplified assumptions are used which may not be consistent with the OPS conditions. For example, artificial lift wells are tuned according to their completion and surface facilities without considering the rest of the system. Traditional optimization techniques such Linear and Dynamic Programming, available from the Operation Research (OR) community, fail to find a global optimum solution for this problem or demand a considerable amount of computational resources making impractical their application. Under these techniques, an objective function has to be stated precisely and has to cover all the variables to optimize, being necessary a strong mathematical and OPS knowledge. This paper presents a new methodology for global optimization of OPSs. We developed an optimization procedure merging Artificial Intelligence (AI) techniques with OR techniques to deal with this problem. Combining the power of evaluating alternative solutions and flexibility of Genetic Algorithms (GAs) with the local search abilities of the Tabu Search (TS) meta-heuristic, a robust solution is found requiring a reasonable amount of computational resources. The OPS manager can easily change the objective function, only the optimization target is requested, and the performance of our technique is not affected. Through this objective function and our OPS model, the OPS is unified under economical or operational criteria. Our method is being tested on 25 wells OPS combining SRP, PCP and ESP wells. A 5% of increase in oil production and a 10% of reduction in energy consumption is expected.
Transient Well Index for Numerical Well Test Analysis
Authors: Archer Rosalind A. , Yildiz Tabiat T. 
Published: December 2007

Abstract
Incorporating well test data into integrated reservoir characterizations may require the well test to be modeled in a reservoir simulator that also forward simulates other dynamic data being matched. Care is required to ensure the simulator is not introducing unnecessary numerical artifacts. Standard finite-difference reservoir simulators use the Peaceman well index, which is based on the solution to single-phase, steady-state, incompressible flow. For a pressure transient test the assumptions of steady-state, incompressible flow are not applicable. However instead of modifying the well index it is common to account for this by using highly refined grids around wells and making very careful choices of timestep sizes to model well tests.
This work presents a new well index formulation that allows well tests to be simulated accurately in finite-difference simulators using uniform, relatively coarse grids, without the problem of artifact wellbore storage (early time unit slope on the pressure derivative only) that otherwise occurs. The well index model computes the average pressure in the well block directly from the analytical solution for infinite acting radial flow. This approach can also be applied to non-square gridblocks and anisotropic reservoirs.
Well tests simulated using finite-difference simulation with the proposed transient well index and the Peaceman well index are compared to analytical well test solutions. The simulated well tests using the proposed transient well index closely follow analytical solutions – even on coarse grids (e.g. 15 cells by 15 cells, 167 feet by 167 feet). When the same simulations were performed using the Peaceman well index, the simulated pressure transients showed significant artifact wellbore storage, especially in low permeability reservoirs.
Fractured-Well-Test Design and Analysis in the Presence of Non-Darcy Flow
Authors: Gil J. A. , Ozkan E. , Raghavan R. 
Published: December 2007

Abstract
The objective of this paper is to discuss the design and analysis of fractured-gas-well tests to account for fracture non-Darcy flow. The results and discussions are based on a semi-analytical model. Guidelines and correlations are presented to design fractured-well tests with tolerable influence of fracture non-Darcy flow. The effect of non-Darcy flow skin (or rate dependent skin) is discussed in detail. A method is also presented to analyze fractured-well tests under non-Darcy flow conditions to estimate the non-Darcy flow coefficient, fracture conductivity, and the reservoir properties. Unlike the conventional methods, this method does not require two tests at different production rates.
Measurement of Vertical Permeability Using a Dual Lateral Well in a Layered Reservoir
Authors: Gill Harmohan S. , Al-Thawad Faisal , Thuwaini Jamil S. 
Published: December 2007

Abstract
This paper presents a case study of a vertical interference test conducted in a single well. The investigation in this dual lateral completion was conducted to determine the effective vertical permeability between the pulsing horizontal lateral and the lower section of the vertical wellbore used for observation.
This case study showed the presence of a thin layer with extremely high permeability, which intersected both the horizontal lateral and the vertical wellbore (also referred to as a stratiform Super-K). Simulations along with geological and production log data indicated that the Super-K layer was not aerially extensive. Because of the layered nature of the reservoir, presence of a Super-K layer and the multiphase conditions, a numerical well test simulator was used to analyze the horizontal well buildup and the vertical interference test.
The test was designed to be able to analyze the horizontal well pressure data in conjunction with the pulse interference data for better reservoir characterization. The paper details the steps followed in this successful integration of all sources of data in the test analysis.
Analysis of Pressure Transient Test of Non-Newtonian Fluids in Infinite Reservoir and in the Presence of a Single Linear Boundary by the Direct Synthesis Technique
Authors: Katime-Meindl Irina , Tiab Djebbar 
Published: December 2007

Abstract
Non-Newtonian fluids are very common during drilling, fracture operations and enhanced oil recovery processes. When a reservoir contains a non-Newtonian fluid such as those injected during polymer flood or the production of heavy oil, well test data cannot be interpreted using Newtonian fluid flow models. The resulting analysis would be erroneous because non-Newtonian fluids behave rather differently.
These results suggest the need for a thorough study of the behavior of non-Newtonian fluids in the reservoir and also a new look at the flow of those fluids in porous media.
This study presents an interpretation technique for pressure behavior of non-Newtonian fluid flow in a homogeneous reservoir without type-curve Matching. The inclusion of a no-flow and/or a constant pressure line is also investigated.
First, the TSD (Tiab’s Direct Synthesis) technique was applied for analyzing the pressure behavior of a well located in (1) an infinite reservoir and, (2) near a linear boundary where wellbore storage and skin effects were considered. The analysis required the generation of type-curve sets for different wellbore storage and skin values.
A step-by-step procedure is presented for the calculation of the reservoir parameters: the permeability/viscosity ratio, wellbore storage coefficient, skin factor and the distance to the nearest boundary without the use of type-curve Matching. The procedure is illustrated by an example.
An Investigation of Horizontal Well Completions Using a Two-Phase Model Coupling Reservoir and Horizontal Well Flow Dynamics
Authors: Vicente Ronaldo , Sarica Cem , Ertekin Turgay 
Published: December 2007

Abstract
A fully implicit, three-dimensional simulator with local hybrid grid refinement around the wellbore solving reservoir and horizontal well flow equations simultaneously for liquid-gas flow systems is used to investigate the effects of permeability, gas saturation, well length, well diameter, reservoir anisotropy and perforation/slot phase angle on the well productivity behavior. In addition, the effect of the coil-tubing diameter on the two-phase production logging measurements is studied. The model implements the conservation of mass equations in the reservoir and conservation of mass and momentum in the wellbore for isothermal conditions. The establishment of the continuity of pressure and preservation of mass balance at the sandface satisfy the coupling requirements between the two computational domains. The hydrodynamic model for the wellbore is based on the homogeneous flow assumption.
In this paper, we show that the indiscriminate use of single-phase flow models to predict the productivity of horizontal wells producing under multi-phase flow conditions can lead to significant errors and the magnitude of the discrepancy increases with reservoir permeability and gas saturation. Also, for multiphase flow conditions, pressure drop along the wellbore plays a crucial role in the asymmetrical flux distribution profile and should not be ignored. The seriousness of the problem is considerably aggravated in long wells, slim holes, high permeabilities and high gas saturation systems. In some completion designs, the simulations have shown that 70% of the production comes from the first 1/6 of the total well length. In other examples, the last third of the well length contributes with less then 2% of the total production. It has been shown that in anisotropic systems, a more uniform flux distribution is obtained with openings aligned orthogonal to the larger permeability direction. Regarding to production logging applications, a significant deviation on the measurements and actual behavior can be observed, depending especially on the ratio between well and coil tubing diameter. The proposed model can be a useful tool in generating the appropriate corrections for the undesirable effects of the coil tubing on production logging measurements.
Numerical Simulation of Water Injection in 2D Fractured Media Using Discrete-Fracture Model
Authors: Karimi-Fard M. , Firoozabadi A. 
Published: December 2007

Abstract
Numerical simulation of water injection in discrete fractured media with capillary pressure is a challenge. Dual-porosity models in view of their strength and simplicity can be mainly used for sugar-cube representation of fractured media. In such a representation, the transfer function between the fracture and the matrix block can be readily calculated for water-wet media. For a mixed-wet system, the evaluation of the transfer function becomes complicated due to the effect of gravity.
In this work, we use a discrete-fracture model in which the fractures are discretized as one dimensional entities to account for fracture thickness by an integral form of the flow equations. This simple step greatly improves the numerical solution. Then the discrete-fracture model is implemented using a Galerkin finite element method. The robustness and the accuracy of the approach are shown through several examples. First we consider a single fracture in a rock matrix and compare the results of the discrete-fracture model with a single-porosity model. Then, we use the discrete-fracture model in more complex configurations. Numerical simulations are carried out in water-wet media as well as in mixed-wet media to study the effect of matrix and fracture capillary pressures.
Assessing Uncertainty in Channelized Reservoirs Using Experimental Designs
Authors: Friedmann F. , Chawathé A. , Larue D. K. 
Published: December 2007

Abstract
It is well established that uncertainty exists in simulated recovery forecasts due to the ambiguity in the measurement and representation of the reservoir and geologic parameters. This is especially true for immature projects, such as deep-water reservoirs, where the high cost of data limits the information that is available to build reservoir models. We present two strategies, based on Experimental Design, to quantitatively assess this uncertainty in recovery predictions for primary and waterflood processes.
We apply the Experimental Design methodology to channelized sandstone systems because of their relevance to many deep-water projects. We choose to study synthetic geological analogs of channelized systems that are built from panoply of relevant parameters while taking into account the uncertainty that exists in the estimation of their ranges. We use the results of this study to generate type curves with neural networks. The trained neural networks can be used to rapidly predict reservoir performance where field data is very limited. We discuss applications of this methodology on field cases from western Africa.