bluuebunny/crossref_metadata_2025_split huggingface dataset:
Openhole Expandable-Sand-Screen Completions in Brunei
Authors: Lau Hon Chung , Vliet Jacques van , Ward Mike , Morin David , Djamil Arifun , Kuhnert Paul , Aldaz Walter , Shanks Steven 
Published: December 2007

Summary
Expandable sand screens were deployed successfully as a sand-control device in two horizontal openhole completions in two geologically different offshore fields in Brunei. A critical success factor was the choice of a drill-in fluid (DIF) that maintained hole stability and gave a near-gauge hole while running and expanding the sand screen. Field experience and extensive research led to the choice of a synthetic-based DIF for one well but a water-based one for the other. Challenges unique to the deployment of expandable sand screens in these wells are discussed.
New Rheological Correlations for Guar Foam Fluids
Authors: Khade Sudhakar D. , Shah Subhash N. 
Published: December 2007

Summary
Foams provide a highly attractive alternative to conventional non-Newtonian fluids for various oil and gas applications because of their high viscosity and low liquid content. Foams have a long history of proven performance in well stimulations, drilling, acidizing, cleanout operations, and enhanced oil recovery (EOR). Foam apparent viscosity is used in hydraulic (pressure drop) calculations for various pumping operations. Thus, accurate rheological characterization is very important to predict foam viscosity.
In this investigation, rheological experiments are carried out with guar gel and guar foam fluids with a ½-in.-pipe viscometer at 1,000 psi and temperatures ranging from 100 to 200°F. Guar, surfactant, and nitrogen (N2) are used as the gelling agent, foaming agent, and gas phase, respectively. Formulations were prepared and tested at several flow rates for qualities ranging from 0 to 80%.
This study has shown that both guar gel and guar foam fluids exhibit behavior analogous to the power-law model fluid. The experimental data are used to develop new rheological correlations to predict power-law fluid-flow parameters and, thus, the apparent viscosity of the foam fluids. These new correlations are functions of temperature, foam quality, shear rate, and fluid concentrations and were compared with various published correlations. The available correlations in the literature have assumed that the foam's flow behavior index is similar to that of the liquid phase. This assumption does not support the basic physics that the increase in viscosity decreases the flow behavior index. Our results show that the previous assumption is invalid and leads to a prediction of extremely low apparent viscosity for foam fluids. In contrast to previous studies, we report high apparent viscosities of high-quality foam fluids.
Multiple-Phase Generation During Carbon Dioxide Flooding
Authors: Henry Richard L. , Metcalfe Robert S. 
Published: December 2007

Abstract
This paper describes research to determine the pressure and temperature region in which multiple phases are generated for selected reservoir oils displaced by CO2. The major purposes of this study were (1) to determine whether single-contact PVT conditions and multiple-contact flow generated multiple phases over equivalent pressures and temperatures, and (2) to determine whether multiple-phase generation would affect mobility.
Multiple phases were generated for two reservoir oils of similar composition above the CO2 minimum miscibility pressures (MMP's) for temperatures between 307.5 and 322 K. For a limited temperature range, the pressures over which these multiple phases were observed agreed fairly well with those determined in single-contact PVT cell studies. However, multiple phases were also seen at higher temperatures in the multiple-contact displacements.
Pressure-drop data as a function of CO2 injection volume were obtained for displacements within the multiple-phase region and for displacements conducted at pressures above the multiple-phase region. Comparison of these data indicates that multiple-phase generation reduces mobility within the flow system used. Mobility reduction would be beneficial during application of CO2 flooding on a reservoir scale.
The Effect of Several Polymers on the Phase Behavior of Micellar Fluids
Authors: Pope Gary A. , Tsaur Kerming , Schechter Robert S. , Wang Ben 
Published: December 2007

AbstractWe made static measurements of the phase volumes of mixtures of surfactant, polymer, alcohol, water, oil, sodium chloride, and in some cases polymer additives. We also made a limited number of viscosity, phase concentration, and interfacial tension (IFT) measurements. The purpose was to determine systematically the effect of various polymers on the phase behavior of various surfactant formulations. We made measurements with and without oil (n-octane and n-octane/benzene mixtures) across a range of salinity appropriate to the particular surfactant at temperatures between 24 and 75°C.
Accurate Subgrid Models for Two-Phase Flow in Heterogeneous Reservoirs
Authors: Efendiev Yalchin R. , Durlofsky Louis J. 
Published: December 2007

Summary
Subgrid effects can have a strong influence on flow and transport in oil reservoirs. In this work, a new model for the representation of subgrid terms is introduced and applied to two-phase reservoir flows. The model entails a generalized convection-diffusion treatment of the saturation equation as well as an extended representation for total mobility in the pressure equation. Motivation for the form of the model is provided through a consideration of volume averaging and homogenization results. The numerical computation of the subgrid terms and the implementation of the overall method are described. The accuracy of the new subgrid representation is compared to that of coarse-scale models with no subgrid treatment and to coarse models based on pseudorelative permeabilities. The new model consistently provides more accurate overall coarse-scale predictions, relative to reference fine-scale results, than the other coarse-scale models, particularly in cases when the global boundary conditions vary in time.
Surface Chemistry of Oil Recovery From Fractured, Oil-Wet, Carbonate Formations
Authors: Hirasaki George , Zhang Danhua Leslie 
Published: December 2007

SummaryOil recovery by waterflooding in fractured formations is often dependent on spontaneous imbibition. However, spontaneous imbibition is often insignificant in oil-wet, carbonate rocks. Sodium carbonate and anionic surfactant solutions are evaluated for enhancing oil recovery by spontaneous imbibition from oil-wet carbonate rocks. Crude-oil samples must be free of surface-active contaminants to be representative of the reservoir. Calcite, which is normally positively charged, can be made negative with sodium carbonate. The ease of wettability alteration is a function of the aging time and temperature and the surfactant formulation.
Compaction-Induced Porosity/Permeability Reduction in Sandstone Reservoirs: Data and Model for Elasticity-Dominated Deformation
Authors: Schutjens P. M. T. M. , Hanssen T. H. , Hettema M. H. H. , Merour J. , de Bree P. , Coremans J. W. A. , Helliesen G. 
Published: December 2007

Summary
Open literature and new experimental compaction data from five reservoir and 16 outcrop sandstones are used to delineate the near-elastic, inelastic, and failure domains in 3D-stress space for porosity classes of 5 to 15%, 15 to 25%, and 25 to 35%. Applications of this compaction-domain model include the analysis of the extent of the near-elastic domain (where elasticity theory can be used to describe and predict rock deformation), the pore-volume compressibility (Cpp), and the permeability reduction as a function of reservoir stress path. This is illustrated for a well-consolidated sandstone reservoir with an average porosity of approximately 18%. Two aspects of dynamic reservoir modeling in the near-elastic domain are addressed: calculation of Cpp from raw volumetric-compaction data as a function of isotropic total stress change, and the correction of Cpp for a nonhydrostatic reservoir stress path. Open-literature work combined with our experimental data indicates that the compaction-induced permeability reduction of 15 to 25% porosity sandstone in the near-elastic domain depends predominantly on the increase of the effective mean stress, not on the reservoir stress path.
Numerical Simulation and Sensitivity Analysis of Gravity-Assisted Tertiary Gas-Injection Processes
Authors: Ren W. , Cunha L. B. , Bentsen R. 
Published: December 2007

SummaryCorefloods and field investigations confirm that a large amount of incremental tertiary oil can be recovered from dipping waterdrive reservoirs using gravity-assisted tertiary gas-injection processes. These processes include the double-displacement process (DDP) and the second-contact water-displacement (SCWD) process. The DDP consists of injecting gas into waterflooded oil zones. The SCWD process consists of submitting these gasflooded zones to a new water-displacement process.Reservoir simulations performed with an adaptive-implicit simulator were applied to investigate the macroscopic mechanisms of the two processes. The effects of several important parameters on the performance of the DDP were studied to optimize the oil production of the process. Moreover, the SCWD process was simulated to investigate its feasibility.The results show that both processes are efficient methods for recovering the residual oil to water. A good representation of the laboratory results was obtained through the simulations. It was confirmed that oil-film flow plays a very important role in achieving high recovery efficiencies in the DDP. In the SCWD process, trapped gas reduces the possibility of the residual oil being trapped in the center of pores in the secondary water invasion. Consequently, residual oil can be recovered quickly by a second water-flood. Therefore, the SCWD process is suitable for application in situations in which the source of gas is not sufficient, and where the formation has a high irreducible gas saturation.
Identifying Reservoir Compartmentalization and Flow Barriers From Primary Production Using Streamline Diffusive Time of Flight
Authors: He Zhong , Parikh Harshal , Datta-Gupta Akhil , Perez Jorge , Pham Tai 
Published: December 2007

Summary
We propose a novel approach that uses streamline-based drainage-volume computations using a "diffusive time of flight" to infer reservoir compartmentalization during primary production. Our approach consists of three steps. First, we perform a traditional decline-type-curve analysis of the primary production data to identify well communications and estimate the drainage volume of individual wells. Second, starting with a geological model, the drainage volumes of each well are recomputed with a streamline-based flow simulation. Finally, flow barriers and reservoir compartmentalization are inferred through a matching of the streamline-based drainage volumes with those from the decline-curve analysis.
Our approach is completely general and can be applied to reservoirs in the early stages of field development and with very few wells. We demonstrate the power and utility of our proposed method using synthetic and field examples. The field example is from a field in the Gulf of Mexico. Starting with a reservoir model based on well-log and seismic data, reservoir compartmentalization and flow barriers are identified from 3 years of primary production response.
Modeling of Both Near-Wellbore Damage and Natural Cleanup of Horizontal Wells Drilled With Water-Based Drilling Fluids
Authors: Ding Y. , Longeron D. , Renard G. , Audibert A. 
Published: December 2007

SummaryPrediction of formation damage that occurs in horizontal wells, often openhole completed, is a critical point for optimizing an oilfield development. The economic impact of near-wellbore induced drilling damage and cleanup efficiency has led to significant progress in both experimental and numerical studies designed to assess the wellbore flow properties during oil production.In a previous paper, a methodology combining both experimental and numerical approaches was presented to evaluate the natural cleanup of horizontal wells drilled with an oil-based mud (OBM). This paper presents an extension of the methodology for simulating both (a) near-wellbore invasion and permeability damage generated with a water-based mud (WBM), and (b) natural cleanup during oil backflow when the well is put into production. There is a fundamental difference between WBM and OBM invasions. In an oil-bearing formation, the displacement of the oil in place with an OBM filtrate is a miscible displacement process, while the displacement with a WBM filtrate is a two-phase flow process (imbibition), generating high wetting-phase saturation in the invaded zone. Then, during oil backflow, a portion of the wetting phase is trapped, leading to residual wetting-phase saturation greater than the initial one. Even in the absence of chemical interaction between filtrate and fluids in place, this induces an adverse water/oil relative permeability effect, which is an additional permeability impairment.This paper describes a numerical approach to model the formation damage with WBM and to predict well performance for natural cleanup when the well is subject to a pressure drawdown. The kinetics of fluid filtrate invasion, the filter-cake properties, and the filtrate/oil relative permeability curves in imbibition and drainage, together with damaged and return permeabilities, are obtained from specific drilling fluid damage laboratory tests. Using these data, the fluid filtrate invasion during the drilling phase is simulated, leading to a cone-type invasion depth along the horizontal well. This approach has allowed us to study the impact of various parameters related to fluids or cake properties, drilling conditions, and natural cleanup processes on the well performance.
Optimal Injection Strategies for Foam IOR
Authors: Shan D. , Rossen W. R. 
Published: December 2007

SummaryMiscible-gas foam field trials have employed a variety of injection strategies, with mixed results. Using simulation, we compare foam-injection strategies in homogeneous reservoirs with a variety of foam models. The optimal injection strategy for overcoming gravity override with foam in a homogeneous reservoir is alternating injection of separate, large slugs of gas and liquid at fixed, maximum-allowable injection pressure. This strategy minimizes both gravity override and time of injection, with minimal rise in injection-well pressure. Injection of gas at maximum pressure can partially reverse the effects of gravity slumping of surfactant during injection of liquid. The process is remarkably insensitive to the detailed properties of the foam, as long as foam does not collapse abruptly and completely at a "limiting water saturation" Sw*. However, care is needed to exclude the effects of numerical artifacts in simulating such a process, especially if foam collapses abruptly and completely at Sw*.An idealized model for the process reveals the mechanisms responsible for process success, why injection at fixed injection pressure is better than injection at fixed rate, why details of foam behavior play a secondary role in sweep efficiency, and why numerical artifacts can be difficult to identify.
A Case Study in the Design and Execution of Subsea Production Development Wells in the Captain Field
Authors: Rae G. , Hampson J. , Hiscox I. , Rennie M. , Morrison A. , Ramsay D. 
Published: December 2007

Summary
This paper outlines the challenges presented and the solutions chosen in executing the subsea-production-well construction design for the Captain Area B subsea development (see Fig. 1). It gives an overview of how a blend of proven and emerging technologies can be applied to develop such fields in innovative ways to meet performance metrices.
Insights Into Upscaling Using 3D Streamlines
Authors: Chawathé Adwait , Taggart Ian 
Published: December 2007

SummaryLarge, multimillion-cell geological models are frequently constructed in an effort to "capture" the vertical heterogeneity measured by well logs and the areal heterogeneity inferred by the depositional environments. These criteria often result in fine-scale models at a resolution of 0.1 to 0.3 m vertically and 30 to 100 m areally, resulting in reservoir models on the order of 107 grid cells. Recourse is made to upscaling to obtain coarsened but computationally efficient flow-simulation models. The coarsened models commonly result in no more than 1 to 5% of the original grid size, underscoring the need for judicious upscaling. Of greater importance is demonstrating, for the chosen grid dimensions, that the upscaled representation is both reasonable and optimal in the sense that a significantly better template would be difficult to obtain.We consider two nonuniformly coarsened models to demonstrate the issues involved and show that the use of 3D streamline methods offers insightful alternatives to decoupled analysis for both the scaleup template design and the pre- and post-diagnostics. We confine ourselves to property-upscaling methods that use local grid information as opposed to estimating upscaled properties based on some global measure. For this class of problems, we demonstrate that the diagnostic phases are necessarily separate from the upgridding and upscaling processes.
Estimating Non-Darcy Flow Coefficient From Buildup-Test Data With Wellbore Storage
Authors: Spivey J. P. , Brown K. G. , Sawyer W. K. , Frantz J. H. 
Published: December 2007

SummaryAn algorithm has been developed for computing the pressure response for a well with constant wellbore storage and non-Darcy skin factor across the completion. The algorithm has been used to generate type curves for drawdown and buildup tests. The buildup-pressure-derivative response for a well with non-Darcy flow across the completion exhibits a much steeper slope during the transition out of wellbore storage than that of a well with constant skin.No reservoir model with constant wellbore storage and skin can reproduce this steep derivative. Thus, if it is present in a buildup test, the well is experiencing either decreasing wellbore storage or decreasing skin factor, or both.With the new type curves, under favorable conditions, both Darcy and non-Darcy skin components may be estimated from a single buildup test following constant-rate production. The new algorithm also may be used to model a test sequence comprising multiple flow and buildup periods.
Scalability of the Deterministic and Bayesian Approaches to Production-Data Integration Into Reservoir Models
Authors: Vega Leonardo , Rojas Danny , Datta-Gupta Akhil 
Published: December 2007

SummaryCurrent techniques for production-data integration into reservoir models can be broadly grouped into two categories: deterministic and Bayesian. The deterministic approach relies on imposing parameter-smoothness constraints using spatial derivatives to ensure large-scale changes consistent with the low resolution of the production data. The Bayesian approach is based on prior estimates of model statistics such as parameter covariance and data errors and attempts to generate posterior models consistent with the static and dynamic data. Both approaches have been successful for field-scale applications, although the computational costs associated with the two methods can vary widely. To date, no systematic study has been carried out to examine the scaling properties and relative merits of the methods.We systematically investigate the scaling of the computational costs for the deterministic and the Bayesian approaches for realistic field-scale applications. Our results indicate that the deterministic approach exhibits a linear increase in the CPU time with model size compared to a quadratic increase for the Bayesian approach. We also propose a fast and robust adaptation of the Bayesian formulation that preserves the statistical foundation of the Bayesian method and at the same time has a scaling property similar to that of the deterministic approach. We demonstrate the power and utility of our proposed method using synthetic examples and a field example from the Goldsmith field, a carbonate reservoir in west Texas.
Competing Roles of Interfacial Tension and Surfactant Equivalent Weight in the Development of a Chemical Flood
Authors: Enedy S. L. , Farouq Ali S. M. , Stahl C. D. 
Published: December 2007

Abstract
This investigation focused on developing an efficient chemical flooding process by use of dilute surfactant/polymer slugs. The competing roles of interfacial tension (IFT) and equivalent weight (EW) of the surfactant used, as well as the effect of different types of preflushes on tertiary oil recovery, were studied. Volume of residual oil recovered per gram of surfactant used was examined as a function of these variables and slug size.
Tertiary oil recovery increased with an increase in the dilute surfactant slug size and buffer viscosity. However, low IFT does not ensure high oil recovery. An increase in surfactant EW used actually can lead to a decrease in oil recovery. Tertiary oil recovery was also sensitive to preflush type. Reasons for the observed behavior are examined in relation to the surfactant properties as well as to adsorption and retention.
New Iterative Coupling Between a Reservoir Simulator and a Geomechanics Module
Authors: Tran David , Nghiem Long , Settari Antonin 
Published: December 2007

SummaryInteractions of solid mechanics and fluid flow have been studied by numerous researchers for the past several years. Different methods of coupling such as full and iterative coupling have been used. Nevertheless, the accuracy and the large run time of the coupled solid-mechanics fluid-flow model are outstanding issues that prevent the application of the coupled model in full-field studies. In this work, a novel relationship of porosity as a function of pressure, temperature, and mean total stress is developed for iterative coupling of stress and flow. The new formula not only improves the accuracy of the coupling but also reduces substantially the number of coupling iterations. The latter feature decreases significantly the CPU time. The new approach was implemented in a modular, iteratively coupled system. The rapid convergence provides the equivalent of a fully coupled method that is necessary to investigate complex coupled problems. The main advantage of this type of coupling is that a geomechanics module can be easily coupled with different reservoir simulators. The paper gives some comparisons of results obtained by the new porosity formula with another formulation.
Pressure/Pressure Convolution Analysis of Multiprobe and Packer-Probe Wireline Formation Tester Data
Authors: Onur Mustafa , Hegeman Peter S. , Kuchuk Fikri J. 
Published: December 2007

Summary
In cases in which flow-rate data are not reliable, the need for flow rate in estimating permeability from wireline formation tester multiprobe and packer-probe pressure-data sets can be eliminated by the use of the so-called pressure/pressure (p/p) convolution. The p/p convolution is based on the use of different pressure-data sets recorded at two different spatial locations and thus enables one to perform parameter estimation without flow rate. In this work, we present a detailed analysis of multiprobe and packer-probe pressure-transient tests by considering various p/p convolution options for both single-layer and multilayer systems. Approximate equations that apply during spherical and radial flow for a vertical well in a single-layer system for various p/p convolution options are derived. These equations indicate which parameters can be determined uniquely from p/p convolution. It is shown that p/p convolution analysis sometimes may not provide unique parameter estimates. Also, we provide a flow-rate-estimation method that proves useful to check the validity of parameter estimates obtained from p/p convolution analysis. Two example tests, a synthetic multiprobe test and a field packer-probe test, are given to illustrate the methodology and procedures developed in this work.