bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Practice of Applying Downhole Real Time Gauge Data and Control-Valve Settings to Estimate Split Flow Rate for an Intelligent Injection Well System
Authors: Sun Kai , Coull Craig , Constantine Jesse 
Published: September 2008

Abstract
Because an Intelligent Well System (IWS) normally addresses multiple zones of production/injection, knowing the exact flow allocation for each controlled zone is important for well optimization and management. In an IWS well, downhole gauges are usually installed at the upstream and downstream sides of a downhole control valve to monitor pressure and temperature. This type of gauge installation configuration makes it possible to estimate the flow allocations through the downhole valve. Many discussions and practices have applied this method, but seldom have successful application cases been published until now.
This paper will discuss a recent application of this method to estimate the flow rate for a dump-flooding intelligent injection well system. In this case, the downhole control valve was kept 100% open, a condition which has been well-recognized for its difficulty in flow rate estimation.
Verification was completed by comparing the different time series predicted results with the flow rate logging data. The comparison showed differences within ±10% range when the injection flow through the choke reached steady state flow conditions.
A discussion of three key factors addresses the accuracy of the method: The compensated differential pressures though the valve.Reliable flow characterization modelsFluid p-v-T behavior impact.
Flow tests provide reliable information to characterize flow through the control valves. A comprehensive hydraulics model addresses the hydrostatic and frictional pressure drop, analyzes fluid p-v-T behavior, and solves the flow rate/pressure profile numerically.
Injectivity Characteristics of EOR Polymers
Authors: Seright R. S. , Seheult Mac , Talashek Todd 
Published: September 2008

Abstract
This paper estimates injectivity losses associated with injection of EOR polymer solutions if fractures are not open and considers the degree of fracture extension if fractures are open. Three principal EOR polymer properties are examined that affect injectivity: (1) debris in the polymer, (2) polymer rheology in porous media, and (3) polymer mechanical degradation. Using Berea sandstone cores (100-600 md) and various filters and filter combinations, an improved test was developed of the tendency for EOR polymers to plug porous media. The new test demonstrated that plugging tendencies varied considerably among both partially hydrolyzed polyacrylamide (HPAM) and xanthan polymers.
Rheology and mechanical degradation in porous media were quantified for a xanthan and an HPAM polymer. Consistent with previous work, we confirmed that xanthan solutions show pseudoplastic behavior in porous rock that closely parallels that in a viscometer. Xanthan was remarkably resistant to mechanical degradation, with a 0.1% xanthan solution (in seawater) experiencing only a 19% viscosity loss after flow through 102-md Berea sandstone at a pressure gradient of 24,600 psi/ft.
For 0.1% HPAM in both 0.3% NaCl brine and seawater in 573-md Berea sandstone, Newtonian behavior was observed at low to moderate fluid fluxes, while pseudodilatant behavior was seen at moderate to high fluxes. No evidence of pseudoplastic behavior was seen in the porous rock, even though one solution exhibited a power-law index of 0.64 in a viscometer. For this HPAM in both brines, the onset of mechanical degradation occurred at a flux of 14 ft/d in 573-md Berea.
Considering the polymer solutions investigated, satisfactory injection of more than 0.1 PV in field applications could only be expected for the cleanest polymers (i.e., that do not plug before 1,000 cm3/cm2 throughput), without inducing fractures (or formation parts for unconsolidated sands). Even in the absence of face plugging, the viscous nature of the solutions investigated requires that injectivity must be less than one-fifth that of water if formation parting is to be avoided (unless the injectant reduces the residual oil saturation and substantially increases the relative permeability to water). Since injectivity reductions of this magnitude are often economically unacceptable, fractures or fracture-like features are expected to open and extend significantly during the course of most polymer floods. Thus, an understanding of the orientation and growth of fractures may be crucial for EOR projects where polymer solutions are injected.
An Integrated Theoretical and Experimental Study on the Effects of Multiscale Heterogeneities in Matrix Acidizing of Carbonates
Authors: Izgec O. , Keys R. , Zhu D. , Hill A. D. 
Published: September 2008

Abstract
Carbonates often have small (micron) to large (centimeter) scale heterogeneities in flow properties that may cause the effects of injected acids to differ greatly from what is predicted by a model based on a homogenous formation. To the best of our knowledge, there are neither theoretical nor experimental studies on the effect of large scale heterogeneities (vugs) on matrix acidizing. The abundance of carbonate reservoirs (60% of the world's oil reserves) and the lack of a detailed study on the effect of multi-scale heterogeneities in carbonate acidizing are the main motivations behind this study.
In this work, we first present a methodology to characterize the carbonate cores prior to the core-flood acidizing experiments. Our approach consists of characterization of the fine-scale (millimeter) heterogeneities using computerized tomography (CT) and geostatistics, and the larger-scale (millimeter to centimeter) heterogeneities using a connected component labeling algorithm. In order to understand the connectivity of vugs and thus their contribution to flow, a 2D visualization algorithm, connected component labeling (CCL), was implemented in a 3-dimension system.
After multi-scale characterization of the cores, acid core-flood experiments were conducted. 4-inch diameters by 20-inch long cores were used to decrease the geometric effects on the wormhole path. The post acid injection porosity distribution and wormhole paths were visualized after the experiments.
The results demonstrate that acid follows not only the high permeability paths but also the spatially correlated ones. While the connectivity between the vugs and size of the core is the predominant factor, spatial correlation of the petro-physical properties has less pronounced effect on wormhole propagation in acidization of carbonates.
Irreducible Water Saturation Has Been Determined As the Key Factor Governing Hydrocarbon Production from Low Permeability Carbonate at the Wattenberg Field in the Denver Julesburg Basin
Authors: Yang Yuanhai , Birmingham Thomas 
Published: September 2008

Abstract
It is commonly known that geological structure and its resultant natural fractures are the predominant factors governing hydrocarbon production from carbonate reservoirs. Through a detailed petrophysical study on a low permeability carbonate play, the authors have obtained new understandings toward the reservoir properties of low permeability carbonate. First, in absent of major geological structures, reduced relative permeability to hydrocarbon is the primary trapping mechanism. Second, the irreducible water saturation range for low permeability carbonate increases significantly. Third, the enlarged irreducible water saturation range makes the curve of relative permeability to hydrocarbon much steep. Therefore, the relative permeability to hydrocarbon is very sensitive to water saturation, and formation water saturation becomes a critical factor affecting hydrocarbon production. The results of this petrophysical study have been successfully applied to identity the "fairways" among a huge low permeability carbonate deposition.
Experimental Study on Downhole Gas-Liquid Separation and Produced Water Reinjection
Authors: Wang Zunce , Wang Xiaoping , Li Sen , Xu Yan , Zhang Jinglong , Lv Fengxia 
Published: September 2008

Abstract
Gas well fluid accumulation caused by floodout is an important problem to restrict natural gas exploitation. To solve the problem by using dewatering gas production is an effective method. For convention gas well production with water withdrawal technics, accumulated water is lifted to ground, gas-liquid mixture is treated on the surface, and separated water is reinjected back into the formation, which resultes in many problems, such as more equipment and investment needed, and other environmental pollution issues. For the purpose of clean, low input and high output, a cost-effective and simple downhole gas-liquid separation and water injection system is developed.
A downhole gas-liquid separation and water reinjection process is proposed in this paper. The core components of the system are the improving hollow rotor screw pump and downhole gas-liquid separator. The gas-liquid recovery and impetus providing for the separation and reinjection water pressure are achieved through a hollow screw pump rotor. The separated gas is produced through casing, and isolated from the underground water through hollow screw pump rotor to provide access for reinjection. The system experiments carried out at Shen 14-6 gas well in Shenyang Oil Production Plant, Liaohe Oilfield, China get a satisfactory result.
Chemical Intervention Technology For Low-Risk Annular Isolation In Existing Gravel Packed Wells And Uncemented Annuli
Authors: Cole-Hamilton Jim , Curtis James 
Published: September 2008

Abstract
It is often desirable to be able to intervene to isolate specific areas within a wellbore. Throughout the life of a well, undesirable changes to production such as increased water may occur that cannot be easily dealt with using mechanical means, unless the completion has been designed with this in mind. Examples include flow through uncemented annuli, or from part of a gravel packed completion. In such cases, a possible solution may be to pump a treating fluid with properties that will provide the isolation required. Several different systems are available such as crosslinked polymer fluids, portland cement, or other hard setting materials.
This paper reviews the properties of one such product, a magnesia cement system, evolved from chemistry that had previously been employed in other applications. The new technology uses fine-grained materials that can be squeezed though small restrictions such as narrow annuli, slots or perforations, or through well screens and into the gravel pack beyond, where later they will set hard and provide selective isolation of the treated section to prevent the flow of unwanted fluids. As with the original chemistry, the new system is composed of acid soluble components, allowing the solid set material to be removed in the future should it be required.
This paper will identify the requirements associated with selecting hard setting materials use in for zonal isolation. It will discuss the development of this squeezable magnesia cement system, showing how it meets these requirements. The results of extensive laboratory evaluations will be reviewed and recent case histories will be discussed.
This technology is expected to find wide application in many existing gravel-packed and un-cemented wells worldwide, when low risk long-term zonal isolation becomes required.
Enabling Efficient Permanent Production Monitoring of Advanced Well Completions in Saudi Arabia Using Fiber Optic Distributed Temperature Sensing
Authors: Hembling Drew , Berberian Garabed , Carter Neale , Naldrett Garth 
Published: September 2008

Abstract
Although the recent focus in the industry on maximum reservoir contact (MRC) and Advanced well completions has provided significant improvements in reservoir depletion it has caused some data gathering disruptions for companies operating these wells. In particular, the options to perform well logging are much reduced, and the costs of performing a production log are extremely high. This is related to both the costs of the more advanced horizontal well logging tools and the more expensive logging methods, such as coiled tubing and tracker systems, used for the conveyance of these tools into the wellbore.
In an effort to acquire high quality downhole data in a timely manner in MRC wells, Saudi Aramco set about investigating the alternatives to traditional production logging methods. A technology gaining greater industry acceptance in recent years is permanently installed Distributed Temperature Sensing (DTS) and this became the focus of investigation. The limitations of conventional DTS technology was, however, soon realized; In particular the limited temperature resolution offered was not sufficient for evaluating high angle maximum reservoir contact intelligent wells. At the time of investigation a new generation of DTS technology became commercially available, providing a 10-fold improvement in measurement resolution. This allowed Saudi Aramco to proceed with field trials of the technology.
This paper will present the requirements for advanced DTS technology to provide quality data sets for use in rate and density modeling in highly deviated MRC wells.
In addition, the installation of the downhole hardware in an advanced well completion and the data from the field trials will be presented.
The Displacement of Oil by Polymer Slugs Considering Adsorption Effects
Authors: Ribeiro P. M. , Pires A. P. 
Published: September 2008

Abstract
Oil displacement by injection of chemical solutions is a widespread Enhanced Oil Recovery method. Analytical models for one-dimensional displacement of oil by water with chemical components have been developed since the 1960´s. This problem involves complex physical-chemical processes of interphase mass transfer, phase transitions and transport properties changes. The continuous injection of this kind of fluid would be very expensive, so, the injection of chemical slugs is an attractive alternative to improve the recovery of mature oil fields. The continuous injection of chemical solutions is a Riemann problem, easily solved by the introduction of a self-similar variable. Nevertheless, the slug injection is not self-similar, and the problem becomes much more complex from the mathematical point of view. This paper presents the analytical solution of chemical slug injection in an oil reservoir. A flow potential associated with the conservation of the aqueous phase is introduced as a new independent variable instead of time. This change of variables allows the system splitting into one equation (lifting equation) and a thermodynamic system (auxiliary system). The number of auxiliary equations is less than the number of equations in the compositional model by one. In this paper different adsorption isotherms were analyzed. The transport equation solution, or lifting problem solution involves interaction between waves of different families and allows the design of slug sizes in order to obtain the maximum efficiency of this process. Another important application of these solutions is the prediction of chemical flooding regardless of the transport properties (relative permeabilities and viscosities). If the mobility ratio is close to one, this model may be applied in the development of streamlines simulators.
Wax Deposition in Pipelines: Flow-Loop Experiments and Investigations on a Novel Approach
Authors: Benallal Amine , Maurel Philippe , Agassant Jean François , Darbouret Myriam , Avril Guillaume , Peuriere Eric 
Published: September 2008

Abstract
Models used to predict wax deposits in oil production pipeline are based on thermodynamic properties coupled with several Fick's diffusion mechanisms. These models generally need fitting parameters to match computational results to experimental data, and moreover they do not explain all aspects of this phenomenon. One of these aspects is the "sticking" of the deposit to the wall. In this study, it is demonstrated that the deposit could result from flow patterns caused by rheological factors. Indeed, thermodynamic properties create the onset of wax crystals, and diffusion mechanisms result in the displacement and accumulation of wax in a particular region. This results in rheological changes that modify the flow pattern and create an unyielded region near the wall, namely a wax deposit. To highlight this process, experimental tests of wax deposition were performed on the Lyre loop at IFP-Lyon in Solaize, France. This loop is 140 meter long with a 2 inches internal diameter and is fully temperature-controlled. A wax deposition section consisting of a 7 meter sub-cooled section is integrated in this loop. A one-meter spool piece can be retrieved to observe and sample the wax deposit. Temperature, pressure drops and flow rate were monitored. The wax deposit was observed after 4h, 24h and 72h and was sampled for rheological measurements. The experimental results are presented in this paper. In addition, to analyse this experimental data, a numerical model based on the previously described physical aspects is implemented, and the results show good agreement with experimental data.
Prediction of Proppant Transport from Rheological Data
Authors: Harris Phillip C. , Walters Harold G. , Bryant Jason 
Published: September 2008

Abstract
Fracturing gels are formulated and viscosity parameters are measured to predict whether and help ensure that a fracturing treatment will be successful. Steady shear viscosity cannot measure the elastic component of viscoelastic fluids. Dynamic oscillatory shear can provide measurements of elastic properties, but such measurements are made in the absence of any particles. A third technique, a slurry viscometer (SV), can incorporate particles and measure proppant transport characteristics of the fluid. This paper compares all three measurement techniques for verification of transport prediction.
Steady shear viscosities of gelled fracturing fluids were measured using couette viscometers. Viscoelastic characteristics of the same fluids were measured with a dynamic oscillatory viscometer to determine G’ and G" moduli and crossover frequency. Proppant particles were added to these same fluids and properties measured with the SV to determine elastic transport and viscous transport times.
Comparison of the three data sets shows that the elastic modulus, G’, and crossover frequency have a high correlation with elastic transport times measured with the SV. Steady shear viscosities above 10 s-1 do not directly correlate with transport times.
Dynamic oscillatory measurements have been thought for years to predict particle transport phenomena, but any correlations that were generated could be incomplete because particles are excluded from the measurements. The SV does include particles in the fracturing gel, and can be used to verify trends of proppant transport indicated by G’ and the crossover frequency.
The Effect of Elasticity on Displacement Efficiency in the Lab and Results of High Concentration Polymer Flooding in the Field
Authors: Jiang Haifeng , Wu Wenxiang , Wang Demin , Zeng Yeming , Zhao Shiguang , Nie Jun 
Published: September 2008

Abstract
The elasticity of polymer solution is usually disregarded in the studies of polymer flooding. The common viewpoint is that the displacement efficiency is determined by the ratio of the pressure gradient and interfacial tension in the system. But new studies show, when the pressure gradient and interfacial tension are constant, that visco-elastic polymer flooding can achieve higher displacement efficiency (De).
In this paper, based on theoretical analysis and through large amounts of core tests on homogeneous water-wet and slightly oil-wet artificial cores, the influence of visco-elasticity of polymer solutions with different concentrations on De were studied at different capillary numbers (determined by the ratio of pressure gradient to interfacial tension). The results show that when the capillary numbers are the same, the higher the flooding fluid's elasticity, the higher the De and the lower the residual oil saturation in both oil-wet and water-wet cores. In the range of these tests, the effect of elasticity on De is about the same as that of ultra-low interfacial tension chemical flooding. It can also been seen that residual oil starts to mobilize at a lower capillary number with higher elasticity driving fluids.
In addition, flooding experiments in the lab on heterogeneous cores by high concentration polymer fluid show that the higher the concentration and viscosity of the driving fluid, the higher the De. High concentration polymer flooding was tested in 3 fields and show that the additional recovery is nearly 2 times that of conventional polymer flooding, obtaining an incremental recovery of more than 20%OOIP.
This conclusion is useful in further understanding the mechanism of polymer flooding, and it can provide further basis for choosing chemicals and determining chemical flooding designs in the field.
Model Building with Difficult Faults
Authors: Hoffman K. S. , Neave J. W. , Nilsen E. H. 
Published: September 2008

Abstract
Many of the commonly used fault modeling techniques can adequately handle simple structures – even when those structures contain large numbers of faults. It is not the sheer number of faults that is often the stumbling block, but rather the complexity of the fault/fault relationships. Common configurations such as a Y intersection formed by a synthetic/antithetic fault pair can be difficult to model due to the limitations of the framework-building technique. Often the truly difficult situations, such as listric faults, low angle faults, or crossing conjugate faults, are not even attempted – which means that the resulting reservoir models do not correctly represent the subsurface.
Our technique for building a fault framework provides a comprehensive solution for modeling any type of fault shape or fault intersection. Listric faults and Y-intersections, for example, must be treated as special cases with pillar-based methods, and a nested-Y structure is nearly impossible to model with this technique. Low angle faults and low angle intersections also pose problems for pillar-based methods; the low angle intersection can distort the shape of one or both faults. Crossing conjugate faults can create half-Y faults, which neither the pillar method nor the binary tree method can model.
The concept of compound relationships used in our approach, where faults are divided into sections based on their relationships with all faults which touch or cross it, allows independent manipulation of each small section of a fault. In this way, even the complex truncations of crossing conjugate faults are easily handled. The solid models and reservoir grids that are created based on these frameworks incorporate all of the complexity of the interpretation. These models provide a better basis for reservoir management decisions and can be shared by all of the disciplines within an asset team.
The advances in fault modeling shown here provide a comprehensive solution to handle all type of faults and fault intersections without any of the compromises previously necessary. The flexibility of the technique reduces cycle time for building the framework and allows for more in-depth investigation of reservoir properties.