bluuebunny/crossref_metadata_2025_split huggingface dataset:
Definitive Method of Flow Analysis of Surface Pipeline Networks
Authors: Kappos Leonidas , Economides Michael J. 
Published: December 2007

Abstract
The producing wells and the surface pipeline network comprise a dynamic system. Flow rate changes in the individual wells affect the flow in the pipeline network and the fluid distribution among the gathering stations and, vice versa. Many times, the surface network is constructed responding to the necessity of merely connecting the wells to the separators or gathering stations without accounting for the impact that dramatically increased or decreased well flow rates may have. Nevertheless, in the life span of a reservoir, the hydrocarbon production may be substantially altered owing to several processes that may take place, such as fracturing, or gas/water injection. Thus, it is imperative that the surface pipeline network be effectively designed to ensure an unobstructed production regardless of the well flow rates. It is readily acknowledged that a computational tool is needed to perform a hydraulic analysis of the pipeline network for any set of flowing conditions.
An iterative algorithm is developed for the quantitative analysis of any surface pipeline network configuration. Pipe gas flow under isothermal conditions is studied. The algorithm uses the minimal information that is commonly available for a surface pipeline network, namely the well mass flow rates, the temperature and molecular weight for the well pipes, the chokes pressures, the gathering stations pressures and the geometric characteristics of the pipes, and does not require the knowledge of the location of the split nodes. It calculates the mass flow rate, temperature and molecular weight in each pipe of the network as well as the nodal pressures. It also derives the flow direction in each pipe identifying the location of the split nodes. The algorithm incorporates an approximation scheme used for large and complex network configurations. The scheme is validated through mass balance and pressure drop tests. The algorithm is a generic tool of network analysis as it can be modified to account for liquid or two-phase flow in the pipes. Application of the iterative algorithm indicates a notable accuracy (the absolute error in calculating mass flow rates and nodal pressures is less than 1%).
Exploring Reservoir Engineering Aspects of Completion in Gas-Condensate Reservoirs: West African Examples
Authors: Kabir C. S. , Chang M-M. , Taghizadeh O. 
Published: December 2007

AbstractThis paper explores multiple completion options in gas-condensate reservoirs with compositional simulations. Besides intelligent well completion (IWC), other options included commingling two reservoirs of contrasting conductivity (permeability-thickness product), and selectively perforating zones or reservoirs to offset the permeability contrast. At the outset, a value of information exercise suggested probing downhole sensing and completion issues in a stacked-reservoir situation. The ultimate objective of this study was to ascertain economic completion strategy so that depletion of reservoirs occurs evenly at the project's termination.Single-well compositional simulations formed the backbone for our evaluation of three completion options. Each reservoir was characterized by history-matching drillstem tests. Experimental design reduced the large number of simulation runs to a manageable few for probabilistic forecasting. Comparison of three options suggested that all of them nearly produced the desired results of maximum liquid recovery, despite a ten-fold difference in permeability between the two horizons. As expected, direct commingling of reservoirs produced somewhat unfavorable results, which was mitigated by the other two completion options.Results further showed that condensate banking was a nonissue in this high-kh system of reservoirs as far as the gas deliverability is concerned. In other words, although 40% to 60% degradation in the gas productivity index (PI) occurred, gas deliverability remained intact. In contrast, both the liquid PI and rate declined with time owing to the phase-behavior issue. Finally, we learned that the net income generated by the IWC is no better than the selective-perforation completion (SPC).
Field and Laboratory Analyses of Effluent Water
Authors: Qabazard Hassan , Salman Mohammad , Moshfegian Mahmood 
Published: December 2007

Abstract
In order to establish water qualities for re-injection purposes, four crude oil gathering centers (GC) in of Kuwait were investigated. Extensive field and laboratory measurements were made for several sampling points. Two modes of operations, namely "normal operation" and "recycled operation" were studied. During the normal operation of a GC, the effluent water represents a mixture of wet tank water and desalter water. In recycled operation, the effluent water was pumped back into the wet tank and the water disposed from the wet tank. No conclusive observation was made on the quality of effluent water but water quality was much lower at the wet tank sampling point for recycled mode. The lowest water quality was at the discharge of the desalters sampling points. The corrosion rate in general was lower at the sampling points for recycled mode as compared to corresponding points in normal operation. However, total iron and soluble iron were much higher at different sampling points of recycled mode of operation. Detail field and laboratory measurement results for each sampling points is reported. The results of this study may be used for core flooding evaluation and also for compatibility analysis of water injection.
Klinkenberg-Corrected Permeability Measurements in Tight Gas Sands: Steady-State Versus Unsteady-State Techniques
Authors: Rushing J. A. , Newsham K. E. , Lasswell P. M. , Cox J. C. , Blasingame T. A. 
Published: December 2007

Abstract
This paper presents results from a laboratory study comparing Klinkenberg-corrected permeability measurements in tight gas sands using both a conventional steady-state technique and two commercially-available unsteady-state permeameters. We also investigated the effects of various rate and pressure testing conditions on steady-state flow measurements. Our study shows the unsteady-state technique consistently overestimates the steady-state permeabilities, even when the steady-state measurements are corrected for gas slippage and inertial effects. The differences are most significant for permeabilities less than about 0.01 md. We validated the steady-state Klinkenberg-corrected permeabilities with liquid permeabilities measured using both brine and kerosene. Although gas slippage effects are more pronounced with helium than with nitrogen, we also confirmed the steady-state results using two different gases. Moreover, we show results are similar for both constant backpressure and constant mass flow rate test conditions. Finally, our study illustrates the importance of using a finite backpressure to reduce non-Darcy flow effects, particularly for ultra low-permeability samples.
Modeling Proppant Settling in Water-Fracs
Authors: Gadde Phani B. , Liu Yajun , Norman Jay , Bonnecaze Roger , Sharma Mukul M. 
Published: December 2007

Abstract
Water-fracs, consisting of proppant pumped with un-gelled fluid are the type of stimulation used in many low-permeability reservoirs throughout the United States. The use of low viscosity, Newtonian, fluids allows the creation of long narrow fractures in the reservoir without the excessive height growth often seen with cross-linked fluids. Proppant transport is a central issue in all these treatments because of the low viscosity of the fracturing fluid.
New models for proppant transport and settling in hydraulic fractures were developed and implemented in a 3-d hydraulic fracturing code. It is shown that a simple Stokes settling model is grossly inadequate. The proppant settling models developed in this paper account for the effects of fracture walls, changes in settling velocities and rheology caused by changes in proppant concentration, turbulence effects due to high fluid velocities and inertial effects associated with large relative velocities between the proppant and the fluid. Narrower fractures, higher proppant concentration and smaller proppant size reduce settling whereas turbulence leads to an increase in settling. Results are presented to show how the settling velocities are impacted by fluid velocity, proppant size, fluid rheology and fracture width. In most instances settling velocities differ significantly from the Stokes settling velocity. The new proppant settling model was incorporated into a 3-D hydraulic fracture simulator (UTFRAC-3D). Simulation results show that when settling is accounted for, significantly shorter propped lengths are obtained. The narrow fractures associated with water-fracs alter settling and thereby alter the proppant placement significantly. Although increasing fluid viscosity can reduce settling rates, increased height growth reduces the distance to which proppant can be placed. This clearly suggests a need to optimize fluid rheology. The improved fracture simulator can be used to better design fracture treatments (fluid rheology, injection rates, proppant concentration and size) for better proppant placement under a given set of in-situ stress conditions.
Multi-Sensor through-Casing Density and Saturation Measurement Concepts with a Pulsed Neutron Source: A Modeling Assessment
Authors: Badruzzaman A. , Badruzzaman T. , Zalan T. A. , Mai K. 
Published: December 2007

Abstract
The paper discusses an assessment, using Monte Carlo modeling techniques, of the advantages we could derive and challenges we would face in utilizing multiple sensors with a pulsed neutron (PN) source for cased-hole logging to obtain petrophysical parameters. Current PN devices are primarily based on two detectors, with source-detector spacing often similar among the various vendors. We consider four sensors to investigate three measurement types, 1) a pseudo-density through casing concept that shows the potential to distinguish between gas and tight zones, 2) computing oil saturation from Carbon/Oxygen logs with oil present in the borehole, and 3) estimation of Sigma and hence water and steam saturation from PNC logs. We illustrate the advantages of using modeling to study measurement concepts independent of specific tools. We identify areas of further research in basic measurement concepts using pulsed sources and in related radiation transport theory.
New Estimate for the Radius of a Condensate Bank from Well Test Data Using Dry Gas Pseudo-Pressure
Authors: Bozorgzadeh Manijeh , Gringarten Alain C. 
Published: December 2007

AbstractPublished well test analyses in gas-condensate reservoirs where the pressure drops below the dew point are usually based on a two-or three-zone radial composite well test interpretation model to represent condensate dropout around the wellbore and initial gas in place away from the well. Gas condensate specific results from well test analysis are the mobility ratios between the various regions and the condensate bank radius. Unfortunately, for a given region, well test analysis cannot un-couple the storativity ratio from the region radius. The storativity ratio must therefore be estimated separately to obtain the bank radius.In this study, a new method is introduced to estimate the storativity ratios between the different zones as a function of the saturation profile during the test. The paper describes an application of the method to the analysis of a transient pressure test in a gas condensate field in the North Sea. The analysis uses single-phase pseudo-pressures and two- and three-zone radial composite well test interpretation models and yields the condensate bank radius.The calculated condensate bank radius is verified by comparing analytical well test analysis results with results from compositional simulations that include capillary number and inertia effects. It is shown that the proposed relationship between the condensate saturation profile at the time of shut-in and that at the end of shut-in yield a consistent interpretation of build-up data.
Impact of Relative Permeability Hysteresis on the Numerical Simulation of WAG Injection
Authors: Spiteri Elizabeth J. , Juanes Ruben 
Published: December 2007

Abstract
Pore-scale physics, laboratory investigations, and field experience, dictate that three-phase relative permeabilities exhibit strong dependence on the saturation path and the saturation history. Such dependence is especially relevant in water-alternating-gas (WAG) processes, which are characterized by a sequence of three-phase drainage and imbibition cycles. In this paper, we study the influence of relative permeability hysteresis on the field-scale predictions of WAG injection.
Because their measurement is difficult and timeconsuming, three-phase relative permeabilities are usually interpolated from two-phase data. The errors associated with this procedure have been investigated by Oak (SPE 20183), who reported that interpolated values may differ significantly from experimental ones. The effect of using different interpolation models in field-scale simulations has been illustrated by a number of authors, who found that recovery predictions could be significantly different depending on the three-phase relative permeability model.
Here, we study the impact of using history-dependent saturation functions in reservoir simulations. First, we investigate the degree of accuracy with which different hysteretic models reproduce Oak's three-phase relative permeability data. In doing so, we assess the validity of existing models, and we identify the model parameters subject to most uncertainty. Second, we illustrate how the use of a hysteretic relative permeability model affects reservoir simulations. We use a synthetic model of a quarter five-spot pattern in a homogenous reservoir, and a more realistic heterogeneous reservoir modified from the PUNQ-S3 model. We find that there is striking disparity in the simulation results depending on whether a hysteretic or a nonhysteretic model is employed, and conclude that it is essential to incorporate hysteresis in the relative permeabilities in order to obtain accurate predictions of realistic WAG processes.
Assessment of Global Uncertainty for Early Appraisal of Hydrocarbon Fields
Authors: Caumon G. , Strebelle S. , Caers J. K. , Journel A. G. 
Published: December 2007

Abstract
We propose a workflow to assess the uncertainty about a global reservoir parameter such as net-to-gross during early exploration. As opposed to traditional statistical approaches that assume data independence and cannot easily account for either seismic data or geological interpretation, this model, based on multiple point statistics, integrates the main components of uncertainty, namely: the choice of a geological scenario, probably the most important factor at the appraisal stage.The location of wells, which could have been drilled elsewhere, giving a different picture of the reservoir.The calibration of the seismic to the well data.
This global uncertainty model is demonstrated on a large 3D fluvial reservoir.
Top-Down Reservoir Modelling
Authors: Williams G. J. J. , Mansfield M. , MacDonald D. G. , Bush M. D 
Published: December 2007

Abstract
Over the last twenty or more years of reservoir performance prediction through simulation there have been only two fundamental changes. First was the evolutionary increase in computing speed that has allowed larger, more detailed reservoir models to be built. Second was the revolutionary change in approach that involved the entire subsurface community in building integrated reservoir descriptions. The next big change may in time prove to be BP's Top-Down Reservoir Modelling (TDRM). This is a new pragmatic approach to fully incorporate reservoir uncertainty in model construction and performance prediction.
TDRM is proprietary technology that has been developed in BP through extensive R&D, and consists of a philosophy and tools that enable a faster and more robust exploration of uncertainty than has hitherto been possible. The philosophy is to start investigations with the simplest possible model and simulator appropriate to the business decision. Detail is added later as required. The approach overcomes the problems of the conventional "bottom-up" process, which uses detailed models that are too slow and cumbersome to fully explore uncertainty and identify critical issues. Highly detailed models cannot overcome an underlying absence of information, and can have the negative effect of creating a false sense of understanding.
The TDRM tools have been designed to minimise manual iterations by creating a semi automated, flexible workflow for case management, assisted history matching, depletion planning optimisation and post-analysis. TDRM has been successfully applied to eighteen oil and gas reservoirs that range from development appraisal stage to mature fields, and has resulted in up to 20% increase in estimated net present value for the projects.
Special Non Polluting Emulsifier for Non Aqueous Drilling Fluids in Deep Offshore Drilling
Authors: Audibert A. , Dalmazzone C. , Dalmazzone D. , Dewattines C. 
Published: December 2007

Abstract
With the increasing number of deep offshore drilling operations and severe environmental constraints, operators and service companies are confronted to more and more complex technical challenges. Extreme conditions encountered at these water depths require an adaptation of the drilling mud composition and properties. In particular, range of temperature and pressure (close to 0 °C and up to 400 bar) are favorable conditions to the formation of gas hydrate solid structures that are liable to plug kill and choke lines as well as the annular, and may also cause interruption of the drilling operations and even destruction of the rig equipment. Oil based muds generally formulated as invert emulsions are difficult to stabilize over a large range of pressure and temperature conditions and specially at low temperature and high pressure where the appearance of hydrate compounds may induce a destabilization of the emulsion and loss of well control (cuttings transport, mud losses ….).
This paper presents credible laboratory data demonstrating the benefits of a special non polluting surfactant system engineered to stabilize brine droplets in an oil phase and to act as an efficient barrier to avoid droplets coalescence, even during hydrate formation. By using Differential Scanning Calorimetry technique without any dilution of the fluid, we show that emulsion droplet size is unaffected by ageing over a large range of temperatures; an adequate choice of oil plus the surfactant system permits to limit the amount of hydrate formed. Furthermore, the use of this specific emulsifying system allows to avoid agglomeration of droplets in the fluid as well as the breakage of emulsions after hydrate dissociation.
Optimizing Horizontal Completion Techniques in the Barnett Shale Using Microseismic Fracture Mapping
Authors: Fisher M. K. , Heinze J. R. , Harris C. D. , Davidson B. M , Wright C. A. , Dunn K. P. 
Published: December 2007

Abstract
The Barnett Shale of North Texas is an ultra low permeability reservoir that must be effectively fracture stimulated in order to obtain commercial production. As a result, techniques to optimize hydraulic fracturing effectiveness have evolved over the past decade. The first Barnett Shale "discovery" well, the C.W. Slay #1, was drilled in 1981 and it was almost 17 years before any significant commercial success was found in the Barnett, so the Barnett is a relatively new play. In fact, 75% of the producing wells in the Barnett have been drilled since 2000. In 1995, when the USGS was performing a gas in place assessment of the significant gas fields in the United States, the Barnett was not even evaluated. In 2002, according to the Energy Information Administration, the Newark East Field produced 202 Bcf, more than any other field in Texas, and was the 7th largest gas producer in the United States!
In some areas of the Barnett, horizontal drilling has recently been applied in an attempt to optimize gas production. Issues such as nearby water bearing intervals, inadequate surface locations, improved gas production rates and cost per scf can, in some cases, be addressed by the use of horizontal wellbores. The goal is to maximize fracture network surface area in the targeted pay intervals, and in some areas, reduce the probability of excessive fracture height growth.
Several horizontal completion techniques have recently been utilized, including single and multiple stage treatments with multiple perforation clusters in uncemented casing and multiple stage treatments performed in cemented perforated casing. In order to understand created fracture geometry for various completion designs, fracture treatments are often mapped with microseismic and tilt sensors.
Production results from this pilot study of the first twenty-three horizontal wells in the same general "Core" area of the Fort Worth Basin are compared in addition to mapped fracture geometry from eleven of these with vertical wellbores. This paper will discuss drilling and completion strategies, look at fracture network areas obtained from each, and then compare and contrast the fracture effectiveness with the standard procedures used in vertical Barnett wells.
Use of Viscoelastic Surfactant-Based Diverting Agents for Acid Stimulation: Case Histories in GOM
Authors: Zeiler Chuck , Alleman David , Qu Qi 
Published: December 2007

AbstractViscoelastic surfactant (VES) based diverting fluid has been successfully used in matrix acidizing in the Gulf of Mexico in recent years. Some cases are acid stimulation to remove near wellbore formation damage, or to cleanup perforation channels prior to gravel or frac packing, while other cases are acidizing to remedy fines migration or inorganic scaling damage on previously frac/gravel packed completions. Success or failure of these treatments is often related to the efficiency of diverting agents, especially for acid treatments on wells with long intervals or multiple-zone completions. A VES diverting agent is of particular interest to remedial treatments of frac/gravel packed wells, since damage to the near wellbore area and completion needs to be minimized for optimum production. Lab studies and field applications have demonstrated the non-damaging properties of a VES fluid.This paper presents several case histories of VES diverting applications in the GOM, including acidizing prior to frac/gravel packing, and remedial treatment of a frac packed completions. The bottom hole static temperature of these cases range from 140° F to 290° F for gas and oil wells. Because of an internal breaker system, the diverter does not require contact with formation fluid, brine, or acid to clean up and provide optimum production. In some cases, as many as four stages of diverters were pumped for the entire acid treatment, and successful diversion was observed for each stage. The paper will detail the general fluid properties as well as fluid properties tailored to specific well conditions and formation characteristics. Details and pressure response of the treatments will be discussed.