bluuebunny/crossref_metadata_2025_split huggingface dataset:
Gas Infill Well Selection Using Rapid Inversion Methods
Authors: Gao H. , McVay D. A. 
Published: December 2007

Abstract
It is often difficult to quantify the drilling and recompletion potential in producing gas fields, due to large variability in rock quality, well spacing, and well completion practices, and the large number of wells involved. Given the marginal nature of many of these fields, it is often prohibitively expensive to conduct conventional reservoir characterization and simulation studies to determine infill potential. There is a need for rapid, cost-efficient technology to evaluate infill potential in gas reservoirs, particularly tight gas reservoirs. Some authors have used moving window statistical methods, which are useful screening tools for identifying potential areas or groups of wells for further study.
We present a new simulation-based inversion approach for rapid assessment of infill well potential. Our work differs from typical simulation inversion applications in that, instead of focusing on small-scale, high-resolution problems, we focus on large-scale, coarse-resolution studies consisting of hundreds or, potentially, thousands of wells. In an initial application, the method employs well locations, production data and an approximate reservoir description and, accordingly, is able to identify potential areas or groups of wells for infill development quickly and inexpensively. Prediction accuracy can be increased commensurate with reservoir characterization effort, time and costs. Thus, the method provides a consistent basis for transition from screening studies to conventional reservoir studies.
The proposed approach is demonstrated to be more accurate than moving window statistical methods in synthetic cases, with comparable analysis times and costs. In a blind validation study of a field case with 40 years of production history, the method was able to accurately predict performance for a group of 19 infill wells.
Installing Low-Cost, Low-Pressure Wellhead Compression on Tight Lobo Wilcox Wells in South Texas: A Case History
Authors: Harms L. K. 
Published: December 2007

Abstract
This paper presents a case history of twenty-one low-cost wellhead compressors on tight Lobo Wilcox wells in South Texas. These wells previously produced to area-typical low-pressure gathering systems. Overall the installations showed substantial increases in the gas production rate as well as outstanding composite economics.
However, not all installations were successful and failures are examined for lessons learned to improve future applications.
Production data on the results of each of the installations are provided. The decision model used to select candidate wells from the 1600 producing wells in the field is also described.
Low-cost, low-pressure wellhead compression is presented as a viable artificial lift alternative and in fact the preferred and cheapest alternative in some cases.
Laboratory Investigation of NMR Crude Oils and Mud Filtrates Properties in Ambient and Reservoir Conditions
Authors: Chen Songhua , Zhang Gigi , Kwak Hyung , Edwards Carl M. , Ren Jason , Chen Jiansheng 
Published: December 2007

Abstract
We present laboratory NMR measurements of 445 crude oil samples, four mud filtrates and four base oil samples, and 47 refined oil samples. In addition to measurements at ambient conditions, a subset of the samples were measured at high temperatures and high pressures for the purpose of investigating the temperature, pressure, chemical structure, and oxygen-saturation dependences of the NMR T2 relaxation time. We found that the relaxation time, T2, correlates with specific gravity better than with viscosity, especially for heavy oils. Molecular oxygen dissolved in the oils affects the light oils significantly and if uncorrected, the oxygen-saturated T2 departs significantly from known T2 viscosity and temperature correlations. We propose an approximate method to correct the effect of dissolved oxygen based on experimental investigation of oxygen-free and oxygen-saturated samples. We further studied the pressure dependence of the crude oils, OBMF, and refined oils and found that even for dead oils, T2 depends on pressure and the dependence fits a quadratic expression. Finally, we investigated the chemical structure dependence of the refined oil samples; we found that the viscosity-T2 correlation is different for ring-structured hydrocarbons from linear-chain structured hydrocarbons. On the other hand, alkanes, alkenes, and esters share the same correlation.
Effect of Coiled Tubing Curvature on Friction Pressure Loss of Newtonian and Non-Newtonian Fluids - Experimental and Simulation Study
Authors: Jain Samyak , Singhal Naveen , Shah S. N. 
Published: December 2007

Abstract
Coiled tubing is widely used in the petroleum industry to pump fluids in the well bore at high rates. The friction pressure losses occurring in the tubing at these high rates are an issue of immense concern to the industry. Most of this friction loss can be attributed to the section of the tubing reeled on the spool during the treatment. The dimension of the reel used in the treatment governs the degree of curvature of the tubing and in turn the corresponding pressure drop. These pressure losses apart from increasing the cost of the treatment due to increased energy requirements also reduce the life of the tubular used.
Experimental and simulation study has been undertaken to determine friction pressure loss in 1 1/2 and 2 3/8-in. coiled tubings using water and 35 lb/Mgal guar as test fluids. Computational Fluid Dynamics software FLUENT has been used to generate simulations that have been validated with limited experimentation using a field-scale test setup. Previous experiments used limited flow rates and few curvature ratios due to high field-scale experimentation costs. But using CFD simulations friction pressure loss data have been gathered for a range of curvature ratios and flow rates that are comparable to the ones used in the field.
Results obtained have been used to determine the effect of curvature ratio on friction pressure losses while pumping Newtonian and non-Newtonian fluids in 1 1/2-in. and 2 3/8-in. tubing.
Investigating How Proppant Packs Change Under Stress
Authors: Schubarth Stephen , Milton-Tayler David 
Published: December 2007

Abstract
Proppant conductivity is an important design criterion in hydraulic fracturing treatments. Knowing how different proppants behave under changing stress conditions is important to fracture stimulation success. Conductivity and non-Darcy flow effects has been laboratory measured for all ceramic proppants. Unfortunately, almost all laboratory measurements are performed with an increasing stress and cyclic stress behavior is not observed. Often, in the production of oil and gas wells, shut-in periods occur and pressure in the wellbore and proppant pack increases causing stress to be relieved on the pack. When production begins again, stress is increased on the pack. This is stress cycling and past publications&lt;sup&gt;1&lt;/sup&gt; have noted that stress cycling can cause a reduction in proppant pack conductivity.
The work presented in this paper chronicles a vast series of crush tests performed on several proppant types and sizes. The crush tests were run using exactly the same starting sieve distribution for each particular proppant tested. After a sample was subjected to stress or multiple stress cycles, it was sieved for a detailed analysis. The change in the sieve distribution was noted and a median particle diameter was calculated along with the standard deviation of the distribution. A relationship was observed between these values and those of conductivity and Beta Factor. From these relationships it can then be possible to estimate the effect that stresses cycling has on conductivity and non-Darcy flow effects.
The papers results can help the fracture design engineer to better understand how conductivity, of the designed proppant pack, will change with time as stress cycling occurs. This understanding can lead to the recovery of more oil and gas through improved stimulation results.
Including Non-Equilibrium Effects in Models for Rapid Multiphase Flow in Wells
Authors: Civan Faruk 
Published: December 2007

Abstract
The modeling of rapid multiphase flow of reservoir fluids in wells and the non-equilibrium partial separation of dissolved gases from the metastable oil and water phases is discussed and reviewed. The effect of non-equilibrium on the deviation of the pressure distribution along the wells from the equilibrium model predictions is delineated.
The multi-phase fluid flow is described by means of the differential mass, momentum, and energy balance equations along the well. The rate of gas transfer from the metastable liquid phases to the gas phase is expressed in terms of the relaxation time determined by the prevailing gas phase volume fraction, and the pressure and temperature conditions. The solution of the set of differential equations is obtained numerically under a typical scenario involving the constant gas, oil, and water production rates at the wellhead. It is demonstrated that the nonequilibrium pressure distribution in the well deviates significantly from the equilibrium results depending on the local relaxation time, which vary along the well.
The present models can be incorporated into the conventional reservoir simulations for accurate description of the effect of the actual multi-phase well-fluid behavior under non-equilibrium flow conditions. The models are applicable with two-phase (oil/gas and water/gas) and three-phase (oil/water/gas) well fluid systems.
Hydrodynamic Conditions of Hydrocarbon Accumulation Exemplified by the Pomorsko and Czerwiensk Oil Fields in the Polish Lowland
Authors: Zawisza Ludwik 
Published: December 2007

Abstract
The hydrodynamic conditions of migration and accumulation of hydrocarbons are exemplified by two oil fields of Polish Lowland.
According to Hubbert, under hydrodynamic conditions a buoyancy force and moving water exert major control over the distribution of water, oil and gas in a reservoir, causing the oil/water and gas/water contact to be tilted.
In this paper, a modified theory is advanced to define more precisely the position of potential oil and gas traps. The theory introduced here is more universal than Hubbert's theory because it accepts not only the groundwater motion (dynamic effect), but also the variability of the oil, gas and water density (static effect) and heterogeneity of reservoir rocks (capillary effect).
According to the presented method, to determine potential sites for hydrodynamic entrapment of hydrocarbon, it is necessary to construct potentiometric maps for groundwater in terms of fresh water, maps of differential energy of oil or gas with respect to groundwater and maps of differential energy of oil or gas caused by capillary forces and then to add them up by superimposition.
The suggested method of determining the positions of potential hydrodynamic petroleum traps is comparatively simple to apply and gives good results in regions of high hydraulic gradients, high variability of salinity and hydrocarbon densities and high variability of porosity and permeability of reservoir rocks.
High-Order Upwind Schemes for Three-Phase Multicomponent Flows, A Preliminary Investigation
Authors: Valenti Gianluca , Jessen Kristian , Mallison Bradley T. , Gerritsen Margot G. 
Published: December 2007

AbstractWe analyze the accuracy of three upwind discretization schemes (first order SPU, second order TVD and third or-der ENO) for the numerical simulation of one-dimensional three-phase multicomponent displacements. The solutions are stepped through time using Runge-Kutta methods with the same accuracy as the spatial discretization.The schemes are tested on numerically challenging 3- and 11-component water-alternating-gas processes. Through lack of an analytical solution, the results are compared to a convereged high resolution simulation.The preliminary results show that higher-order schemes lead to much sharper solution profiles and more accurate front propagation speeds than the first order SPU scheme. The schemes allow coarser grids to be used for the same solution accuracy and are therefore also more efficient. These results agree with a previous study for two-phase flows.1
Competitive Adsorption of a Hybrid Surfactant System onto Five Minerals, Berea Sandstone, and Limestone
Authors: Grigg Reid B. , Baojun Bai , Yi Liu 
Published: December 2007

Abstract
This paper presents the adsorption/desorption results for two surfactant systems and for a mixture of the two onto five minerals and two porous media. The systems are composed of Chaser International CD1045™ (CD) and a calcium lignosulfonate (CLS), Lignosite® 100. Two series of experiments were carried out: (1) static adsorption of CLS, CD, and CLS/CD mixtures onto five pure minerals (silica, montmorillonite, kaolinite, dolomite, and calcite); (2) dynamic adsorption of CLS, CD, and CLS/CD mixtures onto core samples of Berea sandstone and Indian limestone. All experiments were performed at 40°C using a 2.0% brine solution with concentrations of 500 mg/l of CD and 5,000 mg/l of CLS.
Static adsorption experiment results showed that: (1) CLS adsorption density onto silica is less then back ground noise (zero); on the other four minerals, adsorption density ranged from 0.5 to 10 mg CLS per g of mineral; (2) CD adsorption density onto the five minerals ranged from 0.4 to 1.2 mg CD per g of mineral; (3) CD adsorption density onto the five minerals decreased by 20 to 7 0% when mixed with CLS.
Dynamic adsorption experiment results showed that: (1) The times required to reach adsorption equilibrium for both CD and CLS were longer for Berea sandstone than for Indiana limestone and for both porous media, were much longer than those for the non-porous minerals; (2) Competitive adsorption generally took several days to reach equilibrium.
Stability and interfacial tension tests on both injected and effluent samples were performed. Results correlated well with the adsorption/desorption tests; for example, foaming capability was lost in some systems due to adsorption.
Combined Effect of Non-Darcy Flow and Formation Damage on Gas Well Performance of Dual-Porosity and Dual-Permeability Reservoirs
Authors: Pereira Tavares Carlos Alberto , Kazemi Hossein , Ozkan Erdal 
Published: December 2007

AbstractThis paper addresses the combined effect of formation damage and non-Darcy flow in naturally fractured reservoirs using simplified analytical solutions and a two-dimensional numerical simulator. Pressure drawdown, buildup, and isochronal tests simulated in this work indicate that, despite high fracture permeability, skin damage may accentuate the non-Darcy flow effect and drastically influence pressure-transient characteristics of low-pressure, naturally fractured reservoirs. In high-pressure reservoirs, this effect is significant only at high rates. Non-Darcy flow does not usually mask the typical pressure-transient characteristics of dual-porosity and dual-permeability reservoirs, but the conventional interpretation of the early time data may lead to erroneous results. If the exponent, n, of the gas performance curve approaches 0.5 while the matrix permeability is low and flow rate is rather high, this indicates predominance of fracture flow. The practical motivations of this study and its extensions to other practical problems, such as condensate reservoirs where the condensate dropout in the wellbore region should increase non-Darcy flow, are also discussed.
Real-time Bayesian Inversion of Hydraulic Fracturing Treatment Efficiency from Tiltmeter Measurements
Authors: Lecampion B. , Jeffrey R. , Detournay E. 
Published: December 2007

Abstract
In this paper, we describe a method to estimate, in real-time, the efficiency of a hydraulic fracture treatment performed in porous reservoir from tiltmeter measurements.
The poroelastic deformation induced by the fracture opening and the fluid leak off is investigated at first. The resolution of fracture dimensions and orientation from tiltmeter measurements is also discussed. A limit, expressed in terms of the distance between the tiltmeters and the fracture, above which only the volume and orientation of the fracture have an effect on the tilt field is recalled. The proposed method of analysis recognizes that, without additional information, only the fracture volume and orientation can be accurately estimated from tiltmeter measurements. The knowledge of the injected volume at time t together with the tilts data allow to estimate the efficiency of the treatment at this time. Furthermore, because the method is computationally efficient, the treatment efficiency and fracture orientation can be obtained in real time (i.e. as the data arrive) throughout a hydraulic fracturing treatment.
Stability Maps for Continuous Gas-Lift Wells: A New Approach to Solving an Old Problem
Authors: Fairuzov Y. V. , Guerrero-Sarabia I. , Calva-Morales C. , Carmona-Díaz R. , Cervantes-Baza T. , Miguel-Hernandez N. , Rojas-Figueroa A. 
Published: December 2007

Abstract
Continuous flow gas-lift wells are susceptible to hydrodynamic instability (heading), which may cause cyclic variations of the wellhead pressure, oil and gas flow rates. Gas-lift instability is a reason of many operational problems, for example, compressor shutdowns caused by pressure and liquid flow rate surges, difficulties in the operation of low pressure separators, and excessive gas consumption. Stability problems in complex multiphase systems can be solved using stability maps. A stability map is a plane (2D) diagram that shows the regions of stable and unstable operation of the system, as well as its operating limits. In this paper theoretical and experimental stability maps for gas-lift wells are presented. Fild test were conducted to investigate the flow stability in a deep offshore gas-lift well. Different gas-lift stability criteria proposed in the literature are compared. Based on this study, recommendations on the selection of gas-lift stability criteria were developed. Examples of gas-lift stability map applications are also given.
Portfolio Management Framework for Multistage Investments
Authors: Chorn L. G. 
Published: December 2007

Abstract
Decision making for multi-stage exploration and development investments requires more analytical capabilities than are available from a Markowitz portfolio approach. The decision evaluation process is complicated by the evolution of project value as new project data is acquired, improved technology becomes available, and market conditions change. Management must also accommodate multiple business objectives including reserve replacement requirements, positive project NPV, increasing or sustaining annual production volumes, and cost of finding and developing. This article describes the application of dynamic programming techniques and the concepts of Markov chains to modeling projects within an investment opportunity portfolio. Using an exploration investment opportunity, we compare the guidance from a Markowitz approach with those from a Markov chain approach. The incremental insights are much greater than the cost of increased project detail required for the analysis.
Don't Be Fooled by Bayes
Authors: Wills Hector A. , Graves Ramona M. , Miskimins Jennifer 
Published: December 2007

Abstract
Often times the Petroleum Industry focuses on calculating the value of information using Bayesian analysis to determine a modified perception about the state of nature as a result of the new information's ability to better describe it. Some of the methods commonly used and widely published in Petroleum Engineering literature and commercial software; use the concepts of conditional probability, information sources, and the state of nature being interpreted. The interrelationships among these concepts are not systematically defined. More over, the conditional probability is freely assigned not considering the bounds that Bayes' Theorem imposes. This paper demonstrates the dependency of the value of information on how and where the conditional probability is assessed. What happens to the calculation when the initial conditional probability changes? Does it make a difference in the decision to be made after receiving the information? Using sensitivity analysis on the conditional probability term we examine published examples and show the deceiving nature of the reported results. The solution to this deception is given.
Capillarity-Induced Flow in Wetting Liquid Films: Implications for the Recovery of Volatile Oils from Fractured Porous Media
Authors: Yiotis A. G. , Boudouvis A. G. , Stubos A. K. , Tsimpanogiannis I. N. , Yortsos Y. C. 
Published: December 2007

Abstract
The recovery of volatile oils from the matrix of fractured porous media can be significantly aided through gas injection. Within certain assumptions, this process operates much like the isothermal drying of porous media. For example, the recovery from the matrix block is controlled by mechanisms involving capillary, viscous and buoyancy forces in the liquid and the liquid-gas interfaces, and mass diffusion and convection in the gas phase. The receding of the liquid phase is followed by the formation of macroscopic liquid films along the pore walls. Films provide hydraulic conductivity between macroscopically isolated liquid clusters and help transfer liquid over significant distances in the porous matrix. In this work, we study the effect of such films.
We propose a mathematical model for the capillarity-driven flow through wetting films in the context of evaporation and drying. A pore-network simulator that accounts for flow through liquid films, viscous flow in the bulk liquid phase of the clusters and mass transfer by diffusion in the gas phase is used. We study the effect of liquid films on phase distribution patterns and rates of recovery. We find that under strong capillarity conditions, the films span across the whole block, enhancing significantly liquid flow from distant clusters and improving recovery rates. An upscaling of the pore-network findings to macroscopic quantities is then presented. We comment on the extension of the method to binary mixtures and gravity effects. Our results show that flow through liquid films is a major transport mechanism in such processes.