bluuebunny/crossref_metadata_2025_split huggingface dataset:
Fundamentals of Gravel Pack Performance With Mesh Screens
Authors: Martch Eddy , Hudson Andy , Bode Wouter , Fischer Christine , Constien Vernon 
Published: June 2014

Abstract
The Parque das Conchas project is located in the BC-10 deepwater block in the Campos Basin, approximately 120 km southeast from the city of Vitoria, in water depths of 1,500 to 2,000 meters. Shell is the operator with a 50% equity share, with joint venture partners Petrobras (35%) and ONGC (15%)17. The wells flow via Caisson ESP’s to a host FPSO. Horizontal Open-hole Gravel Pack was the sand control method selected in the low frac margin reservoirs of the Ostra Field. In preparation for completing wells in formations with anticipated sand production, a large laboratory study was conducted evaluating the performance of stand-alone woven mesh screens and gravel packs. The study was performed to select a premium mesh screen which would minimize solids production in the event of incomplete gravel pack and manage fines production that would pass through the seabed located Caisson ESP systems. Additionally, it was important to control solids production to the Floating Production, Storage and Offloading (FPSO) unit as there were no provisions installed to handle large volumes of solids at the surface. The test grid compared the performance of multiple screen sizes with and without gravel packs with three unconsolidated formation particle size distributions which were representative of the size distributions anticipated in the completions. The resulting performance data correlated the amount of solids production, size of produced solids, retained gravel pack permeability and retained screen permeability as functions of the effective size of the formation material, the gravel size and the pore size of the screen. The gravel pack media size and premium screen mesh size were selected based on the results of this testing. Screen QA/QC was determined to be critical in the event a full gravel pack was not achieved and the screens would be expected to provide sand control in a stand-alone mode. An enhanced quality process was developed and implemented to ensure the highest quality of the screens was maintained and materials were traceable during well sand control completions.
The laboratory tests identified combinations of screen and gravel packs which appeared to indicate the best choice for controlling solids production in an acceptable range while maintaining high flow capacity, maximizing production at minimum drawdown pressures. An enhanced QA/QC process for screen manufacturing contributed to the success of the completions. Production history for the first 2 years indicates minimal sand production.
Novel Method To Characterize Formation Damage Caused by Polymers
Authors: Maxey J. , Van Zanten R. 
Published: June 2014

Abstract
Formation damage can occur through several different mechanisms ranging from scaling/precipitates to pore plugging by small particles. Polymer invasion into the reservoir pore spaces during drilling, completion or fracturing can be especially damaging and difficult to remediate. This has been previously reported to result from increases in the extensional viscosity that occurs as the polymer is extruded through the pores of the formation. This increase in extensional viscosity traps the polymer in the pore throat and creates a liquid crystalline type state that does not allow the polymer to relax and exit the pore space or allow remedial treatments such as acidizing to contact to polymer to break it down.
This paper will detail a laboratory investigation combining rheological studies of extensional viscosity of polymeric and viscoelastic surfactant fluids with formation damage testing performed on Berea sandstone cores. Using a laboratory rheometer, the shear rate applied to a sample will be increased exponentially, creating strong flows comparable to those experienced in flow through porous media. The type of polymers will be varied to include simple linear biopolymers (HEC), varying degrees of branched biopolymers (xanthan gum, scleroglucan gum), and hyper-branched synthetic polymers; fluids viscosified with polymers will then be compared with viscoelastic surfactant gels. A direct correlation between the rheological properties of the fluid to the formation damage potential of the fluid will be made. This correlation will allow for screening of fluids that will contact the reservoir through a much simpler rheological methodology as compared to the time consuming and highly variable formation damage tests via core flood experiments.
The Influence of Production Rate, Permeability Variation and Well Spacing on Solution-Gas-Drive Performance
Authors: Heuer G.J. , Clark G.C. , Dew J.N. 
Published: June 2014

Abstract
The effect on well behavior of partial permeability barriers, changes in producing rates and well spacings have been calculated through use of a radial, unsteady-state, two-phase-flow mathematical model. This model allows for variations in permeabilities and porosities with distance from the wellbore. The numerical methods necessary to solve the problem require use of a high-speed digital computer, in this case an IBM 704.
In each instance, pressure and saturation gradients, gas-oil ratios and recoveries around a well producing by solution-gas drive have been calculated as a function of time and distance from the wellbore. Comparisons are made to show the effect of changes in producing rate and of varying permeability near the wellbore and out in the formation on the production and pressure history of the well. The effect of different well spacings on producing rate and ultimate recovery is considered. Although the mathematical description of the reservoir is simplified in comparison to an actual reservoir, the results do give some insight into the difficult problem of spacing and proration in a heterogeneous solution-gas-drive reservoir. Results show that for the cases considered spacing has little effect on ultimate recovery and that permeability barriers removed from the well decrease producing rate for a period of time but have only a small effect on ultimate production.

Introduction
The effect of spacing and producing rate on the production characteristics and ultimate recovery of a well producing by the solution-gas-drive mechanism have been topics of interest to the oil industry for many years and the subject of many hearings before state regulatory bodies. The problem is very complicated because of the difficulty of simulating in the laboratory a reservoir producing by the solution-gas-drive mechanism under anything like normal field conditions. This paper gives the initial results of a study aimed at determining the effect of these factors on production from reservoirs simulated by a mathematical model. Two-phase, unsteady-state equations are used to calculate pressures, saturations, and rates of oil and gas flow as a function of time and distance from the wellbore. The model is radial, and reservoir properties may he varied with distance from the wellbore. A decrease in permeability at a given distance results in a low-permeability ring concentric with the wellbore through which all the fluids from more distant portions of the reservoir must flow.
Petrophysical Properties Evaluation of Tight Gas Sands Using NMR and Conventional Logs
Authors: Hamada G. M. 
Published: June 2014

Abstract
Analysis of heterogeneous sandstone reservoirs is one of the most difficult problems. These reservoirs usually produce from multiple layers with different permeability and complex formation, which is often enhanced by natural fracturing. Therefore, using new well logging techniques like NMR or a combination of NMR and conventional open hole logs, as well as developing new interpretation methodologies are essential for improved reservoir characterization. Nuclear magnetic resonance (NMR) logs differ from conventional neutron, density, sonic and resistivity logs because the NMR measurements provide mainly lithology independent detailed porosity and offer a good evaluation of the hydrocarbon potential. Integration of NMR logs, other open hole logs and SCAL minimizes uncertainties in the determination of formation porosity, permeability and capillary pressure curve.
This paper focuses on determination of three petrophysical parameters of heterogeneous gas sand reservoirs; 1) Determination of DMR porosity, 𝚽DMR, it is deduced from NMR porosity and density porosity, 2) NMR permeability, KBGMR, it is based on the dynamic concept of gas movement and bulk gas volume in the invaded zone and 3) Capillary pressure, it is derived from relaxation time T2 distribution
Pressure Behavior of a Hydraulic Fractured Well in Tight Gas Formation with Threshold Pressure Gradient
Authors: Lu Jing 
Published: June 2014

AbstractThe threshold pressure gradient, which is associated with non-Darcy flow in low permeability tight gas formation, is defined as the level of pressure gradient that has to be attained to enable the fluid to overcome the viscous forces and start to flow. With low velocity and non-Darcy flow, the fluid flow boundary is controlled by the threshold pressure gradient and can extend outward continuously, while the fluid beyond this boundary cannot flow.This paper presents analytical solutions to the pressure transient equations of a uniform-flux hydraulically fractured gas well in tight gas formation with threshold pressure gradient. These solutions are obtained by using Green's functions method with numerical approximations. A method to determine the location of the moving boundary front is also presented.This paper concludes that the pseudopressure equalpotential surfaces for a fully penetrating vertical uniform-flux hydraulically fractured gas well are a family of ellipse, whose focuses are the two endpoints of the hydraulic fracture. This paper also concludes that both pressure transient distance in the direction perpendicular to the fracture and pseudopressure drop at the wellbore are approximately linear functions of the square root of producing time. Finally, the solution procedure proposed in this paper is a fast tool to evaluate a hydraulically fractured gas well performance in tight gas formation.
Pinpoint Multistage Fracturing of Tight Gas Sands- An Integrated Model with Constraints
Authors: Yu Haiqing , Rahman M. M. 
Published: June 2014

Abstract
As the demand for gas increases worldwide, tight, deep and multilayered unconventional gas sands are becoming the target for development. For such reservoir the conventional approach of simple fracturing the formation to hydraulically stimulate the well is inadequate. Continuous progress in hydraulic fracturing technology results in pinpoint fracturing, which allows multiple precisely targeted sands to be stimulated. Recently, this technique has been used in the developmet of tight gas sands. However, the systematic design methods for fracture treatment parameters with constraints are not well presented in the literature. Even the most currently available commercial software lack proper optimization tools in them and they do not take into consideration several key parameters and realistic constraints in them. An integrated but constrained model to design pinpoint multistage fracturing treatment has been developed to maximize gas production from layered tight sands. Model couples both the industry experience and design parameters based on hydraulic fracture mechanics. This integrates reservoir in-situ parameters, fracture geometry, fracture treatment design, realistic design constraints, and production and economic models. The integrated model has been successfully applied to a hypothetical deeper and layered tight gas sands to demonstrate its merits. A parametric study is also conducted to compare between the conventional single-stage and pinpoint multi-stage hydraulic fracturing with their basic design concepts and post-fracture benefits. It is evident that the productivity increase is about 20-fold higher in pinpoint multistage fracturing compared to 6-fold for blanket fracturing. Insightful parametric sensitivity analyses are also presented. This model could also be used to study the potential of the deep UAE tight gas sands.
Production Forecast after Hydraulic Fracturing in Naturally Fractured Reservoirs: Coupling a Complex Fracturing Simulator and a Semi-Analytical Production Model
Authors: Cohen Charles-Edouard , Xu Wenyue , Weng Xiaowei , Tardy Philippe M. 
Published: June 2014

Abstract
The growing interest in exploiting shale resources is generating new technologies in fracture modeling and reservoir simulation. In the presence of pre-existing natural fractures, hydraulic fracture propagation and proppant distribution can be very complex. Developing the tools to understand fracture propagation and its link to production in shale reservoirs is one of the major technological challenges that the industry is facing today. These challenges are being addressed with new hydraulic fracture simulators and production models for complex hydraulic fracture networks in shale reservoirs. However, the coupling between these two technologies is not mature yet.
This paper presents a simple automated workflow from simulating hydraulic fracture propagation in naturally fractured reservoirs to the subsequent production. This work documents the coupling of an existing complex fracturing simulator with a new production model. The complex fracture model considers interactions with natural fractures, stress shadow effects and proppant placement. The production model is based on a semi-analytical approach applied to the discrete hydraulic fracture network. The analytical solution used to simulate the flow from the matrix into the fracture network is simple and well known, but it relies on the assumption of constant pressure in the fracture which can only be obtained with infinite fracture conductivity. An original feature of this model is an algorithm to extend the validity of the analytical solution to all fracture conductivities, by calculating a local "time delay" based on mass balance. The validity of this approach is illustrated by a comparison with results from a standard reservoir simulator. The simple automated workflow that combines the two simulators gives the opportunity to investigate the relation between production and fracture treatment design in naturally fractured reservoirs. This paper illustrates the application of the workflow to realistic cases and the sensitivity of several design parameters that affect well performance.
Hybrid Forecasting Methods for Multi-Fractured Horizontal Wells: EUR Sensitivities
Authors: Nobakht M.. , Clarkson C. R. 
Published: June 2014

Abstract
In this paper, the sensitivity of expected ultimate recovery (EUR) for horizontal wells with multiple fractures to decline exponent is studied using the simplified forecasting method introduced by Nobakht et al. (2010). This is very important from the reserves evaluation perspective due to uncertainty in decline exponent, b. This uncertainty is caused by many factors like adsorption and reservoir/completion heterogeneity. It is found that in case of time-based forecast (duration of forecast is specified), the ratio of EURs for two different specified values of decline exponent depends on the ratio of economic life time of a well to the duration of linear flow. On the other hand, this EUR ratio depends on the ratio of rate at the end of linear flow to economic rate limit for economic limit-based forecast (economic rate limit rate is specified).
Proper Selection of Surfactant Additives Ensures Better Well Stimulation in the Unconventional Oil and Gas Formations
Authors: Xu Liang , Fu Qiang 
Published: June 2014

Abstract
A typical assumption for promoting the use of surfactants is that traditional surfactants will work appropriately across a large gamut of fields, but our laboratory tests show that inappropriate application leads to much lower efficiency of the oil recovery and thereby diminished production. Operators must understand how surfactants extract the oil and then select surfactants cautiously in order to maximize recovery and minimize risk.
This paper presents a study on surfactant chemicals and their most relevant parameters. In particular, the key characteristic of surfactant additives in unconventional oil and gas formations was found to be the emulsion tendency. It was found that a weakly emulsifying surfactant was more capable of solubilizing and mobilizing additional oil globules via self association. In stark constrast to a conventional non-emulsifying surfactant, the correct application of a weakly emulsifying surfactant led to better well cleanup and a higher ultimate oil recovery.
A Scale-Model Study of Bottom-Water Drives
Authors: Henley D.H. , Owens W.W. , Craig F.F. 
Published: June 2014

Abstract
The oil recovery performance of systems producing entirely by bottom-water encroachment has been experimentally determined in a series of scaled laboratory-model tests. The effects of well spacing, fluid mobilities, rate of production, capillary and gravity forces, well penetration and well completion techniques on the oil recovery performance have been investigated. The laboratory tests were performed using two uniform, unconsolidated sand-pack models. The models have ratios of the interwell distance to the formation thickness of 12 and 2, respectively. Tests at constant total fluid production rate were performed simulating a range of uniform reservoir characteristics and operating conditions encountered in field operations. The performance was determined by material balance and by observation of the encroachment of dyed fluids into the models. The results of the model tests agreed with those obtained mathematically when the conditions previously considered in theoretical studies were simulated, that is, when the oil and water are of equal density and no capillary forces exist.
The model study of bottom-water drive indicated that certain variables can affect the oil recovery performance to a greater degree than can be predicted by present analytical methods. In one comparison, the oil recovery at a water-oil ratio of 20 (obtained at a wide well spacing) varied as much as threefold, depending upon the system's properties and the production rate. Lesser effect of mobility ratio and no effect of capillary forces over the range studied were observed. The test results also showed that the deeper the well penetration into the oil column, the greater the total water production to a producing WOR of 20. However, the ultimate sweep efficiency, and so the oil recovery to this level of WOR, did not vary significantly with well penetration. Horizontal fractures at the top of the formation did not significantly change the sweep characteristics of the reservoir models when values of radius and fracture capacity encountered in actual reservoirs were used. Impermeable pancakes at the bottom of the well moderately increased the oil recovery efficiency both at water breakthrough and at high water-oil ratios. A method is outlined by which the oil recovery performance of other uniform bottom-water drive systems can be estimated from the information obtained in these model tests.
Unconventional-Natural-Gas Business: TSR Benchmark and Recommendations for Prudent Management of Shareholder Value
Authors: Weijermars Ruud , Watson Steve 
Published: June 2014

Summary
Stock-listed independents have played a leading role in the development of unconventional natural-gas resources in the United States and Canada. Shareholders have provided up to 57% of the total capital tied up in a representative panel comprising the 20 leading US and Canadian operators. The accumulated equity-financed capital also provided the collateral for the complementary 43% debt financing. Prudent management of shareholder value in unconventional-gas businesses is therefore essential for ensuring security of gas supply, not only in North America, but also in other countries with emergent unconventional gas plays. This study analyzes and benchmarks the working capital cycles in unconventional-gas companies. The working capital and cashflow cycles are compared with those of diversified oil and gas majors. The ability to accumulate retained earnings is generally much lower for unconventional-gas producers than for integrated majors. Unconventional-gas producers tend to grow their share capital by new issues and not from economic value added by profit from business operations. Although little or no asset value is built from economic profit, shareholder returns may still grow for unconventional-gas companies as long as investor expectations remain positive about future earnings. In contrast, shareholder returns in conventional-gas companies come from genuine economic value added in profitable business operations. The root cause of the weakness or absence of operational profits in unconventional-gas operations is a combination of low gas prices and well flow rates that are too modest to pay for the total cost of the unconventional-gas production. The operating margins for unconventional-gas companies are either close to zero or negative, but not for the integrated oil and gas majors, which have impressive cash margins even at globally suppressed gas prices. The benchmarks provided here help one to understand which parameters impact the financial performance of unconventional-natural-gas companies most significantly. Recommendations are formulated to avoid the destruction of shareholder value, and to instead maximize total shareholder returns (TSRs).