bluuebunny/crossref_metadata_2025_split huggingface dataset:
History Matching With Parameterization Based on the Singular Value Decomposition of a Dimensionless Sensitivity Matrix
Authors: Tavakoli Reza , Reynolds Albert C. 
Published: June 2010

Summary
In gradient-based automatic history matching, calculation of the derivatives (sensitivities) of all production data with respect to gridblock rock properties and other model parameters is not feasible for large-scale problems. Thus, the Gauss-Newton (GN) method and Levenberg-Marquardt (LM) algorithm, which require calculation of all sensitivities to form the Hessian, are seldom viable. For such problems, the quasi-Newton and nonlinear conjugate gradient algorithms present reasonable alternatives because these two methods do not require explicit calculation of the complete sensitivity matrix or the Hessian. Another possibility, the one explored here, is to define a new parameterization to radically reduce the number of model parameters.
We provide a theoretical argument that indicates that reparameterization based on the principal right singular vectors of the dimensionless sensitivity matrix provides an optimal basis for reparameterization of the vector of model parameters. We develop and illustrate algorithms based on this parameterization. Like limited-memory Broyden-Fletcher-Goldfarb-Shanno (LBFGS), these algorithms avoid explicit computation of individual sensitivity coefficients. Explicit computation of the sensitivities is avoided by using a partial singular value decomposition (SVD) based on a form of the Lanczos algorithm. At least for all synthetic problems that we have considered, the reliability, computational efficiency, and robustness of the methods presented here are as good as those obtained with quasi-Newton methods.
A Multiscale Mixed Finite-Element Method for Vuggy and Naturally Fractured Reservoirs
Authors: Gulbransen Astrid Fossum , Hauge Vera Louise , Lie Knut-Andreas 
Published: June 2010

Summary
Vugs, caves, and fractures can alter the effective permeability of carbonate reservoirs significantly and should be accounted for accurately in a geomodel. Accurate modeling of the interaction between free-flow and porous regions is essential for flow simulations and detailed production-engineering calculations. However, flow simulation of such reservoirs is very challenging because of the coexistence of porous and free-flow regions on multiple scales that need to be coupled.
Multiscale methods are conceptually well-suited for this type of modeling because they allow varying resolution and provide a systematic procedure for coarsening and refinement. However, to date there are hardly any multiscale methods developed for problems with both free-flow and porous regions. Herein, we develop a multiscale mixed finite-element (MsMFE) method for detailed modeling of vuggy and naturally fractured reservoirs as a first step toward a uniform multiscale, multiphysics framework. The MsMFE method uses a standard Darcy model to approximate pressure and fluxes on a coarse grid, whereas fine-scale effects are captured through basis functions computed numerically by solving local Stokes-Brinkman flow problems on the underlying fine-scale geocellular grid. The Stokes-Brinkman equations give a unified approach to simulating free-flow and porous regions using a single system of equations, they avoid explicit interface modeling, and they reduce to Darcy or Stokes flow in certain parameter limits.
In this paper, the MsMFE solutions are compared with finescale Stokes-Brinkman solutions for test cases including both short- and long-range fractures. The results demonstrate how fine-scale flow in fracture networks can be represented within a coarse-scale Darcy-flow model by using multiscale elements computed solving the Stokes-Brinkman equations. The results indicate that the MsMFE method is a promising path toward direct simulation of highly detailed geocellular models of vuggy and naturally fractured reservoirs.
Modeling Fracture-Fluid Cleanup in Tight-Gas Wells
Authors: Wang John Yilin* , Holditch Stephen A. , McVay Duane A. 
Published: June 2010

SummaryOn occasion, a hydraulically fractured tight-gas well does not perform up to its potential because of slow or incomplete fracture- fluid cleanup. A number of papers have been written to address individual factors related to fracture-fluid cleanup, but many questions as to which factors mostly affect gas production from such wells remain unanswered. Numerical reservoir simulation is one of the best methods to study the fracture-fluid-cleanup problem. Continuing from our previous publication (Wang et al. 2008) on the effect of gel damage on fracture cleanup, we used reservoir simulation to analyze systematically the factors that affect fracture- fluid cleanup and gas recovery from tight-gas wells.We first developed a comprehensive data set for typical tight gas reservoirs and then ran single-phase-flow cases for each reservoir and fracture scenario to establish the idealized base-case gas recovery. We then systematically evaluated the following factors: multiphase gas and water flow, proppant crushing, polymer filter cake, and, finally, yield stress of concentrated gel in the fracture. The gel in the fracture is concentrated because of fluid leakoff during the fracture treatment. We evaluated these factors additively in the order listed. We found that the most important factor that reduces fracture-fluid cleanup and gas recovery is the gel strength of the fluid that remains in the fracture at the end of the treatment.This paper illustrates the complexity of the fracture-fluid- cleanup problem and points out the need to use reservoir simulation and to include all the pertinent factors to model fracture-fluid cleanup rigorously. The procedures presented can provide a useful, systematic guide to engineers in conducting a numerical simulation study of fracture-fluid cleanup.
Guidelines for the Proper Application of Critical Velocity Calculations
Authors: P. Sutton Robert , A. Cox Stuart , F. Lea James , Rowlan O. Lynn 
Published: June 2010

SummaryCritical velocity calculations in the form of charts or simple equations are frequently used by field personnel to evaluate a gas well's flowing conditions to determine if the well is experiencing liquid-loading problems. Literature detailing the critical velocity necessary to keep a gas well unloaded suggests using the conditions at the top of the well as an evaluation point. This is convenient for personnel conducting the evaluation because wellhead pressure and temperature data are readily available. A number of situations exist where the use of the wellhead as the evaluation point can lead to erroneous conclusions. The most obvious situation occurs with a change in geometry downhole when a tapered tubing string is run in a well or when the tubing is set above the perforations. In these instances a more robust evaluation results from using conditions at the bottom of the well and the downhole tubing geometry. Other conditions exist where the use of downhole conditions provides a better evaluation point. The assumptions used in the development of the standard, simplified form of the critical velocity equations and charts may not be appropriate for downhole application. In these cases, the fundamental equations must be used. The calculation of critical velocity requires knowledge of pressure, temperature, produced fluids, and pressure/volume/temperature (PVT) properties. The determination of critical rate requires the same properties with the addition of pipe diameter. The required PVT properties, including surface tension and density for both the gas and liquid phases, are reviewed. Correlations to calculate water-gas surface tension were found to have excessive error, so a new, more accurate method is presented. This paper provides recommendations for the use of a surface or a downhole evaluation point is more appropriate for the determination of the minimum critical gas velocity in a well.
Effects of Monoethylene Glycol on Carbonate Equilibrium and Calcite Solubility in Gas/Monoethylene Glycol/NaCl/Water Mixed Systems
Authors: Lu Haiping , Kan Amy T. , Tomson Mason B. 
Published: June 2010

Summary
Monoethylene glycol (MEG), HOCH2CH2OH, is an important raw material with numerous industry applications, which include polyester synthesis, automobile antifreeze, coolant, and aircraft anti-icer. In the oil and gas industry, MEG is commonly used as a gas-hydrate inhibitor, which can prevent the formation of gas hydrate during natural-gas production. However, common gas-hydrate inhibitors have the adverse effects of lowering the solubility of mineral salts and causing a higher risk of scale formation. Despite the importance of scale problems with MEG in oil production, there have been few investigations on the solubility of mineral salt in MEG/brine solutions. In our research, experiments have been conducted on carbonate equilibrium and calcite solubility at 2–70°C, 0- to 6.5-m (m = molality) ionic strengths, and 0–99.67 wt% MEG.
A self-consistent activity model based on the Pitzer theory to calculate the effect of salt and a Born-type equation were used to model the effect of MEG. MEG activity coefficients with respect to dissolved carbon dioxide (CO2), sodium bicarbonate, sodium carbonate (NaHCO3), and calcium are determined as a function of temperature, ionic strength, and mole fraction of MEG in mixed solvent.
Comparison of Flowback Aids: Understanding Their Capillary Pressure and Wetting Properties
Authors: Howard Paul R. , Mukhopadhyay Sumitra , Moniaga Nita , Schafer Laura , Penny Glenn , Dismuke Keith 
Published: June 2010

Summary
Flowback aids are usually surfactants or cosolvents added to stimulation treatments to reduce capillary pressure and water blocks. As the stimulated gas reservoirs become tighter, the perceived value of these additives has grown. This value must be balanced with the cost of the additives, which can be significant in slickwater fracturing treatments. There is a range of different flowback additives containing water-wetting nonionic to amphoteric, microemulsion (ME), and oil-wetting components. Determining the best additive for a specific reservoir is not a simple matter for the end user, and the existing literature is full of conflicting claims as to which one is most appropriate.
This paper compares four different flowback aids: ME, two waterwetting flowback additives, and an oil-wetting additive. Careful laboratory testing was conducted to evaluate surface tension and contact angle for each flowback aid, using the recommended concentrations. Imbibition and drainage tests were performed that allowed calculation of the capillary pressures for the three additives. Drainage tests were performed on 1- to 3-md and 0.1-md cores. Capillary-tube-rise testing was also conducted as a check of the coreflood testing capillary pressures. This provided several different methods to determine capillary forces for the flowback aids. In addition, fluid-loss testing was conducted to determine if the flowback additives could improve fluid loss.
All the flowback aids demonstrated low surface tension (approximately 30 mN/m), but each was different in terms of surface wettability and adsorption in the rock. In all cases, the flowback aids reduced capillary pressure to similar levels 70% lower than water alone. One of the water-wetting additives had much stronger adsorption in the core material than the other additives. The ME and the oil-wetting additive had improved fluid loss in a fully formulated fracturing fluid. In spite of the low capillary pressures, the additives had little effect on cleanup or return permeability on cores greater than 1 md.
There are several implications of these results for the operator. Different flowback additives have a tradeoff of properties, and depending on the reservoir, selecting one that leaves the formation with certain wettability may be advantageous. Our testing indicated that understanding the reservoir is important in selecting the appropriate flowback aid.
Fluid-Diversion Monitoring: The Key to Treatment Optimization
Authors: Glasbergen Gerard , Yeager Valerie , Reyes Robert , Everett Don 
Published: June 2010

Summary
In stimulation and injection treatments for removing or preventing formation damage, placement of the injected fluids is essential. Throughout the years, several diversion and placement techniques have been applied to obtain a desired fluid placement. A recent development is the application of distributed temperature sensing (DTS) to monitor the temperature profiles along the wellbore in real time during these treatments. Recent case histories showed that fluid placement can be quantified. Quantification of fluid distribution enables one to determine the flow distribution both before and after a diverter stage so that the diversion effect can be quantified.
This paper discusses several case histories where DTS was applied to quantify the effectiveness of different diverters. The effects of chemical diverters, such as relative permeability modifiers (RPMs) and in-situ-crosslinked acids (ICAs), and more-traditional diverters, such as rock salt, are discussed. Because of the advanced monitoring used with the temperature profiles, both the immediate and the sustained effect of the diverters can be measured. The changes in the flow distribution are not limited to diverters. Reactive fluid or changes in flow rate can change the flow distribution as well. These effects were measured during the stimulation treatments.
The post-treatment analysis of the measured temperature profiles in combination with treatment pressures and flow-rate information resulted in accurate knowledge of the effectiveness of the different diverters and stimulation effects over time. This knowledge will be used in future treatments to help optimize volumes, rates, fluid systems, and the selection of the appropriate diverter.
Controlling Bacteria in Recycled Production Water for Completion and Workover Operations
Authors: Tischler A.. , Woodworth T.R.. R. , Burton S.D.. D. , Richards R.D.. D. 
Published: June 2010

Summary
Reusing flowback water and produced water from active wells becomes more and more important in today's oil and gas operations to control surface water volumes in order to keep surface water-disposal costs (reinjection or trucking off the premises) to a minimum, especially in operations that do not require secondary-lift support. However, reusing untreated produced and flowback water in workover and completion operations can promote bacteria growth both above and below ground.
Water produced from oil and gas wells is a perfect environment for sulfate-reducing bacteria (SRB) and certain types of acid-forming bacteria (AFB) because of its anaerobic nature [less than 2 ppm (O2) content] and high nutrients content (e.g., organics, free iron). Reuse of water introduces enough oxygen through regular pumping operations to allow aerobic bacteria to grow mostly slime-forming bacteria (SFB) and other species of AFB. The oxygen content is high enough for aerobic bacteria to grow but is too low to kill anaerobic bacteria. The oxygen content will cause the anaerobic bacteria to stay in a biostatic state that does not kill them, but prevents them from multiplying.
As soon as the bacteria find an environment that is conducive to growth, they will become active again and start multiplying. The anaerobic environment in the formation is ideal for growth of bacteria such as SRB and certain types of AFB. The aerobic environment of the wellbore is conducive for SFB and certain types of AFB. The growth of SRB will not only lead to health and safety (H&S) concerns because of increased sour-gas or hydrogen sulfide (e.g., H2S) production, but also to a slow souring of the formation. This also increases operation expenses because of added corrosion (H2S pitting, stress cracking, microbiologically influenced corrosion) in surface and increases subsurface tubulars and related prevention expenses. Other challenges in production can be related to AFB (pitting) and SFBs (emulsion like materials may form).
Different methods can be applied to prevent bacteria growth and reduce operational expenses related to corrosion prevention, remediation of corrosion effects, and remediation of emulsified produced fluids. This paper will take a closer look at the methods of aeration, chlorine-based applications (sodium hypochlorite, calcium hypochlorite, and chlorine dioxide), and biocide application.
The different methods will be compared through laboratory tests, actual field application, and a rating system. The rating system incorporates environmental, health, and safety (EH&S) concerns, operational application/considerations, effectiveness of the method, and cost.
Each method will be discussed and the pros and cons presented. The pros and cons will be supported by laboratory and field data. The conclusion portion of the paper will discuss why and how the current method of application was chosen and discuss future improvements and testing.
Well Testing of Tight Gas Reservoirs
Authors: Jahabani A. , Aguilera R. 
Published: June 2010

Abstract
A tight gas reservoir is commonly defined as a reservoir having less than 0.1 milliDarcies permeability. Because of the very low permeability, hydraulic fracturing is usually carried out in efforts to establish commercial production. There are several basic concepts and field cases of different well tests in tight gas reservoirs in the literature. In this paper, we gather information and provide a guide to some of the most important tests.
Generally because of low permeability, a well will not flow initially at measurable rates and conventional well testing cannot be applied. We review procedures for design of pre- and postfracture tests in single and dual porosity reservoirs. The prefracture test permits estimating preliminary values of reservoir permeability and initial pressure. The post-fracture test provides data for estimating fracture half length and conductivity. We also review the application of convolution/deconvolution methods to analyze well tests with significant wellbore storage.
Because of economic and environmental reasons, short duration procedures are preferred. However, although effective in many instances, these methods also have their own limitations.

Introduction
Unconventional reservoirs (tight gas, coal bed methane, shales gas and gas hydrates) will be an important pat of the global energy mix for decades to come. Large reserves, long-term potential, costs and gas prices and some other factors account for the great influence of these resources on the future of energy.
There is no formal definition for "tight gas." A commonly used definition, describes tight gas reservoirs as those having permeabilities smaller than 0.1 milliDarcies.
Well testing is generally done as an aid to estimate gas in-place and recoverable volumes. Initial pressure (pi) is a critical parameter not only for estimating gas in-place, but also for determining how much field development is required and whether or not the field is overdeveloped. In addition to pi, well testing provides an estimate of permeability and skin.
A problem associated with well testing in tight gas sands is that usually long times are required to reach radial flow, due to their extremely low permeabilities. Therefore, conventional well tests cannot be applied to these reservoirs. Because of initial uneconomic rates, fracturing is usually required. Lee(2) has suggested procedures for pre- and post-fracture tests design. In order to have measurable gas rates for pre-frac testing, often a breakdown with acid, KCl water or N2 is necessary.
The Role of the Geologist in the Assessment of Continuous Gas Accumulations
Authors: Jenkins C.D. , Levine J.R. 
Published: June 2010

Abstract
Finding and developing continuous gas accumulations such as shales, coal seams and tight sands requires the simultaneous development of accurate geological models together with effective engineering technologies. This linkage is well-established in conventional gas reservoirs where several decades of experience have resulted in a clear and important role for geology in exploration and production. Continuous gas accumulations, however, are substantially different, in that they are regional in extent and lack obvious seals or traps. Geologic controls on gas-in-place and production rates are no less important in continuous reservoirs, but these controls operate on a different scale. Moreover, geologic factors are often misunderstood and can be difficult to quantify. This can lead to the erroneous belief that the geology is either too complex to be understood, or that it is of little importance, or that regional variability is effectively unpredictable, or that reservoir behaviour can be sufficiently approximated with simplistic models. In all such cases, the importance of geology is underestimated.
Many companies have relied largely upon engineering solutions in developing continuous gas resources, while excluding basic geological data and analysis from the project budget as a low-priority item. This makes little sense, however, particularly for marginally economic projects that cannot sustain a high proportion of sub-economic wells. In addition, this approach introduces a high level of guesswork, and reduces the optimization of drilling and completion strategies to trial-and-error. To alter this approach, and to contribute more effectively to the exploration and development of continuous gas accumulations, geologists must do a better job of defining their responsibilities, demonstrating why geological knowledge is important, and offering specific recommendations that will favourably impact the bottom line.

Introduction
As compared with conventional gas reservoirs, continuous gas accumulations typically extend over large stratigraphic thicknesses (tens to hundreds of metres) and lateral distances (tens to hundreds of kilometres). Owing to their size, continuous gas accumulations can encompass a variety of rock-types, having widely varying reservoir properties. The three principal types of continuous gas accumulations are:coal seam gas (CSG), also known as coalbed methane;shale gas; andtight sands.