bluuebunny/crossref_metadata_2025_split huggingface dataset:
Scale Prediction and Inhibition for Oil and Gas Production at High Temperature/High Pressure
Authors: Fan Chunfang , Kan Amy T. , Zhang Ping , Lu Haiping , Work Sarah , Yu Jie , Tomson Mason B. 
Published: November 2012

Summary
With the advance of new exploration and production technologies, oil and gas production has gone to deeper and tighter formations than ever before. These developments have also brought challenges in scale prediction and inhibition, such as the prevention of scale formation at high temperatures (150–200°C), pressures (1,000–1,500 bar), and total dissolved solids (TDS) (&gt;300,000 mg/L) commonly experienced at these depths. This paper will discuss (1) the challenges of scale prediction at high temperatures, pressures, and TDS; (2) an efficient method to study the nucleation kinetics of scale formation and inhibition at these conditions; and (3) the kinetics of barite-crystal nucleation and precipitation in the presence of various scale inhibitors and the effectiveness of those inhibitors. In this study, nine scale inhibitors have been evaluated at 70–200°C to determine if they can successfully prevent barite precipitation. The results show that only a few inhibitors can effectively inhibit barite formation at 200°C. Although it is commonly believed that phosphonate scale inhibitors may not work for high-temperature inhibition applications, the results from this study suggest that barite-scale inhibition by phosphonate inhibitors was not impaired at 200°C under strictly anoxic condition in NaCl brine. However, phosphonate inhibitors can precipitate with Ca2+ at high temperatures and, hence, can reduce efficiency. In addition, the relationships of scale inhibition to types of inhibitors and temperature are explored in this study. This paper addresses the limits of the current predition of mineral solubility at high-temperature/high-pressure (HT/HP) conditions and sheds light on inhibitior selection for HT/HP application. The findings from this paper can be used as guidelines for applications in an HT/HP oilfield environment.
Why Monitoring With a Single Downhole Microseismic Array May Not Be Enough: A Case For Multiwell Monitoring of Cyclic Steam in Diatomite
Authors: Murer Anthony S. , McNeish Greg R. , Urbancic Ted , Prince Marc , Baig Adam M. 
Published: November 2012

Summary
Nine wells were drilled to test cyclic steam stimulation as a recovery mechanism in the diatomite reservoir in the Belridge field. Micro-seismic monitoring was proposed to evaluate steam-chest and fracture growth. A series of models were constructed to determine both microseismic-event detectability and locatability. The modeling indicated that poor signal/noise ratios would constrain the ability to locate events using a single array. As a result, three microseismic-monitoring wells (MOWs) were installed. The purpose of this paper is to evaluate the microseismic-event-location results obtained from the three-well solution and compare them with the solutions obtained when turning off one or two of the arrays. This first phase of investigation was performed on the sand-propped hydraulic-fracture stimulation before the cyclic steam operations. This study may be applied to other areas, including imaging hydraulic-fracture stimulations in shale plays, reservoir steam monitoring, or in any area where location precision in microseismic monitoring is necessary.
It has been demonstrated in the field that the monitoring range of a microseismic system can be increased and the potential for locating microseismic events improved by installing multiple arrays having overlapping radii of observation. Innovative system design, deployment techniques, operational procedures, and advanced multiwell processing strategies have all contributed to creating a growing data set with more than 4,000 events recorded during the first 13 months of operation. Results of turning off arrays showed increased location error with two-well solutions and a significant increase in error with one-well solutions, notwithstanding the reduction in event location count because of a lack of multiphase signals on a single array. Azimuth errors in single-microseismic-observation-well solutions result in dispersed interpreted fracture geometry and in misinterpretation.
Overall, our observations show that for both multi-and singlephase events, the observed detection limits and size distribution of the seisms have far exceeded those originally predicted by the earlier modeling.
A Comparison of Hydraulic-Fracture Modeling With Downhole and Surface Microseismic Data in a Stacked Fluvial Pay System
Authors: Mohammad Nur Azlinda , Miskimins Jennifer L. 
Published: November 2012

Summary
This paper presents a study that combines and compares the results of hydraulic-fracture mapping and modeling using both downhole and surface microseismic arrays. There were three objectives for the study: developing detailed post-treatment models of hydraulic-fracturing treatments in the subject well, Well D1, which was monitored with downhole microseismic tools; developing detailed post-treatment models of the hydraulic-fracturing treatments in the subject well, Well S1, which was monitored with surface microseismic tools; and determining the match characteristics of the downhole and surface microseismic data to hydraulic-fracture models developed for both Wells D1 and S1.
Input data for this project were obtained from two wells in the Greater Natural Buttes field, Uinta basin, Utah. Ten fracture models were built using five stages each from the two subject wells, Wells D1 and S1, and detailed pressure matches were made. Comparisons of the match characteristics from the multiple inputs were then developed. The hydraulic-fracture-stimulation models were graphically integrated with the microseismic events using visualization software. This software allowed the final model-simulated fracture geometries to be plotted along with the microseismic events in 3D space, thus allowing the viewer to see a full integration of data in a stacked fluvial pay system.
Results from the integration process show good agreement in geometries and depth for most stages in the downhole-monitored well, whereas comparisons of surface microseismic-mapping measurements with the simulated fracture geometries yielded variable results. When combined with additional inputs such as geologic models, the integration methodology used in this project provides an excellent tool for hydraulic-fracture modeling and reservoir management in stacked pay systems.
Role of Stress Reorientation in the Success of Refracture Treatments in Tight Gas Sands
Authors: Roussel Nicolas P. , Sharma Mukul M. 
Published: November 2012

Summary
The redistribution of stresses around a fractured vertical well has two sources: opening of propped fracture (mechanical effects) and production or injection of fluids in the reservoir (poroelastic effects). In this paper, the coupling of both phenomena was numerically modeled to quantify the extent of stress reorientation around fractured production wells. The results have been compared to field data from the Codell tight gas formation and analyzed for their impact on refracturing operations.
For previously fractured wells, a secondary fracture may be initiated perpendicular to the first fracture if a stress-reversal region is present. Altered-stress refracturing makes it possible to access zones of the reservoirs that are less depleted, thus increasing well production and reserves.
The results of our model quantitatively agree with previous tiltmeter measurements, confirming the existence of refracture reorientation in the Codell formation. The performance of refracturing treatments has been observed to be highly variable in the Wattenberg field (Colorado), with some wells underperforming while others are restored to initial production rates. Historical production from neighboring wells and initial fracture performance were shown to impact the potential benefits from refracturing predicted by the numerical model.
This paper introduces a 3D model, coupling mechanical and poroelastic stress reorientation used to interpret tiltmeter measurements and historical production in the Codell tight gas formation. Guidelines are drawn from the Wattenberg field case study that allow an operator to select candidate wells, choose the timing of the refracture operation in the life of the well, and evaluate the potential increase in well production after refracturing.
Liquid Entrainment in Annular Gas/Liquid Flow in Inclined Pipes
Authors: Magrini K.L.. L. , Sarica C.. , Al-Sarkhi A.. , Zhang H.-Q.. -Q. 
Published: November 2012

Summary
Entrainment fraction is one of the key parameters in many applications, including wellbore and flowline design, separator design, wellbore loading, and corrosion inhibition. This study provides the first comprehensive entrainment data and their critical analysis for a full range of inclination angles ranging from horizontal to vertical in 76.2-mm-internal-diameter (ID) pipes. Experiments were conducted to investigate the effect of pipe inclination on entrainment fraction in air/water annular flow with inclination angles of 0, 10, 20, 45, 60, 75, and 90° from horizontal. Two techniques were used to measure the entrainment fraction: film removal and isokinetic sampling. The experimental results were compared with existing models and correlations, and the best predicting methods were determined for all flow orientations.
An inclination effect on entrainment fraction was observed. This effect occurred at low superficial gas velocities and was more prominent for higher superficial liquid velocities. Using the present study data, the Paleev and Filipovich (1966) correlation was found to be the most accurate in predicting entrainment fraction. On the basis of all available data, the Pan and Hanratty (2002b) correlation performed the best in predicting entrainment fraction in all pipe orientations. For vertical annular flow, the Oliemans et al. (1986) correlation predicted entrainment fraction more accurately. The Pan and Hanratty (2002b) correlation was the most accurate in predicting entrainment fraction for horizontal annular flow. The Wallis (1969) correlation and the mechanistic model developed by Mantilla (2008) most accurately predicted the entrainment fraction for inclined annular flow.
Multiphase Fluid-Loss Properties and Return Permeability of Energized Fracturing Fluids
Authors: Ribeiro L.H.. H. , Sharma M.M.. M. 
Published: November 2012

Summary
With the growing interest in low-permeability gas plays, foam* fracturing fluids are now well established as a viable alternative to traditional fracturing fluids. Present practices in energized fracturing treatments remain, nonetheless, rudimentary in comparison to other fracturing-fluid technologies because of our limited understanding of multiphase fluid-loss and phase behavior occurring in these complex fluids. This paper assesses the fluid-loss benefits introduced by energizing the fracturing fluid.
A new laboratory apparatus has been specifically designed and built for measuring the leakoff rates for both gas and liquid phases under dynamic fluid-loss conditions. This paper provides experimental leakoff results for linear guar gels and for N2/guar foam-based fracturing fluids under a wide range of fracturing conditions. In particular, the effects of the rock permeability, the foam quality, and the pressure drop are investigated. Analysis of dynamic leakoff data provides an understanding of the complex mechanisms of viscous invasion and filter-cake formation occurring at the pore scale.
This study presents data supporting the superior fluid-loss behavior of foams, which exhibit minor liquid invasion and limited damage. It also shows direct measurements of the ability of the gas component to leakoff into the invaded zone, thereby increasing the gas saturation around the fracture and enhancing the gas productivity during flowback. Our conclusions not only confirm but add to the findings of McGowen and Vitthal (1996a, b) for linear gels and the findings of Harris (1985) for nitrogen foams.
Red vs. Green Scale Inhibitors for Extending Squeeze life—A Case Study From the North Sea, Norwegian Sector—Part II
Authors: Jordan M.M. , Sorhaug E. , Marlow D. 
Published: November 2012

SummaryOver the years, environmental legislation has forced changes in the types of scale-inhibitor molecule that can be deployed in certain regions of the world. These regulations have resulted in changes from phosphonate scale inhibitor to polymer-based chemistry, particularly in the Norwegian and UK continental shelf where phosphonates have been either on the substitution list or phased out for many applications. Over the past 10 years, significant improvements in inhibitor properties of the so-called "green" scale inhibitors have been made. However, for one particular operator, the squeeze application of this green scale inhibitor resulted in poorer than expected treatment lifetimes and significant operating cost because of the frequency of retreatment. To overcome the increasing operating cost, an evaluation was made of the current treatment chemicals vs. the older, more-established phosphonate scale inhibitors. The results for the laboratory evaluation suggested that the older chemistry would extend treatment life and reduce operating cost. A case was made to the legislative authority, who approved the use of the phosphonate scale inhibitor, and field applications started. The squeeze lifetimes for the red phosphonate chemistry were shown to be significantly better than the existing yellow/green inhibitors. During the following months, other scale inhibitors with improved environmental characteristics were developed and evaluated. One such molecule was shown to have similar coreflood retention to that of the applied red phosphonate and presented no formation damage. This paper presents the laboratory evaluation of the new scale inhibitor, and illustrates the improvement observed with this new inhibitor through field squeeze-treatment results from a well treated with both the red and new yellow environmental profile inhibitor chemicals.This paper outlines the challenges with environmental legislation and how it has been possible to develop technical solutions (in terms of environmental vs. safety issues and with new inhibitor chemicals) to meet the challenges of offshore scale control.
Field Study of the Physical and Chemical Factors Affecting Downhole Scale Deposition in the North Dakota Bakken Formation
Authors: Cenegy L.M.. M. , McAfee C.A.. A. , Kalfayan L.J.. J. 
Published: November 2012

SummaryNorth Dakota Bakken oil recovery has increased nearly 100-fold over the last 5 years, driven by technological advancements in hydraulic fracturing and completion design. For one North Dakota operator with 150 Bakken producing wells, 22 of the wells have experienced at least one event of severe calcium carbonate scaling in the pump and production tubing, leading to well failure. Bakken wells are completed to a vertical depth of approximately 10,000 ft, with horizontal laterals up to 10,000 ft, and are produced by means of multizone hydraulic fracturing.The operator initially conducted a typical scale-prediction study to reduce well failures and maintain oil production. However, the scale-prediction study was challenging to perform for these Bakken wells because of the variability of the composition of the produced water. Attention then turned to the tracking and analysis of historical field conditions. A “post-mortem” of data collected from all failed wells because of scale was conducted, considering the failure type, date, type of hydraulic-fracturing procedure, pump-intake pressure, scale-inhibitor residual, calcium carbonate scaling index, geographic failure concentration, production time to failure, and cumulative water production to failure.Results showed that 82% of the wells failed during early production (defined as less than 20,000 bbls of water produced and 2 years' production since first oil), after which failures became increasingly rare. This correlated with transient alkalinity spikes in the water analyses attributed to fracturing-fluid flowback during this critical period. Simulated blending of fracturing and formation waters demonstrated that this was the most important period to maintain high scale-inhibitor residuals because of high deposition potentials.This paper discusses the various field and laboratory studies conducted in an effort to understand the problem, the results obtained, and the implications. Also discussed is the evaluation of two scale inhibitors before and after laboratory aging in simulated fracturing fluids.
Accurate Cell-Centered Discretizations for Modeling Multiphase Flow in Porous Media on General Hexahedral and Simplicial Grids
Authors: Wheeler Mary F. , Xue Guangri , Yotov Ivan 
Published: November 2012

Summary
We introduce an accurate cell-centered method for modeling Darcy flow on general quadrilateral, hexahedral, and simplicial grids. We refer to these discretizations as the multipoint-flux mixed-finite-element (MFMFE) method. The MFMFE method is locally conservative with continuous fluxes and can be viewed within a variational framework as a mixed finite-element method with special approximating spaces and quadrature rules. We study two versions of the method: with a symmetric quadrature rule on smooth grids and a nonsymmetric quadrature rule on rough grids. The framework allows for handling hexahedral grids with nonplanar faces defined by trilinear mappings from the reference cube. Moreover, the MFMFE method allows for local elimination of the velocity, which leads to a cell-centered pressure system. Theoretical and numerical results demonstrate first-order convergence on rough grids. Second-order superconvergence is observed on smooth grids. We also discuss a new splitting scheme for modeling multiphase flows that can treat higher-order transport discretizations for saturations. We apply the MFMFE method to obtain physically consistent approximations to the velocity and a reference pressure on quadrilateral or hexahedral grids, and a discontinuous Galerkin method for saturations. For higher-order saturations, we propose an efficient post-processing technique that gives accurate velocities in the interior of the gridblocks. Computational results are provided for flow in highly heterogeneous reservoirs, including different capillary pressures arising from different rock types.
The Effect of Fracture-Face Matrix Damage on Productivity of Fractures With Infinite and Finite Conductivities in Shale-Gas Reservoirs
Authors: Li J.. , Guo B.. , Gao D.. , Ai C.. 
Published: November 2012

Summary
Producing natural gas from shale-gas reservoirs presents a great challenge to petroleum engineers owing to the low-permeability nature of this type of gas reservoir. Large-scale and expensive hydraulic-fracturing operations are often required for enhancing gas well productivity. Because of the shaly characteristics of the reservoir rock, the hydraulically fractured gas wells are vulnerable to damage by fracturing fluids. However, the true significance of the formation damage in shale-gas reservoirs is still not clear. It is highly desirable to have a simple method for predicting the degree of fracture-face matrix damage and for optimizing fracturing treatments. This paper is meant to fill this gap.
A new mathematical model was developed in this study to predict the effect of fracture-face matrix damage on the productivity of fractured gas wells in shale-gas reservoirs. A unique feature of the new model is that it considers reservoir/fracture crossflow in finite-conductivity fractures. Results of the model analyses were sensitized to reservoir properties and facture-face matrix-skin properties determined by the fracturing-fluid properties and treatment conditions. Large ranges of possible leakoff and spurt-loss coefficients were investigated. We concluded that, in the ranges of reservoir and fluid properties used in this study, well productivity should drop by less than 15% even if the residual matrix permeability is reduced to only 5% of the virgin reservoir permeability in the damage zone. Neglecting the resistance to flow in the fracture will overestimate the effect of matrix damage on well productivity. The well-productivity drop caused by matrix damage is most sensitive to the invasion depth and damaged permeability.
A Novel Technique for Monitoring Hydrate Safety Margin
Authors: Yang Jinhai , Chapoy Antonin , Mazloum Saeid , Tohidi Bahman 
Published: November 2012

SummaryA novel technique has been developed for optimizing hydrate-inhibitor dose rates by monitoring the actual hydrate safety margin. The technique is based on measuring acoustic velocity and electrical conductivity in an aqueous sample taken from the pipeline/separator. The developed system then determines salt and organic inhibitor concentration (e.g., methanol, monoethylene glycol, and kinetic hydrate inhibitors). In the case of thermodynamic inhibitors, the information is then fed to a thermodynamic model determining the hydrate stability zone (HSZ). Superimposing the pipeline operating conditions (e.g., pressure and temperature profile), the developed system can determine the hydrate safety margin. The system can provide warning if the operating conditions are inside the HSZ or if too much inhibitor is being injected.The technique can be used in optimizing inhibitor-injection rates, reducing the impact on the environment and operational costs. It can also improve production-system reliability by constant monitoring the hydrate safety margin and protecting the system against pump malfunction and/or changes in process variables (e.g., water cut).This technique has been developed through a joint-industry project, and its performance has been intensively evaluated using synthetic samples and real produced-water samples by the authors and the project sponsors in field trials. The results demonstrate that this system can be used for different inhibitor systems, including methanol (MeOH)/NaCl, monoethylene glycol (MEG)/NaCl, and kinetic-hydrate-inhibitor/salt systems, with good accuracy.The developed system can have a major impact on reducing the inhibitor-injection rates and environmental impact and improving the reliability of production systems against risks associated with hydrate formation. The developed system can be laboratory-based, a mobile unit, or online, with near-real-time samples taken from live pipelines/separators.
Detailed Modeling of the Alkali/Surfactant/Polymer (ASP) Process by Coupling a Multipurpose Reservoir Simulator to the Chemistry Package PHREEQC
Authors: Farajzadeh R.. , Matsuura T.. , van Batenburg D.. , Dijk H.. 
Published: November 2012

SummaryAccurate modeling of an ASP flood requires detailed representation of geochemistry and, if natural acids are present, the saponification process. Geochemistry and saponification affect the propagation of the injected chemicals and the amount of generated natural soaps. These in turn determine the chemical phase behavior and, hence, the effectiveness of the ASP process.In this paper, it is shown that by coupling a multipurpose reservoir simulator (MPRS) with PHREEQC (Parkhurst and Appelo 1999; Charlton and Parkhurst 2008), a robust and flexible tool is developed to model ASP floods. PHREEQC is used as the chemical-reaction engine, which determines the equilibrium state of the chemical processes modeled. The MPRS models the impact of the chemicals on the flow properties, solves the flow equations, and transports the chemicals.The validity of the approach is confirmed by benchmarking the results with the ASP module of the UTCHEM simulator (Delshad et al. 2000). Moreover, ASP corefloods have been matched with the new tool. The functionality of the model also has been tested on a 2D sector model. The advantages of using PHREEQC as the chemical engine include its rich database of chemical species and its flexibility in changing the chemical processes to be modeled. Therefore, the coupling procedure presented in this paper can also be extended to other chemical enhanced-oil-recovery (EOR) methods.