bluuebunny/crossref_metadata_2025_split huggingface dataset:
Modeling the Impact of Capillary Pressure Reduction by Surfactants
Authors: Gdanski Rick 
Published: December 2007

Abstract
Fluid recovery after fracturing treatments in tight gas reservoirs is often critical in obtaining maximum production rates. Fluid recovery aids in washing broken fracturing fluid out of the propped fracture and restores the relative permeability to gas in the invaded matrix of the fracture face. However, recovery of fracturing fluids from the invaded matrix requires overcoming both capillary pressure-driven imbibition and the capillary exit pressure that occurs at the fracture boundary between the matrix and propped fracture. Surface active materials, such as alcohols and surfactants, are often used to reduce the surface tension, and hence the capillary pressure functions in the matrix. These materials are expected to enhance recovery of the fracturing fluid from the matrix, improving load recoveries. Modeling this process with classical reservoir simulators is not possible because they do not allow for the impact of surface tension reduction on capillary pressure functions. A previously reported simulator for modeling fracturing fluid movement has been modified to accommodate the impact of surface tension reduction on capillary pressure. This simulator uses the simultaneous solution (SS) method for solving the two-phase flow equations, followed by calculation of the movement of chemicals based on the pressure solution at each time step. A new modification to the SS method has been developed to allow proper modeling of the impact of capillary pressure reduction by surfactants.
Surfactants can reduce capillary pressure in the matrix by reducing surface tension and/or by changing the wettability of the rock surface when they adsorb on a surface. The classical SS method does not maintain proper "mass balance" when surfactants are allowed to change the capillary pressure; the reason for which is demonstrated in this work. The new modification allows surfactants to impact capillary pressure through surface tension reduction and wettability changes.
Stimulation of Gas Shales: They're All the Same—Right?
Authors: Matthews H. Lee , Schein Gary , Malone Mark 
Published: December 2007

Abstract
In recent years, the upswing in drilling activity and the higher price of natural gas has caused the industry to focus more on non-conventional gas reservoirs. Heading up this list are gas shales. This peaked interest was brought on not only by an increase in natural gas prices, but also the apparent abundance of potential gas shales present in the continental United States and the well publicized success of the Barnett Shale of North Texas. In order to obtain commercial production from these low permeability shale reservoirs, fracture stimulation is required. Numerous technical papers have been published on the merits and success of stimulation in this well documented reservoir. While slickwater treatments have become the stimulation method of choice, it is important to note that several other stimulation and completion techniques have been employed that have resulted in economic and commercially viable Barnett Shale producers over the last 20 years. Although there has been tremendous success with slickwater fracture treatments, many believe this technology can be universally applied to all gas shale reservoirs. While this may be the case in the Barnett Shale it is not necessarily true for other prospective shale basins being explored.
This paper will include a brief history of Barnett Shale stimulation practices and go on to address shale reservoirs and characteristics that make each one unique from a stimulation perspective. It is not the attempt of the authors to provide a stimulation checklist, but to identify a number of shale reservoir characteristics and their effect on the process of stimulation optimization. Case histories in the Ft. Worth Barnett and Permian Basin Barnett and Woodford Shales will be used to infer key differences in reservoir attributes and how these differences influence stimulation decisions.
Experimental Investigation and Modeling of Naphthenate Soap Precipitation Kinetics in Petroleum Reservoirs
Authors: Sarac S. , Civan F. 
Published: December 2007

Abstract
The mechanism, reaction kinetics, and rate equation of the naphthenate soap precipitation are determined by means of experimental and theoretical investigations. Such information may be important for controlling and minimizing the well productivity loss by naphthenate soap precipitation in petroleum reservoirs. This was accomplished by three means: a) Static bottle tests were conducted to determine the precipitation rate at various pH and temperature conditions, b) particle size growth of the naphthenate soap precipitates was investigated under static conditions to determine the governing growth mechanism, and c) core flow tests were run to determine the effect of the naphthenate soap precipitation on permeability impairment in porous media. The naphthenate soap precipitation rate was correlated with respect to the considered parameters based on a power-law expression. The measured particle size data indicated the growth of particle size with time. Finally, the core flow tests allowed the determination of the impact of the naphthenate soap precipitation in porous media in terms of the permeability impairment and damage ratio. The results of these studies may be instrumental in avoiding or minimizing formation damage problems associated with the naphthenic acid containing petroleum reservoirs.
Remediation of Proppant Flowback—Laboratory and Field Studies
Authors: Nguyen Philip D. , Weaver Jimmie D. , Rickman Richard D. , Sanders Michael W. 
Published: December 2007

Abstract
This paper presents the results of laboratory studies and field case histories of a remedial treatment technique using a low-viscosity consolidation fluid system that is placed into the propped fractures by coiled tubing (CT) or jointed pipe coupled with a pressure pulsing tool. The treatment fluids are designed to provide consolidation (for previously placed proppant) near the wellbore to glue the proppant grains in place without damaging the permeability of the proppant pack.
Laboratory flow testing indicates that the proppant pack in a fracture model under closure stress only requires low-strength bonds between proppant grains to withstand high production flow rates. The consolidation treatment transforms the loosely packed proppant in the fractures and the formation sand close to the wellbore into a cohesive, consolidated, yet highly permeable pack. Field case histories are presented and the treatment procedures, precautions, and recommendations for implementing the treatment process are discussed. One major advantage of this remedial treatment method is the ability to place the treatment fluid into the propped fractures, regardless of the number of perforation intervals and the length of the perforated intervals without mechanical isolation between the intervals. The fluid placement efficiency of this process makes remediation economically feasible, especially in wells with marginal reserves.
Zeta Potential Altering System for Increased Fluid Recovery, Production, and Fines Control
Authors: Kakadjian Sarkis , Zamora Frank , Venditto Jim 
Published: December 2007

Abstract
This paper presents a new zeta potential altering system that is based on an inner salt developed to enhance the water flowback recovery on borate and slick-water frac jobs. The system also aids in the control of fines. The mechanism of this system is to modify the zeta potential on particles such as frac sand from -50 mV, or coal from -28 mV, to more neutral values. This modification helps increase the potential for particle agglomeration and changes in the sand pack in the fracture to increase fluid recovery and production.
Results from lab studies have shown that the flow rate ratio for a 2% KCl solution through sand packs (treated/not treated) increased up to 45% when treated with 6.0 gal of chemical per 1,000 lb of frac sand. Similar results were obtained on conductivity tests using ceramic proppant, improving conductivity from 7,150 mD-ft to 11,387 mD-ft at 2,000 psi closure stress.
This new system does not interfere with fracturing fluid rheological profiles for borate systems and improves friction reducing characteristics in slick-water systems.
The system was tested in the field on a slick-water job, where the additive was mixed in the blender tub.
Mixed Finite Element and Related Control Volume Discretizations for Reservoir Simulation on Three-Dimensional Unstructured Grids
Authors: Matringe S. F. , Juanes R. , Tchelepi H. A. 
Published: December 2007

Abstract
The numerical discretization of the reservoir flow equations is a challenging problem on three-dimensional unstructured grids and in the presence of full-tensor permeabilities. Finite volume methods based on a two-point flux approximation (TPFA) do not properly account for grid distortion or permeability anisotropy that is misaligned with the grid. Over the past decade, multipoint flux approximation (MPFA) methods have been devised to address these issues. Recent research has shown, however, that MPFA methods may lead to unphysical nonmonotonic solutions for high anisotropy ratios or strongly distorted grids.
In this paper, we work in the mathematical framework of mixed finite element methods (MFEM). We study a low- and high-order accurate MFEM, based on the lowest order Raviart-Thomas space (RT0) and the Brezzi-Douglas-Marini space of order one (BDM1). On tetrahedrons, the BDM1 space can be localized into a compact finite volume method through the use of an appropriate numerical quadrature. However, this is not possible for hexahedrons.
The main result of this paper is the development of a new mixed finite element method for 3D hexahedral grids, which leads to a multipoint flux approximation finite volume method through the use of a vertex-based numerical quadrature. This is possible because the new velocity space is designed so that the degrees of freedom are the normal component of the velocity field at the vertices of each face. This establishes for the first time a direct link between MFEM and MPFA methods on 3D hexahedral grids.
We compare the performance of classical (RT0 and BDM1) mixed finite element methods with the newly developed method on a number of test cases. We conclude that high-order methods lead to higher-quality velocity fields that are less sensitive to the choice of the grid, and that they have better monotonicity properties for highly anisotropic full-tensor permeability fields. While the added benefit of the new space is that it can be approximated by a cell-centered finite volume scheme, our numerical experiments indicate that the accuracy of the scheme is reduced.
The Development of a Scale Management and Monitoring Program for a High-Temperature Oil Field During the Production-Decline Phase of the Life Cycle
Authors: Jordan Myles , Sørhaug Eyvind , Elrick Morag , Marlow David 
Published: December 2007

Abstract
This paper presents field results from scale squeeze treatments carried out on platform wells within a high temperature (150C) field in the Norwegian sector of the North Sea. Scale control and the resulting squeeze treatments to production wells were highlighted as the most expensive item in the production chemical budget. The development of a cost-effective squeeze and monitoring policy has been critical to reducing the operating cost of this asset as the produced water cut rose.
The decision to use both aqueous and emulsified scale inhibitor for treating these high temperature production wells was arrived at after an extensive series of laboratory tests including formation damage coreflood studies and an assessment of chemical retention at this elevated temperature. The field data from these wells will be presented comparing treatment lifetimes and clean up rates between conventional treatments and the novel emulsion technology
A key factor to the success of such treatment is an understanding of chemical placement and the effectiveness of the treatment chemicals. Evaluation of residual chemical concentration or scaling ion chemistry has long been used in monitoring programs and more recently probes have been developed which increase the rate of evaluation/interpretation. All these monitoring methods prove that the chemical is present in the brine when sampled or that scale formation is not occurring at the point of brine analysis. This paper outlines the experimental methods developed to evaluate the suspended solids collected from the produced brine by environmental scanning electron microscope (ESEM) and the associated brine chemistry to evaluate the scale risk within the produced fluids. The combination of these methods has improved the integrated scale management program in terms of evaluating scale squeeze placement effectiveness, squeeze lifetime and provides the confidence t0 extend the period between scale squeeze treatments. Also, and in some cases treatments were stopped where brine analysis alone would have suggested further scale squeeze applications were required.
Field Trial Design and Analyses of Production Data from a Tight Gas Reservoir: Detailed Production Comparisons from the Pinedale Anticline
Authors: Vincent M. C. , Huckabee Paul , Conway Michael 
Published: December 2007

Abstract
Field trials of new methodologies, products or technologies are considered to be an effective way to gauge the true value of such innovations. However it is difficult and expensive to conduct a rigorous field trial, especially in tight, multi-layered reservoirs, and proper design and analyses are critical to accurately interpret the results. In multi-layered reservoirs the production from individual frac stages must often be evaluated with production logs - this additional expense accentuates the need to carefully design the field trial and thoroughly analyze the resulting data to extract as much value as possible. This paper will provide a detailed comparison of well productivity in the Pinedale Anticline as a function of proppant type and subinterval. Well production has been normalized by many parameters, including reservoir kh, khΔP, kh*(Pr2-Pf2), Φh, and also compared by well location to determine the degree to which those techniques provide similar conclusions. In addition to describing how these field results influence proppant selection in the Pinedale Anticline, this paper will describe many aspects of field trial planning, as well as the proper handling of data to assist in the design of future trials.
This paper will review the following topics: –Design of the field trial–Efforts to minimize variables–Well selection to promote valid offset comparisons–Data handling techniques to minimize bias–Production logging of wells – calibration and timing–Detailed comparison of production data, normalized with six methods to determine whether consistent conclusions can be reached–Statistical analyses to determine whether statistically significant conclusions can be drawn with a high degree of confidence
The results of this study will also be compared to other published field trials to examine well populations, data consistency, and to assess whether studies in similar reservoirs carry similar findings. This paper will summarize the conclusions that are consistent between numerous tight gas field studies in the region, and highlight changes to fracture treatments which have consistently improved well productivity and profitability in these reservoirs.
Advanced Nitrate-Based Technology for Sulfide Control and Improved Oil Recovery
Authors: Dennis D. M. , Hitzman D. O. 
Published: December 2007

Abstract
Industry now recognizes that nitrate based technology is preferred to biocide treatments for the control, prevention, and removal of biogenic produced sulfide in sea and produced water injection systems. Advanced formulations with varying ratios of nitrate/nitrite have proven superior to nitrate-only treatments by providing increased effectiveness at lower treating levels with reduced costs. Concurrent with sulfide control these advanced nitrate/nitrite combination formulations have demonstrated significant increased oil recovery in field operations. Data show the dual benefits of the advanced nitrate/nitrite technology to offer industry the opportunity to reduce operating costs while additionally producing more oil.
Kinetic Parameters for Dilute Epoxy Resins Measured by Nuclear Magnetic Resonance Spectroscopy
Authors: Rickman Richard D. , Wilson J. Michael , Weaver Jim D. 
Published: December 2007

Abstract
Thermosetting resins are employed in a wide variety of oilfield applications. The development of dilute resin formulations offers several advantages over conventional resin systems and new resin applications are making increasing use of dilute formulations. Knowledge of the thermodynamic properties of the resin system is essential to ensure that they perform as expected. We report here on the use of nuclear magnetic resonance, NMR, to measure activation energies, enthalpies, entropies, and frequency factors for the curing of a diglycidylether bisphenol A epoxy resin with a modified cycloaliphatic amine hardener. Results calculated with this technique are presented here and are in good agreement with values calculated using more conventional techniques.
Simulation of Surfactant-Aided Gravity Drainage in Fractured Carbonates
Authors: Adibhatia B. , Mohanty K. K. 
Published: December 2007

Abstract
Waterflooding often recovers little oil from carbonate reservoirs because carbonate reservoirs are usually oil-wet and fractured. Dilute surfactant solution injection into the fractures can improve oil production from the matrix by lowering the oil/water interfacial tension (IFT) and by altering the wettability of the rock to intermediate/water-wetting. A 3-D, two-phase, multicomponent, finite-difference, fully-implicit numerical simulator is developed that incorporates adsorption, phase behavior, wettability alteration, and related capillary pressure / relative permeability variations. The reliability of the simulator is established by comparing the core-scale simulation results with experimental results obtained in our laboratory. IFT reduction, wettability alteration and permeability are varied to study the sensitivity of the surfactant-aided gravity drainage to these process parameters. Wettability alteration drives the oil production at the early stage, but gravity is the major driving force afterwards. Surfactants which alter the wettability to a water-wet regime give higher recovery rates for higher IFT systems. Surfactants which cannot alter wettability give higher recovery for lower IFT systems. Extent of wettability alteration increases the rate of oil recovery. Recovery rate decreases with permeability significantly for a low tension system, but only mildly for high tension systems.
Accelerating Effect of Surfactants on Gas Hydrates Formation
Authors: Pakulski Marek 
Published: December 2007

Abstract
Low dosage gas hydrate inhibitors (LDHI) are divided into two categories; kinetic hydrate inhibitors (KHI) and antiagglomerants (AA). KHI are mostly polymeric or oligomeric compounds while all AA have surface active properties. AA molecules must have hydrophilic "head" attaching to a surface of hydrate particle and hydrophobic "tail" to repel other hydrate particles; thus, preventing hydrate agglomeration. All surfactants having hydrophilic and hydrophobic functionality have some AA properties; however, only a handful of such compounds have found commercial applications in the oilfield.
Some surfactants present in the liquid water phase accelerate formation of gas hydrates. Foaming agents are particularly strong hydrate accelerators. Foamers, if present in water solution, can diminish or nullify the protecting effect of polymeric KHI. Some KHI and practically all AA chemicals used for hydrate control in the oilfield have foaming properties that could result in faster hydrate formation than similar non-foaming products. In some situations, gas producing wells are treated with foaming agents to enhance gas production through improved water unloading. The gas/water stream can require hydrate protection due to Joule-Thomson cooling effect or because of pressure/temperature (p/T) conditions in flowlines. Hydrate conditions can be encountered during flow back operation from foam fractured gas wells. Such conditions must be predicted and prevented through a proper flow back regime or chemical addition to the fluid prior to fracturing operation.
Laboratory experiments proved the accelerating hydrate formation effect of three main types of foaming surfactants; nonionic, cationic and amphoteric. However, the most dramatic effect was when an insufficient amount of methanol was mixed with the foaming agents. A possible mechanism of the acceleration effect could be related to increased gas/water surface contact in foams; thus, accelerating dissolution of gas in water. Emulsifying properties of foaming agents contribute also to the hydrate accelerating phenomenon.
A Study on Catalytic Aquathermolysis of Heavy Crude Oil During Steam Stimulation
Authors: Wen Shoubin , Zhao Yujian , Liu Yongjian , Hu Shaobin 
Published: December 2007

Abstract
The aquathermolysis of Liaohe heavy crude oil during steam stimulation was studied by using molybdenum oleate as oil-soluble catalyst for the reaction in this paper. The laboratory experiment shows that viscosity-reduction ratio of heavy oil is over 90% at 240°C, 24hr, with 0.5wt% catalyst solution. The field test that applied aquathermolytic technology in puff-and-huff operation was carried out in Qi-40 and Qi-108 blocks of Liaohe oilfield. As a result, significant viscosity reduction and production increase were obtained. Further filed test indicated that the cycle decline rate of heavy oil production in puff-and-huff operation was improved by aquathermolytic technology.
Acceleration of Streamline Simulation Using Adaptive Mesh Refinement Along Streamlines
Authors: Andrianov Nikolay , Bratvedt Kyrre 
Published: December 2007

Abstract
Streamline methods have become an efficient technology for reservoir simulation. The key assumption of the method is that the pressure field can be updated relatively less frequently, and the saturations can be transported along the streamlines defined by the velocity field. The efficiency of the solution method along the streamlines is very important for the overall efficiency of the method.
In this work, the acceleration of the saturation transport using adaptive mesh refinement (AMR) along streamlines is investigated. The refinement strategy is based on the multi-scale wavelet techniques. The one-dimensional solution is decomposed into a set of coarse-grid cell values and a set of solution details, which indicate the smoothness of the solution. This decomposition is recursively applied to the resulting representation until the coarsest mesh level is reached. From this multi-resolution representation of the solution an adaptive grid is constructed by thresholding of negligible details. Then, a second-order finite volume method is used on the obtained adaptive grid.
The performance of the resulting multi-resolution scheme on a synthetic and a real reservoir model is studied, using two-phase incompressible and three-phase black oil compressible data. It is shown that the use of the AMR technique can provide up to a five-fold acceleration compared to the solution of the same numerical method on a uniform grid. The proposed technique is implemented in a commercial reservoir simulator.