bluuebunny/crossref_metadata_2025_split huggingface dataset:
Nuclear Magnetic Resonance Applied to Gas Detection in a Highly Laminated Gulf of Mexico Turbidite Invaded with Synthetic Oil Filtrate
Authors: Moore M. A. , Akkurt R. 
Published: December 2007

Abstract
A recently developed time-domain nuclear magnetic resonance (NMR) technique applying matched filters to the difference of raw echo trains acquired with different wait times has proven effective in detecting and quantifying free gas in a highly laminated Gulf of Mexico (GOM) turbidite deposit expected to be badly invaded by synthetic oil-base drilling fluid. This case history is the first documented use of this approach under these conditions, and it clearly met objectives where the more conventional differential spectrum method (DSM) failed.
The technique was applied to data acquired in the Shell-operated Tahoe Field. The VK783 #5 penetration encountered one-hundred-seventy gross feet of laminated turbidite reservoir averaging 50% net to gross through much of the interval. The well was thirteen-hundred psi overbalanced, and this, combined with the miscible filtrate made severe invasion and near residual gas saturations a certainty near the wellbore. Conventional wireline gas indicators such as neutron-density crossover and the various cross plots fail in this environment due to tool inability to resolve the sand beds and to the abundance of shale laminae, and is aggravated by the invasion. Fluid typing is primarily done with fluid pressure gradients established via formation tester. For this well, the logging program included quad-combo, NMR (MRIL-C®) and formation tester. The formation tester proved gas to base in the reservoir, showing a .0951 psi/ft fluid pressure gradient.
The conventional DSM analysis carried out in the T2 domain showed a strong signal from the invading filtrate, but was ambiguous with respect to gas detection. Careful examination of the raw echo train data using matched filters showed clearly both heavy filtrate invasion, and the presence of gas in low saturations. This result is a significant advance in turbidite formation evaluation, providing our petrophysical toolbox with a new, powerful fluid typing tool that has proven effective even under very challenging conditions.
A Hybrid, Neuro-Genetic Approach to Hydraulic Fracture Treatment Design and Optimization
Authors: Mohaghegh S. , Balan B. , Ameri S. , McVey D. S. 
Published: December 2007

Summary
This paper summarizes the efforts conducted toward the development of a new and novel methodology for optimal design of hydraulic fracture treatments in a gas storage field. What makes this methodology unique is its capability to provide engineers with a near optimum design of a frac job despite very little (almost none) reservoir data availability. Lack of engineering data for hydraulic fracture design and evaluation had made use of 2D or 3D hydraulic fracture simulators impractical. As a result, prior designs of hydraulic frac jobs had been reduced to guess works and in some cases dependent on engineers with many years of experience on this particular field, who had developed an intuition about this formation and its possible response to different treatments. This was the main cause of several frac job failures every year. On the other hand, in case of relocation of engineers with experience on this particular field the risk of even more frac job failures was imminent.
The unique design optimization method presented here is a logical continuation of the study that was covered in two previous papers1,2. To thoroughly understand this methodology, reading of these two references are highly recommended. This method will accept available data on each well, which includes basic well information and production history, and provides engineer with a detail optimum hydraulic fracture design unique to that well, along with the expected post-frac deliverability. Please note that there are no simulated data throughout this study and all data used for development and verification of all methods are done using actual field data.
Analytical Gas Pipeline Design Method Using The GERG Equation of State
Authors: Yildiz Turhan 
Published: December 2007

Abstract
This study presents a new analytical method to design gas pipelines. The new method is based on a real gas equation of state developed by The European Gas Research Group (GERG). This equation of state is very accurate in the pressure and temperature ranges that gas pipelines are operated at. The form of the GERG equation of state is such that an analytical solution to compressible gas flow in an arbitrarily inclined flow string can be obtained.
The new analytical method considers the effect of kinetic energy, variable temperature distribution along the flow string, changes in flow string inclination, and variable flow string size, all of which are not considered in available methods in the literature. This method can be applied to both gas pipelines and wells. The new method is verified by comparing model-calculated and field-measured pressure drops in gas pipelines and gas wells. Twenty-seven data set for pipelines are used in the comparison. The average difference between calculated and measured pressure losses is 3 psi for pipelines.
The methodology used to develop the new method can also be used to solve other gas flow problems.
Statistical Analysis of Well Productivity in Heterogeneous Reservoirs
Authors: Lee K. S. , Miller M. A. , Sepehrnoori K. 
Published: December 2007

Abstract
The effect of reservoir heterogeneity on the productivity of wells in closed depletion reservoirs is investigated. A direct pseudosteady-state equation solution, derived using the divergence theorem, is used to conduct an extensive stochastic simulation study at greatly increased computational efficiency. Dozens of permeability fields corresponding to various Dykstra-Parsons coefficients and correlation lengths are generated using geostatistical simulation techniques. The pseudosteady-state equation is solved by a finite-element method in 2D heterogeneous reservoirs. Pressure drawdown is calculated from the solution. Results are analyzed statistically to examine the effects of geostatistical parameters of reservoir heterogeneity on well productivity during pseudosteady-state.
Analysis of the results show that the properties of the pressure drawdown frequency distribution function are sensitive to structure (well-block permeability) and intensity (Dykstra-Parsons coefficient), but weakly to connectivity (congelation length). Bivariate analysis indicates that the logarithm of pressure drawdown is linearly correlated with the logarithm of the well-block permeability, and that spatial connectivity of permeabilities affects the correlation. Comparison with the behavior of equivalent homogeneous systems provides quantification of an additional pressure loss due to reservoir heterogeneity as a function of Dykstra-Parsons coefficient and correlation length.
Evaluating Formation Damage Risks in a Glauconitic Sandstone Reservoir: A Case History from the Offshore North West Shelf of Australia
Authors: Hatcher G. B. , Chen H. , Rahman S. S. , Hogg P. F. 
Published: December 2007

Abstract
When exploiting hydrocarbon reserves in lithologically and petrophysically complex glauconitic sandstones, potentially damaging fluid/rock and fluid/fluid interactions must be thoroughly investigated. This paper reports on the first phase of a comprehensive, multi-disciplinary study of such interactions conducted on samples from the Saladin field, located on the offshore North West Shelf of Australia. Core floods indicate that the formation is not susceptible to significant damage during the flow of simple brines. However, chemical analysis of core flood effluents after periods of stasis indicate continuing interactions between introduced fluids and fluids resident in the large volume of microporosity. Awareness of such delayed interactions will be important in restored state core analysis and when evaluating the damage potential of more complex fluid systems. The reservoir was found to suffer extreme damage on exposure to freshwater. The sum of evidence suggests that swelling of glauconitic smectite is the underlying cause of the damage, with pore throat plugging by mobilised glauconitic smectite and non-expandable glauconitic clays the probable damage mechanism. Saturation with calcium chloride solutions prevented water shock damage.
Horizontal Well Application: Reservoir Management
Authors: Joshi S. D. , Ding W. 
Published: December 2007

AbstractA successful horizontal well project requires well-defined management objectives. These objectives may include increase of production rate, acceleration of reserves, addition of low cost reserves, improvement of economic benefit, etc. These objectives can be achieved by 1) reducing undesirable fluid production and thereby, reducing surface facility cost, 2) producing "lost" reserves in thin oil rim, 3) reducing the number of injection and production wells required for development of a new field, redevelopment of a mature field or infill drilling program, and 4) bringing on-stream currently unused wells by sidetracking.The purpose of this paper is to review the applications of horizontal wells in reservoir management, discuss its advantages and summarize the reservoir parameters that are critical for a commercially successful project
A New Method to Predict Performance of Fractured Horizontal Wells
Authors: Li Hujun , Jia Zhengqi , Wei Zhaosheng 
Published: December 2007

Abstract
When an oil field with low permeability oil reservoirs is developed with horizontal wells, hydraulic fracturing is usually necessary to achieve an economic oil production rate. It is necessary to find a method for predicting performance of fractured horizontal wells. A practical method to predict performance of a horizontal well which is hydraulically fractured and partially perforated has been proposed in this paper. Using the mathematical model presented in this paper, factors affecting performance of a hydraulically fractured horizontal well have been analyzed. Two oilfield cases from the Daqing Oilfield are analyzed using the method and presented in this paper. Calculations and analyses show that the results which are calculated using this method are consistent with the actual results from the oilfield.
Stimulation of Horizontal Wells Using the Dynamic Gas Pulse Loading Technique
Authors: Loman G. , Phillips D. T. , Cicon H. N. 
Published: December 2007

Abstract
This paper describes the application of Dynamic Gas Pulse Loading (DGPL)1,2 in horizontal wells with open hole, predrilled loose liner, and slotted liner completions. Peak pressures generated by DGPL, which were recorded at intervals along the horizontal trajectory within the selected treatment segment, clearly show local variations in the breakdown pressure of the homogenous formation.
Laboratory Evaluation of Drilling Mud Systems for Formation Damage Prevention in Horizontal Wells
Authors: Shaw J. C. , Chee T. 
Published: December 2007

Abstract
Drilling-induced formation damage has played a significant role in the failure of some horizontal wells. The objective of this laboratory study is to provide insights into this complex subject by investigating the main formation damage mechanism(s) and systematically quantify the damage effect caused by the newly formulated drilling mud systems, which are designed to minimize formation damage.
Eleven commercial drilling mud systems were tested in this study and they produced a very wide range of permeability reduction on Berea sandstone cores with similar properties. Bentonite and cellulose based bridging agents appear to cause higher degrees of damage than ground calcium carbonate. High acid solubility of these muds is conducive to much improved permeability after acid stimulation.
Results of additional dynamic mud leak-off experiments show that the most important parameters which affect regained permeability are: 1) mud composition, 2) core permeability, 3) overbalance pressure, 4) filter cake rigidity, 5) pressure drawdown during backflow, and 6) mud particle versus rock pore-throat size distribution. The depth of mud solid invasion is limited to the first few centimetres of the injection end but the filtrate usually invades the whole core. Furthermore, repeated removal of the existing mud cake can cause much deeper invasion and more severe damage.
Kinetics of the Secondary Reaction of HF on Alumino-Silicates
Authors: Gdanski Rick 
Published: December 2007

Abstract
The standard description of HF acidizing chemistry clearly demonstrates a primary and secondary reaction of HF with alumino-silicates.1 Field experience has taught us that possible precipitation during the secondary reaction can adversely affect treatment success,2 especially in formations with high K-feld-spar content or temperatures above 300°F. Recent work has also reported the existence of a third, or tertiary reaction, of HF with alumino-silicates.3
This paper reports the determination of the rate law for the secondary reaction and the kinetics for that reaction on kaolinite and feldspar over a broad temperature range. In addition, the kinetics of fluosilicate precipitation during the secondary reaction were studied and found to be fast but not instantaneous. These findings were made possible by recently applied experimental techniques including 19F NMR spectroscopy, 3fractional pore volume flow experiments,4 and an accurate knowledge of the HF stoichiometry.5 Laboratory findings have been verified based on detailed analysis of flowback samples from field treatments.6
The reaction rate for the secondary reaction is much slower on feldspars than on clays. At temperatures below 125°F, the secondary reaction rate is very slow, which makes spent HF susceptible to fluosilicate precipitation if the HF is mixed with brines as it often is for disposal or injection well treatments. The difference in the kinetics between clays and feldspar allows one to design treatments at lower temperatures based on just the clay fraction. At temperatures above 150°F, the average mineralogy, clay mineralogy, and feldspar mineralogy should each be evaluated separately for potential fluosilicate precipitation. The fluid of choice is the one that passes all three conditions.
The rate law indicates that the speed of the reaction is independent of HCl concentration and would proceed to completion even in the absence of HCl. Chemically, one can accomplish this effect by using water as a proton source and by adjusting the stoichiometry based on a previously reported equilibrium.5 The kinetics for fluosilicate precipitation were fast but not instantaneous. At very high temperatures, the secondary reaction is fast enough that fluosilicate precipitations can largely be avoided. Unfortunately, the silica gel precipitation then occurs so close to the wellbore that damage to permeability will likely occur. The equations recently developed for the HF acidizing process have been incorporated into a fully kinetic geochemical radial flow simulator. Calculations performed with this simulator have confirmed that a good knowledge of the formation mineralogy and acidizing kinetics is necessary for proper optimization of HF acidizing treatments.
Enhanced Foams for Efficient Gas Influx Control
Authors: Dalland Mariann , Hanssen Jan Erik 
Published: December 2007

Abstract
The paper presents new experimental results from laboratory studies on the use of gas-blocking foams for controlling gas influx into production wells. Foam performance is measured using the well-qualified gas-blockage test procedure at the conditions of four reservoirs where pilot testing of foams is currently planned or on-going. New foam formulations are described where polymer is incorporated into the foaming-agent formulation. For one reservoir, cross-linking chemicals have also been included, allowing comparison of conventional foams stabilised only by surfactant, polymer-fortified foams, and gelled foams.
The results show that strongly improved gas-blockage performance may be obtained by addition of polymer to the foaming-agent solution. In the most favorable cases, foams of essentially no gas-blocking ability can be transformed to very efficient gas-blocking agents by adding polymer. However, in some (repeated) experiments, polymer addition did not result in a better gas-blocking foam, and concentration effects are observed so that adding too much polymer can give sharply reduced foam efficiency. Gel foams also are not necessarily superior to polymer foams as gas-blocking agents.
It is concluded that polymer-enhanced foams are of great potential value for gas influx control, but that more knowledge of surfactant/polymer interaction in the thin film network that constitutes the foam is required in order to predict the effects of adding polymer to gas-blocking foam formulations.
A Novel Surfactant for Oilfield Applications
Authors: Borchardt John K. 
Published: December 2007

Abstract
Previously, esters of alcohol ethoxycaiboxylates have been developed for use in surfactant flooding, micellar polymer flooding, and foam flooding enhanced oil recovery. With the increased availability and improved economics of alcohol ethoxycarboxylate surfactants due to commercialization of a more cost-effective synthesis, additional applications of AEC's are being developed. Among these are various oilfield applications.
Foaming data at neutral and basic pH suggest that AEC surfactants could have applications as foaming agents for hydraulic fracturing, acidizing, drilling, and completion fluids. AEC surfactants foam more readily in basic media than in acidic media. However, AEC surfactants form stable foams in acidic media, foams even more stable than basic media foams. So while AEC surfactants could be useful foaming agents in hydraulic fracturing, normally carried out in basic media, they could also be useful as foaming agents in acidizing and acid fracturing.
Taken together, dynamic surface tension values, contact angle measurements, and interfacial tension values suggest that AEC surfactants could have applications in acidizing whether or not they are used as foaming agents
A Novel Technique to Characterize Oxidative Encapsulated Breakers Used in Fracturing Fluids
Authors: Rao Ajoy , Elliff Chris , Bilden Dean 
Published: December 2007

Abstract
Oxidative breakers are used extensively to degrade the polymers used in oil and gas well hydraulic fracturing fluids. These oxidative breakers react extremely fast in most downhole environments and can degrade fracturing fluids at rates that are undesirable. To increase the stability of fracturing fluids, these oxidative breakers have been encapsulated, with various techniques, to delay the release of the breaker into the aqueous environment and cause a delayed break or degradation of the fracturing fluid. Historically, evaluation of the release rates has been accomplished by measuring the degree and rate of viscosity degradation in laboratory rheometers. These tests are very time consuming and somewhat subjective.
A new methodology is provided to characterize encapsulated oxidative breakers (EOB) using Thermogravimetric Analysis (TGA). The new approach is based on weight loss using constant or dynamic heating rates. The novel technique constitutes a powerful tool to characterize the product complementary to conventional laboratory tests which are time consuming.
This technique can be used to streamline the developmental process used in manufacturing these encapsulated oxidative breakers. It is also extremely beneficial for QA/QC of this type of product. The quality of these products can be determined in much less time and with better precision than conventional techniques. Relevant literature references have been identified and are included in the paper.
Reaction Rate and Fluid Loss: The Keys to Wormhole Initiation and Propagation in Carbonate Acidizing
Authors: Huang T. , Hill A. D. , Schechter R. S. 
Published: December 2007

Abstract
The efficiency of the matrix acidizing process in carbonates depends strongly on the wormholing phenomenon—if wormholes are formed, the effects of near wellbore damage can be overcome with relatively small volumes of acid. Numerous previous studies have shown that wormhole patterns can be placed in these general categories: (1) compact dissolution in which most of the acid is spent near the rock face; (2) the wormholing pattern; and (3) uniform dissolution in which many pores are enlarged, as typically occurs in sandstone acidizing. We have developed a theory of the wormholing process which predicts when the wormholing pattern is most efficiently created as a function of the acid flux and other treatment variables.
By testing this theory with several independent sets of laboratory data, we can now demonstrate the important roles that surface reaction rate and fluid loss play in the wormholing process. This theory accurately predicts the optimal flux (that which leads to dominant wormholes with a minimum of branching and hence a minimum acid volume) for experiments with HCl in limestone and dolomite at several temperatures and with acetic acid in limestone. Surface reaction rale differs by several orders of magnitude in these experiments and is the only process variable that differs greatly among them. Paradoxically, though wormholes are formed because the overall reaction rate is controlled by mass transfer in the wormholes, diffusion rates play only a minor role in the wormholing process.
Fluid loss through the walls of the wormholes ultimately limits the distance to which wormholes can propagate. Because of this effect, laboratory linear core floods will give optimistic predictions of wormhole penetration distances. We developed a cylindrical flow model to represent the flow field around a wormhole propagating from a wellbore which illustrates how to translate laboratory results to field conditions.
We have used these theories to predict optimal acid formulations and injection rates for field conditions. In general, the lower the reaction rate (such as at low temperatures in dolomites or with weak acids in limestones), the lower the injection rate required, making it easier to propagate dominant wormholes under matrix treating conditions in the field.