bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Novel Low-Temperature, Forced Precipitation Phosphonate Squeeze for Water Sensitive, Non-Carbonate Bearing Formations
Authors: Lynn Jack D. , Nasr-El-Din H. A. 
Published: December 2007

Abstract
A novel carbonate/sulfate scale squeeze treatment specifically targeted to low temperature, low pressure clastic formations was developed, and successfully applied to Saudi Arabian formation, designated H-A.
A number of different remediation techniques were reviewed. They ranged from adsorption and precipitation squeezes to encapsulated treatments. Due to the low temperature of the field (&lt;160 °F), and the low pressure of the formations, a non-traditional scale squeeze was required. Adsorption squeezes are well documented, but have short return lives and would have required retreating every-6–8 months. Encapsulated squeezes delivered a very short life.
Naturally induced precipitation squeezes using organophosphonates (ATMP, ADMP) have been used to treat Saudi Arabian carbonates since 1986. Unfortunately, the H-A formation is a siliceous clastic reservoir (quartz &gt; 98 wt. %) with little natural carbonates, and a natural precipitation squeeze would not be possible. It was decided that a forced precipitation would be used. A forced precipitation must contain the organophosphonate, a source of di-valent cations (usually, but not confined to Ca++), and a method of either raising or lowering the pH to change the solubility of the Ca-phosphonate derivative, and force precipitation. The change in pH required is a function of the phosphonate used, and a large number of options have been developed. Most however, require temperatures above 180°F to be successful.
This innovative method employs a multiple staged treatment using a diesel emulsified inhibitor/di-valent cation stage injected with pH control stages. The two aqueous stages cannot come into contact with each other until the emulsion breaks. The breaking time of the emulsion is controlled by the adsorption of the emulsifier onto the formation rock, and is not temperature dependent, as are urea-based systems. The formulation contains a clay stabilization chemical.
The treatment has been successfully applied to 25 wells, the first, H-53 nearly 36 months ago. This well has current returns nearly 0.1 mg /L organophosphonate, and has a projected treatment life of 2-3 years.
Estimating a Relationship between Pore Pressure and Natural Fracture Permeability for Highly Stressed Reservoirs
Authors: Kasap E. , Bush E. S. 
Published: December 2007

AbstractA better understanding of production from fractured reservoirs that exhibit permeability reduction with lower bottomhole pressure (BHP) is required. A pore pressure versus permeability relationship, which is essential for optimizing field development scenarios, is also required.In this study, several sets of well-test data from a naturally fractured reservoir were studied to quantify permeability reduction from pore-pressure drop with lower BHP. The tests indicated lower production rates with lower BHP. Various analyzing techniques were employed to determine the true reservoir characteristics. Regression analyses for naturally fractured and hydraulically fractured models were conducted, and reservoir rock properties were estimated.The solution of the partial differential equation (PDE) formulating transient pressure solution for a 1D, infinite-acting fracture was superimposed for multiple rates to estimate initial fracture permeability. The deviations from conventional analysis results were investigated and used for generating a pore pressure versus effective fracture permeability relationship. The relationship developed was used in a numerical model in pressure-dependent permeability mode to simulate well test behavior. Transient pressure and rate data from the numerical model with pore-pressure-dependent permeability were compared with data from the field to verify the developed analysis technique. The numerical model satisfactorily predicted the field-test data.
Improved Water Injector Performance in a Gulf of Mexico Deepwater Development Using an Openhole Frac Pack Completion and Downhole Filter System: Case History
Authors: Shumbera David A. , Ritter David W. , Ellis Richard C. , Jannise Richard C. , Lochte Glen 
Published: December 2007

Abstract
A Gulf of Mexico deepwater subsea development project required seawater injection for pressure maintenance of the producing reservoir. Typical water injector performance in the Gulf of Mexico has been characterized by rapidly declining injectivities that could be partially restored by frequent acid treatments. This type of performance was unacceptable for this field development plan, which required one subsea water injector capable of injecting up to 25,000 BWPD continuously for up to five years.
Two changes to typical Gulf of Mexico water injector completion design were incorporated: 1) an openhole frac pack completion, and 2) a unique downhole filter system. These changes resulted in improved water injector performance compared with that typically experienced in the Gulf of Mexico. Initial injectivity was excellent and remained so over the entire injection period. No acid stimulations were required to either initiate or maintain injection.
This paper presents the design and installation aspects as well as the actual performance results for this water injector.
Well Perforation Using High-Power Lasers
Authors: Batarseh S. , Gahan B. C. , Graves R. M. , Parker R. A. 
Published: December 2007

Abstract
Conventional wellbore perforation techniques are designed to establish flow from the hydrocarbon-bearing reservoir through the cemented casing into the wellbore. The explosive force of shaped charges is focused and intensified into a small-diameter jet that penetrates the casing and cement into the reservoir rock. This process reduces reservoir rock porosity and permeability as metal and carbon debris are forced into the perforation tunnel, while very fine grain particles plug or reduce the pore throat size. As a result, it is necessary to perform time-consuming and costly post-perforation operations to minimize flow restrictions into the wellbore. Developing alternative perforation methods that reduce or eliminate formation damage could significantly boost production rates, cumulative production and overall economic returns.
The research team led by Gas Technology Institute (GTI) has demonstrated, through the application of high-energy lasers to rock samples, that damage to permeability and porosity of the adjacent zones cannot only be reduced, but that near-hole permeability in a reservoir sandstone can be increased up to 171%. By applying this technique downhole, perforations and other directionally controlled completion and stimulation methods could be employed without damaging the reservoir.
This paper presents the experimental methods and results of exposing sandstone, limestone, and shale rock samples to high-power laser beams. A grid pattern was applied to the rock samples from which acoustic velocity and permeability measurements in and near the perforated tunnel where taken. In addition, rock mineralogy and rock properties were analyzed before and after the test.
Pilot Tests in the Illinois and Western Interior Basins to Determine Commercial Productivity from Pennsylvanian Aged Coals
Authors: Green T. W. , Wolfe S. R. , Tedesco S. A. 
Published: December 2007

Abstract
Coalbed methane production is viewed as an attractive source for the growing US natural gas demand. Undeveloped resources of coalbed methane in the United States have been estimated at 60 Tcf1. A majority of the coal in the USA is accessible at shallow depths, making well drilling and completion inexpensive. Finding costs are also low since methane occurs in coal deposits, and the location of the nation's coal resources are well known.
Millions of acres of potential coalbed methane gas production identified in the Illinois and Western Interior Basins are currently being evaluated with multi-well pilot projects. The coals of interest vary from 300 to 2,300 feet in depth, have moderate to high ash content, low moisture content, and are High Volatile C to Medium Volatile in rank. The coal seams range in thickness from one to five feet and have gas contents of 1 to 325 scf/ton, with measured permeabilities on the order of .1 to 100 mD.
The primary purpose of a pilot test program is to determine gas deliverability potential and initial water production. Well spacing, time to dewater, and ultimately time to reach maximum gas production are crucial to overall project development economics. Secondarily, the pilot programs are designed to confirm gas contents and permeability estimates obtained from initial data wells.
The pilot wells are placed in such a way to maximize well-to-well interference during a reasonably short production test period (4 to 6 months). This paper presents the initial results of several ongoing pilot projects in both basins. Parameters such as full-field well spacing, water disposal requirements and facilities, artificial lift criteria, gas deliverability, and ultimate recoveries can be estimated and asset development economics determined.
Using Visualization Tools to Gain Insight Into Your Data
Authors: Plaisant C. , Chintalapani G. , Lukehart C. , Schiro D. , Ryan J. 
Published: December 2007

Abstract
When the term ‘visualization’ is used in the oil and gas industry, it is usually referring to the viewing of complex geologic structures in three-dimensional space. This paper illustrates insights gained by applying interactive visual environments to petroleum industry data that has traditionally been presented in spreadsheets, line graphs, and bar charts. Two information visualization tools, Treemap and SpaceTree, will be shown applied to a variety of oilfield related data.
Essential Components of an Integrated Data Mining Tool for the Oil & Gas Industry, With an Example Application in the DJ Basin
Authors: Mohaghegh Shahab D. 
Published: December 2007

AbstractData Mining seems to be the new buzz word. During the past several years many industries other than ours, have realized the potential benefits of Data Mining and have established sophisticated operations in order to implement this exciting technology in their respective organizations. Data Mining is not new. It has been around for many years. What is new about its current implementation is the incorporation of machine learning techniques. Oil & gas industry has become familiar with machine learning techniques since early 90s. Neural networks, genetic optimization and fuzzy logic have been used in numerous applications from well log interpretations to hydraulic fracturing optimization. Therefore, the new interest in Data Mining in our industry is not surprising. Our industry is at its peak state for benefiting from what Data mining has to offer, thanks to abundance of digital data.A word of caution is in order, which has been the main motivation behind writing this paper. As with many other new tools and technologies, the term "Data Mining" can be, and is currently being, misused in several occasions. In this paper we attempt to answer questions such as, what is Data Mining. How can it be accomplished? What are the essential components of an integrated Data Mining process? What would be the benefits of such a process?In addition to answering questions such as those mentioned above, this paper will provide a road map (a set of guidelines) for a successful Data Mining project. Finally the paper is concluded by applying the presented guidelines to a hydraulic fracturing data set in the DJ basin for a Data Mining study.
Development of the Industry's First Slimhole Point-the-Bit Rotary Steerable System
Authors: Stroud D , Russell M , Peach S 
Published: December 2007

Abstract
This paper describes the results of laboratory drilling tests, bottom hole assembly (BHA) software modeling, and field-testing of the industry's first slimhole rotary steerable system (RSS) using point-the-bit technology. The first system field-tested was 4-3/4 in. diameter for use in slimhole drilling with 6-in. bits. Test results show the RSS is controllable and predictable in behavior, and produces superior borehole quality.
Employing Neural Networks to Integrate Seismic and Other Data for the Prediction of Fracture Intensity
Authors: Boerner Sean , Gray Dave , Todorovic-Marinic Dragana , Zellou Abdel M. , Schnerk George 
Published: December 2007

AbstractA non-subjective technique is presented to combine seismic based fracture detection from shear wave anisotropy with traditional well and structure data to produce a new generation of fracture intensity maps and volumes. Neural networks are easy to use and extremely useful for nonlinear regression where the functional form of the nonlinear equation between the independent and dependent variables are not known. We use a neural network for nonlinearly regressing a number of independent variables to predict fracture intensity within a reservoir. Several of the independent variables are derived from an amplitude versus angle and azimuth (AVAZ) process applied to pre-stack, P-wave seismic data. By examining the changes in reflectivity amplitude with respect to azimuth and incident angle on pre-stack seismic gathers, we can detect the presence of open, near-vertical fractures and their orientation. Seismic data has good lateral coverage, but poor vertical resolution versus well data, which has good vertical resolution, but is sparse laterally. The seismic attributes extracted from the AVAZ process are combined with 3D model attributes, such as porosity and lithology and structural attributes, such as the first and second derivatives of the structural surfaces to predict fracture intensity. Because fracture intensity information is sparse and difficult to obtain, we use expected ultimate recovery (EUR) as a substitute for fracture intensity. The four-month cumulative production provides a good estimate for EUR and is used as the fracture indicator in this study. The attributes are ranked according to their correlation with fracture intensity, and a subset of variables is selected as input into the neural network for the prediction of the fracture indicator. Multiple neural networks are trained on the data providing multiple solutions. These solutions, in the form of 2D maps or 3D volumes, are analyzed statistically to predict the fracture indicator and to high grade prospective drilling locations. In addition, the fracture indicator maps and volumes can be input into discrete fracture modeling tools for further analysis.
Converted Shear-Wave Anisotropy for Fractured-Reservoir Management
Authors: Gaiser James E. , Van Dok Richard R. 
Published: December 2007

Abstract
Fractured reservoirs have been encountered worldwide and in general they are profitably produced, however it is safe to say that none of them have been depleted efficiently. As the petroleum industry focuses less on exploration and in a market of rising costs it is becoming more important to recognize the presence of fractures early in the life of a field for optimal reservoir management. Fractures can significantly complicate the behavior of reservoir porosity and permeability, often resulting in numerous dry wells and higher production costs. A key strategy for fractured reservoir management is a quantitative description of the geology, geophysics and petrophysical attributes obtained from seismic methods during production and development.
3D multicomponent seismic surveys, where compressional waves excite shear-wave reflections (PS-waves), can provide complimentary surface-seismic information to help identify fracture properties early in the production history of a reservoir. Based on measurements of shear-wave azimuthal anisotropy, PS-waves can identify fracture density and strike, and because of their asymmetry they are also sensitive to fracture dip. Examples from both land and marine 3D PS-wave surveys demonstrate the potential of using these attributes to characterize subsurface stress variations that are important for open fracture development. The intermediate-scale seismic anisotropy properties obtained from PS-waves will be critical for solving specific production problems associated with different fractured reservoir types, and could improve reservoir modeling: production-history and pressure-test matching, and fluid-flow simulation. From an economic point of view, if PS-wave surveys acquired over the life of a field can prevent a small fraction of unproductive wells, they are worth the expense.
G·TE Correction for Processing Multigradient, Multiple-TE NMR Log Data
Authors: Chen S. , Hursan G. , Beard D. , Georgi D. 
Published: December 2007

Abstract
We have developed a data processing method that allows a valid integration, in the time domain, of echo trains acquired in different field gradients, G, and different interecho times, TE. The combined echo train can be used to obtain clay bound water (CBW), bulk volume irreducible (BVI), and total porosity information with improved vertical resolution. The same data, in the uncombined form, are used for fluid property estimation. Thus, the data are used more economically.
As an added benefit, the combined echo train allows the use of a single T2cutoff, consistent with the laboratory core-NMR derived T2cutoff. Although using a zero-gradient, laboratory core-NMR derived T2cutoff to "calibrate" NMR logs acquired in a gradient field is a common practice, the discrepancy cannot be ignored for NMR logs acquired with a large G·TE product. With the new method, this discrepancy is minimized. Field examples are provided to show the benefit with the new method.
Liquid Inventory Management Issues in a Dual Large Diameter Long-Distance Subsea Wet Gas Pipeline System
Authors: Harun A. F. , Choate T. G. A. , Cochran S. W. 
Published: December 2007

Abstract
Liquid inventory management is an important subject in a subsea wet gas pipeline system mainly due to long distance (∼ 56 miles), large diameter (20+ inches), and three-phase fluid (gas, water/MEG, and condensate) effects. Using multiphase transient simulation, this paper addresses some issues related to liquid inventory management as a result of transient operations, such as restart and rampup (production increase). This study reveals that gas velocity and a knowledge of liquid holdup during steady state and transient operations at any time and place are key parameters in developing a field operation strategy. Managing pipeline liquid holdup at all times will ensure that liquid surge arriving onshore will be within the slug catcher liquid handling capacity, while the transient operations can be reasonably managed.
Natural Polymer-Based Compositions Designed for Use in Conformance Gel Systems
Authors: Reddy B. R. , Eoff Larry , Dalrymple E. Dwyann , Brown David 
Published: December 2007

Abstract
This paper describes a crosslinking material derived from natural sources. This material can be used with a variety of polymers over a broad temperature range to produce gels for conformance applications.
Delayed cross-linked polymer systems have been used for many years in conformance applications. For the past decade, the most widely used system has been based on chromium (3+) cross-linked polyacrylamide. Organic crosslinkers, such as phenol/formaldehyde and polyethyleneimine have also been used with a variety of polymers. However, these systems are being scrutinized by regulatory agencies and have now been scheduled for phase-out in some countries. Because of these issues, a single, environmentally friendly crosslinker that could be used with a variety of polymers over a broad temperature range was selected for study.
This paper details the laboratory development of an environmentally friendly, natural polyamine crosslinker system. This crosslinker can be used with a variety of polymers, such as polyacrylamide, AMPS/acrylamide, or alkylacrylate polymers. Gels ranging from stiff and "ringing" type to "lipping" gels have been obtained. Recent efforts have targeted designing chitosan-based gel compositions. These efforts included not only using chitosan as the base polymer in combination with a synthetic polymeric cross-linker, but also developing gels derived completely from natural polymers. Results from these studies will be presented.
The Application of a New and Unique Relative Permeability Modifier in Selectively Reducing Water Production
Authors: Nelson Scott G. , Kalfayan Leonard J. , Rittenberry William M. 
Published: December 2007

AbstractThe need to reduce water production through the use of low-risk chemical treatments is becoming an everyday reality in the oil and gas industry today. Rising exploration and development costs, along with ever-increasing water management costs, require that cost-effective methods of reducing unwanted water production be developed and implemented. To address this issue, a new relative permeability modifier system has been developed. The RPM is uniquely formulated to effectively treat sandstone or carbonate formation matrices. The relative permeability modifier selectively reduces the permeability to water, without detrimentally affecting oil or gas permeability.This new water management treatment approach provides simplicity in job application, is viable over a wide range of reservoir types, lithologies, and permeabilities, and can be employed in a broad range of job types, including matrix injection and hydraulic fracturing treatments. This paper summarizes a successful fracturing treatment application employing the new relative permeability modifier.
Mixed-Wet Drainage and Imbibition Relative Permeabilities From the Diffuse Interface Theory
Authors: Papatzacos Paul , Skjæveland Svein M. 
Published: December 2007

Abstract
The Diffuse-Interface model for two-phase flow in porous media is applied to the invesigation of relative permeabilities in unsteady-state flows. It is shown that relative permeabilities have a transient regime where they can be significantly larger than 1. It is also shown that, when normalized by their endpoint values, relative permeabilities can be calculated from formulas involving thermodynamical and capillary pressure functions. The end-point relative permeabilities are linearly related to the fluid velocity, but the coefficients seem to be flow dependent.