bluuebunny/crossref_metadata_2025_split huggingface dataset:
Coiled Pipeline Technology: A Gulf of Suez Case History
Authors: Hoffman John G. , Little Chester T. , El Lathy W.F. , Glanville Shawn M. 
Published: December 2007

Abstract
Coiled "tubing" is a rapidly growing pipeline technology. Until recently coiled tubing was used primarily by service companies for coiled tubing workovers. As the technology expanded the industry began using coiled tubing for other applications such as drilling, coring, logging, well clean out operations and artificial lift. As the tubing mills began producing larger sizes, it became possible to consider using coiled tubing as pipelines. The application of coiled tubing as a pipeline began in the Gulf of Mexico. The early results supported the application as being a low cost, time saving, economic alternative to conventional welded pipe for flowlines. Coiled pipe applications have been used in 4 to 100 feet of water in the Gulf of Mexico area and the installation techniques have varied significantly.
In 1994, the Gulf of Suez Petroleum Company (GUPCO), a joint venture company between Amoco Production Co. and the Egyptian General Petroleum Co., embarked on the first international application of the 3.5 inch coiled pipe using a dynamic lay procedure. The cost savings from the first two jobs were estimated to be in excess of 70% when compared to the traditional lay vessel charges. Engineering design and field experience was shared at the Middle East Oil Show in Bahrain during 1995 (SPE 29786). Subsequently GUPCO has taken a leading role in the application of coiled pipe technology with the 1996 installations using the first production of 4.5 inch coiled pipe, one of which is a record setting 65,000 ft. high pressure water supply line. Cost savings of this larger diameter coiled pipe are still yielding 55% cost savings over the conventional barge lay techniques.

Introduction
The Gulf of Suez Petroleum Company has been using coiled pipe technology since 1994. Since that time the technology has grown with larger diameters being offered. These larger pipes have enabled the company to examine additional opportunities in the Gulf.
To date the company has installed 45,000 feet of 3.5 inch and 72.000 feet of 4.5 inch coiled pipe. In 1994 GUPCO embarked on its first two coiled pipeline projects using the 3.5 inch material. By 1995 a new larger diameter coiled pipe was being offered. The 4.5 inch material offered additional application in the Gulf and GUPCO pursued three additional projects. In January of 19% the company installed the world's first and longest 4.5 inch coiled pipeline.
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Multi-Zone Gravel Pack Techniques: Case Studies From the South China Sea Xijiang Development
Authors: Bennett John Scott , Sanders T. K. , Grigsby Tommy , Fucun Yuan , Liang Zhou , Yaxin Bai 
Published: December 2007

Abstract
Xijiang is the first Pearl River Mouth Basin Development in the South China Sea employing gravel packs. These fields, comprised of multiple-layered reservoirs, are characterized by unconsolidated, friable, and high-permeability sandstones that must be commingled for economical production. This paper will discuss the specific reservoir characteristics and parameters that affected completion scenarios in the development of these fields and how the needs for sand control, zonal isolation, high-rate production, and reduced completion duration have been addressed.
Particularly significant in development of the projects has been the design of two completions systems specific to the Xijiang reservoir conditions that accomplish gravel packing and mechanical isolation of individual sands while minimizing the number of trips made into the wellbore. The single-trip dual-zone (STDZ) system is used when two zones must be gravel packed, and the multi-zone system has been employed when there are as many as 8 zones in one wellbore that must be gravel packed.
Handling Fluid Properties in Reservoir Simulation Studies
Authors: Ridings Robert Lewis 
Published: December 2007

Abstract
The reservoir engineer today is able to evaluate and predict reservoir performance much more precisely through the application of multi-dimensional models to mathematically simulate reservoir behavior. The additional precision requires more attention to the handling of reservoir fluid properties than the traditional material balance studies.
This paper discusses the problems involved and reviews several techniques which have been employed to achieve improved accuracy in the application of fluid properties in reservoir studies. The techniques presented attempt to consider variations in properties presented attempt to consider variations in properties spatially within the reservoir as well as variations with pressure and composition.

Reservoir Bubble Point
Rather than computing one point in time at which the overage reservoir pressure declines to an average reservoir bubble point pressure, model studies reflect the more realistic situation in which local areas become saturated while other areas may remain undersaturated — at least for a time. By their nature, model studies reflect this type of situation and the handling of fluid properties in the model must be appropriate to the situation.
The normal concept of average reservoir saturation pressure disappears in model studies. Figure 1 shows pressure disappears in model studies. Figure 1 shows how a reservoir may be sub-divided into blocks for a two-dimensional study. The pressure and saturation and the resulting fluid flow are calculated at each block over short time steps. As an area of the reservoir becomes saturated and solution gas is released from the oil, that evolved gas may migrate away from the area where it is released. If the pressure in that area increases, even temporarily, the oil must then be treated as undersaturated. Also, the evolved gas may tend to re-saturate the oil in another area of the reservoir.
The type of problem encountered in this type of situation may be illustrated by referring to Figure 2 which shows a typical formation volume factor curve. If the pressure declines in one part of the reservoir to a point well below the original bubble point, the correct formation volume factor would be determined on the "saturated oil" portion of the curve.
A Simplified Well Control Model for Horizontal Slimholes and Coiled Tubing Drilling
Authors: Choe Jonggeun , Juvkam-Wold Hans C. 
Published: December 2007

Abstract
This paper presents the development of a simplified two-phase well control computer model to simulate gas kicks. The paper identifies key factors in the prediction of kick behavior based on a comparison between a fully implicit dynamic two-phase model and a single-phase model. The model also analyzes kick responses for directional and horizontal slimholes and wells drilled with coiled tubing. Directional and horizontal wells consider multiple build-up rates. This paper highlights the effect of homogeneous or locally high pressured horizontal wells and the effect of reeled coiled tubing. This paper also examines theoretical kill sheets for several well trajectories from vertical to horizontal and for coiled tubing drilling. Theoretical kill sheets are compared with conventional kill sheets.
The simplified two-phase well control model developed in this study is reliable and stable. It can handle vertical, directional, and horizontal wells with multiple build-up rates and hold sections and does not have any numerical problems such as may occur with a dynamic two-phase well control model. For directional and horizontal wells with high build-up rates, choke pressure changes rapidly without much kick expansion because of vertical height change of the kick mixture as the kick moves through the curve.
A conventional kill sheet is good enough for a conventional large diameter vertical well with uniform well geometry. However, a theoretical kill sheet should be used with some amount of over-pressure for directional, and horizontal wells, especially when those are slimhole wells or are drilled with coiled tubing.
Selection and Qualification of Drill-ln Fluids for Horizontal Wells in Unconsolidated Sands
Authors: Hale Arthur H. , Lau Hon Chung , Bernardi Louis A. , Albrecht Michele S. , Faircloth Robert J. , Morgenthaler Lee N. , Kielty Jim M. 
Published: December 2007

Abstract
Much of the development using horizontal well technology had been centered around drill-in fluids. These fluids tended to be excellent for completion purposes but poor drilling fluids, and although success was recorded throughout the world, many areas that required more robust fluids were not being drilled. Well conditions such as higher temperature (&gt;175°F), depleted sands, intermittent sand shale layers, low fracture gradient pore pressure spread, and high weights for wellbore stability were limiting the application of horizontal well technology. Not only were fluids not available to drill with, but also it was unclear what methods or techniques were needed for wellbore clean-up.
Because of need for drìll-in fluids, an effort was undertaken in concert with the service companies to develop fluids that met both drilling and completion requirements. The effort was systematic in that established criteria had to be met for both drilling and completion. These criteria included requirements on fluid rheology, thermal stability, lubricity, fluid-loss control, filtercake properties, and removal of filtercakes after drilling leading to low/no formation and screen damage. Laboratory tests to measure candidate drill-in fluids against these criteria were established. Both water and oil or synthetic invert fluids were developed.
In this paper a quality procedure is shown for validating fluids on a screening basis followed by specific evaluation of methods to mix, maintain on the rig, and ultimately to complete. Our field experience has shown that this quality control procedure is crucial to the high success rate of Shell's horizontal wells in the Gulf of Mexico. Data are shown which lead to guidelines for drilling and completing wells with varying conditions.
Analysis of the Steam Assisted Gravity Drainage SAGD Process Using Experimental/Numerical Tools
Authors: Nasr T. N. , Golbeck H. , Lorimer S. 
Published: December 2007

Abstract
There has been a keen interest during the last decade in the application of the steam assisted gravity drainage (SAGD) process as a recovery strategy for oil sands and heavy oil reservoirs. The recent success of field pilot demonstrations in Alberta and Saskatchewan has further accentuated the need to understand process mechanisms and determine techniques to accelerate recovery rates for improving economics. This paper provides an in depth analysis of the SAGD process using numerical and experimental tools. Two-dimensional scaled gravity drainage experiments, designed to represent heavy/extra heavy oil reservoirs, were used to calibrate the thermal reservoir simulator STARS. Visual observations of the development of the steam chamber (gravity cell) were made during the experiments and compared to numerical model predictions. The results obtained provided insight into the effect of key parameters such as permeability, pressure difference between the wells, capillary pressures and heat losses on process performance. A detailed study on the effect of permeability on source/sink simulation of the SAGD process demonstrated the importance of the initialization or transient phase of the process. The duration of the initialization phase increased as the permeability decreased, indicating that this phase occupied an increasingly significant portion of the entire drainage process as permeability decreased. The sensitivity of the validated numerical model to a number of key parameters required for numerical simulation of the process are highlighted in the paper. The effort is intended as a precursor to modeling field scale gravity drainage processes. The ultimate application of the work is in thermal heavy oil recovery operations using steam assisted gravity drainage.
Screening of Reservoirs For Exploitation by Application of Steam Assisted Gravity Drainage/Vapex Processes
Authors: Singhal A. K. , Das S. K. , Leggitt S. M. , Kasraie M. , Ito Y. 
Published: December 2007

Abstract
In an environment of low oil prices and low economic returns for heavy oil operations, SAGD and VAPEX processes appear very promising from a technical point of view. The purpose of this paper is to present guidelines for screening heavy oil reservoirs for exploitation by Steam Assisted Gravity Drainage (SAGD) and VAPEX processes.
Viability in the field would be strongly governed by factors such as net pay thickness, oil viscosity, presence of gas cap or bottom water, barriers to vertical flow, containment of the steam or vapour chamber within the target area, lateral and vertical extent of steam/vapour chambers, number of new horizontal/vertical wells to be drilled, solvent recovery, facilities requirements, etc.
Exploitation viability of heavy oil reservoirs is evaluated under different reservoir settings using a combination of reservoir/geological analyses and numerical simulation. This evaluation helps provide guidelines for screening reservoir prospects for the application of SAGD/VAPEX processes. The viability of these processes is sensitive to the reservoir characteristics of the specific target areas.
Control of Wax Deposition: An Experimental Investigation of Crystal Morphology and an Evaluation of Various Chemical Solvents
Authors: Ferworn Kevin A. , Hammami Ahmed , Ellis Herb 
Published: December 2007

Abstract
Four commercial solvents and o-xylene have been tested for their effectiveness in remediating paraffin (wax) depositions from three different dead oils. The dead oils were sampled from the North Sea, Alberta and Gulf of Mexico, respectively. Representative field solvent/oil concentrations of 2000 and 4000 ppm (vol) were prepared for each oil and solvent considered in this work. Two state-of-the-art techniques, namely a cross polar microscopy (CPM) and a rheometrics mechanical spectrometer (RMS 800), were used to study paraffin crystal habits and/or morphologies at 32°F, wax dissolution temperatures (WDT), and pour point temperatures of the three dead oils with and without solvents. It is found that in almost all cases, the 2000 ppm (vol) solvent concentration yielded similar or better remediation results than mixtures with 4000 ppm (vol) solvents. More importantly, it is shown that the remediation of wax deposition depends not only on the solvent concentration but also the type of oil and, in turn, waxes being treated (i.e., case specific). In some cases, the relatively cheap solvents outperform the more expensive o-xylene in dissolving wax deposits. Finally, a laser based solids detection system (SDS) was used to study the effect of o-xylene on the wax appearance temperature (WAT) of a second live fluid from the Gulf of Mexico.
Permeability Modification Using Sulfomethylated Resorcinol-Formaldehyde Gel System
Authors: Zhuang Y. , Pandey S. N. , McCool C. S. , Willhite G. P. 
Published: December 2007

Abstract
A gel system based on the reaction of sulfomethylated resorcinol and formaldehyde has been developed. This gel system, termed SMRF, is tolerant of a wide range of salinities and divalent ion content. It has been tested in laboratory core floods conducted at 41°C(105.8°F) using Berea sandstone cores, Baker dolomite cores and reservoir rock from the Pen Field which produces from the Lansing-Kansas City formation. In these core tests, the gelling system was injected into short cores and allowed to gel in situ. Permeability to brine after in situ gelation was determined for each core as well as permeability after several pore volumes of brine injection. The SMRF gel system reduced the permeabilities of Berea and Baker dolomite cores to values on the order of 8–18 microdarcies. The Lansing-Kansas City reservoir rock was plugged by the gel system.
The new gel system has a viscosity close to water when the reactants are mixed and is easily injected into porous rock. SMRF forms strong and stable gels at temperatures between 25°C and 52°C(126°F) and in the pH range between 5 and 8.0. Gel times are a function of pH, salinity, concentration of the chemical constituents and temperature, and can be controlled by appropriate adjustment of these parameters. Laboratory data describing the characteristics of the SMRF system in beaker tests are presented. Also included are results of extensive core testing.
The SMRF gel system is one of the few gel systems that will form a gel in situ in the presence of the strong buffering that occurs when brine is injected into carbonate rock. The SMRF system has potential for near wellbore treatments of carbonate matrix rock such as found in the Lansing-Kansas City formations of central Kansas as well as the low permeability carbonates found in the San Andres formations in West Texas.
The Unexpected Advantages of a Temporary Fluid-Loss Control Pill
Authors: Hardy Mary 
Published: December 2007

Abstract
This paper describes the chemical theory behind the unexpected features of an environmentally acceptable temporary fluid-loss control pill. This liquid gel concentrate pill meets EPA and OSPARCOM standards for use in on- and offshore operations, and has been used for a variety of applications throughout the world.
Economic reasons and environmental regulations compelled one oil-service company to find a replacement for an existing field product. Initially, research was aimed toward the development of a pill that had the following characteristics.
It blocks fluid flow into and out of the wellbore. It is mixable in brines 8.35 to 19 lb/gal. It can be used effectively at temperatures as high as 257°F/125°C.
Researchers concentrated their efforts on optimizing the synthesis, manufacture, and field-mixing procedures pertaining to a replacement crosslinkable hydroxyethyl cellulose fluid (RXHEC). RXHEC degrades by uncrosslinking and unzipping the backbone, which simplifies the disposal of returns. It is capable of breaking with weak acids, which allows the use of external breakers in acid-sensitive wells. The first field application took place in May 1993. Since then, some evidence has revealed additional features that were not conceived in the initial design.
Dispersion occurs with no "fish-eyes." Crosslinking occurs with most metals and non-toxic metals. The fluid can be pumped fully crosslinked. Reversible shear degradation of crosslinked RXHEC fluids allows good fluid-loss control. Tubulars slip through the RXHEC pill with little difficulty, making a remedial pill unnecessary. The RXHEC pill remains in place during tripping and retrieving operations. It is indefinitely stable to 275°F/135°C.
Laboratory data and field data are presented. Chemical explanations for the unexpected features are discussed in detail.
Permeability Reduction by Treatment with KUSP1 Biopolymer Systems
Authors: McCool C. S. , Green D. W. , Willhite G. P. , Shaw A. K. , Bhattacharya S. , Singh A. 
Published: December 2007

Abstract
KUSP1 is a polysaccharide that is derived from a particular bacterium that was discovered at the University of Kansas. Unique properties of KUSP1 were the incentive to investigate the application of this polymer for use in permeability-modification treatments. KUSP1 dissolves in alkaline waters but forms a gel as the pH of the solution is lowered to values below 10.8. Two methods to reduce the pH of KUSP1 solutions were studied. An ester was utilized to trigger gelation. Monoethylphthalate ester (MEP) reacts with water to produce an acid. The second method relied on the interactions between the alkali polymer solution and the rock material to reduce the pH. The performance of the KUSP1-MEP system and KUSPl-rock system was studied in several types of porous media.
A second property of KUSP1 is that it can be gelled in a time-delayed manner by the addition of boric acid. Performance of the KUSP1-boric acid system was studied in sandpacks and Berea sandstone cores.
A New Method for Systematic Identification of Nontoxic Gels
Authors: Kolnes Jostein , Saurdal Janne , Nilsson Svante 
Published: December 2007

Abstract
A new method for systematic identification of nontoxic gels is described. It is based on fundamental chemical reactions between organic compounds containing different functional groups, here called X and Y. Such reactions are found in most textbooks on organic chemistry. The next step is to identify polymers with either X or Y as a functional group. The crosslinker can than be selected from a usually large group of molecules containing at least two X groups (for the Y polymer) or at least two Y groups (for the X polymer).
Using catalogues listing the toxicity of organic chemicals, both the polymers and crosslinkers can be screened, and the least toxic and least costly can be selected for further studies. In these studies the gelant can be optimized regarding gelation time, including the effect of pH and temperature, gel appearance as a function of concentration of both polymer and crosslinker, and the behavior of the gelant and gel in cores.
In this study we report results from experiments carried out on gelant systems based on the ester reaction between a carboxylate group (X) and an alcohol group (Y). Here both polymers containing carboxylate groups (hydrolyzed polyacrylamide) and alcohol groups (polyvinylalcohol) can been used. The corresponding crosslinkers are di- and polycarboxylic acids (X) and di- and polyols (Y). This paper focuses on the system polyvinylalcohol and polycarboxylic acids.
Investigation and Improvement of BaSO4 Scale Inhibition Tests
Authors: Yuan M. D. , Anderson M. , Jamieson E. 
Published: December 2007

Abstract
The commonest means of laboratory evaluation/screening of scale inhibitors for oilfield applications is by conducting scale inhibition jar tests. This paper focuses on several aspects concerning barium sulphate scale inhibition jar tests and highlights three particular factors which may influence the test outcome and the ranking of an inhibitor's performance as compared with others. The work presented in the paper confirms the critical importance of temperature. It proves that filtration of a supernatant sample when taken from the test jar for Ba analysis could lead to erroneous results on barium sulphate inhibition efficiency. This investigation also indicates that chelating agents may reduce inhibitor inhibition efficiency against barium sulphate. However, such an effect is found to be far less significant than that reported elsewhere.