bluuebunny/crossref_metadata_2025 huggingface dataset:
A ética no marketing
Authors: D'Angelo André Cauduro
Published: April 2009

De todas as atividades empresariais, o marketing é a de maior visibilidade e, por isso, a mais sujeita a questionamentos de ordem ética. Historicamente, as práticas de marketing têm sido alvo de críticas, o que torna pertinente uma revisão da literatura acadêmica relativa ao tema e a análise das principais contribuições oriundas dos trabalhos publicados. Existem basicamente duas categorias de questionamentos éticos em relação ao marketing: a primeira, ligada às características do sistema capitalista, diz respeito ao presumível estímulo materialista despertado pelo marketing; a segunda, de caráter mais prático, enfoca atividades de marketing como precificação, propaganda e vendas. Em comum entre ambas está a multiplicidade de visões relativas à ética que, por se tratar de tema complexo e subjetivo, está sujeita a diferenças de interpretação, que variam conforme as circunstâncias e as percepções, dificultando o consenso. Como resultado, os atores do marketing e do mundo dos negócios tendem a se mover em certa zona de amoralidade, deixando que o mercado e a sociedade julguem as suas práticas.
Inovação e o desempenho empresarial: lucro ou crescimento?
Authors: Brito Eliane Pereira Zamith , Brito Luiz Artur Ledur , Morganti Fábio
Published: April 2009

A inovação é considerada um fator fundamental para o desempenho das empresas. No entanto, as evidências empíricas não suportam consistentemente essa relação no nível da empresa. Neste trabalho, foram utilizados dados secundários da base Pintec do IBGE, que segue a definição de inovação da OECD. Esta métrica considera um amplo espectro de aspectos do processo inovativo. Uma amostra de empresas atuantes no setor químico brasileiro foi analisada por meio da técnica de regressão linear múltipla. Os resultados mostraram não haver relação significativa entre os indicadores de inovação e métricas de lucratividade. Por outro lado, foi encontrada uma relação positiva e estatisticamente significativa com o crescimento da receita líquida. A conclusão é de que o esforço inovador tende a afetar mais o crescimento do que a lucratividade. As descobertas tanto corroboram alguns estudos anteriores como se contrapõem a outros.
Antizyme is necessary for conversion of pancreatic tumor cells into glucagon-producing differentiated cells
Authors: Suzuki Jun-ichiro , Murakami Yasuko , Samejima Keijiro , Ohtani Kohfuku Kohda Masahiro , Oka Takami
Published: April 2009

Human pancreatic tumor cell lines – AsPC-1, PANC-1, MIA paca2, KP-1 and KP-59 cells – can be induced to differentiate into pancreatic hormone-producing cells by brief trypsin treatment and subsequent culture in a serum-free, chemically defined medium. During culture, AsPC-1 cells formed cell clusters resembling the pancreatic islets, expressed genes associated with the pancreatic development and produced glucagon but not insulin. When PANC-1, MIA paca2, KP-1 and KP-59 cells were treated and cultured the same way, they underwent similar morphological changes and produced insulin and glucagon. We used these systems to identify intracellular regulatory molecules involved in the conversion of pancreatic tumor cells into glucagon-producing cells. We found that the expression of antizyme 1 (AZ1), a negative regulator of ornithine decarboxylase, was increased and its localization was altered from the nucleus to the cytoplasm during AsPC-1 cell differentiation. Transient transfection of AsPC-1 cells with AZ1 siRNA resulted in inhibition of the morphological and functional cell differentiation as well as the specific suppression of AZ1 expression. By contrast, constitutive overexpression of AZ1 in AsPC-1 cells led to the enhancement of glucagon production. We also found that PANC-1 cells reduced the expression of glucagon mRNA when treated with AZ1 siRNA. These results suggested that AZ1 was necessary for the conversion of pancreatic tumor cells into glucagon-producing cells. Glucagon production in AsPC-1 cells was not affected by addition of putrescine, suggesting that the polyamines were not directly involved in the AZ1-mediated conversion of pancreatic tumor cells to differentiated state.
Prediction of Wellbore Temperature Profiles During Heavy Oil Production Assisted With Light Oil
Authors: Yu Yanmin , Lin Tao , Xie Hongxing , Guan Yanyan , Li Kewen
Published: April 2009

In some heavy oilfields, oil can flow in the reservoirs but may not flow through the wellbore without taking measures such as heating or diluting with light oil because of the high viscosity caused by low temperature around the wellbore close to surface. We focused on the latter issue in this study which is being widely used in Tah oilfield and other oilfields in China. Since the viscosity of the crude oil changes with temperature significantly, accurate prediction of wellbore temperature profiles is of great importance to determine the injection rate and temperature of light oil for dilution. An analytical model was derived to predict the wellbore temperature profiles for the heavy oil production assisted with the addition of light oil from the annulus. The model was based on energy balance between the formation and fluids flowing through each conduit. The temperature profiles were calculated using the proposed temperature model and the results were compared with the measured data. Sensitivity analysis was conducted using the proposed model and the main factors that influence the temperature profiles were discussed.
Effects of Friction on Post Buckling Behavior and Axial Load Transferring of Pipe in a Horizontal Well
Authors: Gao Guohua , Miska Stefan
Published: April 2009

In this paper, the buckling equation and natural boundary conditions are derived with the aid of calculus of variations. The natural and geometric boundary conditions are used to determine the proper solution that represents the post-buckling configuration. Effects of friction and boundary conditions on the critical load of helical buckling are investigated. Theoretical results show that the effect of boundary conditions on helical buckling becomes negligible for a long pipe with dimensionless length greater than 5π. Velocity analysis shows that lateral velocity approaches infinity and lateral friction becomes dominant at the instant of buckling initiation. Thus, friction can significantly increase the critical load of helical buckling. However, once buckling is initiated, axial velocity becomes dominant again, and lateral friction becomes negligible for post-buckling behavior and axial load transfer analysis. Consequently, it is possible to seek an analytical solution for the buckling equation. To verify the proposed model and analytical results, the authors also conducted experimental studies. Experimental results support the proposed solutions.
Production Enhancement through Pattern Modification—Analysis and Field Results
Authors: Pu Hui , Wang Guofeng , Han Guangzhi , Base Casper
Published: April 2009

Xinzhao oilfield, a naturally fractured low-permeability field in Daqing, was put into development in 2000 using an inverted nine-spot waterflood pattern with 300m×300m well spacing. Although waterflooding at Xinzhao oilfield had been an economic success, performance had generally been considered disappointing because oil response following expansion and waterflood adjustment was always less than predicted, so an integrated study aiming to improving the development effect of Xinzhao oilfield was conducted. This paper presents the results of a study addressing the impact of fractures on the recovery and on the reservoir management in pattern waterfloods.

Geological study and reservoir performance study indicate that several factors result in this seemingly unfavorable performance, one of main reasons are that the inverted nine-spot pattern is not compatible with the orientation of fractures. The production wells on the row of injectors are seriously watered-out and watercut increases very fast. Reservoir simulation studies indicate that oil cut can be improved if the injection pattern is modified from current inverted nine-spot well pattern to direct line drive pattern to take advantage of orientation of fractures. A field test project based on these studies has yielded results that indicate improved economic performance and better development effect.
Predicting Production Outcome from Multi-stage, Horizontal Barnett Completions
Authors: Grieser Bill , Shelley Bob , Soliman Mohamed
Published: April 2009

Developing a predictive reservoir model involves determination or estimation of key reservoir components, which can vary through the rock volume. Sophisticated, 3-D grid models usually require significant input data and are built for conventional reservoirs producing in Darcy flow.

Production from the Barnett shale is not conventional. Shale-rock gas flow involves a complex mixture of free and adsorbed storage and production mechanisms. Free gas can be stored in the microporosity, natural fractures, or thin lamination existing or created during hydraulic fracturing. Adsorbed gas is contained in the organic material randomly distributed in the bulk rock.

Horizontal, multistage-fractured wellbores add another level of complexity. Massive hydraulic fracturing of horizontal shale has shown complex fracture networks are created along the wellbore. Mapped data suggests multiple fracture planes are created during injection. These fracture planes can be irregular in length and are not always symmetrical. Conventional reservoir models can not handle this level of complexity.

A new, 3-D, four-phase, nonisothermal, multiwell black oil and "Pseudo-compositional" simulator that allows placement of multiple transverse fractures along the horizontal has been developed. Its ability to model horizontal, multiwing, transverse fractures and account for all three reservoir phases, including injected fluid, makes this model more predictive of production.

This paper uses mapped fracture dimensions of horizontal wells in the north Texas Barnett (NTB) to build a reservoir model. Comparisons of model production to real production are made to demonstrate the model's predictive ability.
Evaluation of Twophase Flow Correlations and Mechanistic Models for Pipelines at Horizontal and Inclined Upward Flow
Authors: Yuan Hong , Zhou Desheng
Published: April 2009

In this study, commonly used two-phase flow pressure prediction correlations and mechanistic models for pipelines in petroleum industry are evaluated against experimental data. The experimental data were obtained from published papers.

Horizontal and upward two-phase flow are common in oil and gas production and transportation. During pipeline design and simulation, experimental data are usually unavailable to calibrate against correlations and models. In this situation, it is difficult to determine which correlation or model to use in predicting pressure gradient in pipelines.

Experimental data used in this study are from Kokal and Stanislav papers (Kokal and Stanislav, 1989) and from Chen et al. paper (Chen et al., 1997). For the Kokal and Stanislav papers, experimental data were gathered from 1-inch, 2-inch and 3- inch pipes with seven inclination angles. Oil and air were used as testing fluids. During the experiment, superficial liquid velocities range from 1.2 to 10 ft/s and superficial gas velocities range from 0.76 to 85 ft/s. For the Chen et al. paper, data were gathered from a 3-inch horizontal pipe at stratified-wavy flow. Kerosene and air were testing fluids.

Beggs-Brill, Dukler-Eaton-Flanigan, Dukler and Eaton correlations and Xiao mechanistic model are evaluated in this study.

The results of this study can be used as guidelines in choosing two-phase flow pressure prediction correlations and models in designing and analyzing horizontal and upward two-phase flow pipelines.
Developing a 2 Year Oil and Gas Education Program
Authors: Bjornen K. H. , Stacy J. R.
Published: April 2009

Since the peak of employment in the domestic oil and gas industry in 1982, employment in this industry has declined by 51% from 708,000 to 345,000 workers in 2007. Prices for oil and natural gas have generally increased since 2000 with increasing worldwide demand. While the state of hiring for professionals and engineers is well known, there has also been a critical shortage of qualified field personnel who drill for and extract the oil and gas. In some regions this has led to limits on the growth of domestic drilling and production. Safety and environmental records have also been impacted due to the lack of experienced operators and well trained new hires. Additionally, the level of skills required for field personnel has increased due to technological advances in the oil and gas industry.

To address this need there has been an effort by some two year post secondary institutions to develop programs that will lead to well prepared entry level employees. The following paper will discuss curriculum development for a two year program offered through a community college. The program was designed such that graduates would have a broad background suitable for many facets of field work in the oil and gas industry.
Correlating Flowing Time and Condition for Perforation Plugging by Suspended Particles
Authors: Tran Tung V. , Civan Faruk , Robb Ian
Published: April 2009

Conditions leading to plugging of perforations in wells and pore-throats in porous formations are investigated experimentally. Accurate correlations are developed for the effect of pore-throat-to-particle-size ratio on flowing fluid conditions and plugging time leading to particle bridging. It is demonstrated that the critical pore-throat-to-particle-size ratio vs. particle-volume- fraction Reynolds number can be correlated satisfactorily using an exponential function and the dimensionless plugging time vs. reciprocal-particle-volume-fraction yields an exponential-type correlation. Such empirical correlations can be used to determine and alleviate the conditions which induce perforation and pore plugging by migrating particles in petroleum reservoirs. These correlations reveal that the critical pore-to-particle diameter ratio below which plugging occurs may be greater than the unit physical limit.
Multilateral Completions in the Granite Wash: Two Case Studies
Authors: Goodlow K. , Huizenga R. , McCasland M. , Clift D. , Neisen C.
Published: April 2009

This paper will detail the design and installation of two multilateral completions in the Granite Wash in the Texas Panhandle. The paper will discuss the operational aspects of the drilling programs, construction of the lateral junctions, fracture treatments of both laterals, and final realized production. Details on the completion equipment and techniques developed to meet the operational goals will also be covered.

Multilateral completions have strong economic potential in unconventional gas developments. Operators can save capital investment by accessing production from two laterals while drilling a single vertical wellbore. Greater drainage access across a section is also possible by using this technology.

The technical challenge of this project is to provide a 10,000-psi seal across the junction to selectively fracture both laterals, which requires a TAML level 4 junction. The commercial challenge is to provide this technology and install it so that economic benefits exceed those of drilling two separate wellbores. Details of how well both of these challenges were met will be discussed.

The subject wells of this paper were drilled and completed between February and September of 2008. The paper will document lessons learned, modifications needed, and relative operational success. These objectives will be presented from both the operator's and contractor's viewpoints.
Backside Auto-Injection System
Authors: Garner Ted D.
Published: April 2009

The Backside Auto - Injection System (BAIS) is designed to allow gas to be injected into the packerless production tubing/casing annulus intermittently without having to pull the tubing and install gas-lift mandrels and valves. This is accomplished by using a single portable wellhead compressor to collect gas from the tubing and simultaneously compress the gas down the casing-tubing annulus. The control of gas flow is directed by pressure activated motor valves. As the gas enters the bottom of the tubing, the gas-liquid ratio (GLR) is increased sufficiently to unload the wellbore liquids to the surface. Once unloaded, the gas flow is directed to sales until further loading is detected by the BAIS. This system is designed to provide liquid unloading and economic production enhancement to marginal gas wells.
Oriented Perforation in Dual Completion Wells: A Real Case in East Texas
Authors: Gama Cesar , Gerez David , Babasick Paul A. , Piedras Jose
Published: April 2009

Fracturing is an important technique for stimulating production in low-permeability formations, and requires special consideration in designing the preceding perforating job. Aligning the perforations along the direction of maximum geological stress, known as the preferred fracture plane (PFP), provides significant opportunities to improve the efficiency of the fracture job, maximizing ultimate production from the well.

Wells are frequently completed with multiple tubing strings (up to four in some cases), sensor lines, control lines, or other hardware that can be damaged during perforation. The traditional approach of hiring a workover rig to remove the completion prior to perforating is, in many cases, not cost effective, leading to foregone opportunities to extend production by perforating new intervals or reperforating existing producing zones. With casingless completions, even this option is not available.

A downhole orienting and imaging platform has the unique capability to orient guns along the PFP for optimal fracturing efficiency while simultaneously avoiding damage to complex downhole completions, without the expense of workover. This technology enables the enhanced production from wells that may otherwise have been uneconomical. The technique was applied during a pre-fracturing perforating job for Total E&P USA, Inc. (Total) in their Bethany field located in east Texas. The job addressed the dual objectives of orienting the perforations along the PFP, while simultaneously avoiding the parallel completion, which if perforated would open a communication path between reservoirs with different pressures.
Transient-Pressure Analysis of a Well With an Inclined Hydraulic Fracture Using Tiab's Direct Synthesis Technique
Authors: Dinh Anh V. , Tiab Djebbar
Published: April 2009

The purpose of this study is to develop a technique, based on the pressure derivative concept, for interpreting pressure transient tests in wells with an inclined hydraulic fracture. Detailed analysis of unsteady-state pressure behavior of fully penetrating inclined fracture in an infinite slab reservoir was provided. Both uniform flux and infinite conductivity models were considered. The study has shown that inclined fracture pressure data exhibit similar flow regimes as for vertical fracture counterpart. Those flow regimes are linear and pseudo-radial flow for both uniform flux and infinite conductivity models. However, for infinite conductivity model, a bi-radial flow regime is also observed. In the case of high formation thickness to fracture half length ratio and high angle of inclination, both uniform flux and infinite conductivity inclined fracture model exhibit an additional flow regime called early radial flow. Both bi-radial flow and early radial flow regimes for inclined hydraulic fracture have not been mentioned in the literature before.

A step by step procedure based on Tiab's Direct Synthesis (TDS) was developed in this study. Fracture properties such as half fracture length, inclination angle, formation permeability and pseudo-skin factor can be obtained from the direct interpretation of the log-log plot of pressure and pressure derivative without the need of any type curve matching. Several unique features of the pressure and pressure derivative plots of both uniform flux and infinite conductivity inclined fracture models were identified including the points of intersection of straight lines for different flow regimes. These points can be used to verify the results or to calculate unknown parameters. Equations associated with these features were derived and their usefulness was demonstrated. Numerical examples with both pressure build-up and drawdown data were also demonstrated for this procedure.
Metrics for Evaluating Cementing Success
Authors: Duckworth Deborah
Published: April 2009

Many papers and books have been written relating the importance of cementing operations to the success of drilling and completions operations. While cementing costs typically represent less than 10% of total planned wells costs for domestic US onshore operations1, the failure to get good zonal isolation and adequate cement bonding to the casing and formation can be catastrophic…from loss of potential pay zones to the loss of the entire well. Even operator personnel involved with cementing on a regular basis may take the operation for granted. "Cementing should be seamless." "It is not a commodity that I am as tied into as mud or casing."2 Often the success of the cementing operations is measured on location with a single drilling report entry…Bumped the plug and floats held. Good cement job. But was it really a good cement job? Does bumping the plug and pumping all the cement really reflect the efficiency and quality of the job? A recent two year cementing project in Wyoming provided both the operator and the service company an opportunity to develop metrics for evaluating cementing success that go beyond "bumping the plug". The purpose of this paper is to present the key performance indicators developed and demonstrate how to apply them to other cementing projects to quantify cementing success. For the seasoned engineer this paper provides a review of the importance of cementing operations while newer engineers may use it to become more familiar with the scope of planning and implementing successful cementing operations.
Multiphase Meter Production Well Testing Applied to Low-GOR Mature Fields
Authors: Mehdizadeh Parviz , Farchy David , Suarez Jairo
Published: April 2009

In many mature fields production well testing is limited by the availability of test separator. Prior industry attempts to utilize the new technology of multiphase metering to fill this gap has been hampered by the cost of multiphase meters. This paper describes the development and field tests of a low cost portable multiphase meter. The meter utilizes the Coriolis flow meter technology combined with a microwave based water cut meter that can measure WC in the 0-100% range. The combination of these techniques provides a light weight metering package that can be mounted on trailer for portable well testing. This multiphase meter can measure oil, water and gas without separation of the production stream at low GOR. These applications can be found in mature fields with low GOR and in heavy oil fields.

The multiphase meter was subjected to field qualification tests prior to deployment in a West Texas field. The paper describes the results from the qualification tests and the performance history during the 18 months of deployment in the field. Well test data from the multiphase meter is compared to conventional test separator and grab samples. Comparison between the test separator and the multiphase meter shows average liquid flow deviation of about ±7%. The water cut was measured within 1-2 points of the water cut from the test separator.
A Case Study Examining a Cost-Effective Gel System for Water Shutoff in a Low Pressure Layer
Authors: Major C. R. , Hines D. N. , Gould J. H. , Pender D. B.
Published: April 2009

An innovative system consisting of three different Chromium Carboxylate Acrylamide Polymer (CCAP) gels is being used in place of conventional cement squeezes in the Upper Spraberry formation located in West Texas. The application of the CCAP gel to shut off water production by abandoning the Upper Spraberry formation has resulted in increased oil production, lower workover costs and reduced lease operating expense (LOE) in the majority of the wells that have been treated to date.

A typical Spraberry Trend Area well consists of the Upper and Lower Spraberry and Dean formations. After fracture stimulation, the intervals are produced by beam pump. Reservoir characteristics and the completion configuration cause the Upper Spraberry formation to be more susceptible to water encroachment. Because the Upper Spraberry has low reservoir pressure, conventional squeeze cementing is difficult. The hydrostatic pressure resulting from a column of cement will further breakdown the formation requiring high cement volumes and/or multiple squeeze attempts in order to successfully shut off the interval. As an alternative to conventional cement squeezes, gel treatments with volumes between 700 and 1,000 barrels using three different gel systems are used to successfully shut off the Upper Spraberry formation.

One hundred eight wells have been treated to date. Many of the wells initially treated in 2003 are still benefiting from the gel treatment, maintaining oil production with lower water/oil ratios. Gel treatments have been successful in increasing or restoring oil production, and reducing operating expense and workover cost. Increases in gel treatment cost have been minimal over the years compared to that of cement. The gel treatments have proven to be a cost-effective, long-term alternative for conventional cement squeezes.
Determining the Optimal Artificial Lift Strategy When Operating a Mature CO2 Flood in the Real World
Authors: McWilliams Jay Paul , Gonzales David
Published: April 2009

Effectively operating artificial lift systems can be a very challenging endeavor when implementing tertiary recovery on a mature oil field. The desire to produce a maximum amount of oil must be balanced with the physical limitations of the artificial lift equipment. The traditional operating limitations of artificial lift equipment may be too liberal in a CO2 flood. Being too aggressive when attempting to reduce fluid levels can lead to excess failures and thus, reduced overall production and excessive costs.

Attempting to determine the optimal artificial lift strategy in this environment can be a daunting task. Traditional models for determining operational policy may not capture all of the dynamics that affect the performance of the system. An empirical approach can be helpful in setting artificial lift guidelines.

This paper discusses the results of an empirical analysis of an artificial lift system's performance in a mature CO2 flood vs. the performance in a mature water flood. For the analysis, data from two oil fields in southeastern Utah, the McElmo Creek Unit (mature CO2 flood) and the Ratherford Unit (mature water flood) was compared and contrasted. The data was analyzed using statistical modeling tools to determine the appropriate strategy for the system. The results from the review gave significant insights to the optimal strategy for operating the system and will be discussed.
Green Proppant Systems From Locally Available, Low-Cost Materials
Authors: Santra Ashok , Saini Rajesh , Luo Hongyu , Norman Lewis , Parker Mark
Published: April 2009

Description of Materials

Recycled materials and waste products, such as glassy materials, igneous-rock tailings, and Portland cement-based materials, have been used to prepare new proppants. Both conventional recycled glass, such as plate glass, e-glass, and common bottle glass, have been explored in addition to unconventional sources, such as materials generated from the burning of sewage sludge. Undersized materials, such as fines from the processing of the minerals to make roofing-shingle granules, have been used to prepare proppants. Recycled concrete may also be used to manufacture proppants.

Applications

All of the above mentioned proppants are useful in place of conventional sand and intermediate-strength proppants in applications including gravel packing and hydraulic fracturing.

Results

Glass-based proppants are known for their catastrophic failure and tendency to crush into fine particulates. New processing methods allow for mitigation of this shortcoming by generating proppants that closely resemble the performance of conventional sand proppants. Igneous materials can be processed to create proppants that exceed the performance of sand proppants and approach that of conventional intermediate-strength ceramic proppants. Portland cement-based proppants have been developed with a SG as low as 1.6. New processing techniques allow for lower sintering temperature compared to commercial ceramic proppants, resulting in reduced energy consumption during manufacture. Recycled concrete has been used to generate proppants that resemble conventional ceramic proppants but are also processed at reduced temperature to reduce the energy required during manufacture. API testing, such as crush and conductivity tests, are reviewed in this paper for comparison to conventional proppants. These new proppant systems are desirable because of a potential lower cost and for their sustainability during manufacture. In some aspects of performance, the new proppants exceed conventional proppants.

Significant New Contribution

Several new materials systems are presented for consideration in the manufacturing of proppants. In some cases, these systems make use of recycled materials or waste materials and, in other cases, these systems are processed at reduced temperature to reduce the energy required during manufacture, compared to conventional proppants. As potential opportunities for new proppants, these materials are presented to the oilfield community to judge whether they are technically and commercially viable.
Well-Performance Diagnostics Using Smart Plunger Technology
Authors: Gray Travis P.
Published: April 2009

Plunger lift system installations throughout the United States are experiencing an alarming boom as liquid loading becomes an ever-increasing impediment to hydrocarbon recovery in depleting wells.

Newly installed plunger lift installations within a field normally required individual onsite calibration at each well site. Accurate calibration of these installations can take many hours or even days to ensure optimal capability to recover liquid within the tubing string at acceptable rates. Operating expenses in turn often increase reflecting the time needed on location to "tune" the system to levels approaching maximum operational efficiency under plunger lift. Given the increase in the number plunger lift installations within a field(s) and resulting limitations in onsite operator calibration time at each installation, the need for automation to aid in "efficient tuning" of each individual plunger lift installation is critical to maintaining a steady production decline in a well with liquid loading characteristics.

Today, with the advent of modern automation technology, it is possible to access and manage all plunger lift installations within a producing field remotely. This can be accomplished with the aid of a personal computer connected to the field's collective network of plunger lift controllers via the use of a SCADA (Supervisory Control and Data Acquisition) system supported by key control system components such as Programmable Logic Controllers ("PLC") and Remote Terminal Units ("RTU"). These provide a field operator with the capability to perform basic operational tasks (e.g. the closing and opening of valves), without being present at the well site and allow for the plunger lift installation to adapt to changing field conditions without operator interface.

This paper will address the proper application of Smart Plunger Diagnostic Technology in the field with the objective of increasing plunger lift installation efficiency in turn leading to improved well productivity with minimal increased operating expense.
New Sucker-Rod Connection Designed for High-Load Applications
Authors: Telli Francisco Diaz , Muse Daniel , Fernandez Ezequiel , Pereyra Matías
Published: April 2009

The present paper describes the premium connection (PC) sucker rods field experience in various applications and shows the results collected until now. Ay the moment this paper was written, 11 wells were working with this sucker rods under different loads ratings.
A New Nodal Analysis Technique Helps Improve Well Completion and Economic Performance of Matured Oil Fields
Authors: Awal M. Rafiqul , Heinze Lloyd R.
Published: April 2009

Mature fields lack the sparkle of a new play, and an operator typically will not invest capital for waterflooding, much less EOR. But prevailing higher oil prices can turn such a mature oil field more profitable by employing innovative production enhancement techniques. We propose the use of a simple, tapered tubing string completion (using larger internal diameter (ID) tubing pipes in the upper sections) that can be customized for specific reservoirs. Historically there are few instances of tapered ID tubing completion, which were basically necessitated by technical constraints (liner, workover, etc.). But our approach is focused on enhancing economic performance. We have employed nodal analysis technique to develop an equivalent tubing diameter (ETD) concept. The ETD allows for comparing the well performance for single-ID tubing completion. The procedure also seeks an optimum length for the larger tubing ID in the upper section. Using reservoir simulation for full life cycle, and oil prices projected over time until abandonment, the economic performance is evaluated using NPV and other economic parameters.

The proposed production enhancement method is suitable for wells with moderate to high open flow potentials (AOFP). It is especially suited for low GOR wells with high future water-cut that will eventually require an ESP system, and also remote oilfields, where reservoir pressure maintenance and EOR is not viable.

The use of larger tubing ID section entails only a marginal increase in CAPEX. However, the tapered completion gives increased production rate sustained over a long time, which results in significant economic gain. The economic benefits accrue from the prevailing high oil price, yielding a quick payout and many returns on investment.

The proposed completion approach does not involve complexity, and the innovative application of nodal analysis coupled with high oil prices show how to make mature oil fields onshore and offshore, more profitable.
Modified Foss and Gaul Model Accurately Predicts Plunger Rise Velocity
Authors: Rowlan O. Lynn , Lea James F. , McCoy J. N.
Published: April 2009

Accurate prediction of the average plunger rise velocity is important to optimally unload liquid from a plunger lifted well. A modified Foss and Gaul model presented in this paper predicts the minimum build casing pressure criteria to open the motor controlled valve for a selected plunger rise velocity. Results from the modified Foss and Gaul model are contrasted with results from the original Foss and Gaul model. The minimum build casing pressures predicted using both models are compared to measured casing pressures at the same rise velocities measured from field data acquired on 10 different plunger lifted wells.

During the shut-in time period the plunger falls through gas, liquid and then rests at bottom on the bumper spring. At the end of this time period when the surface valve opens sufficient pressure is required to build to enough magnitude to unload the accumulated liquid and conventional plunger from the bottom of the well to the surface. An industry rule-of-thumb load factor criterion is frequently used to determine at what casing pressure build, Pc, the well should be opened to unload the liquid to the surface. The best technique to predict the maximum casing build pressure, Pcmax, is to use a Foss and Gaul type model to predict the rise velocity within a range of 500-1000 feet per minute (fpm), more optimally at 750 fpm that will unload the plunger and liquid to the surface.

The modified Foss and Gaul model favorably predicts a required casing operating pressure to bring the plunger and liquid to the surface at a specified average rise velocity. Using the modified model will allow an operator to determine the maximum shut-in casing pressure a plunger lifted well should be allowed to build before opening the valve and safely bring the plunger to the surface.
Quickly Identifying Well Problem by Modern Production Analysis for a Better Stimulation Plan
Authors: Wang Sharon , Túnjar César
Published: April 2009

Diagnosing well performance problems before stimulation treatment is an important step to successfully improve a well's productivity. Normally, the method used to do this is well testing. Unfortunately, often no well testing is done in a well before planning a stimulation treatment. An operation engineer then has to determine the causes of a well underperformance without well testing data. This is one challenge an operation engineer has to face before he/she designs a stimulation job. Another common challenge is inadequate data available to analyze a well's performance. In many instances, the only data available to an operation engineer is the production data. The critical questions then are how to get the insight of a well's production problem, and how to evaluate well performance and reservoir potential by the limited data. These are real challenges for engineers attempting to develop an effective stimulation design. The modern production analysis derived from pressure transient in well test is a practical and economical alternative to well testing for evaluating well performance, and the needs of a treatment.

This paper presents an effective method of how to quickly identify well problems with a limited amount data. Two case studies have been conducted in how to assist an operation engineer in development of a proper stimulation plan.
Acoustic Liquid Level Testing of Gas Wells
Authors: McCoy J. N. , Rowlan O. Lynn , Podio A. L.
Published: April 2009

Initially Gas Wells usually flow at sufficiently high rates to remove all liquids from the wellbore. When the gas flow rate decreases below critical rate1 some intervention such as compression, surfactants, and/or velocity strings is required. At a later time when either reservoir pressure and/or gas flow rate is sufficiently reduced, then other means of artificial lift (usually such as plunger lift, gas lift, or sucker rod lift) must be added to maintain production. Acoustic fluid level testing can be used to investigate the producing condition of a gas wells. Developments in digital acoustic fluid level technology have resulted in the operator being able to undertake fluid level measurements and use this technology to investigate the status of his gas wells. The act of acquiring a fluid level on a gas well is an inexpensive and non-intrusive process. Examples of acoustic tests are presented, where the test are performed on shut-in or flowing above or below critical flow rate gas wells with or without surfactant treatments acquired down the tubing or the tubing/casing annulus.

Techniques for acoustic liquid level analysis are discussed for gas wells where unusual conditions exist such as very shallow liquid levels, very deep liquid levels, noisy wells, high bottomhole temperature, and low or high surface pressures. Some gas wells have gas lift mandrels, liners, multiple zones of perforations, tubing holes, flush pipe and other conditions which result in the acquisition of difficult to interpret acoustic traces. This paper describes analysis techniques used to determine the distance to the liquid level in gas wells with these unusual conditions. The analysis is based on data obtained at the surface without entering the wellbore and yields accurate representation of the conditions existing on the surface, within the wellbore and within the reservoir.
Experimental Study on Fiber Sweeps in Horizontal and Highly Deviated Configurations
Authors: Ahmed R. M. , Takach N. E. , Savitri M.
Published: April 2009

Cuttings transport in horizontal and highly deviated wellbores is challenging because the fluid velocity in these wells has a reduced vertical component. Hole cleaning sweeps are applied to reduce cuttings accumulation in the wellbore. Field studies indicate that fiber-containing sweep fluids have been very effective in cleaning horizontal and highly deviated wells. Although the results of preliminary field studies are encouraging, very little is currently known about cuttings transport efficiency of fiber sweeps.

This article presents results of experimental investigations conducted to study hole cleaning performance of fiber sweeps. Flow loop experiments were performed in horizontal and inclined configurations using two test fluids: i) base fluid (0.47% Xanthan Gum); and ii) fiber sweep (0.47% Xanthan Gum with 0.04% synthetic fiber). Rheological properties of the test fluids were very similar. Experiments were conducted by eroding cuttings deposited in the test section at a constant flow rate and measuring the amount of cuttings removed by the base and sweep fluids. Results indicate that the fiber sweep has better hole cleaning capabilities than the base fluid in the horizontal configuration. When tests were conducted in an inclined configuration (68° from vertical), improvement in the hole cleaning capability of the fluid due to the addition of fiber is moderate. The experimental results and findings of this research are very useful for directional and extended-reach well drilling applications.
Novel Completion for Effective Deliquification of Natural Gas Wells
Authors: Wang John Yilin
Published: April 2009

Liquid loading has been a problem for natural gas wells for several decades. With gas fields becoming mature and gas production rates dropping below the critical rate, deliquification becomes more and more critical for continuous productivity and profitability of gas wells.

Current methods for solving liquid loading in the wellbore include plunger lift, velocity string, surfactant, foam, well cycling, pumps, compression, swabbing and gas lift. All these methods need to lift the liquid up to surface, which increases the operating cost, onshore and offshore. A better completion method has been developed to separate and reinject the liquid into the reservoir formation.

The new completion method – wellbore separation and reinjection through vertical well or horizontal well – depends on reservoir permeability, reservoir pressure, formation thickness, liquid production rate and geology. Through numerical reservoir simulation study, these parameters have been quantified and optimal completion has been developed for particular reservoirs based on gas recovery. Effect of liquid loading on gas productivity has also been investigated in two aspects: backup pressure and near-wellbore-liquid blocking. The new completion methods can increase gas recovery, prevent scale problem in the wellbore and surface pipeline, and avoid the liquid lifting and processing. It is an effective, economical, and environment friendly technology for natural gas wells.
Effects of Subsurface Pump Size and Setting Depth on Performance of Sucker-Rod Artificial Lift—A Simulation Approach
Authors: Shedid Shedid A.
Published: April 2009

The need for better understanding of sucker rod pumping process is heavily required. Many problems are still under investigation such as determination of the fluid level from surface, selection of the optimum pump size and the required pump setting depth to maximize the pumping rate in a particular well. The main purposes of this study are to investigate effects of fluid level over pump, pump size, and pump setting depth on the sucker rod performance. These goals are achieved using the Artificial Sucker Rod Pump (ASRP) design simulator with actual field data.

The results show that applying good fluid level from the surface and increasing the plunger stroke consequently increase the resultant pumping flow rate. Furthermore, good fluid level yields high pump intake pressure and results in a good pump fillage, which increases the pump efficiency. In addition, the analysis of the effect of pump size on rod stress shows that the increase of pump size increases the rod stress and increases the pump flow rate. Therefore, the plunger size must be selected according to both the required flow rate and the allowable sucker rod stress. With respect to the effect of the pump setting depth on the performance of the sucker rod pump, the increase of the pump setting depth reduces the pump flow rate and increases the rod stress. Actual Egyptian field data is used for the purpose of achieving this simulation investigation of the above-mention effects.
Economics of LNG Projects
Authors: Al-Saadoon Faleh T. , Nsa Abel U
Published: April 2009

The economic viability of a liquefied natural gas (LNG) project is evaluated using industry-wide data. The range of expenditure figures (both capital and operating) obtained from the literature is synchronized into a unit energy basis across the value chain – liquefaction, shipping and re-gasification.

A Base Case is adopted based on a single train of 4.2 million metric ton per annum (MMTPA) capacity for a round-trip distance of 6200 miles (from Nigeria to the U.S. Gulf Coast), taking one (1) month round-trip voyage. It is assumed that the plant requires a 4-year construction period and it operates for 350 days a year in evaluating the economics of the project.

Two measures of profitability are used in assessing the economic viability of the LNG project, namely rate of return (ROR) and undiscounted pay-out-time (POT). A Base Case is performed using a Base Case Capital Expenditure (Base Case CAPEX), 15% discount rate and 3.00$/MMBtu raw gas price. In addition, sensitivity analyses are carried out on CAPEX (using -20%, -10%, Base Case CAPEX, +10%, and +20%), on discount rates (using 10%, 15%, 20% and 25%), on raw gas prices (using 1.00, 2.00, 3.00, 4.00, and 5.00$/MMBtu) and on overall operating expenditures (OPEX) ranging between 4.7% and 14.7% of CAPEX.

The pay-out-times for the various scenarios considered at discount rates of 10, 15, 20 and 25% are 7.82, 5.18, 3.68 and 2.76 years after startup/commissioning, respectively.

The break-even prices range between 3.00$/MMBtu (at Base Case CAPEX less 20%, 10% discount rate and 1.00$/MMBtu raw gas price) and 12.10$/MMBtu (at Base Case CAPEX plus 20%, 25% discount rate and 5.00$/MMBtu raw gas price). The corresponding mark-ups range between 2.00 and 7.15$/MMBtu, respectively.

The break-even and mark-up prices increase linearly with increasing raw gas prices yielding slopes of 1.17 and 0.17, respectively. These relationships hold true with all 100 cases considered in the sensitivity analysis.

A general survey of LNG liquefaction processes is also included.