bluuebunny/crossref_metadata_2025_split huggingface dataset:
Selection Slug Catcher Type
Authors: Vergara Contreras Moises Alfredo , Foucart Nicolas 
Published: December 2007

Abstract
Margarita field is one of the most important gas fields in Bolivia, not fully developed yet. The field development is to be completed in the near future and as part of the facilities to be constructed, it is included the installation of a slug catcher. The slug catcher situated at the end of the pipeline is intended to separate the phases and to provide temporary storage for the liquid received. Slug Catchers should be designed to take care of a slug.
The selection between the "Finger Type" and "Vessel Type" would be thorough the economical aspects and the characteristics of the equipment that best adapts to the conditions of the site.
The slug volume of the Margarita Field, calculated for a gathering system of 13 wells, being the outermost 30 Km. apart from the Plant, resulted in 26,35 m3 with a design pressure of 2025 psig.
The "multiple-pipe" slug catchers ("Finger Type") equipment is the most common equipment to handle slug volume, it is efficient and the operation is well known, however the common practice recomends that for volumes less than 100 m3, it is better to use the "vessel type" (this would be our case with 26,35 m3.) According to the rule of thumb the selection should be "Vessel Type", where 18 MMsm3/d is considered the gas flow for the design, that results in a diamenter of 102 inches by 14 meters long and a weight of 150 tons for the equipment size.
The "finger type" design from the equipment manufacturers could handle the same slug volume but the size is four fingers with a diameter of 40 inches by 10 meters long. The finger type needs 16 field welds and the weight is 80 tons. The equipment results in an easy assembly, of simple operation, smaller and lighter that facilitates transportation.
The Ex-Work delivery Cost and the equipment delivery to the site favors the "finger type" over the "vessel type". The installation cost for the vessel type is cheaper than the finger type but it is not enough as to favor the vessel type because if we add Ex-Work delivery and Installation costs, the finger type saves 30%.. The vessel type does not fulfill the savings expectations.in the Margarita Field Project ("onshore").
Additionally one more characteristic in favor for the finger type is the weight where the finger type does not risk transportation, where as the vessel type has transportation risks because the existing roads have only one lane that allows the passing of equipment less than 90 tons. The vessel type has 150 tons with a pressure design of 2025 psig; and if the pressure design would be 1500 psig, the weight would be of 120 tons.
After taking in consideration all the points in favor of the finger type (the multiple-pipe slug catchers), it is recommended to be installed in the Gas Treatment Plant (GTP).
Maximization of the Exploration and Development Efforts in Petroleum Field and Its Impact on the Hotelling's Model
Authors: Marques J. B. , Trevisan O. V. , Suslick S. B. 
Published: December 2007

Abstract
Many works on dynamic models for the maximization of the Net Present Value (NPV) on upstream projects have been published in recent years, originating in the academy as well as the industry. These models usually treat the effort considering either the exploration stage or the development stage of the petroleum field, but not both together. In this paper, two purposes will be pursued: (1) Investigating of the optimum net present value in the upstream project considering both exploration and development efforts simultaneously, and (2) Comparing the impact of this model against the dynamic models that deal with the sustainability of the exploration of exhaustible resources according to Hotelling's rule (1931). On the first topic, some papers were published by Pakravan (1977), Peterson (1978), Pindyck (1978), Liu and Situnen (1982), and Nilssen and Nystad (1986). The present paper shows a model bearing resemblance to the model proposed by Nilssen and Nystad (1986) but without the simplifications assumed by it. For this reason, the model proposed here may be more realistic. Some of the questions addressed in this work are: (a) What is the optimum exploratory effort for a petroleum field? (b) For how long do the exploratory efforts deserve investment before the beginning of the development stage? (c) What is the appropriate value of the reservoir recovery factor? The maximization of the NPV is represented by an objective function. The influence of the parameters in the calculation of the proposed objective function is shown by means of sensitivity analysis. Among the the companies in the world exploring petroleum, several do not usually adopt a methodology combining the exploration and development efforts. Filling this gap in the methodology is the main motivation for this work, which intends to disseminate the use of the combined model in the analysis of the economic viability project of the upstream area. Finally, in the conclusion section, among other suggested guidelines, indications are given as to which parameters from this model deserve more attention from persons making hard decisions in the upstream projects, and which information from the exploration and development of a petroleum field must be collected from existing data, or specially treated.
Single Step Matrix Acidising With HF–Eliminating Preflushes Simplifies the Process, Improves the Results
Authors: Rae Phil , Lullo Gino Di 
Published: December 2007

Abstract
For over 50 years, mixtures of hydrochloric and hydrofluoric acids have been used for the removal of near-wellbore damage in sandstone formations. Such mixtures dissolve many siliceous minerals, including clays and quartz fines, the materials most frequently associated with particulate plugging of the formation pores. Unfortunately, the dissolution of these minerals is not a simple process and various chemical reactions can result in the generation of voluminous solid precipitates or colloidal gels. The appearance of such precipitates in the near-wellbore, can ultimately cause further formation damage and negate the benefit of the acid treatment.
Other byproducts can be formed in sandstones containing carbonate minerals that react with acid and fluoride ions to produce the very insoluble calcium fluoride, CaF2, which is another potential source of formation damage. For this reason, traditional HCl:HF matrix treatments in sandstone formations are always preceded by a preflush, usually consisting of HCl to dissolve these carbonates.
This approach is not always successful and adds to the complexity of the operation. The situation is worse in multistage treatments, which traditionally involve many repeat stages of preflush, main HF-stage, overflush and diverter. In such situations, it is difficult to ensure that the correct acid stage is always entering the appropriate zone and encountering the appropriate mineralogy. The result can be poor zonal coverage, poor damage removal, creation of unexpected damage due to acid/rock incompatibilities and, ultimately, poor stimulation results.
This paper presents the results of a new acidising technique that eliminates the need for preflushes, across a wide range of mineralogies. It describes the background to this approach and reviews the results of laboratory testing and field treatments. It concludes with a matrix acidising methodology that can improve logistics, reduce cost and improve results while, simultaneously, making treatments easier to implement and control, at the field level.
Strategic Deployment of Chemical Systems in Petroleum Development Oman
Authors: Ojukwu K. I. , Al-Sharji H. H. , Al-Kitany N. , Stephenson E. , Edwards C. 
Published: December 2007

Abstract
Over 85% of Petroleum Development Oman (PDO) production is water and without action, this may increase to 95% by 2012. In 2004, a Chemical Profile Control (CPC) team was launched to coordinate a 2-year trial deployment of chemical water-shut-off technologies across the company. The aim being to reduce unwanted water or gas ingress for the purpose of improving oil or gas production while securing target recovery.
The deployment of chemical systems is adversely affected by four major challenges, namely; (1) limited know-how, especially of petroleum engineers & well engineers, (2) lack of multidisciplinary approach to candidate & chemical selection, (3) proof of concept before deployment and, (4) definition & measurement of success.
To tackle this problem, CPC team began by grouping PDO's Water Shut-Off challenges into 8 problem statements and presented it to known global providers. A workshop was organized inviting all contractors to propose solutions to the stated problems and acquaint PDO with available solutions. Based on our findings and confirmatory laboratory tests, the CPC team developed a Heatmap, which is a solution matrix that matches problems with solutions. A multidisciplinary assessment team was also created responsible for reviewing every project and proposing realistic solutions.
Since then more than 33 well trials – mainly in carbonate formations – have been completed at over 52% success rate using 3 existing contractors. Encouraged by these results, the company awarded umbrella contract to 3 other contractors to deploy a wider range of systems expected to boost success rate. The company strongly believes that increased success rate can be achieved by exploiting wider choice of effective systems, as inspired by laboratory trials.
This paper, therefore, presents the strategy, team, methodology, and overall results of the trials to date.
First Application of Novel Microemulsion Technology for Sand Control Remediation Operations—A Successful Case History from the Rosa Field, a Deepwater Development Project in Angola
Authors: Lavoix F. , Leschi P. , Aubry E. , Quintero L. , Le Prat X. , Jones T. 
Published: December 2007

Abstract
This paper documents a novel engineering approach and the operational methodology used to achieve high efficiency remediation on two offshore applications. Results are presented, detailing specific placement procedures, in-situ treatment design and productivity improvements.
Two wells were recently drilled and completed for the Rosa deepwater project, Block 17 offshore Angola, using a Non-Aromatic Oil-Based Mud (NAOBM) weighted with sized calcium carbonate. After installing the Stand-Alone-Screens (SAS) across the production intervals and allowing the wells to cleanup, the Productivity Index (PI) measured on each well was very disappointing. A diagnosis study concluded that the severe productivity impairment on these wells was related to either screen plugging by mud particles while running the screens to bottom in the NAOBM and/or the plugging induced by a mixture of formation sand, mud, and filter cake when draw-down was applied during cleanups.
Based on collaborative laboratory work between the operator and a service company to design a treatment fluid for removing NAOBM filter cake material for water injection wells, a microemulsion spotting fluid was formulated to remediate the damage in the two Rosa wells. The formulation contains a surfactants blend, acetic acid, and brine. The remediation was performed using a Coiled Tubing (CT) equipped with a rotating jet blaster to spot the treatment fluid inside the screen assemblies. Each treatment was allowed to soak. After the placement of the treatment pills on each well, cleanup measurements indicated significant PI improvements close to expected values. Production Logging Tests (PLT) analysis indicates that both wells are producing from almost all screen lengths.
Despite the challenging placement of the treatment fluid in the SAS assembly, the diffusion of the microemulsion with acid allowed break up and removal of blocking solids from the completion screens and filter cake residues from the wellbore walls, allowing full production.
Recovery of Heavy Oil by Thermoelectric Stimulation With Cyclical Injection of a Liquid Solvent, Maracaibo, Venezuela
Authors: Colmenares O Carlos E. , Faría Q Edwin R. , Pizzarelli Sergio G. , Chavier Tomas 
Published: December 2007

ABSTRACT
Concurrently in the West of Venezuela, they have come proposing technicians to improve the recovery of oil weighed through of new processes of thermal stimulation that do not use water steam as agent of heating.
In this work it is considered the injection of hot gasoil the reservoir and exists the thermal stimulation process's physical mathematical foundation, based on the several mechanisms of heat transference as convection and conduction, as a whole with the mechanism of transference of matter for liquid diffusion – liquid, which one, it based in: A Balance of calorific energy, through it is determinated distribution of temperature in the reservoir, and the heat losses to the adjacent formations evaluated by the model of Marx and Langengein, besides the model of production defined by Boberg and Lantz. A Balance of matter ruled by Fick's Law of the diffusion oil-solvent, and the equation of difusitivity that governs the transitory behavior of pressure defined by Everdingen and Hurst.
The stability of the simultaneous solution of the differential equations system is acceptable, due the founded solutions are analytical type.
Operationally the efficiency of the stimulation and the field practice, they will be key points that there will allow the successful execution of the planned process, through the wells completation with sand control filters, sensors of pressure and temperature, besides the thermal equipments of completation that requiere the thermal processes.
To illustrate the field application of the proposed technology, there was selected the reservoir Bachaquero-01.
The results obtained in several running of sensibilities, indicate that it is achieved an increase obtains in the mobility factor of the oil at reservoir conditions of 10,5 times superior than the original one. Giving cycles of production of approximately 10 months, for a stimulated average rate with hot solvent of 850 BN/day versus stimulated average day with steam of 380 BN/day, in an arrangement of conformated wells by two horizontal ones in parallel.
The obtained results indicate that the heat solvent injecting technology to the formation is more favorable alternative than the steam alternate injection process, due it is predicted a major optimized recovery of oil by cycle.
Prediction of Recovery by Spontaneous Imbibition in Gas/Liquid/Rock Systems
Authors: Zhou K. , Zhang W. , Li Y. , Li K. 
Published: December 2007

Abstract
An analytical recovery model derived theoretically based on fluid flow mechanisms was applied to predict the production and the recovery by spontaneous water imbibition in gas-water-rock systems. Capillary pressure and relative permeability were included in this recovery model. It was demonstrated that the model prediction data were very close to the experimental data. When all of the fluid and rock properties are available, the analytical recovery model could also predict the production and recovery satisfactorily. Also studied were the effects of permeability, fluid property, relative permeability, and capillary pressure on the recovery by spontaneous water imbibition into gas-saturated rocks.
Heavy-Oil Recovery Mechanisms During Steam Injection in Naturally Fractured Reservoirs
Authors: Hernandez Mateo J.A. , Trevisan O. V. 
Published: December 2007

Abstract
The present work addresses the contributions, in both individual and combined forms, of the driving mechanisms, namely, solution gas, CO2 generation, steam distillation, capillary imbibition and gravitational drainage, for the recovery of oil and gas during the continuous steamflooding of a naturally fractured reservoir containing heavy oil. The investigation is carried out via numerical simulation of the phenomena in representative pattern cells.
Two numerical models were used to represent the matrix heating process. The first describes the heating of a horizontal cross-section of a matrix block surrounded by a fracture, in which the steam is steadily flooding. The second model is similar to the first, except for the position, which is changed to vertical to incorporate gravity effects.
The studies were performed for a fractured rock saturated with live oil. The rock properties are representative of a real fractured carbonate reservoir, as well as the fluid properties referring to the same field case. Also, the operational conditions used for pressure and temperature were the ones observed in the field, conferring to the work and conclusions, the character of a case study. A strategy was adopted to isolate the effects of each recovery mechanism.
The results show that the main mechanisms of oil recovery for the matrix block during steamflooding are the integrated action of steam distillation and solution gas. The first is the dominant mechanism and it is responsible for the quality improvement of the produced oil. The other mechanisms have a minor contribution to ultimate oil recovery. Such results are vital for the design of a steam injection project in similar oil fields.
Estimation of Rock Properties Applying an Alternative Geostatistical Autocorrelation Tool
Authors: Saccomano A. F. , Savioli G. B. 
Published: December 2007

Abstract
We present an autocorrelation estimator based on the dispersion variance (DVA) as an alternative to the classic semivariogram (CSV) used in Geostatistics to determine spatial distributions of reservoir rock properties. We evaluate DVA behavior with 2-D synthetic and field data sets, and we compare its performance to that of CSV. DVA turns out reliable to estimate spatial autocorrelation and anisotropy in two dimensions, it is more efficient than the classic estimator and it is very smooth and easy to fit with a theoretical model. We also use a set of porosity field measurements and a cross-validation technique to validate an autocorrelation model obtained with DVA. We conclude that DVA is a powerful tool to determine spatial autocorrelation.
Evaluating Resource Plays With Statistical Models
Authors: Hall Russell K. 
Published: December 2007

Abstract
The purpose of this paper is to help you, the evaluating engineer, understand the assumptions and procedures used to estimate probabilistic reserves using numerical simulation. More specifically, we will examine Monte Carlo predictions in resource plays. Throughout this paper, I assume that you are a bright petroleum engineer well versed in the traditional methods of estimating reserves such as decline curve, volumetric, and material balance analysis, but you are relatively unfamiliar with numerical simulations and probabilistic reserve estimates. This paper discusses some of the basic concepts of Monte Carlo modeling with a particular emphasis on the underlying assumptions. The paper offers some definitions to help identify resource plays and the assumptions used to forecast reserves and performance. The techniques of Monte Carlo simulation are then applied to various resource plays to estimate probabilistic reserves.
Screenless Completions as a Viable Through-Tubing Sand Control Completion
Authors: Wise M. R. , Armentor R. J. , Holicek R. A. , Gadiyar B. R. , Bowman M. D. , Jansen R. A. , Krenzke S. N. 
Published: December 2007

Abstract
Screenless sand control completions provide a cost-effective means of completing wells in the Gulf of Mexico by eliminating the need to have a rig on location. To date, six screenless completions have been performed for a major operator in the Gulf of Mexico. Each of the six treatments provided significant cost savings, as well as excellent return on investment for the operator.
Screenless completions are an integrated solution that involve many field-proven technologies such as reservoir characterization, perforating, coiled-tubing intervention, matrix acidizing, resin consolidation, optimized fracturing with proppant flowback control, and fines migration prevention. The proper candidate selection, treatment design, treatment execution, production management and co-ordination of all services are essential to the success of the screenless completion.
In this paper, the common sequence of events for a screenless completion is presented as well as the key technologies involved, from perforating to production. Each of the six case histories are examined in detail and will show that screenless completions provide effective through-tubing sand control in a variety of well conditions. Screenless completions have been proven effective in reservoirs from 10 to 60 ft in thickness, at depths from 4,000 to 10,500-ft true vertical depth, in casings from 3-1/2 to 9-5/8-in. and in oil and gas reservoirs at rates of up to 600 BOPD, 1750 BFPD or 3.5 MMSCFD and in wells deviated as high as 42o. The technique can also be applied in different wellbore configurations to target pay behind casing, and also zones that are located behind both tubing and casing.
Quantitative Analysis of Reaction Rate Retardation in Surfactant-Based Acids
Authors: Nasr-El-Din H. A. , Al-Mohammed A. M. , Al-Aamri A. D. , Al-Fahad M. A. , Chang F. F. 
Published: December 2007

Abstract
Fracture acidizing has been a dominant practice in the industry to enhance well productivity in low permeability carbonate reservoirs. Many acid systems have been developed to improve this stimulation process. The most desirable characteristics for an acid system to be suitable for fracture acidizing are leakoff control and retarded reaction rate. These characteristics are required for deep acid penetration so that when fracture closes, long flow channels are etched on the fracture surfaces. Leakoff control is normally achieved by a pad containing viscosifying or solid bridging agents to plug wormholes generated by acid dissolution. Reaction retardation is normally attempted by lowering the effective diffusivity of hydrogen ion.
It is well known that during an acid fracturing operation the overall reaction rate of hydrochloric acid with limestone is mass transfer limited. Designing the treatment requires knowing the effective diffusivity of the acid fluid system. This parameter does not exist for viscoelastic surfactant gelled acids. Due to its combined leakoff control and retardation capabilities, surfactant-based acids have been used in acid fracturing treatments. As more carbonate reservoirs to be treated by the surfactant-based acid, it is important to obtain the effective diffusivity of H+.
The rotating disk device has been used to investigate the reaction kinetics between a reactive solution and carbonate rocks because the thickness of the boundary layer is uniform throughout the disk surface. This paper discusses the reaction rate data recently generated for surfactant-based acid using a rotating disk apparatus and presents the methodology used to quantitatively extract the effective diffusivity from the measurements.
The results obtained indicated that the viscoelastic surfactant examined (Betaine-type) reduced the dissolution rate of calcite with HCl acid. The surfactant reduced the diffusion coefficient for H+. The effect of temperature on the diffusion coefficient did not follow Arrhenius law.