bluuebunny/crossref_metadata_2025_split huggingface dataset:
Defining the Evolve Gas Rate and Composition from the Crude Oil During its Storage in Tanks
Authors: Braganza E. M. , González E. L. , Rost E. J. , Salleo A. M. 
Published: December 2007

Abstract
Upstream management and technological constant anxiety about production, transportation and storage or the crude oil includes gauging, running, and measuring processes variables (such temperature, API gravity, sediment and water, true boiling point, true vapor pressure) and consequently the evolves vapor rate in order not to removed it to the air as an atmospheric residual product but to be metered accurately to design properly the processes and operations to used it.
Using tools such HySim, crude oil destilation and crude oil viscosity curve, it can be performed a complete oil characterization, defining composition, properties and of course the rate of the evolves gas during its storage in tanks.
Artificial System - Plunger Lift - Time of Fall of The Plunger Under Operative Condition of Well of Petroleum
Authors: Braganza Eduardo , Rost Enrique , Gonzalez Esteban , Salleo Antonino 
Published: December 2007

Abstract
The study consists on analysing the times of fall of the plunger in Plunger Lift Artificial System, the speed to which the fall becomes weightless, the influence of the characteristics of the gas, of the production pipes, of the flows of gas remainders, the plunger weight.
Effect of Acidizing Additives on Formation Permeability During Matrix Treatments
Authors: Frenier Wayne W. , Hill Donald G. 
Published: December 2007

Abstract
Matrix acidizing treatments are performed to increase the permeability of oil and gas formations and to remove various types of damage. Mineral acids, organic acids and chelating agents are used to stimulate carbonate formations and to remove damage. Sandstone formations are usually treated with mineral acids (usually containing some HCl and HF) to remove damaging solids or liquids. Usually, stimulation in sandstone is not achieved. While a reactive fluid must be present to dissolve the damage or to remove part of the formation, numerous "additives" can be used to aid the penetration of the fluid or to perform other important tasks. To enable the reactive fluid to be pumped from the surface through the tubing and into the formation, corrosion inhibitors usually will be required to protect the metal from attack by the fluid itself. Surfactants, solvents, iron control agents, non-emulsifiers and several other types of agents also may be present.
There is increasing concern and some evidence (H. A. Nasr-El-Din, SPE 56712) that the additives adsorb onto the formation (or scale) and may actually be a cause of increased damage. Stimulation of carbonates frequently results in the formation of highly permeable wormholes, so adsorption of the additive may not be as important as damage caused in sandstone formation where damage removal is the primary goal. However, it is very possible that the additives may alter the surface kinetics during limestone acidizing, and thus change the degree of penetration or the efficiency of wormhole formation.
To understand some of the effects of additives on acidizing operations, we have studied some commercial corrosion inhibitors, surfactants and solvents during treatments of simulated sandstone and carbonate formations. The goal of the tests was to determine if the additives are damaging the formations due to adsorption or precipitation or altering the removal of damage or the dissolution mechanisms. Two major techniques were used: linear core flood tests and rotating disk tests. Using these methods, we have determined the effects of selected additives of the effectiveness and kinetics of reaction of HCl and chelating agents on limestone and Berea sandstone.
The effects of the additives depend on their individual chemical structure as well as the fluid and the formation being penetrated. In general, additives that are highly soluble in the fluid had less effect than agents that are insoluble or dispersible in the fluid. We have also shown that some additives can change the break-through volume during carbonate stimulation tests, thus altering the effectiveness of the treatment. In the paper, we will describe tests conducted at various temperatures, including tests run at 350 °F to evaluate hydroxy chelating agent formulations14,15 for use in matrix stimulation of carbonates.
Coreflood Evaluation of In-Situ Gelled Acids
Authors: Taylor K. C. , Nasr-El-Din H. A. 
Published: December 2007

Abstract
Three different commercial formulations (Company A, B and C) of in-situ gelled acids for matrix acid stimulation were compared in carbonate coreflood experiments at a temperature of 100 °F (38 °C) and at acid concentrations of 5 wt% HCl. The in-situ gelled acids contained a polymer, a cross-linker and a breaker in addition to corrosion inhibitors and surfactants. The coreflood experiments were done with small acid volumes (0.3 to 1.0 PV) so that permeability could be measured before acid breakthrough occurred. After acid injection, permeability was measured in both forward and reverse directions to assess the damage induced by the polymers used in these systems.
The concentration of cross-linker in the coreflood effluent samples was measured since precipitation of the cross-linker may lead to formation damage. It was found that in-situ gelled acids reduce permeability of low permeability carbonate reservoir rock. The polymer in these formulations is the primary source of the permeability reduction. Cross-linker was retained in the reservoir cores during injection of in-situ gelled acid.
Detailed viscosity measurements of each in-situ gelled acid were made as a function of equilibrium pH. Only Acid C showed significant in-situ gelation behavior in 5 wt% HCl.
Experience Using Microbubbles-Aphron Drilling Fluid in Mature Reservoirs of Lake Maracaibo
Authors: Ramirez Francisco , Greaves Roberto , Montilva Julio 
Published: December 2007

Abstract
The objective of the paper is to present field results obtained through the evaluation of the Micro-bubble Aphron system, as the drilling fluid in wells VLA-1321, VLA-1325, VLA-1326, VLA-1327, VLA-1329, VLA-1331, VLA-1332, VLA-1334 and VLA-1335 (wells corresponding to Lagomar Integrated Laboratory). This fluid does not require equipment such as compressors, rotary wellhead, equipment to generate and/or inject nitrogen and permits the taking of electric logs conventionally.
During drilling, mud weight varied between 6.8 to 7.9 ppg and very low-pressure zones were run through, with equivalent gradients oscillating between 2.4 ppg and 6.4 ppg, without any problems of loss of circulation.
The micro-bubble fluid presented excellent inhibition values to clay and shale since the Miocene sands of Basal La Rosa and the alternating sand and shale of the Eocene reservoirs were drilled without any problems. Moreover, in well VLA-1321, this lithology was with an exposure time of 25 days, without any instability problem. On the other hand, in wells VLA-1329, VLA-1331, VLA-1332, VLA-1334 and VLA-1335 all the intervals were drilled from 1520’ to 6900’, without using intermediate casing and without great problems, which cut down drilling time to 31.0 days with a saving of 4.7 MMUS$ for the corporation.
It should be pointed out that the fluid has presented rheological properties, which have permitted drilling with excellent hole cleaning.
During the drilling of well VLA-1321, 90’ of samples were taken in the Miocene and 300’ in the Eocene sands with a high percentage of recovery (90.80%) and in well VLA-1326, 411’ of samples were cut with a percentage of recovery of 90.4%.
Additionally, the electric logs were not affected by the micro-buble mud and caliper logs showed a hole of excellent gage.
Judging from the excellent results obtained, the Micro-bubble Aphron system is still being evaluated in the Eocene mature reservoirs of Lake Maracaibo.
Formation Damage Due To Sulfur Deposition in Porous Media
Authors: Shedid Shedid A. , Zekri Abdulrazag Y. 
Published: December 2007

Abstract
The existence of sulfur compounds in crude oils creates many problems of sulfur deposition in the vicinity of wellbore hole, in well completion and/or production equipment, and in producing reservoir rocks.
The major objectives of this experimental study are to investigate the influences of oil flow rate, initial sulfur concentration of crude oil, and reservoir rock permeability on elemental sulfur plugging in carbonate oil reservoirs. To achieve these objectives, actual crude oils were de-asphaltened to eliminate the effect of asphaltene deposition. Ten dynamic flow experiments were conducted using two actual crude oils of 0.78 % and 1.67 % sulfur concentrations. Viscosity of crude oils of different sulfur concentrations was measured under different conditions of temperature. The crude oils were flooded through actual carbonate cores of different permeability in the range of 2.34 to 28.16 millidarcy and under different flow rates of 0.5, 1.0, 1.5, and 2.0 cc/min. In-situ sulfur deposited was measured using Scanning Electron Microscope (SEM) to provide the amount of sulfur deposited along the core samples.
The results indicated that crude oil of higher sulfur concentration has higher viscosity than that one of lower concentration. The deposition of elemental sulfur does not take place at low rate of 0.50 cc/min, starts at 1.0 cc/min and increases as the flow rate increases up to 1.50 and 2.00 cc/min, respectively. In addition, the higher of sulfur concentration of the crude oil increases the deposition of sulfur in carbonate oil reservoirs. The results also showed that permeability of carbonate reservoir rocks has a severe effect on sulfur deposition since carbonate rocks of higher permeability does not experience the problem of elemental sulfur deposition while the problem is more severe for lower permeability rocks. In addition, the depositional rate is accelerated rapidly as the rock permeability decreases.
The obtained results of this study have important interest in identification the most important factors affecting the elemental sulfur precipitation in heterogeneous carbonate oil reservoirs and robust implications in the development of reservoir simulation models.

INTRODUCTION AND REVIEW
Many gas/oil reservoirs suffer of having large amounts of hydrogen sulfide and other sulfur compounds. Sulfur occurs free in the elemental state. Precipitation of elemental sulfur within reservoir rocks can impair oil productivity and thus affects economic feasibility negatively. Sulfur compounds are considered as the most important non-hydrocarbons in crude oils, because of (1) their corrosive nature, (2) their deleterious effects of petroleum products, (3) their attendance to plug porous medium, which may impair formation productivity, (4) their effect on oxidation characteristics, and (5) their disagreeable odor.
High-pH Clay Instability Rating
Authors: Gdanski Rick 
Published: December 2007

Abstract
It is commonly understood that clays have surface hydroxyls that are available for various interactions. The magnitude of the interactions possible because of the natural acidity that clays possess has been previously demonstrated.1 Laboratory experiments using a 3-ft Hassler sleeve and unconsolidated sand/clay-packed columns demonstrated that the pH profile of buffered and unbuffered high-pH fluids can be readily understood as the result of two dominant mechanisms. The first mechanism is neutralization by the natural clay acidity. The second mechanism is the attack of hydroxide on clays and is demonstrated in this paper. The rate of hydroxide attack is temperature, clay, and pH dependent. The rate constants were used to develop a high-pH Clay Instability Rating (CIR) for the clays tested. The impact of CIR on injected-fluid pH profiles was numerically demonstrated with the new model for both linear and radial flow. These two geometries are relevant to leak-off during frac-packs (linear) and for drill-in fluids and matrix treatments (radial).
An Experimental Study for Mechanical Formation Damage
Authors: Soares A. C. , Ferreira F. H. 
Published: December 2007

Abstract
This paper presents a new methodology to evaluate mechanical formation damage due to drilling and oil production. The methodology covers a wider range of stress path adding new insight to fluid flow analysis in porous media. In some reservoirs occur large deformations during oil production due to the increasing of effective stresses. This may cause permanent damage to the reservoir, as the rock structure changes, lowering the permeability and the final oil recovery. A series of rock mechanics tests were carried out, including velocity measurements of P and S waves. These tests showed that plastic behavior is always present and that a yielding region occurs and that it may be represented by the cap model. This methodology allowed a near wellbore evaluation and permeability investigation using stress path concept.
An Experimental Investigation of Fracture Propagation During Water Injection
Authors: Suárez-Rivera Roberto , Stenebråten Jørn , Gadde Phani B. , Sharma Mukul M. 
Published: December 2007

Abstract
Water injection for pressure maintenance, waterflooding or disposal of produced water has become an important issue in the management of produced fluids. However, suspended particles in the injected water cause formation damage and can lead to fracture initiation due to an increase in injection pressure. Injectivity decline in injection or disposal wells can have a large impact on the economic feasibility of water disposal operations. Fracture propagation could potentially result in undesirable environmental and reservoir engineering consequences.
The paper presents results of a study conducted to understand the mechanisms of injectivity decline and fracture propagation during water injection. Large-scale injection tests were conducted under simulated in-situ stress and pore pressure conditions, using rock blocks 27″×27″×32″, representative of a consolidated reservoir rock and laboratory-made produced-water.
Results indicate that the rate of fracture growth is strongly dependent on the type and concentration of particles in the injected fluid. The shape, size and compressibility of the injected particles play an important role. Our results clearly demonstrate that the injectivity remains almost constant once a fracture is initiated. The injected particles are filtered largely near the tip of the fracture where the leakoff is the highest. The depth of penetration of the particles into the matrix appears to be small. Analyses using optical microscopy observations on thin sections show that the filter cake is not a continuous film but rather a region (from 3 to 10 grains deep) where the connected flow paths have been effectively blocked by solid particle deposition. Results from these experiments provide a basis for developing analytical and numerical modeling tools for injectivity decline and fracture propagation in fractured injectors.
Adjustment of Hydraulic Fracture Design in Gas-Condensate Wells
Authors: Indriati Shirley , Wang Xiuli , Economides Michael J. 
Published: December 2007

Abstract
Hydraulic fracturing has been the stimulation/completion method of choice to enhance production for the vast majority of natural gas reservoirs throughout the world. However, the post-treatment behavior of hydraulically fractured gas and gas-condensate reservoirs is complex. This work addresses important aspects of this behavior.
Many natural gas reservoirs exist in the region of retrograde condensation. During production of hydraulically fractured wells, the pressure gradient formed between the reservoir pressure and the flowing bottomhole pressure is likely to result in liquid condensation normal to the fracture face and extending at considerable distance into the reservoir. This leads to an unavoidable reduction of the relative permeability-to-gas, a phenomenon, which was correlated, based on preliminary experimental results that has been obtained. Such a relative permeability reduction depends on the phase behavior of the fluid and the penetration of the liquid condensate into the reservoir. The latter depends on the pressure drawdown imposed on the well. This situation causes a well performance impairment, which behaves as if an apparent damage, tantamount to fracture face damage has affected the fractured wells. Well testing of such wells invariably calculates much shorter apparent lengths than actually placed.
This work proposes a model that predicts the performance of hydraulically fractured gas condensate reservoirs (quantifying the effects of gas permeability reduction), adjusts fracture treatment design, calculates the optimum fracture morphology and presents guidelines for the calculation of the optimum pressure drawdown during production to maximize well performance. While these issues are important in all gas reservoirs they become particularly crucial in higher-permeability cases.
Predicting Brine Mixing Deep Within the Reservoir, and the Impact on Scale Control in Marginal and Deepwater Developments
Authors: Mackay E. J. , Jordan M. M. , Torabi F. 
Published: December 2007

Abstract
Sulphate scale deposition is a common problem in hydrocarbon reservoirs where injection seawater, rich in sulphate, mixes with formation brines, rich in barium, strontium and calcium. The deposition of these scales can cause significant production impairment if it occurs within zones near the production wellbores. To control scale deposition within the near wellbore region of a reservoir, scale squeeze treatments are commonly deployed. In cases where the scale severity is very high, removal of sulphate ions from the injection water is an alternative scale control strategy. Both these methods of mitigation have associated CAPEX (e.g. desulphation plant) and OPEX (e.g. scale squeeze treatments) costs.
Typically, to assess the severity of the problem in new fields, thermodynamic calculations are performed to calculate the mass of scale that will form. Until present there has been little work carried out to identify the location of scale formation within the reservoir. In this paper, field data and flow simulations from three North Sea fields are presented to show that the formation of scale can in fact occur deep within the reservoir, and have negligible negative impact on oil production within the near wellbore region.
Evidence is presented from these North Sea fields that shows the evolution of the brine chemistry as seawater breakthrough occurs and squeeze treatments were applied. The evidence from the produced brine chemistry is linked to flow calculations for these fields to show that in some systems scale is depositing deep within the reservoir, reducing the potential for damage in the near production wellbore region. The extent and impact of the deposition varies throughout the reservoir and can be quantified. The ability to model brine mixing and stripping of the scaling ions before the fluids reach the production wellbore has a very significant impact on the economic assessment of marginal fields and deepwater developments. In such fields, the technical challenge and cost (CAPEX/OPEX) of scale control might make development un-economic. This paper outlines the data requirements and methodology used to allow such an assessment to be made.
Injection-Induced Hydraulic Fracturing in a Naturally Fractured Carbonate Reservoir: A Case Study from Saudi Arabia
Authors: Azeemuddin M. , Ghori S. G. , Saner S. , Khan M. N. 
Published: December 2007

Abstract
A case study involving power water injection in the fractured Arab-D carbonate reservoir in a Saudi Arabian field is discussed. The study was conducted to investigate the role of injection operations in the initiation and propagation of induced fractures and their communication with nearby faults, and to provide a methodology for early detection of the induced fracturing process.
The study involved analysis of data gathered from step-rate, falloff, flowmeter tests, as well as injection rate and pressure data over the history of the injection operation, followed by well test modeling and hydraulic fracture modeling (HFM).
Most of the eight wells studied showed the existence of fractures, corresponding to a rise in injection pressure beyond the fracturing gradient or formation parting pressure (FPP). Skin and injectivity indices obtained from the falloff tests were found to be good indicators of fracturing behavior, based on which most of the studied wells were inferred to communicate with the natural fracture system or super-permeability streaks. HFM showed that induced fractures could reach a half-length of up to 1400 ft, to various heights depending upon the injection rate and permeability. The distance to the nearest fault obtained by superimposition on a 3-D seismic interpretation was found to vary from 500 to 2,000 ft. At high injection rates, fractures were found to grow out of reservoir into underlying tight formation, which could lead to loss of injected water. For controlled fracture height, which may lead to more efficient injection operations, preparation of injection rate guidelines was recommended.
Fractal Formulation of the Porosity and Permeability Relationship Resulting in A Power-Law Flow Units Equation – A Leaky-Tube Model
Authors: Civan Faruk 
Published: December 2007

Abstract
This paper presents a "leaky-tube model" for characterization of flow units and permeability of porous media in terms of the relevant parameters of the interconnected pore space. This is accomplished by representing the flow through porous media using a bundle of leaky-capillary hydraulic tubes/hoses allowing interactions between the hydraulic tubes and the relevant fractal attributes of the interconnected pore structure in real porous media. Civan's power-law flow-units equation is derived by three alternative means. It is demonstrated by comparison to experimental data that this model can accurately represent the permeability vs. porosity data of actual geological porous formations.
This model can be used for convenient means of correlating experimental data and determining the parameters of the flow units of geological porous media by straight-line plots. It can also be used for describing the variation of the flow units in porous media undergoing formation damage and stimulation processes.