bluuebunny/crossref_metadata_2025_split huggingface dataset:
Differential Pressure Valve Incorporated With the Single-Trip Horizontal Gravel Pack and Selective Stimulation System Improves Sand Control for Extended Reach Wells
Authors: Vilela Alvaro , Hightower Chad , Farias Rodrigo , Neumann Luis , Moura Heleno , Samuel Max , Augusto José 
Published: December 2007

Proposal
Most of the reservoirs located in the Campos Basin, deepwater and ultra-deepwater offshore Brazil are described as unconsolidated sandstone that require sand control on both producers and water injection wells. Horizontal Open Hole Gravel Pack completions are the preferred method of development. Due to the recent discoveries of heavy oil reservoirs, there is a necessity of longer horizontal open hole sections. Low fracture gradients may limit the length of gravel pack in the open hole section because of the pressure increase during the Beta wave proppant deposition phase.
This system allows the gravel pack assembly to be installed and the gravel pack to be pumped during the alpha and beta wave deposition phases without the limitation of high pressures that could fracture the well. The benefits of the Single Trip Horizontal Gravel Pack and Selective Stimulation System (SHGPSS) using the differential valve include the ability to complete longer horizontal intervals, valuable rig-time savings and, efficient mechanical diversion of the stimulation fluid.
This paper outlines the first application of the SHGPSS system using a differential valve to successfully complete a horizontal well in the Campos Basin, offshore Brazil. The need for a differential valve is primarily in horizontal gravel packing operations when normal circulating rates and pressures around the openhole would exceed formation break down pressure. The valve is intended to be easily spaced out and run in the washpipe. At a predetermined differential pressure the valve opens and the return flow path distance around the bottom of the tailpipe is shortened, thus reducing backpressure preventing filter cake damage without slowing the pump rate.
Economic considerations along with completion efficiencies are especially important on deepwater, subsea completions. The utilization of differential valves allows completion of extended-reach open hole wells and/or low fracture gradient reservoirs insuring alpha and beta wave proppant deposition phases yielding efficient completions with improved coverage.
A New Model for Predicting Wormhole Structure and Formation in Acid Stimulation of Carbonates
Authors: Panga Mohan K. R. , Ziauddin Murtaza , Gandikota Ramakrishna , Balakotaiah Vemuri 
Published: December 2007

Abstract
We present a new averaged model for describing wormhole formation in carbonates. The model presented here captures the reaction and transport mechanisms at the pore scale and couples it to the Darcy scale through the use of two concentration variables, structure property correlations and mass transfer and dispersion coefficients. A salient feature of the model is that it captures both the reaction and mass transfer controlled regimes simultaneously, thus enabling the study of a wide range of stimulation fluids. Three important dimensionless parameters are identified in the model, namely, the Thiele modulus (pore scale parameter), Damköhler number (core scale parameter) and the acid capacity number that depends on the fluid/mineral system. Comparison of model predictions to experimental data shows good agreement. A preliminary analysis is presented on the factors that influence wormhole density.
Method for Characterizing Secondary and Tertiary Reactions Using Short Reservoir Cores
Authors: Ziauddin Murtaza , Gillard Matthew , Lecerf Bruno , Frenier Wayne , Archibald Iain , Healey Duncan 
Published: December 2007

Abstract
A new technique for characterizing secondary and tertiary reactions during sandstone matrix stimulation treatments is presented. In the new technique, traditional experiments on short reservoir cores are supplemented with measurement of the effluent element concentrations, batch reactor experiments and geochemical simulations to predict the extent of secondary and tertiary reactions in the reservoir treatment. Alternative methods of characterizing secondary and tertiary reactions, such as those using long core flow tests and laboratory radial flow setups, are reviewed.
The new design technique is used in designing a treatment for a well in the North Sea. Details of how this technique was applied to the treatment design are presented. Post-treatment data from the well showed a successful matrix treatment design. The production from the well increased by 1,400% immediately after the treatment. The 3-month stabilized production gain was 650%.
Hot Oil And Gas Wells Can Be Stimulated Without Acids
Authors: Frenier Wayne , Brady Mark , Al-Harthy Salah , Arangath Roberto , Chan Keng Seng , Flamant Nicolas , Samuel Mathew 
Published: December 2007

Abstract
A revolutionary family of treating fluids designed for the stimulation of critical, hot or exotic oil and gas wells has been developed through application of detailed chemical and engineering studies.1–3 Formulations based on the hydroxethylaminocarboxylic acid family of chelating agents have now been used to successfully increase production of oil and gas from wells in a variety of different formations. Included in the field test matrixes were new and producing wells drilled into carbonates and sandstone formations. The temperatures of the wells treated ranged from 230°F to 370°F (110-187°C) bottom hole static temperature (BHST).
Because these formulations do not contain high concentrations of corrosive mineral or organic acids (the formulations are less acidic than carbonated beverages), very low corrosion rates of the tubulars can be achieved by application of small amounts of special, inexpensive corrosion inhibitors. The mild fluids also are highly retarded so high-temperature carbonates can be stimulated and sensitive sandstone formations are not damaged. The fluids have reduced health, safety, and environmental (HSE) footprints because: (1) they are much less toxic to mammals as well as to aquatic organisms than mineral acids or organic acids such as HCl, HF or formic acid; (2) the fluids are returned to the surface at pH values between 5 and 7 and frequently can be added to normal well production fluids without neutralization; (3) because of much lower corrosion rates for corrosion resistant alloys (CRAs), lowered concentrations of Ni and Cr will be in the well returns compared with conventional acids that also may contain antimony (as a corrosion inhibitor).
Inverse Problems for Treatment of Laboratory Data on Injectivity Impairment
Authors: Bedrikovetsky P. , Marchesin D. , Hime G. , Siqueira A. G. , Serra A. L. , Rodrigues J. R. P. , Marchesin A. , Vinicius M. 
Published: December 2007

Abstract
Severe fall of injectivity in porous rock occurs from the practice in offshore fields of injecting sea water containing organic and mineral inclusions. In general, injection of poor quality water in a well curtails its injectivity. The injectivity loss is assumed to be due to particle retention in the porous rock.
A model for porous rock damage due to retention in deep filtration during injection of water containing solid particles is formulated. The model contains two empirical functions that affect loss of injectivity - filtration coefficient and damage coefficient versus deposited particle concentration.
We show how to solve the inverse problem for determining the first function based on effluent particle concentration measurements in coreflood tests.
The second inverse problem is the determination of the formation damage coefficient from the pressure drop history on a core. These two methods allow determining from laboratory tests the information necessary for prediction of well impairment.
Production Improvement for Horizontal Wells in Sumatra
Authors: Gunarto Ronny , Tran Thanh B. , Widyantoro Barkah , Kritzler Torsten 
Published: December 2007

Abstract
Several horizontal wells have been drilled in different sandstone formations in Sumatra. These formations have a typical permeability of 100 to 500 md, a low bottomhole pressure (BHP) of 450 to 750 psi, and a bottomhole temperature (BHT) of approximately 200°F. The wells are completed with perforated liner. The objective of the horizontal drilling program was to increase oil recovery in low-permeability estuarine reservoirs. Some of the drilled horizontal wells did not perform to expectations and an intensive study was undertaken to identify completion and stimulation opportunities to increase production.
During this study, all aspects of the initial completions were examined and redesigned. The drill-in mud was reformulated to reduce the amount of polymer and increase the use of fine calcium carbonate to decrease lost circulation during drilling and simplify the removal of filter cake during initial completion.Core tests were performed to identify the optimum fluid formulation, which dissolves the remaining filter cake but does not destroy the formation's natural permeability.A new way of removing the filter cake after completing the well was introduced using oxidizer technology.A new, true fluidic oscillator was used to remove near-wellbore skin (in conjunction with an improved acid system) for wells that have been producing for several months or years.
The paper presents several case histories to discuss how completion and stimulation problems were systematically evaluated resulting in increased horizontal well production.
Convective Heat Transfer in Turbulent Flow: Effect of Packer Fluids on Predicting Flowing Well Surface Temperatures
Authors: Vollmer Daniel P. , Fang C. S. , Ortego Anne M. , Lemoine Emile 
Published: December 2007

Abstract
A flowing well continuously looses heat to its surroundings. An accurate prediction for the flowing surface temperature is necessary for production operations. Above optimum surface temperature, chillers are required to cool the gas prior to flowing in pipelines. Too cold of a surface temperature can cause precipitation problems that restrict flow and may require an insulating packer fluid. Economic justification must be decided based on the increased flowing surface temperature that an insulating packer fluid can provide above a conventional one. Therefore, a predictive model was developed that can accurately predict the surface temperature for a flowing well for any Newtonian fluid. The model predicted the flowing well surface temperature (FWST) within 5°F of the measured temperature for the wells studied.
The uniqueness of this model is that a newly derived equation is used to predict the velocity of the packer fluid along the tubing wall caused by free convection for a vertical annulus. Laminar or turbulent flow can be determined from this velocity. In turbulent flow, a friction factor for flat plate or pipe flow must be used to insure accurate predictions. Only when the thickness of the boundary layer equals the midpoint within the annulus can friction factors from pipe flow be used. The model showed how the addition of friction reducers can decrease a well&s flowing surface temperature due to the increase in free convection, i.e., by up to 17°F for one case.
Characterization of Crosslinked Gel Kinetics and Gel Strength Using NMR
Authors: Romero-Zeron Laura , Manalo F. , Kantzas A. 
Published: December 2007

Abstract
Highly crosslinked gels are used in high-permeability reservoirs to achieve good fluid-loss control during well completion and workover operations. Crosslinked gels are also commonly used for shutting off unwanted gas and/or water influx into production wells, and for improving the conformance of the near wellbore injection profile in naturally fractured or in high-permeability reservoirs. In all such applications, the appropriate design of the gel treatment is critical to ensure an efficient gel placement. One important variable of the gel application design is the rheology of the gel system for establishing the crosslinking kinetics and the gel strength after gelation is complete.
Rheology of gels and gelation rates are commonly determined by rheological methods or in a qualitative mode through bottle testing using a well-known gel strength code (i.e., the Sydansk&s Code). The rheological measurements can be both time consuming and expensive, while bottle testing can lead to an inconsistent gel description as a result of the subjective nature of the gel strength code. This paper describes the use of low field nuclear magnetic resonance (NMR0 to monitor gelation rates and to characterize gel strength. This technique provides fast and accurate gel strength characterization and gelation monitoring. Through calibration with polymer concentration, crosslinker concentration, aging of gels, and the effect of brine, it is possible to predict NMR parameters. This then allows for a standardized method for the rheological categorization of gels.
The results of this work present the correlation between the NMR spectra, rheological measurements, and the qualitative codification of gel strength.
Formation Damage Due To Simultaneous Sulfur and Asphaltene Deposition
Authors: Shedid Shedid A. , Zekri Abdulrazag Y. 
Published: December 2007

Abstract
Although many oil reservoirs are producing crude oils of different sulfur and asphaltene contents, deposition problems of sulfur and asphaltene components in porous media were investigated separately. The major objectives of this laboratory study are to investigate the simultaneous deposition of sulfur and asphaltene in porous media. To achieve these objectives, the influences of (1) crude oil flow rate, (2) reservoir rock permeability through which crude oil flows and (3) concentrations of sulfur and asphaltene in the crude oil, on permeability damage of the reservoir rock were experimentally investigated.
Ten dynamic flow experiments were carried-out using different crude oils of different sulfur and asphaltene concentrations and under different flow rates. The crude oil was flooded through different rock permeability of 2.34, 6.23, 16.58, and 21.48 md and under different flow rates of 0.5, 1.0, 2.0, and 3.0 cc/min, respectively. The results indicated that the increase of flow rate increases the formation damage due to simultaneous deposition of sulfur and asphaltene in the reservoir rock. Core samples of lower permeability showed more severe permeability damage than that ones of higher permeability, for the same applied flow rate and the same sulfur and asphaltene content of the crude oil. Furthermore, the increase of asphaltene and/or sulfur content of the crude oil increases the rock damage.
The attained results of this study enlightened the important role of formation damage of carbonate oil reservoirs containing oils of considerable amount of sulfur and asphaltene. In addition, the study provides two empirical correlations capable to predict the permeability damage rate as a function of flow rate, or initial rock permeability. These correlations represent useful tools for semi-analytical and simulation studies.

Introduction and Review
Almost all deep sour gas reservoirs and many oil reservoirs contain elemental sulfur as a dissolved species in virtually. Reduction in pressure and temperature induced sulfur precipitation by a reduction in the solubility of the sulfur in the gas and/or oil phase beyond its thermodynamic saturation point. These changes occur during production operations and can result in sulfur deposition in the reservoir, wellbore and surface facilities. Deposition of elemental sulfur in the near well bore area may significantly reduce the inflow performance of sour-gas wells. In addition, oil reservoirs all over the world suffer of simultaneous sulfur and asphaltene deposition problems in porous media and cause problems in production facilities. Investigation of sulfur deposition in porous media has little attention while asphaltene nature and deposition in porous media has been covered extensively. Furthermore, the investigation of simultaneous sulfur and asphaltene deposition has not been studied in spite of the expected problems of formation damage and facility corrosion.
Fracture Flow Modeling and Visualization
Authors: Augustine Jody R. 
Published: December 2007

Abstract
Many questions relative to fracture flow characteristics remain under investigated. How big does a fracture need to be? How can fines migration potential be alleviated with a fracture? What is the fracture production contribution versus the radial contribution? How much production is directed through out-of-phase perforations? How close can the fracture be to an aquifer?
A three dimensional radial reservoir model was developed to answer these questions. The model integrates the reservoir, wellbore, formation damage, fracture, and the completion hardware.
Historically, researchers have modeled the fracture as one dimensional. By modeling the fracture in 2 and 3 dimensions one can visualize the flow patterns around a fractured well. By analyzing these flow patterns, one can better understand the impacts the fracture is having. Results are presented (both vector and contour plots) that highlight the flows within and around the fracture. Conclusions are presented that quantify fracture effectiveness vs. length and comparisons are made to previous work.
Near-Wellbore Formation Damage Effects On Well Performance - A Comparison Between Underbalanced And Overbalanced Drilling
Authors: Ding Y. , Herzhaft B. , Renard G. 
Published: December 2007

Abstract
Prediction of formation damage that occurs while drilling horizontal wells is a critical point for optimising an oil field development. The economic impact of near wellbore drilling-induced damage and clean up efficiency has led to make significant progress in both experimental and numerical studies in order to assess wellbore flow properties during oil production. As a result, a numerical model has been developed to study the impact of various parameters related to the properties of drilling fluids on the well inflow performance.
This paper describes a numerical approach developed in this model to simulate near wellbore formation damage due to underbalanced (UBD). It is generally expected that UBD will be of benefit from preventing formation damage. However, this benefit can be lost for various reasons. For instance, an overbalanced pressure can be applied on the formation during short periods of time for various operational reasons and it can cause a severe formation damage due to the absence of external cake protection and huge filtrate invasion. Another possible cause of formation damage in UBD is related to spontaneous imbibition which induces water blocking, experienced while drilling tight gas reservoirs.
A methodology for the modelling of possible formation damage during UBD is presented. Cross flow phenomena due to spontaneous imbibition is taken into account to model the filtrate invasion from the well to the porous media as the well is producing.
Impact Assessment and Benthic Recruitment Following Exploration Drilling in the South Caspian Sea
Authors: Tait R. D. , Maxon C. L. , Parr T. D. , Newton F. C. , Hardin J. L. 
Published: December 2007

AbstractPre- and post-drilling environmental studies were conducted around an exploration well drilled in the south Caspian Sea in a water depth of 145 m using both water-based and synthetic-based drilling muds. Eight months after completion of the well, chemical analyses of surface sediment samples for linear alpha olefins, polycyclic aromatic hydrocarbons, saturated hydrocarbons, and selected metals confirmed that the spatial extent of the settled cuttings and mud was limited to an approximate 400-m radius.Cross-sectional photographic images of the seafloor showed significant oxygen demand and presence of sulfidic sediments within 50 m of the well. Coincident benthic samples were examined for total infaunal abundance, species richness, biomass, and distribution of major taxa. The macrofaunal groups Amphipoda, Cumacea and Gastropoda were present in pre-drilling and post-drilling reference samples, but were not present in post-drilling samples collected within 50 m of the well. However, these groups had enhanced abundances, likely in response to moderate organic enrichment at 200 and 400 m distances, where there was no evidence of excessive oxygen demand. Ostracod crustaceans were rare in pre-drilling samples, but were the most abundant post-drilling group in all sediments collected within 400 m of the well site, indicating that elevated organic matter may be a strong macrofaunal attractor. Overall results indicate that changes in sediment chemical concentrations and benthic community composition associated with drilling did not extend significantly beyond 400 m from the well site, and that recolonization of the site was underway, eight months after completion of the well.
A Method to Calculate the Gas-Lift System Efficiency
Authors: Yonghui Liu , Yingchuan Li , Sanwei Liu , Hai Wang , xiaoqi Li 
Published: December 2007

Abstract
The gas-lift system is comprised of gas-lift pumping plant, gas distribution network, gas-lift well, and pipes between gas-lift well and metering station. Each part will affect the others work. Therefore, only when each part works well, the system efficiency would be high. What's more, Rod pump unit has a series of methods to calculate the efficiency, but research on the efficiency of gas-lift system is not available. So it is in trouble in accurately valuing the measures taken to improve the system efficiency. This study also helps engineers find the energy loss and take aimed measures to enhance the efficiency of gas-lift system.
Silica Scale Inhibition for Steam Generation in OTSG Boiler
Authors: Pedenaud Pierre , Goulay Caroline , Pottier Fabien , Garnier Olivier , Gauthier Bernard 
Published: December 2007

Abstract
The production of extra heavy oil or bitumen using the SAGD method (Steam Assisted Gravity Drainage) entails the generation and injection of a large quantity of steam into the reservoir. A similar quantity of hot water is produced together with the oil. Taking into consideration environmental regulations, it is probable that partial or even total recycling of the produced water into steam will be required.
After circulating in the ground production water may contain high concentrations of silica (up to 400 mg/l). Silica removal is very expensive in terms of investment and operating costs. The risk of silica salt deposition in the boiler tubes becomes significant when the silica content in the feed water exceeds 100 mg/l (OTSG boiler supplier specifications). Deposition of silica increases local thermal resistance and can lead to tube failure. The silica removal process is also an environmental issue owing to the production of sludge.
This paper demonstrates that silica scale inhibitors can be used in steam generation in an OTSG boiler. The original laboratory test program and results obtained are presented. Test results were corroborated on an industrial OTSG boiler in operating conditions. Results show that use of silica scale inhibitors instead of silica removal could generate substantial savings in cost.