bluuebunny/crossref_metadata_2025_split huggingface dataset:
Microbial Stimulation of Lake Maracaibo Oil Wells
Authors: Trebbau G. L. , Nuñez G. J. , Caira R. L. , Molina N. Y. , Entzeroth L. C. , Schneider D. R. 
Published: December 2007

Abstract
More than 300 oil producing wells have been stimulated with microorganisms in Lake Maracaibo, western Venezuela, since 1996. Most of these wells are managed by Tía Juana E.U. (Exploitation Unit), PDVSA E&P, Western Area, and belong to reservoir LGINF-05. This reservoir is constituted by four different unconsolidated Miocene sandy intervals, at an average depth of 3,800 feet, average porosity 30%, average permeability to oil of 600 mD and average oil gravity of 25° API.
The wells were injected at the platform using a self-propelled barge, equipped with a triplex pump, at an average rate of 3 bls/min. and were shut-in for 7 days. Fifty (50) wells stimulated in 1997 were monitored for at least 6 months after the injection. Production data is reported and a correlation was made with different geological and reservoir data, to determine the parameters that mostly influenced the effectiveness of the responce.
The results showed a 78% success, with production increments ranging from 30 additional BOPD, to 400 additional BOPD, with an average of 65 additional barrels of oil produced per day. Correlation results showed a better performance on wells with higher bottom hole pressure, located along the erosional axes formed during the deposition period, thus providing the zone with higher oil saturations. The wells with good responce also showed to have cleaner type of sand with less clay associated to it.
This technology has improved the overall production of the reservoir and it has being proved to be cost effective. It is currently being used as a conventional treatment in the Tia Juana District of Western PDVSA.
Producing GOR Used to Predict Permeability Distribution in a Tight Heterogeneous Reservoir
Authors: Wo S. , Weiss W. W. , Balch R. S. , Roe J. , Kendall R. 
Published: December 2007

Abstract
Production from tight reservoirs can yield flow pressures around the wellbores that are below the bubblepoint. The accumulation of free gas around the wellbores results in a rapid increase in the producing gas-oil ratio (GOR). This paper investigates the sensitivity of depletion-drive GOR to variations in permeability. A public domain, black oil simulator was modified to automatically estimate the permeability from GOR histories. The method presented in this paper is especially useful when interpretable pressure transient tests are not available and can be adapted to existing simulators without changing the core code.
A multi-objective, simultaneous bisection algorithm was developed to provide automatic GOR history match and to predict permeability distributions. Following each iterative simulation run, the permeability-searching intervals for all of the wells were simultaneously reduced by half and the permeability distribution map was updated. The updated searching intervals are uniquely determined because the permeability-GOR correlation is monotonic. Usually a satisfactory match is obtained within 10 simulation runs, which is much more efficient than the gradient or stochastic methods typically used for an automatic history matching procedure.
This method was applied to field data from the South Bisti Gallup Pool. Well communication tests have shown a strong permeability preference for a southwest-northeast orientation in the pool's two tight pay zones. The automatic GOR match was applied to the 14-year depletion history of 52 wells. First, the ratio of Kg/Ko was estimated from the total field GOR match. Then, the local variation of permeability was determined according to the GOR history of the wells. Two perpendicular-oriented permeability distributions were obtained. This new method should be valuable for other low permeability reservoirs.
Effects of Wettability on Dielectric Properties of Porous Media
Authors: Nguyen Buu-Long , Bruining Johannes , Slob Evert C. 
Published: December 2007

Abstract
We present in this paper the results of measurements of the complex dielectric permittivity and electric conductivity in oil-wet and water-wet porous media in a frequency range of 300kHz to 1.5GHZ. The porous media are made from unconsolidated acid-purified quartz sand which originally is water-wet. We used silylating agents to convert the same glass beads to hydrophobic oil-wetted surfaces. This avoided the effects of geometry on the dielectric permittivity that would happen if different glass grains are used.
We have made measurements in a specially designed capillary pressure cell with a built-in transmission line which goes through the porous media. The measured capillary pressure curves serve as an indication of the degree of wettability. From the scattering characteristics of the built-in transmission line, we computed the complex dielectric permittivity of the porous media as function of frequency and water saturation
We observed a significant difference in dielectric permittivity of water-wet and oil-wet porous media. At low water saturation, the dielectric permittivity of oil-wet sand is smaller than that of the water-wet one. At water saturation higher than 0.3, the dielectric permittivity of oil-wet sand becomes much larger that that of the water-wet one.
Our results with results show the same trend observed by some previous researchers, but do not agree very well with dielectric permittivity, calculated using mixing models.
This experimental study illustrates the importance of the wetting state of the porous media in determining their dielectric behavior.
Macroscopic Electrical Anisotropy of Laminated Reservoirs: A Tensor Resistivity Saturation Model
Authors: Schoen J. H. , Mollison R. A. , Georgi D. T. 
Published: December 2007

Abstract
Accurate petrophysical evaluation of deep water turbidites composed of thin bedded sand-shale sequences is crucial in the economic decision to explore, develop, and produce these reservoirs. Traditional laminar shaly sand saturation equations are based on a parallel conductivity model that typically results in significant underestimation of in-place hydrocarbons.
Electrical anisotropy is the macroscopic effect of thinly layered sedimentary formations in which logging tools have insufficient vertical resolution to properly resolve individual beds or laminae. Utilizing anisotropy in the saturation analysis transforms the classic "low resistivity shaly sand problem" into a tensor petrophysical model. The tensor shaly sand saturation model is applied to both simple and complex reservoir types with the following results: Simple laminated sand-shale model: Forward model calculations for the resistivity tensors demonstrate the effect of the model variables on net-to-gross, shale resistivity, sand resistivity, and sand porosity. Sand saturation determination is dominated by the vertical component and shale resistivity is dominated by the horizontal component.Complex anisotropic sand model: Forward modeling using alternating fine-coarse grain size distributions within a sand body demonstrates the effect of pore size changes resulting in capillary-induced water saturation profiles. Tensor components for anisotropic sands are presented as an integral expression for any water saturation distribution. The following response of the Resistivity Index (RI) is noted:RI vs. Sw relationship does not follow an Archie-type power lawRI vs. Sw relationship is different for the parallel and perpendicular laminated resistivity components.
The tensor water saturation equation utilizing electrical anisotropy is demonstrated to be theoretically correct for both the laminar sand-shale reservoirs and complex anisotropic sand reservoirs. The significant advantage of the tensor model is a more accurate water saturation determination that minimizes the errors inherent in traditional parallel conductivity saturation equations.
Characterizing Fluid Saturation Distribution Using Cross-Well Seismic and Well Data: A Geostatistical Study
Authors: Idrobo Eduardo A. , Malallah Adel H. , Datta-Gupta Akhil , Parra Jorge O. 
Published: December 2007

Abstract
One of the goals of reservoir characterization, particularly in mature reservoirs, is to identify unswept regions containing high oil saturation for targeted infill drilling or enhanced recovery. A common approach to the problem is to generate high resolution distribution of reservoir properties such as permeability and porosity and then conduct flow simulations to identify regions of high oil saturation. One possible alternative to flow simulations would be to generate spatial distribution of properties that are related to fluid saturations and then infer fluid saturation distribution through the use of appropriate correlations.
In this paper we present a field application to infer interwell water saturation distribution by combining cross-well seismic and well data. First, we use a non-parametric transformational approach to correlate sonic velocity with resistivity and porosity at the wells. An iterative procedure using alternating conditional expectations (ACE) forms the basis for this calibration. Next, stochastic cosimulation is carried out to generate conditional realizations of resistivity and porosity in the interwell region. In this cosimulation, cross-well seismic velocity is considered as the secondary data while resistivity and porosity are treated as primary data. Finally, water saturation distribution is deduced from the resistivity and porosity distributions through the use of Archie's law.
New HF Acid System Improves Sandstone Matrix Acidizing Success Ratio By 400% Over Conventional Mud Acid System in Niger Delta Basin
Authors: Kume Nicholas , Melsen Robert Van , Erhahon Luckie , Abiodun Afolabi F. 
Published: December 2007

Abstract
Matrix Acidizing has been used as the preferred method of stimulating hydrocarbon producing wells in the Niger Delta Basin. The majority of reservoirs in this area are Sandstone reservoirs. Conventional Mud Acid system has been the main HCl:HF acid mixture used in restoring or improving the productivity of these sands. A combination of rapid spending with clays and silicates, matrix unconsolidation in the near wellbore area and subsequent precipitation of various acid reaction by-products has limited the usefulness of Mud Acid for matrix stimulation treatments in this area.
Various attempted solutions using existing fluoboric acid systems and in-situ HF generated acid mixtures have been tried with mixed results. Using statistical data gathered from over fifty wells stimulated with Mud Acid, a major operating company in Nigeria rated the results of these treatments as less than 20 percent, successful in 1997.
A New HF Acid System has been successfully applied on more than thirty wells over the last two and a half years. Field results using the New HF Acid System demonstrate a remarkable increase in the success ratio (greater than 400%) over conventional Mud Acid formulations. Consistent extension in the time to return to pre-treatment production rates has been observed. An increase of 350% in the incremental hydrocarbon production, using the New HF System, has been recorded over results with Mud Acid on the same drainage points. Notable matrix acidizing cost reduction of 25% and a drastic payback time reduction (500%) based on a $12/bbl crude, has been noticed since the New HF System was introduced in the Niger Delta basin.
Actual candidate selection criteria, job design, technical and economic performances evaluation, and the laboratory analysis of core samples from the sands stimulated with this new HF system, have been included in this paper.
A Comparative Study of Straight/Gelled/Emulsified Hydrochloric Acid Diffusivity Coefficient Using Diaphragm Cell and Rotating Disk
Authors: Conway Michael W. , Asadi Mahmoud , Penny Glenn S. , Chang Frank 
Published: December 2007

Abstract
A successful acid fracturing design depends strongly on the rock-acid reactivity. In carbonate reservoirs where the reaction is mass transfer limited, flow rate and diffusion coefficient determine the overall reaction rate. In an acid fracturing program, the value of the acid diffusivity is often unknown to the engineers. Quantifying diffusivity is a key step for a successful acid fracturing design. Diffusion coefficients of straight acids, gelled acids, and emulsified hydrochloric acids were measured with both the diaphragm cell and the rotating disk device. In addition, the data obtained has been utilized to develop a new correlation to predict the diffusivity coefficient of hydrochloric acid, which accounts for the effect of temperature, acid concentration, and rock type with which the acid reacts.
Gas and Liquid-Phase Relative Permeabilities for Cold Production from Heavy Oil Reservoirs
Authors: Tang Guo-Qing , Firoozabadi Abbas 
Published: December 2007

Abstract
Solution–gas drive in two sets of experiments, one with a mineral oil of some 30,000 cp viscosity (at 24°C), and another with a heavy crude of about 10,000 cp viscosity (at 35°C), have been carefully studied. Both oils show recovery in excess of 10 percent at test termination. Should we have continued the test, the recovery would have been higher.
From pressure and flow rate measurements, gas and oil relative permeabilities are estimated by a simple mathematical expression. The results establish that high recovery in heavy oil reservoirs from cold production is not due to the foamy nature of a heavy crude. The results also establish that there may be recoveries in excess of 13 percent, mainly due to the shape of the gas relative permeability curve.
Effective Steamflood Management Using Heat and Mass Balance Model
Authors: Terez Ivan E. , Barnhardt Carl M. 
Published: December 2007

Abstract
This paper summarizes development of a new heat and mass balance model to apply to dipping reservoirs. Previous methodologies and models developed by the Bakersfield Region Office of Texaco Exploration and Production Inc. were evaluated and tested. A new heat and mass balance model was developed to optimize heat management in mature steamfloods in dipping reservoirs. A 30% "safe" margin above the calculated minimum energy requirement is proposed as a target for the reduction of the steam injection into mature projects. The proposed strategy could result in significant fuel cost savings for such projects. Special cases such as reservoirs with very thick formations, unusual pattern orientation, or a high degree of reservoir permeability anisotropy may require detailed numerical simulation, or special parameter adjustment in the application of the model.
Computer Optimization of Large Gas Reservoirs with Complex Gathering Systems
Authors: Holst Richard , Malowany Larry , Kopjar Randy 
Published: December 2007

Abstract
The modeling of large, shallow gas fields, which produce into complex gathering systems was once a difficult and uneconomical task to perform. The optimization of these systems has now become cost efficient through the use of electronic databases and efficient computer modeling software. This paper focuses on the study of a large Hatton shallow gas field in Southwest Saskatchewan, Canada. The field currently has 800 wells (1367 completions) and a complex surface network with substantial line looping and flow splitting. The reservoir is of low permeability and has three isolated productive zones. In 1998, 32 infills were drilled on the basis of adding incremental reserves. Encouraging results led to a desire to further improve the economic performance by infill drilling an additional 260 wells. A model of the surface network and reservoirs was constructed and used to plan facilities modifications upon the tie-in of the 1999 infill wells and to prepare long term forecasts. The study showed that numerical modeling of large, shallow gas properties can be cost effective.
Evaluating the Transport of Solids Generated by Shale Instabilities in ERW Drilling – Part II: Case Studies
Authors: Martins A. L. , Santana M. L. , Gonçalves C. J. C. , Gaspari E. , Campos W. , Perez J. C. L. V. 
Published: December 2007

Abstract
The problem of cuttings transport in the inclined sections of ERW's is a major concern in the oilwell drilling industry. This paper presents a field on the possibility of keeping drilling in the presence of a controlled instability process. The study is supported by an innovative time dependent mathematical model, along with a computer implementation of it, which is based on the well-known two-layer model approach. An innovative feature of this model consists in the consideration of the added amount of solids that comes from the crumbling and cave-in of the wellbore. The model results, coupled with an exponential approach, enables to optimize circulation of different lengths ERWs. The paper represents a further step on the integrated analysis of cuttings transport and wellbore stability problems, aiming cost reduction and safe well design.
A Pragmatic Approach to Managing Wellbore Instability in Extended Reach Wells in the Goodwyn Field
Authors: Tan C. P. , Willoughby D. R. 
Published: December 2007

Abstract
Drilling experience with numerous inclined wells highlighted the issue of wellbore stability in the Goodwyn Field, North West Shelf of Australia. Subsequently, a study, with an emphasis on the longest horizontal well drilled in Australia at that time, GWA 12, was conducted. The aim of the study was to develop strategies to control shale instability during the drilling of future wells in the field. Following the drilling of a number of extended reach wells, a post-drilling review of the wells, including GWA 12, was conducted and the additional information used to revise the critical mud weight contour plots for future application. An assessment was also made of the drilling fluid design for long term stability of GWA 13ST2 based on pore pressure changes induced by key drilling fluid-shale interaction mechanisms.
This paper describes the required information, methods used to carry out the wellbore stability analyses and utilisation of the results from the two studies to develop the recommendations for the mud weight programs of the field. The approach adopted in the studies utilises the relevant field observations in vertical and inclined wells to develop strategies to control instability through theoretical wellbore stability analyses. Reference mud weights, based on drilling experience and wellbore condition in the wells, were used to calibrate the predicted critical mud weights. In addition, design charts of pore pressure change due to mud pressure penetration and chemical potential mechanisms were used to assess the drilling fluid chemistry for long term wellbore stability.
Gas Hydrate Formation and Dissociation with Thermodynamic and Kinetic Inhibitors
Authors: Makogon Yuri F. , Makogon Taras Y. , Holditch Stephen A. 
Published: December 2007

Abstract
This work presents new data on the kinetics of gas hydrate formation and dissociation for methane with water and seawater, with thermodynamic and kinetic inhibitors in static and in dynamic conditions, and several results of the morphology study of gas hydrate crystals. Effective porosity of methane hydrate ranges between 0 - 80%. Hydrate formation and dissociation can proceed simultaneously with transit of hydrate formers from one crystal to the other, both in bulk water and in gas phase with dissolving or sublimation of some crystals and formation of others. At the same time there can be recrystallization of hydrates with change of structure, porosity, and density of crystals.
Metastable state of the system in static conditions may last many hours even at large supercooling with no hydrates. Induction time of hydrate formation depends on structure of water, water and gas composition, pressure and supercooling, cooling rate, dynamic or static conditions. Presence of thermodynamic or kinetic inhibitors may decrease induction time, decrease supercooling and increase rate of hydrate formation. We have tested four different kinetic inhibitors with fresh water and seawater with concentration of kinetic inhibitors from 0.5 mass % up to 5 mass %. Fresh water and seawater formed hydrates in presence of all kinetic inhibitors, which we tested.
Content of natural gas dissolved in water in presence of hydrate at the interface is significantly lower than in water, which is in direct contact with gas. As a consequence, the formation of gas hydrate deposits in nature may proceed more rapidly than the formation of free gas deposits.
A Novel Method to Winterize Traditional Pour Point Depressants
Authors: Manka John S. , Magyar James S. , Smith Robert P. 
Published: December 2007

Abstract
Crude oil producers have used pour point depressants and wax deposition inhibitors with great success for several decades. Unfortunately, undiluted pour point depressants and wax deposition inhibitors are waxy materials that are often solids at the ambient production site temperature. To be able to pump these wax control products down hole, they usually need to be drastically diluted with solvent. The solvent adds to the raw material expense, handling, transportation and storage costs and increases the health, fire and safety hazards of using these heavily diluted products.
This paper introduces an innovative technology that eliminates the need for extensive dilution while improving the low temperature handleability of the pour point depressant or wax deposition inhibitor. This technology does not involve a new type or family of additives. The new process is simply a novel way to deliver traditional performance chemicals down hole.
A patented process1 is used to emulsify waxy pour point depressants and other high melting performance chemicals to yield a product that pumps easily and flows at temperatures as low as −55°F while still delivering a relatively concentrated package. Based on laboratory testing, the emulsified additives retain their original field performance.
Gas-Liquid Metering Using Pressure-Pulse Technology
Authors: Gudmundsson J. S. , Celius H. K. 
Published: December 2007

Abstract
The Pressure-Pulse multiphase metering method is described. The combined effects of water-hammer and speed of sound in gas-liquid mixtures are used to measure the mass flow rate. Through continuity the mass flow rate at the wellhead is the same as the mass flow rate downhole and at standard conditions, making the Pressure-Pulse method suitable for routine production testing and allocation measurements. The method is highly repeatable. Offshore testing of the water-hammer effect and the speed of sound in gas-liquid mixtures, demonstrates the feasibility of the Pressure-Pulse method in petroleum production operations.
Field Evaluations of Different Multiphase Flow Measurement Systems
Authors: Mohamed P. G. , Al-Saif K. H. , Mohamed A. 
Published: December 2007

Abstract
Two multiphase flow meters (MPFM) working on different operating principles were tested (one at a time) in series with a conventional well testing system (test separators and a test tank) at an operating field in Kuwait. The first MPFM utilizes a fluid conditioner to separate the gas, which is measured by a vortex shedding flow meter. Liquid flow is measured with coriolis meter and the water cut is obtained by cyclic sampling and measurement of electrical characteristics and differential pressure between top and bottom of the sample chamber. The other MPFM employs a positive displacement meter, a venturimeter and microwave sensor to measure the flow of total fluid, gas and water respectively. A bypass loop with a vortex shedding flowmeter enables measurement of a larger range of gas flow rate. A number of wells covering a wide range of production rate (377 to 6661 bpd), gas oil ratio (207 to 945) and water cut (0 - 65%) were tested. A turbine flow meter was also included in the tests to measure liquid production rate. Comparative results are presented. Aspects related to foaming and increased back pressure due to MPFMs on well production are discussed along with other key information.