bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Integrated Approach to Obtain Reliable Permeability Profiles From Logs in a Carbonate Reservoir
Authors: Balossino P. , Pampuri F. , Bruni C. , Ebzhasarova K. 
Published: December 2007

Abstract
Permeability is one of the key petrophysical parameters in reservoir evaluation. Information about permeability is commonly derived from cores and test data, that generally cover only part of the reservoir section, but can also be derived from logs, and then extrapolated to uncored intervals and wells. Two logs provide such information: acoustic and nuclear magnetic resonance. In the Karachaganak Field, an approach based on the acoustic tool was preferred because of the textural characteristics of the vuggy carbonate reservoir.
The approach relies also on the use of image logs to obtain a detailed description of reservoir rocks texture and discriminate between rocks with primary interparticle porosity or very small vugs and lithotypes with multi modal distribution of pores, enlarged and touching vugs.
More than 900 meters of core have been used to validate the permeability log derived from the analysis of Stoneley waves in 25 wells from this field. A correlation between the validated log derived permeability and the textural facies from image logs, has allowed the relationship between permeability variations and the geological framework to be established.
The results have been compared with dynamic data from production logging through the definition of flow units from Stoneley wave-derived permeability and porosity log data and the use of a Stratigraphic Modified Lorenz Plot to identify possible fluid entry points.
Three main permeability trends have been identified: for undolomitised or patchily dolomitised biohermal deposits.for pervasively dolomitised lithologies characterised by lower mean permeability values.for facies characterised by well developed vuggy porosity with enhanced dissolution phenomena (touching vugs, microfracturing etc.)
Besides the presence of very high K values clearly unmatchable by log derived matrix permeability has been highlighted by some well test result. This great difference suggests the presence of fracturing improving matrix characteristics in the volume investigated by the test and the well performances.
The comparison of log derived permeability and well test results has given a new perspective in the interpretation of well test results with respect to the geological framework and a well defined sequence stratigraphic model. The extension of this methodology to new wells could improve the knowledge of the petrophysical characteristics of the reservoir and allow better prediction of reservoir productivity.
A Novel Approach for Drilling and Gravel Packing Horizontal Wells in the Presence of Reactive Shales Using a Solids-Free Synthetic Fluid
Authors: Aragao A. F. L. , Quintero L. , Martins A. L. , Calderon A. , Sa A. , McKellar A. , Gabrysch A. D. 
Published: December 2007

Abstract
Drilling of build-up and horizontal sections in a single step is an attractive design approach aimed at cost reduction and increased performance efficiency in offshore field development, including the reentry of old wells in mature fields – infill drilling.
Most of the large production wells in sandstone reservoirs require sand control due to the poorly consolidated formations. Open-hole gravel pack (OHGP) is still the most popular solution for sand control in offshore deepwater reservoirs. The petroleum industry has developed a number of fluid systems for successful OHGP, including using water-based drill-in fluid (DIF) and gravel carrier fluid, or a synthetic DIF and water-based gravel carrier fluid.
In spite of the industry's effort to develop high performance water-based fluids, the use of synthetic fluids guarantees superior wellbore stability, lubricity, inhibition and drilling performance. Substituting synthetic DIF for water-based gravel carrier fluids is a complex operation, due to the potential for fluid interaction, formation damage and problems of offshore logistics. Another challenge is to provide a reliable sand control technique in the horizontal section with operational safety and minimum formation damage.
This article proposes a new approach that utilizes a synthetic fluid for all steps of the well construction and completion. Using a solids-free invert emulsion synthetic fluid as the carrier medium to pack the gravel (IEGPF) in a conventional alpha-beta wave deposition technique eliminates the need for introduction of a water-based fluid.
The goal was to optimize the synthetic fluid to provide Newtonian behavior (including low-shear rate viscosity), minimize viscosity for a given density, compatibility with the drilling fluid, minimum formation damage, wellbore stability, and gravel wettability.
Experiments were conducted using a large-scale acrylic flow loop to evaluate the performance of the synthetic fluid as a carrier medium in horizontal gravel packing operations. Alpha wave deposition heights and packing qualities were measured for different proppant materials and densities. The resultant fluid formulation has densities ranging from 9.0 to 10.5 ppg, and guarantees proper alpha-beta wave gravel deposition and minimal formation damage.
Neural-Computer Modelling for Reservoir Properties Prediction from Stochastic Seismic Inversion Results
Authors: Gritsenko A. M. 
Published: December 2007

Abstract
This report is dedicated to description of complex reservoir properties prediction method using neural-computing for stochastic seismic inversion results processing. Some case studies are provided.
It is very important for successful reservoir properties prediction using seismic and well log data to take all a priori geological and geophysical data into account correctly. Stochastic seismic inversion results (cubes of pressure and shear velocities, density, impedance) are defined all over the area of survey, fully correspond with seismic wavefield and with a priori geological and geophysical information too. Refined geological model possesses higher vertical resolution (due to reduction of reflections interference) and provide dimensional physical values unlike seismic amplitude. Application of neural-computer technology with integrated prediction stability check mechanism (Jack-Knife), provide reservoir properties prediction quickly and guarantee good quality.
Prediction of Sand Production Rate in Oil and Gas Reservoirs: Importance of Bean-Up Guidelines
Authors: van den Hoek P. J. , Geilikman M. B. 
Published: December 2007

Abstract
Most sand production prediction models to date have the capability to indicate whether initial sand production may take place during the lifetime of a reservoir but they are unable to predict whether the sand production will be ‘problematic’ (excessive erosion, plugging, well sand-up, separator fill, etc.), particularly for systems that have some tolerance towards sand production.
In order to predict whether sand production will be ‘problematic’, it is important to estimate sand volumes / rates as a function of bottom-hole load conditions, drawdown, time, etc. This paper presents a model to predict sand volumes / rates for any type of clastic oil or gas reservoir. This model captures both the geomechanical aspects (rock deformation and failure) and the transport aspects (e.g. role of drawdown and watercut) of the sand production problem. It was extensively validated comparing predicted sand volumes and rates with field observations for a variety of oil and gas fields under various stages of depletion. For all these cases, the model predictions and field observations are in reasonable to good agreement.
The main focus of the current paper is the discussion of bean-up procedures, i.e. the question is addressed as to whether an appropriate bean-up strategy (e.g. small bean-up steps) may reduce the cumulative volume of produced sand.
We show that for wells without sand control, the cumulative amount of sand produced to surface is independent of bean-up procedure. If a large sand production volume is expected in such a well, beaning it up in small steps not only increases the risk of sand-up in itself, but also the risk of repeated sand-ups before the well can finally be produced. By contrast, for wells with sand control, the risk of plugging by fines mobilization is reduced by beaning up in small steps.
Performance Step Change in Kuwait: Drilling Deep-Directional 16inch Hole Build Section Saves Operator 13 Days Rig Time
Authors: Al-Saeedi Mohd. , Sounderajan Mahesh , Al-Enezi Dakhil , Moore Ross , Sharma Maneesh , Eckstrom Darren 
Published: December 2007

Abstract
In 2005, Kuwait Oil Company Exploration Group (KOC) began drilling KM-05, a deep directional exploration well in their West Kra Al maru (KM) field. The well was projected to TD at 16,285 feet MD. In order to intersect the reservoir fractures at the appropriate angle to enhance production potential, the well profile required drilling a 16" directional hole section. The operator considered this a significant challenge to complete the build section with a 16" PDC as it had never been attempted at a depth below 11,500 ft, but they wanted to explore the possibilities.
Similar vertical wells required both roller cone and PDC bits to complete the section. Because roller cone had unacceptably low ROP, the operator determined PDC would offer the best option to efficiently drill the build section, therefore offering the best chance for success. Contingencies allowed for fallback to roller cone because of the PDC’s anticipated high reactive-torque, the ability to meet directional objectives and limited experience drilling deep directional wells in this large hole size.
In the preplanning stage, the operator’s drilling team closely examined new technologies which would allow them to achieve their goals, especially drilling the demanding deep directional section. The entire BHA was engineered to ensure the ROP and directional requirements would be met. A team was organized to aggressively seek technology/best practices that would efficiently deliver well objectives. The team identified that poor tool-face control in limestone would be the primary obstacle. BHA and PDC bit technology was a key focuses in optimizing the 16" directional section. Due to this careful planning and collaboration between the operator and service providers, the directional objective in the 16" hole section of one PDC bit run was achieved. By applying new technology the section was drilled 13 days faster than the directional offsets constructed with roller cones with an estimated savings of US$258,364.
Near-Wellbore Field Water/Oil Relative Permeability Inferred from Production with Increasing Water Cut
Authors: Toth J. , Bodi T. , Szucs P. , Civan F. 
Published: December 2007

Abstract
Oil and water relative permeability data and values of relevant displacement and petrophysical parameters are determined directly at actual in-situ conditions from the oil and water production history of wells. This is accomplished using the convenient interpretation formulae derived for radial unsteady-state two-phase immiscible fluid displacement in the near wellbore formation. The application of the new methodology is demonstrated by processing the typical literature and oil-field production well data. This approach provides a more accurate estimation of the water-oil relative permeability around the production wells than those obtained from the laboratory immiscible flow tests conducted using reservoir core and fluid samples.
Pipelines Slugging and Mitigation: Case Study for Stability and Production Optimization
Authors: Tang Y. , Danielson T. 
Published: December 2007

Abstract
The ConocoPhillips Alpine facility, on the Alaskan North Slope, has experienced slugging problems severe enough to trip the high-high inlet separator level, causing frequent plant shutdowns, and loss of production of 110 kbbl/d. A slugging study was commissioned to investigate the cause of the existing CD-2 pipeline slugging, and possible mitigation procedures, which could alleviate and/or eliminate slugging. Further, the Alpine expansion called for an additional two pipelines (CD-3 and CD-4) to be brought into Alpine inlet separator.
Slugging mechanism and instability analysis were performed. The instability is due to combination of its low flow rate, overly-sized pipeline ID and unfavorable pipeline profile. Flow pattern transition exists at the low spots and liquid accumulates and blocks the flow. In the low pressure system, once gas blows out and system pressure drops, the pipeline inlet gas increases velocity and picks up a new hydrodynamic slug. This slug moves through the road crossing and the pipe rack riser, becoming a long slug which arrives at the separator.
In this study, a slug-tracking model with separator gas/liquid PID controllers was built to reproduce the field SCADA data. A remarkably good match of pressure variations, slugging frequency and liquid level was achieved. A sensitivity study was performed to investigate the effective and practical ways to suppress slugging in the existing CD-1 and CD-2 pipeline. Finally, a combined control was recommended by installing a by-pass control valve at the butterfly valve location. The by-pass inlet control valve before the separator acquires separator liquid level signal, and actuates when the separator liquid level exceeds the set value. This significantly reduces slugging effect on separator performance.
The slugging model and results based on the existing CD-2 pipeline were applied to the future expanded CD-3 and CD-4 pipeline study. Some conclusions were drawn from the slugging behavior.
A New Slim-hole Drill Bit
Authors: Qingyou Liu , Hu Qin 
Published: December 2007

Abstract
With exploration moving into deeper waters, deserts and plateaus, operators and contractors will continue to face complex technical and financial challenges. After various advantages of slim-hole drilling, especially great reduce of cost, are well known, slim-hole drilling has become an important technology and been applied extensively. However, existing three-cone bits and PDC bits can not satisfy the requirements of slim-hole drilling owing to limited structure and short life. So, Southwest Petroleum University (SWPU) has developed a new slim-hole bit, named disc one-cone bit, which combines one-cone bit with disc bit. This new bit will have expansive application prospect in deep drilling, ultradeep drilling and slim-hole drilling because of its less torsion, higher bottom-hole coverage coefficient and longer bearing life.
During the development of new disc one-cone bit, it is very important to ascertain the arrangement and the structural size of disc tooth reasonably according to its rock-breaking mechanism. However, the factors to affect bit rock-breaking efficiency are more and restrict each other. If laboratory experiment is carried out to research a kind of new bit, it will be long period, much cost and only under very simplified conditions. Therefore, computer simulation has important technical and economic value during studying the new bit. This paper discusses rock-breaking mechanism and kinematics simulation researches of disc one-cone bit emphatically.
Predicting Primary Depletion Recovery of a Giant Light-Oil Carbonate Reservoir
Authors: Ayyalasomayajula P. , Kamath J. , Dehghani K. , Fischer D. 
Published: December 2007

Abstract
Predicting primary depletion recovery below the bubble point is a very difficult challenge, especially for carbonate reservoirs. Accurate predictions require sufficient laboratory data to cover the variability in response from the different rock types and laboratory procedures, and proper upscaling of laboratory data to simulation grid scales.
Many recent studies have shown that laboratory-derived gas-oil relative permeability curves often depend on whether the tests were conducted using depletion drive or steady state methods. Though it may seem preferable to use laboratory data from depletion drive experiments for modeling solution gas drive recovery, these tests are complex and there is concern using data from tests conducted at pressure depletion rates much higher than that in the field. More significantly, such tests are expensive and it is not practical to conduct many depletion tests.
We used mercury injection, porosity, permeability, CT scans, and thin section data to classify the giant carbonate reservoir into different rock types. Steady state gas-oil relative permeability tests on plug samples were then conducted to span these rock types, and P10-50-90 curves developed. We also carried out steady state and reservoir condition multi-rate depletion on select whole cores. This data was used to apply a correction to the steady state plug data, and this typically lowered the gas relative permeability curves.
We next conducted numerous upscaling studies using sector models extracted from the full field simulation model. These studies showed that areal upscaling cause the core based critical gas saturation to be increased and the oil relative permeability to be decreased. Vertical upscaling, including the presence of high permeability streaks to represent fractured zones, has not yet shown much impact on the laboratory derived curves.
Finally we developed a template to systematically modify the steady state relative permeability plug data to account for process and scale effects. The new P10-50-90 curves were then used in simulation predictions and results compared to that from the plug based curves.
A Method for Analysis of Pressure Response with a Formation Tester Influenced by Supercharging
Authors: Banerjee R. , Thambynayagam R. K. M. , Spath J. 
Published: December 2007

Abstract
Interpretation of pressure transient tests conducted in a dynamic environment, like drilling, is challenging. One of the difficulties arises due to phenomenon known as supercharging which is caused by mud filtrate invasion. The supercharging results in an increase in sandface pressure which is above the reservoir pressure. Therefore, any calculation of initial pressure and permeability must take into account the supercharging effect.
We present an algorithm that takes into account the supercharging effect in analysis of pressure transient tests acquired with a single or multiple probe formation tester. The solution is obtained by successive integral transforms to the governing equations and to the associated initial and boundary conditions. Thus a complex phenomenon can be modeled, using some valid simplifying assumptions, with sufficient accuracy for the purpose of test design or interpretation. The rationale for the initial and boundary conditions deployed here, which are unique to a supercharged system, is explained in detail.
Process Data for Thermal Gas-Liquid Stimulation of Wells in Zybza-Glubokiy Yar Field
Authors: Stashok Y. I. , Antoniadi D. G. 
Published: December 2007

Abstract
Presented in the paper are the results of pilot-commercial thermal cyclic stimulation of wells performed in various producing intervals of Zybza-Glubokiy Yar field containing heavy (with density of 0.975-0.986 g/cm3), high-viscosity (with kinematic viscosity of 340-580 cSt@50°C) and resinous (with sulfuric acid resins content of up to 72% mass) crude oil. Cyclic steam stimulation of bottom-hole zones and reservoir steaming were the technologies realized to develop the field which is mature now. Two thermal EOR processes had been tested in the field within the period of 2000-2004. One of the said processes involves the use of a gas-liquid heat carrier (gas-steam), the other – a gaseous heat carrier (thermal gas).
Fractured Reservoir Characterisation and Modelling—A Pragmatic Approach
Authors: Wynn Tim 
Published: December 2007

Abstract
Fractured reservoirs are complex and technically challenging to characterize and model. To help reduce the instances of inefficient modelling schemes and inappropriate results we present a process for defining fractured reservoirs workflows optimized for the study objectives, available data and reservoir characteristics. This process contains nested levels of study issues with iterative workflow stages. This is to enable the definition and monitoring of a flexible workflow that considers relevant high level study issues whilst executing the detailed study work. Although this approach may add some administrative complexity, it is suggested that by maintaining focus on all relevant issues at each stage, the final results should be more relevant.
Borehole Fluid Reinvasion Effects on C/O Logs in Openhole Completion
Authors: Kelder O. , Al-Hajari A. A. , Crary S. 
Published: December 2007

Abstract
This paper discusses the borehole fluid reinvasion effects on carbon/oxygen (C/O) saturation results in wells with openhole completions. Although the advantage of C/O technology in a fresh or mixed formation water salinity environment is evident, the main limitation of C/O technology is the relatively shallow depth of investigation ranging from 6" to 10". To overcome this problem, the general recommendation for wet producers has been to acquire data in flowing conditions to minimize reinvasion effects. Two field examples with C/O saturation data in dedicated openhole observation wells which have been shut-in for a longer period of time, have shown that reinvasion remains a major issue and is mainly controlled by the pressure differential between borehole and formation and formation permeability. The degree of pressure overbalance is evaluated with borehole fluid pressure and offset RFT formation pressure data. Flowing data from these observation wells provides a significant different answer and is the recommended solution for observation wells. Alternatively, if only shut-in data can be acquired, another field example shows that shallow reading C/O measurements should be combined with deep reading resistivity readings to evaluate the degree of invasion and assess deep formation saturation.
Jet Pump Performance With Secondary Fluids Differ in Density and Viscosity From Primary Fluid
Authors: Abdou Hesham A.M. , Mikhail S. , Abou-Ellail Mohsen 
Published: December 2007

Abstract
Many researches had been carried out on the water jet pumps during the last few decades, and discussed the effect of changing the pump geometric parameters on its performance. Some other researches investigated pump performance with Two-phase (liquid-gas) and (liquid-solid) flow. In spite of the several researches, which investigated the case of liquid-liquid flow (almost water-water), neither of them did have examined the case in which the secondary flow liquid differs from the power flow liquid in density and viscosity, which is the main objective of this research. The subject is treated experimentally on a special test rig, with the primary jet water and the secondary different types of oils. Performance of the jet pump and static wall pressure inside the mixing chamber, were measured as a function of the mixture Reynolds number. A one-dimensional analysis is also carried out, taking into account the difference of the viscosity and density of the two liquids (each primary and secondary fluids). Discussion of both the experimental and analytical results and comparison between them are made with the main conclusions and recommendation for further researches. Contributions of the present work are:
– Developing an equation giving the performance of the jet pump when the viscosity and density of the primary fluid is different from those of the secondary fluid. – Proposing pressure loss coefficient in the mixing chamber due to turbulent of mixing, as a function of Reynolds number which is calculated based on the density, viscosity and velocity of the mixture in the mixing chamber. – Turbulent mixing for the power and secondary fluids, in the mixing chamber, distribution of axial and radial velocity for both of carrier and carried phases are determined numerically by using the assumption of Two-phase, Two-dimensional flow.