bluuebunny/crossref_metadata_2025_split huggingface dataset:
Real-Time and In-Situ Detection of Calcium Carbonate Scale in a West Texas Oilfield
Authors: Smith J. K. , Yuan M. , Lopez T. H. , Means Mitch , Przybylinski John L. 
Published: December 2007

Abstract
A novel technique has been developed to detect the onset and increase of calcium carbonate scale deposition from oilfield production fluids. This method utilizes an attenuated total reflectance (ATR) probe, called the scale sensor, to detect scale formation in-situ. Because this method is based on existing technology and requires little supporting equipment, a simple cost-effective monitoring device could be placed in many locations within a production system. This method could provide a system wide, in-situ, real-time response to calcium carbonate scale formation at its earliest stages.
As a first step towards evaluating the effectiveness of this new technology, the scale sensor was field tested at a west Texas oilfield. The scale sensor was observed to detect the deposition of calcium carbonate under static and flowing conditions in actual produced fluids. In the static tests, crude oil, suspended solids and other endogenous materials did not affect the scale sensor response. Under flowing conditions, like those found in the production flow lines at the west Texas oilfield, scale sensor response was observed to correlate to the chemical injection rate of both the scale inhibitor and dispersant. Based on the results from the scale sensor, the scale inhibitor injection point will be moved to the wellhead shortly.
Scale Prediction and Remediation for Deep Water Fields
Authors: Bezerra Maria C. M. , Rosario Francisca F. , Rocha Anderson A. 
Published: December 2007

Abstract
Completion technologies for horizontal and subsea deep-water wells have been developed to make feasible and increase oil production.
Horizontal and subsea wells in Petrobras are usually located at long distances from production facilities and in deepwater. Scale control can be implemented on these wells via bullhead treatment along a service line or down production lines.
The scale potential for deepwater fields from Campos Basin, Brazil, was assessed. Thermodynamic model predicted a moderate barium and strontium sulfate precipitation in production wells (down hole). More severe precipitation was predicted for the lower temperature of the risers (10 to 20°C). Despite of the predictions based on thermodynamic calculation, experimental work performed considering conditions of temperature, residence time and chemistry of produced water showed that precipitation is expected in reservoir rather than in the risers. Laboratory results agree with field data observation. Data from gamma ray log obtained in recent intervention caused by productivity loss in one well of these fields, showed that scale was formed in the production well (screen, gravel and reservoir) rather than in the flow lines. Chemical dissolution treatment was designed and applied in the wells from this field restoring their productivity.
Scaling Problems in Western Siberia
Authors: Voloshin A. I. , Ragulin V. V. , Tyabayeva N. E. , Diakonov I. I. , Mackay E. J. 
Published: December 2007

Abstract
Yukos Oil Company is the second largest oil production company in Russia, and produces 1.2 million barrels daily, with &gt; 60% of this coming from fields in W. Siberia. Base oil and gas production units are located in the European part of Russia (OAO Samaraneftegaz) and W. Siberia (OAO Yuganskneftegaz and OAO Tomskneft VNK) [1]. This production comes from a variety of fields, and it is common for these fields to produce at significant water cuts. Produced water leads to several production and cleanup problems (since it is also re-injected), one of these being the problem of mineral scale.
The most common scale is calcium carbonate and this is found in both mild and more severe scaling cases. Sulfate deposits are present too in minimal amounts. However, a feature of the W. Siberian reservoirs is that they have many thousands of wells. Therefore, although the technical problem of treating a single well may not be large, the approach and logistics to protect such a large number of wells is a significant challenge.
In this paper we survey the problems of scale in these W. Siberian fields and we outline how Yukos has approached this challenge.
Numerical Modeling of Forchheimer's Equation to Describe Darcy and Non-Darcy Flow in Porous Media
Authors: Belhaj H. A. , Agha K. R. , Nouri A. M. , Butt S. D. , Vaziri H. H. , Islam M. R. 
Published: December 2007

Abstract
This paper adds a new dimension to fluid flow in porous media by replacing Darcy's equation with Forchheimer's equation, which in fact takes in consideration both Darcy and non-Darcy flow behaviors. Mathematical derivation of the diffusivity equation based on the Forchheimer equation has been accomplished for linear flow in both one- and twodimensional cases.
Numerical simulation of the new diffusivity equation has been achieved in both cases of Darcy and non-Darcy (Forchheimer) domains. Both numerical models have been tested and verified giving very reasonable accuracy in describing flow characteristics of Darcy and non-Darcy behaviors. Interestingly, a new dimensionless number "Be" relating β (mainly a function of permeability and porosity), velocity, density and viscosity has been introduced to differentiate between Darcy and non-Darcy flow in porous medium for any types of rock and flowing fluid. This new dimensionless number is far from being considered declaration of turbulence flow in porous medium rather the energy loss is contributed to the nature of both flowing fluid and the porous medium. Theoretically, the break point of non-Darcy behavior from Darcy's has been found at (Be = 0), for practical use it has been determined that non-Darcy flow would start at the point when "Be" become greater than zero.
A practical range of permeability with porosity changing accordingly, fluid velocity, density, viscosity and the non-Darcy coefficient (β) estimated from different types of available correlations in the literature have been examined using the numerical models obtained. In all cases "Be" remains the same at the point of flow behavior change to non-Darcy.
Effect of Volumetric Failure on Sand Production in Oil-Wellbores
Authors: Nouri Alireza , Vaziri Hans , Belhaj Hadi , Islam Rafiqul 
Published: December 2007

Abstract
Sand production is a major problem being faced by operating oil companies for many years. Sand problems are known to have increased production costs considerably. To-date, the roles of shear and tensile failure modes have been well thought out in studying sand production, but the contribution of volumetric failure mechanism in this phenomenon has been ignored. Even though volumetric failure mechanism has been well studied in looking into the phenomenon of land subsidence, but its role in sand production has been neglected in the past. In this paper, the contribution of this mechanism in sand production is addressed.
In numerical studies, a finite difference based program was used. This program captures the fluid/solid interaction with complete rigor. In the experimental part, uniaxial strain condition was applied on some synthetic samples to examine volumetric failure mechanism, while traditional triaxial tests were performed on the same type of samples to learn about shear characteristic of the material. The mechanical parameters obtained from these tests were used in the numerical model that covers all tensile, shear and volumetric failure mechanisms.
By using numerical and experimental means, it was discovered that volumetric failure mode, i.e. pore collapse, has a significant contribution in sanding. Initially at the well face, only shear and tensile failure may take place, but pore collapse can be triggered in a zone very close to the cavity hole. Subsequent to production of shear or tensile failed material from the open face, pore collapse induced disintegrated material may be exposed to cavity face, and potentially massive sanding may take place.
Development of Highly Durable Materials for Drilling Hard and Abrasive Rocks
Authors: Mori Nobuyuki , Moriguchi Hideki , Ikegaya Akihiko , Shioya Yutaka , Ohbi Katsuhiro 
Published: December 2007

Abstract
The paper presents an overview of the development of the material, which is highly durable against wear and chipping, and can increase the lifetime of roller cone bit inserts while drilling hard & abrasive formations. And the paper also details the design and structure of the new materials referred to as Co-composition graded cemented carbide.
The new sintering process achieves the goal of enabling the development of graded composition technology to be applied for insert materials. That is, grading the structure with varying percentages of Cobalt along with the varying Tungsten Carbide (WC) grain size and density not only results in maximum wear resistance of the surface layer, but also in the shock resistively of inward structures. In general, cemented carbide performance depends on the amounts of Cobalt used for material cementation. The new materials and their development process eliminate the normal compromises made between breakage and wear resistance.
The advantages as indicated from the test results on conically shaped inserts showed that the samples achieved over eight times the wear resistance of conventional inserts, while the semi-round design insert achieved over twenty times the wear resistance of conventional materials.
The laboratory and bench test sample were designed in accordance with typical rock bit insert designs, and the actual tests simulated drilling rotation and weight-on-bit normalization. This facilitated an environment as close as possible to an actual drilling environment. The paper further details the testing methodology and results and demonstrates the advantages of the new sintering process and material development over conventional materials in rock bit inserts.
An Innovative Solution for Maximizing Productivity from Perforated Completions
Authors: El-Bermawy Hady , El-Assal Hossam 
Published: December 2007

Abstract
Inadequate flow efficiency in perforated wells in cased-hole completions has been a major concern in the oilfield since the first use of perforating gun systems. Because of this, one of the primary needs in design of a perforated completion is the accurate assessment of the efficiency of the proposed perforation scenario to transmit fluid from the reservoir to the wellbore.
Flow efficiency is affected by such conditions as the number of perforations actually open to flow, degree of damage around the perforations, formation physical properties, in-situ stress conditions influencing the perforator penetration, and extent of formation crushing around the perforation. This complex interaction of perforating geometry, formation characteristics, and perforating environment precludes traditional, global solutions to design or analyze perforated completions in order to achieve optimum productivity results. Each case must be addressed individually, and all possible information must be considered; (e.g., Cores, logs and well test results).
Unfortunately, existing industry models used to design and optimize perforated completions are fairly basic and have relied primarily on section I API Perforator Test Data (i.e. perforator penetration and entrance-hole results obtained from testing the perforating system under surface conditions in concrete targets) for predicting downhole perforation performance. Since these models obviously do not reflect the actual reservoir conditions, field performance often falls short of predicted results because an accurate validation method for optimizing the gun selection process has not been applied.
This paper will review a new quantitative method based on the unique properties of the reservoir that has been developed to optimize perforating design for individual wells. The process is based on experimental data from laboratory tests as well as theoretical (i.e. numerical and analytical) modeling to identify optimal parameters needed for efficiency in perforated completions.
Case Histories showing the successful implementation of the quantitative method will be presented. The results attained from the process design technique will be validated against actual post-perforation, pressure-transient-analysis field data to demonstrate the productivity improvement that is possible through the use of this perforating solution.
Managing Wellbore Instability in Sabah Basin of East Malaysia
Authors: Tan C. P. , Hamid Pauziyah Abdul , Chen X. , Yaakub Mohd Azriyuddin , Willoughby D. R. , Wu B. 
Published: December 2007

Abstract
Drilling experience in Alab and Samarang fields in the Sabah Basin highlighted the issue of wellbore stability in the region. A wide range of drilling problems has been experienced, ranging from tight-hole to overpull and stuck pipe, and a range of drilling fluid designs has been implemented. Subsequently, a wellbore stability study was conducted to address the problems in the planned extended reach Alab wells. The aim is to develop a strategy to maintain mechanical and time-dependent stability of the extended reach wells to ensure well constructions encounter minimum wellbore instability-related problems.
This paper describes the outline of the study and the approach adopted in the development of the strategy. The drilling experience, material properties, typical in-situ stresses and formation pressure in the Sabah Basin are presented and discussed. Based on the gathered drilling experience, caliper and composite logs, and laboratory tests conducted on downhole core materials, dominant time-dependent failure mechanisms were identified. Mud weight stability profiles and examples of critical mud weight contour plots which form part of the strategy for designing optimal drilling fluid program are presented.
Comparisons were made between predicted mud weights determined from the contour plots and mud weights used in the field together with associated drilling experience and hole size in a post-drilling review. The comparison showed a good agreement for a low angle well but inconsistent for two high angle wells. The reasons for the inconsistencies and means of reducing the uncertainties of input data required for wellbore stability study are presented and discussed.
Design of Aerated Mud for Low Pressure Drilling
Authors: Gücüyener I. Hakki 
Published: December 2007

Abstract
This paper presents a multiphase hydrodynamic model for design of the aerated mud hydraulics in vertical and moderately deviated directional wells with an angle of less than 20° from vertical. The model is capable of predicting flow pattern and pressure drop in two phase flow through the drillstring and the annulus. Bubbly, dispersed bubble, slug and churn flow patterns are accounted for down flow in the drillstring. In addition to these flow patterns; the annular flow is included for up flow in the annulus. Effect of cuttings loading on the bottomhole pressure is implemented to the model using the effective density concept. Carrying capacity of aerated mud is evaluated by incorporating two-phase flow properties into a cuttings transport model proposed for conventional drilling mud. Pressure drop across the bit is calculated using an adiabatic and frictionless flow model for homogeneous mixture of air and mud.
In this study, the circulating system is divided into a number of small computational intervals to take into account temperature and pressure dependent properties of aerated mud. Based on the proposed model and computational algorithm, a computer program, UNDRILL~S, was developed to predict flow patterns, circulating pressures, optimum mud and air flow rates, bit hydraulics, and hole cleaning. The program provides a useful tool to help planning a low pressure drilling operation with aerated mud.
An Improved Method for Predicting Pore Pressure of Formation in Offshore
Authors: Yongfeng Guo , Xiaojian Jin 
Published: December 2007

Abstract
The authors supplied an improved method for predicting pore pressure of formation in the offshore oil field. And the result to apply the method is decreasing the density of fluid so that protecting the oil and gas layers and speeded velocity of drill when drilling. The paper gives some formula of mathematics and its procedure of introduction. In past the design of drilling obeyed the rule: the density of drilling fluid would be decided by the value of predicting pore of information, and the value would be decided by the highest pressure of formation pore in the same area. The paper put forward a new rule that the designers can ignore few layers of formation that have high pressure in pore, which are the lessen proportion in the whole open hole because a lot of equipment has been used, which are controlled by computers, and many ways have been mature to control wells when meeting high pressure formation. The effect of application speeds up the velocity of drill, and greatly decrease the density of fluid of drilling. So the application of the rule provides a efficient way to protect the layers of oil and gas underground. The improved method had been accepted in a well in the oilfield in Bohai Bay in 1998, and the well became the well of high production well that products 1000 tons oil in a day.
A Study of Drilling Performance of Energy Balanced Roller Cone Bit
Authors: Chen S. L. , Dahlem J. , Rayburn C. 
Published: December 2007

Abstract
A significant research and development effort plus extensive laboratory and field tests have resulted in a new generation of roller cone bits, namely an energy balanced roller cone bit. An energy balanced roller cone bit incorporates three patented features: (1) balanced cutting structure, (2) optimized tooth orientation, and (3) optimized anti-tracking mechanism. This paper details the principles of these three features and their application to rock bit design. Field performance of energy balanced bits is evaluated by rate of penetration, footage drilled, durability of cutting structure, and reliability of bearing/seal system. Significant performance improvement has been observed in the field.
Horizontal Completions — Improvements in Fluid and Tool Technology Continue to Redefine the Application Envelope
Authors: Ali Syed , Grigsby Tommy , Vitthal Sanjay 
Published: December 2007

Abstract
One technological concept that has been capable of successfully coordinating drilling and completion disciplines is horizontal openhole gravel packing. The synergy required to deliver a reliable high-rate well completion has been evidenced in recent completions, and the successful results have brought about the use of horizontal gravel packing as a mainstay completion technique in deepwater development. The technique has been successfully used in Brazil and has shown the same potential in the upcoming deepwater developments in West Africa. This paper will address how and where the concept was started, how the technology has evolved, and lessons learned that are being applied to increase the application envelope and the reliability of this completion method. The review will cover advances in openhole drilling techniques that eliminate openhole tortuosity, gravel-pack fluids that can reduce rig time and enhance well productivity, and improvements in downhole tools that have or will potentially reduce risk while reducing completion cycle time.
Carbonate Rocks Wettability Changes Induced by Microbial Solution
Authors: Zekri Abdulrazag Y. , Ghannam Mamdouh T. , Almehaideb Reyadh A. 
Published: December 2007

AbstractContact angles are used to measure the wetting behavior of two immiscible fluids on a solid surface. Fluids are considered wettings if their contact angles with surface are less than 90°, and they are considered non-wetting, if their contact angles are greater than 90°. Because of its influence on other petrophysical properties of reservoir rocks, such as relative permeability, capillary pressure, and the residual oil saturation after a flood, wettability and its direct measure, the contact angle, play a significant role in affecting the recovery from both primary and improved recovery processes.In this work, contact angle alteration occurring in microbial enhanced oil recovery processes (MEOR) are quantififed and described, along with a study of the factors that would enhance such contact angle alteration. An experimental method for the measurement of contact angles has been developed in which the contact angle is measured as a function of time. Measurements of contact angle and interfacial tension for four different types of UAE crude oil and four different mineralogical rock composition over a range of microbial concentration, salinity, and temperature are reported. Results showed that contact angles for the studied systems increased with temperature, crude oil sulfur concentration and microbial concentration up to a certain concentration, beyond which the bacteria concentration exhibited no effect on the contact angle. Crude oils containing low asphaltene concentration produced a stable contact angle and oils containing high asphaltene concentration produced surfaces with unstable wettability. The mineralogical composition of limestone rocks had no effect on the contact angle of microbial-oil system.
Correcting for Frictional Pressure Drop in Horizontal Well Inflow Performance Relationships
Authors: Archer R. A. , Agbongiator E. O. 
Published: December 2007

Abstract
This paper presents the development of a correlation that corrects for error in horizontal well productivity calculations made by neglecting frictional pressure drop in the wellbore. Frictional pressure drop within the wellbore is frequently a controlling factor on the performance of long horizontal wells. Frictional pressure drop could be especially significant in wells completed with screens and slotted liners. This pressure loss is neglected in traditional inflow performance (IPR) calculations such as those developed by Joshi, and by Babu and Odeh. This study develops a correction that can be added to these analytical IPR relationships to account for friction. This correction is based on a dimensionless group that combines well and reservoir information. It is easy to evaluate and can be readily used in nodal analysis.
The correction was developed on the basis of over 5,000 finite-difference simulation runs using a simulator with the capability to model wellbore friction. These runs spanned a wide range of well and reservoir parameters. The results are presented in terms of productivity error i.e. the flowrate without friction minus the flowrate when friction is included in the model, divided by the flowrate reported without friction. The study found productivity errors as high as 90% in some cases (usually long wells with small wellbore radius). These errors could lead to poor decisions on field development and production facilities. This paper presents a simple way to improve well productivity predictions without requiring a reservoir simulation model to take account of frictional pressure drops in the wellbore.