bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Biopolymers for Drilling, Drill-In, Completions, Spacer, and Coil-Tubing Fluids, Part II
Authors: Navarrete R. C. , Seheult J. M. , Coffey M. D. 
Published: December 2007

Abstract
Xanthan gum has been used extensively as a viscosifier in the oil industry for different applications due to its unique rheological properties. In this paper we describe the properties of two previously introduced bio-polymers for use in drilling, drill-in, completions, spacer fluids and coiled tubing applications. The first bio-polymer yields higher viscosities and better temperature stability at lower polymer concentrations than welan and xanthan gum due to its higher molecular weight; this polymer is particularly effective in low salt fluids. The second bio-polymer has improved solubility in high density CaCl2 brines.
Viscosity data over a wide shear rate range in different brine systems is presented comparing the new bio-polymers with xanthan and welan gum at temperatures between 75°F to 330°F. The effect of different types of solids and friction pressure tests in coiled tubing are presented, showing diutan's friction reduction properties.
Paraffin Solvation in the Oilfield
Authors: Barker K. M. , Newberry M. E. , Yin Y. R. 
Published: December 2007

Abstract
Paraffin damage occurs from the reservoir1,2,3,4 to the refinery. This deposition costs the oil companies hundreds of millions of dollars per year in removal costs and much more in lost production. Solvents of many different types are used to try to remove this damage with mixed results. This paper will discuss the various factors involved in the paraffin solvency process: the effect of temperature, the carbon chain length of the n-alkane, the solvent type and application problems. The solvent capacities of commonly used solvents will be compared over a range of temperatures (40ºF to 100ºF) using different chain length n-alkanes or paraffin.
High-Density Invert-Emulsion System with Very Low Solids Content to Drill ERD and HPHT Wells
Authors: Nicora Luigi F. , Pirovano Pierangelo , Blomberg Nils , Taugbøl Knut 
Published: December 2007

Abstract
The paper describes the laboratory development of a new Low Solids Oil Based Mud System (OBMS) with a very high specific gravity (2.04 SG; 17 ppg) for high-temperature and high-pressure applications. The system can also be applicable as solid free oil based mud with very low viscosity at densities up to 1.52 SG, especially suggested for Extended Reach Drilling Wells. The main goals of the new system are:
Optimization of fluid rheology by reduction of the solids contents in the mud. Temperature and system stability at 170 °C.
The objectives have been pursued in the following ways:
– by using a very heavy brine as the internal phase; – by decreasing the oil / brine ratio; – by using a weighting agent with higher density than barite.
In this way, the amount of weighting solids which needs to be added can be drastically reduced to even below 22% v/v for a 2.04 SG mud, compared to 35% v/v as in traditional oil based muds. Also the PV values have been reduced from typically round 60 cP to even below 25 cP.
The addition of new components to the system has lead to the need of a new emulsifier package, which has been optimized with the development of a primary emulsifier and a wetting agent based on innovative chemistries.
Calculating Variation of Fluid Density in Near-Wellbore Environment and Its Application to Density/Porosity Calculations
Authors: Hamouda A. A. , Van De Verg P. E. , Enderlin M. B. 
Published: December 2007

Abstract
Knowledge of fluid density within the pore volume investigated by gamma-gamma density logging tools is necessary to accurately calculate porosity. As porosity increases the effect of fluid density on density porosity estimates increases. The algorithm presented here calculates "true fluid density" as a function of fluid saturations, hydrocarbon composition, temperature and pressure. The algorithm can handle mixtures of oil, gas, and water at different salinities, temperatures, and pressures. More accurate fluid densities are used to improve accuracy of porosities derived from gamma-gamma density measurements.
Because the gamma-gamma density tool responds to some function of "electron density" and not the "true density", the concept of "apparent density" was developed during the 1950's for quantitative interpretation of gamma-gamma density logs. "True density" is related to "electron density" by the ratio (Z/A) of the atomic number (Z) to the atomic weight (A). The ratio (Z/A) varies with the fluid composition, hence the accuracy of calculated densities is influenced by fluid composition. The algorithm developed in this paper follows two paths. In one path, only stock-tank oil density is known and in the other path, the composition of the oil and gas are known. In both paths, water composition (salinity or total dissolved solids) is required.
The paper includes a sensitivity study for the calculation and a field example in which this method is applied to a high porosity oil field where accurate density porosity calculation is hindered by fluid density variation related to water injection, depletion, large temperature anomalies, and drilling mud type. Results from density porosity calculations using "apparent fluid density" are compared with core porosity measurements and with other density log porosity calculations. Density porosity based on "apparent fluid density" matches core results more closely than other calculations.
Studying the Mechanisms of Crude Oil Pour Point and Viscosity Reductions When Developing Chemical Additives with the Use of Advanced Analytical Tools
Authors: Tung Nguyen Phuong , Phong Nguyen Thi Phuong , Long Bui Quang Khanh , Thuc Phung Dinh , Son Tong Canh 
Published: December 2007

Abstract
Laboratory investigations of paraffin deposition process and the remarkable changes in the crystal structure of waxes resulted in the development of several copolymer paraffin crystal modifiers. Their mixtures with surfactants have caused strong viscosity reduction in Various Vietnam high paraffin crudes.
The changes in form and size of paraffin crystals due to co-crystallization between effective pour point-viscosity depressants and crude oil waxes, were investigated and the results were recorded by means of scanning electronic microscopy (SEM). The mechanisms of pour point and viscosity reductions were examined using Infrared and Raman spectroscopes. The advantages and disadvantages of these tools were noted.
Lab Testing and Field Application of a Large-Scale Acetic Acid-Based Treatment in a Newly Developed Carbonate Reservoir
Authors: Nasr-El-Din H. A. , Lynn J. D. , Taylor K. C. 
Published: December 2007

Abstract
A large-scale acetic acid-based stimulation treatment was developed to remove drilling mud filter cake in vertical wells in a newly developed carbonate reservoir. The wellbore stability of this weakly consolidated carbonate formation can easily be reduced by contact with HCl-based acids. Extensive lab testing had indicated that the formation is mechanically weak, becomes brittle upon contact with acids and produces large amounts of fine particles that can cause severe damage. Furthermore, a chloride-free acid formula was required to minimize interference with the pulsed-neutron logs (PNL). A special acid treatment was needed to remove the damage while maintaining the integrity of the formation.
Several tests were conducted in the laboratory to evaluate both regular and emulsified acetic acid and non-acid formulae (mainly EDTA). Initially, two acid formulae were selected for field application. The first used 10 wt% acetic acid in an emulsified form, while the second formula was based on 10 wt% regular acetic acid in combination with additives. Further lab and field-testing indicated that the emulsified form might pose a problem in the presence of fine inter-matrix dolomite particles. Therefore, the treatment performed in the field focused on the use of 10 wt% acetic acid with several waterwetting agents (mainly surfactants and mutual solvent).
The acetic acid treatment was applied in five vertical wells in this field using a coiled tubing unit. Pressure build-up tests after the treatment indicated that the acid was successful in removing the filter cake in all cases. Neither fine particles, nor any type of emulsion was noted in the well flowback samples. However, well productivity after the treatment was found to be a strong function of the lithofacies of the formation (e.g., chalk versus packstone). Wells with high reservoir quality rock (i.e., packstones with a permeability of 20–30 mD), demonstrated excellent pressure response after the treatment. Flowing wellhead pressures were increased significantly. Wells with low reservoir quality showed a moderate increase following the treatment.
E&P Decision Support System for Asset Management - A case study
Authors: Floris F. J. T. , Peersmann M. R. H. E. 
Published: December 2007

Abstract
In recent years the emphasis in the development of new methodologies and tools has been on integration of data and applications. The new challenge lies in using the data generated by these packages to support the decision making process. In a joint industry project NITG-TNO have developed an E&P Decision Support System which helps the E&P asset manager to make more informed decisions regarding the exploration and development of hydrocarbon assets at any given moment in time. In the E&P DSS the data and information from earth modeling, surface engineering and economics are combined into an integrated asset model. It is then possible to place the technical decisions in an economic framework and come to a more transparent and auditable decision making process based on more diverse sources of information.
The asset manager can define scenarios representing the key decision and uncertainties for the asset. From the defined scenarios a scenario tree is built automatically. Within each combination of scenarios, full probabilistic assessment of the decision indicators in the asset model is still possible. The assessment can either be done based on Monte Carlo analysis using fast evaluation models, or by loading data for multiple stochastic realizations generated by external software. The probability distributions for the scenarios are then merged to form the total uncertainty. The options for the key decisions are then evaluated using the full probabilistic assessment. Finally, the sensitivity of the decisions on the input parameters can be analyzed.
The method is demonstrated for a typical development decision. In the case study, decisions must be made for the best type of surface facilities and wells, and whether water injection is preferred. Key uncertainties are the conductivity of a fault, the strength of the aquifer and the oil price. Application of the methodology allows the assessment
Integrated High Technology of Formation Evaluation and Directional Drilling – Key Inputs for Well Placement in a Complex Structural Environment –– A Case Study
Authors: van den Bosch R. H. , Meier L. P. , Rohde U. , Maggs D. 
Published: December 2007

Abstract
A directional sour-gas well achieved its objective, a long horizontal reservoir penetration, after the third attempt. The 431 m penetration is a record in this complex Zechstein Stassfurt carbonate area. Key to the final success was state-ofthe-art information derived from Logging-While-Drilling (LWD) tools, fast development of a new geological model and modern directional drilling techniques.
The 70° slanted well reached top of reservoir on schedule but exited after 40 m. This was unexpected because the original model showed a possibility of 600 m pay. A side-track was drilled with less deviation, but left the target after 30 m. The well would not have been economic with such a short pay interval.
Although LWD-data indicated that porous and gas-bearing reservoir had been encountered it was unclear from standard log information why reservoir thickness was reduced so dramatically. An innovative interpretation came from the use of density-image analysis. Continuous azimuthal density measurements of the wellbore wall allowed structural interpretation similar to a resistivity image sonde. With this approach a normal fault was identified which cuts off the lower part of the reservoir, and its orientation determined. This information formed the basis for a new geologic model.
The challenge for the third hole was to construct and drill a well path with an extended pay zone without exceeding the constraints of the new geologic model. The result was a ‘designer-well-path’ with rapid changes in deviation and azimuth. This had not been attempted before at depths around 3000 m TVD and a hole diameter of 5 7/8". The second sidetrack encountered 431m of reservoir section and the well was successfully completed.
Integrated Uncertainty Assessment for Project Evaluation and Risk Analysis
Authors: Corre B. , Thore P. , de Feraudy V. , Vincent G. 
Published: December 2007

SummaryThe main technical contribution of the study presented in this paper was, by an integrated assessment of uncertainties in geophysics, geology and reservoir engineering, to provide a rational basis with risk analysis for the management of uncertainties in the development of the field and therefore better decision making.The objective of the study was to integrate the uncertainties identified on the Lambda Lower & Upper reservoirs and to quantify their impact on Gross Rock Volume (GRV), Oil Originally in Place (OOIP), recoverable reserves and production profiles.The work was carried out in five main steps:Determination of the distribution of the GRV. Building of a representative cloud of geological full field models (1000 equiprobable models) integrating geophysical, sedimentary and petrophysical uncertainties. Determination of the distribution of OOIP. Sorting and selection of a representative subset of reservoir models to quantify dynamic uncertainties. Modelisation by means of experimental design of the impact of dynamic uncertainties on the representative subset of geological models. Integration of static and dynamic uncertainties to assess statistical distributions of recoverable reserves, production profiles and plateau duration using experimental design technique coupled with multi-variable regression and Monte-Carlo simulations.The following results were obtained:– probability distributions of GRV – probability distributions of OOIP for each reservoir (Lower & Upper) and for each zone of the Upper reservoir – probability distributions of recoverable reserves and production profiles – probability distribution of production plateau duration – probability estimation of different models, associated with quantiles 10, 50 and 90 of the OOIP and Np distributions – measure of the weight of the main uncertainties on the OOIP and reserves.
Improvement and Application of a Mineral-Dispersion System to EOR
Authors: Li Jiyong , Wang Lushan , Yuan Mou , Shao Hongyun , Ji Shujie , Wang Yefei 
Published: December 2007

Abstract
This paper deals with the improvement and application of a new technology to EOR. This technology is applicable to high salinity and severe heterogeneity reservoir, especially to high temperature reservoir.
The essence of this technology is to decrease the water cut of production wells and attain the result of oil production and recovery enhancement by injecting a mineral dispersion system. According to lab test, this colloidal dispersion system is a pseudoplastic fluid with temperature tolerance, shearing resistance, stability and low cost. The lab experiment result shows oil recovery is improved by 8–10%.
The information of lab study and field application relative to this technology was presented at the 1999 SPE International Symposium on Oilfield Chemistry. As to the defect of this technology, lab study was improved. A new oil displacement system, can be mixed by formation water and possesses strong salt resistance, was presented and applied in oilfield.
Pilot area lies in Shengtuo Oilfield Tuo 7 block, including 5 injection wells and 10 corresponding production wells. The viscosity of aimed formation oil was 13–24 mPa.s, the temperature was 80, the salinity of reservoir brine was 15000mg/L and well spacing was 200–500m. The result was observed that production wells were effective after a month injection during the successive injection of this dispersion system for 6 months. Water cut of typical effective well was decreased by 10%. Oil production per day increased 9 ton.
Pilot test shows that this technology has better enlarge commercial application potentiality and economic value. It will be applied in Shengtuo Oilfield on great scale in the future.
Evaluating Asphaltene Inhibitors: Laboratory Tests and Field Studies
Authors: Yen Andrew , Yin Y. Ralph , Asomaning Samuel 
Published: December 2007

Abstract
A producer in Alaska had been experiencing asphaltene deposition problems in one well of a dual string completion, producing from two zones. Laboratory tests performed on both dead and live oil samples identified inhibitor A as the most effective chemical for this well. The field performance of inhibitor A was monitored by a wellhead side stream filter plugging loop. Results from laboratory tests and a field trial are presented. In this paper the correlation between lab data and field performance shows that predictive lab tests can successfully select an asphaltene inhibitor for field applications.
Effect of the Spreading Coefficient on Two-Phase Relative Permeability
Authors: Araujo Y. C. , Araujo M. , Guzmán H. , Moya G. 
Published: December 2007

Abstract
Understanding the dynamics of multiphase flow is essential for optimizing enhanced oil recovery processes. One of the properties that describes the behavior of the fluids in the reservoir is the relative permeability. Despite the development of empirical functional forms and the gathering of a growing body of experimental data, the subject lacks a fundamental basis based on the analysis of the configuration of the fluids at the microscopic scale. In this direction, we have addressed a systematic study of the effect of the spreading coefficient on two-phase relative permeabilities for systems of known wettability.
We have developed a method to evaluate the spreading coefficient for solid/liquid/liquid and solid/liquid/gas systems. Samples used for evaluation of the effect of the spreading coefficient on relative permeability were chosen within a wide range of wettability conditions which include water wet, mixed and oil wet samples. Relative permeability was measured using the dynamic method at reservoir conditions. It is found that oil recovery and relative permeability are higher for spreading than for non-spreading conditions. This information is relevant for gas drainage displacements. We comment on the fluid distribution for positive and negative spreading energy and the effect on residual oil saturation.
Reduction of Fluid Wastes in Gas Production and Storage Operations
Authors: Kozera Greg , Amick Paul , Toothman Rick 
Published: December 2007

Abstract
Wastes are generated during all oilfield and gas-field operations. Produced fluids make up the largest volume of generated waste, and any material used for drilling, treating, or reworking oil and gas wells canbecome part of the waste stream. In some cases, the cost of proper waste disposal can be significant. However, the cost of fines, cleanup, litigation, and a tarnished corporate image associated with improper waste disposal is far greater.
To remain competitive and profitable, companies must control their costs. Workover and fracturing fluids can be reused, or they can be disposed of on-site for minimal cost. However, these fluids must sometimes be shipped to off-site treatment facilities at great expense to the gas-production or storage company. This paper discusses ways of reducing the volume of produced fluids and used fracturing fluids that must be disposed of. We present a case history on (1) reusing fracturing flowback fluids and produced fluids and (2) redesigning fracturing treatments so that they use less fluid to provide the same results.
Drilling Fluids Design and Field Procedures to Meet the Ultra Deepwater Drilling Challenge
Authors: Camero Charles B. 
Published: December 2007

Abstract
This paper focuses on the potential problems facing the operator inultra-deepwater exploration and development drilling. A practical review ispresented of world-wide deepwater drilling fluid experience with examples ofsuccessful technology application. Remote locations, high rig costs andenvironmental constraints - coupled with low fracture gradients, long risersand the associated risks of shallow water flows, mud losses, and gas hydrateformation - present significant challenges to the industry. These potentiallytroublesome drilling conditions are addressed along with the technologies thatare being developed to overcome them.
Critical drilling fluid success factors, in the planning and construction ofan ultra-deepwater well, are discussed. These include the drilling fluidselection process, rheology optimization, downhole hydraulics modeling and gashydrate prediction. The latest techniques in monitoring drilling fluid andwellbore behaviour while drilling a well are also introduced.

Introduction
The definitions of deepwater and ultra-deepwater have tended to vary bothgeographically and chronologically as drilling and completion operations haveadvanced into deeper and deeper waters. Depending on the geographical location, deepwater is variously defined as water depth greater than 400–500 metres andultra-deepwater greater than 1500–1700 metres.
Deep-water operations involve some unique issues in offshore drilling whichcan pose significant additional challenges to the operator. From the drillingfluids perspective, these include:High rig cost and remote locationLarge circulating fluid volumesShallow water flowsLow mud temperature in the riser and pitsLow fracture gradients and narrow mud weight/fracture gradient windowsHole and riser cleaningEquivalent Circulating Density (ECD) control and potential for lostcirculationGas hydrate risk
In addressing these deepwater challenges, environmental and safety issuesare of paramount importance. The following technical issues are frequently alsoof concern:
Well Planning
In deepwater drilling, the selection of a stable drilling fluid, which canbe left in the hole for extended periods, is essential. Inhibitive fluids withlow dilution and consumption rates are of considerable benefit in minimizinglogistics and supply problems. With typical riser volumes from 160 to 500m3 (1,000 to 3,000 bbl) and circulating volumes from 400 to 800m3 (2,500 to 5,000 bbl), any requirement for massive dilutionvolumes must be avoided.
Solids control efficiency is paramount to control low gravity solids (LGS)and minimise dilution volume. Optimal solids control equipment would includefour linear motion shale shakers, ideally preceded by four scalping shakers, plus two high speed centrifuges in parallel. One or two drier shakers forsynthetic or oil base fluid recovery may also be required.