bluuebunny/crossref_metadata_2025_split huggingface dataset:
Acid Sensitive Aluminosilicates: Dissolution Kinetics and Fluid Selection for Matrix Stimulation Treatments
Authors: Hartman R. L. , Lecerf B. , Frenier W. , Ziauddin M. , Fogler H. S. 
Published: December 2007

Abstract
Dissolution kinetics of analcime (a zeolite), chlorite and illite (layered aluminosilicates) are determined in hydrochloric and mixtures of hydrochloric and hydrofluoric acid systems. Dissolution kinetics were determined from batch reactor experiments in the temperature range of 25 to 100 °C. The reaction progress was monitored by analysis of Al, Si, Fe, Mg, and Na concentrations in the aqueous phase. The reactivity of these aluminosilicates was compared with that of kaolinite under similar experimental conditions.
Models for the reaction of the aluminosilicates with each acid will be presented. The reaction kinetics incorporated into a geochemical simulator predicts matrix stimulation results for formations containing these minerals. Guidelines for design of matrix stimulation treatments for acid sensitive formations will be presented.
Carbonate Matrix Acidizing Fluids at High Temperatures: Acetic Acid, Chelating Agents or Long-Chained Carboxylic Acids?
Authors: Huang Tianping , McElfresh Paul M. , Gabrysch Allen D. 
Published: December 2007

Abstract
Matrix acidizing of carbonate formations has been carried out for many years using HCl acid in various strengths. However, in some high temperature applications, HCl does not produce acceptable stimulation results due to lack of penetration or surface reactions. Organic acids, like formic acid and acetic acid, were introduced to offer a slower reacting a thus deeper stimulating acid. These "retarded" acids also had short- comings due to solubility limitations of acetate or formate salts. In recent years, several alternatives have been developed, including aminocarboxylic acids and long-chained carboxylic acids. These long-chained carboxylic acids offer low corrosion rates, good dissolving power at high temperature, high biodegradability,and easier and safer to handle.
Many experimental and theoretical studies in carbonate acidizing have confirmed the existence of an optimal acid injection rate at which major wormholes are formed, and the benefit from stimulation is maximized. This optimal rate depends on reservoir conditions, rock properties and chemical reaction rate of the acid being used. In our previous study, a theoretical model showed that under the same conditions, the optimal injection rate for weaker acids is lower than that for stronger acids. This paper presents a comparison of the efficiency of stimulation in carbonate acidizing of three different kinds of high temperature stimulation fluids. A chelating agent, EDTA, acetic acid, and a mixture of long-chained carboxylic acids were used to acidize carbonate cores at high temperatures. The effectiveness of the process and the optimal injection rate were studied by measuring the acid volume needed to propagate wormholes through 4-inch cores. The dendritic nature of the acid penetration was also determined by making castings of the wormhole structures after acidizing. The experimental results from this study showed that the optimal injection rate of long-chained carboxylic acids is lower than that for acetic acid and the EDTA. This increase in efficiency then determines that a deeper and more efficient stimulation per gallon of acid mixture used is obtained with the long-chained carboxylic acids.
Field Validation of a Carbonate Matrix Acidizing Model: A Case Study of Seawater Injection Wells in Saudi Arabia
Authors: Thomas R. L. , Nasr-El-Din H. A. 
Published: December 2007

Abstract
Although hydrochloric acid has been used for more than 60 years to matrix acidize carbonate reservoirs, the process is still as much art as science. Historically, design engineers have used a "rule-of-thumb" based on field experience to quantify the design parameters for a candidate well. However, each well is different and this "generic" approach for treatment design can result in under- or over-treating. This paper is directed at matrix acidizing of vertical water injection wells completed in a heterogeneous carbonate reservoir (Arab-D) in Saudi Arabia with focus on field validation of a commercial matrix acidizing design simulator. The "validation" process allows the production engineer to "calibrate" the simulator for his specific field, and use it with confidence to improve treatment designs.
In this field study three matrix-acidized injection wells were used for validation of the carbonate acidizing model. The wells were completed in 150 to 200 feet openhole intervals in a reservoir composed of a variety of limestone - dolomite mixtures. Treatments were performed using hydrochloric acid along with particulate diverter stages, which was bullheaded down casing. The post-treatment model validation process consisted of simulation of the actual treatment using various values of "acidizing efficiency" to yield an acceptable match with the final skin. Subsequently, a comparison of the simulated and actual surface treating pressure, and the prepost-treatment wellhead pressure during seawater injection was made. A detailed description of the validation process and the supporting well data are presented.
A good match of predicted surface pressure and actual wellhead pressure obtained from the treating report adds credibility to the simulator. Normally, the difference in actual and simulated pressure was less than 10%. Pressure data indicate that the benzoic acid/rock salt diverter systems were inefficient. The simulator indicates diverter inefficiency causes the high permeability zones to become "thief zones" resulting in non-uniform acid distribution. In all cases the pressure dropped 25 to 50% within ten minutes following injection of acid into the formation. An internal acidizing efficiency factor was increased to allow the predicted skin of the simulator to approximate the actual skin determined from a falloff test. It was discovered that the optimum efficiency factor was a function of the amount of dolomite in the reservoir. Guidelines for the determination of the efficiency factor based upon mineralogy are presented along with an explanation for this and other observations.
On the Rheological Mechanisms Governing Drill-in Fluid Invasion into Reservoir Rocks
Authors: Martins A. L. , Massarani G. , Waldmann A. T. A. , Costa F. G. 
Published: December 2007

Abstract
This article deals with the comprehension of the rheological mechanisms relevant to drill in fluid invasion through reservoir rocks, aiming the design of a solids free non-invasive fluid. The strategy to develop this concept was to flow different kinds of fluids (Newtonian and different polymeric solutions) through consolidated inert porous media. Experimental results indicate that Newtonian fluids, CMC solutions and low concentration XC and PHPA solutions were properly fit by Darcy law. On the other hand, the highly concentrated solution presented relevant deviations. Such deviations tended to increase with the increase of deformation rate (or differential pressure). This fact indicates that there is a need for applying viscoelastic constitutive models to account for the extra friction losses. An expression for resistive force estimation as function of the first normal stress difference correlated properly with the experimental results.
Improving Performance of Low Density Drill in Fluids with Hollow Glass Spheres
Authors: Chen Guoqiang , Burnett David 
Published: December 2007

Abstract
The increasing number of open hole horizontal well completions in low-pressure and depleted reservoirs requires the use of non-damaging low-density drill-in fluids (LDDIF) to avoid formation damage and realize optimum well productivity. To address this need we have formulated new LDDIFs with specific density lower than 1.0 sg (8.34 ppg) specifically to drill and complete low pressure and depleted reservoirs with minimum formation damage and maximum production. These materials exhibit typical drilling fluid characteristics, allowing the well to be safely drilled to required well depth, but also perform as completion fluids, lessening formation damage to a greater extent than fluids with greater density and higher wellbore pressures.
The new LDDIF incorporates low-density hollow glass spheres (HGS) to allow near-balanced drilling in low pressure and depleted reservoirs. The LDDIF uses potassium chloride (KCl) brine as the base fluid because of its low density and inhibition of clay hydration and employs low concentrations of the HGS so that fluid rheology is not altered.
We have conducted extensive laboratory testing to compare performance of the HGS LDDIF with that of conventional horizontal well DIFs. Experiments consisted of permeability regain tests on unconsolidated sands with sand control screens. Test variables included temperature, concentration of drill solids, cleanup technique and HGS concentration. Test results have shown that the new fluids are up to 50% easier to remove from the wellbore formation faces and provide higher productivity than higher density fluids. Such results indicate that higher well productivity from wells with less impairment would offset any added costs of HGS additives in the fluids.
Successful Application of Mud Cake Pop-Off Technique in Horizontal Well Bore Cleanup - Case Histories
Authors: Abiodun Afolabi , Nwabueze Vincent , Opusunju Austa , Sibigem Francis 
Published: December 2007

Abstract
Early return on investment, high productivity indexes, late water/gas breakthrough and tight reservoir oil recovery are among the benefits of horizontal well over vertical well. Many operators have perfected and standardized the drilling and completion procedures of horizontal wells, however, the results of the different drain hole cleanup approaches have been inconsistent (especially where oil or pseudo-oil base mud were used during drain hole drilling).
Conventionally, the removal of the damage caused by drilling mud filter cakes and filtrate is achieved with the aid of acid cleanup, Nitrogen lifting or brine wash. While the results of enzymes or acid cleanup in water based mud filter cakes removals are encouraging, the results in oil or pseudo-oil base filter cakes have been considerably inconsistent.
This paper details the Pop-Off approach to the removal of drilling fluid damage and filter cake in horizontal wells with high heterogeneous permeability profiles. The paper described how the application of filter cake flow initiation pressure combined with treated drill-in fluid base fluid and reservoir's fluid solvent and dispersion power have delivered superior and consistent value on investment. The results from the application of this method showed remarkably low drawdowns and high productivity indexes. Field data resulting from this method demonstrates a history of 100% technical and economical success with more than 150% improvement in recovery and projected productivity index. In addition, there has been consistent improvement in sustenance of well productivity with wells treated with Pop-Off method over wells treated with previously applied conventional methods of filter cake removal.
An Alternative Drill-in Fluid System for Low-Pressure Reservoirs
Authors: Quintero Lirio , Jones Tom A. 
Published: December 2007

Abstract
The majority of wells drilled with water-based fluid systems in pressure-depleted reservoirs are subjected to high overbalance pressures due to drilling fluid densities greater than the density of water. These overbalanced conditions are directly related to loss of circulation, stuck pipe and especially, formation damage due to solids and fluid invasion. Specialized technologies, such as under-balanced drilling with ultra-low density foams or aerated fluids, have been used to resolve most of the aforementioned problems1, 2 High application costs, however, have made these alternative systems almost prohibitive in many mature fields.
With appropriate surfactant and polymer selection and the implementation of unique bridging methods, drill-in fluids may be designed with highly thixotropic behavior, minimal filtration properties, excellent crude-oil compatibilities and high return permeability. This paper presents the development of a low-density water-based drill-in fluid stabilized by a specially selected polymer-surfactant complex and bridging materials designed specifically for low pressured sandstone and carbonate reservoirs.
Drilling, Producing and Treating Complex Wells. A Collection of New Technologies to Optimise the Overal Well Process
Authors: Charlez Ph. A. 
Published: December 2007

Abstract
This paper highlights the concept of complex well through various advanced or emerging technologies involved during the well life process. The current state of the art states that drilling technology is more mature than production and treatment technologies.
The well life process is divided into four phases: pre-project, conception, realisation and exploitation. Each phase is studied in terms of productivity on one side, cost on the other. New concepts such as limitation of well oversizing or anticipation of field maturity are regarded through actual examples. It is finally concluded that this technical revolution can only be a success if culture and human organisation evolve at the same rythm. Well being the most transverse object of the E&P chain, it represents a fantastic opportunity for all disciplines to work in close collaboration within integrated teams and not anymore through conventional isolated petroleum professions.
Representative Laboratory Testing Procedures for Selecting Drilling Fluids
Authors: Watson R. B. , Nelson A. C. 
Published: December 2007

Abstract
Due to an increased understanding of the effects of formation damage, it has become commonplace to test the damage potential of drilling fluids with reservoir core, prior to drilling. This preventive approach has shown to be more effective than neglecting pre-drilling laboratory testing. However, the current approaches are lacking in many areas.
Through research, as part of an E.U. funded project, well productivity 2002, a standard procedure for testing the formation damage of drilling fluids has been developed. The research provides a number of explanations as to why previous "round robin" studies display large variations in results between laboratories. False ranking of drilling fluids and formations were subsequently produced due to the varied procedures currently used. Explanations and solutions are specified in order to allow future testing to be repeatable in any laboratory and most importantly, representative of the wellbore situation.
The result of the research is a cost-effective procedure, which can be scaled to the reservoir after testing. Although the laboratory equipment used is not greatly different from that used in many laboratories, there are procedural changes. These changes allow accurate testing and ranking of formation damage potential. The results detail representative fluid application, basic fluid ranking procedures and a more advanced investigative procedure, which determines type and extent of damage expected from the formation and fluids. Additions to these procedures allow for the testing of solid and chemical completions, to provide a strong tool for well planning.
The research was part of Work Package 1 of the E.U. project "Well Productivity 2002" and the recommended methods are already being used in a number of reservoir studies. It is intended to present future work using these methods, in parallel with well data.
Beyond Acidizing and Fracturing
Authors: Tambini Mauro 
Published: December 2007

Abstract
The oil industry is still focusing on the optimization of hydrocarbon production with the minimum cost possible in complete HSE respect.
Nowadays a continuous flow of innovative ideas generates worldwide new technological frontiers. As a result, we witness remarkable applications of new well solutions and techniques. In this scenario we would like to give an overview of the possible answers to the technological needs and actions towards Stimulation Treatments and Formation Damage Removal.
The main issues to investigate are: if the mature and worldwide applied techniques of Acidizing and Fracturing are still adequate to the new well geometry scenarioif the "novel" technologies are well known and cost effectiveif innovative ideas on formation stimulation and damage removal are to be better investigated and implemented.
Mitigation of Naturally Occurring Oil Seeps and Methane at the Olinda Ranch Residential Development, Brea-Olinda Oil Field
Authors: St. Peters Kay 
Published: December 2007

Abstract
Mass grading of a hillside residential project within the Brea-Olinda oil field in southern California provided an opportunity to mitigate the naturally occurring oil and gas seeps at the site during the grading process. Multiple strategies, such as subsurface collection and venting systems, were used to reduce the potential for oil seeps to form in graded lots, and to prevent hazardous accumulations of methane gas in homes. Monitoring of the systems will be conducted by an environmental consultant in accordance with maintenance manuals prepared for the project.
Urban Development of Oil Fields in the LA Basin Area, 1983 to 2001
Authors: Gamache M. T. , Frost P. L. 
Published: December 2007

Abstract
Since 1983, construction-site projects in the Los Angeles Basin area have been reviewed under the Construction-Site Plan Review Program of the Department of Conservation’s Division of Oil, Gas, and Geothermal Resources. Under its auspices and before issuing building permits, local permitting agencies review and implement the division’s pre-construction, oil-well recommendations and requirements.
Oil-well proximity to proposed structures statistics derived from division data suggest there are three types of urbanized oil fields in the Los Angeles Basin area. This information may prove valuable to anyone involved in oilfield land development.
Rose Field: A McLure Shale, Monterey Formation Development Story
Authors: Ganong Barbara L. , Hansen Chris , Connolly Paul , Barree Bob 
Published: December 2007

Abstract
Following the development of successful McLure production in the North Shafter Field, the newly designated Rose Field was explored and developed. With an analogous model six miles to the south, well performance seemed predictable in the Rose Field. However, results suggested differences requiring explanation. The core data, tiltmeters and post-frac analysis indicated the limiting factor was reservoir quality, suggesting that project viability required significant cost pruning.
This case study discusses the revelations and processes implemented in discovering the new pool and its development as a horizontal, hydraulically-fractured McLure Shale play. Producing oil ranging from 22 to 26 degrees API through a low permeability, over-pressured zone presented its own share of engineering challenges from drilling to completion and through operation. In this first paper, the primary discussion revolves around identifying the analogous zone north of the North Shafter Field, in what has become the Rose Field and understanding the differences between the new field and its nearest analog, allowing for improved engineering practice.
Boon or Bane? A Survey of the First 10 Years of Modern Multilateral Wells
Authors: Oberkircher Jim , Smith Ray , Thackwray Ian 
Published: December 2007

Abstract
Since their introduction in 1993 the modern multilateral systems and their applications have developed rapidly. System capabilities and features have adapted to a myriad of operating conditions and demands placed upon them. But in many cases the development of equipment has outstripped the industry's ability or willingness to adapt it. There are two main reasons:
Reliability: Despite high technical and economic success rates in a wide range of applications the common perception of multilateral technology is that it is "risky". However industry-wide statistics show that Multilateral Technology (MLT) is not the high-risk technology it is often perceived to be.
Value: Even the Operators most experienced in multilateral technology struggle at times with identifying and quantifying the true value and return on investment of these wells. It is understandable there is some uncertainty when assessing the true economics of this type of well. One issue with this is the inability to perform effective modeling and prediction of well performance and lateral contribution. A second is the expense to provide equipment to actually monitor the production from additional laterals.
Tangible (or Intangible) Rewards vs. Perceived Risks. This paper will examine these arguments using industry data and information and by examining actual multilateral case histories from the first 10 years of multilateral developments. This paper will also take a look at the future of this technology and discuss what may happen in the next 10 years.
Application of Large Thermal Sector Models in a Field Performance Optimization Study of a Mature, Heavy Oil Field
Authors: Márquez L. , Hurtado J. , Wang J. , Iwere F. , Gomez E. , Hudgens P. , Ponce E. , Bashbush J. L. , Gurpinar O. , Aly A. 
Published: December 2007

Abstract
The results of a reservoir performance evaluation of a giant mature heavy oil field are presented here. This field began production in 1927. By 2002, cumulative production had surpassed half a billion barrels of low-gravity oil from Miocene sandstone formations produced under natural depletion, water and gas injection, and cyclic steam injection from more than 400 wells. As a result, several interdependent flow models including black-oil full-field, thermal single-well, and thermal large-sector models were built for field analysis and optimization. The long and complex production history, as well as the various recovery mechanisms, presented a number of challenges in constructing and calibrating the models to past historical performance.
The optimization work was done in the following three stages. First, a coarse-grid black-oil model was constructed to study the field performance prior to steam injection, following the successful geological modeling phase of this project (presented in Márquez et al., 20011). The second stage involved single-well and sector-model thermal simulation analysis. The thermal models were used to match the field historical pressure and production data over the natural depletion, water injection and cyclic steam injection periods. Third, we investigated the field performance under different development scenarios. Optimization results with the singlewell thermal models were incorporated into the sector models, which were used for processing runs to examine infill drilling; recompletion of active wells; waterflooding; huff ‘n’ puff steam injection; steam drive; and horizontal well drilling.
The project resulted in the identification of more than 100 infill or recompletion candidates, and an estimated three million barrels of oil (MMBO) of additional recovery during the first 2 years of this project. As a result there were significant performance improvements and more are anticipated through the implementation of the field development strategies recommended here. The modeling approach led to significant time savings and provided an effective reservoir management tool for future field development.