bluuebunny/crossref_metadata_2025_split huggingface dataset:
Problems Associated With the Operation of Offshore Sea Water Injection Systems
Authors: Flammang Robert F. , Medcalfe T.M. , Culligan Paul T. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
This paper was prepared for the SPE-European Spring Meeting 1976 of the Society of Petroleum Engineers of AIME, held in Amsterdam, The Netherlands, April 8–9, 1976. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal, provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Introduction

OFFSHORE SEA WATER INJECTION SYSTEMS
Offshore sea water injection systems are rapidly increasing in number. It wasn't many years ago that you could number the existing systems on the fingers of your hands.
Offshore sea water injection systems have all the problems common to onshore systems plus a few problems inherent to their offshore location.
Offshore sea water injection systems must be more dependable than onshore systems because of their remote locations and the difficulty of getting men and material on site. This is particularly true during winter operations in such locations as the North Sea. Supplies and spare parts cannot be received shortly after a phone call as is common with onshore operations.
The high expense of offshore operations coupled with the high capital cost of the platform make it imperative that plans be platform make it imperative that plans be well thought out and complete before embarking on an offshore sea water injection project. project.

DESIGN CONSIDERATIONS IN OFFSHORE SEA WATER INJECTION SYSTEMS
There are a number of constraints imposed upon the design engineer when he switches from onshore to offshore sea water injection systems. These are imposed by high platform costs and by high offshore operating costs. The design engineer must: Minimize weight on platform Minimize space utilized on platform Minimize maintenance offshore Minimize supply offshore Minimize manpower offshore

THE DESIGN BASIS
The design basis is set by following the principle that the water quality must be only that which enables injection for the life of the project at a minimum injection pressure and minimum cost. pressure and minimum cost.
Metson Attic Steam Drive
Authors: Rehkopf B.L. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
This paper was prepared for the Improved Oil Recovery Symposium of the Society of Petroleum Engineers of AIME, to be held in Tulsa, Okla., March 22–24, 1976. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
The Metson Pool of the Midway-Sunset Field in California is a steeply dipping viscous oil reservoir. Steam type thermal recovery operations have been in progress in the pool for ten years. pool for ten years. Cyclic steam stimulation techniques have been utilized to take advantage of both natural and induced productive mechanisms. These cyclic operations have proven effective in all but the updip sections of the formation.
An attic steam injection program was initiated as a pilot project in October, 1970 and has since been expanded to include 18 steam injection patterns across the updip edge of the formation. The short term objective of this program is to economically displace and recover oil at the top of the structure by conventional steam flood mechanisms. The long term objective is to accelerate recoveries from downdip cyclic operations.
The excellent results of this project indicate that the attic steam drive process should be applicable to any massive, steeply-dipping, heavy oil reservoir. The process will be of particular value along updip reservoir edges where cyclic steam injection has become uneconomic.

HISTORY
The Metson Lease is located approximately 27 miles southwest of Bakersfield, California at the southernmost tip of the Mid-way-Sunset Field in Section 24, T11N/R23W, SBB and M, Kern County, California (see Figure 1). The discovery well was completed in 1953 and was followed by the drilling of 31 additional wells through 1968. Extensive drilling was not continued at this time in the life of the lease due to relatively poor economics and low production rates prior to the evolution of thermal stimulation.
The advent of cyclic steam stimulation in 1965 was a boon to production from this property as wells that normally would only property as wells that normally would only produce 10–20 BOPD without steam, would produce 10–20 BOPD without steam, would now produce in the 100 + BOPD range.
Comparisons of Polymers Used in Workover and Completion Fluids
Authors: Lipton Daniel , Burnett David B. 
Published: December 2007

Abstract
This paper describes a study of water-soluble polymers used in workover and completion fluids, including xanthan gum and two new biopolymers. Comparisons were made of polymer solution rheology in brines, shear stability, viscosity at elevated temperatures, and formation-damaging characteristics. A mathematical model was used to show the role fluid rheology has in well-stimulation techniques. The paper includes the results of field treatments with xanthan gum fracturing systems.

Introduction
Numerous studies have shown that proper attention to workover and completion fluid design is repaid many times over by the dividends of increased well productivity. The advent of "clean" low-solids fluids has been brought about by industry's usage of water-soluble polymers to provide viscosity and solids-suspending ability.
Today's oil prices are allowing the use of more expensive yet more effective workover and completion fluids. We have made a comparative study in the field of water-soluble polymers to determine if biopolymer systems could be considered as alternates to currently accepted designs and practices. This study presents an examination of polymer properties and attempts to relate polymer properties and attempts to relate polymer performance to workover and completion performance to workover and completion fluid design.
The following eight water-soluble polymers were chosen for the comparative polymers were chosen for the comparative study due to their common use in the field or possible application:
Guar Carboxymethylcellulose Xanthan gum PS-7 (Experimental) Hydroxypropylguar Hydroxyethylcellulose Polyacrylamide (partially hydrolyzed) ZANFLO (Kelco biopolymer)
Application of Neural Networks for Improved Gravel-Pack Design
Authors: Faga A. T. , Oyeneyin B. M. 
Published: December 2007

Abstract
Use of effective sand-control practices has sustained oil and gas production from wells that would otherwise have shut-in. However, a large number of gravel-packs fail early after installation necessitating expensive well intervention. A basic prerequisite to effective control among others is a good gravel-pack design and execution1. This includes obtaining a representative sample of the formation sand, analysing the grain-size distribution and selecting an optimum gravel-size. Gravel-size selection is carried out in relation to formation grain-size to control formation sand movement and using the optimum screen slot to retain the gravel. However, core samples are generally not taken in all wells in a field. In the absence of specific well information, it has become accepted practice to use offset-well data for designs creating a potential for ineffective gravel-packs. This paper discusses the application of neural networks to obtain real-time, well specific, grain-size distributions and how this input could be used to improve gravel-pack design and achieve optimum sand control. Neural networks have been applied with success to predict grain-size distributions from well logs. The availability of a continuous grain-size profile across an entire reservoir has facilitated comparison between the size of gravel on existing gravel-packs where offset-well information was used and gravel-size obtained based on neural network estimates. The results indicate significant differences. They further demonstrate that the use of estimates of grain-size distribution across the entire reservoir rather than offset well grain-size can lead to improved gravel pack performance and thus significant savings on life-cycle costs.
Field Test of a Novel Drill-In Fluid Clean-Up Technique
Authors: Burton R. C. , Hodge R. M. , Wattie Ian , Tomkinson Jane 
Published: December 2007

Abstract
Horizontal wells continue to be used in applications requiring high production rates. However, many of these wells suffer from low productivity due to ineffective mud cake removal. This problem is most commonly encountered in horizontal wells fitted with sand control screens.
In a recent field test, a new technique was applied to remove the drill-in fluid filter cake in a North Sea horizontal well fitted with a sand control screen. This technique uses an EDTA/ascorbic acid/enzyme mixture to effectively remove calcium carbonate and polymer filter cake. The treating fluid was formulated to provide a controlled, long-term degradation of the filtercake, while minimizing corrosion of the screen, production tubing, and packer. The new technique shows some improvement over previous completion practice which resulted in wells with low productivity associated with flow back of calcium carbonate drill-in fluid solids through prepacked sand control screens.
This paper will review productivity and completion impairment analysis of previous wells, laboratory testing of the new EDTA clean-up system and conclude with field implementation and post-job analysis of the clean-up technique.
Optimizing Production in Fields with Multiple Formation Damage Mechanisms
Authors: Tague James R. 
Published: December 2007

Abstract
Optimizing production in fields prone to formation damage often requires considerable time and effort. In fields with multiple formation damage mechanisms, the challenge becomes even greater. Standard industry practices often fail to remove all of the formation damage or prevent it from occurring for a variety of reasons including improper identification of the damage mechanism and selection of inappropriate remedial or prevention techniques. In this environment, only a well planned, comprehensive approach designed to cover all aspects of formation damage will succeed in optimizing production.
Colloid Chemistry of In-Situ Clay-Induced Formation Damage
Authors: Tchistiakov Alexei Andreevich 
Published: December 2007

Abstract
Clay induced formation damage in the vicinity of injection and disposal wells is a worldwide problem in the petroleum industry. The physical chemistry and dynamics of the internal clay transport are still poorly understood issues. In this paper we give a comprehensive theoretical overview over effect of the main physico-chemical factors on the stability and transport of clay particles in sandstone porous media and their influence on the rock permeability. First we give a short "reservoir oriented" introduction to the DLVO theory (Derjagin – Landau – Verwey – Overbeek) which makes it possible to quantify the interactions between clay particles and the rock matrix in terms of electrostatic repulsive and Van der Waals attractive forces. Secondly, we explain the mechanisms of clay surface charge formation. Than we describe the structure of the electrical double layer around clays. Subsequently we consider in detail the influence of hydrodynamic and physico-chemical factors on coagulation –dispersion of clay particles in sandstone. In particular we describe the effect of interstitial velocity, chemical composition, pH, and temperature of the permeating fluid, as well as clay mineralogy, micromorphology, and composition of the exchangeable cations. Furthermore we describe the effect of structural forces on clay stability, which are often ignored in the petroleum literature. Finally we consider the influence of rock microstructure and clay micromorphology on sandstone water sensitivity.
Improvements in High-Rate Water Packing with Surface-Modification Agent
Authors: Ali Syed , Vitthal Sanjay , Weaver Jim 
Published: December 2007

Abstract
High-permeability wells are often completed with high-rate water packing techniques that bypass production-limiting, nearwellbore damage, which can occur during drilling and completion operations. High-rate water pack completions frequently perform poorly in both hydrocarbon productivity and production endurance. In many cases, this poor performance has been linked to pack permeability damage caused by the fines invading the pack and migrating toward the wellbore.
Designing high-rate water pack completions requires careful planning to ensure that the gravel is sized to physically screen out the naturally occurring mobile fines, preventing them from invading the gravel pack. Normally, the generalized sizing criteria first reported 25 years ago are still the standard for high-rate water-pack completion designs. Under certain conditions, these guidelines result in a pack that effectively prevents fines invasion but is limited in conductivity, which reduces well profitability.
Reports indicate that a new surface-modification agent (SMA) applied to proppant is effectively controlling coal fines in coalbed methane fracture-stimulation treatments. This agent works by making the surface of the proppant tacky, causing the proppant pack to be stable to cyclic production changes and causing fines to stick to the formation-pack interface, thus preventing them from invading the pack. These stimulation treatments yielded long-term fines stabilization and significantly increased fracture conductivity.
Recently reported laboratory studies of this SMA indicated that similar fines stabilization in high-rate water-pack completions could also be expected. Additionally, it was discovered that the gravel size required to prevent fines invasion in the pack could be dramatically increased to allow greatly improved conductivity without jeopardizing pack integrity or fines invasion.
This paper presents results of the first high-rate water-pack field testing with this new surface-modification agent with gravel sized one and two times larger than the gravel normally used. Laboratory studies to support this work are also presented, including development of new gravel sizing criteria and the impact of hydrofluoric acid (HF) stimulation treatments if fines invasion eventually does occur.
Detecting Additional Hydrocarbons and Evaluating Formation Damage By Enhancing Old Electrical Logs
Authors: Allen Rob L. 
Published: December 2007

Abstract
Oil and gas accumulations were frequently underestimated or undetected when old electrical logs were used. Computer enhancements of old logs have revealed additional hydrocarbons. Numerous zones were successfully located and produced. Ratios of enhanced curves frequently distinguish tight zones, formation damage, hydrocarbons in place, and moveable oil. Damaged zones have been detected and treated to help production.
Near Wellbore Cleanup in Openhole Horizontal Sand Control Completions: Laboratory Experiments
Authors: Brady M. E. , Ali S. A. , Price-Smith C. , Sehgal G. , Hill D. , Parlar M. 
Published: December 2007

Abstract
Wellbore cleanup in horizontal, openhole sand control completions has been the subject of many publications in recent years. Although a large majority of horizontal wells have been standalone screen completions, an increasing number of these wells are being gravel-packed, particularly in deep water, sub sea environment where reliability of the sandface completion is of utmost importance due to prohibitively high cost of intervention. In such wells, increased significance of "doing it right the first time" further necessitates an emphasized consideration of wellbore displacement and filter cake removal treatments. Although a substantial amount of laboratory data on filter cake cleanup are available in the literature, a great majority of these data are relevant to non-gravel-pack completions.
In field practice to date, cake cleanup in GP completions has almost exclusively been done after gravel packing and typically involved coiled tubing. Although several new methods have recently been proposed and successfully practiced in several applications (e.g., inclusion of cake-breaking chemicals into gravel-pack carrier fluids, post-GP breaker treatments immediately after GP w/o requiring coiled tubing), laboratory data directly applicable to such conditions have been scarce.
In this paper, we present laboratory data relevant to gravel-packed completions. We show that the cake removal time scales in the presence of a gravel-pack are longer compared to absence of a gravel-pack on top of the filter cake. The degree of delay is shown to depend primarily on carrier fluid viscosity and whether the breakers are included in the carrier fluid or introduced as a post-GP treatment. It is further shown that including breakers in brine during water packing must be exercised with extreme caution since even slow-reacting breakers can yield premature screenout due to increased losses should external cake erosion occur.
System for the Hydraulics Analysis of Underbalanced Drilling Projects in Offshore and Onshore Scenarios
Authors: Silva Valter , Shayegi Sara , Nakagawa Edson Y. 
Published: December 2007

Abstract
As a reservoir is depleted, both pressure and production rates decline and lost circulation or differential sticking problems can hamper or prevent drilling operations undertaken to enhance production, such as in-fill drilling, drilling horizontal sections through the reservoir or re-entry operations. Underbalanced drilling is a workable method to drill in such depleted or low-pressure fields. Another benefit of underbalanced drilling is that it can potentially prevent or reduce near wellbore permeability damage (skin), thus enhancing production, reducing stimulation requirements and delaying water or gas break-through time due to the lower pressure drop required for the same flow rates.
In order to design and realize a successful underbalanced drilling project many important elements must be considered conjointly. This is especially important for UBD operations offshore from floating vessels, where the number of critical issues increases significantly. An integrated analysis method has been developed which incorporates these elements, including multiphase flow calculations, gas and liquid injection rate optimization, hydrostatic gradient and frictional pressure loss calculations, cuttings transport, reservoir fluid influx (gas, oil, or water), and operational procedures such as tripping and liquid unloading.
Software has been developed based on this method so that an engineer can quickly and easily consider and compare the use of different light-weight fluids or to see the effect when varying diverse parameters. The software can model gasified liquid, foam, mist air or non-Newtonian single phase mud for upward or downward vertical and inclined flow as well as horizontal flow. A cuttings transport model resulting from full-scale experimental work is incorporated to delineate the limits of adequate hole cleaning and the effect of operational procedures can be studied.
Different field cases have been modeled with the software and the results have compared well with actual data. A gasified fluid example is included to illustrate the potential of the software.
Borehole seismic: supplying answers to fractured reservoir questions
Authors: Evans R. , Gaucher E. , Randall N. , Vuillermoz C. , Rodriguez S. , Michaud G. 
Published: December 2007

Abstract
The importance of being able to characterise fractured reservoirs in oil field development is widely accepted. This paper discusses two recently developed borehole seismic techniques which have proved to be useful in achieving this. In particular, case histories gathered from recent experience illustrate how these well seismic techniques can help to determine main fracture orientations and densities. One technique involves monitoring microseismic activity taking place in active fractures at the reservoir, the other an analysis of the birefringence effects that apply to shear wave energy when passing through the fracture medium.
Microseismicity occurs in association with geological stress changes. In the case of hydrocarbon reservoirs it can arise naturally from straightforward production, as the result of injection, or hydraulic fracturing operations. In two major surveys in the North Sea the SST500 VSP tool has been used by CGG to successfully record microseismic activity.
In late 1997, CGG participated in a major Reservoir Characterisation Project (RCP VII) designed to monitor the effects of prolonged CO2 injection over the Vacuum field, New Mexico. Seismic data was acquired using conventional surface seismic techniques together with downhole-recorded data, simultaneously recorded using an SST500 tool deployed in a well within the RCP area. One Pwave plus two orthogonal Swave sources shooting into a downhole array comprising of 12 3C receivers gives rise to a 9C/3D dataset. This dataset was processed to provide information on the character of reservoir fracturing through the analysis of shear wave
Stochastic Imaging of Vuggy Formations
Authors: Casar-González Ricardo , Suro-Pérez Vinicio 
Published: December 2007

Abstract
This paper is dealing with modeling a heterogeneous reservoir rock from a Mexican offshore field. The problem is porosity characterization through the use of computed tomography images. The addressed issues include: association of secondary porosity with vugs and fractures, vug connectivity and spatial distribution, porosity associated to the rock, and vugs stochastic imaging. Porosity was obtained from computed tomography images, and calibrated with core data. From these images, exhaustive porosity variograms were obtained, showing a correlation range of about 20 millimeters. Further, use of indicator variables allowed vugs visualization, confirming the assumption that dissolution was the dominant process in vugs genesis. It is showed also that permeability has been enhanced through the connection of vugs by high porosity footprints. This detailed information has been used to reproduce geometry and spatial distribution of vugs through a sequential indicator algorithm. The stochastic images reproduce well vugs spatial distribution, explaining the secondary porosity role in the production mechanism in these reservoirs.