bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Hydrogeologic Cycle And Its Relationship To Geologic Processes
Authors: Parizek Richard R. 
Published: December 2007

Abstract
The concept of the hydrologic cycle, the germ of which was conceived of by Plato and expanded upon by Vitruvius, Palisay, Perrault, Mariotte, Halley, Lametherie and others required more than 2000 years for its acceptance. The physical and chemical factors that govern the state, occurrence, movement, quality and quantity of water in various segments of this cycle are still being clarified 2300 years after Plato advanced his pluvial concept in "Critis's." Man's understanding of the natural laws that operate in the hydrologic cycle and his engineering mastery over them holds the key to his successful evaluation, development, and management of water in all segments of this cycle.
Water in the hydrologic cycle serves as an active and passive agent to geologic and other processes and has played a varied and significant role in shaping geologic events. Since water is an intimate agent to geologic processes, it should not be thought of exclusively in the restricted sense of man's economic exploitation of water, his social and aesthetic benefits nor the harassment it causes him due to its overabundance or scarcity.
Consideration of the role of water in the hydrologic cycle through geologic time and of water not generally considered part of the hydrologic cycle requires that recognition be given to a second grander cycle - the hydrogeologic cycle — which involves the interaction of earth materials and water under varied environmental conditions from sediment accumulation to tectonics.
Corrosion Inhibition Of Gas Pipelines By Chemical Treatment
Authors: Robertson A.R. , Stanford J.R. , Chappell G.D. 
Published: December 2007

Abstract
Gas shortages, inflated pipeline replacement costs, and gas losses caused by internal corrosion have caused gas gathering and storage companies to become very concerned about internal corrosion in pipelines. Gathering systems take gas of pipelines. Gathering systems take gas of lower quality now more than ever before. Storage systems are pulled harder and longer, thus, more corrosive liquids are produced on withdrawal. The need exists for a specialized internal corrosion control program for gas handling systems. A program has been developed that includes detection of internal corrosion, treatment and monitoring of treatment results.
The energy shortage of recent months has helped focus attention to the internal corrosion problems in gas pipeline systems. However, internal corrosion and treatment in gas gathering systems has been documented since the early 1950's. This early treating program was accomplished by using an oil soluble water dispersible corrosion inhibitor. Application was by slug treatment and later as an inhibitor mist. Although the inhibitor program was successful in controlling corrosion, side effects such as sludge and emulsions occurred.
Internal corrosion in gathering systems is caused by acid gases in water and usually occurs along the bottom and sides of the line. In low flow systems where gas production has declined, corrosion and failures production has declined, corrosion and failures can take place on the upper surfaces of the pipeline. pipeline. In gas storage systems, the traditional treatment is with biocide and/or corrosion inhibitor. The chemical is mixed with water or a suitable solvent, pumped into the storage well and followed with gas. This method assumes the gas will displace the chemical mixture into the formation to control bacterial growth. Although negative bacteria cultures have been noted with this type of treatment there is concern that the biocide stayed in the bottom of the well or near the well bore and was not carried far into the formation where bacterial growth still continues.
Side effects of biocide treatments are foaming, emulsions, and expensive equipment costs for individual well treatments.
Experimental Study of Fluid/Rock interaction Caused by Drilling and Cementing Filtrates in Carito Field
Authors: Gambino F. E. , Guimerans R. , Galarraga F. A. , Pestana D. C. , Rojas E. 
Published: December 2007

Abstract
Fluid–Rock interactions were evaluated using formation rocks and fluids from Carito Field at East of Venezuela, in order to establish better criteria for the design of more efficient cement spacers. Rock and formation fluids were analyzed before and after exposure to overbalanced drilling and cementing filtrates through formation cores. Rock changes were evaluated by X-ray diffraction, SEM, permeability and wettability, whereas fluids were analyzed by fluid and gas chromatography, GC - MS, NMR and IR. Results indicate that 100% oil based mud filtrate produces a large permeability reduction. Spacer A showed greater mud removal efficiency than spacer B, whereas the cement slurry filtrate generates lighter formation permeability reduction than the oil-based mud, after either spacer exposure. This can be explained due to insoluble salts' precipitation when the cement filtrate is in contact to the residual formation water.
The molecular analysis of crude samples indicates that the absence of heavy molecules from hopane compounds in the crude saturated fraction could be related to adsorption of these compounds on the rock surface, which is partially oil wettable. In addition, absence of C15 – C20 molecules from crude oil is related to molecular distribution in the gasoil from mud and spacers evaluated. The results of these tests indicate interaction between crude oil and rock composition with drilling and cementing filtrates. Overall results of this study will allow achieving a more efficient approach for design of spacer fluids.
The Development of a Novel Environmentally Friendly Dual Function Corrosion and Scale Inhibitor
Authors: Collins I. R. , Hedges B. , Harris L. M. , Fan J. C. , Fan L. D. G. 
Published: December 2007

Abstract
Production chemicals being discharged into the natural environment are increasingly becoming scrutinized for their impact on the environment. New and existing chemicals for scale and corrosion control are likely to be impacted by the developing legislation and regulatory control. Therefore, there exists an urgent need to bring the marketplace new chemistry that is able to reduce the environmental impact while still retaining its excellent efficiency. This paper describes the development of novel polymeric chemistry, which has a dual functionality acting as both a scale and corrosion inhibitor under oil field conditions. This chemistry can be readily biodegradable and has achieved the stringent standards required for its use in the North Sea. Laboratory studies demonstrate that this chemistry can inhibit both carbonate and sulfate based scales. Corrosion experiments with or without flow suggest that greater than 90% of inhibition in a carbon dioxide rich environment can be achieved. The calcium compatibility of this chemistry far exceeds the performance of most commercially available scale inhibitors. The impact on oil and water separation, and subsequent oil in water content, is minimal.
Synergism and Antagonism of Foaming Agents and Corrosion Inhibitors
Authors: Pakulski Marek , Martin Richard 
Published: December 2007

Abstract
Continous or batch treatment of low pressure wet gas wells with foaming agents is a common and cost-effective method to sustain production from such wells. The foam additives convert well liquids into water/gas foams lowering the bottomhole hydrostatic pressure and increasing brine unloading from the well, thus preventing well "drowning" resulting in lower or ceased gas production. However, foaming surfactants being good wetting agents may accelerate the casing corrosion process and work against corrosion inhibitors. This effect would be particularly severe in deep wells having high bottomhole temperatures.
Foaming properties and steel corrosion rates were tested on fluids formulated with anionic, cationic, non-ionic and amphoteric foamers combined with the main categories of corrosion inhibitors. In most cases, there was a negative effect of corrosion inhibitors on foams or even a complete chemical incompatibility for some combinations. Occasionally, addition of certain corrosion inhibitors improved a foam's persistence and quality. However, the effect of a few percent of condensate seems to be stronger than 300 ppm of corrosion inhibitors. Additives had the greatest effect on the performance of non-ionic and amphoteric surfactants.
The effect of foaming agents on steel corrosion is not uniform. In most cases a surfactant offers some corrosion protection at mild conditions. Most foaming agents accelerate corrosion rates at high temperatures. Few chemicals produced spectacular corrosion.
Mixtures of foaming agents and corrosion inhibitors usually are less corrosive than foaming agents applied without any corrosion protection. However, no single component corrosion inhibitor reduced the corrosivity of such mixtures to an acceptable level.
The results indicate that wells that are being treated with foaming agents should also be treated with an appropriate corrosion inhibitor. For any particular application a proper combination of foamer/corrosion inhibitor should be selected. More consideration should be given to the properties of the foamer/corrosion mixture, than to those of the individual components.
Comparison of First and Multiple Contact Carbon Dioxide Induced Asphaltene Precipitation
Authors: Parra-Ramirez M. , Peterson B. , Deo M. D. 
Published: December 2007

Abstract
Precipitation of solids, believed to be asphaltenes is common in most carbon dioxide floods. The oils in most carbon dioxide flood applications, however, are light crudes with low initial asphaltene content. Precipitation is common after carbon dioxide breakthrough in production equipment. It is believed that precipitation does not occur in the reservoir. The objective of this paper was to identify the reasons for this phenomenon. The mature carbon dioxide flood at Rangely field in Colorado was selected as an example.
A high-pressure, high-temperature pressure-volume-temperature apparatus in conjunction with a high-pressure core flooding system was used to study carbon dioxide induced precipitation from the Rangely crude oil. Rangely crude contains about 1% heptane insolubles. It was determined that first-contact precipitation, at different carbon dioxide concentrations was negligible. Core flooding experiments at field conditions revealed that precipitation did occur at the core exit. This essentially showed that the precipitation phenomenon in crudes that are likely CO2-flood candidates is due to the multiple contact process and the associated compositional changes. Multiple contact experiments conducted to prove this hypothesis showed that multiple contact precipitation amounts were 3-5 times the first-contact precipitation values. The compositional changes (in the original crude) to cause widespread precipitation were established.
The precipitates from the field and various laboratory experiments were analyzed using GC and SARA, which showed that field precipitates contained compounds other than original heptane insolubles and also exhibited some unique features.
The Repairing Technology of Driving Channel on Small Drifting-diameter&apos;s Casing Damage in Daqing Oilfield
Authors: Lan Zhongxiao , Xia Yumin , Zhang Chuanan 
Published: December 2007

Abstract
Less than "70mm drifting diameter casing damage wells couldn"t be repaired by using normal methods. Its repairing is one of main tasks of oil and water wells workover and is a key to improve the workover rate. For this kind of wells, there is no effective repairing method in practice on domestic and abroad. The existence of the casing damage wells has seriously affected the results of exploitation, which restricted the oilfield continuing development. This paper introduced in detail on "139.7 mm casing and less than "70 mm the minimum drifting diameter"s casing damage by using two categories, mechanical type and explosive type, which can be diveided into five kinds of driving channels principles and methods. Its three kinds of matching cementing techniques i.e. explosive sealing welding, hydraulic sealing cementing, and mechanical slip sealing cementing are also introduced. After repairing, the inner drifting diameter of casing damage are ∮100 mm, seals loaded pressure 15 Mpa, hang capacity more than 400KN, the range of cemented length 1--100 m. After using this repairing techquies, it can adopt small diameter production casing of K344–95 to separately produce and inject water.
Conditioning Geostatistical Models to Flow Meter Logs
Authors: Mezghani M. , Lingen P. van , Cosentino L. , Sengul M. 
Published: December 2007

Abstract
This paper describes a method to condition facies (rock-type) permeabilities in geostatistical models to dynamic reservoir data: the flow meter log and the well test KH value. The proposed approach consists of two steps. In the first step, the flow meter logs are transformed into (reference) permeability profiles by use of the well test permeability–thickness (KH). This transformation is analytical, meaning that a geostatistical reservoir realization and numerical flow simulation are not required. In the second step, synthetic permeability profiles are computed for the known rock-type classification at the well locations. An optimization procedure is applied to improve the match of these synthetic permeability profiles with the reference (flow meter) profiles. In this process the initial (core based) rock-type permeability model is modified. The optimization procedure simultaneously takes into account all the wells, and is subject to geological constraints imposed by the user (ranking, permeability bounds). Although a number of assumptions must be verified, this fully analytical approach leads to a fast, flexible, and practical optimization routine that is relatively easy to implement. The up-front integration of dynamic data into the modeling process leads to a more representative permeability description than is obtained using only plug values. Because of the global nature of the optimization method, a satisfactory match can be extrapolated throughout the reservoir with a reasonable degree of confidence. The paper presents a successful application of the procedure to a Middle East reservoir.
A Comparison Of Sodium Orthosilicate And Sodium Hydroxide For Alkaline Waterflooding
Authors: Campbell Thomas C. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
Alkaline waterflooding has been extensively investigated over the past 50 years in laboratory and field testing situations as a method for increasing crude oil recovery. Alkaline salts such as sodium silicate, sodium hydroxide and sodium carbonate have been cited in various patents and investigations as useful agents for patents and investigations as useful agents for improving water flood performance.
Laboratory measurements of interfacial tension (IFT) values between alkaline solutions of sodium orthosilicate and sodium hydroxide and several mid-continent and California crude oil samples have been obtained with a variety of types of injection water. In softened water with no Ca++ or Mg++ ions present, both alkaline salts exhibit similar reductions in interfacial tension with all the crude samples tested.
When unsoftened water was used to prepare alkaline injection solutions, sodium orthosilicate was effective in significantly reducing IFT values at concentrations of 0.5% to 1.0% with mid-continent crudes. However, using sodium hydroxide, even up to 5% by weight, IFT values with these same crudes were not reduced as much as with sodium orthosilicate.
Both alkaline salts were equally effective in reducing IFT values between the California crude oils tested and unsoftened injection solutions. The concentration of alkaline salt required to produce a minimum IFT value ranged from 0.01% to 0.5% by weight, depending upon the injection water used.
This paper will review the laboratory data which has been accumulated, and present a comparison between sodium orthosilicate and sodium hydroxide as alkaline waterflood additives.

Introduction
A recent article by Johnson provides an excellent review of the historical background, proposed mechanisms and the state-of-the-art proposed mechanisms and the state-of-the-art in caustic and emulsion methods for improved waterflood recovery of oil. The addition of alkaline chemicals to injection water has been proposed by many workers over the past six proposed by many workers over the past six decades (Reference 1 and the references contained therein). Considerable laboratory data and a few field trials have suggested that alkaline waterflooding, or modifications thereof, can provide an incremental increase in oil recovery under the proper operating conditions in selected reservoirs. At the present time there are several field trials of alkaline waterflooding under way or proposed.
Oseberg: Increased Recoverable Resources by Optimal Reservoir Management and Use of New Technology
Authors: Aasheim Ivar 
Published: December 2007

Abstract
The giant Oseberg Field is located offshore Norway 140 km Northwest of Bergen at approximately 100-m water depth. The field is developed with four offshore installations and the 1998 reserves estimate is 337 MSm3. Pressure maintenance is implemented by reinjection of associated gas and import of gas from the nearby Troll Field.
The field is by September 2000 producing approximately 42000 Sm3/d from 46 wells. Plateau production of 81000 Sm3/d ended in 1997. 82 percent of the expected reserves have been produced and the original oil leg of 215 m is now reduced to between 20 to 40 m in the main reservoirs. Gas treatment capacity is the bottleneck controlling the oil production rate and production is optimized on a daily basis based on individual well gas oil ratio.
The Oseberg field has been an offshore laboratory to implement new technologies as they have emerged during the late eighties and the nineties. The paper will discuss both successful and less successful technologies.
More than 80 percent of the production is currently coming from horizontal wells that have been drilled in the field since the early nineties. Typical horizontal well lengths are between 1200 m to 1700 m and are placed close to the water oil contact.
Geo-steering by use of navigator and autotrack has been applied for optimum well placement. Three multilateral wells with both branches exceeding 1200 m have been successfully established.
To increase the recovery and accelerate tail end production, intelligent completions in the horizontal wells are assumed to play an important role. Currently four wells with up to four independent zones have been completed.
Reservoir management on Oseberg has also involved WAG techniques and attempts with foam to shut of gas influxes. To monitor the gas flooding of the reservoir and well inflow profiles, wireline, coiled tubing and well tractors have been applied at a large scale.
Oseberg has been in the front-line to utilize geophysical technology and shot full field 3D seismic in 1982. The first 4D seismic was acquired in the central area of the field in 1989. In 1998 part of the field was covered with seabed seismic and a new conventional 3D seismic to map out remaining reserves was shot in 1999. Seismic attribute analyses have been used to map out channel sand deposits and dedicated production wells have been targeted successfully with this technique. Lately, seismic data have been visualized by "CAVE" technology for geo-steering purposes.
IOR/EOR – Over Six Decades of Romanian Experience
Authors: Paduraru Rodica , Pantazi Ion 
Published: December 2007

Abstract
The concern for new reserves discovery and the extension of the existing ones dates back to 150 years ago and since then oil production has become a tradition in Romania. Therefore, for over 6 decades, the IOR/EOR methods have been tested and applied at a commercial level in the already known reservoirs.
The paper presents the importance of using these methods (yielding about 12% of Romania's annual oil production), related to Romanian reserves structure (out of which about 32% are due to conventional methods and about 20% to unconventional ones).
The beginning was in 1925, when one horizon was drilled-in and produced by mining methods. In 1936, the first gas injection was recorded, while in 1950 began the first water injection process. Currently, water injection is applied on 181 reservoirs (about 1/3 of the reservoirs produced by National Romanian Oil Company).
The discovery of and the production from heavy oil reservoirs (where the conventional recovery methods application generally leads to modest results) showed the necessity of testing and applying new methods, namely thermal methods.
1964 is the year when the "Romanian tradition" began in the in-situ combustion application, on the Pannonian Suplacu de Barcåu reservoir, the best-known process of this kind worldwide. Due to its performances (production being maintained at the same level for over 25 years and a recovery factor of 56% in the area swept by the front), Suplacu de Barcåu remains the singular in situ combustion process in the country (other 5 processes being ceased recently due to economic reasons).
Other methods (chemical, microbiological, CO2 etc.) were also tested and extended to a commercial level.
For future increase of production process profitability, the increase of the oil produced per unit of injected agent, as well as the reduction of the produced water are aimed at.
Challenges Opportunities and Reservoir Management, of a Giant Field in Venezuela
Authors: Mengual R. D. , Rattia A. D. 
Published: December 2007

SUMMARY
The Naricual formation of the El Furrial field is a deep anticline oil reservoir. It was originally highly overpressure and the reservoir temperature was quite high. The medium-type crude oil has a large asphaltene content and the fluid properties change significantly with depth. The field is sealed off from the underlying aquifer by a 200 feet tar mat. The primary production mechanism is fluid and rock expansion.
A major data collection campaign for reservoir definition was set up right from the start of production. It resulted in a pressure maintenance programme whose objectives were the acceleration of oil production and the maximisation of the oil recovery and profitability.
The pressure maintenance project and the enhanced recovery methods that have been implemented were based on 400,000 barrel/day water injection, later to be increased to 550,000 barrel/day and 450 million standard cubic feet per day of miscible gas injection. Together with the primary recovery these projects were estimated to produce 3,210 million barrel oil, and increase the oil recovery by 33 % of the original oil in-place. An integrated reservoir management and a continuing actualisation of the reservoir model was required from the start. As an illustration, the geological model was refined eight times during the past 13 years and the ongoing exploitation plan was adjusted accordingly. Its implementation required flexibility of facilities and production operations.
This paper describes the field monitoring techniques of the water and gas injection. Tools and methods used to improve production and injection patterns have also been addressed. The application of resins, emulsions and diverting agents to control production and injection was excluded mainly due to the extreme reservoir conditions. Sand plugs have been set and intervals have been re-perforated with the aim of obtaining a more uniform injectivity and productivity. Their success ratio exceeded 70 %.
Finally, the paper provides information on current studies, whose short term implementation could lead to produce up to 55 % of the original oil in-place.