bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental and Numerical Investigation of Carbon Sequestration in Saline Aquifers
Authors: Izgec O. , Demiral B. , Bertin H. , Akin S. 
Published: December 2007

AbstractBecause of the global warming threat posed by greenhouse gases, mainly by CO2, some strategies were proposed. Along those, disposal and long term storage of greenhouse gases is important for reducing global warming. Aquifers represent the most widely available and the second largest, naturally occurring potential store for CO2. Although there are a number of mathematical modeling studies related to injection of CO2 in deep saline aquifers, experimental studies are limited and most studies focus to sandstone aquifers as opposed to carbonate ones.Potential CO2 sequestration capacity of a carbonate aquifer formation located in S. East Turkey was evaluated using computerized tomography (CT) monitored experiments. Porosity changes along the core plugs, drilled from Midyat aquifer formation located in south-east Turkey, and the corresponding permeability changes are reported for differing CO2 injection rates, pressures and temperatures with differing salt concentrations. CT monitored experiments are designed to model fast near well bore flow and slow reservoir flows. It was observed that permeability initially increased and decreased for slow injection cases. As the salt concentration decreased the porosity and thus the permeability decrease was less pronounced. Orientation of the core plugs was observed to be influential in rock-fluid-carbon dioxide interactions. For vertically aligned cores high injection rates resulted in an increase then decrease of permeability. On the other hand horizontally aligned cores represented a decrease in permeability due to CaCO3 precipitation. It was observed that CO2 sequestration by solubility trapping is larger compared to mineral trapping. The results are discussed using a finite difference, non-isothermal compositional numerical simulator where solution and dissolution of carbonates via chemical reactions are considered. The calibrated model was then used to analyze field scale injections and to model the CO2 sequestration capacity of a potential carbonate aquifer formation located in S. East Turkey.
Corrosion in High Rate Gas Wells—A Case History
Authors: van Grinsven R. , Jackson L. , Suarez I. , Bouts M. 
Published: December 2007

Abstract
The Reedijk-1 gas well was completed in 1992 with 3 ½" Carbon Steel (CS) tubing and taken into production early 2003 with a capacity of 1.8 mln Nm³/d. Due to the CO2 content, continuous corrosion inhibition was required. However as a result of operational problems it took about 9 months before injection was established.
In August 2004 it was observed that the annulus injection pressure increased slowly towards the tubing head pressure and finally became equal. By closing the flapper valve and releasing some pressure of the tubing, it was assessed that the communication should take place above the subsurface safety valve. A downhole video camera run was carried out and identified the leak 1.8 m below the top of the tubing hanger. The camera also revealed that pipe bodies were still in good shape but the couplings showed severe pitting. Subsequently, straddling off the leaking coupling minimized gas production deferment. The well could normally be produced until it was worked over to 5" Chromium 13 (Cr13) tubing.
From this case history it can be learned that: In high rate gas wells understanding the film persistency of the chemical corrosion inhibitor is important as removal of inhibitor films is a possibility due to the high velocities thereby leaving this part of the tubing unprotected. This is especially the case at subsurface safety valve (SSSV) depth as a result of the restricted diameter.The application of chemical corrosion inhibition in downhole situations may not manage corrosion when pitting corrosion has been initiated.Alternative solutions to corrosion management need to be sought. Improved technologies that enable increased inhibitor availability, improved inhibitor chemistry's demonstrating high persistency at high gas velocities. Application techniques such a batch dumping of corrosion inhibitor into the well with high persistency chemicals are being tried as alternatives.
Experimental and Theoretical Study of Uranium in Situ Solution Mining With H2SO4
Authors: Harloff Gary J. , Riese A. C. 
Published: December 2007

ABSTRACT
Experimental and theoretical studies of solution mining indicate that the macro chemical composition of the produced fluids are governed by solution mineral equilibria. The aqueous composition of these solutions and the mineral mass distruction and creation in the host rock are calculated as a function of pH. The site specific geologic and hydrologie characteristics are accounted for as boundary conditions, thus this technical capability is not site specific. The bulk solution chemistry and the uranium extraction curve for a field site are successfully modeled.
Scaling criteria are developed and a scaled two dimensional field simulator was built and tested to demonstrate a hydrological barrier concept which is applicable to leach and restoration field tests. Tests with Hele-Shaw flow in a transparent porous media were conducted to obtain flow visualization and tracer data. A uranium extraction test was conducted in the field simulator to illustrate and verify new well concepts and to provide data for the computer models of the process.
The Advantages of Conditioning an Orebody With A Chloride Solution Before in Situ Uranium Leaching with A Carbonate Solution
Authors: Tweeton Daryl R. , Guilinger Terry R. , Breland W. Michael , Schechter Robert 
Published: December 2007

ABSTRACT
Laboratory experiments conducted by the University of Texas at Austin as part of a research contract funded by the U.S. Bureau of Mines indicate that conditioning an orebody with a chloride solution prior to carbonate leaching offers two advantages. First, the permeability loss occurring upon the injection of the carbonate solution is reduced. This effect is tentatively attributed to a reduction in precipitation of calcium carbonate. Calcium chloride is soluble, so calcium can be flushed out of the orebody. Second, the great difficulty of complying with current regulations concerning restoration of groundwater quality after leaching with ammonium carbonate may be avoided because the substitution of potassium carbonate for ammonium carbonate may be made economically feasible. Flushing the orebody with potassium chloride before leaching satisfies cation exchange sites with potassium from relatively cheap potassium chloride, thereby reducing the consumption of the more expensive potassium carbonate. Field tests are planned.
Biotechnology Applications to EOR in Talara Off-shore Oil Fields, Northwest Peru
Authors: Maure A. , Saldaña A. A. , Juarez A. R. 
Published: December 2007

Abstract
Seven producer wells (oils between 32-36 °API) from Basal Salina fm. in Providencia and Lobitos areas of Z-2B Block (Talara basin, Northwest Peru) were selected to evaluate a biotechnology approach for Enhanced Oil Recovery.
The MEOR candidates are vertical and high-angle slanted wells. They produce from faulted reservoirs through intermittent gas lift methods under an off-shore operative environment. The oils are paraffinic and hence with positive bio-treatability.
The treated wells exhibited a typical MEOR response in two consecutive stages: 1) Clean-up effects by the removal of organic damage occurring in the near wellbore of the perforated interval, opening non-productive zones bearing oils with a more segregated, pseudoplastic behavior. The typical signature is a high pulse in oil rate but only lasting a short time. 2) Radial-Colonizing response, by generation of light-end solvents (biocracking on N-alkanes present in the oil) which cause a permanent rheological effects by the compositional alteration that occurat deeper colonization radius, in drainage zones with extremely low shear rate values (low fluid velocity).
The MEOR pilot stage in PG-U9 and PG-9 of Providencia and LO16-14 and LO16-24 of Lobitos fields resulted in 3,086 M[3] (19,410 bbls.) and 2,211 M[3] (13,907bbls.) of Incremental Oil respectively. MEOR Increments of36.5% in Providencia and 46.5% in Lobitos were assumed as conservative (non optimized) MEOR performance indexes. Note: Due to operative reasons not directly related to MEOR, the complete inoculation program was concluded in only four of the original seven candidate wells.
The pilot project was considered profitable and economically feasible of further expansion.
Z-2B block possess 430 producers as excellent MEOR prospect and waterflooding schemes as potential targets for biotechnology (MEOR[2]). [Ref. 7 to 14].
New Hydrocarbon Traps in the Acema Area, Eastern Venezuela: An Alternative for a Mature Oil Field
Authors: Azalgara C. , Boada E. , Diaz M. , Bonfanti B. , Blanco R. 
Published: December 2007

Proposal
In 1997, during the third Round of Mature Oil Fields bid, PDVSA awarded the Consortium COROIL-Petrobras Energia Venezuela (then Perez Companc de Venezuela) the Acema Block operation. This block, which extends through 300 km2, includes several oil-fields that have produced hydrocarbons from the Oficina Formation (Fm.) for more than fifty years. Currently, most of these reservoirs are depleted.
This work aims to characterize the Oficina Fm. reservoirs under exploitation, and to identify upsides in the Acema Block in order to reverse the declining production tendency. The available data to perform the study comprised: old wire-line logs set from 82 wells and modern wire-line logs set from 9 wells, a standard seismic volume covering 420 km[2], modern VSP's and check-shots surveys, and reservoir production and pressure data.
The methodology included: Creating a petrophysical model. Validating / creating synthetic seismograms. Characterizing the original seismic data. Performing rock-physics analysis. Applying the High-Frequency Imaging reprocessing technique to enhance the original frequency content. Creating the structural and the stratigraphic models. Creating geocelular models of the two most important fields (A and B fields). Assessing the OOIP and the remaining reserves (volumetric and material balance methods) of those fields. Performing economic analysis under different development scenarios.
We have recognized two types of hydrocarbon traps:
Structural-Traps, which consist of extensional anticlines adjacent to normal faults.
Combined Stratigraphic-structural Traps, which comprises the following elements: (a) The strata dip, 4° north. (b) Elongated sandstone bodies whose predominant characteristics are: northwest-southeast trend, net thickness 10-35 feet, effective porosity 12-17 %, width 0.7-2.3 km and length in the order of tens of kilometers. (c) Shale beds that seal those sandstone bodies. (d) A main permeability barrier, which is defined by the southwest border (up-dip direction) of the elongated sand body. (e) Sealing normal fault that serves as lateral permeability barrier that shows the following characteristics: trend approximately orthogonal to the sandstone body elongation and length larger than the width of the sandstone body at their intersection zone.
Both kinds of traps include stacked, relatively small, mostly solution gas-drive reservoirs. Production history indicates that the reservoirs associated to the Combined-Traps are more prolific than those related to the Structural-Traps.
We have defined a highly Prospective Area of 2630 acres located at the south-central part of the Acema Block that shows a Combined-Trap cluster. The estimated reserves of this Prospective Area at least represent 15% of the total reserves for the Acema Block.
Recent In-Situ Oil Recovery-Technologies for Heavy- and Extraheavy-Oil Reserves
Authors: Cunha L. B. 
Published: December 2007

Abstract
The heavy and extra heavy oils in Canada represent an amount of recovery oil resources of about 300 billion barrels. These vast quantities of heavy and extra heavy oil are trapped in shallow, accessible reservoirs, but are difficult to extract. Producers involved in heavy oil recovery face special challenges in producing these high-viscosity crudes.
Conventional heavy oil recovery methods have showed to provide limited oil displacement efficiencies in Canada's heavy and extra heavy oil deposits. To overcome their inherent difficulties several variations of steam, air and solvent injection methods have been proposed. The most interesting ones appeared along with developments in horizontal well technology. These methods combine the concept of oil gravity drainage with the conventional air-steam and solvent-based heavy oil recovery processes and the horizontal well technology. Methods known as cyclic steam stimulation – CSS, steam-assisted gravity drainage – SAGD, solvent vapor extraction – VAPEX, and top-dow combustion, are examples of this class of methods.
This article presents an overview of the recent production technologies for extra heavy oil reserves. Some of the properties of heavy oil are summarized and a review of the drilling/completion and production techniques that help to make heavy-oil reservoirs profitable assets is presented. Both, limitations and potential benefits of these techniques are described.
Detection of Hydrothermal Alteration in A Sedimentary Type Geothermal System Using Well Logs
Authors: Ershaghi Iraj , Ghaemian Shahed , Mathews Mark 
Published: December 2007

ABSTRACT
A study was conducted to examine well log responses in the hydrothermally altered zones of a sedimentary type geothermal reservoir. The logs were run under precooled borehole conditions. In spite of uncertainties about the borehole temperature at the time of logging and lack of calibration data for quantitative estimation, qualitative interpretation of the logs indicate that the zones with extensive hydro-thermal alteration are detectable on conventional logs such as conductivity surveys, S.P., compensated density and neutron logs. These observations confirm the worthiness of wireline logs in geothermal exploration.
How And Why Does Scale Stick—Can the Surface Be Engineered To Decrease Scale Formation and Adhesion?
Authors: Wang Z. , Neville A. , Meredith A. W. 
Published: December 2007

Abstract
In many production fluids encountered in the oil and gas industry, the formation of mineral scales such as BaSO4 and CaCO3 causes major problems with respect to flow assurance. It has recently become apparent that in order to fully understand a scaling system both an appreciation of the bulk precipitation and surface deposition characteristics must be obtained [1]. In surface deposition the important steps are (i). nucleation of crystals, (ii) the growth of these crystals at the surface site and (iii) finally the adhesion of crystals to create a scale layer. In some instances where scaling causes operational problems (e.g in heat exchangers in desalination units) application of ‘non-stick’ materials are considered as a promising method to alleviate scale deposition. To date, there have been few instances where surface modification or surface coatings have been considered seriously for scale control in the oil and gas industry.
In this paper results are reported from experiments to investigate calcium carbonate scale formation and adhesion at solid surfaces. Two aspects relevant to adhesion are considered: 1. the influence of the substrate on the extent of surface scale formation; 2. the critical shear stress required for removal of scale. Four substrates were investigated in the study, UNS S31603 (stainless steel), electrochemically pretreated UNS S31603 and two coatings: DLC (diamond like carbon) and PTFE (polytetrafluoroethylene). Deposition experiments were conducted from supersaturated solutions of calcium carbonate at 50°C. In order to investigate the critical shear stress for removing scale on different substrates, a submerged impinging jet (SIJ). It has been shown that the amount of scale formed at the surface is dependent on surface energy and on physical surface roughness. The surface energy, and in particular the polar component, is an important factor in adhesion – as are the morphology and crystal arrangement in the surface scale deposit.
Technical and Economic Analysis of the Downhole Scale Risks and Uncertainties for Subsea and Deepwater Field Developments
Authors: Graham G. M. , Collins I. R. , Johnson T. J. 
Published: December 2007

Abstract
Scale control is conventionally achieved by the use of chemical inhibitors, introduced to the production system either by squeeze treatment into the reservoir or continual injection into the well. However, as new field developments encounter more challenging production environments or when the associated economic impact of chemical intervention is large (e.g. subsea completed wells with poor chemical placement by bullhead treatments, or limited access to wet subsea wellheads), other methods of scale control such as sulfate removal must be considered during the front end engineering design (FEED) stage for the development. However, the final selection of a fields scale management strategy relies on various technical and economic factors which themselves are controlled not just by the severity of the anticipated scaling regimes but also on the proposed field development plan. For subsea completed wells, especially those located in deepwater, the initial field development concept and drainage strategy can have a significant bearing on the costs ultimately associated with various scale management strategies and can, in extreme cases, significantly reduce the Net Present Value (NPV) of the project. The decisions taken at the concept selection stage for scale management in such environments are therefore crucial to the success not only of the chosen scale management strategy but also to the fields economic viability.
This paper reviews the various challenges associated with scale formation and control in subsea and deepwater environments and the impact that different field design scenarios may have on the potential success of various scale management options. In particular, the paper will focus on technical, economic and risk-based analysis conducted for a number of new and proposed subsea field developments with different scaling challenges. The options for scale management in selected subsea and deepwater developments including examples from the North Sea (Shallow water), offshore Angola, and Gulf of Mexico cases will be reviewed. The impact of the various risks and uncertainties associated with determining the severity of the scale challenge (including the quality and source of initial water compositions, the accuracy of simulation tools used for the prediction of future scaling challenges prior to field production, the ability to effectively squeeze treat and place scale inhibitors into particular wells and the potential for changes in the field drainage strategy) are assessed in terms of the total costs associated with particular cases. In summary, the paper will describe the decision process used at the pre-FEED stage to determine a field scale management strategy for different development concepts. Detailed economic analysis of different options considered in recent field cases will be presented to support the different strategies adopted.
In-Situ Uranium Leach Mining: Considerations for Monitor well Systems
Authors: Durler David L. , Bishop Author L. 
Published: December 2007

Abstract
Monitor wells are placed around an in situ leach mine to alleviate the potential for groundwater degradation. Such monitoring systems are the result of regulatory requirements or theoretical hydrologic concepts, irrespective of geologic anisotropies. Certain geologic factors can influence the groundwater regime and, therefore, markedly affect the adequacy of groundwater monitoring systems.
Deep Mineral In-Situ Solution Mining
Authors: Hunkin Geoffrey G. 
Published: December 2007

ABSTRACT
Uranium exploration drilling depths for western sandstone type deposits have increased from a maximum of 60 m (200 ft) to over 600 m (2000 ft) in the past 25 years. Recent test wells have exposed favorable depositional conditions and mineralizations below 1350 m (4500 ft). This paper describes engineering analysis and bench testing performed in order to estimate exploitation processes appropriate for these deep occurrences.
Physical-chemical laws show that the efficiency of uranium dissolution increases with pressure. The key factor is the square root of the partial pressure of oxygen, which controls the oxidation of four valency uranium to the six valency soluble condition. As depth increases operating pressures, so control of high oxidation potentials becomes easier and less expensive. Cost of all reagents, including complexing chemicals, is reduced without risk of re-precipitation, due to the decreased pH sensitivity.
Inter-well spacings are shown to increase rapidly, while maintaining the same permeability/flow rate/differential pressure relationship. The mass of recoverable uranium tributary to an operating well increases much more rapidly than does the incremental cost of deeper wells.
Environmental factors should become of reducing importance as depth increases due to the remoteness of the production area from potable, exploitable groundwater supplies.
Operating Experience in the Recovery of Uranium at the Pawnee and Zamzow Sites
Authors: Annamalai Velu , McGarvey Francis X. 
Published: December 2007

Abstract
IEC Corporation is presently recovering uranium by in-situ leaching or solution mining technique at the Zamzow site, and completed its production at the Pawnee site. An oxidative lixiviant with ammonium carbonate and hydrogen peroxide is injected into subsurface ore strata according to a defined wellfield pattern. The resulting uranium-enriched leachate solution is pumped out of the ground and brought to the recovery plant. This solution is filtered first and then the uranium is recovered by an ion exchange process. The final product of yellowcake is produced by steam precipitation and vacuum drying. The uranium-free barren solution is re-injected into the orebody after adding the necessary make-up chemicals.
Several problems related to ion exchange performance were observed during the initial startup of the Pawnee site. These included fouling with polythionates and oxidative attack on the resin structure. Cooperative studies between IEC Corporation and Sybron Corporation led to the selection of a resin with increased resistance to oxidative attack. Modification of the feed solution chemistry resulted in control of the polythionate fouling and also in reduction in uranium losses. These findings were also applied to the second site operation where acceptable performances have been experienced for the past two years.
The Pawnee site, a small orebody, has been worked out and a site restoration program has been under way for over a year. Methods for handling above ground wastes are discussed and approaches to the control of underground ground water contaminants are outlined. Lessons learned at Pawnee are discussed in light of restoration of future sites.
The Zamzow site has been in full production since July 1978. General plant practices and economics are outlined and future recommendations on process modifications suggested.
CO2 Corrosion in Bromide and Formate Well-Completion Brines
Authors: Leth-Olsen H. 
Published: December 2007

Abstract
Corrosivity data for halide and formate well brines that have been acidifies as a concequence of influx of large amounts of acid gas has been requested.
The well materials C-steel, standard 13%Cr steel and Super 13%Cr steel were corrosion tested in potassium formate and CaBr2 brines acidified with CO2 gas, simulating a well situation with influx of acid gas. The acidification resulted in an initial accelerated corrosion of C-steel in both solutions, reduced to low levels by time due to formation of a protective iron-carbonate layer. Both C-steel and standard 13%Cr steel were attacked by severe localised corrosion in the bromide brine, whereas only limited general corrosion was developed in the formate brine. Super 13%Cr was uncorroded in both brines.