bluuebunny/crossref_metadata_2025_split huggingface dataset:
Probabilistic Model to Develop Multilayer Gas and Oil Prospects
Authors: Faya Luis C. 
Published: December 2007

Abstract
It is not that uncommon when putting together an exploratory program to find that there are several prospects within a block, and/or several reservoirs within an individual prospect. Given that we could successfully develop each prospect, the total value of the property will be equal to the sum of the individual prospects, i.e. we can add the Net Present Value (NPV) distributions taking into account the probability of success of each prospect to obtain an estimation of the block's value. This simple process will be complicated when one or more of the prospects have more than one potential layer.
We can solve this problem by introducing simplifications, such as adding all the layers and developing them as one unit. But what if they are at different depths, have different productivity index, gravity or impurities? We can also build a decision tree that takes into consideration the different future scenarios. This is usually tedious, time consuming and we could introduce additional bias when having to assign probabilities to the different branches.
This paper shows a simple methodology to build a probabilistic production forecast, capital and operation expenditures for a prospect with several layers, in order to make an economic evaluation of an exploration opportunity.
Variation of the Mechanical Properties for Cementing Slurries with Different Compositions
Authors: Altuna Gustavo , Centurion Sergio , Perez Ipina Juan E. 
Published: December 2007

Abstract
Without any doubt, the primary cementing of a gas / oil well is the most critical stage in its life. The cement will make the isolation between zones and will avoid any kind of communication, it will also protect the casing from external fluids or pressures, and it will bring the necessary structural support.
When one design is made, a lot of disciplines (chemistry, geology, physics, mechanics, electric, etc) will participate to define the final design.
Anyhow, in the completion / production phases of the well, the cement is subjected to higher loads or higher stresses that were designed for the goals above mentioned. For example, when a well is perforated, it is subjected to high dynamic loads and high variations of temperature. Another example is when a hydraulic fracture is performed or when it is converted into a multi-lateral well.
A lot of effort was made to improve the techniques in the completion process but not enough to study the way to give the cement column better mechanical properties, and let it improve its strength throughout the well's life. On the other hand, the criterion to analyze the stability of the cement is through the compression strength that changes with time and composition.
The industry accepts that the cement has a very limited capacity to support tensile load. In addition, there is little knowledge about the behavior of a crack under a tensile load and how it behaves as a function of time.
In this paper, the behavior of two cementing slurries with different compositions through the use of Linear Elastic Fracture Mechanics (LEFM) [1], the fracture toughness and their variation with time were analyzed. The variation in the mechanical properties was focused in two slurries with different compositions. The difference was the addition of a styrene-buta-diene latex in the cement slurry.
The fracture toughness variation through setting time was studied; having been observed a maximum toughness value between 7 and 21 days.
All the slurries were mixed under API- Spec10 [2] requirement and all the tests were performed taking into account E 1820-96 ASTM standard [3].
Interventionless Production Packer Setting Technique Reduces Completion Costs
Authors: Patterson Daniel L. , Taggart Ian D. , Breivik Harald W. , Scott Gordon , Simonds Randy , Falconer Rod 
Published: December 2007

Abstract
Developing marginal petroleum fields or extending the life of mature fields becomes significantly more attractive when technology is available that can enhance cost efficiency and reduce operational and environmental risks. To support the above needs, a major oilfield equipment supplier has introduced an interventionless technique for setting production packers downhole that provides an alternative to conventional setting procedures. When applied to the proper scenarios, the costs relating to setting the packer can be substantially reduced. The system can be used for completions where the capability to set and retrieve a plug is deemed virtually impossible or when the use of wireline or coiled tubing tractors would be very costly and risky. Basically, the system reduces the intervention risks by eliminating the need for intervention. This paper will describe the system, its testing, and the structured approach that was applied throughout system development to enable the concept to materialize from its initial concept to a finished product.
Using this technology, a packer can be set without using such traditional techniques as setting and retrieving plugs. In addition, no complicated tools or hazardous materials are required. The concept uses the hydrostatic pressure of the well to provide the energy supply to set the packer. The application of a predetermined surface pressure initiates the setting sequence and does not require electronics or special surface equipment.
Two offshore North Sea case histories that will provide data that verifies the cost advantages provided to the operator when the hydrostatic-set packer system is used will be discussed.
In fact, one of the wells in which this technology was used is the longest extended-reach horizontal subsea completion in the world to date.
Seismostratigraphic Model of the Tundy Field Carboniferous Reservoirs, Chaco Basin, Bolivia
Authors: Kusiak M. E. , Cardona R. , Rivero J. L. 
Published: December 2007

Abstract
The Carboniferous Glacio-Eustatic Reservoirs of the Tundy Field related to the San Telmo Formation, represent fluvial and shallow marine facies. San Telmo Formation was deposited in the Upper Carboniferous transgressive-regressive cycles associated with common climatic changes in these glacially influenced intracratonic basins. These Carboniferous reservoirs are mostly associated with stratigraphic-structural trapping and the Devonian shale's as a source rock. The sequence is divisible into three units in order to determine an accurate siesmostratigraphic model. Two marine units and one fluvial unit are recognized from 3D seismic and wells drilled in the study area. The Lower Marine Unit is the lowest shoreline deposit and consists predominantly of shaly sediments. They are upward-coarsening successions that represent parasequences deposited during a high stand of relative sea level that were incised by streams and were partly eroded during a lowering of relative sea level. The Upper La Peña Fluvial Unit is the aggradational valley fill that was accumulated on the subsequent rise of relative sea level. This stacking fluvial channels unit is aquiferous with a considerable thickness in Tundy Field and productive in the La Peña neighbour Field. The Upper Marine Unit, accumulated when the sea transgressed across the area from southwest to northeast, has two shoreline distinguished sand bodies; one of them is the main reservoir in the Tundy Field and thins toward its landward pinch-out. Conclusions on the 3D seismic interpretation have an excellent coherence between the geological units that are supported with interference and pressure analysis and studies obtained in the field.
DBU+ A Geoscience Integrated Tool
Authors: Albano J. R. , Dogliani J. , Pandolfo L. E. , Quintana J. C. 
Published: December 2007

Abstract
With the aim to get a reliable, integral, simple and efficient tool for information access requested in geosciences project, we have developed a computer integral system for access, validation and preservation of data and documents.
The kernel system is a relational data base with a set of validation process to guarantee the consistency and quality of information. This Kernel is interfaced with a document management system to visualize scanned document.
The front-end for data access is an interactive graphical interface with functionality to open specific applications, well logs and seismic lines export to integrate project, to retrieve production and workover dates, to display geological cross sections, to visualize scanned documents, etc.
The system consists of six data bank interconnected by an integrator module to access at the different kinds of data stored in it: digital data, well logs curves, seismic field data and processed cross section, scanned technical documents.
The input/output and query operations can be made by UNIX workstations, PC or inside an Intranet/Internet web page.
DBU+ is the integration of two different independent experiences implemented in YPF and ASTRA prior to the merge of both company. These are the Data Base Upstream (DBU) oriented to the production, and the Argentine Corporative Data Bank (ABCD) oriented to geosciences. These two systems are presently in operation in the different fields of REPSOL-YPF.
With DBU+ a geoscientist can access from any remote station, in interactive graphics mode and at his fingertip, to any kind of geological, geophysical, petrophysics and reservoir information. The documents management system is the tool to visualize the well file and any type of scanned document.
The Sand-Rich and Mixed Sand-Mud Ramp Deep-Water Depositional Systems of the Apiuna Unit (Santa Catarina State, Brazil): a Challenge to Decrease the Unrecovered Oil
Authors: Basilici Giorgio , Martins Jorge Leonardo 
Published: December 2007

Abstract
A 3D model of an ancient sand-rich and mixed mud-sand ramp deep-water sedimentary environment, outcropping near Apiuna, Santa Catarina State, Brazil, is presented. This research contributes in the following way to the upstream sector of the petroleum industry: i) with a 3D conceptual model of reservoirs in ramp deep-water systems and ii) with 2D synthetic seismograms based on real outcrops.
The first contribution refers to a more refined 3D conceptual model for the reservoirs. The proposed architectural model is more complicated than the previous interpretations which saw the deposits of Apiuna unit as a channel-lobe system in a deep-water fan. In this new model, two type of ramp are recognized. One, sand-rich, is characterized by extensive sandy-sheet reservoirs, not linked to proximal channels and showing an apparent casuality of construction. The sandy sheets vary downcurrent their lithologic features as function of a density-stratified flow: debris flow &lt;I&gt;s.l.&lt;/I&gt; in the lower part of the sedimentary flux and turbidity current in the upper part. The second type of ramp, mixed sand-mud, is characterized by a channel-levee complex. The two mentioned ramp systems represent the variation of the depositional environment controlled probably by tectonic-morphologic factors.
Construction of synthetic seismograms by using extensive 2D geologic models evaluated from outcrop data is the other part of this work. The properties needed for constructing the synthetic seismograms, which are densities and P-wave velocities of each stratigraphic unit, are evaluated from appropriate petrophysical tables. Synthetic seismograms are then used to qualitatively analyse the seismic response of a stratigraphic column. Correlation of each generated seismogram with the respective stratigraphic column allows identifying small-scale features not visible within the range of seismic frequencies.
A New Integrated Reservoir Model for F-H Sands in Oritupano B Field, Eastern Venezuela Basin
Authors: Alvarado E. , Camacho M. , Salazar P. , Salas D. , Gonzalez R. 
Published: December 2007

Abstract
The objective of this work was to create an integrated model of the F4U, F4L, F5, F67, F8, H12 and H3U,L clastic reservoirs, within the Lower Miocene Oficina Formation of the Oritupano B field (Eastern Venezuela Basin) in order to evaluate different development alternatives for these reservoirs.
Based on the 3D seismic data reinterpretation, a new model was developed integrating new structural data and sequence stratigraphy as well as defining the different depositional sequences. A new sedimentological interpretation and stratigraphic framework from correlations and two available cores were used to determine the main sedimentary bodies and trends of deposition.
The static model was developed using geostatistical techniques and incorporating the new structural and sedimentological models as well as the available petrophysical data. Stochastic simulations were performed in order to obtain the areal and vertical properties distribution for the different deposits. The results showed consistency with the depositional model previously defined.
Two numerical simulation models were created: a stochastic model, based on the results of the geostatistical analysis, and a deterministic model, based on the new conventional static model. Both simulations yielded similar results. The adjustment of the static/dynamic models allowed the determination of oil reserves associated with these reservoirs and the refinement of the optimal exploitation strategy.
The new geological model indicates that the main structural features of the field are normal faults and extensional reverse drag folds, unlike the preexisting model in which a gentle homocline structure was suggested. A SW-NE depositional trend for the erosive channels and NW-SE depositional trend for coastal bars, parallel to the paleocoastline, were determined. In addition, four depositional sequences were defined formed by transgressive and highstand systems tracts.
Both, the stochastic and the deterministic model suitably represent the dynamic behavior of the studied reservoirs. The communication between the F-H sands of the up-thrown block, with the A9-A13 sands of the down-thrown block, was demonstrated through both dynamic models, which also improved the characterization of the aquifers within the reservoirs. Based on the results of this study, 3 new vertical wells and 5 additional workover wells were recommended. It is expected that these wells will increase the recovery factor of the F-H sands by 12 %.
New Applications of NMR in Understanding Heavy-Oil Behavior
Authors: Romero P. , Quintairos M. 
Published: December 2007

Abstract
Actually in Venezuela reservoir characterization has become very important, especially for heavy oil reservoirs because of the great amount of reserves located in the Orinoco belt. For this reason, new logging techniques like nuclear magnetic resonance are being applied in order to determine petrophysical properties of the reservoirs and fluid characteristics.
The transversal magnetic relaxation time or T2 has been measured to determine the T2 cut-off and fluids saturations of unconsolidated core plugs samples from Melones field. Also the T2 distribution has been measured in heavy oil hydrated and dehydrated samples from Hamaca and Melones fields in the laboratory at different temperatures to obtain the viscosity based on the distribution fitting to gaussian curves.
The effect of temperature increase on heavy oil and water saturated core plugs contributes to a decrease of the oil viscosity, which is observed as a shift of the oil signal to higher T2 times, while the water signal decreases.
The NMR response of core plug samples, saturated with heavy oil, heavy oil with gas in solution and gel is used for calculating the oil and gel saturations, irreducible oil saturation, porosity and the oil volume displaced by gel.
This work presents some of the applications of NMR techniques for a better understanding of the heavy oil reservoirs.
Multilateral-Horizontal Wells Increase Rate and Lower Cost Per Barrel in the Zuata Field, Faja, Venezuela
Authors: Stalder John L. , York Gregory D. , Kopper Robert J. , Curtis Carl M. , Cole Tony L. , Copley Jeffrey H. 
Published: December 2007

Abstract
Petrozuata, C.A is a joint venture (JV) company between Conoco Orinoco Inc. and PDVSA. This JV is developing extra heavy crude in a 74,000-acre block in the Zuata field in the western portion of the Faja del Orinoco in Venezuela.
After the initial single lateral wells were brought on production an opportunity was identified to change the development program to multilateral wells in order to increase production rates. The geometry of multilateral wells is designed to fit the actual sand distribution and depositional environment that ranges from subarial fluvial to marine tidal systems. The various forms of multilateral wells drilled by the JV include stacked dual lateral, stacked triple lateral, gullwing dual lateral, gullwing triple lateral or crow's foot, and pitchfork dual lateral wells. In addition a fishbone multilateral concept consisting of a "spine" or main lateral with liner connected to many ribs or fishbones without liners has been used in single lateral and multilateral configurations. The geologic and geographical reasons for drilling these different types of multilateral wells are reviewed. The result has been an increase in production rate per well that is nearly proportional to the effective lateral length connected to the well bore at a lower cost than possible with single lateral wells of the equivalent length.
Orinoco Oil Belt Well Construction Using "Wells-in-Series" Technology with Horizontal and Multilateral Trajectory
Authors: Silva Boza Gilberto C. , Romero P. Tito H. 
Published: December 2007

Abstract
The Orinoco Oil Belt, located in the southern part of Venezuela, is a gigantic reservoir of 55,000 sq. Km, which contains accumulations of heavy and extra-heavy hydrocarbons of 1,200 MMM barrels of oil in place, and final recovery of 270 MMM barrels. The first well, Canoa N°1, was drilled in 1935. At that time, various multinational companies started exploratory activities in the area. However, due to the oil characteristics, such as low gravity, high viscosity and metals content, the interest of these companies decayed rapidly. Finally, in 1977 the Executive Branch, through the Ministry of Energy and Mines, assigned the responsibility to PDVSA of planning and executing the necessary activities to evaluate and develop the energy resources of Faja.
During the period 1978/1983, an intensive exploration and evaluation program was developed1, including drilling about 1,000 wells, which resulted in a detailed evaluation of the regional geological model, the reservoir characteristics and the crude physicochemical properties. The facility requirements for oil transportation and processing were analyzed as well. Simultaneously, a territorial ordaining of the entire southwestern part of the country was carried out through an Agreement among PDVSA and several Government institutions.
In the early 90′s, as a result of the hydrocarbon worldwide demand forecast and the huge heavy and extra-heavy crude reserves in the Faja, PDVSA, in accordance to the premises established by the Government, decided to promote the creation of Strategic Associations to carry out projects with the aim of fully developing the Faja.
Influence of Asphaltenes Content and Dilution on Heavy Oil Rheology
Authors: Argillier J-F. , Barré L. , Brucy F. , Dournaux J-L. , Hénaut I. , Bouchard R. 
Published: December 2007

Abstract
The increasing oil demand is leading to the development of the very large world resources of heavy oils that are of the same order of magnitude than conventional oils. However, production and transport of these oils are challenging because of their very high viscosities. Our aim in this study was first to understand the role of asphaltenes in these high viscosities and secondly to evaluate the viscosity reduction efficiency when blending with different diluents.
Many previous works studied asphaltene associations in simple organic solvents like toluene or toluene/heptane mixtures, but these conditions are not representative of heavy crude oils. Our approach has been to characterize the rheological behavior of asphaltenes in their natural environment. Samples coming from the same crude oil have been prepared with different asphaltenes contents, from 0 to 20%, after deasphaltating and recombination. From viscosity measurements two concentration regimes were identified: a diluted regime where the apparent viscosity increases linearly with the weight fraction of asphaltenes and a concentrated regime where the viscosity increases dramatically because of asphaltene particles entanglement. The diluted regime can be described as a solution of solvated asphaltene particles that are independent from one another. Natural heavy crude oils correspond to the concentrated regime and the high viscosities observed are due to this entanglement of solvated asphaltene particles. A strong influence of temperature on the rheology is revealed by measured high activation energies.
Dilution of heavy oils has been studied using various solvents, in terms of aromaticity, chemical nature and viscosity. Dilution with low viscosity hydrocarbons, like light crude oil or naphtha, has shown that the viscosity reduction efficiency is controlled by the sole viscosity of the diluent and not by its aromaticity. The aromaticity has no effect up to very high dilution rate, more than 60% in our tests, where flocculation may begin. Results have also shown that blending diluents of different chemical natures and polarities can enhance viscosity reduction. From these observations, the colloidal description of heavy oils can be extended to diluted heavy oils, considered as solutions of asphaltene particles solvated in diluted maltenes.
An Integrated Reservoir Model for Sand Production and Foamy Oil Flow During Cold Heavy Oil Production
Authors: Wang Yarlong , Chen Carl C. , Dusseault Maurice B. 
Published: December 2007

AbstractContinuous sand production and foamy oil behavior are both believed to be key factors for the enhanced non-thermal fluid production in unconsolidated heavy oil reservoirs in Canada (Alberta and Saskatchewan). The same mechanisms are likely to be active in similar heavy oil strata in Venezuela (Faja del Orinoco), Oman, China (Bohai Bay), and elsewhere. Field experience indicates that fundamental understanding of sand production mechanisms, reservoir fabric alteration, foamy oil behavior, pressure gradient changes, and stress changes are key to successful operations involving massive continuous sanding. Inter-relating these factors requires coupling of geomechanics and fluid flow processes.An integrated approach incorporating a three-phase, three-dimensional black-oil model coupled with a geomechanics model is introduced in this article. Piping channels ("wormholes") are postulated to develop from perforations when pressure gradients exceed the residual cohesion of the sand. An elastoplastic constitutive model is used to describe the reservoir material before seepage forces liquefy and suspend the sand particles at the advancing tips of wormholes. The hemispherical wormhole tip is postulated to propagate as long as a critical tip pressure gradient is exceeded. A slurry transport model is used to describe the flow inside the wormholes. Field data from Frog Lake, Alberta are used to validate the model, and it appears that the simulation can match the field data remarkably well.