bluuebunny/crossref_metadata_2025_split huggingface dataset:
Water-Alternating-Gas Pilot in the Largest Oil Field in Argentina: Chihuido de la Sierra Negra, Neuquen Basin
Authors: Fernandez Righi Esteban , Pascual Mario 
Published: December 2007

Abstract
Two field pilot tests of immiscible water-alternating gas (WAG) injection are being conducted in Chihuido de la Sierra Negra, the largest oilfield in Argentina. Immiscible gas injection technology was selected because of its attractive incremental oil recovery potential for the two main reservoirs in this field. These are mature, waterflooded, undersaturated light oil sandstone reservoirs that are expected to reach a combined ultimate waterflood recovery factor of about 40 % OOIP. Scaled laboratory tests, pilot-scale simulation models, and pilot performance indicate that the immiscible WAG process can be expected to add between 3 and 8 % OOIP due to the contribution of several improved recovery mechanisms, namely oil swelling and viscosity reduction, and waterflood residual oil mobilization in three-phase flow. Another important mechanism that has been cited in immiscible WAG projects is improved volumetric sweep, either because of relative permeability effects or gravity segregation. The latter effect can be advantageous under particular circumstances, such as in clean formations with good vertical communication that may have undergone water underride during waterflood and may thus have unswept oil at the top of the reservoir.
This paper presents a status report on the preliminary evaluation of the performance of the field tests. Although we focus on oil production response and sweep efficiency estimation, a comprehensive view is presented including all the relevant production, facilities, environmental and reservoir engineering issues associated with the pilot tests.
The key to a successful evaluation of the process performance in the field is a quantitative assessment of the incremental oil production, volumetric sweep efficiency and compositional effects. These issues have proved to be more difficult than it was initially expected, due to the particular circumstances of the recent production history of the field and limitations in its routine measurement tools. However, careful data analysis, the introduction of unconventional measurement techniques and the use of numerical simulation have allowed to obtain performance indicators and to estimate the incremental production. These estimations are crucial for the decision analysis of project expansion to field scale, whose economics can be marginal due to high capital and operation expenses.
Water Control in Heavy-Oil Mature Field, Block 1AB
Authors: Sánchez Pedro Zegarra , Delgado Marco Augusto , Quiñones Victor Huerta 
Published: December 2007

Abstract
A water control approach integrating log interpretation, core analysis and production history has been designed and applied to extend life of the very mature heavy oilfields of Block 1AB, located in the Peruvian Jungle. The acquisition of new data, re-processing of old data, the use of new technologies, precisely complemented, by the innovation and experience of a multidisciplinary work team have been crucial towards refining selection of zones with high water production, and stablish a new completion scheme.
It was proposed a methodology consisted of correlating neutron and production logs with core data to update the fluid saturation profile, in order to identify high water cut sands within Main Vivian and Vivian B formations. Also the technique is used to identify silt/shale beds with areal extension, separating Vivian A from B, and thin low permeability sands plugged with kaolinitc matrix within Main Vivian, which are interbedded with the productive sands; those layers are used as seal rocks when redesigning well completion.
Eleven applications in Jibarito, Jibaro and Shiviyacu oilfields were developed during 2005-2006, with successful results. Oil production was instantaneously increased in 947 BOPD, while water production was sustainably reduced in 83647 BWPD. In addition, producing cost was reduced due to lowering energy consumption by means of a reduced pumping requirement, as well as, less water injection volume; diminishing surface water treatment and mitigated environmental impacts.
A Case Study in the Bakken Formation: Changes to Hydraulic Fracture Stimulation Treatments Result in Improved Oil Production and Reduced Treatment Costs
Authors: Phillips Z. D. , Halverson R. J. , Strauss S. R. , Layman J. M. , Green T. W. 
Published: December 2007

Abstract
The Bakken Formation in the Williston Basin has experienced multiple periods of activity and the current level of exploration/exploitation in North Dakota is widespread. The prevalent drilling practices include single and multi-lateral horizontal wellbores requiring hydraulic fracture stimulation to be productive.
Many operators are experimenting with an assembly of completion and stimulation techniques in order to achieve economic production. Knowledge and techniques used in other basins with shale production have been applied with positive results. This paper describes the methodologies applied and subsequent production enhancements.
By changing stimulation techniques and methodologies along with an evolving thought process, economic productivity has been achieved enabling significant development of the resource for the operator.
Contrastive Analysis of the Conventional and Unidimensional Dynamic Modeling Applied in an Oil Field of Eastern Venezuela Basin
Authors: Lopez Sonia , Peron Renato , Selva Carlos , Becerra Gustavo 
Published: December 2007

Abstract
In line with the time available to introduce a development plan for several fields in eastern Venezuela with low reliability in the production data, it was decided to evaluate the remaining power of the field by a dynamic modeling using a one-dimensional simulator (Peron, SPE-94723-PP). During the model development, the analysis showed inconsistencies in the gas production data. The methodology of correction is analyzed in this paper. Production &#45;primary and secondary-forecasts were performed and employed to approve the field operation plan.
After approving the field development plan under this methodology and due to time constraint while the project was being implemented for sands L, M and N (35% of the remaining reserves of the field) a conventional numeric simulation was performed to increase the reliability of the previous forecasts. The conventional simulation considered the original and the corrected production data from the one-dimensional simulation in order to compare the effects in the historical adjustment.
This paper is intended to show a contrastive analysis of the results in both cases. Also, to evaluate the advantages and disadvantages of the one-dimensional simulation methodology defining the parameters that show uncertainty when it comes to analyze a field (size of the aquifer, formation of the secondary gas cap, relevant production mechanism, dispersion level of phases, trend towards channeling and coning).
Marlim Field: Incorporating 4D Seismic in the Geological Model and Application in Reservoir Management Decisions
Authors: Oliveira Rildo M. , Bampi Dirceu , Sansonowski Rui C. , Ribeiro Nier M. S. , Schroeder Johann Paulo R. , dos Santos Marcos S. , Ferreira Deise M. 
Published: December 2007

Abstract
The 4D seismic technology has been successfully applied on numerous brown fields in order to optimize reservoir production and recovery. This paper will describe how we incorporated the 4D seismic results in the geological model and illustrate some applications in reservoir management decisions, thereby mitigating drilling risks in Marlim deepwater turbidite heavy oil field. It will highlight the repositioning of numerous planned wells and the improvement in the history match using the updated geological model.
The Marlim giant field is located on the eastern Brazilian coast in water depths varying from 600 to 1200m (Figure 1). The reservoir is characterized by an unconsolidated sandstone turbidite related to the regressive mega sequence of the Brazilian eastern continental margin. It is the largest producing oilfield in Brazil (production peak: 615,000 bpd in 2002), with the original oil-in-place volume of 6.4 billion STB. Production started in 1991 and injection of water in 1994.
Three seismic surveys cover the Marlim Field. The first one acquired in 1986, the others in 1997 and 2005. The most recent survey was specifically acquired for reservoir characterization and monitoring purposes.
Porosity Variations by Diagenesis in Reservoirs of the Bajo Barreal Formation, San Jorge Basin: Methodology of Evaluation With Logs
Authors: Acosta Néstor , Estrada Enrique , Saavedra B. 
Published: December 2007

Abstract
This work is the result of the authors' several experiences in sandy reservoirs of clay minerals matrix in the San Jorge Basin. It is intended to highlight the advantages of the use of integrated reservoir models originated from the group of ordinary lithologic characteristics among reservoirs, their integration to sedimentary subambients inferred from logs, and high technology log data (spectral gamma ray and magnetic resonance).
The majority of the reservoirs of the Bajo Barreal formation are volcanoclastic sandstones with porosities modified and/or reduced with burial and as diagenesis grades increase. That decrease mainly takes place due to three processes: mechanic compaction, dissolution of grains by intergranular contacts, and pore cementation.
The quantization of the compaction is influenced by the abundance and type of lithic material. The use of technologies that make it possible to have a detailed estimate of the lithology (Spectral Gamma Rays, Lateral Impact and Rotated Cores) is of pre-eminent importance when evaluating that type of reservoirs.
The diagenetic conditions and processes directly affect porosity determination from conventional logs. This justifies the use of porosity tools that are independent from the type of material of the reservoir rock. However, the combination of porosity data obtained in the NMR together with lithologic determinations and appropriate logs results into an interesting alternative to improve the evaluation of sandy reservoirs.
Generally, it is considered that volcanoclastic sandstones have a poor potential as oil reservoirs, because of their low porosity and permeability due to compactational processes and precipitation of authigenic mineral, such as cement. But thanks to the high reactivity of their materials with fluids from the reservoir, secondary important porosities are developed making the reservoir a high quality one. For this reason, these processes can be used to indicate the quality of volcanoclastic sandstones.
The implementation of methodologies, as the ones in this work, endeavors to apply evaluation criteria of sandy reservoirs.
Horizontal Well Completion and Stimulation Techniques—A Review With Emphasis on Low-Permeability Carbonates
Authors: Rodrigues Valdo Ferreira , Neumann Luis Fernando , Torres Daniel , Guimarães Cesar , Torres Ricardo Sadovski 
Published: December 2007

Abstract
This paper presents a brief review of the available techniques in the oil and gas industry to complete and stimulate horizontal wells, with emphasis on low permeability carbonates. These techniques can also be applied in non-conventional reservoirs, particularly in tight formations. The paper starts by reviewing the lessons learned in some chalk fields in the North Sea (Dan, Halfdan, South Arne, Valhall and Eldfisk) and in a few pilot projects offshore Brazil (Congro and Enchova). Based on these lessons learned and in the broad literature, the paper devises some considerations on the methodology to select completion and stimulation techniques for horizontal wells. Cased and cemented horizontal wells, in addition to open hole and perforated/slotted liners wells are addressed. The macro aspects of field/area management are stressed as the completion and stimulation drivers. The key parameters for designing, implementing and evaluating horizontal completion and stimulation are presented, emphasizing the most common failures and the controversial aspects. The paper presents a summary of mature field and new scenarios that are candidate to horizontal completion and stimulation in Brazil and other Latin America countries. Then it makes a few comments on the resources available in Latin America to face the mentioned opportunities and related challenges. It is supposed that this brief review will be useful for the low permeability scenarios in Latin America and worldwide.
Communication Between Perforations: Solution Based on Good Practices and Numerical Simulations
Authors: Morris W. , Robles J. , Zappacosta M. , Bajuk P. , Moreyra J. , Lorenzo E. 
Published: December 2007

Abstract
After almost 200 wells drilled in Cerro Fortunoso and more than 500 in the Barrancas and Ugarteche oilfields, located in Mendoza, Argentina, during the past 20 years, ongoing efforts are dedicated by operator and service companies to solve frequent communication between perforations (CBP) problems. Drilling parameters, well cleaning systems, cement slurries designs and acid stimulation treatments are some of the main aspects that have been reviewed and modified in order to solve this problem. However, random CBP keeps occurring during well completion jobs even when good cement bond logs (CBL) are achieved. The CBP events are typically observed on perforated zones that are separated 10 to 50 m between them, and usually occur either when performing swabbing, while pumping pre-flushes or during the acid treatments. These wells are subjected to high stresses generated by Andina tectonic. Therefore, wells are drilled with deviated trajectories usually up to 40° inclination angle (Cerro Fortunoso).
In order to understand the CBP mechanism several studies were conducted. Image logs to obtain geomechanical properties as well as pumping pressure records and falloff profiles during communication events were analyzed. Interactions between the formation and completion fluids, as well as mechanical stresses numerical simulations of the open-hole and cemented-cased near wellbore conditions were conducted.
The experimental tests performed with rock samples and completion fluids showed no significant interactions that could cause channeling due to formation shrinkage effects. On the other hand, the numerical simulations studies confirmed the data obtained from image logs and geo-mechanical studies, where high shear stresses generate wellbore oversize calipers and breakouts. The simulations also show that high stress levels are transmitted to the cement and the casing, reaching, in some cases their colapse limit. During the last year, CBP problems were diminished by introducing slight changes in the well design, mud density window and by improving casing centralization. Based on the numerical simulation results, the next step consists in using enhanced cement slurries designs with improved mechanical properties, in order to allow near wellbore stress redistribution. All these changes will avoid formation breakouts and cement rupture that could create fractures along the well trajectory, and therefore, will reduce the possibility for fluid communication during well completion jobs.
The Real-Options Approach to Analyze Sequential Investments in Oil and Gas Projects: An Application to Heavy-Oil Production Projects
Authors: Costa Lima Gabriel A. , Suslick Saul B. , Schiozer Rafael F. 
Published: December 2007

Abstract
The largest remaining reserves of heavy oil can be considered an important energy source for future supply. This means that heavy oil is a strategic resource for the future of energy industry. In order to produce these resources, a petroleum company has to invest from exploration to decommissioning, over a time-period that may reach several years.
The problem faced by managers is the correct valuation of sequential investment opportunities whose result will be known only many years ahead. The traditional method for valuation and decision-making is to compute the expected value of the mapped future scenarios with the help of a decision-tree, but its main drawback is that the correct discount rate is hard to estimate because it changes continuously over the nodes of the tree.
In this paper, we use the option-pricing approach, noting that after the success of seismic exploration, management has the option to invest in appraisal whose exercise price is the cost of wildcat wells. After the success of appraisal, management has the option to invest in development and production.
We apply the proposed model to the analysis of investment in a typical petroleum integrated project. We find different results and conclusions from those of the traditional NPV: Increase in the volatility will increase the value of flexibility to adapt the project to new environment;The strategy of carrying out the project in phases can contribute to increase its value;Even if the expected NPV is negative in some stages, the project is still valuable because of the possibility of increase in value of present value of cash flows in the future.
The Application of Stress Corrosion Cracking to Time-Dependent Shale Stability
Authors: Park N. , Olson J. E. , Holder J. 
Published: December 2007

Abstract
Wellbore stability in shale is a crucial issue for drilling in all kinds of environments. The analysis of time-dependent wellbore stability in shales has largely concentrated on the influence of fluid chemistry and filtrate invasion into the formation to predict compressive failure using continuum models. Another possible mechanism for time-dependent behavior is stress corrosion cracking (subcritical crack growth), an important mechanism for the growth of natural tensile and shear fractures. Using discrete element method (DEM) to simulate grain-scale processes, we apply the concept of time-dependent cracking to hole enlargement for vertical wellbores. We use a published example from the North Sea to demonstrate the application of this new modeling approach to hole stability in shale. Laboratory results on rocks indicate a wide range of susceptibility to stress corrosion cracking related to rock petrology and contact fluid chemistry. Using laboratory calibrated rock properties, we run two-dimensional simulations of vertical wellbore stability in shale, where hole enlargement is tracked through time. As a result of stress corrosion cracking, the numerical models show a time-dependent failure history, with an initial stable period of varying duration (influenced by mud weight, rock properties and in situ stress), followed by a brief period of combined shear and tensile failure, ending with stabilization at an enlarged, elliptically-shaped geometry. Time to failure increases with increasing mud weight. Enlarged hole shape changes from elliptical to roughly circular with decreasing stress anisotropy. This new modeling approach for time-dependent wellbore failure can be readily constrained with straight-forward fracture mechanics tests on rock samples, and has the potential to also be applied to time-dependent, intermittent sand or fines generation during production.
Productivity and Drainage Area of Fractured Horizontal Wells in Tight Gas Reservoirs
Authors: Medeiros F. , Ozkan E. , Kazemi H. 
Published: December 2007

Abstract
This paper discusses the performance and productivity of fractured horizontal wells in heterogeneous, tight-gas formations. Production characteristics and flow regimes of unfractured and fractured horizontal wells are documented. The results show that if hydraulic fracturing affects stress distribution to create or rejuvenate natural fractures around the well, productivity of the system is significantly increased. Unless there is significant contrast between the conductivities of the hydraulic and natural fractures, hydraulic fractures may not significantly contribute to the productivity. For extremely tight formations, effective drainage area may be limited to the naturally fractured region around the well and the hydraulic fractures. It is also shown that very long transient flow periods govern the productivity and economics of fractured horizontal wells in tight formations. The results of this study are also applicable to oil production from fractured shale.
Drilling Fluids Rheological and Volumetric Characterization Under Downhole Conditions
Authors: Demirdal B. , Miska S. , Takach N. , Cunha J. C. 
Published: December 2007

Abstract
Accurate estimation of equivalent circulating density (ECD) and circulating bottom hole pressure (CBHP) are essential components of successful managed pressure drilling operations. Normally, calculated frictional pressure losses do not match actual frictional losses recorded during drilling operations. Discrepancies between calculated and measured pressure losses are more severe in operations where synthetic based drilling fluids are used because synthetic based drilling fluid rheologies vary with changes in downhole conditions.
In order to deal with differences between actual and theoretical pressure losses, rheological and volumetric characterization of the fluid under downhole conditions was performed. N-paraffin-based drilling fluid (NPDF) was used in this study.
Effects of pressure and temperature under HPHT conditions were determined using a mercury-free PVT cell. The volumetric behavior of the NPDF was compared with the behavior of water-based muds and less toxic mineral oil-based muds. An empirical relation for density as a function of pressure and temperature is introduced.
In addition, rheological characterization of the NPDF was conducted using an HPHT rotational viscometer. The rheological model that defines the shear stress – shear rate relation of the drilling fluid used in this study at all pressure and temperature conditions is the Yield Power Law model. The effects of downhole conditions on the rheological parameters consistency index (K), flow behavior index (n) and yield stress (τo) are analyzed.