bluuebunny/crossref_metadata_2025 huggingface dataset:
Hybridizing Genetic Algorithms and Real Options to Approach of the Optimal Decision Rule for Oilfield Development Under Uncertainties
Authors: Lazo Lazo Juan G. , Pacheco Marco Aurélio C. , Vellasco Marley M. V. R.
Published: December 2007

A decision to invest in the development of an oil reserve requires an in-depth analysis of several uncertainty factors. Such uncertainties may involve either technical uncertainties related to the size and economic quality of the reserve, or market uncertainties. When a great number of alternatives or options of investment are involved, the task of selecting the best alternative or a decision rule is very important and complex, due to the considerable number of possibilities and parameters that must be taken into account. This paper proposes a new model, based on Real Option Theory, Genetic Algorithms and Monte Carlo simulation, to find an optimal decision rule for alternatives of investment regarding the development of an oil field under market uncertainty. The objective of this new model is to help decision-making in the following situation: immediate development of a field or wait until market conditions are more favorable. This optimal decision rule is formed by three mutually exclusive alternatives, which describe three exercise regions through time, up to the expiration of the concession of the field. The Monte Carlo simulation is employed within the genetic algorithm to simulate the possible paths of oil prices up to the expiration date. The Mean-Reversion Process is assumed as the stochastic process for the oil price. A technique of variance reduction was also used to improve the computational efficiency of the Monte Carlo simulation.
Look Ahead VSP, Inversion, and Imaging from ZVSP and OVSP in a Surface Basalt Environment: Neuquen Basin, Argentina
Authors: Rodríguez Aias Leonardo , Galaguza Mario , Sanchez Adrian
Published: December 2007

In order to improve the seismic imaging and delineation of a reservoir, an OVSP was run in an exploratory well; Neuquén Basin; Argentina. A second purpose of this acquisition was to accurately locate an Intermediate Casing above the main target. Acoustic Impedance Inversion of the corresponding Zero Offset VSP plus the image interpretation generated from the OVSP data helped to define the position of a sill, which was one of the objectives in this project.

The thick (hundreds of meters) and extensive Auca Mahuida volcanic complex which covers most of the region, considerably reduces the signal to noise ratio of the seismic data; strongly attenuating the high frequencies of the data due to wavefields dispersion, hampering their separation at the processing stage. This effect is stronger in surface seismic than in borehole seismic, due to greater offset and two-way traveltime, so that VSP is used as a tool in this environment. Therefore, Q factor estimation (and consequently Q inverse filtering application) computed directly from Zero offset VSP, is a very valuable technique which allowed us to recover high frequencies in the field area improving vertical seismic resolution and helped to define the reservoir with greater accuracy.

An acoustic impedance inversion of the VSP trace was later obtained, and its interpretation was very useful to predict impedance variations, related to lithology and formation changes in the deeper portion of the stratigraphic column. This was the first deep exploratory well (4750 meters) in this part of the basin, so the implemented technique led to define deep formation tops.

The acquisition was performed by Schlumberger using the multilevel 3C high-fidelity downhole tool, Versatile Seismic Imager (VSI). It was used two vibrators simultaneously in flip-flop configuration for both source positions in order to reduce the operational time.
Increase Heavy-Oil Production in Combustion Tube Experiments through the Use of Catalyst
Authors: Ramírez-Garnica M. A. , Mamora D. D. , Nares H. R. , Schacht-Hernández P. , Mohammad A. A. , Cabrera-Reyes M. C.
Published: December 2007

In this research a catalyst was evaluated in a combustion tube using heavy oil from Gulf of Mexico. The underlying objective is to increase the mobility of the oil inside the reservoir by effect of the catalyst during the combustion.

The catalyst, used in the experiments was previously mixed with heavy crude oil of 12.5 °API. The catalyst, in liquid phase, is based in Molybdenum, Cobalt, Nickel and Iron. This organometallic catalyst is highly soluble and ultradispersed, and it was mixture with heavy crude oil with a concentration of 750 ppm wt.

The porous media used in the combustion tube was a triturated dolomite carbonated rock with a 41.9% of porosity, and a particle size of 0.42 mm. This rock was used for two experiments at the same saturation conditions: heavy crude oil (23.79%), and water (25.26%).

The results obtained shown the advantages of use of catalyst in relationship of a conventional combustion as follows: (1) oil production increases, (2) faster combustion front, (3) higher efficiency in the combustion, and (4) higher temperatures at the beginning of the combustion.

The use of this kind of organometallic catalyst at low concentrations is a potential application in order to upgrade the oil properties in-situ, saving the cost of facilities on surface required for the same purpose.
Optimization of Cyclic Steam Stimulation Under Uncertainty
Authors: Revana K. , Erdogan H. M
Published: December 2007

Heavy Oil is an increasingly important resource for securing future energy supply as conventional resources are depleted. The recovery of this resource is associated with high fixed capital investments. The underlying economics for developing heavy oil are heavily dependent on market demand and price of oil & gas1. On the upside, the geologic risk associated with the recovery of this resource is minimal and the in-place quantity is three times the combined world reserve of conventional oil and gas2.

Field development decisions must be made despite uncertainties of oil and gas price, well performance, facilities costs, and downstream demand. Several conventional thermal methods exist to recover heavy oil such of steam floods, cyclic steam stimulation and SAGD.

Cyclic Steam Stimulation represents a widely used thermal recovery process that can be optimized to achieve higher oil recovery. This paper presents a workflow for coupling physics based reservoir simulator with an economic model to optimize the hydrocarbon recovery under uncertainty. In this work, a synthetic single well heavy oil reservoir model was generated and coupled with a spreadsheet based economics model to understand the synergies between the two domains.
Rubiales Oil Field: A Heavy-Oil Colombian Example of Excellent Operative PCP Systems Development
Authors: Rubio C. A. , Doval J. M. , Medina J. A.
Published: December 2007

Rubiales is an oilfield located in Llanos Orientales Basin (Colombia) where was installed first PCP system in 2003. At the present, Meta Petroleum Limited, a private company in growing, established in our country, operates this oilfield.

From their beginning in Rubiales field there were 23 wells with PCP Systems of which today in day prevail 12 of them, operating under stable production conditions represented in an important volume portion of total recovered crude volume at oilfield. Some of these conditions are for example, torque, water cut (BS&W %) and each well fluid level, all them features that helping reservoir production mechanism.

This oilfield produces heavy oil (12,3 °API @ 60 °F) with high water cut (Rubiales’ average BS&W = 81%) in emulsion state that indirectly has allowed an excellent development of PCP Systems, description that constitute the main objective of this article because in this application the PCP System is featured for long run lives (over one thousand days of average).

Additionally is good to emphasize, MTBF (measured time before fail) of Rubiales’ PCP Systems like a good parameter to show into wide world petroleum industry in situations to choose any artificial lift system in oilfields with similar features that Rubiales. Also several wells have supported organic treatments in some cases during this time (applying dimethylbenzene) and operating at high velocities, keeping stable production tendency and registering a minimum quantity historically from interventions to wells by reason of fails in the systems.

To finish, in this writing are described components of these systems (showing main operation parameters), type of produced fluids, oilfield generalities, identified wells with best production developments and occurred fails, information translated in a strong evidence to reach the objective of this document.
Case Study: Application of a Viscoelastic Surfactant-Based CO2-Compatible Fracturing Fluid in the Frontier Formation, Big Horn Basin, Wyoming
Authors: Bustos O. , Chen Y. , Stewart M. , Heiken K. , Bui T. , Mueller P. , Lipinski E.
Published: December 2007

CO2 based fluids are commonly used to fracture stimulate formations with low reservoir pressure as well as formations that are more sensitive to water treatments (high capillary pressure, swelling clays etc). In particular, the Frontier Formation located in Bighorn Basin, Wyoming, has seen a variety of stimulation fluids used over the past years with varying degrees of success. When dealing with water sensitive formations, a common practice has been to use oil-based fluids. However, fluids of this nature can have detrimental effects on gas zones with low reservoir pressure and this might be the reason for erratic well performance of previously treated Frontier completions. It has also been determined that oil-based fluids can alter the reservoir wettability and hence cause formation damage. With this in mind and considering the environmental and economical benefits of using a water-based fracturing fluid, a novel visco-elastic surfactant based, CO2-compatible, high foam quality (>60%) fluid was proposed as the main fracturing fluid. This paper will discuss the first application of this visco-elastic based fluid on wells in Park County, Wyoming.

This paper will discuss stimulation with the new fluid and how pin-point pressure measurement enabled the operator to make informed decisions to define fracturing/completion strategy. We also present the additional benefits of incorporating existing dipole sonic tool information to calibrate "in-situ" stress, Young's Modulus and Poisson's ratio. Finally, a production history match is conducted on wells treated with the new fluid.
Lessons Learned From Modeling Hydraulic Fracture Treatments in Coals Using a Fully Functional Three-Dimensional Fracture Model in a San Juan Basin Project
Authors: Ramurthy Muthukumarappan , Lyons Bill
Published: December 2007

The two main objectives of using a hydraulic fracture model in coals are: (a) optimization of job design and placement, and (b) post-fracture diagnostics. Though certain limitations still exist, hydraulic fracture modeling in coals has undergone major advancements in the past decade. Pseudo or lumped three-dimensional (3-D) models have usually been employed to try and meet the objectives mentioned above. The effectiveness of using such models in coals has been very limited. Fully functional 3-D models are currently available in the industry and can be used to obtain better estimates of the fracture dimensions. This paper shows that a grid-oriented fully functional 3-D fracture simulator with shear decoupling can be especially useful in coals for post-fracture diagnostics if sufficient input data can be fixed from logs and Diagnostic Fracture Injection Tests (DFIT).

When problems occurred with placement of fracture treatments, especially in the upper Fruitland coals of a San Juan basin project, instead of experimenting with various ideas arbitrarily, technical evaluation using DFIT data and fracture modeling with a grid-oriented, fully functional 3-D fracture simulator, was used to pin-point the issues and address them accordingly. This paper will discuss the deficiencies of using 2-D and pseudo-3-D fracture models in coals and also will discuss the lessons learned from using a grid-oriented, fully functional 3-D fracture simulator in this project along with the successful implementation of the results developed from the modeling work.
Fiber-Laden Fracturing Fluid Improves Production in the Bakken Shale Multilateral Play
Authors: Powell A. , Bustos O. , Kordziel W. , Olsen T. , Sobernheim D. , Vizurraga T.
Published: December 2007

Since the horizontal lateral Bakken dolomite play began in 1999 in eastern Montana, more than 330 wells have been permitted and more than 200 wells are now producing. The lateral play began in Richland County, Montana, and the success there is now accelerating the transfer of technology to the North Dakota side of the Bakken trend and is attracting several new and existing operators to the area. Different drilling and completion techniques have been tried since the start of the play with different degrees of success.

In June of 2005 a new technique was introduced utilizing chopped fibers within the fracturing gel slurry to help suspend proppant in the slurry both during the fracture pumping and also during fracture closure. The primary goal was to be able to create a more even distribution of proppant in the created fracture while reducing the polymer requirement for the fracturing gel slurry. A secondary goal was to use slugs of the fiber to bridge at the fracture entry face and divert the treatment into new fracture planes, thereby improving the completion efficiency of the treatment. Lastly, it was hoped that the introduction of the fiber, which would dissolve shortly after placement, would improve proppant retention within the hydraulic fracture and impede flowback into the horizontal leg of the wellbore.

The results from this new technique have been encouraging; with an estimated 24% improvement in average well productivity since the fiber designs have been implemented. Additional benefits have been realized like elimination of chokes cutting out due to sand production and associated wellbore fill clean out, lower polymer requirements reducing gel costs, and a reduction in premature screenouts.
Forecasting Oil Production in Waterflooded Reservoirs
Authors: de França Corrêa Antonio Cláudio
Published: December 2007

A three-parameter model relating the decline of the oil cut with the fractional oil recovery for waterflooded petroleum fields or reservoirs is described. The model is based on observation of the behavior of several Brazilian oil fields, in which the oil displacement occurs either by water injection or by natural aquifer influx, or both.

The model is used to derive equations to forecast the oil and water production rates in waterflooded systems. These equations may also be used to design a waterflood expansion in any phase of a field's life.

An example of the application of the model equations to forecast the behavior of a waterflood in a mature heavy oil field is presented. Because the results of the analysis indicated that the field will still be profitable at the end of the concession period, the model equations are applied to design and forecast an augmented waterflood for the field.

The model equation may be used to estimate the oil reserves at any stage of maturity of an oil field.

The model parameters are obtained by fitting the model equation to historical field data by means of a least square algorithm. A type-curve procedure is applied to obtain the initial guesses of the model parameters required by the mathematical algorithm.

A relation between the oil cut decline model and the classical rate-time decline is derived for the case in which the total liquid flow rate is constant.

Examples of oil cut decline of several Brazilian fields are presented and the decline model is used to determine the ultimate oil recoveries of these fields. The ultimate oil recovery is proportional to the amount of water produced during the field's life, which is related to the water-oil ratio at abandonment conditions.

When the operating conditions of a field change, so does the oil-cut decline trend. An example of the change in the oil-cut decline trend is presented for a heavy oil field submitted to a late steam drive.
Estimating Critical Velocity to Prevent Bed Development for Horizontal-Inclined Wellbores
Authors: Ozbayoglu Evren M. , Saasen Arild , Sorgun Mehmet , Svanes Kare
Published: December 2007

Hole cleaning is one of the major considerations at both design and application stages for a drilling operation. This concept is more emphasized as the wellbore inclination is high, and the size of the wellbore flow area is lower. Especially at horizontal or high inclinations, if the fluid velocity is lower than a critical value, a stationary bed develops, which may cause various problems such as high drag, higher probability of pipe stuck, higher hydraulic requirements, etc, if not removed properly. Therefore, it becomes important and essential to identify the critical velocity. This study aims to estimate the critical fluid flow velocity for preventing the development of a stationary bed using empirical correlations that can be used easily at the field. Also, a rough estimation of bed thickness is also introduced if the flow velocity is lower than the critical velocity. For this purpose, extensive cuttings transport experiments with water have been conducted at Middle East Technical University, Petroleum and Natural Gas Engineering Department, Cuttings Transport Flow Loop for various inclinations, flow rates and rate of penetrations. The inner pipe is subjected to a sagging, therefore, more realistic annulus representation is achieved. Observations showed that, a stationary bed can be developed even the inclination of the wellbore is down to 50 degrees. Results showed that, the critical velocity could be estimated using the proposed correlations with a reasonable accuracy when compared with the experimental results. Also, for flow velocities less than the critical values, the thickness of the stationary bed can be detected within an error range of ± 10%.
An Engineered Fiber for the Fracturing of Unconsolidated Sand in Highly Deviated Wells in the Tali Field of Brunei
Authors: Law Matthew , Chao George W. , Alim Hafeez A. , Hashim Ahmad F. , Samuel Elsamma , Samuel Mathew
Published: December 2007

This paper discusses the application of fibers for the Frac and Pack application for Brunei Shell Petroleum (BSP). Seven wells with a total of seventeen fracturing treatments in this study are on a multilayered unconsolidated formation, where sand control is a part of well management during the production life of the wells. Previous techniques of open hole external gravel packing and cased hole Internal Gravel Packing (IGP) for controlling formation sand were challenged by reduced flow efficiency of the wells. The recent development of Expandable Sand Screen (ESS) combined with fracturing treatment could not control produced sand, due to failure in perforation techniques. An improved idea of perforating only the lower side of deviated wells using minimum viscosity fluids and minimum amount of pad with limited proppant sand concentration resulted in low net pressure build up.

These challenges were prevailed over by the application of a new fiber technology in which fiber is used (1) to transport higher sand concentration to the fracture, and (2) to control the sand flow back during production as well. Since this technology is physical rather than chemical, the proppant flowback is controlled without specific shut-in time, temperature, or pressure constraints. The use of fiber technique prevents sand falling down from perforations and ensures the ESS running smoothly. This technique enabled Brunei Shell Petroleum to cost effectively complete the highly deviated wells with stimulation and sand control. In presence of the fiber, higher proppant concentrations upto 9 ppa could be used successfully even with linear guar gel. This promotes the net pressure build up which is vital for fracturing treatment in high permeability reservoir. Eleven fracturing treatments on five different wells have been performed with excellent results.
Evaluating Reservoir Production Strategies in Miscible and Immiscible Gas-Injection Projects
Authors: Farzad Iman , Amani Mahmood
Published: December 2007

Successful design and implementation of a miscible gas injection project depends upon the minimum miscibility pressure (MMP) and other factors such as reservoir and fluid characterization. The experimental methods available for determining MMP are both costly and time consuming. Therefore, the use of correlations that prove to be reliable for a wide range of fluid types would likely be considered acceptable for preliminary screening studies. This work includes a comparative evaluation of MMP correlations and thermodynamic models using an equation of state by PVTsim1 software. We observed that none of the evaluated MMP correlations studied in this investigation is sufficiently reliable. EOS-based analytical methods seemed to be more conservative in predicting MMP values. Following an acceptable estimate of MMP, several compositional simulation runs were conducted to determine the sensitivity of the oil recovery to variations in injection pressure (at pressures above, equal to and below the estimated MMP), stratification and mobility ratio parameters in miscible and immiscible gas injection projects. Simulation results indicated that injection pressure was a key parameter that affects oil recovery to a high degree. MMP determined to be the optimum injection pressure. Stratification and mobility ratio could also affect the recovery efficiency of the reservoir in a variety of ways.
Use of Single-Step 9% HF in Geothermal Well Stimulation
Authors: Rae Phil , bte Ahmad Atikah , Portman Lance , Acorda Edgar Paul
Published: December 2007

Geothermal wells represent an important source of energy in many parts of the world, yet they receive little attention in the mainstream literature. Annual worldwide production of geothermally-derived electrical power is some 57000 GWh from 8900MW of installed capacity and Philippines is the second largest producer with almost 2000MW of capacity.

In general, geothermal wells produce steam, generated by the contact of water with hot metamorphic rock, and this is used to drive turbines for electricity generation. Geothermal fields usually comprise both production, and injection, wells and, like oil and gas wells, these can suffer from production (or injection) impairment. The most common forms of impairment in geothermal wells are mineral scales dissolved in the hot water and then deposited as a result of thermal disequilibrium or phase changes. Many mineral species can be present, depending on rock composition and injection water quality, but one of the more prevalent is silica (SiO2). Normally, such mineral deposits are removed, periodically, by acidising with combinations of hydrochloric and hydrofluoric acids.

This paper describes work performed on geothermal wells in Philippines in early 2006. Laboratory testing demonstrated that acid formulations with 3-6% HF, as had been used historically, were capable of dissolving only a fraction of the scale deposits, even with a large stoichiometric excess of acid. Surprisingly, increasing the HF concentration to 9%, in a specially buffered acid system, resulted in total scale dissolution, in laboratory tests. Furthermore, the high silica content of the scale, absence of problematic minerals in the formation and fractured nature of the reservoir, persuaded us to eliminate the HCl preflush on these treatments, a novel concept that had never been tried in Philippines.

The application of this system in the field posed some special technical and HSE challenges. However, all the treatments were carried out safely and successfully, without incident, and with excellent results as briefly described in this paper.
Bayesian Characterization of Subsurface Lithofacies and Saturation Fluid
Authors: Teixeira Raquel , Braga Igor , Loures Luiz
Published: December 2007

Bayesian decision theory is a statistically based theory that is used to assess the degree of certainty and the potential costs when making decisions. This paper presents a methodology, based on the Bayesian decision theory, used to infer subsurface lithofacies and saturation fluid by integrating different data sources, such as well logs data and seismic attributes, which are derived from an elastic seismic inversion. This methodology was applied on a data volume from an offshore Brazilian field to generate, as a final product, a lithofacies model and a fluid indicator for this field. Uncertainty quantification of the models was also analyzed at this work.

To infer the subsurface lithofacies, the existing facies were identified from well logs data, using the expectation-maximization (EM) algorithm. This step defines the lithofacies behavior in seismic attributes domains through the use of probability density functions (PDF). Next, the subsurface lithofacies were classified by applying the maximum posterior probability (MAP) classification, using the seismic attributes as input and the PDFs computed previously. The environment was divided into cells, then the probability and uncertainty was assessed to infer the lithofacie for each cell.

After inferring the subsurface lithofacies, the fluid was inferred for the cells identified as reservoir lithofacies. Assuming an oil-water system, the fluid substitution theory and the Bayes theorem were applied to the well log data to determine the PDFs for each scenario. Following the Bayesian decision theory, the most likely fluid and the associated error was determined for each cell identified as reservoir.
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

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

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

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

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 -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

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

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

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

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

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

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

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

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.