bluuebunny/crossref_metadata_2025 huggingface dataset:
Risk Analysis Speed-up with Surrogate Models
Authors: Amorim T. , Schiozer D. J.
Published: April 2012

Risk analysis is crucial in investment decisions. A more accurate risk analysis for a field development study can demand a large number of simulation runs, which can lead to high computational time. Some techniques have been developed to reduce the number of runs, such as experimental design with surface response methodology. One problem usually associated with this technique is the possibility of lower reliability associated with complex problems. Furthermore, they might not properly represent the problem when there are changes in the uncertain parameters, in this case a complete restart in the process may be necessary. An alternative is proposed here through the use of fast surrogate simulation models that generate results similar to the base model, even with changes in the reservoir attributes.

The surrogate simulation model has the same data as the base simulation model, but with a much coarser grid. The coarse grid parameters are adjusted automatically with a gradient-based optimization algorithm, minimizing the difference between the responses from the base and the surrogate models. Due to the large number of variables to adjust, several techniques were incorporated in the optimization algorithm: simultaneous perturbation stochastic approximation, response surface methodology and data partition. After this adjustment, a risk analysis can be conducted with the surrogate model.

Simulation models were constructed to test the results generated with the proposed surrogate model methodology. Sensitivity analysis for several factors has shown acceptable adherence of the coarse and base models. A risk analysis was conducted with both coarse and base models, the results generated with the coarse models were close to those with the base models. Overall, the time spent in adjusting the coarse model and generating responses for the risk analysis was smaller than directly using the base model in a risk analysis.

The main contribution of this work is to develop a methodology to construct fast surrogate models and to show that they can help to reduce the time needed to build a risk analysis, generating results that are similar to the full simulation model.
Royalty and Tax versus Production-Sharing Petroleum Fiscal Models: An Analysis of Risk and Return of the Optimal Production Strategy Applied in Brazil
Authors: Ravagnani A. T. , Lima G. A. , Barreto C. E. , Munerato F. P. , Schiozer D. J.
Published: April 2012

Brazilian Government has proposed a change in the current fiscal regime because of the recent discoveries of large oil reserves in Brazilian pre-salt areas, from royalty/tax system to production-sharing contracts. Implementing the production-sharing system, the government believes that this is the best policy to increase gains to be transferred to society. Although, the production-sharing system is not currently clearly defined in Brazil, some debates among companies and government are occurring. Some questions may arise when comparing royalty/tax and production-sharing contracts under the company's point of view: 1) Are the appropriate oil exploitation strategy different for each fiscal model regarding configuration of wells? 2) What are the risk and return created by each fiscal regime for companies? The aim of this paper is to present a comparative analysis considering risk and return of the optimum exploitation strategy for both systems, regarding number of injectors and producers and their allocation in the reservoir. The methodology consists of: (1) selection of a typical oil field from pre-salt area; (2) optimization of an oil exploitation strategy through reservoir simulation aiming to maximize company NPV for a single deterministic scenario for each fiscal system; (3) modeling of uncertainty in oil price, capital and operating costs etc. (4) Monte Carlo simulation and quantification of risk and return (Expected Monetary Value, EMV) of royalty/tax and production-sharing systems (5) sensitivity analysis of parameters of major interest. Results indicate that the optimal production strategy to maximize NPV is different for each fiscal system. The uncertainties in the economic scenario considered in this work influence the EMV significantly. Moreover, it is also important the cost structure of the oil field and how production is shared between the parts involved over time.
First Three Surface Casing While Drilling Operations in Brazil Demonstrate Technical Feasibility in Loss Circulation Scenarios
Authors: Plácido J. C. , Fonseca C. E. , Araki N. , Desousa J. H. , Thomson I. J. , Krasuk R. , Almeida J.
Published: April 2012

Historically, casing while drilling (CWD) has not been largely deployed in Brazil land operations due to inconsistent results achieved in the past and also due to the lack of a clearly identified technical need.

In some onshore fields located in the Northeast of Brazil, total or partial mud losses in many shallow surface sections, make those sections very expensive to drill. Apart from the large volume of mud required when lost circulation occurs, which heavily impacts the operation logistics, and the cost associated with remedial actions such as cement plugs and lost circulation materials, HS&E risks are typically the major concern. To validate a technically viable casing while drilling solution with a non-retrievable bit, a series of three surface hole sections were drilled through this severe lost circulation zone.

This paper will describe the planning, implementation, results and lessons learned from the first three surface non-retrievable CWD onshore operations done in Brazil. These wells were drilled by land rigs equipped with a kelly and the operations were performed with specialized 12 1/4-in non retrievable casing bits and 9 5/8-in surface casing. It is important to mention that to perform these operations did not require any modification to the rigs.

The results showed that the casing while drilling technique has considerable applicable in surface sections that are Polycrystalline Diamond Compact (PDC) drillable and where fluids losses make conventional drilling practices difficult or expensive. However, in those applications the casing bit design must be tailored to drill efficiently through the medium to hard tophole carbonates, to ensure reaching the desired casing point.
Modeling and Analysis of Temperature Transients Caused by Step-Like Change of Downhole Flow Control Device Flow Area
Authors: Silva Junior M. F. , Muradov K. , Carvalho M. S.
Published: April 2012

Evolution and wide-spreading of downhole monitoring systems has increased a lot over the last few years. Particularly downhole temperature data has been recognized as an important input for real-time production optimization. Whereas distributed temperature analysis and interpretation are the only methods used now, temperature evolution with time offers an excellent new source of information not yet fully understood. Simulation and analysis of temperature transients in wells are therefore a promising research area at the initial stage of development.

Near wellbore multiphase flow simulation considering heat transfer is not a simple task. There are aspects such as wellreservoir mutual influence where transient analysis needs to be considered. Neglecting thermal effects and completion design will result in inaccuracies of the physical phenomena representation.

This paper describes a non-isothermal dynamic well-reservoir simulator taking into account the presence of flow control valves in the wellbore. A fully coupled approach was used to solve the problem. The proposed model studied is two dimensional for the reservoir and one dimensional for the well. The reservoir is considered homogeneous, anisotropic and two -phase (oil/water or gas/liquid) saturated with the initial pressure above the bubble point. The well is vertical and the multiphase drift-flux model considering the radial influx is used to describe the flow in the wellbore.

Case studies for three-zone intelligent wells are analyzed from transient temperature profiles generated by the simulator. A single phase is used as a base case for the two-phase case. This paper shows that temperature transients from a step-change in production rate are able to provide full well-test equivalent information about each production zone. A downhole flow control valve step-change is also analyzed as a feasibility study of a well test without zonal shut-in. Restrictions of the simulator are presented and discussed for an appropriate use of the results.
Fracturing With Viscoelastic Surfactant Fluid in Cyclic Steam Injection Wells - A Synergy for Heavy Oil Recovery
Authors: Gomez J. , Morles H. , Toyo D. , Bracho J.
Published: April 2012

Unconventional oil sources have became one of the most important keys for maintaining the world energy supply. Considering the increasing contribution of the crude below 15 deg. API in the worldwide oil reserves, one aim should be technology development to improve oil production and increase reserves recovery from such reservoirs.

One of the most used technologies in hydrocarbon recovery is hydraulic fracturing. On the other hand, cyclic steam injection is a widely used technique to improve recovery from heavy oil reservoirs.

This paper describes an example where hydraulic fracturing using anionic viscoelastic surfactant fluids has been combined with cyclic steam injection to synergistically improve production results in a mature heavy oil field. After several years of performing these treatments, this synergy has led to larger heating coverage and therefore improved viscosity reduction of the crude; higher than 100% regained permeability; creation of a very low-viscosity dispersion of the oil in water; and asphaltene dispersion.

Such findings are supported by laboratory testing results and backed by post-treatment production results in the heavy oil reservoir where this fracturing campaign was performed and the results analyzed.

The observations in the laboratory, their analysis, and the match with field data demonstrate that combining a properly designed stimulation treatment using anionic viscoelastic surfactant with steam injection have led to significant improvements in the stimulation of this heavy oil reservoir. They also show that such results are applicable to other reservoirs where high-viscosity reservoir fluid is a challenge.
Production Logging During Shut-In To Characterize Water Production in Vertical Wells With Multizone Completions
Authors: Sampaio Tiago Pitchon , Morosov André Luís , Camargo Christiane de
Published: April 2012

An ultra-deep water depth giant oil field located in Campos Basin, Brazil, has been produced for over 10 years on turbidite reservoirs. Some wells with multizone completions and very long flow production lines have problems of hydrate formation, especially after a shut down.

The water cut increasing pattern suggests that one specific zone is responsible for this fluid production, but it is very difficult to identify which is the right one. In order to calibrate the simulation model and reduce the risk of hydrate formation by closing this zone, a production logging campaign was designed. The logging campaign was performed with the wells shut-in as the flow could not be processed to the workover rig because it has not the capacity to process the high volume of water, neither to the production unit, as it has a history of hydrate formation during such operations.

The well A (W-A) has been shut-in for 2 months due to a hydrate formation problem before the start of the production logging. As the difference in static pressures between zones was large, the PLT was conclusive and the crossflow rate of water was calculated. Another PLT was run in well B (W-B) after the first one with the same success. But, in this case, the well has been shut-in just before the workover rig arrived.

The running of production logging tools in closed wells with multizone completions in turbidites reservoirs has proven to be a good way to indentify the water origin in a safe and low cost way. The experience can be reproduced in other fields with same characteristics.
Models for Estimating the Shrinkage Factor in the Mixtures of Diluents with Colombian Heavy Crude Oils
Authors: Arenas F. Guarin , Garcia C. A. , Chinome L. M.
Published: April 2012

The production of heavy and extra heavy crude by dilution with lighter hydrocarbons produce volumetric differences, which are associated to diluent losses attributed to volatilization phenomena. This article present results of the production data analysis from different fields of heavy and extra Oil in Colombia, where the assessment of models for determine the shrinkage factor in mixing process of heavy crude oil with diluents were incorporated.

To develop this work, a model to predict the volume shrinkage occurring in heavy light oil mixtures was defined. The analysis was conducted with 25 types of crude oil and 11 diluents, their mixing properties of viscosity and API gravity were measured and calculated. Several authors have proposed models to determine shrinkage factor (Erno, Booker and API). Those models were evaluated with production data, then using multivariable regression techniques an adjusted model was proposed, Results shown the fraction of diluent and the value of the difference between the inverse of the densities of oil and diluent are the important variables in this new model. \Finally the model was incorporated in the volumetric production balance of these fields.
A Procedure for Upscaling a Complex Fractured Reservoir using Near-Well Refinement
Authors: Correia Manuel G. , Maschio Celio , Schiozer Denis J.
Published: April 2012

Classical fracture upscaling techniques are usually based on numerical or analytical solutions which can present some problems to capture the near-well flow behavior, leading to wrong well productivity index. In addition, grid cell size must be chosen carefully to maintain both connectivity and permeability tensor of fracture network in a reasonable simulation computational time. This paper proposes a near-well refinement in conjunction with a classic fracture upscaling technique in order to improve the accuracy of well productivity. The matrix porous media is respected to a microbial carbonate reservoir where discrete fractured network is composed by diffuse fracture pattern (small-scale fractures) and sub-seismic conductive fractures that strongly affect fluid flow. Fracture network density was defined using lithology as control driver. In this work, a dual-porosity system with a block cell size smaller than diffuse fractures was used as reference model (fine grid) for the upscaling method due to its quality to reproduce properly the connectivity between diffuse and sub-seismic fractures. The fracture upscaling method based on Oda's solution (Oda, 1985) was applied to a coarser model defined by near-well refinements, which capture the fine grid fracture properties near-well. Homogeneous petrophysical matrix is applied in order to isolate the matrix heterogeneity effects. It was possible to adjust the main reservoir parameters (field average pressure, oil recovery factor and water cut) and advanced water front. The fine grid simulation time was drastically reduced using the proposed procedure.
Filtering of Tide Effects in Formation Evaluation Data
Authors: de Araujo Marco Aurelio , Campos Wellington , Moreno Rosangela Barros
Published: April 2012

In this work, a method is proposed for filtering the data recorded in formation tests and subtract the noisy parcel due to the tidal effects. The tidal effects originate on the variation of the gravitational potential applied to the reservoir as the moon and the sun change their position in space. This phenomenon, named tidal effect, can be observed when measuring the pore pressure of any accumulations of fluids in the pores of rocks in the underground, including petroleum reservoirs. Tidal effects were observed in petroleum reservoir pressure tests by the mid-seventies and a correlation between the amplitude of the tidal effect and the reservoir parameters were noted. From Biot poroelastic theory, methods were developed, using the tidal effect, to evaluate reservoir parameters such as compressibility, porosity, permeability. The selective extraction of the tidal effect is an important part of these methods. Fourier transform appears as great resource for this purpose, since the tidal effect is a sinusoidal signal with well-known component periods. The selective extraction of signals using the Fourier transform can also be important to assist in the determination of reservoir parameters, since the presence of the tidal effects may prevent or hinder the interpretation of the formation test from the diagnostic log-log plot. This paper shows the Fourier transform application to extract noise and tidal effect observed in formation evaluation data. The Fourier transform techniques were successfully used in three set of data recorded in formation tests performed in offshore wells.
Improved Heavy Oil Recovery by Drilling Horizontal Wells in Rubiales Field, Colombia
Authors: Anaya A. Florez , Paz Y. Araujo , Rivas M. Uzcategui , Moreno W. Parra , Quinones R. Lavado
Published: April 2012

The purpose of this paper is to report the methods used and results of the Rubiales Field development, located onshore in "Los Llanos" Basin in Colombia. Horizontal well technology was used to drill through unconsolidated sandstones with an active and strong aquifer, under primary heavy oil depletion with an oil gravity ranging from 11.3 to 14.4 °API. Horizontal wells allow oil production rate increases, water production delays, oil recovery factor increases, and sand production decreases.

The Rubiales Field has an OOIP of 4,608 million STB oil, and a wide reserves volume of 385 million STB oil was certified in June 2011 with horizontal well technology. On 31 December 2011, the cumulative oil production of the field was 163 million STB oil (3.7% recovery factor). Currently, the oil production rate is 180.3 thousand BOPD, of which 159.6 thousand BOPD (88.5%) come from horizontal wells.

The actual operator company has implemented an aggressive campaign, drilling over 296 horizontal wells from 2006 to 2011. Since 1981, 202 vertical wells and 7 deviated wells have been drilled. In Areniscas Basales Unit, the average production rate reached a peak of over 2,000 BOPD for each completed horizontal well. This production rate is almost 7 times that of the neighboring vertical wells production.

The placement of the producer horizontal wells has been optimized in the Rubiales Field in locations where the net pay is less than 30 feet by implementing the use of the azimuthal resistivity log, which allows for real-time mapping while drilling up to a distance of 20 feet. In December 2011, 27 horizontal wells were drilled using this technology. The global production rate for these wells is currently 17.5 thousand BOPD.

Because of the success of these horizontal wells, the operator company also implemented this technology at the Quifa Field, discovered in 2008, which is an extension of the Rubiales Field. The oil production rate at the Quifa Field in December 2011 was 39.4 thousand BOPD.
Unusual Asphaltene Phase Behavior of Fluids from Lake Maracaibo, Venezuela
Authors: Gonzalez Doris L. , Garcia Martha E. , Diaz Omar
Published: April 2012

Reservoir fluids from Lake Maracaibo have reportedly caused asphaltene operational problems ranging from plugging of wellbores, pipelines and flowlines to clogging of surface facilities (Garcia et al, 2001). Production of fluids from some part of the region has been dramatically reduced due to asphaltene precipitation and deposition (Vasquez, 2010).

Asphaltene and wax precipitation is a serious problem in production, transport and processing of reservoir fluids. Of particular concern are the effects of asphaltene precipitation and their potential to disrupt production due to deposition in the near-wellbore regions and production tubulars. This phenomenon is directly influenced by changes in temperature, pressure and composition. Commonly, low temperatures increase the probability of asphaltene precipitation; however, experimental studies on the fluid under study demonstrated unusual asphaltene phase behavior.

This project involved experimental studies on fluid phase behavior as part of a formation damage investigation. The main challenges with fluids from the Maracaibo area are the relative high H2S content (1–3%), high reservoir temperature (270°F) and the asphaltenic nature of the crudes.

In this study, the asphaltene precipitation envelope was determined using Near Infrared (NIR) Solid Detection System (SDS), High Pressure Microscope (HPM), Particle Size Analysis (PSA) and gravimetric techniques. As expected, a significant amount of asphaltene was observed to precipitate during depressurization. However, reversibility of the precipitated asphaltene was also observed below the bubble point and during re-pressurization.

What was unusual about this fluid was the unconventional asphaltene precipitation onset conditions found at low temperatures. For most crude oils worldwide, asphaltene precipitation onset pressure increases at lower temperatures; however, the fluids considered in this work have shown a non typical behavior wherein the asphaltene onset pressure decreases with decreasing temperature. Such behavior was earlier presented by Ting et al, 2003 on the Maracaibo oils; however, no reports have been published since.
Integration of Uncertainty Analysis and History Matching: Application in a Complex Case
Authors: Silva Luciana dos , Schiozer Denis
Published: April 2012

The large amount of uncertainties on reservoir modeling increases petroleum production forecast risks. Therefore, the history matching, which refines the simulation model to closely reproduce production data, is a vital procedure once it approximates numerical models to reality providing reliable predictions. As history matching is an inverse problem, the use of multiple models with good match is important to guarantee future analysis.

Many methodologies were developed to integrate uncertainty analysis and history matching, in order to mitigate the reservoir uncertainties by using the observed data. In this context, the present article aims to evaluate the application of existing methods on a synthetic complex model (i.e. similar to a real field) and propose new methods with some improvements to be applied in real cases of the petroleum industry.

The main characteristic of these methods is the use of differences between observed and simulated data to recalculate the probabilities distribution of uncertain parameters with the purpose of reducing reservoir uncertainties. The redistribution of occurrence probabilities is made with different formulas, representing the distinct four methods discussed: the first two are reviewed from literature and other two proposed by authors. The first proposed method combines the best practices of the two reviewed ones, making it robust to be used in real cases with a great number of wells and production functions to be adjusted such as water production and pressure. The second proposed method is only an iterative application of the first one with a redefinition of attribute values in order to refine the results.

A comparison of the results of the four methods shows an evolution in the uncertainty reduction. Besides that, there is a decrease in the dispersion of the representative curves, which are centralized around the history data. Finally, this work presents a simple and practical way of integrating uncertainty analysis with history matching that provides reliable reservoir simulation models for production forecast and risk analysis of future projects.
Interference Tests Analysis in Fractured Formations with a Time-Fractional Equation
Authors: de Swaan-Oliva A. , Camacho-Velázquez R. , Vásquez-Cruz M.
Published: April 2012

Fluid flow analytical models traditionally used in well test analysis not always yield adequate results for reservoir characterization. Contrastingly, fractal formulations have proved to be a more suitable tool. Among the various formulations, the Metzler-Glockle-Nonnemacher (MGN) equation includes a fractional time derivative. In this paper, that equation was applied to analyze interference tests in actual field cases. The MGN equation was applied and automatically matched to the observed pressures. Both usual reservoir properties -porosity and permeability- and also fractal exponents were varied in the matching procedure.

Automatic matches of the involved variables resulted in pressure increments that compare fairly well with observed data from the field tests. The responses show a high anisotropy in the rock properties.

The MGN equation implemented in this paper comprises fractal behavior in spatial variables as well as in the time term.

Thus, well tests recorded in highly heterogeneous media, not amenable to standard techniques, can be analyzed with such analytical fractal approach.
Dilatancy Criterion Applied for Borehole Stability During Drilling Salt Formations
Authors: Rios A. , Roegiers J.
Published: April 2012

Despite the fact that drilling activity through salt formations became an important issue for the oil industry since 1901, with the discovery of the Spindletop Field in Texas, wellbore stability in the neighborhood of rock salt has been seldom by analyzed. Considering that pore pressure is not present in salt formations because the low porosity they have, and that the fracture gradient is considered greater than the overburden; constraints for a safe mud weight is difficult to determine. Therefore, the mud weight program for salt section is mostly determined using the isothermal curves given by Leyendecker et al. (1975) or following rules-of-thumb. Currently, the approaches to study wellbore stability issues through salt formations are based on creep behavior, which is function of the activation energy. These models were elaborated under certain pressure and temperature conditions, so their reliability is not universal. Hunsche & Cristescu (1998) analyzed the deformations mechanisms due mostly for the volumetric behavior of rocks. They determined a compressibility/dilatancy boundary for rock salt which is function of the state of stresses that prevails. In 2007 Henglin et al. presented the hypothesis that a borehole would be stable only if the magnitude of the octahedral shear stress is below the dilatancy boundary given by Hunsche & Cristescu. This paper tries to explain the wellbore instability in rock salt based on Henglin et al. hypothesis. A new stability criterion is proposed and applied to field data from Yaxche and Sen Oil Fields to planning the appropriate mud weight for salt sections. Yaxche field is classified as high pressure-high temperature conditions, is offshore in the Gulf of Mexico; whereas Sen field is an onshore field, under low-pressure-high temperature conditions.
Integrated Risk Analysis of Uncertainties in Geological Model and Dynamic Flow Properties for the Development of Oil Fields
Authors: da Silva Genilson A. , de Oliveira Guimarães André M. , da Silva Gislene A. , Lucas Marcos Aurélio
Published: April 2012

Given the high degree of uncertainty in the oil industry present production development projects, the use of probabilistic models is of considerable interest as a means to support decision making. Besides that, there is a constant pursuit to optimize oil drainage, to maximize reserves as well as the financial outcome of the project. A robust study, characterizing the uncertainty of the various critical parameters, such as number of wells, maximum water injection rates, relative permeabilities and rock and PVT data, is of paramount importance to assure that the impact of all uncertain parameters have been accounted for.

The present risk curve construction methodology takes into consideration uncertainties in the geological model and in the dynamic properties in an integrated manner. Six geologic scenarios with distinct permo-porous distributions were generated. A study was conducted to obtain PVT correlations of the produced fluids.

A sensitivity analysis was performed to eliminate non-significant parameters. The relevant ones were well adjusted to the production data in all geologic scenarios. Optimum exploitation configurations were obtained for each model, using the net present value (NPV) as an objective function. Each configuration was applied to all scenarios and the estimated monetary values (EMV) of each configuration were calculated. The maximum EMV was used as optimum criteria. The final product obtained was a development strategy risk curve, showing the viability of the proposed methodology.
Results of the Implementation of the Project Management System: Towards a Competitive Quality Model
Authors: García L. F. , Naranjo J. G. , Salazar J. S. , Linero L. M.
Published: April 2012

Investment projects are the primary vehicle for companies to achieve their goals, maximize the value of its shares by generating value. It is therefore important that the resources allocated to projects are used efficiently and that the promise of value of each project is met according to plan.

In response to this need, it was proposed to implement a project management system in the Vice-presidency of Exploration, Ref 1, based on international standards, industry best practices and definition of deliverables to achieve a continuous improvement process designed to develop more efficient exploration projects.

Implementation of the proposed management system for exploration activities has shown strong benefits, as evidenced in the systematic measurements of the FEL index over the past 5 years.

This paper presents an account of the FEL measurements of exploratory wells from 2006 to 2010 and its corresponding analysis considering the sustainability of the model's application in time, the benefits in terms of time, costs and characterization that determines the FEL index measurement.

Because of the confidentiality of information, for purposes of this article the names of projects were omitted were omitted and the figures are presented as monetary and time units.
Estimation of Geological Facies Boundaries Using Categorical Indicators with P-Field Simulation and Ensemble Kalman Filter (EnKF)
Authors: Nejadi S. , Trivedi J. J. , Leung J.
Published: April 2012

The Ensemble Kalman Filter (EnKF) is a Monte-Carlo based technique for assisted history matching and real time updating of reservoir models. However, it often fails to detect facies boundaries and proportions as the facies distributions are non-Gaussian, while prior knowledge of the data is usually insufficient.

It is common to represent distinct facies with categorical indicators, which are intrinsically non-Gaussian. We implemented discrete cosine transform (DCT) to parameterize the facies indicators. This methodology was promising for simple and two facies models. For more complex models, though observed data were matched, it failed to reproduce realistic facies distribution corresponding to the prior variogram and facies proportion.

In this paper a new step is proposed to be included in the history matching of complex reservoirs using EnKF: realizations exhibiting the largest mismatch in terms of production data, experimental variogram, and histogram are discarded after the first few update steps, and a probability map for facies modeling is derived using the remaining ensemble members. Probability field (P-Field) simulation is performed subsequently using the facies probability map to generate a new set of realizations replacing the discarded members. The new realizations are updated again from the beginning using EnKF.

Several case studies with different facies distribution and well configurations were conducted. Initial ensembles were created using known facies classification at the well locations and populating binary facies data throughout reservoir using numerous variogram models and prior facies proportions. The regenerated realizations are closer to the true reservoir state since they already take into account the first few set of production data.

The qualities of the history-matched models were assessed by comparing the experimental variograms of facies distribution and facies propositions of the final ensemble, as well as the Root Mean Square Error (RMSE) of the predicted data mismatch.

Combination of DCT-EnKF and regenerating new realizations using P-Field simulation demonstrates reasonable improvement and reduction of uncertainty in facies detection. Incorporating the new step in the procedure assists filter to preserve the reference distribution and experimental variogram for complex reservoirs.
Inclusion of Environment Assessment in the Decision-Making Process of Petroleum Fields Projects
Authors: Barreto C. E. , Schiozer D. J.
Published: April 2012

In the last decades, environmental issues have been discussed more carefully. Consumers and government have required that companies become cleaner and make operations environmentally safer. Discharge of produced water from petroleum reservoirs may have a significant impact on environment and it is expected that this operation will be more taxed and the costs of treatment will be increased, besides the influence of consumer's preference. Considering that the relevance of the water discharge may impact on the field operation, it is important to study if the cost of discharge may change the choice of the production strategy. This work proposes a methodology to assess the environmental impact of water discharge and to consider this factor at the economic evaluation, including environmental analysis in the decision-making process. The methodology combines reservoir simulation, contaminants dispersion simulation and economic evaluation in order to make feasible the proposed assessment. The main idea is to make an economic valuation of an environment assessment and to add it in the project net present value (NPV). The maximum benefit is to implement a strategy with the concept of "zero discharge". This methodology was applied in a study case considering a reservoir simulation model in which different strategies are evaluated taking discharge of water evaluation into account. Different economic scenarios are evaluated. The results show that considering an environmental factor in the cash flow analysis can change the choice of the production strategy. The strategies producing less water obtained best results when compared with strategies which produced more water. This study points out that environmental analysis can be included in a global strategy selection process. Moreover, it is concluded that considering environmental impact on economic evaluation can really change the choice of production strategy.
Development of a Static/Dynamic Model for Chac Field Based on a Novel Multidisciplinary Workflow
Authors: Galindo R. Ortega , Galindo-Nava A. , Pérez-Alvis E. , Ortuno E. , Morales C. A.
Published: April 2012

The development of advanced computational systems has increased not only the capability but also the demand of complex simulation models in the oil industry. Unfortunately, due to the complexity of naturally fractured reservoirs in the Gulf of Mexico, PEMEXs North-East Marine Region has faced many difficulties in producing these models for its new and mature fields.

A practical workflow to generate static-dynamic simulation models for naturally fractured reservoirs is presented, with a strong emphasis on multi-disciplinary integration and interaction. A constant feedback between the various disciplines is crucial for a successful project.

The methodology was applied to develop the static-dynamic model for Chac field, located off the coast of Campeche. The simulation model was constructed with 100% active cells. The dimensions of the grid were optimized to maximize efficiency without losing vertical geological definition.

The model is able to reproduce the historical pressure-production behavior of the field, as well as the behavior of individual wells. Using coning and channeling correlations for fractured reservoirs; uncertain oil production data of some wells were revised to reproduce observed water productions.

The results of this work show how a multidisciplinary approach, during the construction of static and simulation models, creates a synergic environment that strengthens available tools. Additionally, this approach encourages the creation of larger pools of information from different sources and specialties, which can be used to explain reservoir phenomena observed during history matching.

This novel methodology, based on an integrated workflow, will allow the optimized construction and history match of numerical models developed for the RMNE. The interaction between various disciplines will provide a better understanding of reservoir phenomena, which in turn, will provide better tools during the decisions making process.
Understanding the Impact of Channel Fracturing in the Eagle Ford Shale through Reservoir Simulation
Authors: Altman R. , Viswanathan A. , Xu J. , Ussoltsev D. , Indriati S. , Grant D. , Peña A. , Loayza M. , Kirkham B.
Published: April 2012

Oil and gas production from unconventional reservoirs has witnessed significant growth in the last few years. Historically, massive stimulation treatments have been used to produce these hydrocarbons. While the in-place hydrocarbon volumes are often large, the challenge is to increase recovery while using fewer resources. One of the technologies that have been used to address this challenge is the channel fracturing technique. A number of horizontal wells have been stimulated in the Hawkville field of the Eagle Ford shale with this technique. The objective of this work was to evaluate the impact of the channel fracturing technique in these wells by using numerical reservoir simulation.

Numerical simulations were performed on a total of 15 horizontal wells. Six wells were completed with channel fracturing and nine wells were completed with slickwater or hybrid fracturing treatments. Because the Hawkville field has large variations in fluid composition, wells producing in the condensate-rich section were studied separately from those in the dry gas section. A consistent history matching methodology and workflow was applied across all wells which enabled a direct comparison of results.

Results from analytical work, such as normalized production comparisons, were used to narrow down the range of uncertainties and assumptions made in the numerical simulations. A trend emerged from the analytical evaluations, showing that wells completed with the channel fracturing technique have higher productivity while using significantly less proppant and fracturing fluid. Numerical simulations confirmed the finding and provided insights on the cause of higher production on these wells. Unlike analytical methods, numerical simulation can model changes in complex fracture properties between wells, the effects of transient flow, shale gas desorption from kerogen, interference effects between perforation clusters, and accounts for differences in shale reservoir quality between wells. Furthermore, calibrated well models allowed for sensitivity studies such as evaluating the impact of changes in fracture geometry and conductivity on future wells.

Reservoir modeling provided an estimation of effective stimulated fracture volume and fracture conductivity. Wells treated with the channel fracturing technique were observed to have on average 50% greater effective stimulated volume and more than double the stimulated conductivity compared to wells fractured with slickwater. When compared to wells fractured with hybrid treatments, channel fracturing wells had on average 27% greater effective stimulated volume and 50% more stimulated conductivity.
Design of a Neural Network Model for Predicting Well Performance after Water Shutoff Treatments Using Polymer Gels
Authors: Ferreira I. , Gammiero A. , Llamedo M.
Published: April 2012

Current selection of candidate wells for water shutoff by polymer gel technology is based on empirical criteria which make uncertain its result. Although sophisticated models to resemble the injection of polymer gels in a porous media are available, they require extensive knowledge of the well and reservoir, plus specific yet to be characterized gel kinetics parameters. In this work a model is proposed to predict a well future production response based on well and reservoir information that is commonly available.

Neural network models were designed, trained and validated for predicting wells production performance after a polymer gel treatment for water shutoff. A total sample of 31 historical applications of gel treatments were used for training and validating the proposed networks. Historical applications gathered include different well and reservoir types, which make the model prediction validity wide broad.

Neural networks with two different tasks were developed during this study, one of them with a bi-valuated response (output), and qualified as classification networks and the others with a wider range of potential output, identified as regression networks. The model aims to predict a well future oil production and the percentage of water associated to that production after the execution of a gel treatment. Training of the neural network was carried out using 90% of the wells set gathered and 10% of the wells were used for validation. An average relative error of 20% was obtained when comparing the actual production performance of wells and the neural network prediction for oil rate and water content.

The proposed neural networks allow the selection of future candidate wells for gel treatments, based on its potential success. Additionally, the proposed network allows improving future gel treatments by evaluating the effect of the volume of gel to be injected on the treatment's result.
A Simulation Study of Chemically Enhanced Water Alternating Gas CWAG Injection
Authors: Majidaie S. , Khanifar A. , Onur M. , Tan Isa M.
Published: April 2012

Water alternating gas (WAG) injection has been a popular method for commercial gas injection projects worldwide. The injection of water and gas alternatively offers better mobility control of gas and hence, improves the volumetric sweep efficiency. Although the WAG process is conceptually sound, its field incremental recovery is disappointing as it rarely exceeds 5 to 10 % OOIP. Apart from operational problems, the WAG mechanism suffers from inherent challenges such as water blocking, gravity segregation, mobility control in high viscosity oil, decreased oil relative permeability, and decreased gas injectivity.

This paper addresses the aforementioned problems and proposes a new combination method, named as the chemically enhanced water alternating gas (CWAG), to improve the efficiency of WAG process. The unique feature of this new method is that it uses alkaline, surfactant, and polymer as a chemical slug which will be injected during WAG process to reduce the interfacial tension (IFT) and improve the mobility ratio. In a CWAG process, a chemical slug is chased by water, preceded by gas slug and followed by alternate CO2 and water slug or chemical slug injects after one cycle of gas and water slug. Essentially CWAG involves a combination of chemical flooding and immiscible carbon dioxide (CO2) injections. These mechanisms are IFT reduction, reducing water blocking effect, mobility control, oil viscosity reduction due to the CO2 dissolution and oil swelling.

CMG's STARS was used to study the performance of the new method using some of the data found in the literature. It is a chemical flood simulator that can simulate all aspects of chemical flooding, and it can also handle immiscible CO2 injection features by considering K-value partitioning. The sensitivity analysis shows that the new method gives a better recovery when compared to conventional WAG. This study shows the potential of CWAG to enhance oil recovery.
Foam-Oil Interaction in Porous Media: Implications for Foam Assisted Enhanced Oil Recovery
Authors: Farajzadeh R. , Andrianov A. , Krastev R. , Hirasaki G. J. , Rossen W. R.
Published: April 2012

The problems associated with many gas injection projects are the inefficient gas utilization, poor sweep efficiency and low incremental oil recovery due to viscous instabilities (channeling or fingering) and gravity segregation. These are caused by rock heterogeneity as well as the low density and viscosity of the injected gas. To mitigate these drawbacks foam can be injected into the oil reservoir by co-injection of surfactant solution and gas, or by surfactant-alternating-gas (SAG) mode. When the foam films are created in-situ, the flow of gas is hindered and gas can sweep the pores that would not be reached in the absence of foam – better vertical and areal sweep. The efficiency of the displacement process in foam-assisted gas flood depends largely on the longevity of the created foam films, and ratio of film destabilization and re-generation rates. Experimental studies have demonstrated the detrimental impact of oil on foam stability. This paper reviews the mechanisms and theories (disjoining pressure, coalescence and drainage, entering and spreading of oil, oil emulsification, pinch-off, etc) suggested in the literature to explain the impact of oil on foam stability in the bulk and porous media. Moreover, we describe the existing approaches for foam modeling in porous media and the ways these models use to describe the oil effect on foam propagation in porous media.

Further, we present various ideas on an improvement of foam stability and longevity in the presence of oil. The outstanding questions regarding foam-oil interactions are pointed out.
Biosurfactant Producing Microorganisms and Its Application to Enhance Oil Recovery at Lab Scale
Authors: Gudiña E. J. , Rodrigues L. R. , Teixeira J. A. , Pereira J. F. , Coutinho J. A. , Soares L. P.
Published: April 2012

Microbial Enhanced Oil Recovery (MEOR) is a tertiary oil recovery process where microorganisms and their metabolites are used to retrieve unrecoverable oil from mature reservoirs. Stimulation of biosurfactant production by indigenous microorganisms can reduce the capillary forces that retain the oil into the reservoir. The studied reservoir is characterized by alternated oil and water sand layers, with an average porosity of 25% and a permeability of 50 mD. It's a flat structure at 450 m depth, with an initial pressure of 32.4 bars and a temperature of 42.5°C. The oil is paraffinic, with low viscosity, high pour point and a gravity of 25° API, with no gas dissolved. Due to these properties, the wells can't flow naturally and the production has to be lifted, making this reservoir a good candidate for MEOR application. This work addresses the isolation and identification of microorganisms capable of producing biosurfactants and degrading heavy oil fractions at the oil reservoir conditions. Five Bacillus subtilis strains isolated from oil samples were able to grow and produce extracellular biosurfactants at 40°C under anaerobic conditions in medium supplemented with hydrocarbons. In addition, some of the isolates displayed a capacity to degrade, both in aerobic and anaerobic conditions, the large alkyl chains, and reduce the viscosity of hydrocarbon mixtures. A sand-pack column model was designed to simulate the oil recovery operations and evaluate the mobilization of residual oil by microorganisms. Additional oil recovery using B. subtilis isolates ranged from 19.8 to 35.0%, suggesting that stimulation of biosurfactant production by these strains in situ can contribute to mobilize entrapped oil. The novelty of this technique, compared to the conventional EOR methods, is the application of indigenous microorganisms to increase the oil recovery.