bluuebunny/crossref_metadata_2025_split huggingface dataset:
Predictive Analytics: Development and Deployment of Upstream Data Driven Models
Authors: Holdaway Keith R. 
Published: April 2012

Abstract
The oil and gas industry is engulfed by a plethora of disparate data collated across multiple geoscientific and siloed disciplines. Moreover, the data are growing exponentially as digital oilfields are being implemented in some fashion to manage conventional and unconventional assets. Performing exploratory data analysis and generating data marts tailored to specific advanced analytical workflows are cornerstones to enable development and deployment of predictive models that are data driven, both in real-time and across historical data sets.
To build data driven models that can predict under uncertainty is essential to rapidly identify multi-dimensional parameters in a multivariate environment and thus surface hidden patterns and relationships in data that subsequently reduce time and resources in the critical decision-making cycles. With improved workflows and advances in High Performance Computing, it is now possible to ascertain risk and quantify uncertainty for very large populations of data without sampling and losing knowledge garnered by predictive models driven by the data and not by empirical petroleum engineering algorithms or deterministic methodologies. By marrying the stochastic with the interpretive school of thought, the upstream community can maintain robust data driven models that are kept current as new data are introduced.
This paper draws upon two case studies that ameliorate the path from raw data to invaluable knowledge. We shall look at a suite of predictive models driven by real-time data that were built upon patterns surfaced in historical data. These models have been implemented to identify optimized drilling and production strategies in the North American tight gas plays and acid stimulation strategies in the Gulf of Mexico.
Risk Analysis Speed-up with Surrogate Models
Authors: Amorim T. , Schiozer D. J. 
Published: April 2012

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.