bluuebunny/crossref_metadata_2025 huggingface dataset:
Integration of Surface and Reservoir Modeling for Steam Assisted Gravity Drainage on the Bare Field in Eastern Venezuela
Authors: Ruiz R. , Nuñez J. , Martinez A. , Alvarez A.
Published: April 2012

The efficient and economic recovery of heavy oil and bitumen is a mayor technical challenge due to their high viscosity. In the Orinoco Oil Belt, due to the high viscosity, different thicknesses and heterogeneities found, thermal recovery processes have demonstrated to be the best alternative for the enhancement and acceleration of heavy oil recovery. Bare Field, with an average API gravity of 10°, is among the fields of the Orinoco Oil Belt where thermal recovery has been applied through the implementation of Cyclic Steam Injection in horizontal wells, with substantial productivity increase. This led to the introduction of the first SAGD (Steam Assisted Gravity Drainage) pilot project on the Orinoco Oil Belt, on the Bare Field, this pilot test is in operation from 2009, and the recovery factor of the area affected by the steam is estimated to increase from 14 to 60 %

The location and design of these SAGD wells was accomplished using independents models for reservoir, well and surface, creating a production scenario without taking into account the interaction between models. A dynamic coupling of the reservoir simulation model with the well and surface models allows the consideration of more realistic boundary conditions. In this sense, an integrated model was developed in the present work, allowing the dynamic evaluation of the entire system helping to understand the energy consumption along the system to improve the recovery method performance.

To develop this model, a dynamic thermal reservoir model was created from an existing static model of the reservoir. Once the reservoir model was able to reproduce the flow rates, pressure and temperature with acceptable accuracy compared to the real history data, the next step was the elaboration of well models. The reservoir and well models were coupled in one model to evaluate the advantages of use integrated models for the evaluation of the energetic efficiency of SAGD projects.
Estimation Coalbed Methane Content from Elemental Analysis for "Los Cuervos" Formations High Volatile Bituminous C Coals Applying Nonparametric Regression Techniques
Authors: Rodríguez S. , Navas G. , Gómez A.
Published: April 2012

Unconventional gas exploration and development is the new challenge that faces the Colombian energy industry, and understanding of the reservoirs is the first step to achieve the goal of increasing gas reserves. Coalbed Methane (CBM) has become an important resource given that Colombia holds the largest coal reserves in Latin America.

Exploration of CBM began in 2008 with characterization of coal reservoirs, gas content, and storage capacity of four coal bearing formations in the main Colombian basins. In addition, the coals were assessed using techniques such as proximal and ultimate analysis, Rock-Eval pyrolysis, organic petrography, gas chromatography, isotopic analysis and desorption tests.

From the four basins evaluated, this article will be focused in "Los Cuervos" Formation where four stratigraphic wells were drilled. Based on ultimate analysis and gas desorption measurements of cores, a mathematical model for estimating gas content was developed. The gas content showed excellent correlation and statistical significance with depth, total carbon and moisture percentage. 53 samples, classified as High Volatile Bituminous C using heating value from proximate analysis, were included in this study. Non parametric regression techniques based on statistical and optimization theory were applied to find the best correlation for predicting gas content. The equation set was generated with Grace98® software applying the ACE method. The non parametric model obtained explains the 92.5% variability of gas content and makes predictions with exactitude of 91.8%. The average percent deviation between experimental and calculated gas content was 7%, indicating good fitting between data and the proposed model. Based on the Anderson Darling test and residual plots, the errors generated from prediction were found to be randomly dispersed without any pattern. The obtained results showed that non parametric techniques were more efficient to predict gas content than conventional multiple regression. It was also found that there is not a kind of "universal correlation" but specific basin correlations since the gas content depends on geologic characteristics.
Mature Carbonate Heavy Oil Field Exploitation Strategies: The Cretaceous Ku Field, Mexico
Authors: Pérez-Martínez E. , Rojas-Figueroa A.
Published: April 2012

This paper aims to present the strategy for future exploitation of the Ku oil field, based on its historical behavior of pressure-injection-production profiles and the advance of gas-oil and oil-water contacts.

The production performance of all wells in Ku oil field was analyzed in order to evaluate the gas and water breakthrough and production.

A pressure maintenance program was started in 2009 by injecting nitrogen at a rate of 160 MMsfc/D, which reduced the pressure decline from 4.45 to 1.36 kg/cm2 per year. At the end of 2011, the nitrogen injection rate was increased to 250 MMscf/D in Ku field in order to maintain reservoir pressure and minimize advance of the OWC (oil-water contact), which is estimated at 3,140 vertical meters subsea (vmss). On the other hand, the GOC (gas-oil contact) continues to advance at a rate of 25 m/year. To maintain production, a staggered workover schedule is utilized to open new producer intervals in every well where the gas cap approaches.

Ku is one of the offshore oil fields located in the Ku-Maloob-Zaap Asset. It produces mainly from naturally fractured carbonates in the Upper Cretaceous (UC), Middle Cretaceous (MC) and Lower Cretaceous (LC) formations. In addition to high net pay thickness and structural relief, UC rocks have a very high permeability, which ranges between 4 and 9 Darcies, because of high fracture density. This condition gives the formation a thief zone characteristic during drilling, cementing and completion jobs. In fact, during cementing of the last casing pipe on many wells, most or all cement slurry volumes are lost to the formation, creating an unrestricted channel to flow and thus an increased tendency towards water coning.

The remaining oil reserves volume in Ku oil field will be recovered from the oil column located between the contacts. Therefore, it is necessary to understand the production performance under these conditions in order to establish the optimal operative ranges under which wells will be producing. The water coning and fluids channeling effects depend upon the rock – fluids properties, well geometry and design, and, finally, the production conditions under which the wells will be operated.
A New Reservoir Classification Based on Pore Types Improves Characterization
Authors: Rodolfo Soto B. , Martin Cintia , Pérez Orlando , Arteaga Duarry
Published: April 2012

In the past, only four types of reservoirs were defined to characterize matrix and fracture systems. These definitions based on matrix and fracture systems do not cover all the pore systems present in the real world because a great number of reservoir systems are made up of different lithologies and pore types. The pore types could be matrix, fractures, or vugs or combinations of these. One of the potential problems is that engineers have simplified that complex problem and therefore have erroneously produced the reservoirs. If a complete classification were available in the literature, more effort would have been made to recognize all the pore types present in a specific reservoir for better characterization and production.

This paper discusses a new methodology to classify all kind of reservoirs in the real world: fracture, matrix, vugs, or combinations of those. We have developed membership functions using fuzzy logic concepts for the cementation factor m variable. We have identified at least five types of reservoirs according to pore types.

All types of unconventional or conventional reservoirs are represented in this new classification system. We used core data from Southern Vietnam, Libya, the United States, Argentina, Iran, Iraq, Saudi Arabia, Colombia, and Venezuela to validate our new classification, and we are certain that it will be of great help to the engineers. Better understanding of the behavior of a specific reservoir will help increase the production and the recovery factor.

We also discuss how to increase the oil or gas production as a reservoir moves from one class to another as result of hydraulic fracturing.
Probabilistic Risk Analysis Applied to the Evaluation of Alternatives for Management and/ or Exclusion of Sand
Authors: Jaimes M. G. , Sanabria F. E. , Quintero Y. A. , Contreras G. Y. , Martin D. P.
Published: April 2012

Sand production is a critical problem that causes the industry spending over $3.0 Billion U.S. per year (70% of the wells worldwide have this problem). To mitigate the impact, many operators choose the option of deploying technologies to exclude the sand, and usually reduce the benefits for decrease a risk not quantified.

Currently the reservoirs trending to sand production contain an increasing percentage of the world's hydrocarbon reserves. Many of the wells that exploit these resources are producing beyond the limits of their originally estimated useful life, which can result in weak formations. Consequently, it is required being more demanding in the profit margins of the projects of Management and / or sand control achieved at these reservoirs, so it requires a probabilistic risk analysis (PRA) in them, taking into account that the risk and uncertainty are two factors that are often present. This analysis facilitates decision making and allows determine the best Completion and production strategy of the formations sensitive at sand production.

Based on the above, this work focuses on developing a methodology for probabilistic risk analysis to evaluate management alternatives and / or exclusion of sand using Monte Carlo simulation. The methodology includes six phases: (1) Selection of alternatives to evaluate and definition of the conditions of production of each one, (2) Structuring the deterministic model of each alternative (3) identification of most impacting variables on the level of production of each alternative and determination of its range of typical behavior (4) Estimation of probability distributions of production for each variable, (5) Monte Carlo simulation for risk assessment of each alternative and selecting the best choice.

The methodology was applied to evaluate management alternatives and / or exclusion of sand in the formations sensitive to sand production of the fields: Lisama, Llanito, Galan, Brisas and Yarigui-Cantagallo in Colombia and was compared with the results of the evaluation when using deterministic models. In this paper is present the Application cases in the wells: Lisama 171 and Yarigui 168.

Finally, the main findings, conclusions and recommendations obtained in this study are shown.
High Energy Gas Fracturing: A Technique of Hydraulic Prefracturing To Reduce the Pressure Losses by Friction in the Near Wellbore - A Colombian Field Application
Authors: Jaimes M. G. , Castillo R. D. , Mendoza S. A.
Published: April 2012

One adequate management and optimization of mature fields requires the use of techniques, methodologies, technologies and analysis of the behavior of the wells to generate recommendations of production optimization with the highest probability of exit.

One alternative that today has proven successful and is widely applied worldwide to maximize the profitability of the fields, consists in the implementation of hydraulic fracturing jobs, to improve the flow capacity of the wells, which is achieved to go through the formation damage, speeds up the reserves, etc. However, one of the main difficulties of hydraulic fracturing, are the high friction pressure losses in the near wellbore (NWBF), which require high pressures to break the formation and equipment of higher power in surface. This means work over more expensive and with a lower economic profitability.

An evaluation of new technologies, allowed the identification of the alternative called High Energy Gas Fracturing (HEGF), as a pre-fracturing technique to reduce pressure losses by friction in the near wellbore (NWBF). HEGF is a perforating technique with propellants, which not detonate, but they blaze with high heat, but unexploded (deflagrate), releasing a high energy gas that reaches a sufficient pressure pulse (10,000 to 50,000 psi) and combustion time (5 – 30 milliseconds) that creates fractures in all radial directions at short distance.

For different operational areas of the Colombian state owned oil company, Ecopetrol SA, was performed an evaluation of pressure loss by friction in the near wellbore (NWBF), during hydraulic fracturing operations that have been executed. This allowed to make recommendations to implement HEGF and thus optimize the hydraulic fracturing operations. This paper presents the results of the assessment in the fields Apiay, Austral, Gavan, Suria and Yarigui.

Finally, the main findings, conclusions, recommendations and field results obtained in this study are shown.
Feasibility of High Pressure Air Injection in Heterogeneous Light Oil Reservoir by Thermal Simulation
Authors: Shah Aarshavi , Modi Kaushal
Published: April 2012

HPAI in Light oil reservoirs have gained a success nowadays in the field. Air injection in light oil is decided on the basis of in which phase of the life reservoir stands. The main aim of this EOR method is to strip out the Lighter Hydrocarbons from the residual Heavy Fractions and also to act as a pressurizing agent as from conventional heavy oil reservoirs to reduce the viscosity and removing the residual oil saturation. The factors affecting the HPAI are Geology and the Geological structure and the reaction kinetics parameters like reaction frequency, enthalpy, activation energy and the mode of reaction i.e. Low Temperature Oxidation (LTO) and High Temperature Oxidation (HTO). In this paper, the laboratory procedures, for the Air injections have been calculated i.e. the velocity of the combustion front, temperature profiles and the ignition time of the initiation of reaction. Simulation of combustion tube experiment has been carried out and expanded to the block model in CMG STARS. The tuning of the reaction parameters is to generate the temperature profile of the twelve zones of the combustion tube experiment. History matching with the data generated in simulation and the outcomes of the laboratory experiment is performed. The block model with five spot inverted pattern predicts the variation of oil saturation, temperature, oil cut, water cut, cumulative fluid rates with time. The conclusion from this simulation is the feasibility of High Pressure Air injection processes in Light Oil Reservoir and predicting the future performance in the reservoir. The results from this simulation were that the clay particles affect the reaction kinetics in the Light Oil and the increment in the recovery is about 20 % because of HPAI.
Novel Method for Characterizing Single-phase Polymer Flooding
Authors: Sun Wenjie , Peking U. , Li Fen , Qu Yantao , Yang Yaozhong , Li Kewen
Published: April 2012

Polymer flooding has been used to enhance oil production and reduce water cut for a long time. However there are still many fundamental challenges in characterizing the multi-phase fluid flow, even the single-phase fluid flow, associated with polymer flooding. For example, it is difficult to measure and calculate two-phase polymer solution/oil relative permeability. One of the difficulties comes from the non-Newtonian and time-dependent properties of polymer solutions; another comes from the change in absolute permeability caused by the adsorption of polymer on rock surfaces. Almost all of the methods for computing relative permeability are based on the assumption that the absolute permeability is constant. It will be helpful to further understand the mechanisms and develop more reliable methods for calculating two-phase polymer solution/oil relative permeability by investigating the single-phase polymer flooding more profoundly. In this study, a new method has been developed to calculate the pseudo permeability during single-phase polymer flooding. The non-Newtonian property of the polymer solutions was considered in the proposed method. A series of polymer flooding experiments using different concentrations of polymers were designed and conducted to study the single-phase flow of polymer solution in rocks with different permeabilities. The values of the pseudo permeability of single-phase polymer flooding were then calculated using the new method. It has been found that the relationships between the pseudo permeability and the reciprocal of shear rate were linear. The pseudo polymer flooding permeability extrapolated at the infinite shear rate was close to the brine flush permeability after polymer injections in most of the cases.
Economic and Technical Feasibility Analysis of the Use of a Water Base Drilling Fluid at Levas Field, Dacion Production Unit, San Tome District Ayacucho Division - Venezuela
Authors: Ras Nael Abo , Graterol Jenny , Ruiz Fernando
Published: April 2012

The development of the Levas field began in 1952, by drilling vertical wells using a water-based drilling fluid, however, from 1998 when the aggressive drilling of deviated wells began, also the operational problems started in the middle section, problems such as tight hole, drag, hole instability, stuck pipe, and others. In 2002, the company decided to switch to oil-based mud to reduce and control the incidence of those inconveniences.

PDVSA Services San Tome, began searching for a special drilling fluid to replace the existing, due to high demand of the main component of the oil-base drilling fluid (Vassa), and its low supply due, and more important the high cost and environmental difficulties to treat and dispose this kind of drilling fluid and the cuttings. This study evaluated four sets of high performance water-based drilling fluids, to start a new development stage for drilling deviated wells at the Levas Field.

To determinate the technical feasibility, some studies were made, first the physical properties, such as: rheology, filtration, solids percentage in the system, and others, were evaluated to make a comparative analysis to find out which water-base drilling fluid had the best performance considering the geological and operational conditions of the field.

Also the mineralogy (clay minerals) of the field was determinate through the X-ray diffraction test, which concluded that the predominant mineral of the field was kaolinite. This clay has a low CEC value that means it has a high dispersion capacity. This result allowed to determinate one of causes of the hole instability in the middle section of the deviate wells. Additionally, the Dynamic Linear Swell test was made to determinate the inhibitory capacity of each water-base drilling systems with the clays from the formation and bentonite, beside the clay dispersion test evaluated evaluate the capacity of each high performance drilling fluid systems to maintain the integrity of the body shale and cuttings.

Finally, the cost analysis allowed evaluating the economic feasibility of each drilling fluid system. After analyzed the various results, we concluded that the drilling fluid trading system number one had the best cost benefit to drill deviated wells in Levas Field.
Transient Modeling of a Subsea Pumping Module Using an ESP
Authors: Teixeira V. F. , Gessner T. R. , Shigueoka I. T.
Published: April 2012

In the pursuit of more productivity, Petrobras has been using more and more ESPs (Electric Submersible Pumps) on its subsea wells, especially on heavy oil fields, where the gas-lift is not as attractive as that method. Those scenarios are very common in the Campos Basin, particularly at the Jubarte-Cachalote Asset, where the oil has an average API gravity below 20°.

However, since the ESP MTTF (Mean Time To Failure) is around two years, Petrobras has proposed new technologies that can reduce the intervention time and costs for this method. The Subsea Pumping Module (MOBO) is an excellent alternative for it. The system consists of an ESP that is installed on a caisson located around two hundred meters from the production wellhead. This module allows not only a faster intervention for pump exchange after a failure when compared to the conventional in well ESP, but also accept the ESP installation without interrupting production (by using gas-lift as a contingence, bypassing the MOBO).

On the other hand, the Pumping Module has inherent constructive instabilities. The geometry of the system forces a downward annular flow, which causes the partial gas-liquid separation of the incoming multiphase production. This separation may generate not only instabilities, but also an excessive gas fraction at the pump inlet, that may cause the phenomenon known as gas-lock, impairing the pump performance and even causing its failure.

Thus, this study intends to characterize the hydrodynamic behavior of the flow in the Pumping Module, through the use of a multiphase transient approach. This model have been developed using a multiphase transient simulator and it has been validated through an extensive comparison with a producing well. To carry it out, data were collected from online instrumentation and production tests to be used as validation parameters. A good correlation between model results and production information was obtained, helping Petrobras to predict unexpected behavior of new wells that will produce using the MOBO. The validated modelling proved to be an useful tool for flow assurance studies for this production setup.
Micro-tomographic Characterization of Dissolution-induced Local Porosity Changes including Fines Migration in Carbonate Rock
Authors: Qajar Jafar , Francois Nicolas , Arns Christoph H.
Published: April 2012

The microstructure of carbonate rocks experiences substantial changes under reactive processes, in particular chemical dissolution and deposition including dissolution-released fines migration occurring during acidizing. A better understanding of such changes at the pore scale and their influences on rock properties is of great value for the effective design and implementation of reactive processes in carbonate reservoirs. In this work, we demonstrate the use of X-ray micro-computed tomography (μ-CT) to quantitatively investigate the local porosity changes in a meso/microporous carbonate core sample during chemical dissolution. A reactive flooding experiment in a core sample by a non-acidic solution is designed such that changes in pore space from before to after the reactant injection could be imaged in exactly the same locations using μ-CT at resolution of less than 5μm. A methodology based on three-phase segmentation and 2D intensity histograms of images is used to quantify distributions of the evolution of each image voxel. This technique allows the incorporation of microporosity into the calculation of the evolution regions including the migration of fines in order to accurately quantify the evolution scenarios. The µ-CT images reveal a quasi-uniform dissolution pattern and allow characterizing the accompanying migration of fines within the core sample. 3D pore networks are derived from the image data, which quantify changes in network structure and the pore geometry. 2D histograms of image intensity derived from the pre- and post-dissolution images quantitatively show how macro and micropores are enlarged by dissolution close to the inlet while deposition of fines mainly occurs in pores far from the inlet boundary. These results can explain why permeability of the sample initially decreases and then increases as injection time increases. Based on the spatially resolved voxel evolution scenarios, pore surface area between each region is computed. This allows calculation of local distribution of reactive surface area which in turn will assist in the prediction of local reaction rates in reactive flow simulators.
Economic and Social Development of Angola Because of Petroleum Exploration (Revisited)
Authors: do Carmo D. Fernandes , Amoreira M. Gonzalez , Bone R. Bröker
Published: April 2012

Angola currently represents one of the largest economies in Sub-Saharan Africa. The same has achieved great economic growth, derived mainly from its mineral wealth. However, is still part of the low human development group with regard to the HDI, with 68% of the population living below the poverty line and 15% living in extreme poverty (second bulletin No. IFAD/23/08) with a consequent increasing rate of social inequality. The evaluation of the exploration and production (E&P) of oil in a country is essential for there to be a better use of the commodity for the purpose of economic growth and development. This article aims to explain the conditions, both social and economic consequences of Angola, to know whether the country has gained in quality of life with the national oil and gas activity. The variables to be examined are: the Human Development Index (HDI), Human Poverty Index (HPI), Infant Mortality Rate, Gross Domestic Product (GDP), Indexes of Health and Demographic Trends. In what concerns the variables in the oil sector, it is observed: the daily production and proved reserves of oil and natural gas and oil GDP. This juxtaposition of social and economic indices for the period 2004–2010 will evaluate the effects of the insertion of Angola's oil production and gas worldwide, as part of OPEC since 2007. From the analysis made in this article enables us to say that oil is not bringing the expected social development for the country as the income generated by oil still remains concentrated in few hands, and the civil organization of the main culprits behind it. The process of political reconstruction of the country was late, allowed the first presidential elections only in 2008, which ended up hindering the effective implementation of an effective social inclusion plan. Meanwhile, GDP per capita grows at relatively high rates. We know that Angola is presented on the world stage as a strong oil and gas power, yet the country still needs to rearrange themselves politically in order to create more jobs and income, which will ultimately improving the health, education and living conditions of citizens Angolans.
Combining Decline-Curve Analysis and Capacitance-Resistance Models To Understand and Predict the Behavior of a Mature Naturally Fractured Carbonate Reservoir Under Gas Injection
Authors: Salazar Martín , Gonzalez Hector , Matringe Sébastien , Castiñeira David
Published: April 2012

Capacitance-Resistance (CR) models have received renewed interest in the past few years as a fast alternative to reservoir simulation to model and predict complex water or gas floods in mature reservoirs. Using an analogy between reservoirs and electrical systems, CR models represent the interactions between wells through analytical solutions to an equivalent capacitor-resistor circuit.

CR models do not require a geologic model and can be built with only production and injection data. When modeling fields with numerous wells and a long history, traditional reservoir simulation workflows are extremely time-consuming. The simplicity of CR models make them extremely attractive to quickly model and predict the behavior of these complex reservoirs.

Current CR models are able to represent accurately the behavior of reservoirs under strong water or gas floods, where the injection is the main driving mechanism for production. In such cases, the production rates are strongly correlated to the injection rates and CR model are ideally suited to decipher these interactions.

However, most reservoirs start with a period of primary depletion or many are exploited under a weak injection strategy, for which CR models are not ideally suited. Here, we propose to combine decline-curve (DC) analysis with a CR model in order to solve this shortcoming. Using the superposition principle, the contribution of primary depletion to production is represented by DC and the contribution of injection is represented by the CR model.

After presenting the formulation and implementation of our DC-CR model, we demonstrate its performance on a deep naturally fractured carbonate reservoir under hydrocarbon gas and nitrogen injection. The reservoir has over 30 years of production history: 23 years of primary depletion and 8 years of gas and nitrogen injection. Using a one-year blind test, we demonstrate that the model is able to accurately predict the reservoir behavior.
Analytical Estimation of CO2 Storage Capacity in Depleted Oil and Gas Reservoirs Based on Thermodynamic State Functions
Authors: Valbuena Ernesto , Barrufet Maria , Falcone Gioia
Published: April 2012

Numerical simulation has been used, as common practice, to estimate the CO2 storage capacity in depleted reservoirs. However, this method is time consuming, expensive, and requires detailed input data. This investigation proposes an analytical method to estimate the ultimate CO2 storage in depleted oil and gas reservoirs by implementing a volume-constrained thermodynamic equation of state (EOS) given average reservoir pressure and fluid composition.

This method was implemented in an algorithm which allows fast and accurate estimations of final storage, which can be used to select target storage reservoirs and design the injection scheme and surface facilities. Impurities such as nitrogen and carbon monoxide, usually contained in power plant flue gases, are considered in the injection stream and can be handled correctly in the proposed algorithm by using their thermodynamic properties in the EOS.

Results from analytical method presented excellent agreement with those from reservoir simulation. Ultimate CO2 storage capacity was predicted with an average difference of 1.26 wt% between analytical and numerical methods; average oil, gas, and water saturations were also matched. Additionally, the analytical algorithm performed several orders of magnitude faster than numerical simulation, with an average of 5 seconds per run.
Simulation Study of Displacement Mechanisms in Microbial Improved Oil Recovery Experiments
Authors: Shabani-Afrapoli Mehdi , Crescente Christian , Li Shidong , Alipour Samaneh , Torsaeter Ole
Published: April 2012

Microbial Improved Oil Recovery (MIOR) processes use bacteria or their bioproducts to help mobilizing additional oil from the reservoir. The chemical and physical properties of the reservoir fluids and rock are changed during the MIOR process. An extensive investigation has been carried out at laboratory temperature with dodecane and an alkane oxidizing bacterium, Rhodococcus sp 094, suspended in brine to study potential recovery mechanisms involved in the MIOR process. Flooding experiments on Berea sandstone cores and flow visualization experiments within glass micromodels have shown the effects of bacteria on remaining oil saturation. The interfacial tension reduction, wettability alteration and selective plugging are recognized as important displacement mechanisms during the MIOR process. The objectives of this paper are to present the experimental results and to evaluate the driving mechanisms of MIOR by using two simulators. ECLIPSE is used to build a model based on core parameters for simulating the core flooding process. While, COMSOL Multiphysics models the two phases flow obtained experimentally at the pore scale within the micromodels. Simulation results are consistant with the experimental results and indicate that both tools are useful to solve the simulation problems of MIOR process. The obtained results address capability and inability of simulators to model the MIOR displacement mechanisms.
Achieving Low Interfacial Tension with Industrial Available Surfactants
Authors: Guy Biesmans , Salazar Luis , Miller Angie
Published: April 2012

Growing interest in Enhanced Oil Recovery (EOR) has generated renewed interest in surfactants for Chemical EOR (CEOR). While new developments typically build on past experiences of surfactant injections, academic and research institutes continue to propose new high-performance surfactant structures. Although these new molecules can easily be provided in sufficient quantities for laboratory tests and limited field trials, scale up to large commercial application could prove challenging. Moving to production on a large commercial scale will require the availability of raw materials and suitable production assets. In addition, regulatory compliance issues must be addressed, as must future supply chain efficiency.

This paper describes the development process for surfactants capable of attaining low interfacial tensions. It specifically addresses the impact of raw material availability and quality, production assets and regulatory compliance on a global basis.

Surfactant performance envelope data is presented as the first step to enable selection of potential candidate structures for given field conditions. The influence of the selected production assets for scale up to commercial quantities on the molecular composition of the final product is also illustrated. As will be seen, changes in the raw material feed and feed processes determine the poly dispersion of the resulting product. The impact of variations in chemical structure and total product composition manifest themselves in the product performance envelope. We show how small changes in composition not only impact performance, but also affect regulatory compliance and the corresponding supply chain processes.

A holistic approach to surfactant development, which considers the full process from product concept to commercial large-scale production, is essential to make CEOR successful. The development process must consider the sustainability of the proposed structures and processes required to make them. Here we will demonstrate why design for future growth in demand must be built in from day one of the product concept.
A Holistic Risk Analysis Approach for Reservoir Modeling
Authors: Huerta V. A. , Lanchimba A.
Published: April 2012

During recent years, some wildcat wells located in remotes areas of the Peruvian Amazonian rainforest tested commercial volumes of oil and gas. Beyond this preliminary success, reservoir uncertainties due to seismic interpretations, and limited cores and log data impose complexity in reservoir characterization; major sources of uncertainties can be broadly group into three main categories: structural, rock & fluid properties and reservoir performance.

Applications of numerical simulation have been extended to conceptualize reservoir characterization in early development phases; coupled with statistical experimental design, montecarlo simulation and scenario analysis, numerical simulation become the most powerful tool to fulfill a complete sensitivity analysis with significantly fewer simulation runs towards sizing downhole and surface facilities, as well as, optimizing field development.

The proposed holistic approach was applied to a new lean gas condensate field in the Peruvian rainforest so as to sensitize production plateau, evaluate rock & fluid properties, field size and recovery factors, predict liquid yield performance, analyze water influx and optimize field development. Pareto plots and response model surfaces showed that porosity, permeability, position of gas water contacts and faults transmissibility are the main factors affecting field size, as well as, gas and liquid recovery. In addition, cumulative plots showed distribution of gas & condensate recoverable resources. Finally, a matrix of scenarios showed that blowdown strategy is the best development alternative for this lean gas condensate field.
Effect of Pressure and Air Flow Rate on In-Situ Combustion Experiments of Heavy Oil
Authors: Cazarez-Candia O. , Cruz-Hernández J.
Published: April 2012

In this work in-situ combustion experiments were carried out using a combustion tube of 1 m. in length and 0.0381 m. internal diameter. Experimental tests were performed with heavy oil (18.1 API and 0.6614 Pa-s) from a Mexican field. The aim of this study was to survey the effect of pressure and air flow rate on temperature, oil recovery, front velocity, oxygen utilization and produced gases.

The experimental conditions were: 1) oil and gas saturations, 38% and 28% respectively, 2) porosity, 41%, 3) initial temperature, 373 K., 5) air flow rate, 5.83×10−5 m3/s and 7.5x×0−5 m3/s, and 6) pressure, 2068.4, 3447.4, 4826.3, 6894.7 and 10342.2 kPa. The results indicate that the in-situ combustion method is technically applicable to the rock-fluid system tested. Average combustion front temperatures were recorded in the range of 713 to 815 K, and the oil recovery factors were greater than 84%. The combustion front velocities were from 4.64 to 8.05 m/s.

It was found that, as the pressure increases (5.83×10−5 m3/s): 1) the average combustion front temperature and the combustion front velocity increase when pressure is smaller than 6894.7 kPa, 2) the oil recovery, and 3) the oxygen utilization diminishes. However the average combustion front temperature and the combustion front velocity decrease when pressure is larger than 6894.7 kPa. On the other hand, all such parameters increase as the air flow rate increases from 5.83×10−5 to 7.5×10−5 m3/s.

The basic combustion parameters (fuel consumption, air requirement, air/fuel ratio, atomic H/C ratio, oxygen utilization) obtained from the experiments may be used to design a pilot project planned for the field.
3D Analytical Modeling of Hydraulic Fracturing Stimulated Reservoir Volume
Authors: Yu Guang , Aguilera Roberto
Published: April 2012

An easy to use analytical 3D model is developed to simulate the growth of stimulated reservoir volume (SRV) with time once a hydraulic fracturing job is started in an anisotropic poroelastic medium. In the proposed method, diffusivity coefficients in three dimensions are determined first by calibrating the model with an actual 3D microseismic-event cloud. Then the geometry of SRV is predicted under different stimulation conditions. The method permits studying the geometry of hydraulic-fracturing SRVs in both vertical and horizontal wells. The analytical model is corroborated with the use of a numerical simulator.

The proposed method is important because in unconventional low-permeability reservoirs, such as shale and tight gas reservoirs, productivity depends primarily on permeability of the SRV and the reservoir area contacted by the SRV. Microseismic monitoring has been shown to be a useful technology to study the characteristics of hydraulic fractures. As such, the optimum is to constrain the analytical 3D model developed in this study with the use of microseismic data. It is concluded that this easy to use, yet accurate analytical model, is a viable tool for analyzing the orientation and geometry of hydraulic-fracturing SRV and for predicting other SRVs in the same reservoir. Examples of applications which can be reproduced easily in a spread sheet are presented in detail.
The Effect of Aquifer Condition on Methane Recovery for CO2 Injection in Coalbed
Authors: Kim K. H. , Lee M. K. , Sung W. M.
Published: April 2012

The purpose of this paper is to investigate the influence of various aquifer conditions on the CO2 displacement efficiency and methane recovery in the coal seam. The movement of CO2 in cleat is sensitively dependent upon aquifer condition as well as sorption characteristics of coal, since the pressure of coalseam is determined based on the position of aquifer. In this study, methane recovery for CO2 injection process was analyzed regarding the contacting position and strength of the aquifer. We ascertained that both methane recovery and CO2 sequestration are inefficient when the hydraulic connection between overlying aquifer and coal seam is strong. This is because buoyancy effect causes gas leakage to the overlying aquifer although CO2 displacing methane has a greater affinity compring to methane. Although the vertical permeability of underlying aquifer is great, the effect of methane recovery and CO2 sequestration are efficiently successful during CO2-ECBM process because the leakage of both the amount of injected CO2 and desorbed methane is negligible. Although the injected CO2 is effetively sequestrated in the edge aquifer case, ECBM recovery shows irregular efficiency in part due to the asymmetrical flow of the injected CO2. It is considered that the design of proper strategies regarding CO2 movement means a lot to the aspect of methane recovery and CO2 sequestration to maximize economic profit.
Initial Characterization of an Extra Heavy Oil Carbonate Exploratory Field
Authors: Aguilar E. G. , Gonzalez L. M. , Ruiz V. G.
Published: April 2012

Reservoir discoveries are getting more difficult and complex. Currently in the Gulf of Mexico new Oil Fileds are being characterized. The presence of secondary porosity into dissolution cavities with extra heavy oil become in a complex challenge to characterize those exploratory reservoirs. Only 18 wells have been drilled in a total area of 1100 km2, with water depth between 100 and 680 meters. The API gravity varies between 6 and 13 °API, which represent an adverse water-oil mobility ratio with a water-oil contact into fractures with high permeabilities. The main objective of this job is to show an advanced technique of Geosciences and Reservoir applied to an Extra Heavy Oil Carbonate Exploratory Field, to estimate the Original Oil in Place (OOIP) with probabilistic methods and define associated reserves to the field development.

The methodology applied starts with geophysics interpretation; Geo-statistics methods in the velocity model were used for depth conversion and a geo- mechanical model also was built for the development well design. The 3D Model includes: wells data, as well test, cores, electrical logs, horizons and faults in time and depth, geological tops, petrophysics, contacts and velocity model. Due to the high uncertainty, the 3D model integration was a challenge. The final result was a base case with a lithology and petrophysics properties distribution such as porosity, water saturation and net pay, used to calculate the OOIP.

Different workflows were used for the final result. Velocity variations were analyzed for the impact of each associated variable to the OOIP and understand area and thickness variability. Bayers Theorem was used for porosity, water saturation and net pay. Analogous wells by lithology were built, making more consistent the results and represent the reservoir in a best way possible into a numerical simulation model. Static and dynamic elements were integrated for reservoir and fluid behavior, including sensitivity analysis. The final result has uncertainty analysis, building of proxies and makes probabilistic forecasts to establish mitigation plans and define the more optimistic field development.
Geomechanics Applied to Perforating Design: One Solution to Reduce the Sand Production Risk
Authors: Quintero Y. , Jaimes M. , Martin D. , Rivera G.
Published: April 2012

One of the main causes of sand production is the rock faulting, situation that is given by the stress condition, pressure and mechanical properties that is applied. We use geomechanical criteria for the design of gunfire (density, diameter, penetration, phase and drop pressure for cleaning, etc.). It is possible to generate stable conditions that reduce the risk of the rock failure.

Therefore, identified some geomechanical criteria to determine areas of highest stress contrasts, which can accelerate the rock failure, areas with increases in stresses for proximity effect between canyons, among others, must be taken into account in the perforating operations in areas susceptible to sand production, in order to reduce the risk of the rock failure and start early sand production. With the aid of geomechanical models and these criteria it is possible elaborate a methodology for optimal perforating design.
Milestone in Production Using Proactive Azimuthal Deep-Resistivity Sensor Combined with Advanced Geosteering Techniques: Tarapoa Block, Ecuador
Authors: Guevara A. , Sandoval J. , Guerrero M. , Manrique C. A.
Published: April 2012

A recent challenge of drilling a horizontal well in a Ml Sandstone reservoir presented high seismic uncertainty and limited lateral extent; this well is located in the Napo formation of the Oriente basin in Ecuador. The geology in this basin is complicated; most of the reservoirs are formed from a small, stacked-channel sandstone sequence. As a result, well-to-well reservoirs are difficult to correlate because of their limited lateral extent. Horizontal wells placed in this kind of environment generally require adjustments in the planned directional well trajectory and modification of the navigation TVD when required.

The primary goal of this project was to maintain the well in the sweet spot of the reservoir to improve productivity. As a final delivery, the structural map of the top of the M1 Sandstone enabled the customer to adjust the seismic information in the zone of influence of the well. A major drilling company assumed the challenge by using a rotary steerable system, proactive logging-while-drilling azimuthal resistivity sensors, and 3D geosteering techniques to place the well in the sweet spot of the reservoir and to ensure the permanence in the sandstone reservoir.

The azimuthal deep resistivity sensor can provide a broad quantity of curves with various depths of investigation (DOIs). Having this information as an entry, the geoscientists applied the three logical geosteering phases of model, measure, and optimize. At the modeling stage, the geosteering team selects the appropriate proactive set of variables to transmit in real time, including compensated resistivities at various ranges of investigation, images, and geosignals according to the geology in the area, reservoir thickness, and existing resistivity contrast. The measuring stage begins by obtaining the selected variables in real time with average resistivities that enable the calculations of the distance-to-bed boundary (DTB) using a forward-modeling technique, while real-time images are compared against modeled information for stratigraphycal positioning. During landing, the drilling and geology departments agreed that the reservoir top was 35 ft (10.7 m) shallower than expected. At this point, the directional drilling plan needed to be changed, beginning the optimization stage even before the horizontal section began.

The appropriate combination of reactive and proactive logging-while-drilling sensors enabled the well to be placed parallel to the top of the reservoir, maintaining an optimal distance of 1 to 3 ft, with 100% reservoir exposure in the pay zone and no exits.

The main objectives of geosteering were achieved. The well produced 6,800 BOPD after an initial estimate of 800 BOPD. The top of the reservoir was mapped, thereby improving knowledge of this zone for future study.