bluuebunny/crossref_metadata_2025_split huggingface dataset:
IPR in Naturally Fractured Gas Condensate Reservoirs
Authors: Qasem Fuad , Gharbi Ridha , Baroon Bodoor 
Published: June 2014

Abstract
Predicting the performance of individual oil wells is of great importance to petroleum engineering for continuous production optimization in the field. This study proposes a new Inflow Performance Relationships (IPR) for naturally fractured gas condensate reservoirs. Existing IPR models are commonly used for conventional solution gas drive reservoirs. The purpose will be to generate inflow performance relationships (well flowing pressure vs. flow rate) for naturally fractured condensate reservoirs as a function of the average reservoir pressure and fractured reservoir parameters including storage capacity (fracture storativity) and inter porosity flow parameter (interporosity flow coefficient). A dual porosity/dual permeability compositional equation of state simulator is used in this study. A regression program is used to fit the IPR curves and to obtain the corresponding equations. As a result, rational functions have been developed for the IPR curves for gas and oil phases. These correlations are functions of pressure drawdown and reservoir depletion. Additional correlations for predicting future maximum gas and oil rates were developed. The behavior of the future gas rate shows linear relationships between average reservoir pressure ratio and the maximum gas rate ratio. However, a highly non-linear behavior was observed for the oil phase. Additionally, fluid representing extreme types of condensates were also considered. Condensates with high fraction of light composition shows a hump and three distinct regions with different slopes in future maximum rate curves. In the other case where the composition of the condensate contains heavy components has shown nonlinear curves.
Miscible WAG-CO2 Light Oil Recovery from Low Temperature and High Pressure Heterogeneous Reservoir
Authors: Ligero Eliana L. , Schiozer Denis J. 
Published: June 2014

Abstract
Brazilian pre-salt oils should contain a variable concentration of dissolved CO2, which is produced in the gas phase. A sustainable production of these oils requires a destination for the produced gas. As offshore fields have limitations associated to gas manipulation, storage and exportation, miscible CO2 flooding is an Enhanced Oil Recovery (EOR) method with great potential to be employed in pre-salt reservoirs. In fact, miscible CO2 injection in highly heterogeneous reservoirs should increase the oil production. As CO2 flooding is related to high gas mobility, an alternative EOR method is water-alternating- gas injection (WAG). The WAG with CO2 (WAG-CO2) is advantageous in this scenario due to the sea water available apart from enabling the control of gas mobility. In addition, using CO2 as an injection fluid is a viable solution for the GHG problem. Before implementation of WAG injection in a field, the prediction of the oil production through reservoir simulation is recommended. Simplified Black-Oil modeling is not appropriate to simulate a reservoir with light oil and miscible CO2 injection. The rigorous simulation of WAG injection requires a compositional model. Also, hysteresis of relative permeability should be implemented in the simulation model to consider the cyclic hysteresis of the three-phase relative permeability. The case studied has analogous characteristics of pre-salt reservoirs such as light oil with 8% molar of CO2 and initial reservoir conditions of low temperature and high pressure. The phase behavior of the oil and CO2 mixture is represented by an Equation of State that contemplates the swelling resulting from the CO2 dissolution in the oil. As hysteresis modeling requires some uncertain experimental parameters, a sensitivity analysis is carried out to determine the influence on oil recovery. The importance of using the reservoir simulation as a tool to predict the oil recovery before implementing WAG injection in practice is evidenced. It also demonstrated that the sensitivity analysis of the required uncertain parameters to consider the hysteresis is a viable approach to give the pessimistic and optimistic scenarios of light oil recovery prediction under WAG injection.
Solid Expandable Systems Brings New Life to Aging Venezuelan Field and Optimizes Production
Authors: Perez Reina , Romman Randy , Ciliberto Alejandro , Granados Cesar 
Published: June 2014

Abstract
In the early 1970's, drilling started in the Northeast of Venezuela on a series of extended depth wells averaging 16, 000' in measured depth. The field currently produces both crude oil and natural gas of approximately 2, 000 barrels of oil equivalent per day. The subject wells in this paper were drilled in the early 1980's to the same approximate depths. Initially, production remained steady for many years, but mechanical problems discovered in the early 2000's led to re-entry and re-completion of some wells. The plan for re-entry in one particular well began with the use of conventional technologies, re-entering through 9–5/8 casing, running and cementing a 7 in. liner and drilling with best practices to the production zone where a planned 4–1/2 in. production liner would be placed at total depth. While drilling below the 7 in. liner, the operator encountered issues with lost circulation, followed by differential sticking, which led to three sidetrack operations over the next few years. After review, the operator decided on solid expandable technology that would allow isolation of the problem zone into two different hole sections, without downsizing the well. The Solid Expandable liner isolated the unstable zone, while still yielding enough pass through ID to allow for optimally sized drill ahead and the running of a production liner into the reservoir. By covering the unstable zone with the Solid Expandable liner, the operator was able to lower the mud weight before drilling into the production zone, avoiding lost circulation, differential sticking and other associated drilling hazards.
A Simplified Computer Model for Determination of Cuttings Concentration and Wellbore Cleaning
Authors: Gasbarri S. , Wills V. 
Published: June 2014

Abstract
Plugging of cuttings in the wellbore is a common problem during drilling processes. Some authors have analyzed settling or slip velocity of particles in a liquid both analytically and experimentally. The concentration of cuttings throughout the well has been also analyzed. It has been proven that numerical models have the potential to help predict the performance of the cuttings concentration for solving this problem.
A computer model for determining the cuttings concentration for the different processes applied during wellbore drilling is presented. It is a useful tool for the drilling engineer to predict and analyze the drilled cuttings transport to assure efficient wellbore cleaning during operations. The model is based on central difference, and non-Newtonian power low fluids can be used. The effect of the cuttings interaction for different concentration in the settling velocity was determined experimentally. The model was designed to allow the user to calculate the cuttings bed formation, determine whether the bed remains stationary or build ups and analyze the position of the cuttings bed formed and the height of the cuttings bed layer.
Using a typical case study, the wellbore cuttings concentration and the height of the cutting bed are shown for the different processes; i.e. during hole-cleaning and shut down. The effect of operating parameters, wellbore geometry, non-Newtonian fluid parameters and cutting characteristics was analyzed. This computer model is a helpful tool to predict stuck problems and speed up wellbore cleaning processes.
Inflow Performance Relationship Equation for Solution Gas-Drive Reservoirs under Gravity Segregation
Authors: Padilla-Sixto R. , Camacho-Velázquez R. 
Published: June 2014

Abstract
Based on synthetic results obtained by Padilla and Camacho for the fluid flow of gas and oil in reservoirs producing by solution gas-drive (SGD) and gravity drainage (GS), in this paper the behavior of the oil mobility function in partially and fully penetrated wells is studied; also its influence on the development of a practical IPR equation is analyzed.
It is concluded that the Fetkovich's straight line approximation with an ordinate to the origin equal to zero is valid only when the production comes from the middle of the production thickness with and without gravitational effects. Also, changes of the gas saturation with depth due to the influence of gravity drainage and also the measurement position causes that the ordinate of the mobility function, λ(p) = ap+b, be different from zero; however, this linear approximation is reasonable at long producing times during the boundary dominated flow period around the wellbore. For partially penetrated wells this consideration is not entirely appropriate.
Considering the above results, a productivity coefficient (ϑ) defined as the ratio of oil to the total productivity index is defined. A quadratic IPR equation valid for any position of the production interval is derived. The quadratic flow efficiency definition given by Camacho and Raghavan is considered. A table of normalized reference equations for different productivity coefficient values is presented, where the classic equations of Vogel, Fetkovich and constant productivity index are particular cases. Finally normalized cubic correlations for totally and partially penetrated wells also are obtained. The equations were proved with information of real field cases of saturated naturally fractured reservoirs (NFR's) of Mexico.
A New Engineering Approach for Gas Anchor Applications for Extra Heavy Crude Oil –Study Case at PetroPiar in the Orinoco Belt
Authors: Díaz Sierra J. , Moreno Mendoza O. , Rivas Johnson S. , Arredondo M. 
Published: June 2014

Summary
Wells with high gas/oil ratio (GOR) using progressing cavity pumping (PCP) or rod pumping (RP) typically have a high gas/liquid ratio at the pump intake. For those wells, the use of a downhole gas separator is crucially important to remove as much free gas as possible from the stream reaching the pump. This makes possible to increase pumping volumetric efficiency under reasonable speed conditions and thereby improve well productivity.
In applications of PCP is well known that pump performance degradation occurs when handling high fractions of free gas (GVF). Gas blockage, lack of lubricity, reduced heat dissipation, elastomeric swelling, etc., are some of the different problems that occur to the pump before it tear down.
Typically the design of downhole gas separator for light or medium crude oil uses separation efficiency values based on empirical trials and settling velocity criteria in biphasic streams. This approach has enabled the industry to mainly develop concentric configurations based on vertical positioning.
In the Huyapari field, at least 43% of the wells have free gas at bottomhole conditions in the range of 70–90%. This represents a great opportunity to develop reliable gas separation technologies, looking to improve pump efficiency and run life.
This article describes a pilot-scale study of two high GOR wells to evaluate the performance of a "cross flow" downhole gas separator designed for heavy oil production in horizontal wells. This low cost equipment has no moving parts; its configuration is robust, easy to build and simple to be ran in the bottomhole assembly (BHA) at slanted positions.
Free gas and liquid separation theory is briefly reviewed to show the most adverse conditions for gas separation present in extraheavy crude oil at field conditions.
Production results before and after application showed an increase in the annulus gas rate from 48% up to a range between 55 and 75%. This has promoted improvement in pump efficiency, greater differential pressure in the tubing column and a production increase in the well operating at a lower PCP speed.
Experimental Inter-stage Study of an Electrical Submersible Pump Handling Viscous Fluid in Multiphase Conditions
Authors: Ibarra Javier , Valderrama Alberto , Gonzalez Juan , Carios Enrique 
Published: June 2014

Abstract
Electrical Submersible Pumps (ESP) are turbo machines that deliver energy to fluids using several stages comprised by one impeller and one diffuser. ESP performance is affected by viscosity variations and changes in the value of gas void fraction of the fluids that are pumped. For any centrifugal pump, as the viscosity of the fluid increases, the required brake horsepower increases as well; whereas, head capacity and efficiency decrease. Additionally, gas void fraction presented in multiphase pumping condition may affect negatively the head capacity of ESP systems. This research had as main goal to evaluate, in a fit for purpose test rig, a 513-series, 35-stage, mixed-flow-stage pump under two-phase flow conditions. Pressure and temperature changes at several stages through the pump were recorded. As a fluid, it was selected a multiphase mixture with air and ISO 320 mineral oil. The experimental matrix included tests with range of gas void fraction from 0% to 17%, 50 psig as pump intake pressure and 50 Hz of operating frequency. A better performance of downstream stages, located in the upper section of the ESP, was reported. A considerable rise of fluid temperature throughout the pump's stages was particularly reported in a range from medium to low flow rates. Furthermore, it was corroborated the unstable pumping region, where surging phenomenon occurred. The study was operational constrained by health security and environment restrictions – specifically the impossibility of using real heavy crude oil and gas as pumping fluid. The resulting information will allow better understandings of the ESP performance focused on multiphase pump condition where viscous fluids are present.
First Hole Enlargement From 8 ½ to 9 ½ Inches With Point the Bit Rotary Steerable System and Hole Opener in a High-Inclination Well in Ecuador: Session 32: Recent Advances in Drilling Technologies
Authors: Sanchez Jose Luis , Carrizo Hector , Camacho Gustavo 
Published: June 2014

Abstract
Palo Azul field in Ecuador has always presented challenges for drilling high-inclination wells. The main issue is the natural tendency of the Napo formation to drop inclination even when using fulcrum or push-the-bit bottom hole assemblies (BHAs) designed to build inclination. Napo formation is composed of many intercalations of sandstone, limestone and unstable shale.
With the introduction of a Point-the-Bit rotary steerable system (RSS), a successful drilling campaign was developed. The capacity of this RSS to build inclination in 8 ½-in-hole sections independently of the type of formation drilled was the technical solution to build inclination while drilling through the formation that historically causes a drop in inclination. However, short trips to the 9⅝-in casing shoe and trips to surface have been very difficult, with several problems such as packing off, tight hole and back-reaming.
Several times the 7-in-liner did not reach the bottom of the hole, requiring an extra trip to condition the well for a new attempt to run the liner.
The use of a hole opener to enlarge the hole from 8-½ to 9-½ inches while drilling with a point-the-bit RSS was the best technical solution to finish the hole section in a single run, avoiding extra trips to surface and ensuring a clean 7-in-liner run.
The point-the-bit RSS and hole-opener run performed in this study was the first successfully run in a high-inclination well (51° to 68°) in Ecuador, generating an average dogleg severity of 5°/100 ft.
This technical solution is allowing the operator to plan more high-inclination or horizontal wells to optimize Palo Azul field production.
The synergy between the Directional Drilling Company and the hole opener provider to simulate and execute the run described above with an integrated BHA was the key to success in implementing this technological solution for the client.
Geoengineering Data Integration at Petrobras Production Engineering
Authors: Schonmann M. V. , da Silva J. B. , Oliveira A. G. 
Published: June 2014

Abstract
The O&G industry has been realizing that the implementation of Data and Information Governance (DIG) has a significant impact on their business initiatives in all levels of the company, such as the strategic, the tactical and the operational ones. The DIG has the aim to guide the company to manage its data assets through the implementation of rules, policies, procedures, roles and responsibilities. In essence, the DIG is a multidisciplinary function led by the company business areas. Its success depends on the clear definition of the technologies, processes and people aligned with the Information Technology (IT) strategy.
The Petrobras Production Engineering is implementing governance model which focus on the data integration that subsidizes the work processes in the geoengineering disciplines. In the geoengineering workflow, the geophysicists work with great volumes of data to do the best reservoirs' characterization. From the results produced by them, the geologists, sum to geophysical studies, data and information from the research labs, from the Petrophysics and from the Geomechanics, among others, to construct the reservoirs static structure. The engineers receive the geological studies and work with them generating dynamics flow studies of reservoirs within the various probabilistic scenarios for the estimation of the O&G reserves production as well as to subsidize economic analysis. Each area of study manages their data universe and the results are supposed to work both ways, moving and flowing in a coordinated and integrated manner amongst the disciplines.
The goal of this article is to present the strategy used in the implementation of a DIG model, describing a methodology and the achieved results. This methodology was supported by the IT and Production Corporate management which defined a strategy for conducting diagnosis in all Production Engineering business units' areas involved. With these results it was possible to identify opportunities for improvement and the definition of the best place to start was prioritized. It was clear the necessity to have a data and information management group working in all the business units and the adoption of new technological solutions used by the company and the industry supported by the IT.
Reduced Order Modeling In Reservoir Simulation Using the Bilinear Approximation Techniques
Authors: Ghasemi Mohammadreza , Ibrahim Ashraf , Gildin Eduardo 
Published: June 2014

Abstract
Despite great advances in reservoir simulation capabilities with the introduction of high-performance computing (HPC) platforms and enhanced solvers, high fidelity grid-based simulation still remains a challenging task. This task is especially demanding for fine-resolved geological reservoirs with multiphase and multicomponents and in production optimization and uncertainty quantification frameworks where several calls of the large scale simulation model need to be performed. Model order reduction techniques have been applied in porous media flow modeling in order to obtain fast simulation surrogates to alleviate the high computational cost associated with these simulations. The difficulty of applying model reduction techniques to porous media flow arises from the nonlinearity of the system. In order to overcome the issue of nonlinearity, we introduce the bilinear form of the dynamical system which in many cases produces a satisfying approximation of the system. The bilinear approximation is a simple form of the parent system and it is linear in the input and linear in the state but it not linear in both jointly. The bilinear form is computed using truncated multidimensional Taylor's expansion of the system terms. Examples are presented to illustrate this recent approach for the case of single phase flow modeling, and comparisons are made with the case of linearized models and the full nonlinear models. In addition, we present methods to reduce the complexity of the bilinear system of equations and results are presented that compare linear model reduction (balanced truncation) and nonlinear model reductions, such as POD techniques.
Catalytic Effect of Metallic Additives on In-Situ Combustion of Two Brazilian Medium and Heavy Oils
Authors: Strazzi Alfonso , Trevisan Osvair Vidal 
Published: June 2014

Abstract
Increasing the final recovery factor from mature fields is a major challenge to meet the growing energy demand in the coming years. The in-situ combustion, an important thermal enhanced oil recovery method, has experienced an increasing interest as an alternative solution to this challenge.
In-situ combustion is the process of injecting oxygen into oil reservoirs where a portion of oil is burned and heat is in-situ generated. As consequence the oil viscosity decreases resulting in larger oil recovery factor. The propensity of the reservoir oil to form fuel is a major constraint limiting the applicability of the in-situ combustion. In lighter oil reservoirs insufficient fuel may be deposited resulting in a combustion front that cannot be self-sustained. Contrariwise, in heavier oil reservoirs excessive fuel may be deposited leading to high air injection. Metallic salts are known to play an important role as a catalyst and thereby affect the amount of fuel formed.
This paper describes an experimental study with eight combustion tube runs to evaluate the effects of metallic additives in the combustion of two Brazilian medium and heavy oils. The oils are 12.8° and 27.2° API, respectively from an onshore field in Espírito Santos Basin and an offshore field in Santos Basin. The metallic additives are iron nitrate and zinc nitrate.
Results for the heavy oil show that a self-sustained front combustion can be obtained only with the presence of clay, due to its catalytic effect. The addition of iron nitrate increased the fuel concentration while increasing the air requirement and reducing the combustion front velocity. The addition of zinc nitrate also increased the fuel concentration and increased the air requirement and reduced the combustion front velocity. Interesting results were observed for the medium oil: a self-sustained combustion was not achieved only with the presence of clay, but stable and sustained combustions were observed with the addition of iron and zinc nitrates.
Iron and zinc salts are metallic additives with potential to expand the range of candidate reservoirs for in-situ combustion. Further studies are necessary to evaluate potential additives to act as fuel reducing agent.