bluuebunny/crossref_metadata_2025_split huggingface dataset:
Brazilian Pre-Salt: The Challenges of Coring at a New Frontier
Authors: Peixoto F. T. , de Souza I. S. 
Published: December 2010

Abstract
The recent discovered pre-salt reservoirs in Brazil have been plenty of challenges to coring, as well as other upstream areas. Its coring campaign warmed up in the middle of 2009 and has experienced good and bad moments, but the results were in general quite positive. This paper describes the problems and lessons up till now learned during these coring operations. The reservoirs are Cretaceous carbonate formations overwhelmed by a thick layer of rock; hence they are very hard and abrasive. Furthermore, the presence of faults increases jamming occurrence, when the core sample is not able to enter the barrel anymore due to friction factors. The unusual peculiarities of this scenario require unusual techniques, a new train of thought and an expertise restarting from square one. The lessons up till now learned will guide the next coring jobs at this scenario.
This paper also presents the results of an analysis obtained at this scenario, comparing the performance between different kinds of equipments or techniques, and jamming occurrence. Finally, the paper describes the obstacles faced during a salt coring. There will probably be a big exploration movement at this scenario in the next years. Start a coring job aware of what we will face may save a substantial time and money.
Enhanced Oil Recovery (EOR) Status - Colombia
Authors: Castro R. , Maya G. , Mercado D. , Trujillo M. , Soto C. , Pérez H. , Lobo A. , Ordóñez A. , Sandoval J. E. 
Published: December 2010

Abstract
Secondary and tertiary oil recovery technologies are not a common practice in Colombia. There are only 23 secondary oil recovery applications in a commercial level, and tertiary projects are limited to pilots that for different reasons have not been taken to the next level and to steam injections projects (huff & puff) in some heavy oil fields. However, Colombian interest and knowledge about the topic is every time higher and there exist different registers about an important number of initiatives to laboratory level that included modeling tasks for specific fields.
This paper looks around the different EOR§ initiatives that have existed in Colombia, from laboratory to field scale; in the same way, the research activities that have been done in the Instituto Colombiano del Petróleo (I.C.P.) of ECOPETROL S.A. are highlighted, where an important percentage of the jobs have been done, and where the necessary tools for modeling and evaluating almost every process exist. There are also presented in this paper the actual efforts in EOR, identifying the technologies for which exist the highest attention and the number of projects in design stage.
From the material presented in this article it is possible to understand the EOR potential in Colombia, to identify the increasing interest in the subject, to recognize opportunities in the subject and to learn from the applications done until now.
Dina Cretáceos Field Chemical EOR: From Screening to Pilot Design
Authors: Sandoval J. R. , Pérez H. , Maya G. , Castro R. , Muñoz E. , Colmenares K. , León J. , Sánchez F. , Villadiego D. , Manrique E. , Romero J. , Izadi M. 
Published: December 2010

Abstract
Dina Cretaceous Field is located in the Upper Magdalena Valley (UMV) Basin, Colombia. Producing reservoir consist in a marine-transitional depositional environment with good sand continuity and thickness. Ecopetrol S.A operates the field. The field was discovered in 1969. Primary production peaked at 6,500 BOPD. Peripheral water injection started in 1985 reaching a maximum oil production rate of approximately 10,000 BOPD. Current recovery factor is estimated in 32% of the OOIP with water cuts of 96%. Water injection is operating under adverse mobility ratios (M &gt; 4) due to crude oil viscosity (10.8 cp) at reservoir conditions.
As a strategy to increase oil recovery an integrated study started in October 2009. Main objective of the multidisciplinary group was to evaluate different IOR/EOR technologies, select the most promising technology and identify areas of the field suitable to implement a pilot project. First phase of the study was a comprehensive evaluation of injection-production history of the field and IOR/EOR screening. Simultaneously, the team was also focused on updating the history match of the field injection-production history. The numerical model was based on a high-resolution geological model with a detailed lithological and petrophysical description. Once a reasonable history match was achieved the model was converted into a commercial platform to simulate chemical EOR processes.
The analysis of injection-production history did not support strong water channeling due to the presence of thief zones. IOR/EOR screening results confirmed the feasibility of polymer-based technologies due to the adverse mobility ratios and remaining oil saturation in the reservoir. Reservoir analogs identified during the screening study, conceptual simulations and laboratory studies concluded that the injection of Colloidal Dispersion Gels (CDG) shows high potential to increase oil recoveries economically in Dina Field. A pilot area was selected ranking different options and operational constraints. Pilot project design scheduled for the last quarter of 2010 was based on a sector model of the field.
This study provides guidance to effectively evaluate and implement chemical EOR technologies to revitalize mature water floods. A proper decision framing, availability of data and commitment of management and decision makers are key elements to perform EOR evaluations and implementation is short periods of time.
Analysis of Mechanisms of Flow in Fractured Tight-Gas and Shale-Gas Reservoirs
Authors: Moridis G. J. , Blasingame T. A. , Freeman C. M. 
Published: December 2010

AbstractIn this paper we analyze by means of numerical simulation the mechanisms and processes of flow in two types of fractured tight gas reservoirs: shale and tight-sand systems. The numerical model includes Darcy's law as the basic equation of multi- phase flow and accurately describes the thermophysical properties of the reservoir fluids, but also incorporates other options that cover the spectrum of known physics that may be involved: non-Darcy flow, as described by a multi-phase extension of the Forschheimer equation that accounts for laminar, inertial and turbulent effects; stress-sensitive flow properties of the matrix and of the fractures, i.e., porosity, permeability, relative permeability and capillary pressure; gas slippage (Klinkenberg) effects; and, non-isothermal effects, accounting for the consequences of energy balance and temperature changes in the presence of phenomena such as Joule-Thompson cooling in the course of gas production. The flow and storage behavior of the fractured media (shale or tight sand) is represented by various options of the Multiple Interactive Continua (MINC) conceptual model, in addition to an Effective Continuum Method (ECM) option, and includes a gas sorption term that follows the Langmuir isotherm. Comparison to field data, analysis of the simulation results and parameter determination through history matching indicates that (a) the ECM model is incapable of describing the fractured system behavior, and (b) shale and tight-sand reservoirs exhibit different behavior that can be captured (albeit imperfectly) using some of the more complex options of the multi-continua fractured-system models. The sorption term is necessary to describe the behavior of shale gas reservoirs, and significant deviations from the field data are observed if it is omitted. Conversely, production data from tight-sand reservoirs can be adequately represented without accounting for gas sorption. All the other processes and mechanisms allow refinement of the match between predictions and observations, but appear to have second- order effects in the description of flow through fractured tight gas reservoirs.
Controlling Oil Production in Smart Wells by MPC Strategy with Reinforcement Learning
Authors: Talavera Alvaro Lopez , Túpac Y. J. , Vellasco Marley M. 
Published: December 2010

AbstractThis work presents the modeling and development of a methodology based on Model Predictive Control – MPC that uses a machine learning model, based on Reinforcement Learning, as the method for searching the optimal control policy, and a neural network as a proxy, for modeling the nonlinear plant. The neural network model was developed to predict the following variables: average pressure of the reservoir, the daily production of oil, gas, water and water cut in the production well, for three consecutive values, to perform the predictive control. This model is applied as a strategy to control the oil production in an oil reservoir with existing producer and injector wells. The experiments were carried out on a synthetic oil reservoir model that consists in a reservoir with three layers with different permeability and one producer well and one injector well, both completed in the three layers. There are three valves located into the injector well, one for each completion, which are the handling variables of the model. The oil production of the producer well is the controlled variable. The experiments performed have considered various set points and also the impact of disturbances on the production well. The obtained results indicate that the proposed model is capable of controlling oil production even with disturbances in the producing well, for different reference values for oil production and supporting some features of the petroleum reservoir systems such as: strong non- linearity, long delay in the system response, and multivariate characteristic.
Laboratory Development and Successful Field Application of a Conformance Polymer System for Low-, Medium-, and High-Temperature Applications
Authors: Vasquez J. , Eoff L. 
Published: December 2010

Abstract
This paper presents the laboratory development of an organically crosslinked polymer (OCP) system with a wide temperature range of execution (60 to 350°F). The OCP system is targeted to address conformance problems (water and gas shutoff) to ultimately improve hydrocarbon recovery. This paper presents an overview of case histories in which the OCP system was implemented in various regions of the world in onshore and offshore hydrocarbon-producing wells.
The OCP system has been successfully applied to sandstone, carbonate, and shale formations needing a conformance treatment. The OCP system has proven to be resistant to acid and stable in CO2 and H2S environments. In addition, the activation time and gel strength of the system is not affected by lithology, formation fluids, or heavy metals. The OCP system is acceptable to be used in some areas of the North Sea (including UK and Netherlands).
Recently, a base polymer (for low temperatures) and a retarder (for high temperatures) have been introduced to the system to allow a wider temperature range of applicability without compromising its effectiveness or thermal stability. With the new base polymer, reasonable gelation times (~4 to 6 hours) can be achieved at 60°F with low crosslinker loadings. In addition, the new retarder allows reasonable placement times up to 350°F, without the need of cooling down the formation to obtain enough pumping time. Neither the new base polymer nor the retarder are detrimental to the thermal stability or gel strength of the system.
To date, more than 600 jobs have been performed with the OCP system around the world to address conformance problems, such as water coning/cresting, high-permeability streaks, gravel-pack isolation, fracture shutoff, and/or casing leak repair. Because of the capability of the OCP system to withstand pressure, workover operations have been successfully performed in previously treated wells, including acid stimulation, sand control, and frac-pack treatments, among others. Case histories are presented for onshore and offshore applications.
Proposed Brazilian Fiscal System for Pre-Salt Production Projects: A Comparative Study of Gain and Loss of Government and Companies
Authors: Costa Lima G. A. , Gaspar Ravagnani A. T. , Schiozer D. J. 
Published: December 2010

Abstract
After the discovery of large oil reserves in pre-salt areas of Santos Basin, the Brazilian government has changed the fiscal regime from royalty/tax system to production sharing system, which is the one already adopted in countries like Indonesia, Colombia, among others. The proponents of this idea say that it is necessary, because after these discoveries the exploration risk in this area is low. The proposed fiscal regime has created an intense debate among professionals, institutions and government. Who will be the winner? Who will be the looser? How much will be the loss or gain? At this moment, there is not clear convergence of viewpoint about the forecasting of the impacts on new investment. The reason for the implementation of production sharing system is because government wishes to capture a larger share of the profits. How? Politicians believe that the following policy could bring more benefits to government: in the bidding to new productions projects, the winner will be the company that offers the largest share of production to government. Then, the main objective of this paper is to investigate the behavior of the proposed fiscal regime in terms of production profile, NPV and risk, etc. In order to carry out this study, first, a typical oil field project from the pre-salt area is selected, whose characteristics are: large reserve, located in deep-water and bellow salt layer. After that, it is carried out an economic evaluation, comparison and risk analysis of a production strategy considering both regimes of concession and production-sharing. It is concluded that, it is not always that production-sharing agreement is superior, since it depends on the share of government in production, investment level, operation cost, among others.
BC-10 Brazil: Successful Deepwater 3D ERD Directional-Drilling Strategy Using Seismic Inversion and Point-the-Bit Rotary-Steerable System
Authors: Stockwell L. , Zambrano S. , Bezerra F. , Arevalo Y. 
Published: December 2010

Abstract
The BC-10 project has installed an FPSO in some of the deepest waters worldwide. The well configurations include complex 3D profiles that kick off from vertical in a riserless top hole section very close to the seabed in an unconsolidated formation. In the intermediate hole, high turn and build rates are required for accurate landing at challenging targets close to horizontal. The asset is operated by Shell with a 50% interest with joint-venture partners Petrobras (35%) and ONGC (15%)
Complex lithology among interbedded shales, siltstones, and hard limestone layers generated different directional responses that required collaboration by Shell geology/drilling department and the Schlumberger drilling engineering team to gain a better understanding of the directional performance and formation response so that they could plan the correct drilling parameters and improve drilling performance.
Aggressive dog leg severity requirements for the top hole and buildup sections reaching up to 4.2°/100 ft could not be fully met in the initial three wells. For that reason, a change not only in drilling tool technology but also in the planning workflow process was required. Understanding the formation characteristics and anomalies by using seismic modeling software to interpret and extrapolate directional results to the wells being planned had played a key role in correlating formation tendencies with DLS, RSS capabilities, and drilling parameters performance.
The process consists of analyzing actual drilling parameters in the software (ROP, RSS ratio, DLS, drilling parameters) by correlating them with the respective lithology in the trajectory. The results form the basis of the design for planning subsequent sections to be drilled.
Steep performance improvements regarding DLS capabilities and drilling practices under different lithology tendency profiles enabled new benchmarks for technological limits and well complexity. The new technology and process achieved a step change in performance was achieved for surface sections that was proven in 11 sections drilled. Average days per 1,000 m dropped from 8 to 2.5 days for a savings of approximately USD 15 million.
The techniques developed, the directional results of this initial stage of the project, and the lessons learned are discussed. This new techniques has extended the potential of future ultradeep development projects. As a result, the innovative planning process is being considered in the design workflow for similar borehole profiles worldwide.
Influence of Non-parallel SAGD Well Pairs and Permeability Heterogeneities on Recovery Factors from Warm Heavy Oil Reservoirs
Authors: Bashbush Jose Luis , Pina Jose Antonio 
Published: December 2010

AbstractA key component influencing the final recovery factor of a Steam Assisted Gravity Drainage (SAGD) well pattern is the correct well placement. The optimum spacing and position of the well pairs within the net pay is a function of in-situ oil viscosities, reservoir properties and heterogeneities defining the steam injectivity and the effective heat transfer within the reservoir.The well design parameters are typically optimized with thermal reservoir simulators constructed considering that both injector and producer wells are parallel to themselves, to the formation boundaries and with the well-pairs aligned throughout their entire length. However, due to various operational realities including the precision of the guiding tools that navigate the wells, actual SAGD well pairs in the field are seldom drilled perfectly parallel.The study was directed to wells drilled in thick, heavy oil reservoirs where the combination of very high permeabilities of poorly consolidated sands and reservoir temperatures higher than about 30 °C [86 °F] have the ability to flow cold at reasonable oil rates in spite of having in-situ oil viscosities in the thousands of centipoises.This paper expands the previous work of the authors (2010) analyzing the fact that wells from a SAGD pair in the field are not likely to be precisely parallel and quantifies the effects that this lack of exact parallelism brings to the production rates and overall recovery factors comparing them to the recovery variations that result from small to moderate reservoir heterogeneities.
Integrated Project Management Applied in World-Class Gas-Field Development Projects: From Theory to Practice
Authors: Safra Eduardo Bazo , Antelo Sergio Barrios 
Published: December 2010

Abstract
Stage Gate Project Management Process (SGPMP) is a methodology that has been widely used by many important Oil & Gas companies worldwide. SGPMP aims to improve the decision-making process in Project and Portfolio Management by helping to manage the levels of uncertainty and increase the quality of the projects.
The goal is not the elimination of uncertainties, but to make the best decision in a rational and systematic manner for managing the uncertainties and the associated risks that will always exist in any project.
This document will analyze the application of the SGPMP methodology used to manage and control two world-class gas-field development projects in Peru and Bolivia. It takes into account that the decision whether or not to continue with the project is related to factors such as cost-benefit ratio, risks, funds availability, human resources, as well as project alignment with strategic business objectives.
Implementation of this approach was a challenge, as it was one of the company's first experiences using SGPMP. This experience was a learning process to adapt project management theory into practice.
This paper will be useful for those Project Managers who are considering implementing a methodology similar to SGPMP in their Oil and Gas development projects. It provides key insights about value improvement practices and lessons learned by the authors from the early stages of the projects.
Conclusions and opinions expressed herein are those of the authors and not necessarily those of the company.
Optimization of Completions in Unconventional Reservoirs for Ultimate Recovery
Authors: Snyder Daniel J. , Seale Rocky , Hollingsworth Robert 
Published: December 2010

Abstract
Over the last decade, an industry wide shift to unconventional plays has occurred due to advances in technology allowing for the recovery of previously uneconomic reserves. The primary objective of completions in these unconventional reservoirs is to increase the effective surface area of the well to maximize reservoir contact. Horizontal drilling and multi-stage fracturing are two technologies which have accomplished this.
The two main methods of horizontal, multi-stage completions currently used in unconventional reservoirs are: cemented liner "plug and perf" and open hole, multi-stage fracturing systems. This paper provides an introduction to unconventional reservoirs, describes the main methods of horizontal, multi-stage completions, and discusses how the choice of method can affect good fracturing practices as well as long-term production. Case study examples are presented from a variety of unconventional reservoirs including shale, tight sandstone and tight dolomite formations.
Operators working in a number of unconventional reservoirs, such as shales and other tight rock formations are experiencing faster than expected production decline rates, resulting in reduced long-term, ultimate recovery. This may be in part due to the abandonment of good fracturing practices, developed over the past 50 years, with the advent of horizontal, multi-stage fracturing. Issues such as near wellbore conductivity, flowback, and fracture tortuosity that can have a significant effect on the long-term production of wells need to be considered when choosing a completion method, particularly for unconventional reservoirs.
Unconventional plays are becoming a significant part of the oil industry today and will become a bigger part in the future. It is important that the reservoirs are completed optimally to achieve maximum recovery. The information provided in this paper is applicable to unconventional resource plays worldwide.
Integrated Sand-Production Management in a Heterogeneous and Multilayer Mature Field with Water Injection
Authors: Nunez G. , Amaya M. , Hernandez J. , Agudelo O. 
Published: December 2010

Abstract
Casabe Field since the beginning of primary stage presented sand production problem because the producers are opened with different multilayer and heterogeneous unconsolidated sandstone. Additionally in the first stage of waterflooding project the use of gravel pack was implemented to control sand production, but it generated a large fall down in production due to the mechanical damage, which caused re-pressurization in certain area and drop down injection rate. At the end oil recovery was too low and sweep efficiency very poor.
In the current stage, at first, the sand production was facing by excluding intervals that could produce sand based on geomechanics study made and reduction in PI, but at the end we allow the sand production to increase oil production. Now being conducted an integrated management of sand production by implementing open intervals with high penetration and high density, patterns balance, water injection definition by layer through selective string installed in injector wells, optimization of fluid levels based on pressure drop, real-time sand monitoring, implementation of PCP as artificial lift system, sand fill removal optimization by coiled tubing (using clean fluid and nitrogen), displacement of flow lines and adequacy of surface facilities to better manage produced sand.
It is necessary to learn and live with sand production to increase oil production and profitability in unconsolidated conventional wells instead of looking to avoid it, the solution is to handle in an efficient and economical way.