bluuebunny/crossref_metadata_2025_split huggingface dataset:
Selection of Infill Drilling Locations Using Customized Type Curves
Authors: Al-Kinani A. , Nunez G. , Stundner M. , Zangl G. , Iskandar O. , Mata T. , Cottone S. , Cavero J. 
Published: May 2009

Abstract
This paper discusses a new workflow to stochastically estimate the performance of infill locations in a mature oil or gas field. Usually performance evaluations for infill wells are conducted using either much generalized statistical methods or numerical simulation. Both approaches have a significant drawback; the prior being quick however very often lacking in accuracy, the latter being very accurate however usually very complex in setup and computation.
The presented workflow is a new approach to infill well performance prediction that combines speed and reasonable accuracy. The workflow generates a set of key performance indicators of existing wells derived from historic dynamic data (fluid production rates, pressures, etc.), static data (reservoir properties, etc.) and predicted data (simplified production forecasts). The wells are then grouped according to the similarity of their KPIs. The production profiles of the wells within the same group are combined to a type curve that is described by the most likely production profile and an associated uncertainty range.
A data-driven expert system is used to identify and capture the correlations of the parameters such as geographic locations, well spacing, reservoir properties and the group membership (equivalent to type curve). This expert system can then be applied to any location in the field in order to determine the most likely group membership of a potential infill well. The classification of an infill well to a group is hereby not necessarily unique; the expert system might classify an infill well into several groups and assign a probability of occurrence for each of the groups. A Monte Carlo routine is then applied to forecast the performance of the infill locations honoring the respective probability of occurrence of each type curve.
The presented approach has been successfully applied for infill well selection in a statistical field development study for YPF in the Argentinean San Jorge Basin.
Noncontinuous Steam Injection Optimization for SAGD Process for Improving Heavy Oil Recovery
Authors: Barillas J. L. M. , Dutra T. V. , da Mata W. 
Published: May 2009

Abstract
Several processes for improved oil recovery are thermal and are based on steam injection. Through these methods is possible to heat the reservoir, reducing oil viscosity and increasing the oil-phase mobility, allowing a better oil displacement in reservoir and increasing swept efficiency. Nowadays, one of the most promising thermal recovery technologies is Steam Assisted Gravity Drainage (SAGD). In this process, two horizontal wells, separated by a vertical distance are placed near formation bottom. Horizontal top well is used for steam injection, which creating a steam chamber which grows upper and to surroundings allow heat transfers between steam and oil by conduction. Bottom well is used for oil production.
SAGD process appears to be technically attractive, due to the high recovery and highs oil rates and oil-steam ratio. This process was applied in country such U.S.A., Canada and Venezuela. In this work, it was idealized a reservoir with some northeast Brazilian characteristics in a homogeneous model. It was done an optimization of steam rate, in a non continuous form, injected steam for several time periods. For the optimization study was also realized a net present value study and it was compare to a process with continuous steam injection. All the cases studied were done using the software STARS from CMG (Computer Modelling Group).
This study showed that, in SAGD process, steam requirement can be reduced by injecting it in a non continuous form, alternating steam injection with stops at several time intervals. It was possible optimized these intervals minimizing heat losses and improving oil recovery. The optimal time interval was found at six months that mean, it can injected steam for six months and then stops the steam injection for next six months. When it was compare to a system with continuous steam injection, was founded that this system had a lower net present value that the system with steam injection with stops. It was founded that was possible to reduce water production, with an improved of oil recovery.
In this work was obtain a way to optimized steam rate, minimizing heat losses and increasing net present value, in reservoirs with some Brazilian Northeast Basin characteristics, and that become important, because it is necessary to improved heavy oil recovery with minimal environments damages, and with lower production cost.
Application of an Advanced Dynamic-Underbalance Perforating System for Improved Oil Production in Development Wells: Case Histories from Eastern Venezuela
Authors: Casas C. , Mattey A. , Molina O. , Larez A. , Mata J. , Fam M. , Fernandez R. 
Published: May 2009

Abstract
The deep reservoir sandstones of the El Furrial and Pirital oilfields, located in northern Monagas state, eastern Venezuela, are famous for their high degree of geological complexity and heterogeneity. Typical well completions in this area consist of natural flow from multiple intervals through perforations in cemented casing. However, conventional perforating guns used in these completions cause additional near-wellbore formation damage that adversely affects well productivity and results in reduced productivity indexes in these wells.
There have been significant efforts in recent years to implement new methods and technologies to produce cleaner perforations and better production rates. One of these technologies is a new dynamic underbalance perforation system which allows precise management of the underbalance differential pressures to produce a relatively clean perforated tunnel while minimizing formation damage. Application of this system results in improved connectivity between the reservoir and wellbore which allows substantial improvement in oil production rates.
Formation petrophysical properties are used to determine whether an interval is a suitable candidate for application of this technology. A separate nodal analysis model is created for every reservoir interval in each well. These models are designed to represent the actual and expected production conditions and account for reservoir heterogeneity. In the El Furrial and Pirital fields, reservoir properties can vary widely: permeabilities from 0.1 to 1,000 mD; porosities from 9 to 18%; oil gravities from 22° to 32° API; static pressures from 6,000 to 8,000 psi; and confined compressive strengths from 7,000 to 20,000 psi.
This paper presents case histories from wells in eastern Venezuela to illustrate the production benefits derived from this advanced perforating system technology. In three wells, supporting evidence demonstrates that near-wellbore damage caused by this new innovative underbalance perforation system is close to zero, resulting in over 100 % increase in the productivity index. In the fourth case history, we discuss the reasons why the actual well production rates did not achieve the rates projected by nodal analysis.
Improved Drilling Performance: Downhole Dynamic Logging Tools Break Paradigm in Ecuador
Authors: Barton S. , Clarke A. , Garcia A. , Perez D. , Mora G. , Carrion C. 
Published: May 2009

Abstract
In today's high cost drilling environment, vibrations are recognized as the primary contributor to drilling inefficiency. As such, accurate prediction, identification, and quantification of vibration along the drill string has become increasingly important in order to reduce drilling costs. Near-bit measurements are also particularly important, as the drill bit is often predicted to be an important cause of vibration.
This paper reviews a project within Ecuador, where high vibration and mechanical damage to drill bits has been observed, clearly affecting performance. This application is drilled with Fixed Cutter (FC) bits on a Rotary Steerable System (RSS) through a challenging sequence of formations including sandstone, shale, limestone, and conglomerates. Initial steps had been taken to optimize the drill bit design in terms of cutting structure, gauge geometry, and cutter technology. However, in order to truly understand the vibration issues, a unique downhole dynamic logging tool was utilized. This tool records drilling dynamics data at a high frequency sample rate, enabling lateral and torsional events to be accurately identified and recorded. Due to its size, and thus flexibility in string placement, the tool was located in two different points in the BHA.
Evaluation and interpretation of the vibration data led to the recommendation of new drilling parameters, very different to traditional practices in this application, in a critical section for the next well in the same pad. This resulted from detection of torsional vibration, not only at the bit, but also at points along the BHA.
Implementation of the recommended drilling parameters resulted in significant mitigation of torsional vibration at the bit and in the BHA. This resulted in reduction of wear to components within the BHA, as well as both time and cost savings in excess of $200K.
Fracturing Very High Permeability Gas Wells in Offshore Brazil: It Works!
Authors: Neumann L. F. , Rocha J. D. H. , Denadai N. J. 
Published: May 2009

Abstract
This paper presents the results of a fracpack campaign in a series of very high permeability gas wells in Espirito Santos Basin, off-shore Brazil. This first fracpack campaign in four wells was conducted from March 2007 to June 2008. Permeability ranges from high 50 mD to very high 200 mD.
The main debate was internal: why does someone need to fracturing very high permeability gas wells? In fact, this question is associated to two issues: overcome formation damage and assure very reliable sand control. The answer is obvious: fracpack.
Several injection tests and minifrac prior to the main treatment were performed in order to address mainly closure stress and fluid leakoff although perforation friction, near-wellbore tortuosity were minor concerns. The main drive was the amount of fluid required to effectively propagate a fracture in such very high permeability gas wells. Again, someone claimed the volumes would be enormous! However, it was observed that this volume was almost the same ordinary volume used in Campos Basin's regular oil fracpacks.
The results were outstanding. The production tests showed some of the greatest absolute open flows in Brazilian gas wells. All the wells are current in production and sustaining the very high productivity levels.
Rock Types and Flow Units in Static and Dynamic Reservoir Modeling: Application to Mature Fields
Authors: Osorio Peralta Oscar 
Published: May 2009

Abstract
The definition of rock types (RT) and flow units (FU) in the static and dynamic models is useful to have a better description of the potential zones with a reservoir quality. The study and integration of information from conventional and special core analysis, well logs, test pressure, geocellular model, gridding and properties upscaling to simulation are required for the reservoir modeling characterization.
The Winland and Flow Zone Indicator (FZI) methods to identify RT, as well as, the Stratigraphic Modified Lorenz (SMLP) method for FU; are the most used techniques to determine the properties at the well level. This document describes a workflow of that techniques at well level to be applied to the 3D static and dynamic reservoir models. The main objective is to identify the different features of the RT and FU in the entire reservoir. As result of this methodology, the FU are well defined and are used to determine the zone mapping in the upscaling process to perform the reservoir simulation model; and put new wells with oil opportunities in a mature field.
Impact Analysis and Interpretation of the Sand Thickness Obtained From Electric Logs and Outcrops in the Geostatistical Modeling of Stratigraphic Complex
Authors: Gómez R. A. , Morales J. , Pérez H. H. , Sandoval J. E , Jaimes M. A. 
Published: May 2009

Abstract
In the modeling of deposits with a stratigraphic complexity, one of the main purposes is to determine in 3D, the direction, continuity and distribution of sand layers. This goal is achievable with a degree of uncertainty depending on the information available such as the 3D seismic to interpret the filled canal deposits, as well as the electrical logs that allow definition in the vertical. Unfortunately in mature fields, we have little information which mostly consists only of 2D seismic and well logs. Under these conditions the definition of potential channels becomes a process with highly uncertainity and requires further work on integration of geological data field and electric logs to achieve a first approximation to the distribution channels of different formations and thus achieve improved geostatistical models.
A methodology is proposed, based on a statistical analysis of the different sand lenses identified in the electric logs. With this statistical analysis the value of average thickness of the predominant channels for each formation is obtained, which are supported and integrated to the collected information from data from outcrops in a phase of field and thereby define its main features. This definition of the cannel, guide allows geostatistical modeling in such stratigraphic fields with acceptable results according to the response of the existing wells.
The methodology was applied to the Mugrosa and Colorado Formations in the Lisama Field, located in the Middle Valley of the Magdalena River in Colombia, to conduct a geostatistical modeling based on objects to which the petrophysics of the facies information was integrated, leading to obtain the modeling of channels not only in direction, but also in size, continuity and its associated petrophysical properties.
Foam Detection in Process Units
Authors: Fransen G. , Carbajal R. , Guevara I. 
Published: May 2009

Abstract
Foaming in refinery applications and production processes has been a longstanding industry concern. Commonly available solutions such as DP gauges, capacitance probes and electromagnetic radiation, to name a few, fail to provide early warning detection1. These technologies only detect the presence of foam after severe foaming has occurred and often not until the foam has upset downstream operations leading to off-spec products, loss of liquid product due to foaming carry-over, damage to compressors, reduced through-put and increased chemical usage.
Because foam buildup can occur in many production, refining and petrochemical processes, the need for a technology that acts as an early warning system, accurately detects the presence of foam, responds to changing foam concentrations, and automatically adjusts the defoamer injection rates in the process separators/contactors before upsets occur is critical.
A newly marketed foam detection system, operating on the principle of energy absorption, meets these criteria. The foam detector is a device that is installed into the process vessel providing early detection as foam begins to form - advising operations to take preventative action before process upsets or equipment damage occurs.
With this early detection system, operators can automatically initiate or increase the anti-foam chemical injection rate causing foam to dissipate. As a result, anti-foam chemical feed rates are optimized, which in turn, reduces overall chemical costs.
Application of Combined Technologies for the Treatment of Phenols in Wastewater Oil Productions
Authors: Restrepo R. , Forero J. E. , Cardenosa M. , Gonzalez J. 
Published: May 2009

Abstract
The removal of phenols from wastewaters at crude oil production fields is one of the most important challenges in the Arauca-Field of ECOPETROL S.A. (Saravena, Arauca). Based on the review of available technologies for wastewaters treatment with variable phenol concentrations above maximum allowable limits, both at National and International levels, a combined alternative using biological (biodegradation) and physical (aeration - photo oxidation) technologies was considered. The implementation of this combination of technologies allowed the crude oil production field to comply with phenol concentrations at the discharge, obtaining higher than 99% removal efficiency and being consistently lower than the maximum allowable limit set by environmental authorities.
Inflow Performance Relationships for Heavy Oil
Authors: Gasbarri S. , Martinez V. , Garcia J. , Pinto R. , Garcia L. , Gil C. 
Published: May 2009

Abstract
Inflow Performance Relationships, IPR, are quantitative estimates of the productive potential of a well-reservoir system. Through this relationship, engineers determine basic elements such as the optimum production scheme and artificial lift design and operation. Several authors studied IPR in vertical and deviated wells considering two and three-phase flow in light oils. Other studies have also estimated productivity index for horizontal and slanted wells but only based on single-phase flow. All of them have not explicitly included how the oil API gravity affects the performance.
Since a large amount of the world oil reserves are heavy oils, the goal of this research is to generate a general Vogel type correlation valid not only for light oil reservoirs but also for heavy oils. The experimental study, performed with numerical reservoir simulation, was run over variables such as: permeability; relative permeability curves; reservoir pressure, degree of depletion, and PVT fluids properties. Due to the huge advantage of horizontal and deviated wells for producing heavy oil, vertical to horizontal permeability ratios was also analyzed within different angles of inclination. Furthermore, different water cuts were generated for vertical wells using reservoir water saturation in order to evaluate the effect of this variable over the IPR.
A general correlation for the V coefficient of Vogel's equation was generated that depends on the angle of inclination of the well, and several reservoir and fluids characteristic. Additionally, reservoir depletion was addressed through the reservoir pressure ratio with respect to the bubble point pressure. The application of the relationship described in this study is simple and only requires common known parameters of the field.
Waste Injection: The Environmentally Safe and Cost-Effective Solution for Ultimate Waste Disposal
Authors: Ovalle A. , Ronderos J. , Simmons S. 
Published: May 2009

Abstract
As the worldwide consciousness concerning environmental protection evolves along with the technology, the need for new methodologies to dispose of oilfield wastes in a safe manner grows under tight governmental regulations and careful management of risks, liabilities and costs. This is particularly true for remote areas such as deep water and environmentally sensitive locations where there is a strong emphasis on protecting the natural resources of the drilling area. Accordingly, many regulatory agencies demand zero-discharge policies and require all generated wastes to be disposed in a responsible manner. Such a process involves the adequate management of by-products generated during drilling operations including cuttings, excess drilling fluid, contaminated rainwater, produced water, scale, produced sand, and even production and cleanup waste. Old practices involve temporary box storage and hauling of the waste products to a final disposal site. Often, these practices create not only liabilities for the operating company but also environmental risks such as accidental spills, gas emissions and eventually, high operating costs.
Waste Injection (WI) into sub-surface formations has proven to be the most effective technology for final disposal of wastes from oil and gas drilling and production that provides a secure operation achieving zero discharge. WI achieves this by storing the injected material several meters below surface in hydraulically created fractures, avoiding surface environmental risks and future liabilities for operating companies.
This paper presents the methodology based on risk analysis, supported by successful worldwide case histories, to prepare an operational and cost-efficient operation that continuously analyzes information and provides fit-for-purpose recommendations to achieve a seamless injection process. The Assurance Waste Injection process permits the detection and identification of potential risks giving mitigation options to prolong the life of the injector.
Water Injection in Espadarte Module I Field
Authors: Reid M. G. , Melo V. L. A. , Lima L. M. S. , Serra A. L. S. 
Published: May 2009

Abstract
Espadarte Field is located in Campos Basin at about 110 km offshore of Rio de Janeiro state, Brazil. The water depth ranges from 750 to 1,500 m and its ring fence has an area of 720 km2.
The Espadarte field exploitation strategy comprises 8 producers and 5 injectors and was developed using subsea vertical, deviated and horizontal wells, all they producing to the FPSO Espadarte. These wells produce from 4 oil reservoirs with maximum thickness of 53 m and saturated with 29° API oil and the production started in August 2000. Water injection started in 2001 and it is the main drive mechanism to replace the reservoir energy, having the field an active aquifer as well. In 2002, after the seawater breakthrough, a production decline was observed and Barium and Strontium Sulphates scale were detected. After that, the seawater injection was stopped in order to provide a Scale Control Plan, based on a remote inhibitor squeeze treatment.
During the seawater injection interruption, an intense production decline and pressure reduction in the reservoirs was observed. In 2005, the injection was resumed and improvements in production and reservoir pressure were observed immediately.
In 2007, a study to increase the seawater injection in the field was conducted to anticipate the production. From this study, several parameters were analyzed, including the reservoir fracture pressure, the capacities of water injection and treatment at the production facility, the wells injectivity index and the quality of injected water. These parameters are monitored by technical teams including reservoir, production operation and lifting & flow people.
This paper presents the methodologies adopted to increase the seawater injection in the Espadarte Field Module I. It is discussed the reservoir management and the results obtained with the reservoirs pressurization, namely production anticipation and stability of the process.