bluuebunny/crossref_metadata_2025_split huggingface dataset:
Integrated Methodology for Laboratory Evaluation of Shale Plays Cores
Authors: Pérez E. R. , Pachón Z. , Gómez J. J. , Marin M. P. 
Published: June 2014

Abstract
In the last 10 years, shale gas has emerged as an alternative source because of its contribution to oil and gas reserves. Colombia has a high hydrocarbon potential in unconventional shale gas deposits, and this become the main objective of the national oil industry. Currently proven reserves of conventional gas in Colombia are about 6 TCF, while technically recoverable reserves of shale gas according to the US. Energy Information Administration (EIA) studies1 are about 55 TCF, so successful production of these reservoirs will increase significantly gas reserves in Colombia.
Ecopetrol was the first company in Colombia in starting the characterization of unconventional shales through the stratigraphic well La Luna-1 located in the Medium Magdalena Valley, from which 3445 feet of core were recovered in five months between 2011 and 2012.
The need for interpretation frameworks in order to understand properties such as rock source quality, mechanical properties and production performance from a diverse range of measurements require a laboratory characterization of rock properties that is an important part of any resource evaluation. This was the challenge for the labs of the Colombian Petroleum Institute, that based in its experience in Conventional reservoir analysis could adopt its skills and methodologies for analyze 2851 rock samples. The work flow includes geochemical analysis for Total Organic Content (TOC), Pyrolysis Rock Eval VI (parameters S1, S2, Tmax) and quantification of gas content (canister). Samples selection for other analysis was based on core Tomography and Spectral Core Gamma. From the same foot of core, the samples were taken for petrographic analysis, quantitative mineralogical analysis by XRD, mineral distribution and microtexture by SEM, geomechanical Analysis (elastic module and the rock strength), basic petrophysical analysis and Mercury Injection Capillary Pressure (MICP). The information obtained was integrated in order to obtain petrographic rock types, hydraulic rock types and identify the most prospective intervals. The coherence in the parameters obtained by different methods demonstrated the sturdiness of quality system and methodologies applied.
PCP Run Life Improvement in Orinoco Belt With New PCP Technology
Authors: Caballeroa D. , Hurtado Y. , Gomez A. , Zimmer L. 
Published: June 2014

Abstract
In 1997, the commercial development of the large Heavy & Extra Heavy Oil (HO & EHO) resources of the Orinoco Belt (7 to 12° API / Estimated 295 Bbbl of Recoverable Crude Oil) was initiated. The SINCOR Project (SINcrudo ORiente – then a JV between Total, Statoil & PDVSA), now operated by Petrocedeño JV, was the first of its kind in the area, and until today it is considered as a reference when it comes to developing the most recently allocated blocks in the area.
After more than 10 years of intensive production programs, some fields are showing signs of depletion and associated production of gas is increasing. PCM, who is involved in supplying Progressing Cavity Pumps technologies to the Orinoco belt since the very beginning, has developed the exclusive & patented HR-PCP (Hydraulically regulated PCP) technology in order to extend run life of the conventional PCPs in these fields where ALPCP systems' Mean Time Between Failure (MTBF) has shown sharp decrease in the last few years.
In 2011, a project was launched in collaboration with Petrocedeño optimization department in order to validate HRPCP technology in this field. 2 × 115E1600 HRPCP pumps were installed in XA07 & YA02 selected wells. The wells selections criteria were: Wells with high gas production & high estimated GVFShort pumps run life
Following the study of Progressing Cavity Pump Technology's behavior in Multiphase conditions (SPE95272), the subsequent development of the "New PCP" (SPE 97833), and the example of the first commercial and large scale deployment in Argentina (SPE 152228), this paper shows how the HRPCP Technology benefits to the specific Orinoco Belt environment, and what this technology could bring to further development of this heavy oil basin.
Preventing Premature Gravel Pack Failures Using FLUX Calculations on High-Rate Dolphin Field Gas Wells_A Case Study
Authors: Lerza A. , Dolan J. , Guerrero A. 
Published: June 2014

Abstract
One of the most important rock properties in Reservoir Engineering is very often absolute permeability. Unconsolidated sands offer some of the highest permeabilities due to their typically low consolidation degree, leaving more space between the porous media for conductivity. This low degree of consolidation, however, also brings high sand production potential while producing the reservoir; therefore sand control is required. This paper discusses how well failure histories were used, along with downhole analytical methods, to determine maximum FLUX limitations recommended to be used to minimize completion failures and sand production while producing at the highest safe rate.
Chevron has a 50% working interest in an NOJV area with BG, in three different offshore dry gas fields located in Trinidad and Tobago. Dolphin field is the main producing field, having been on production since 1996 from four main groups of sands, all of which are unconsolidated (D, Upper E, Lower E and G sands). Due to the sands highly unconsolidated nature and targeting high gas production rates, all completions in the field utilize openhole gravel packs for sand control.
During the field production history, several sand completion failures were encountered, as evidenced by formation sand production at the surface and reduced rates; and in some cases, complete cessation of flow (due to sand fill). After completing various analyses on possible failure root causes, it was found that the highest probable reason for sand completion failure was high FLUX across the completions. After drawing this conclusion, it was imperative for the Reservoir Management and Production Teams to understand FLUX associated with the failures, determine the maximum recommended FLUX to avoid future failures and finally, to apply a FLUX limit on current and future forecasts, from a prudent reservoir management perspective, in order to develop more realistic and reliable production forecasts.
This case study shows how the failure history data was used and integrated with a downhole velocity analytical approach in order to determine the maximum FLUX limit to prevent current and new completion failures and sand production.
Journal Assurance Data (JAD) – Customization and Integration of Standard Production Tools at Orncem for Ensuring Quality Control of Production Data from Sacha Oil Field
Authors: Díaz A. , Caicedo P. , Enríquez R. , Erazo B. , Gabarron R. J. , Crespo C. G. 
Published: June 2014

Abstract
The aim of this project is to implement the Journal Assurance Data (JAD) as a control mechanism that allows to guarantee reliability and integrity of information related to production processes, from data entry to management reporting, and for control agencies of the Ecuadorian State.
The concept of JAD is based on the need to define a time period within which production data recording, evaluation and processing are viable, within a single source scheme for data entry, ensuring the quality of entered and processed data, for the purposes of determining production values generated during such period on a quantitative basis. This system allows to perform a retrospective evaluation of previous journals as well as a projection towards future journals based on complete and reliable information.
The success of JAD is based on ensuring reliability and consistency of input data for production processes, aiming at delivering quality information for decision taking as final product. This could only be accomplished with the implementation of efficient control mechanisms for data entry, as well as tools for monitoring workflows and occurrence of changes during their execution.
For the initial recording of production data, it should be checked that such data belong to the current JAD only (last 24 hours). Information regarding previous journals could only be included with due consent and previous authorization from the information quality team (Data Management).
In relation to follow-up tools, automatic notifications to work teams have been implemented in order to keep them updated regarding process execution, current changes, such as out-of-range records (from other JADs), non-valid values for entered parameters, required parameters not entered, etc.
Now then, as regards integration processes for computer applications, for both data export and import, it should be noted that the same control mechanisms are applied; that is, only information from the current JAD will be processed, being it possible to process information from previous journals provided that the information quality team has previously given their consent. Thus, information flow based on defined control guidelines is guaranteed, and any change occurred in the information can be detected and timely collected at each stage involved in production processes.
Technical-Economic Evaluation of Downhole Electric Heater Cable Application in Orinoco Oil Belt: Successful Case
Authors: Quintero E. , Quezada A. , Romero I. 
Published: June 2014

Abstract
This paper presents a study of the reservoir simulation OFI INF SDZ-2X located in Zuata Main Field, Junin Division of the Orinoco Oil Belt to evaluate the incidence and extent of Electric Heating in downhole with heating cable technology as the mechanism of enhanced °API ≤10 oil recovery.
The proposed simulation model uses the historical data of JK2306 well to which was applied a pilot test with system of electrical heating turning out an increase in its production therefore decreasing viscosity from 14.500cp (120°F) to 3.500 (150°F) and improving rock-fluid and fluid-fluid properties of reservoir. Once the history of the production-before and after the electrical heating-was matched, values of the thermical variables were obtained of reservoir for the contribution of a second simulation model where production forecasts were made for 6 years from a sample of 4 wells of the RS19 cluster it was obtained a profile of increased production of it and the impact of technology in the recovery factor. Furthermore, an economic analysis was elaborated by checking the scenarios for which the application of the technology of heating cable in extra-heavy oil reservoir from the Orinoco Oil Belt is profitable.
QVA (Quick Value Assessment) of San Andrés Oil Field, Veracruz, Mexico
Authors: Meza-Pérez Edgar , Reyes-Alanis Francisco , Reyes-Aguirre José Manuel , Silva-López Pedro , Irani Barry 
Published: June 2014

Abstract
The Quick Value Assessment (QVA) method is designed to quickly pinpoint and highlight the reserves and production potential of a field and to identify rework, recompletion, enhanced recovery and drilling opportunities that could lead to additional reserves and production. A QVA study provides a first order magnitude range of reserves for all potentially productive reservoirs in a field. (Subsequent additional work can be undertaken as required to further refine the analysis and to obtain more deterministic values for each identified opportunity.)
Another objective of the QVA study is to develop a relatively quick, easy and reusable process to organize and evaluate data. It is designed to adapt to technical information and hard data, which are entered into an application, thereby generating a reliable database so that all the information, technology and processes are available for future consultation, modification and subsequent studies.
QVA software helps to visualize surface and subsurface data in an organized manner, which facilitates analysis.
All available information including openhole well logs, production information, wellbore mechanical information, available reservoir rock and fluid information, and results of tests and special studies were used in the analysis.
A QVA study was applied to a mature field in Mexico with very encouraging results.
Numerical Simulation of 2D Hot Waterflooding Using Analytical Solutions Along Streamlines
Authors: Vicente B. J. , Priimenko V. I. , Pires A. P. 
Published: June 2014

Abstract
Streamline simulation is an alternative method to conventional finite difference methods, more suited to complex reservoir physics but limited in size by computational effort. The main feature of streamline modeling is replacing the space variable by the time-of-flight. In this approach, the fluid transport equation is solved along each streamline. This method is more attractive in convection-dominated flow and in large heterogeneous models. In high paraffinic oil reservoirs cold water flooding does not lead to satisfactory ultimate recovery factors due to the precipitation of solid paraffin from the liquid in the pore space. For this particular case, hot water flooding is an enhanced oil recovery technique option to increase oil production. In this work the process of displacement of waxy crude by a hot water slug followed by cold water drive in porous media was modeled. The liquid phase is composed by two pseudo-components, oil and paraffin. It was assumed that the viscosities of the components and paraffin concentration in the liquid phase are functions of temperature only. The simulations were run in 2D incompressible models without heat losses to adjacent layers and neglecting gravity and capillary effects. The system of hyperbolic equations that represents the mass conservation of each component was solved analytically. The solution of the continuous injection problem is self-similar, but in the case of slug injection interaction between waves of different families occurs. An important characteristic arising from the use of analytical solutions along streamlines is the ability to capture correctly the saturation and temperature shocks. Using analytical solutions along streamlines allowed to reduce the number of time steps and achieved results free of numerical diffusion. The results of streamline simulations were compared a commercial finite difference based simulator and presented close agreement with lower computational cost. The simulations were performed for two cases. The first one considers the injection of a high temperature water slug followed by water drive at the reservoir initial temperature. The second case analyzes the injection of a water slug at a lower temperature followed by water drive at a temperature higher than the reservoir temperature.
Online Transient Simulation To Support Production Operations Planning in Wet Crude-Oil-Gathering System
Authors: Mollinedo R. , López L. F. , Kulkarni M. , Lazcano J. , Villanueva F. , Vivas P. , Palacio S. , Solano E. 
Published: June 2014

Abstract
Production operations planning is an important function for the integration of petroleum midstream delivery activities, as it defines the strategy for product delivery at the operational level in order to meet delivery contracts.
This paper describes a practical application of real-time online transient flow simulation technology to support operations planning in a crude oil gathering system, in which an onshore terminal manages production from five offshore pipelines. Planning operations at the terminal is a daily challenge due to limited storage and water processing capacities, and is further complicated by large uncertainties in fluid arrival volumes and product quality caused by operating changes.
A production planning support system based on transient flow modeling technology was implemented in the wet crude pipeline network. The objective was to track the dynamic state of the system and use it to provide virtual measurements of hydraulic conditions in the pipelines, along with production volumes and product quality indicators at the terminal. Such information is generated in real time and has enabled the following business functionalities: Planning for crude oil production at the terminal proactively rather than reactivelyQuantifying oil and water volume impact on terminal operations in response to operational changes taking into consideration dynamic oil/water holdup effectsForecasting water production volumes and exposing results to manage operation of water treatment facilities according to capacity and availability
The modeling system has proven to be an effective tool in the tracking and forecasting of the pipeline operation, and has been incorporated into the operator's daily production planning workflow. The system has also drawn much needed attention to the transient aspects of fluid flow in an oil-water pipeline network, behavior that is often perceived as immaterial for liquid only systems, but was largely responsible for the quality and volume tracking issues that the operator was facing.
This paper is a reissue of the paper published in 2013 (SPE-166537), which has now been updated to reflect the newly expanded scope of the online system to cover both the light oil (original scope) and heavy oil (new scope) pipeline networks.
Shallow Horizontal Drilling Meets with Very Extended Reach Drilling in the Venezuelan Faja
Authors: Chamat Burgos E. , Peñaranda J. , Gonzalez K. , Trejo E. , Meneses M. , Rosales A. , Martinez J. 
Published: June 2014

Abstract
Early in the 1990s, Venezuela accelerated drilling and production of the Orinoco oil belt called "La Faja." Since then, thousands of horizontal wells have been drilled. Despite the giant reserves in the highly porous and permeable sands found in the Faja, low reservoir pressure and heavy oils with reduced crude API require that reservoir exposure for production is maximized. Because of this, longer horizontal sections are being drilled and will continue to be drilled in the Faja.
Drilling of the Faja started in reservoirs of true vertical depths (TVD) from 2, 500 ft to 4, 000 ft; however, as the development of the Orinoco belt has moved towards the south, reservoirs in the last 5 years have been drilled at TVDs from 1, 500 ft to 2, 500 ft. Further development, in the last 2 years, of the southern Faja has required drilling reservoirs at TVDs from 1, 200 ft to 1, 500 ft. Drilling horizontal wells at these shallow TVDs requires adequate planning and execution because of the inherent risks of high dogleg severity, cyclic stress of bottomhole components, high torque and drag, poor hole cleaning, inadequate weight-on-bit transfer, pipe swaps, wiper trips, and stuck pipe events. To maximize reservoir exposure, recent advances in extending horizontal lengths of these shallow wells have also been achieved. A few wells drilled in south Faja in 2013 fit the very extended reach drilling classification as defined by the oil industry because of their 1:4 stepout ratio, the ratio of true vertical depth versus horizontal displacement.
Along with the evolution of shallow horizontal and extended reach drilling, advances in surface pads and trajectory design, bottomhole assemblies (BHAs), drilling practices, directional drilling tools, and advanced geosteering techniques have allowed drilling extended reach wells of longer total depth with reduced nonproductive time, enabling increasing oil production in the Faja. Experience in the execution of shallow horizontal ERD wells has led to the consolidation of lessons learned and capture of best practices which will be key to improving drilling along the extensive southern area of the Faja, where reservoirs even shallower than 1, 100 TVD are found.
The Effect of Oil Price on Oil Consumption and Reserves
Authors: Aguilera Roberto F. , Aguilera Roberto 
Published: June 2014

Abstract
There has been considerable price volatility in the crude oil market since 1861. At times the yearly variations, as reported by the BP Statistical Review, have been minor but on occasion they have been quite significant. The small and large variations have been matched successfully with a Variable Shape Distribution (VSD) model. Remarkably, the comparison between actual price variations and those calculated by the VSD leads to a coefficient of determination (R2) larger than 0.98. Given this validation, we integrate the results with a Global Energy Market (GEM) model developed in 2007 that presented an oil consumption forecast to 2030. Thus far, the forecast has been in line with actual oil consumption to 2012.
Contrary to statements made by various oil commentators, the integration of results suggests that the possibilities of seeing sudden, large and permanent increases in future oil prices are very low. Given the huge quantities of conventional and unconventional oil available at or below current market prices, society should be able to substitute between alternative sources long before depletion causes oil to become unduly expensive.
Further, a case can be made that with the vast global oil resource base and the significant technological advances being implemented by the industry, oil prices could decrease in the future.
Dynamic IPR – Modeling Reservoir Well Interactions to Improve Transient Simulations of Wells
Authors: Garcia Artur Posenato , Neto Gilson Moura , Machado Marcos Barbosa , Carvalho Renato de 
Published: June 2014

Abstract
The objective of this work is to present a new IPR model for transient well simulations that gives precise results without the high computational costs of the reservoir finite difference simulation. The limitations of using conventional IPR models for transient well simulations, specifically for oscillatory wells experiencing severe slugging or casing heading phenomena, are evidenced. The flow rate calculated with the IPR might significantly differ from the results obtained with the reservoir finite differences model for periodic bottom-hole pressures. Analytical solutions of a radial homogeneous reservoir were developed (both in time and Laplace domain) and they were used to generate its frequency response. A low order transfer function that approximated this frequency response was generated, which was named "Dynamic IPR".
Adequate boundary conditions are essential to obtain a precise result for transient well simulations. The conventional IPR models are frequently employed as the bottom-hole boundary conditions to represent the reservoir response even in transient simulations. Another possibility is to couple the reservoir finite difference model with the well and solve them simultaneously, when the IPR transient response is known to be inaccurate. A new alternative approach, the Dynamic IPR, is presented as a low order system of ordinary differential equations that can be applied for oscillatory wells and supposedly for any transient simulation without complex reservoir behavior such as coning for example.
The Dynamic IPR was compared with the two analytical solutions (the deconvolution of the Laplace domain solution was performed with the Iseger algorithm) and the conventional IPR. A sinusoidal bottom-hole flowing pressure was assumed and the corresponding liquid flow rates were calculated. The liquid flow rates determined from the transfer function were almost identical to the exact results and the computational costs incredibly lower than performing finite differences in cases in which the conventional IPR presented poor results.
This work emphasizes that there are some situations for which the IPR are inadequate and presents simple procedures to determine when that is the case. Most importantly, the proposed Dynamic IPR can be easily included in any transient simulation and greatly improve the results.