bluuebunny/crossref_metadata_2025_split huggingface dataset:
Old Problems, New Challenges: Evaluating a Horizontal Well in Naturally Fractured Carbonate Reservoirs
Authors: Moreno A. , Rosales S. , Reséndiz T. , Ramírez E. , Tellez F. , Losada M. , García G. , Quevedo M. , Añez A. 
Published: June 2014

Abstract
Extracting oil from horizontal wells in naturally fractured carbonate reservoirs (NFR) is challenging. To properly evaluate the formation, a solution was developed that integrates key formation evaluation technologies with stimulation systems and which has proved to be effective in holistically solving such challenges.
The holistic well analysis included evaluation of static data by integrating all available openhole data and special logs. To locate the most productive zones, fracture characterization was conducted using advanced interpretation techniques. Dynamic evaluation also included the analysis of measurements obtained using a formation tester. An integrated technical solution included a proper matrix stimulation design that considered all these data to reduce formation damage and connect the fracture networks.
This study successfully confirmed the presence of hydrocarbons in the T field in southern Mexico for the first time. Production not only exceeded expectations, but also added reserves to this new exploration area, aiding in the development of the Upper Cretaceous formation referred to locally as the KM.
Water Injection in Offshore Naturally Fractured Reservoirs Associated to a Common Aquifer
Authors: Toledo-Piña R. , Leon-García A. , Padilla-Sixto R. 
Published: June 2014

Abstract
The APC complex include three naturally fractured reservoirs, Abkatun, Pol and Chuc, which were of the most important fields of Mexico; they are located offshore and communicated by a common aquifer. Of these, the most important is Abkatun, producing a light oil which began its production in 1980 with average values of 8% and 2,000 md of porosity and permeability, respectively; reached its maximum oil production in 1983, maintains a production volume of 300×103 STB/D from 1986 to 1994; in 1985 were subject to a pilot test of water injection and its implantation was performed in 1991 and suspended in 2006.
This paper presents an analysis of the pilot test design process, implantation, monitoring and adjustment of the injection project, also an evaluation of results. With the pilot test was possible to found that in Abkatun field the water injection caused high drops pressure in fractures and therefore an early influx of water due to the high production of wells, so it was proposed the injection into the aquifer associated to the three fields of APC complex far away the production area. In the implementation initially was injected 420×103STB/D of treated seawater, reduced gradually to 80×103 STB/D in order to maintain the reservoir pressure of the three fields and generate a more uniform advance with a total volume injected of 1, 386×106 bbl. The benefit of the injection program was 455×106 bbl of oil. The greatest achievement of the water injection project to APC complex it was to hold a production platform of 550×103 STB/D in the period 1990 to 1994, increasing the total recovery factor from 37 to 43%. A compute of the residual oil saturation in the water invaded zone is in the order of 40%, which address to the implantation in a very near future of another process of advanced recovery.
Economic Comparison for the Potential Development of Onshore Unconventional Resources and Offshore Conventional Prospects in Uruguay
Authors: Ferro S. , Tomasini J. , Gristo P. , de Santa Ana H. , McLeroy P. G. 
Published: June 2014

Abstract
As a result of the bidding Round 2009 and Uruguay Round II, 10 Production Sharing Agreements were signed for offshore areas, in which 8 IOCs are involved as contractors. The exploration that is currently taking place implies a superlative increase in the knowledge of Uruguayan offshore basins. For awarding onshore contracts there is an open door system in place. The fiscal regime is very similar to the one applied offshore, but with slight differences. Nowadays there are 4 contracts for exploration-exploitation of hydrocarbons onshore Uruguay, with 2 IOCs as contractors, in Uruguayan Norte basin, which is the southern extension of Chaco Paranaense Basin. The Norte basin potentially has Devonian-age shale oil and shale gas resources, in addition to conventional leads and prospects.
This work presents an economic assessment for a shale gas and shale oil development in a 10 000 km2 Area in Norte Basin, resulting that the viability of the project could only be possible in the values of EUR higher than the P5 case, and it is strongly related to the drainage area and the cost of drilling, completing and hydraulic fracturing of the wells.
In addition, for the sake of comparison of profitability indexes and project profit distribution related to slightly different fiscal regimes, the same resources volumes were considered for an offshore project. On the other hand, the results show that the offshore development project is economically viable for the case of higher resources volumes. Finally, the Minimum Economic Field Size was calculated for offshore prospects, for the oil and associated gas case.
This work constitutes a first approach to a technical/economic evaluation applied to the development of unconventional resources onshore Uruguay, comparing its results to conventional prospects offshore Uruguay. Its findings and conclusions are significant for those international oil companies that are already carrying out or interested in potentially conducting exploration activities in both onshore and/or offshore Uruguayan basins. The results of this assessment are also very illustrative of the comparison of government's take for the different onshore and offshore fiscal regimes and represent a valuable input for ANCAP and the Uruguayan government to take into consideration to define offered areas policies.
Hydraulic Unit Determination and Permeability Prediction Based On Flow Zone Indicator Using Cluster Analysis
Authors: Aguilar Cesar , Hugo Govea , Rincón Guillermo 
Published: June 2014

Abstract
Classical discrimination of petrophysical rock types is based on subjective geological observations and on empirical relationships between permeability and porosity data. The Hydraulic Unit approach is a methodology for classification of rock types and prediction of flow properties, based on flow zone indicator that incorporates geological attributes of texture, mineralogy and the physics of flow at pore scale to discriminate distinctive hydraulic units.
This paper presents a methodology for the determination of Hydraulics Units and permeability prediction using a cluster analysis technique due to a hydraulic unit's zonation process requires a rigorous statistical approach. MULTI-RESOLUTION-GRAPH-BASED CLUSTERING (MRGC) is a very powerful non-parametric algorithm which allows defining the optimal number of hydraulic units.
The methodology was applied to Venezuelan Eocene sandstone reservoir integrating core data (flow zone indicator) and log data such as porosity, shale volume and caliper as an input data. Compared to previously classification, based on lithofacies information, it yielded to increased accuracy of permeability prediction and enhance reservoir description. All geological information available was integrated (core descriptions, image log, lithofacies, XRD, thin sections and SEM information) and five hydraulic units were identified, without any "a priori" subjective knowledge. A detailed characterization was achieved, determining rock properties (porosity and permeability) and SCAL properties (capillary pressure and relative permeability curves) by each rock type, which is an input data in the dynamic modeling of the reservoir.
In order to verify this approach a nodal analysis was performed in an uncored well using all data available (buildup-flowing bottom hole, RFT-pressure data, petrophysical and fluid reservoir properties) obtaining and excellent match between real and predicted initial oil production.
Wireline Perforating Technology Maximizes Well Productivity and Minimizes Operational Risks
Authors: Baumann C. , Gultom D. , Williams H. , Yudhatama A. , Rahman R. 
Published: June 2014

Abstract
In this paper we describe a perforating technology that helped deliver highly productive wells in the Tunu field, a multilayer sandstone gas reservoir in Indonesia. We describe the simulation models used to evaluate perforating designs and operational risks, and we include post-job productivity data for 9 wells, all of which ended up delivering more than 500% of the expected productivity, in large part due to highly conductive perforation tunnels.
The intervention technique used in the Tunu field is based on applying Dynamic Underbalance (DUB) perforating with a nitrogen kick-off technique to perforate on balance or slightly under-balance. This technique enables perforating long intervals with deep penetrating charges at high shot density, and with very low risk of gun jumping. This technique also promotes natural well flow after perforating, without the extra cost of coiled tubing intervention to perform liquid unloading.
We discuss several aspects of job design and simulation. Predictive simulations based on API RP 19B Section 4 data and rock perforating models for sandstones indicated that perforating damage clean-up with dynamic underbalance would deliver the highest well productivity. The simulation model that predicts wellbore dynamics, namely pressure waves in the wellbore, at the sand face and inside the reservoir, also predicts the gunstring dynamics with the associated gunshock loads on the conveyance. Gunshock simulations showed that the DUB technique also minimizes operational risks.
All the important aspects of the DUB perforating technique were predicted in the job planning stages. Guns were custom loaded to produce a good dynamic underbalance to remove the low permeability crushed rock zone from inside and around the perforation tunnels, thus minimizing perforation skin and maximizing well productivity. In many cases well productivity turned out to be exceedingly high, more than 500% of the initially expected productivity for7 DUB perforating jobs and 2 DUB post-perforating clean-up jobs.
Finite Wellbore Radius Solution for Gas Wells by Green's Functions
Authors: Sousa E. P. , Barreto A. B. , Peres A. M. 
Published: June 2014

Abstract
Even when written in terms of a pseudo-pressure function, the diffusivity equation for flow of gases through porous media is, rigorously speaking, non-linear because the viscosity-compressibility product is pseudo-pressure dependent. However, several techniques and analysis procedures neglect such non-linearity. A new methodology for constructing solutions for gas reservoirs through the Green's Function (GF) technique was recently proposed in the literature. Such methodology handles the viscosity-compressibility product variation rigorously and it has been applied to solve several gas well tests problems successfully. In those problems the wellbore is always represented by a line source. This work extends a little further the theory by considering a finite wellbore radius boundary condition for a single vertical well producing at constant rate from an isotropic homogeneous and infinite gas reservoir. The presented solution does not consider non-Darcy flow effects and wellbore storage and skin as well. Results from our finite wellbore radius (f.w.r) solution are compared to a commercial finite difference reservoir simulator that shows a very close agreement. We also compared the f.w.r solution to the correspondent line source solution to study the difference between the two solutions. As expected, the pseudo-pressure solutions do not match at early times but they do agree at long times, which is exactly how f.w.r and line-source well solutions for slightly compressible fluids behave. It seems that, even for gas well problems, the wellbore can be satisfactorily represented by a line source without significant loss of generality. The line source assumption greatly simplifies the math and the computational effort. This aspect is especially attractive for complex non-linear gas well problems that remains to be solve by the GF approach.
Electrical Wellbore Heating in Environmentally Sensitive Llancanelo Field, Argentina
Authors: Ucan S. , Savoy E. , Federici M. A. , Azcurra M. O. 
Published: June 2014

Abstract
Steam injection processes were abandoned due to environmental regulations in Llancanelo heavy oil field. This reservoir consists of a series of interbedded sandstone and conglomerates in cretaceous aged Neuquen Group. Down-hole electrical well bore heating technique, which is insensitive to the environmental regulations, was implemented. Despite that electrical heating for heavy oil reservoirs are established methods for in situ viscosity reductions, the commercialization and wider application of this heating technique required detailed analyses to determine optimal application conditions in horizontal well trajectory design for a heterogeneous reservoir.
Recovery factor obtained with natural depletion was less than 0.2%. Viscosity and temperature relationship was the most critical parameter to determine the applicability of the project in the productive interval. In this paper, it has been shown that electrical well bore heating can be an alternative in this environmentally sensitive reservoir with two different oil viscosity layers; Green zone with 11200 cp and Olive zone with 3880 cp at the surface conditions.
The impact of the different heating temperature and heating time on additional oil recovery were analyzed for the reservoir rock and fluid properties. Detailed simulation runs were conducted to understand recovery mechanism of convective and thermal conductive processes for well heating. By increasing the well bore temperature from initial 56 °C to 100 °C, the following results were obtained; 1- An additional oil recovery for Olive zone can be increased up to 110%, on the other hand an additional oil recovery for Green zone can be increased up to 62%, respectively.2- Energy consumption of 1 MM BTU for Olive zone will lead an additional oil recovery of 6 STB, whereas 1 MMBTU consumption for Green zone will lead an additional oil recovery of 3 STB.3- Energy rate per horizontal length is in range of 40–60 Watt/ft per the Green zone.4- Well bore heating will not change the reservoir temperature and viscosity of the oil beyond 30 m far away.
In this paper, it has been shown that electrical well bore heating was economically viable in environmentally sensitive and heterogeneous reservoirs.
Evaluation of Multiphase Flow Models to Predict Pressure Gradient in Vertical Pipes with Highly Viscous Liquids
Authors: Ruiz R. , Brito A. , Marquez J. 
Published: June 2014

Abstract
The prediction of pressure drop in multiphase flow for risers is of particular interest for the oil industry and also a critical variable for the right design of surface facilities in offshore fields. Empirical steady state correlations, mechanistic models and dynamic models are available to calculate the multiphase flow pressure drop, holdup and phases distribution.
The main purpose of this paper is to evaluate the accuracy of several steady state pressure drop prediction models with two phase flow laboratory data conformed by 108 point using air as gas phase and liquids with viscosity up to 310cP. The models considered in this study, for predicting pressure drop are Beggs and Brill, Duns and Ros, Govier and Aziz, Hagedorn and Brown, Mukherjee and Brill, Orkiszewski, Ansari and OLGAS model, using PIPESIM simulator. The evaluation was based on the comparison between the predicted and the measured pressure drops, demonstrating the performance of each model for highly viscous liquids. Statistical parameters as average absolute percent error and standard deviation have been calculated to find the most acceptable one. The statistical analysis showed that among the evaluated Hagedorn and Brown model has the best performance to predict pressure drop in risers with highly viscous liquids.
Effect of Oil Saturation on Acid Propagation during Matrix Acidization of Carbonate Rocks
Authors: Kumar R. , He J. , Nasr-El-Din H. 
Published: June 2014

Abstract
The existence of an optimum injection rate for wormhole propagation and face dissolution at low injection rates during matrix acidizing are well established. However, little has been documented that describes how the presence of residual oil affects carbonate acidizing. This study demonstrates the impact of oil saturation on wormholing characteristics while acidizing field and outcrop cores under reservoir conditions (200°F). Knowledge of the effect of different saturation conditions on acid performance will contribute towards the design of more effective acid treatments.
Coreflood experiments at flow rates ranging from 0.5 to 20 cm3/min were performed to determine the optimum injection rate for wormhole propagation when acidizing homogeneous limestone reservoir cores and low permeability Indiana limestone cores of dimensions 3 and 6 in. length and 1.5 in. diameter. The absolute permeability of the cores ranged from 1 to 78 md. The study involved acidizing cores saturated with water, oil, and waterflood residual oil using 15 wt% HCl. The viscosity of the crude oil used was 3.8 cp at 200°F. CT scans were used to characterize wormholes through the cores. The concentrations of the dissolved calcium and magnesium ions were measured using Inductively Coupled Plasma–Optical Emission Spectroscopy (ICP-OES) and the effluent samples were titrated to determine the concentration of the acid.
At injection rates 0.5 to 20 cm3/min, 15 wt% HCl was effective in creating wormholes with minimal branches for cores with residual oil (Sor=0.4–0.5). Compared to brine and oil saturated cores, waterflood residual oil cores took less acid volume to break through. Additionally, the wormholing efficiency of regular acid improved with increased acid injection rates in the presence of residual oil. A decrease in acid pore volumes to breakthrough for oil saturated cores was noted at high acid injection rates, which could be attributed to viscous fingering of acid through oil. Unlike brine saturated and oil saturated cores, waterflood residual oil cores showed no face dissolution at low acid injection rates. Conclusions from this work will aid in the design of better acid jobs by highlighting the impact of oil saturation on wormholing characteristics of acid while acidizing carbonate rocks.
Registration and Fusion of Backscattered Electron Images and Energy Dispersive Spectroscopy Images on Siliciclastic Rock Samples for Petrophysical Calculations
Authors: Lattanzi D. A. , Salazar L. , Jaime P. I. , Tallec G. , Chan K. , Gerwig T. 
Published: June 2014

Abstract
High resolution Backscattered Electron images (BSE) can be used to extract textural information such as grain and pore size; specific surface area; and so forth. Based on this information porosity and permeability can be estimated. On the other hand, low resolution Energy Dispersive Spectroscopy Imaging (EDS) provides valuable information about the mineralogy and chemical composition of the rock samples. Scanning Electron Microscopy (SEM) instruments are capable of generating BSE images of core and cuttings samples in a relatively short period of time at very high resolutions. The story is different if EDS images are also acquired. For example EDS images at 20 μm point spacing usually do not take longer than 30 minutes to be captured, but if point spacing is reduced to 10 μm, then measurement time increases approximately by 4 times.
This paper proposes a new methodology to combine high resolution BSE images with low resolution EDS images and to use the combined textural and mineralogical information in order to improve grain segmentation, grain size calculations as well as estimating porosity and permeability in rock samples. This methodology starts with the acquisition of the BSE and EDS images looking for an optimal relationship between acquisition time and image quality. Secondly the registration and fusion of the two images is performed and advanced image processing techniques are applied to extract information that corresponds to underlying physical characteristics such as porosity and permeability.
Results of this methodology are encouraging, 4 to 5 μm point spacing BSE images have been registered and fused with 20 μm EDS images and excellent grain segmentation has been achieved. Calculated porosity values show a good match with helium porosity core data and estimated permeability using the Kozeny-Carman equation gives results in the same order of magnitude.
This new approach saves time, operating costs and enable geoscientists to collect valuable rock data at the micro-scale level. Furthermore, this information can be used to estimate important rock properties when integrated with other data sources to improve reservoir characterization especially in cases where information is scarce or difficult to obtain.
Numerical Simulation of a Dry Combustion Tube Test for a Brazilian Heavy Oil
Authors: Mercado Sierra D. P. , Trevisan O. V. 
Published: June 2014

Abstract
Combustion tube tests’ simulations become an increasingly important part in the design of projects aimed at the implementation of this recovery technique. Although simulations at the laboratory scale cannot be scaled directly to the field, they provide essential knowledge on how numerical modeling of physical and chemical phenomena that occur during combustion could be dealt with. The present paper reports simulations and history matching of a dry combustion tube test for a Brazilian heavy oil. Reaction model includes a coke generation reaction and three high temperature oxidation reactions of coke, heavy and light oil components.
The history matching process is conducted in three stages. The first stage considers the matching of the combustion front velocity and fuel consumption, by altering the activation energy of the heavy fraction cracking reaction and the frequency factor of coke oxidation. In the second stage, production fluid rates and pressure drops are considered with the adjustment of the relative permeability curves and heat losses. In the third stage, the peak temperatures and produced gas composition are matchedby reviewing the kinetic parameters and the reaction stoichiometry.
From the analysis of the laboratory data, a significant influence of the steam plateau in the production behavior is identified. It is observed that the initial volume of water present in the system is produced almost entirely before oil production begins. The oil bank approximates to the producer well once the initial water volume of the system has been produced. To better represent such occurrence, it is necessary to consider the relative permeability variation as a function of oil temperature, besides taking into account the radial heat losses in the system. This is shown as an efficient alternative to more adequately represent the fluid distribution along the combustion tube. Finally, it should be noted that the simulated results show an overall good representation of the experimental data.