bluuebunny/crossref_metadata_2025_split huggingface dataset:
Hydraulic Fracture Propagation Modeling in a Homogeneous Elastic Media with Leakoff
Authors: Morales-Matamoros D. , Kanaun S. , Chi-Chim M. 
Published: May 2017

Abstract
An infinite homogeneous, isotropic and elastic medium with a penny-shapedhydraulic fracture is considered. The hydraulic fracture is subjected to the pressure of fluid injectedfrom its center with a positive injection rate. Description of the hydraulic fracture growth is based on the lubrication equation (balance of the injected fluid and the crack volume), equation for hydraulic fracture opening caused by fluid pressure on the hydraulic fracture surface, the Poiseullie equation related local fluid flux with the hydraulic fracture opening and the pressure gradient and classical criterion of hydraulic fracture propagation from lineal elastic fracture mechanics. The hydraulic fracture growth is simulated by a discrete process consisting of three basic stages: increase of the hydraulic fracture volume by a constant hydraulic fracture size, hydraulic fracture jump to a new size defined by the fracture criterion, and filling of the new appeared hydraulic fracture volume by the fluid. It is shown that the model results in a reasonable dependence of the hydraulic fracture radius with time as well as the pressure distribution on the hydraulic fracture surface. Comparisons withother solutions of hydraulic fracture problems for penny-shaped geometry existing in the literature are presented. The model is applied to the case of media with leakoff, and numerical examples of hydraulic fracture propagation with the leakoff effect are presented.
Interrelationship Between Asphaltene Precipitation Methods and Asphaltene Characteristics and Self-Association Behavior
Authors: Afra S. , Alrashidi H. G. , Nasr-EL-Din H. A. 
Published: May 2017

Abstract
Asphaltene self-association and precipitation are unfavorable processes that can occur during production, transportation, and storage of crude oils. The primary mechanisms of asphaltene self-association are dispersion interactions, electrostatics interactions, hydrogen bonding, and orientation-dependent repulsive steric interactions. This process consists of sequential steps initiating with nano-aggregation of five to six asphaltene molecules and continues by increasing its concentration into formation of clusters. Further augmentation of asphaltene dosage leads to formation of asphaltene micro-aggregates that are detrimental to oil rheological behavior. However, a more detailed and comprehensive interpretation is required to determine the contribution of each mechanism in aforementioned steps.
In the present work, asphaltene samples from a light crude oil have been accordingly fractionated by various precipitants and analyzes chemically in various solvents by none-fragmenting techniques such as matrix-assisted laser desorption/ionization (MALDI). Influences of heteroatoms on asphaltene precipitation mechanisms and molecular weight were assessed by conducting elemental analysis. Sensitivity of asphaltene constituents stacking to extraction methods were evaluated by curve deconvolution and fitting routines of X-ray diffraction (XRD) patterns of solid asphaltenes. Finally, asphaltene precipitation onsets were determined for various asphaltene samples and conditions by using near-infrared (NIR) spectroscopy technique.
Results of the current study reveal the substantial impacts of various precipitants and solvents on asphaltene aromaticity and its propensity toward self-association. Also, the results indicate that alteration of the extraction methods is conducive to variation in asphaltene molecular weights as well as precipitation onset points. Alteration of critical aggregate concentration (CAC) and critical micelle concentration (CMC) were observed from NIR results and were used to determine asphaltene stability.
Current study proposes further understanding of asphaltene self-association and aggregation mechanisms. Concrete understanding of these mechanisms leads to designing more efficient asphaltene dispersants and heavy oil viscosity modifiers to prompt higher oil recovery and facilitate transportation processes.
How to Maximize the Value of the Lajas Tight Gas Play by Dynamic Modeling
Authors: Tanco F. J. , Thompson A. , Alencastre P. , Santiago E. 
Published: May 2017

Abstract
The Lajas formation in the Neuquén Basin, Argentina, has been identified as a key opportunity to supply the gas requirements of the Argentine economy. A number of fields are currently being developed in this formation with an ongoing exploration program likely to yield more discoveries. Maximizing the value of existing and new assets was the task at hand.
To optimize the development, dynamic models were needed to produce forecasts for different development scenarios. One of the main issues to solve was how to represent in commercial dynamic software the hydraulic fractures and their interaction with a low permeability formation. The optimum approach to model induced fractures had to be identified.
Additionally, flow tests of wells were infrequent and often gave contradictory results. Hence we explored a number of different options for controlling the history match and forecast such as controlling by gas rate, tubing head pressure and back pressure through the choke.
We concluded that dual porosity modeling of the fractures offered an acceptable balance between computational overhead, absolute accuracy and flexibility. The main parameters adjusted to achieve the history match were the fractures half length, height, volume and conductivity/permeability that ruled the early behavior of the wells and the matrix permeability that conditioned their longer term productivity.
Controlling the wells in the history match was found to be best achieved by control through the choke and line pressure. Tubing head pressure as well as gas and water simulated rates were cross checked against historical data.
The vertical lift performance modeling of the wells was also found to be critical to achieve the history match. The pressure drop in the wells was modelled by lift curves from the well head to the first perforation and by segments from there onwards to understand their liquid loading. All this had to be taken into account due to the fact that wells were impacted by tubing, choke and line pressure changes through their production history.
It was possible to optimize Lajas gas development by applying an integrated modelling methodology linking geology, reservoir and production engineering. The model helped justify new infill locations and estimate the difference in productivity between different Lajas geological sequences.
The dynamic model results were compared with the outcome of other forecasting methods such as DCA Tipe Well, RTA and layercake dynamic models.
Integrating Pilot Well Measurements for Horizontal Well Planning - a Case Study, Vaca Muerta Formation, Neuquén Basin, Argentina
Authors: Belobraydic M. , Reynolds L. , Frydman M. , Makarychev G. V. , Faulkner Y. , Pacheco F. , Luneau B. A. , Higgins-Borchardt S. , Kaufman P. , Caniggia J. , Nielsen O. , Ponce J. E. , Graf G. C. 
Published: May 2017

Abstract
The Jurassic- and Cretaceous-age Vaca Muerta formation of the Neuquén Basin, Argentina, is a heterogeneous self-sourcing reservoir that is complicated by tectonic and volcanic influences. As an unconventional reservoir, its characterization requires the evaluation of key properties related to the production drivers: reservoir quality (RQ), drilling quality (DQ), and completion quality (CQ). A methodology is presented to maximize horizontal well success by identifying optimum horizontal well landing locations through integration of multidimensional petrophysical and geomechanical properties.
This ongoing case study identifies of the key properties for RQ, DQ, and CQ through correlation analysis and production validation. The methodology uses a systematic and quantitative probability calculation to determine the lateral landing score (LLS) for all depths along a vertical pilot wellbore. Core-calibrated petrophysical evaluations of the interbedded siliciclastics, organic shales, ash beds, and tight limestones of the Vaca Muerta quantify uncertainty in estimates of reservoir properties (e.g., mineralogy, maturity, porosity, fluid saturations, and permeability) and RQ. Stress profiles, calibrated using core evaluation and stress tests, provide a predictive model of geomechanical properties (e.g., anisotropic elastic properties, in-situ stresses, wellbore stability, and rock fluid sensitivity). These parameters are critical for DQ and CQ predictions.
Production results define appropriate normalization and weighting of properties for the LLS probability. Tectonic stresses in the Vaca Muerta may promote horizontal fractures that create restrictions to fracture growth and/or induce pinch points. Previous approaches to determine the target location in an unconventional resource play using geomechanical inputs alone may not apply to the Vaca Muerta because they overlook the effects of the fracture complexity induced by the stress regime of the prograding depositional environment. A high LLS occurs where positive RQ, DQ, and CQ values exist in sections thick enough to drill.
The LLS brings together measurements from multiple domains to provide a qualitative, comparative, and repeatable ranking of ideal landing locations in tectonically active unconventional plays. Implementing the LLS as a decision-making tool for horizontal well placement generates both an optimized landing point and completion design. The workflow is iterated with available horizontal well production data to validate the relevant production drivers.
Onset of the Asphaltene Flocculation and Asphaltene Hydrodynamic Radius Determination Using H-Diffusion- Ordered Spectroscopy DOSY NMR
Authors: Sandoval M. I. , Muñoz Navaro S. F. , Molina Velasco D. 
Published: May 2017

Abstract
During EOR recovery processes, asphaltenes macromolecules can flocculate and cause drastic changes in the petrophysical properties of the reservoir, therefore it is very important to determine the time at the flocculation begins and further the size of the aggregates, since ultimately this depends on whether these can be trapped in the porous media. This work aims to evaluate the change in the asphaltene hydrodynamic radius of at different concentrations of n-heptane and to detect the onset asphaltene floculation using a new technique known as 1H Diffusion ordered spectroscopy-NMR (DOSY-NMR). H-DOSY NMR is a method based on the pulsed field gradient spin-echo from nuclear magnetic resonance (PFGSE NMR) and it allows the identification of the molecular components of a mixture sample and at the same time obtain information of their size through the diffusion coefficient. For our specific case, the asphaltene hydrodynamic radius was 16.8 Å and the onset of asphaltene floculation can be observed when the concentration of solvent n-heptane was 30 wt %.
Carbon Dioxide Storage in High Asphaltene Content Oil Reservoirs
Authors: Hascakir Berna 
Published: May 2017

Abstract
Carbon dioxide storage in high viscosity and density hydrocarbon reservoirs that have high asphaltenes content is attractive. However, CO2 is an asphaltenes insoluble solvent, hence, CO2 injection into these reservoirs is expected to cause asphaltenes deposition. In pore-scale, how the deposition of asphaltenes would impact the CO2 trapping and consequently CO2 storage is not known. This study proposes highly efficient trapping and storage of CO2 in high-asphaltenes content reservoirs. Our recent experimental studies on CO2 flooding into bitumen reservoirs revealed with Scanning Electron Microscopy (SEM) images that CO2 gets trapped in asphaltenes phase. The CO2 trapping is occurred both in residual and displaced oil due to mainly the presence of clays in the reservoir rock. The CO2-displaced oil interaction promotes the formation of foamy oil. As the size of the CO2 bubbles in the displaced oil increases, the CO2 storage capacity of the displaced oil is enhanced. The bubble size is mainly controlled by the CO2 injection rate and the bigger CO2 bubbles in the displaced oil are obtained at lower CO2 injection rate. Hence, CO2 trapping in high asphaltenes content reservoirs can be more effective if the oil reservoir has high clay content and when CO2 storage is achieved through low injection rates. However, because low injection rates provide more interaction time for asphaltenes and CO2, asphaltenes deposition may occur near injection well and deposition of asphaltenes may inhibit the further propagation of CO2 which may limit the reservoir CO2 storage capacity. It should be also noted that the optimum CO2 injection rate for storage purpose can be different for every reservoir and hence, should be determined experimentally.
Determination of Unconventional Technical Limit on Shale Wells
Authors: Castañeda G. Espinosa , Cruz D. Velazquez , Robles A. Morquecho , Franco R. Resendiz , Santiago D. Silva 
Published: May 2017

Abstract
The optimization of well drilling is the logical process of analyzing the variables involved in well construction to maximize the efficiency of the operations involved. The philosophy of optimized drilling is based on the knowledge and experience gained in the first drilled well for its learning and application in the drilling of subsequent wells; So that the total cost of drilling is reduced to a minimum. In order to identify those points to be optimized, a methodology of analysis of drilling times (ATP) was developed, which allowed to obtain the actual drilling operations times, non-productive times (NPT's) and normal times for drilling operations. Each of the stages of selected shale / oil gas wells in northern Mexico. Second, we identified the best times, comparable stages and penetration indices (ROP'S) that traversed the selected wells. Finally, the different problems with high frequency indices and best practices were identified to obtain an unconventional technical limit to obtain an optimized baseline for well design and planning.
Development of Sensors Systems for the Validation of Mathematical Models for Sucker Rod Pumps
Authors: Bastos I. C. , Mayr L. 
Published: May 2017

Abstract
In order to extract the oil from reservoirs which have reached the end of the natural flow, the use of an artificial lift system is necessary. The mechanical pumping system accounts for about 90% of all artificial lift systems in the world. This kind of pump has a highly complex mechanical design and serves as a test for evaluating the developed mathematical model and the construction of special measuring equipments for future analysis systems. This work includes the construction and performance testing of an electronic force sensor installed at the Pitman (rod) and an acceleration sensor installed on the Walking Beam. The design and development of these sensors are discussed from the basic including the process of selection and configuration of strain gauges for the signal conditioning for use in harsh environments with interferences during an necessary continuous data transfer. After the acquisition of data in real time, an analysis of the mechanical pumping system using the developed mathematical model and the measured data is performed. The validation of this model is performed by comparison of force and position (angle) values of the measurement and the simulation. The entire system was implemented in software and hardware, and the results are evaluated in field tests in Gänserndorf, Austria.
Injection Completion and Well Integrity Performance of First Cyclic Steam Stimulations to Horizontal Wells in the Huyaparí Field
Authors: López A. , Sanchez R. , Pacheco J. 
Published: May 2017

Abstract
The first thermal pilot project in the Huyaparí field (formerly Hamaca) in the Orinoco Belt in eastern Venezuela was designed to use ‘non-thermal’ wells in an existing cold producing field to explore steam stimulation injection and production response while maintaining wellbore integrity and safe operations.
The pilot project consisted of performing cyclic steam stimulations in active horizontal producers. The selected candidates were active wells producing extra heavy crude oil (8–9 °API) from prolific unconsolidated sands with 30% porosity and &gt;5 Darcy permeability. A selection process was implemented to identify wells based on favorable sand quality and dynamic reservoir conditions to address potential issues of relatively high-pressure high-temperature saturated steam injection conditions.
A risk analysis was implemented to design the injection completion and workover program to maintain well integrity during high-temperature steam injection (550 °F). Well injection completion consisted of concentric vacuum-insulated-tubing (VIT), thermal hydraulic-set packer, thermal wellhead conversion, and high temperature downhole sensors; all designed to protect Class B cement and 9.625-in. J-55 BTC production casing. In addition, open-ended injection tubing was installed inside standalone 7-in. slotted liner (0.020-in.) approximately 1500 feet past production casing shoe depth to mitigate potential steam backflow.
The steam injection phase consisted of delivering 80% quality steam at wellhead using a portable steam generator (25MMBTU). Upon injection completion, the well was left shut-in for five days to undergo a soak period to dissipate heat to reservoir. Finally, the wells were converted back to production by safely removing the injection completion and installing a 5.5-in. production tubing, sucker rods, insert rod pump, and downhole intake temperature-and-pressure sensors for monitoring reservoir behavior.
This paper will discuss well selection criteria to achieve reservoir injection and production results, injection completion design based on wellbore risk analysis, and well integrity performance based on strain-based design using the Modified Holliday Stress Ratio (HSR) approach for thermal service tubulars of the first cyclic steam stimulation project in ‘non-thermal’ wells.
Modeling and Interpretation of the Bottomhole Temperature Transient Data
Authors: Onur Mustafa 
Published: May 2017

Abstract
This paper presents analytical and semi-analytical solutions based on a coupled wellbore/reservoir thermal model to investigate the information content of transient temperature measurement made within an inclined wellbore across from the producing horizon or at a gauge depth above it. The models are capable of simulating bottomhole transient temperatures from multi-rate production tests including buildups. We provide interpretation/analysis methodology based on temperature-derivative and straight line methods for estimating near wellbore and far field formation parameters from temperature transient data. Slightly compressible, single-phase, and homogeneous infinite-acting single-layer reservoir system is considered. The reservoir and wellbore models account for Joule-Thomson heating/cooling, adiabatic fluid expansion, conduction and convection as well as heat losses to strata and formation. Wellbore temperatures at a certain gauge depth are evaluated through a wellbore thermal energy equation coupling the reservoir temperature equation. Sandface temperature data during production and buildup periods may exhibit two semilog straight lines; one at early-times reflecting the effects of adiabatic fluid expansion in the in the skin zone near the wellbore, whereas the late-time semilog straight line reflecting the Joule-Thomson effects and exhibiting the nonskin zone properties. For temperature measurements made at locations above the producing horizon, wellbore transient temperature is dependent upon the flowrate, distance above the producing horizon, geothermal gradient, and radial heat losses from the wellbore fluid to the formation on the way to gauge. Depending upon these parameters, transient temperature response at early times may be almost solely reflective of the wellbore/thermal storage effects, and the flow regimes that are exhibited by the sandface temperatures are distorted due to heat losses effects between the wellbore and the formation adjacent to the wellbore. Synthetic test examples demonstrate the use of the models and methods proposed to interpret and analyze bottomhole temperature transient data.
Portfolio Management Strategies to Maximize Profitability from Mature Fields under Optimal Cash Exposure Mode in Ecuador
Authors: Rodas Cabrera J. A. , Fun Sang B. A. , Garibaldi L. A. 
Published: May 2017

Abstract
A national oil company in Ecuador was focused on the exploration and production of hydrocarbon resources within the Ecuadorian territory. It became the main operator in Ecuador after a merger with another operator in 2012. This paper presents the master plan prepared by the operator to reorganize the entire portfolio, ranking assets in terms of value as a first approach to maximize return on investments (ROI). Following the merger, the new organization was attempting to reach equilibrium; however, issues regarding how best to allocate financial and human resources affected production delivery. At that time, risk and uncertainty management became crucial for reorganizing the entire portfolio. A pilot project to address similar issues had been initiated by the operator beginning with Blocks 7 and 21 in 2010, where the value of the different fields in the block had been ranked using the front-end loading (FEL) methodology. This exercise had also been successfully replicated in Blocks 12, 15, and 18. When the merger was finalized, this approach was applied immediately to integrate and rank all assets operated by the newly merged company, allowing upper management to assign resources accordingly. Once the assets were ranked and grouped to identify clearly those fields comprising 60, 30, and 10% value for the operator, the process of calculating the associated investment to capitalize production and additional reserves from those fields began. A matrix to measure ROI vs. risk was then built, and every project was assigned an estimated operational expenditure (OPEX) value associated with the new growth strategy. This tool allowed the operator to select those opportunities that required minimum investment coupled with low and stable operating costs. In several fields, foreign investments were made under a contractual model, allowing service companies to provide specific services to increase oil production and recoverable volume based on a risked investments model, while the operator maintained the decision-making power and operatorship of all assets. As a result of this strategy and in conjunction with a robust management and execution plan, production not only stopped declining but reached higher production levels than previously experienced.
Implementation of an Innovative Drilling Fluid and Cuttings Separator in Latin America
Authors: Luna O. L. , Ibarra R. , Carter C. , Ramos D. 
Published: May 2017

Abstract
Under challenging market conditions, optimization and cost reduction become a priority, this paper presents the results and the best practices learned after the implementation of an innovative drilling fluid and cuttings separator in Latin America with three operators. This new technology has been field proven worldwide, in Latin America, operators in Argentina, Colombia, Ecuador and Bolivia have experienced improvements in overall solids control equipment efficiency and optimization of drilling operations. The use of new technologies regarding solids control equipment has allowed operators to significantly reduce drilling fluid consumption, waste volumes and improve the HSE profile in their operations.
Three case studies are presented, each one of them correspond to the implementation of the new technology with a different operator in the region.